UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
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| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended December 31, 20172018
or
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| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 001-37365
Tallgrass Energy, GP, LP
(Exact name of registrant as specified in its charter)
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| Delaware | | | | 46-315926847-3159268 |
| (State or other Jurisdiction of Incorporation or Organization) | | | | (IRS Employer Identification Number) |
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| 4200 W. 115th Street, Suite 350 | | | | |
| Leawood, Kansas | | | | 66211 |
| (Address of Principal Executive Offices) | | | | (Zip Code) |
(913) 928-6060
(Registrant's Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | | Name of each exchange on which registered |
| Class A Shares Representing Limited Partner Interests | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer", "accelerated filer", "smaller reporting company", and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one): |
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| Large accelerated filer | | x | | Accelerated filer | | ¨ |
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| Non-accelerated filer | | ¨ (Do not check if a smaller reporting company) | | Smaller reporting company | | ¨ |
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| | | | | Emerging growth company | | ¨ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The aggregate market value of voting and non-voting common equity held by non-affiliates on June 30, 2017,29, 2018, the last business day of the Registrant's most recently completed second fiscal quarter (based on the closing sale price of $25.43$22.16 of the Registrant's Class A shares, as reported by the New York Stock Exchange on such date) was approximately $1,452.6$1,264.2 million. On February 13, 2018,8, 2019, the Registrant had 58,085,002156,353,761 Class A shares and 126,709,225123,887,893 Class B shares outstanding.
TALLGRASS ENERGY, GP, LP
TABLE OF CONTENTS
Glossary of Common Industry and Measurement Terms
Bakken oil production area: Montana and North Dakota in the United States and Saskatchewan and Manitoba in Canada.
Barrel (or bbl): forty-two U.S. gallons.
Base Gas (or Cushion Gas): the volume of gas that is intended as permanent inventory in a storage reservoir to maintain adequate pressure and deliverability rates.
BBtu: one billion British Thermal Units.
Bcf: one billion cubic feet.
British Thermal Units or Btus: the amount of heat energy needed to raise the temperature of one pound of water by one degree Fahrenheit.
Commodity sensitive contracts or arrangements: contracts or other arrangements, including tariff provisions, that are directly tied to increases and decreases in the price of commodities such as crude oil, natural gas and NGLs. Examples are Keep Whole Processing Contracts and Percent of Proceeds Processing Contracts, as well as pipeline loss allowances on our pipelines.
Condensate: an NGL with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
Contract barrels: barrels of crude oil that our customers have contractually agreed to ship in exchange for firm service assurance of capacity and deliverability to delivery points.
Delivery point: any point at which product in a pipeline is delivered to or for the account of a customer.
Dry gas: a gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.
Dth: a dekatherm, which is a unit of energy equal to 10 therms or one million British thermal units.
End-user markets: the ultimate users and consumers of transported energy products.
EPA: the United States Environmental Protection Agency.
FERC: the United States Federal Energy Regulatory Commission.
Firm fee contracts: contracts or other arrangements, including tariff provisions, that generally obligate our customers to pay a fixed recurring charge to reserve an agreed upon amount of capacity and/or deliverability on our assets, regardless if the contracted capacity is actually used by the customer. Such contracts are also commonly known as "take-or-pay" contracts.
Firm services: services pursuant to which customers receive firm assurances regarding the availability of capacity and/or deliverability of natural gas, crude oil or other hydrocarbons or water on our assets up to a contracted amount.
Fractionation: the process by which NGLs are further separated into individual, typically more valuable components including ethane, propane, butane, isobutane and natural gasoline.
GAAP: accounting principles generally accepted in the United States of America.
GHGs: greenhouse gases.
Header system: networks of medium-to-large-diameter high pressure pipelines that connect local gathering systems to large diameter high pressure long-haul transportation pipelines.
Interruptible services: services pursuant to which customers receive limited, or no, assurances regarding the availability of capacity and deliverability in our assets.
Keep Whole Processing Contracts: natural gas processing contracts in which we are required to replace the Btu content of the NGLs extracted from inlet wet gas processed with purchased dry natural gas.
Line fill: the volume of oil, in barrels, in the pipeline from the origin to the destination.
Liquefied natural gas or LNG: natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.
Local distribution company or LDC: LDCs are involved in the delivery of natural gas to end users within a specific geographic area.
Long-term: with respect to any contract, a contract with an initial duration greater than one year.
MMBtu: one million British Thermal Units.
Mcf: one thousand cubic feet.
MDth: one thousand dekatherms.
MMcf: one million cubic feet.
Natural gas liquids or NGLs: those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, or other methods in natural gas processing or cycling plants. Generally, such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).
Natural Gas Processing: the separation of natural gas into pipeline-quality natural gas and a mixed NGL stream.
Non-contract barrels (or walk-up barrels): barrels of crude oil that our customers ship based solely on availability of capacity and deliverability with no assurance of future capacity.
No-notice service: those services pursuant to which customers receive the right to transport or store natural gas on assets outside of the daily nomination cycle without incurring penalties.
NYMEX: New York Mercantile Exchange.
NYSE: New York Stock Exchange.
Park and loan services: those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), our facilities.
Percent of Proceeds Processing Contracts: natural gas processing contracts in which we process our customer's natural gas, sell the resulting NGLs and residue gas and divide the proceeds of those sales between us and the customer. Some percent of proceeds contracts may also require our customers to pay a monthly reservation fee for processing capacity.
PHMSA: the United States Department of Transportation's Pipeline and Hazardous Materials Safety Administration.
Play: a proven geological formation that contains commercial amounts of hydrocarbons.
Produced water: all water removed from a well as a byproduct of the production of hydrocarbons and water removed from a well in connection with operations being conducted on the well, including naturally occurring water in the recovery formation, flow back water recovered during completion and fracturing operations and water entering the recovery formation through water flooding techniques.
Receipt point: the point where a product is received by or into a gathering system, processing facility, or transportation pipeline.
Reservoir: a porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (such as crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.
Residue gas: the natural gas remaining after being processed or treated.
Shale gas: natural gas produced from organic (black) shale formations.
Tailgate: the point at which processed natural gas and NGLs leave a processing facility for transportation to end-user markets.
TBtu: one trillion British Thermal Units.
Tcf: one trillion cubic feet.
Throughput: the volume of products, such as crude oil, natural gas or water, transported or passing through a pipeline, plant, terminal or other facility during a particular period.
Uncommitted shippers (or walk-up shippers): customers that have not signed long-term shipper contracts and have rights under the FERC tariff as to rates and capacity allocation that are different than long-term committed shippers.
Volumetric fee contracts: contracts or other arrangements, including tariff provisions, that generally obligate a customer to pay fees based upon the extent to which such customer utilizes our assets for midstream energy services. Unlike firm fee contracts, under volumetric fee contracts our customers are not generally required to pay a charge to reserve an agreed upon amount of capacity and/or deliverability.
Wellhead: the equipment at the surface of a well that is used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground.
Working gas: the volume of gas in the storage reservoir that is in addition to the cushion or base gas. It may or may not be completely withdrawn during any particular withdrawal season. Conditions permitting, the total working capacity could be used more than once during any season.
Working gas storage capacity: the maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Effective working gas storage capacity excludes base gas and non-cycling working gas.
X/d: the applicable measurement metric per day. For example, MMcf/d means one million cubic feet per day.
PART I
As used in this Annual Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TEGP""TGE" and similar terms refer to Tallgrass Energy, GP, LP, in its individual capacity or to Tallgrass Energy, GP, LP and its consolidated subsidiaries collectively (including Tallgrass Equity, TEP and their respective subsidiaries), as the context requires. References to "Tallgrass Equity" refer to Tallgrass Equity, LLC. References to "TEP" refer to Tallgrass Energy Partners, LP. The term our "general partner" refers to TEGP Management,Tallgrass Energy GP, LLC. References to "Tallgrass Development" or "TD" refer to Tallgrass Development, LP. References to "Kelso" are to Kelso & Company and its affiliated investment funds and, as the context may require, other entities under its control, and references to "EMG" are to The Energy & Minerals Group, its affiliated investment funds and, as the context may require, other entities under its control.
A reference to a "Note" herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8.—Financial Statements and Supplementary Data. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding certain risks inherent in our business.
Cautionary Statement Regarding Forward-Looking Statements
This Annual Report and the documents incorporated by reference herein contain forward-looking statements concerning our operations, economic performance and financial condition. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "could," "will," "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
our ability to pay distributionsdividends to our Class A shareholders;
our expected receipt of, and amountamounts of, distributions from Tallgrass Equity;
TEP'sour ability to complete and integrate acquisitions, including integrating the acquisitions discussed in Item 1.—Business, "Acquisitions;Acquisitions and Dispositions;"
the demand for TEP'sour services, including crude oil transportation, storage, gathering and terminalling services; natural gas transportation storage,and storage; crude oil transportation; and natural gas gathering and processing, services;crude oil storage and terminalling services, and water business services, as well as services;
our ability to successfully contract or re-contract with our customerscustomers;
large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;
our ability to successfully implement our business plan;
changes in general economic conditions;
competitive conditions in our industry;
the effects of existing and future laws and governmental regulations;
actions taken by governmental regulators of our assets, including the FERC;
actions taken by third-party operators, processors and transporters;
our ability to complete internal growth projects on time and on budget;
the price and availability of debt and equity financing;
the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of crude oil, natural gas, natural gas liquids, and other hydrocarbons;
the availability and price of natural gas and crude oil, and fuels derived from both, to the consumer compared to the price of alternative and competing fuels;
competition from the same and alternative energy sources;
energy efficiency and technology trends;
operating hazards and other risks incidental to transporting, storing, gathering and terminalling crude oil; transporting, storing, gathering and processing natural gas; and transporting, gathering and disposing of water produced in connection with hydrocarbon exploration and production activities;
environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
interest rates;
labor relations;
changes in tax laws, regulations and status;
the effects of existing and future litigation; and
certain factors discussed elsewhere in this Annual Report.
Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities laws.
Item 1. Business
Overview
TEGPTGE is a limited partnership formedthat owns, operates, acquires and develops midstream energy assets in 2015 thatNorth America and has elected to be treated as a corporation for U.S. federal income tax purposes. We were formed as part of a reorganization involving entities that were previously controlled
Our operations are conducted through, and our operating assets are owned by, Tallgrass Equity to effect the initial public offering of our Class A shares (the "TEGP IPO"), which was completed on May 12, 2015. Our sole cash-generating asset is an approximate 31.43% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of the direct and indirect partnership interestssubsidiaries, including Tallgrass Equity, in TEP and itswhich we directly own an approximate 55.79% membership interest in Rockies Express Pipeline LLC ("Rockies Express") as described below:
Tallgrass Equity owns 100% of the outstanding membership interests in Tallgrass MLP GP, LLC ("TEP GP"), which owns all the general partner interest in TEP as well as all the TEP incentive distribution rights ("IDRs"). The general partner interest in TEP is represented by 834,391 general partner units, representing an approximate 1.13% general partner interest in TEP at February 13, 2018.
Tallgrass Equity owns 25,619,218 TEP common units, representing an approximately 34.60% limited partner interest in TEP at February 13, 2018, inclusive of the 5,619,218 TEP common units acquired from Tallgrass Development on February 7, 2018 as described below.
On February 7, 2018, Tallgrass Development merged into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity ("Tallgrass Development Holdings"), and as a result of the merger, Tallgrass Equity acquired a 25.01% membership in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TEGP and Tallgrass Equity issued 27,554,785 unregistered TEGP Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of Tallgrass Development.
TEP is a publicly traded, growth-oriented limited partnership formed in 2013 to own, operate, acquire and develop midstream energy assets in North America. TEP's operations8, 2019. We are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Marcellus, Utica, Niobrara, Bakken, Mississippi Lime, and Eagle Ford, Bakken, Marcellus, and Utica shale formations. TEP intendsWe intend to continue to utilize the significant experience of itsour management team to execute itsour growth strategy of acquiring midstream assets, increasing utilization of itsour existing assets and expanding itsour systems through construction of additional assets.
TEP'sOur reportable business segments are:
Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and an integrated natural gas storage facilities;facility;
Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system;systems; and
Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering and processing facilities; crude oil gathering, storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs.
Additional segment and financial information is contained in TEP's segment results included in Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations and the notes to our consolidated financial statements included in Item 8.—Financial Statements and Supplementary Data of this Annual Report.
Our Assets
The following map shows our primary assets, which consist of natural gas transportation and storage assets; crude oil transportation assets; natural gas gathering and processing assets,assets; crude oil transportation, storage gathering and terminalling assets,assets; and water business services assets. Each of these assets are described in more detail below. Connected third party refineries are also indicated on the map below.
Natural Gas Transportation SegmentRockies Express Pipeline. TEP ownsWe own a 49.99% membership interest in Rockies Express. As discussed in Note 22 –Subsequent Events, on February 7, 2018, Tallgrass Equity acquired a 25.01%75% membership interest in Rockies Express in connection with the merger of Tallgrass Development into Tallgrass Development Holdings, bringing the aggregate membership interest of Pipeline LLC ("Rockies Express under the control of TEGP to 75%Express"). Rockies Express owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system with approximately 1,712 miles of transportation pipelines, including laterals, extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio (the "Rockies Express Pipeline") and consists of three zones:
Zone 1 - 328 miles of mainline pipeline from the Meeker Hub in Northwest Colorado, across Southern Wyoming to the Cheyenne Hub in Weld County, Colorado capable of transporting 2.0 Bcf/d of natural gas from west-to-east;
Zone 2 - 714 miles of mainline pipeline from the Cheyenne Hub to an interconnect in Audrain County, Missouri capable of transporting 1.8 Bcf/d of natural gas from west-to-east; and
Zone 3 - 643 miles of mainline pipeline from Audrain County, Missouri to Clarington, Ohio, which is bi-directional and capable of transporting 1.8 Bcf/d of natural gas from west-to-east and 2.6 Bcf/d of natural gas from east-to-west.
For the year ended December 31, 2017,2018, approximately 97%98% of Rockies Express' revenues were generated under firm fee contracts.
The following tables provide information regarding the Rockies Express Pipeline for the years ended December 31, 2018, 2017, 2016, and 20152016 and as of December 31, 2017:2018:
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| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
Approximate average daily deliveries (Bcf/d) (1) | 4.3 |
| | 3.2 |
| | 2.5 |
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| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
Approximate average daily deliveries (Bcf/d) (1) | 4.4 |
| | 4.3 |
| | 3.2 |
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| | Approximate Capacity | | Total Firm Contracted Capacity (2) | | Approximate % of Capacity Subscribed under Firm Contracts | | Weighted Average Remaining Firm Contract Life (3) |
| West-to-east | 2.0 Bcf/d | | 1.5 Bcf/d | | 75 | % | | 3 years |
| East-to-west | 2.6 Bcf/d | | 2.6 Bcf/d | | 100 | % | | 1514 years |
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(1) | Reflects average total daily deliveries for the Rockies Express Pipeline, regardless of flow direction or distance traveled. |
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(2) | Reflects total capacity reserved under long-term firm fee contracts as of December 31, 2017.2018. West-to-east firm contracted capacity excludes the 0.2 Bcf/d contracted with Ultra beginning December 1, 2019 as part of the settlement agreement discussed in Note 19 – Legal and Environmental Matters. |
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(3) | Weighted by contracted capacity as of December 31, 2017.2018. Weighted average remaining firm contract life of west-to-east contracts excludes the 0.2 Bcf/d contract with Ultra discussed above. After giving effect to the Ultra contract agreement reached in January 2017, the weighted average life of the west-to-east contract lives would be approximately 4 years. |
TIGT System. TEP ownsWe own a 100% membership interest in Tallgrass Interstate Gas Transmission, LLC ("TIGT"), which owns the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system with approximately 4,641 miles of varying diameter transportation pipelines serving Wyoming, Colorado, Kansas, Missouri and Nebraska (the "TIGT System"). The TIGT System includes the Huntsman natural gas storage facility located in Cheyenne County, Nebraska. The TIGT System primarily provides transportation and storage services to on-system customers such as local distribution companies and industrial users, including ethanol plants, and irrigation and grain drying operations, which depend on the TIGT System's interconnections to their facilities to meet their demand for natural gas and a majority of whom pay FERC-approved recourse rates. For the year ended December 31, 2017,2018, approximately 93%94% of the TIGT System's transportation revenue was generated from contracts with on-system customers.
Trailblazer Pipeline. TEP ownsWe own a 100% membership interest in Trailblazer Pipeline Company LLC ("Trailblazer"), which owns the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system with approximately 465 miles of transportation pipelines, including laterals, that begins along the border of Wyoming and Colorado and extends to Beatrice, Nebraska (the "Trailblazer Pipeline"). During the year ended December 31, 2017,2018, substantially all of the Trailblazer Pipeline's operationally available long-haul capacity was contracted under firm transportation contracts.
The following tables provide information regarding the TIGT System and Trailblazer Pipeline for the years ended December 31, 2018, 2017, 2016, and 20152016 and as of December 31, 2017:2018:
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| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Approximate average daily deliveries (Bcf/d) | 1.2 |
| | 1.1 |
| | 1.1 |
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| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Approximate average daily deliveries (Bcf/d) | 1.3 |
| | 1.2 |
| | 1.1 |
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| | Approximate Number of Miles | | Approximate Capacity | | Total Firm Contracted Capacity (1) | | Approximate % of Capacity Subscribed under Firm Contracts | | Weighted Average Remaining Firm Contract Life (2) |
| Transportation | 5,106 |
| | 2.0 Bcf/d | | 1.7 Bcf/d | | 83 | % | | 4 years |
| Storage | n/a |
| | 15.974 Bcf | (3) | 11 Bcf | | 69 | % | | 4 years |
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| Approximate Capacity | | Total Firm Contracted Capacity (1) | | Approximate % of Capacity Subscribed under Firm Contracts | | Weighted Average Remaining Firm Contract Life (2) |
| Transportation | 2.0 Bcf/d | | 1.6 Bcf/d | | 80 | % | | 5 years |
| Storage | 15.974 Bcf | (3) | 11 Bcf | | 71 | % | | 4 years |
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(1) | Reflects total capacity reserved under long-term firm fee contracts, including backhaul service, as of December 31, 2017.2018. |
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(2) | Weighted by contracted capacity as of December 31, 2017.2018. |
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(3) | The FERC certificated working gas storage capacity. |
NatGas. TEP ownsWe own a 100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas"), which is the operator of the Rockies Express Pipeline and receives a fee from Rockies Express as compensation for its services.
Crude Oil Transportation Segment
Pony Express.Express System. TEP currently provides crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through itsWe own a 100% membership interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express"). As discussed, which provides crude oil transportation to customers in Note 22 – Subsequent Events, TEP acquiredWyoming, Colorado, Kansas, and the remaining 2% membership interest in Pony Express from Tallgrass Development effective February 1, 2018, bringing its aggregate membership interest in Pony Express to 100%.surrounding regions. Pony Express owns an approximately 769-mile834-mile crude oil pipeline commencing in both Guernsey, Wyoming and Weld County, Colorado and terminating in Cushing, Oklahoma, with delivery points at the McPherson, El Dorado and Ponca City refineries and in Cushing, Oklahoma and a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). In addition,the second quarter of 2018, Pony Express is currently constructing a 55-mileplaced into service an extension that will extendof the Pony Express System beginning at a newsystem from an additional origin point in Weld County, Colorado located near Platteville, Colorado and ending at the Buckingham Terminal (together, the “Platteville Extension”("Platteville Extension"). TEP believesWe believe the Pony Express System is positioned as a low-cost, competitive transportation system with access to Bakken Shale, DJ Basin and Powder River Basin production.
The table below sets forth certain information regarding the Pony Express SystemSystem's long-haul capacity as of December 31, 20172018 and for the periods indicated:
| | Approximate Design Capacity
(bbls/d) (1) | Approximate Design Capacity
(bbls/d) (1) | | Approximate Contractible Capacity Under Contract (1)(2) | | Weighted Average Remaining Firm Contract Life (3) | | Approximate Average Daily Throughput (bbls/d) | Approximate Design Capacity
(bbls/d) (1) | | Approximate Contractible Capacity Under Contract (1)(2) | | Weighted Average Remaining Firm Contract Life (3) | | Approximate Average Daily Throughput (bbls/d) |
| | Year Ended December 31, | | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | | 2018 | | 2017 | | 2016 |
| 320,000 |
| | 100 | % | | 3 years | | 267,734 |
| | 285,507 |
| | 236,256 |
| (4) | |
| 342,000 | |
| | 93 | % | | 2 years | | 336,314 |
| | 267,734 |
| | 285,507 |
|
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(1) | Excludes additional capacity related to the Pony Express System's ability to inject drag reducing agent, which is an additive that increases pipeline flow efficiency.efficiency, and additional capacity related to expansion projects. |
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(2) | TEP isWe are required to make no less than 10% of design capacity available for non-contract, or "walk-up", shippers. Approximately 100%93% of the remaining design capacity (or available contractible capacity) is committed under contract. |
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(3) | Based on the average annual reservation capacity for each such contract's remaining life. The weighted average remaining firm contract life reflects the Continental Resources, Inc. ("Continental Resources") contract extension effective January 1, 2018. |
Powder River Gateway. In January 2019, we completed the expansion of our existing joint venture with Silver Creek Midstream, LLC ("Silver Creek") and acquired a 51% membership interest in Powder River Gateway, LLC ("Powder River Gateway"). Powder River Gateway owns the (i) Powder River Express Pipeline ("PRE Pipeline"), a 70-mile crude oil pipeline with a capacity of 90,000 barrels per day that transports crude oil from the Powder River Basin to Guernsey, Wyoming; (ii) Iron Horse Pipeline ("Iron Horse Pipeline"), a 80-mile crude oil pipeline expected to be placed into service in the second quarter of 2019 that will have an initial capacity of approximately 100,000 barrels per day and will transport crude oil from the Powder River Basin to Guernsey, Wyoming; and (iii) crude oil terminal facilities in Guernsey, Wyoming with approximately 370,000 barrels of crude storage currently in-service and over 1 million barrels of storage expected in the second quarter of 2019 once current construction of additional facilities is completed.
| |
(4)
| Approximate average daily throughput for the three months ended December 31, 2015 was 288,362 bbls/d. Approximate average daily throughput for the year ended December 31, 2015 reflects the volumetric ramp-up during the year due to the construction and expansion efforts of the Pony Express lateral in Northeast Colorado and third-party pipelines with which Pony Express shares joint tariffs. |
Gathering, Processing & Terminalling Segment
Midstream Facilities. TEP ownsWe own a 100% membership interest in Tallgrass Midstream, LLC ("TMID"), which owns and operates a natural gas gathering system in the Powder River Basin (the "Douglas Gathering System") that was acquired on June 5, 2017.. TMID also owns and operates natural gas processing plants in Casper and Douglas, Wyoming and a natural gas treating facility at West Frenchie Draw, Wyoming (collectively with the Douglas Gathering System, the "Midstream Facilities"). The Casper and Douglas plants currently have combined processing capacity of approximately 190 MMcf/d. The Casper plant also has an NGL fractionator with a capacity of approximately 3,500 barrels per day. The natural gas processed and treated at these facilities primarily comes from the Wind River Basin and the Powder River Basin, both in central Wyoming. TMID also owns and operates an NGL pipeline with an approximate capacity of 19,500 barrels per day that transports NGLs from a processing plant in Northeast Colorado to an interconnect with Overland Pass Pipeline, and an NGL pipeline that originates at our Douglas facility and interconnects with ONEOK's Bakken NGL Pipeline. Each of TEP'sour NGL pipelines are supported by 10-year leases for 100% of their respective pipeline capacity, with the lease for the NGL pipeline in Northeast Colorado having commenced in October 2015, and the lease for the NGL pipeline from our Douglas facility having commenced on January 1, 2017. During the year ended December 31, 2017,2018, approximately 17%12%, 53%51%, and 30%37% of TMID's operating incomeAdjusted EBITDA came from firm fee, volumetric fee, and commodity sensitive contracts, respectively.
TEP also provides crude oil gathering services for customers in Wyoming through a 50-mile crude oil gathering system in the Powder River Basin (the "PRB Crude System") acquired on August 3, 2017. As discussed in Note 22 – Subsequent Events, TEP has agreed to sell the PRB Crude System to an affiliate of Silver Creek Midstream, LLC. The sale is expected to close in February 2018.
The table below sets forth certain information regarding natural gas gathering and processing at the Midstream Facilities as of December 31, 20172018 and for the years ended December 31, 2018, 2017, 2016, and 2015:2016:
| | | | | Approximate Capacity (MMcf/d) | | Approximate Average Volumes (MMcf/d) | | Approximate Capacity (MMcf/d) | | Approximate Average Volumes (MMcf/d) |
| | | Year Ended December 31, | | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | | 2018 | | 2017 | | 2016 |
| Gathering | | 75 |
| | 37 |
| (1) | N/A |
| | N/A |
| | 75 |
| | 42 |
| | 37 |
| (1) | N/A |
|
| Processing | | 190 |
| (2) | 109 |
| | 103 |
| | 122 |
| | 190 |
| (2) | 122 |
| | 109 |
| | 103 |
|
| |
(1) | Reflects approximate average gathering volumes subsequent to our acquisition of the Douglas Gathering System on June 5, 2017. |
| |
(2) | The West Frenchie Draw natural gas treating facility treats natural gas before it flows into the Casper and Douglas plants and therefore does not result in additional inlet capacity. |
Water Solutions. TEP providesWe provide water business services through itsour 100% membership interest in BNN Water Solutions, LLC ("Water Solutions"). Water Solutions owns and operates a freshwater delivery and storage system and a produced water gathering and disposal system in Weld County, Colorado, and a produced water disposal facility in Campbell County, Wyoming.Wyoming, and a produced water gathering and disposal system in North Dakota. Water Solutions is also the sole voting member and owns a 75.19% membership interest in BNN West Texas, LLC ("West Texas"), which owns a produced water gathering and disposal system in Reeves and Reagan Counties, Texas that is operated by Water Solutions and owns a 63% membership interest in BNN Colorado Water, LLC ("BNN Colorado"), which owns a freshwater storage reservoir and supply pipeline in Weld County, Colorado. These systems are used to support third party exploration, development, and production of oil and natural gas. Water Solutions also sources treated wastewater from municipalities in Texas and recycles flowback water and other water produced in association with the production of oil and gas in Colorado. In JanuaryNovember 2018, Water Solutions acquired a 100% membership interest in Buckhorn Energy Services,NGL Water Solutions Bakken, LLC and Buckhorn SWD("NGL Water Solutions LLC (collectively, "BNN North Dakota"Bakken"). BNN North Dakota, which owns a produced water gathering and disposal system in the Bakken basin with approximately 133,000 acres under dedication.basin.
The table below sets forth certain information regarding the Water Solutions assets as of December 31, 20172018 and for the years ended December 31, 2018, 2017, 2016, and 2015:2016:
| | | | | Approximate Capacity Under Contract | | Approximate Current Design Capacity (bbls/d) | | Remaining Contract Life | | Approximate Average Volumes (bbls/d) | | Approximate Current Design Capacity (bbls/d) | | Approximate Average Volumes (bbls/d) |
| | | Year Ended December 31, | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Freshwater | | 68 | % | | 30,863 |
| (1) | 3 | | 69,139 |
| | 13,201 |
| | 14,579 |
| | 170,863 |
| (1) | 17,849 |
| | 69,139 |
| | 13,201 |
|
| Gathering and Disposal | | 67 | % | | 45,000 |
| (2) | 7 | | 31,511 |
| | 11,307 |
| | 7,951 |
| | 271,500 |
| (2) | 98,489 |
| | 31,511 |
| | 11,307 |
|
| |
(1) | Represents design capacity at our BNN Western, LLC ("Western") owned facilities.facilities and our BNN Colorado freshwater storage reservoir and supply pipeline. Western also has access to an additional 144,539 bbls/d under supply arrangements, which are not included in the approximate current design capacity. |
| |
(2) | Represents the combined daily disposal well injection capacity for the Western produced water gathering and disposal system acquired in December 2015, and the West Texas produced water gathering and disposal system which commenced operations by Water Solutions in March 2016.2016, the BNN North Dakota, LLC ("BNN North Dakota") produced water gathering and disposal system acquired in January 2018 and produced water disposal system acquired in November 2018. |
Terminals. TEP providesWe provide crude oil storage and terminalling services through itsour 100% membership interest in Tallgrass Terminals, LLC ("Terminals"). Terminals owns and operates several assets providing storage capacity and additional injection points for the Pony Express System, including the crude oil terminal near Sterling, Colorado with approximately 1.3 million bbls of storage capacity (the "Sterling Terminal") and, the crude oil terminal in Weld County, Colorado with four truck unloading skids capable of receiving up to 16,00042,000 bbls per day (the "Buckingham Terminal"), and the crude oil terminal in the Central Kansas Uplift that can deliver upward of 20,000 bbls per day into the Pony Express System and commenced operations in the first quarter of 2018 (the "Natoma Terminal"). Terminals also owns an approximately 60% membership interest in Deeprock Development, LLC ("Deeprock Development"), which owns a crude oil terminalterminals in Cushing, Oklahoma with approximately 2.34.0 million bbls of storage capacity (the "Cushing Terminal"). As discussed in Note 22 – Subsequent Events, on January 2,In April 2018, Terminals acquired an approximately 38%a 51% membership interest in Deeprock North, LLCthe Pawnee, Colorado crude oil terminal ("Deeprock North"Pawnee Terminal"), which was merged into Deeprock Development immediately following the acquisition. Deeprock North owned a terminal facility in Cushing, Oklahoma adjacent to the existing Deeprock Development facilities, bringing the total with approximately 300,000 bbls of storage capacity of the Cushing Terminal to approximately 4.0 million barrels. In addition, Terminals is currently constructing both the Grasslands Terminal, which will connect to the Platteville Extension, and the Natoma Terminal in Central Kansas, and owns projects currently under development to provide additional storage capacity and other potential service opportunities, including approximately 550 acres in Cushing, Oklahoma and approximately 250 acres in Guernsey, Wyoming.capacity.
The table below sets forth certain information regarding Terminals as of December 31, 2017:
|
| | | | | | |
Approximate Storage Capacity
(bbls) | | Approximate Storage Capacity Under Contract | | Weighted Average Remaining Contract Life |
| 3,750,000 |
| | 93 | % | | 19 years |
Stanchion. During 2017, TEP establishedWe own a 100% membership interest in Stanchion Energy, LLC ("Stanchion"), to engagewhich engages in the marketing of crude oil. Stanchion currently consists of three of our employees who primarily engage in the purchase and sale of crude oil.
Major Customers
For the year ended December 31, 2017,2018, Continental Resources accounted for approximately 15%10% of our revenues on a consolidated basis. The loss of this customer could have a material adverse effect on our financial results.
Organizational Structure
Our general partner interest is held by TEGP Management,Tallgrass Energy GP, LLC, whose sole member is Tallgrass Energy Holdings. Holdings, LLC ("Tallgrass Energy Holdings is also the general partner of Tallgrass Development.Holdings"). A group of persons, which we refer to as the Exchange Right Holders, collectively own all our outstanding Class B shares and an equivalent number of Tallgrass Equity units. The Exchange Right Holders are entitled to exercise the right to exchange their Tallgrass Equity units (together with an equivalent number of Class B shares) for Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged. TheAs of February 8, 2019, the Exchange Right Holders primarily consist of Kelso, EMG, and Tallgrass KC. Tallgrass KC refers to Tallgrass KC, LLC, which is an entity primarily owned by certain members of our and TEP's management. Certain of the Exchange Right Holders collectively own 100% of the voting power of Tallgrass Energy Holdings.
On January 31, 2019, we announced that affiliates of Blackstone Infrastructure Partners (collectively, "BIP") had entered into a definitive purchase agreement with Kelso, EMG, and Tallgrass KC (collectively, the "Sellers"), pursuant to which BIP will acquire from the Sellers 100% of the membership interests in our general partner and an approximately 44% economic interest in us (the "Blackstone Acquisition"). One or more affiliates of GIC Special Investment Pte. Ltd. ("GIC SI"), the infrastructure and private equity arm of GIC Pte. Ltd., Singapore's sovereign wealth fund, will be a minority investor in the Blackstone Acquisition. The interests acquired in the Blackstone Acquisition will include all of the economic interests in us held by EMG and Kelso, and a substantial portion of the interests held by Tallgrass KC.
Subject to customary closing conditions, the Blackstone Acquisition is expected to close within the first quarter of 2019. Following consummation of the Blackstone Acquisition, (i) the Exchange Right Holders are expected to consist of BIP and certain members of our management and (ii) BIP will own 100% of the membership interests in our general partner.
On February 7, 2018, Tallgrass Development merged into Tallgrass Development Holdings, a wholly-owned subsidiary of Tallgrass Equity, and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TEGP and Tallgrass Equity issued 27,554,785 unregistered TEGP Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of Tallgrass Development.
While we like TEP, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of TEP. Most notably, (i) we have elected to be treated as a corporation for U.S. federal income tax purposes, (ii) neither our general partner nor the holders of our Class B shares are entitled to receive any distributionsdividends from us, and (iii) our capital structure does not include incentive distribution rights. Therefore, our distributionsdividends will be made exclusively to our Class A shares. However, holders of our Class A shares and Class B shares vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or our partnership agreement. The term "shares" used in this annual report refers to both the Class A shares and Class B shares representing limited partner interests in us. References to our "shareholders" refer to the holders of our Class A and Class B shares.
Our operations are conducted directly and indirectly through, and our operating assets are owned by, our subsidiaries. Our general partner is responsible for conducting our business and managing our operations. However, as of February 8, 2019, Tallgrass Energy Holdings effectively controls our business and affairs through the exercise of its rights as the party that controls the sole member of our general partner, including its right to appoint members to the board of directors of our general partner. Following consummation of the Blackstone Acquisition, BIP will, subject to certain contractual rights, exercise such control through the ownership of 100% of the membership interests in our general partner.
In connection with the closing of the initial public offering of our Class A shares (the "TGE IPO"), we, our general partner, Tallgrass Equity and Tallgrass Energy Holdings entered into an omnibus agreement (the "TGE Omnibus Agreement"), that addresses the following matters:
Tallgrass Equity's obligation to reimburse Tallgrass Energy Holdings and its affiliates for expenses incurred (i) on our behalf, (ii) on behalf of our general partner and (iii) for any other purposes related to our business and activities or those of our general partner, including our public company expenses and general and administrative expenses; and
Our use of the name "Tallgrass" and any associated or related marks.
The chart below shows the structure of Tallgrass Energy Holdings and its subsidiaries as of February 13, 20188, 2019 in a summary format.
Previous Organizational Structure
We were initially formed in 2015 as part of a reorganization involving entities that were previously controlled by Tallgrass Development
On February 7, 2018, Tallgrass Development merged into Tallgrass Development Holdings, and as a resultEquity to effect the TGE IPO. As of the merger, Tallgrass Equity acquiredclosing of the TGE IPO in May 2015, our sole cash-generating asset was a 25.01%controlling membership interest in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TEGPTallgrass Equity and Tallgrass Equity issued 27,554,785 unregistered TEGP Class B sharesEquity's sole cash-generating assets consisted of direct and Tallgrass Equity units, valuedindirect partnership interests in TEP, which was a publicly traded limited partnership at approximately $644.8 million based on the closing price on February 6, 2018,time.
Prior to the limited partnersFebruary 2018 merger discussed below, Tallgrass Energy Holdings was the general partner of Tallgrass Development. Prior to the merger, Tallgrass Development was controlled by its general partner, Tallgrass Energy Holdings, which continues to indirectly control our general partner.
Historically, TEP has acquired a number of its assets from Tallgrass Development. In connection with TEP's initial public offering onin May 17, 2013 (the "TEP IPO"), Tallgrass Development contributed to TEP 100% of the membership interests in TIGT and TMID. Since then,Following the TEP hasIPO, TEP acquired the following additional assets from Tallgrass Development: (1) in April 2014, a 100% membership interest in Trailblazer, (2) in four separate transactions, the most recent of which was effective on February 1, 2018, a 100% membership interest in Pony Express, (3) in January 2017, a 100% membership interest in NatGas and Terminals, (4) in March 2017, a 24.99% membership interest in Rockies Express, and (5) effective February 1, 2018, a 100% membership interest in Tallgrass Operations, LLC, which primarily ownsowned certain administrative assets consisting primarily of information technology assets. In addition, in May 2016 Tallgrass Development assigned to TEP its right to purchase a 25% membership interest in Rockies Express from a unit of Sempra U.S. Gas and Power ("Sempra") pursuant to the purchase agreement originally entered into between Tallgrass Development's wholly-owned subsidiary and Sempra in March 2016.
Pursuant to an Omnibus Agreement enteredOn February 7, 2018, Tallgrass Development merged into upon the closing of the TEP IPO, among TEP, TEP GP, Tallgrass Development Holdings, (as successor toa wholly-owned subsidiary of Tallgrass Development)Equity, and as a result of the merger, Tallgrass Energy Holdings (the "TEP Omnibus Agreement"), Tallgrass Development Holdings has granted TEPEquity acquired a right of first offer to acquire certain assets, if Tallgrass Development Holdings decides to sell such assets to a non-affiliate. The only asset currently owned by Tallgrass Development Holdings subject to such right of first offer is the 25.01% membership interest in Rockies Express.Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TGE and Tallgrass Development Holdings is otherwise under no obligation to offer to sell TEP additional assets or to pursue acquisitions jointly with TEP,Equity issued 27,554,785 TGE Class B shares and TEP is under no obligation to buy any assets from Tallgrass Development Holdings or pursue any such joint acquisitions.
Further, in connection withEquity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of the TEGP IPO,Tallgrass Development.
On March 26, 2018, we ourentered into an Agreement and Plan of Merger (the "Merger Agreement") with Tallgrass Equity, Tallgrass MLP GP, LLC, a Delaware limited liability company and the general partner of TEP ("TEP GP"), and Razor Merger Sub, LLC, a Delaware limited liability company. The merger transaction contemplated by the Merger Agreement (the "TEP Merger") was completed effective June 30, 2018, and as a result, 47,693,097 TEP common units held by the public were converted into the right to receive Class A shares of TGE at an exchange ratio of 2.0 Class A shares for each outstanding TEP common unit, TEP's incentive distribution rights were cancelled, TEP's common units ceased being publicly traded, and 100% of TEP's equity interests are now owned by Tallgrass Equity and Tallgrass Energy Holdings entered into an omnibus agreement (the "TEGP Omnibus Agreement"), that addresses the following matters:
Tallgrass Equity's obligation to reimburse Tallgrass Energy Holdings and its affiliates for expenses incurred (i) on our behalf, (ii) on behalf of our general partner and (iii) for any other purposes related to our business and activities or those of our general partner, including our public company expenses and general and administrative expenses; and
Our use of the names "TEP" and "Tallgrass" and any associated or related marks.subsidiaries.
Acquisitions and Dispositions
The acquisition of midstream assets and businesses that are strategic and complementary to TEP'sour existing operations constitutes an integral component of itsour business strategy and growth objectives. Such assets and businesses include natural gas transportation storage,and storage; crude oil transportation; and natural gas gathering and processing, assets, crude oil transportation, storage gathering and terminalling assets,services, and water business servicesservice assets and other energy assets that have characteristics and provide opportunities similar to TEP'sour existing business lines and enable TEPus to leverage itsour assets, knowledge and skill sets. Below are summaries of significant acquisitions TEP completed in 20172018 and in early 2018,2019, as discussed in Note 43 – Acquisitions and Dispositions and Note 22 – Subsequent Events.
Terminals and NatGas. In January 2017, TEP acquired 100% of the issued and outstanding membership interests in Terminals and 100% of the issued and outstanding membership interests in NatGas from Tallgrass Development for total cash consideration of $140 million.
Additional Membership Interest in Rockies Express. In March 2017, TEP acquired an additional 24.99% membership interests in Rockies Express from Tallgrass Development for cash consideration of $400 million.
Douglas Gathering System. In June 2017, TEP acquired 100% of the membership interests in DCP Douglas, LLC (subsequently renamed as Tallgrass Midstream Gathering, LLC) for approximately $128.5 million, subject to working capital adjustments.
Additional Interests in Deeprock Development. In July 2017, TEP acquired an additional 40% membership interest in Deeprock Development from Kinder Morgan Cushing, LLC for cash consideration of approximately $57.2 million, net of cash acquired. TEP subsequently acquired an additional 9% membership interest in Deeprock Development from Deeprock Energy Resources LLC ("DER") for total consideration valued at approximately $13.1 million, consisting of approximately $6.4 million in cash and the issuance of 128,790 TEP common units (valued at approximately $6.7 million based on the July 20, 2017 closing price of TEP's common units).
PRB Crude System. In August 2017, TEP acquired 100% of the membership interests of Outrigger Powder River Operating, LLC (subsequently renamed as Tallgrass Crude Gathering, LLC, "TCG") for approximately $36 million. As discussed in Note 22 – Subsequent Events, TEP entered into an agreement in February 2018 with an affiliate of Silver Creek Midstream, LLC ("Silver Creek") to form Iron Horse Pipeline, a new joint venture pipeline to transport crude oil from the Powder River Basin. In addition to forming the joint venture, TEP also agreed to sell to Silver Creek our 100% membership interest in TCG. TEP expects to close the sale of TCG and the formation of the joint venture in February 2018.
Deeprock North. In January 2018, TEPwe acquired a 38% membership interest in Deeprock North from Kinder Morgan Deeprock North Holdco, LLC for cash consideration of $19.5 million. Immediately following the acquisition, Deeprock North was merged into Deeprock Development. Subsequent to the acquisition and merger, Terminals owns approximately 60% of the combined entity.
Pawnee Terminal. In January 2018, TEPwe entered into an agreement to acquire a 51% membership interest in the Pawnee, Colorado crude oil terminal from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately $31 million, subject to working capital adjustments. TEP expects themillion. The transaction to closeclosed in the first quarter of 2018, subject to certain closing conditions.April 2018.
BNN North Dakota. In January 2018, TEPwe acquired a 100% membership interest in Buckhorn Energy Services, LLC and Buckhorn SWD Solutions, LLC, which were subsequently merged and renamed BNN North Dakota, LLC, for cash consideration of approximately $95.0 million, subject to working capital adjustments.$95 million.
Additional Interest in Pony Express. In February 2018, we acquired the remaining 2% membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from Tallgrass Development for cash consideration of approximately $60 million, bringing itsour aggregate membership interest in Pony Express to 100%.
Additional Membership Interest in Rockies Express and Additional TEP Common Units. In February 2018, Tallgrass Development merged into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity, and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TGE and Tallgrass Equity issued 27,554,785 TGE Class B shares and Tallgrass Equity units, valued at approximately $644.8 million. Subsequent to the closing of the transaction, our aggregate membership interest in Rockies Express is 75%.
Tallgrass Crude Gathering. In February 2018, we entered into an agreement with an affiliate of Silver Creek to sell our 100% membership interest in Tallgrass Crude Gathering, LLC ("TCG") for approximately $50 million. The sale of TCG closed in February 2018.
Joint Venture with Silver Creek. In February 2018, we entered into an agreement with Silver Creek to form Iron Horse Pipeline, LLC ("Iron Horse"), which owns the Iron Horse Pipeline currently under construction. In August 2018, we entered into an agreement with Silver Creek to expand the Iron Horse joint venture through the contribution by us and Silver Creek of cash and additional Powder River Basin assets. These additional contributions were completed in January 2019. The expanded joint venture operates under the name Powder River Gateway, LLC and owns the Iron Horse Pipeline, the PRE Pipeline, and crude oil terminal facilities in Guernsey, Wyoming. Effective January 1, 2019, we own a 51% membership interest in Powder River Gateway and operate the joint venture.
Acquisition of NGL Water Solutions Bakken. In November 2018, we acquired 100% of the membership interests in NGL Water Solutions Bakken, which was subsequently merged into BNN North Dakota, for cash consideration of approximately $91 million, subject to working capital adjustments.
Growth Projects
Our extensive asset base and our relationships with customers provide us with opportunities for internal growth through the construction of additional assets that are complementary to, and expand or extend, our existing asset base. The following growth projects are currently ongoing and will extend throughout 2019 and beyond:
Iron Horse Pipeline. Iron Horse Pipeline, an approximately 80-mile crude oil pipeline currently under construction, will have an initial capacity of approximately 100,000 barrels per day, expandable up to 200,000 barrels per day, to transport crude oil from the Powder River Basin to the Guernsey, Wyoming oil hub and is expected to be in-service in the second quarter of 2019. As discussed above, the Iron Horse Pipeline is part of the Powder River Gateway joint venture.
Grasslands Terminal. We are currently constructing the Grasslands Terminal in Platteville, Colorado, which will connect to the Platteville Extension and enable Pony Express to batch multiple common streams out of Platteville. The Grasslands Terminal is expected to be in-service by the second quarter of 2019.
Cheyenne Connector. We are currently constructing the Cheyenne Connector, a new pipeline lateral in Northeast Colorado that will transport natural gas from the DJ Basin in Weld County to the Rockies Express Pipeline's Cheyenne Hub, discussed below. Cheyenne Connector will be a large-diameter pipeline approximately 70 miles long, with an initial capacity of at least 600 mmcf/d and significant capability for expansion. Cheyenne Connector is expected to be in-service in the fourth quarter of 2019.
Cheyenne Hub. The Rockies Express Pipeline's Cheyenne Hub is an existing natural gas facility owned and operated by Rockies Express Pipeline in northern Weld County. At the Cheyenne Hub, the existing Rockies Express Pipeline intersects and/or connects with numerous other natural gas pipelines. The Cheyenne Hub Enhancement Project consists of modifications to the Rockies Express Pipeline's Cheyenne Hub to accommodate firm receipt and delivery interconnectivity among multiple natural gas pipelines with various operating pressures and will provide customers significant diversity in terms of market access. Cheyenne Hub is expected to be in-service by the fourth quarter of 2019.
Plaquemines Liquids Terminal. In November 2018, we entered into a joint venture agreement with Drexel Hamilton Infrastructure Fund I, L.P. ("DHIF") to jointly-own Plaquemines Liquids Terminal, LLC ("PLT"). We made an initial cash contribution of $30.7 million in exchange for a 100% preferred membership interest and a 80% common membership interest. DHIF contributed any and all assets and rights related to the project in exchange for a 20% common membership interest and the right to receive certain special distributions. PLT will construct a liquid export terminal facility on the Mississippi River on an approximately 600-acre site in Plaquemines Parish, Louisiana. The site was acquired in November 2018 pursuant to an agreement between PLT and the Plaquemines Port & Harbor Terminal District. The facility is expected to offer up to 20 million barrels of storage for both crude oil and refined products and export facilities capable of loading Suezmax and Very Large Crude Carriers ("VLCC") vessels for international delivery. The project is currently expected to be in-service in 2020.
Competition
All of TEP'sour businesses face strong competition for acquisitions and development of new projects from both established and start-up companies. Competition may increase the cost to acquire existing facilities or businesses and may result in fewer commitments and lower returns for new pipelines or other development projects. TEP'sOur competitors may have greater financial resources than TEP possesseswe possess or may be willing to accept lower returns or greater risks. Competition differs by region and by the nature of the business or the project involved.
Additionally, pending and future construction projects, if and when brought online, may also compete with TEP'sour natural gas transportation, storage, gathering and processing services, crude oil transportation, storage, gathering and terminalling services, and water transportation, gathering, recycling and disposal services. Further, natural gas as a fuel, and fuels derived from crude oil, compete with other forms of energy available to users, including electricity, coal, other liquid fuels and alternative energy. Increased demand for such forms of energy at the expense of natural gas or fuels derived from crude oil could lead to a reduction in demand for TEP'sour services. Moreover, several other factors may influence the demand for natural gas and crude oil which in turn influences the demand for TEP'sour services, including price changes, the availability of natural gas and crude oil and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, weather, and the ability to convert to alternative fuels.
TEP'sOur principal competitors in itsour natural gas transportation and storage business include companies that own major natural gas pipelines, such as Spectra Energy Partners,Enbridge Inc., Kinder Morgan Inc., Northern Natural Gas Company, Southern Star Central Gas Pipeline, Inc., Energy Transfer Partners, EQT Midstream Partners,LP, and The Williams Companies Inc., some of whom also have existing storage facilities connected to their transportation systems that compete with TEP'sour storage facilities.
Pony Express encounters competition in the crude oil transportation business. A number of pipeline companies compete with Pony Express to service takeaway volumes in markets that Pony Express currently serves, including pipelines owned and operated by Sinclair Oil Corporation, Plains All American Pipeline, L.P., Suncor Energy Inc., SemGroup Corporation, Magellan Midstream Partners, L.P., Anadarko Petroleum Corporation, NGL Energy Partners LP, Energy Transfer Partners,LP, and Enbridge Energy Partners.Inc. Pony Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers looking to capitalize on basis differentials between two primary crude oil price benchmarks (West Texas Intermediate Crude and Brent Crude), and with refineries that source barrels in areas served by Pony Express. In addition, Terminals encounters competition in the crude oil storage and terminalling business from similar facilities owned by Magellan Midstream Partners, NGL Energy Partners, Plains All American, Blueknight Energy Partners, SemGroup, and Enbridge Energy Partners.
TEPWe also experiencesexperience competition in the natural gas processing business. TEP'sOur principal competitors for processing business include other facilities that service its supply areas, such as the other regional processing and treating facilities in the greater Powder River Basin which include plants owned and operated by Kinder Morgan, Inc., which we refer to as Kinder Morgan, ONEOK, Partners, LP,Inc., Western Gas Partners, LP, The Williams Partners L.P.Companies Inc., and Meritage Midstream Services II, LLC. In addition, due to the competitive nature of the liquids-rich plays in the Wind River Basin and Powder River Basin, it is possible
that one of TEP'sour competitors could build additional processing facilities that service TEP'sour supply areas. In addition, Terminals encounters competition in the crude oil storage and terminalling business from facilities owned by Magellan Midstream Partners, L.P., NGL Energy Partners LP, Plains All American, L.P., Blueknight Energy Partners, L.P., SemGroup Corporation, and Enbridge Inc. Further, TEP experienceswe experience competition in the water business services. TEP'sOur principal competitors in such business are other midstream companies, such as NGL Energy Partners LP, who compete with Water Solutions in areas of concentrated production activity.
Regulatory Environment
Federal Energy Regulatory Commission
TEP providesWe provide open-access interstate transportation service on itsour natural gas transportation systems pursuant to tariffs approved by the FERC. As interstate transportation and storage systems, the rates, terms of service and continued operations of the Rockies Express Pipeline, the TIGT System and the Trailblazer Pipeline are subject to regulation by the FERC, under among other statutes, the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy Policy Act of 2005, or EPAct 2005. The rates and terms of service on the Pony Express System, PRE Pipeline, and Iron Horse Pipeline are subject to regulation by the FERC under the Interstate Commerce Act, or the ICA, and the Energy Policy Act of 1992. TEP providesWe provide interstate transportation service on the Pony Express System and PRE Pipeline pursuant to tariffs on file with the FERC. TEP'sOur NGL pipeline that interconnects with Overland Pass Pipeline is leased to a third party who has obtained a waiver for itself from the FERC from the tariff, filing and reporting requirements of the ICA, and TEP'sour NGL pipeline that interconnects with ONEOK's Bakken NGL Pipeline is leased to a third party who is obligated to operate the leased pipeline in conformance with the ICA as a FERC regulated NGL pipeline.
The FERC has jurisdiction over, among other things, the construction, ownership and commercial operation of pipelines and related facilities used in the transportation and storage of natural gas in interstate commerce, including the modification, extension, enlargement and abandonment of such facilities. The FERC also has jurisdiction over the rates, charges and terms and conditions of service for the transportation and storage of natural gas in interstate commerce. The FERC's authority over interstate crude oil pipelines is less broad than its authority over interstate natural gas pipelines and includes rates, rules and regulations for service, the form of tariffs governing service, the maintenance of accounts and records, and depreciation and amortization policies.
The rates and terms for access to interstate natural gas pipeline transportation services are subject to extensive regulation and the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of these initiatives, interstate natural gas transportation and marketing entities have been substantially restructured to remove barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from competing effectively with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The FERC's regulations require, among other things, that interstate natural gas pipelines provide firm and interruptible transportation service on an open access basis, provide internet access to current information about available pipeline capacity and other relevant information, and permit pipeline shippers under certain circumstances to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. The result of the FERC's initiatives has been to eliminate interstate natural gas pipelines' historical role of providing bundled sales service of natural gas and to require pipelines to offer unbundled storage and transportation services on a not unduly discriminatory or preferential basis. The rates for such transportation and storage services are subject to the FERC's ratemaking authority, and the FERC exercises its authority by applying cost-of-service principles to limit the maximum and minimum levels of tariff-based recourse rates; however, it also allows for discounted or negotiated rates as an alternative to cost-based rates and may grant market-based rates in certain circumstances. The FERC regulations also restrict interstate natural gas pipelines from sharing certain transportation or customer information with marketing affiliates and require that the transmission function personnel of interstate natural gas pipelines operate independently of the marketing function personnel of the pipeline or its affiliates.
FERC; Market Behavior Rules; Posting and Reporting Requirement; Other Enforcement Authorities
EPAct 2005, among other matters, amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC and, furthermore, provides the FERC with additional civil penalty authority. The FERC adopted rules implementing the anti-manipulation provision of EPAct 2005 that make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas transportation services subject to the jurisdiction of the FERC to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person.
These anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. EPAct 2005 also amended the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes of more than $1 million per day per violation. In connection with this enhanced civil penalty authority, the FERC issued policy statements on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines, including the disgorgement of unjust profits.
EPAct 2005 also amended the NGA to authorize the FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. The FERC has taken steps to enhance its market oversight and monitoring of the natural gas industry by adopting rules that (1) require buyers and sellers of annual quantities of 2,200,000 MMBtu or more of gas in any year to report by May on the aggregate volumes of natural gas they purchased or sold at wholesale in the prior calendar year; (2) report whether they provide prices to any index publishers and, if so, whether their reporting complies with the FERC's policy statement on price reporting; and (3) increase the internet posting obligations of interstate pipelines.
In addition, the Commodity Futures Trading Commission, or CFTC, is directed under the Commodities Exchange Act, or CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act, in July 2010 and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of more than $1 million or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA.
Further, the Federal Trade Commission, or FTC, has the authority under the Federal Trade Commission Act, or FTCA, and the Energy Independence and Security Act of 2007, or EISA, to regulate wholesale petroleum markets. The FTC has adopted anti-market manipulation rules, including prohibiting fraud and deceit in connection with the purchase or sale of certain petroleum products, and prohibiting omissions of material information which distort or are likely to distort market conditions for such products. In addition to other enforcement powers it has under the FTCA, the FTC can sue violators under EISA and request that a court impose fines of more than $1 million per violation per day.
The FERC also has the authority under the ICA to regulate the interstate transportation of petroleum on common carrier pipelines, including whether a pipeline's rates or rules and regulations for service are "just and reasonable." Among other enforcement powers, the FERC can order prospective rate changes, suspend the effectiveness of rates, and order reparations for damages. In addition, the ICA imposes potential criminal liability for certain violations of the statute.
Certain Outstanding Notices Issued by the FERC
FERC Advanced Notice of Proposed Rulemaking, Revisions to Indexing Policies and Page 700 of FERC Form No. 6, Docket No. RM17-1-000
On November 2, 2016, the FERC issued an Advanced Notice of Proposed Rulemaking, under which the FERC is proposing changes to its regulation of oil pipelines in two different areas: (1) its policies regarding the permissible scope of rate increases based on its annual issuance of changes to the generic oil pipeline index, based on specific pipelines' earnings or their specific changes to costs; and (2) the reporting requirements for page 700 of FERC Form No. 6, Annual Report of Oil Pipeline Companies. The FERC's Advanced Notice of Proposed Rulemaking does not propose specific regulations, and may be followed by a Notice of Proposed Rulemaking proposing specific regulations or a Policy Statement announcing new or changed policies. Comments have been filed with the FERC by interested parties and the proceeding is pending before the FERC.
Notice of Inquiry Regarding theon FERC's Pipeline Certificate Policy for Recovery of Income Tax Costs, Docket No. PL17-1-000Statement, PL18-1-000
On December 15, 2016,April 19, 2018, the FERC issued a Notice of Inquiry regarding whether it should revise its current policy statement on its review and authorization of natural gas pipelines under Section 7 of the FERC'sNatural Gas Act. The current policy for recoverystatement, "Certification of income tax costsNew Interstate Natural Gas Pipeline Facilities - Statement of Policy," was issued in pipeline cost of service rates.1999. The FERC sought comments regarding how to address any double recovery resulting from the FERC's current income tax allowance and rate of return policies. This Notice of Inquiry followsrequested comments in four general areas: (1) the U.S. Court of Appeals for the District of Columbia Circuit holding in United Airlines, Inc., et al. v. FERC that the FERC failedreliance on precedent agreements to demonstrate that there is no double recovery of taxesneed for a partnership pipeline as a resultproposed project; (2) the potential exercise of eminent domain and landowner interests; (3) the FERC's evaluation of alternatives and environmental effects under the National Environmental Policy Act and the Natural Gas Act; and (4) the efficiency and effectiveness of the income tax allowance and return on equity determined pursuant to the discounted cash flow methodology.FERC's certificate processes. Comments have been filed with the FERC by interested parties and the proceeding is pending before the FERC.
Examples of Our Dockets at the FERC
Rockies Express Zone 3 Capacity Enhancement Project
On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compression at one existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. As proposed, the facilities would increase the Rockies Express Zone 3 east-to-west mainline capacity by 0.8 Bcf/d. Pursuant to the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the project facilities. The project was placed in-service for the 0.8 Bcf/d on January 6, 2017.
TIGT 2015Trailblazer 2018 General Rate Case Filing
On October 30, 2015, in Docket No. RP16-137-000, et seq., TIGTJune 29, 2018, Trailblazer filed a general rate case with the FERC proposing, among other things, an increase in rates on Trailblazer's Existing System Firm Transportation Service and a decrease in rates for Expansion System Firm Transportation Service and interruptible services. On July 31, 2018, the FERC issued an Order: (1) approving the as-filed rate decreases for Expansion System Firm Transportation Service and interruptible services, effective August 1, 2018; (2) accepting and suspending the rest of the rate case filing (including the proposed rate increases) to become effective January 1, 2019 subject to refund, and establishing hearing and settlement procedures; and (3) establishing a paper hearing to examine the extent to which Trailblazer is entitled to an Income Tax Allowance. Parties have submitted briefs on the Income Tax Allowance issue and the paper hearing remains pending before the FERC. The remaining issues are currently subject to settlement judge procedures.
Cheyenne Hub Enhancement Project
On March 2, 2018, Rockies Express submitted an application pursuant to Section 4section 7(c) of the NGA.NGA for a certificate of public convenience and necessity authorizing the construction and operation of certain booster compressor units and ancillary facilities located at the Cheyenne Hub in Weld County, Colorado that will enable Rockies Express to provide a new hub service allowing for firm receipts and deliveries between Rockies Express and certain other interconnected pipelines at the Cheyenne Hub. Rockies Express filed this certificate application in conjunction with a concurrently filed certificate application by Cheyenne Connector, LLC ("Cheyenne Connector") for the Cheyenne Connector Pipeline Project further described below. The general rate case was ultimately resolvedcomment period for the Cheyenne Hub Enhancement Project closed on April 9, 2018. To date, various comments have been filed by settlement, whichmarket participants and others regarding the proposed project. Rockies Express has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC approvedissued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on November 2, 2016, and a compliance filing that modernized TIGT’s FERC Gas Tariff, consistent with prior FERC orders, whichrequests for authorizations for the proposed project. On December 18, 2018, the FERC accepted onissued the Environmental Assessment.
Cheyenne Connector Pipeline Project
On March 16, 2017. Per the terms2, 2018, Cheyenne Connector, an indirect subsidiary of TGE, submitted an application pursuant to section 7(c) of the settlement, TIGT is requiredNGA for a certificate of public convenience and necessity to fileconstruct and operate a new general rate case70-mile, 36-inch pipeline to transport natural gas from multiple gas processing plants in Weld County, Colorado to Rockies Express' Cheyenne Hub. The comment period for the Cheyenne Connector Pipeline Project closed on May 1,April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Cheyenne Connector has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 (provided that such rate case is not pre-emptedas the deadline for decisions by a pre-filing settlement).other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment.
For additional information regarding these dockets and certain other regulatory filings with the FERC, see Note 18 – Regulatory Matters.
Pipeline and Hazardous Materials Safety Administration
TEP isWe are also subject to safety regulations imposed by PHMSA, including those regulations requiring TEPus to develop and maintain integrity management programs to comprehensively evaluate certain areas along TEP'sour pipelines and take additional measures to protect pipeline segments located in areas, which are referred to as high consequence areas, or HCAs, where a leak or rupture could potentially do the most harm.
In January 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or The Pipeline Safety Act of 2011, which amended the Pipeline Safety Improvement Act of 2002, increased penalties for violations of safety laws and rules, among other matters, and may result in the imposition of more stringent regulations in the next few years. This legislation also requires the U.S. Department of Transportation to study and report to Congress on other areas of pipeline safety, including expanding the reach of the integrity management regulations beyond high consequence areas, but restricts the U.S. Department of Transportation from promulgating expanded integrity management rules during the review period and for a period following submission of its report to Congress unless the rulemaking is needed to address a present condition that poses a risk to public safety, property or the environment. PHMSA issued a final rule effective October 25, 2013 that implemented aspects of the new legislation. Among other things, the final rule increases the maximum civil penalties for violations of pipeline safety statutes or regulations, broadens PHMSA's authority to submit information requests, and provides additional detail regarding PHMSA's corrective action authority. In addition, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, or PIPES Act, reauthorized PHMSA's oil and gas pipeline programs through 2019 and gave PHMSA power to issue emergency orders upon finding an imminent hazard, required PHMSA to issue safety standards for underground natural gas storage facilities, set deadlines for conducting post-inspection briefings and making findings, required liquid pipeline operators to undertake new safety measures, and required certain updates to the PHMSA website.
Additionally, PHMSA is also currently considering changes to its regulations. On December 14, 2016, PHMSA issued an interim final rule, or IFR, that addresses safety issues related to downhole facilities, including well integrity, well bore tubing, and casing at underground natural gas storage facilities. The IFR incorporates by reference two of the American Petroleum Institute’sInstitute's Recommended Practice standards and mandates certain reporting requirements for operators of underground natural gas storage facilities. Operators of natural gas storage facilities were given one year from January 18, 2017, the effective date of the IFR, to implement this first set of PHMSA regulations governing underground storage fields. PHSMAPHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the IFR that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule. On January 13, 2017, PHMSA finalized new hazardous liquid pipeline safety regulations. Among other things, the final rule requireswould have required additional event-driven and periodic inspections, requiresrequired the use of leak detection systems on all hazardous liquid pipelines, modifiesmodified repair criteria, and requiresrequired certain pipelines to eventually accommodate in-line inspection tools. It is unclear when or ifHowever, on January 24, 2017, this rule will go into effect as, on January 20, 2017,was withdrawn for further review by the Trump Administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. Accordingly, the anticipated January 2017 rulemakingand was never published in the Federal Register.
Also, on April 8, 2016, PHMSA published a notice of proposed rule-making, or NPRM, addressing natural gas transmission and gathering lines. The proposed rule would include changes to existing integrity management requirements and would expand assessment and repair requirements to pipelines in areas with medium population densities (referred to as Moderate Consequence Areas or MCAs), along with other changes. This NPRM builds on an Advisory Bulletin PHMSA issued in May 2012, which
advised pipeline operators of anticipated changes in annual reporting requirements and that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. TIGT continues to investigate and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for maximum allowable operating pressure, or MAOP. We are currently
undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines. At the state level, several states have passed legislation or promulgated rulemaking dealing with pipeline safety. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, the addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures.
Pipeline Integrity Issues
The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline's integrity and changes to the amount of pipe determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs can have a significant impact on the costs to perform integrity testing and repairs. TEPIn July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. We will continue pipeline integrity testing programs to assess and maintain the integrity of its existing and future pipelines as required by the U.S. Department of Transportation regulations. The results of these tests could cause TEPus to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines, which expenditures could be material.
From time to time, TEP'sour pipelines may experience integrity issues. These integrity issues may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, TEPwe may be sued for damages caused by an alleged failure to properly mark the locations of itsour pipelines and/or to properly maintain itsour pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties and TEPwe may also be subject to private civil liability for such matters.
Trailblazer
Starting in 2014 Trailblazer’sTrailblazer's operating capacity was decreased as a result of smart tool surveys that identified approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing subscription levels or had a material adverse financial impact on us. However, Trailblazer intends to continuecontinued performing remediation to increase and maximize its operating capacity over the long-term and expects to spend in excess of $20spent approximately $21 million during 2018 for this pipe replacement and remediation work. As of October 2018, the pipeline was returned to its maximum allowable operating capacity. Trailblazer is exploring all possible cost recovery options to recover expenditures, including recovery through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.
In connection with TEP's acquisition of Trailblazer in April 2014, TD agreed to indemnify TEP for certain out of pocket costs related to repairing or remediating the Trailblazer Pipeline. The contractual indemnity was capped at $20 million and subject to an annual $1.5 million deductible. TEP has received the entirety of the $20 million from TD pursuant to the contractual indemnity as of December 31, 2017.
Pony Express
In connection with certain crack tool runs on the Pony Express System completed in 2015, 2016 and 2016,2017, Pony Express completed approximately $10$18 million of remediation in 2016 for anomalies identified on the Pony Express System associated with portions of the pipeline that were converted from natural gas to crude oil service, and completed additional remediation in 2017 on the Pony Express Systemservice. Remediation work was substantially complete as of approximately $8.2 million.
March 1, 2018.
Environmental, Health and Safety Matters
General
The ownership, operation and expansion of TEP'sour assets are subject to federal, state and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health. These laws and regulations can restrict or impact TEP'sour business activities in many ways, such as restricting the way TEPwe can handle or dispose of itsour wastes, requiring remedial action to mitigate pollution conditions that may be caused by itsour operations or that are attributable to former operations, regulating future construction activities to mitigate harm to threatened or endangered species, wetlands and migratory birds, and requiring the installation and operation of pollution control or seismic monitoring equipment. The cost of complying with these laws and regulations can be significant, and TEP expectswe expect to incur significant compliance costs in the future as new, more stringent requirements are adopted and implemented.
Failure to comply with existing environmental laws, regulations, permits, approvals or authorizations or to meet the requirements of new environmental laws, regulations or permits, approvals and authorizations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and/or temporary or permanent interruptions in TEP'sour operations that could influence itsour business, financial position, results of operations and prospects. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. The costs and liabilities resulting from a failure to comply with environmental laws and regulations could negatively affect TEP'sour business, financial position, results of operations and prospects. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
In addition, TEP haswe have agreed to a number of conditions in itsour environmental permits, approvals and authorizations that require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve, among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas where TEPwe currently operates,operate, and would operate in the future, and TEP iswe are unable to predict the effect that any such measures would have on itsour business, financial position, results of operations or prospects.
TEP isWe are also subject to the requirements of the Occupational Health and Safety Act, or OSHA, the Pipeline Safety Act and other comparable federal and state statutes. In general, TEP expectswe expect that it may have to increase expenditures in the future to comply with higher industry and regulatory safety standards. Such increases in expenditures could become significant over time.
Historically, TEP'sour total expenditures for environmental control measures and for remediation have not been significant in relation to TEP'sour consolidated financial position or results of operations. It is reasonably likely, however, that the long-term trend in environmental legislation and regulations will eventually move towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business.
For additional information regarding Environmental, Health and Safety Matters, please read Item 1A.—Risk Factors.
Air Emissions
TEP'sOur operations are subject to the federal Clean Air Act, or CAA, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that TEP obtainswe obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions (including GHG emissions, as discussed below), obtain and strictly comply with air permits containing various emissions and operational limitations and/or install emission control equipment. TEPWe may be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.
The EPA finalized a rule, effective August 2, 2016, under the New Source Performance Standard Program, or NSPS Program, to limit methane emissions from the oil and gas and transmission sectors. The rule sets additional emissions limits for volatile organic compounds and regulates methane emissions for new and modified sources in the oil and gas industry. TheIn October 2018, the EPA is currently reconsideringproposed a rule to reconsider and amend various requirements of the rule and has proposed to stay its requirements.NSPS standard. However, the NSPS rule currently remains in effect. The EPA also finalized a rule effective August 2, 2016 regarding the alternative criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes. EPA draft guidance issued in September 2018 clarified that this rule pertains to the oil and gas industry. Also, effective January 17, 2017, the Bureau of Land Management of the U.S. Department of the Interior, or BLM, imposed new rules to reduce venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian lands. In December 2017,This rule was suspended, stayed, and reinstated before the BLM issued a final rule in September 2018 that temporarily suspends or delays theserescinds and revises many of the requirements until January 2019, whileof the BLM considers revising or rescinding these requirements.
2017 rule. The revision rule is being challenged in the U.S. District Court for the Northern District of California but currently remains in effect.
Developments in GHG Regulations
Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas and products produced from crude oil, are examples of GHGs. The EPA has determined that the emission of GHGs presentpresents an endangerment to public health and the environment because emissions of such gases contribute to the warming of the Earth's atmosphere and other climatic changes. Various laws and regulations exist or are under development that seek to regulate the emission of such GHGs, including the EPA programs to control GHG emissions and state actions to develop statewide or regional programs. In recent years, the U.S. Congress has considered, but not adopted, legislation to reduce emissions of GHGs. There have also been efforts to regulate GHGs at an international level, most recently in the Paris Agreement, which
was signed on April 22, 2016 by 175 countries, including the United States. The Paris Agreement will require countries to review and "represent a progression" in their intended, nationally-determined contributions, which set GHG emission reduction goals every five years beginning in 2020. However, in August of 2017, the United States informed the United Nations of its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is November 2020.
Because TEP'sour operations, including itsour compressor stations, emit various types of GHGs, primarily methane and carbon dioxide, such new legislation or regulation could increase itsour costs related to operating and maintaining itsour facilities. Depending on the particular new law, regulation or program adopted, TEPwe could be required to incur capital expenditures for installing new emission controls on itsour facilities, acquire permits or other authorizations for emissions of GHGs from itsour facilities, acquire and surrender allowances for itsour GHG emissions, pay taxes related to itsour GHG emissions and administer and manage a GHG emissions program. TEP isWe are not able at this time to estimate such increased costs; however, as is the case with similarly situated entities in the industry, they could be significant to TEP.us. While TEPwe may be able to include some or all of such increased costs in the rates charged by itsour pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond itsour control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or other regulations. Similarly, while TEPwe may be able to recover some or all of such increased costs in the rates charged by itsour processing facilities, such recovery of costs is uncertain and may depend on the terms of itsour contracts with itsour customers. In addition, new laws, regulations, or programs adopted could also impact TEP'sour customers' operations or the overall demand for fossil fuels. Any of the foregoing could have an adverse effect on TEP'sour business, financial position, results of operations and prospects.
Regulation of Hydraulic Fracturing
A sizeable portion of the hydrocarbons TEP transports, processes,we transport, process, and storesstore comes from hydraulically fractured wells. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process typically involves the injection of water, sand and a small percentage of chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state's oil and gas commission; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act, or SDWA, and has released draft permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where the EPA is the permitting authority. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. In addition, some states, including those in which TEP operates,we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Other states, including states in which TEP operates,we operate, have restrictions on produced water storage from hydraulic fracturing operations and the operation of produced water disposal wells. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, and in some cases, may seek to ban hydraulic fracturing entirely. Some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing, including temporary or permanent bans, additional permit requirements, operational restrictions and chemical disclosure obligations on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for TEP'sour customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of crude oil, natural gas, and NGLs that TEP'sour customers produce, and could thereby adversely affect TEP'sour revenues and results of operations.
Hazardous Substances and Waste
TEP'sOur operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, nonhazardous and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of nonhazardous and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release or threatened release of a hazardous substance into the environment. TEPWe may handle hazardous substances within the meaning of CERCLA, or analogous state laws, in the course of itsour ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released or threatened to be released into the environment.
TEP
We also generatesgenerate wastes that are subject to the Resource Conservation and Recovery Act, or RCRA, and comparable state laws. RCRA regulates both nonhazardous and hazardous solid wastes, but it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. It is possible that wastes resulting from TEP'sour operations that are currently treated as non-hazardous wastes could be designated as "hazardous wastes" in the future, subjecting TEPus to more rigorous and costly management and disposal requirements. It is also possible that federal or state regulatory agencies will adopt stricter management or disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on TEP'sour business, financial position, results of operations and prospects or otherwise impose limits or restrictions on itsour operations or those of itsour customers.
In some cases, TEP ownswe own or leaseslease properties where hydrocarbons are being or have been handled for many years. Hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by TEPus or on or under the locations where these hydrocarbons and wastes have been transported for treatment or disposal. TEPWe could also have liability for releases or disposal on properties owned or leased by others. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, TEPwe could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners and operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.
TEP'sOur produced water disposal operations require it to comply with the Class II well standards under the federal SDWA. The SDWA imposes requirements on owners and operators of Class II wells through the EPA's Underground Injection Control program, including construction, operating, monitoring and testing, reporting and closure requirements. TEP'sOur disposal wells are also subject to comparable state laws and regulations. Compliance with current and future laws and regulations regarding TEP'sour produced water disposal wells may impose substantial costs and restrictions on itsour produced water disposal operations, as well as adversely affect demand for itsour produced water disposal services. State and federal regulatory agencies recently have focused on a possible connection between the operation of produced water injection wells used for oil and gas waste disposal and seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In some instances, operators of produced water injection wells in the vicinity of minor seismic events have been ordered to reduce produced water injection volumes or suspend operations. Regulatory agencies are continuing to study possible linkage between produced water injection activity and induced seismicity. These developments could result in additional regulation of produced water injection wells, such regulations could impose additional costs and restrictions on TEP'sour produced water disposal operations.
Federal and State Waters
The Federal Water Pollution Control Act, also known as the Clean Water Act, or the CWA, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including petroleum products, into state waters or waters of the United States. In 2015, the EPA and the U.S. Army Corps of Engineers adopted a rule to clarify the meaning of the term "waters of the United States" with respect to federal jurisdiction. This rule has been challenged in federal courts at both the appellate and district court levels. Based on a January 2018 U.S. Supreme Court decision, only the district courts were determined to have jurisdiction to hear the challenges. As a result, stays entered by district courts remain in effect, however, a stay previously issued by the Sixth Circuit is expected to be withdrawn. Accordingly, although the rule is currently stayed in several states pursuant to a district court decision, it could become effective in other states absent additional agency or judicial action. Many interested parties believe that the rule expands federal jurisdiction under the CWA. In July 2017,This rule was initially challenged in federal courts at both the EPAappellate and district court levels. It was stayed nationwide by the U.S. Army CorpCourt of Engineers publishedAppeals for the Sixth Circuit but, based on a proposedJanuary 2018 U.S. Supreme Court decision determining that only the district courts have jurisdiction to hear the challenges, the Sixth Circuit stay was withdrawn. Some federal district courts have enjoined the rule, to rescindbut the 2015 rule.rule is currently effective in over 20 states. In February 2018, the agencies also published a final rule adding a February 6, 2020 applicability date to the 2015 rule. The final rule, addingbut this applicability date is currently subjectrule was enjoined nationwide in August 2018. In December 2018, the EPA and the U.S. Army Corp of Engineers released a proposed rule to litigation. redefine the extent of CWA jurisdiction. If finalized, this rule would replace the 2015 rule defining "waters of the United States" and the scope of federal jurisdiction.
Regulations promulgated pursuant to the CWA and analogous state laws require that entities that discharge into federal and/or state waters obtain National Pollutant Discharge Elimination System, or NPDES, permits and/or state permits authorizing these discharges. The CWA and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the CWA and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. Some states also maintain groundwater
protection programs that require permits for discharges or operations that may impact groundwater. We believe that TEP iswe are in substantial compliance with the CWA permitting requirements as well as the conditions imposed thereunder and that continued compliance with such existing permit conditions will not have a material effect on itsour results of operations.
The primary federal law related to oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill provisions of the CWA and imposes certain duties and liabilities on certain "responsible parties" related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. Spill prevention, control and countermeasure requirements of federal laws and analogous state laws require TEPus to maintain spill prevention control and countermeasure plans. These laws also require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. Regulations promulgated pursuant to OPA further require certain facilities to maintain oil spill prevention and oil spill contingency plans. A liable "responsible
"responsible party" includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, TEPwe may be liable for costs and damages.
Endangered Species
The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of TEP'sour operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that TEP iswe are in substantial compliance with the ESA. However, the designation of previously unlisted endangered or threatened species could cause TEPus to incur additional costs or become subject to operating restrictions or bans or limit future development in the affected areas.
National Environmental Policy Act
The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC or other federal approval must undergo a NEPA review. A NEPA review can create delays and increased costs that could materially adversely affect TEP'sour operations.
Employee Safety
TEP isWe are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that TEP'sour operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Seasonality
Weather generally impacts natural gas demand for power generation, heating purposes and other natural gas usages, which in turn influences the value of transportation and storage. Price volatility also affects gas prices, which in turn influences drilling and production. Peak demand for natural gas typically occurs during the winter months, caused by heating demand. Nevertheless, because a high percentage of TEP'sour natural gas transportation and storage and crude oil transportation revenues are derived from firm capacity reservation fees under long-term firm fee contracts, TEP'sour revenues attributable to those segments are not generally seasonal in nature. TEP experiencesWe experience some seasonality in itsour processing segment, as volumes at itsour processing facilities are slightly higher in the summer months. TEPWe also experiencesexperience some seasonality in itsour maintenance, repair, overhaul, integrity, and other projects, as warm weather months are most conducive to efficient execution of these activities.
Title to Properties and Rights-of-Way
TEP'sOur real property generally falls into two categories: (i) parcels that it ownswe own in fee and (ii) parcels in which itsour interest derives from leases, easements, rights-of-way, permits, surface use agreements, or licenses from landowners or governmental authorities, permitting the use of such land for our operations. We believe that TEP haswe have satisfactory title to the material portions of the land on which itsour pipelines and facilities are owned by itus in fee title. The remainder of the land on which TEP'sour pipelines and facilities are located are held by itus pursuant primarily to leases, easements, rights-of-way, permits, surface use agreements or licenses between TEP,us, as grantee, and a third party, as grantor. We believe that TEP haswe have satisfactory rights to all of the material parcels in which itsour interest derives from leases, easements, rights-of-way, permits, surface use agreements, and licenses.
Insurance
We generally share insurance coverage with Tallgrass Energy Holdings for which we reimburse Tallgrass Energy Holdings and its affiliates for our share of the cost pursuant to the terms of the TEGPTGE Omnibus Agreement and an Omnibus Agreement dated May 17, 2013 entered into among TEP, TEP GP, Tallgrass Development and the general partner of Tallgrass Development (the "TEP Omnibus Agreement.Agreement"). This shared insurance program includes general and excess liability insurance, auto liability insurance, workers' compensation insurance, pollution, business interruption and property and director and officer liability insurance. All insurance coverage is in amounts which management believes are reasonable and appropriate.
Employees
We do not have any employees. We are managed and operated by the board of directors and executive officers of our general partner. All ourAs of December 31, 2018, we employed approximately 750 full-time employees are employed bythrough Tallgrass Management, LLC ("Tallgrass Management"). Prior to July 1, 2018, Tallgrass Management was a wholly-owned subsidiary of Tallgrass Energy Holdings,Holdings. Effective July 1, 2018, Tallgrass Management was contributed to Tallgrass Equity in connection with the TEP Merger. As a result, the costs of employer and devote the portion of their time to our businessdirector compensation and affairs that is reasonably required to manage and conduct our operations. benefits are now incurred directly by Tallgrass Equity.
Under the terms of the TEGPTGE Omnibus Agreement, the TEP Omnibus Agreement and our partnership agreement, we reimburse Tallgrass Energy Holdings (and its affiliates) and our general partner, respectively, for the provision of various general and administrative services for our benefit and for direct expenses incurred by Tallgrass Energy Holdings (and its affiliates) or our general partner on our behalf, including services performed and expenses incurred by our executive management personnel in connection with our business and affairs.
Available Information
We make certain filings with the SEC, including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge through our website, www.tallgrassenergy.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC's website, www.sec.gov, at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330.www.sec.gov. Our press releases and recent presentations are also available on our website.
Item 1A. Risk Factors
Limited partner interests are inherently different from shares of capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay quarterly distributionscash dividends on our Class A shares at the current distributiondividend level, or pay any distributiondividend at all, and the trading price of our Class A shares could decline. References to "us," "we," and "our" in this Item 1A refer to Tallgrass Energy GP, LP in its individual capacity.
Risks Related to Our Business
Our only cash-generating asset is a 31.43% membership interest in Tallgrass Equity and therefore ourWe may not have sufficient cash flow is entirely dependent uponfrom operations following the ability of TEP and Rockies Express to make cash distributions to Tallgrass Equity, and the ability of Tallgrass Equity to make cash distributions to us.
Our only current source of earnings and cash flow is cash distributions from Tallgrass Equity, which currently consists exclusivelyestablishment of cash distributions from TEPreserves and Rockies Express.payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the quarterly cash dividend at the current dividend level, or at all, to holders of our Class A shares.
We may not have sufficient available cash each quarter to enable us to pay the quarterly cash dividend at the current dividend level or at all. The amount of cash that TEP and Rockies Express can distribute to its owners, including Tallgrass Equity,we have available for dividends on our Class A shares principally depends upon the amount of cash each generateswe generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
the level of firm services we provide to customers pursuant to firm fee contracts and the volume of customer products we transport, store, process, gather, treat and dispose using our assets;
our ability to renew or replace expiring long-term firm fee contracts with other long-term firm fee contracts;
the creditworthiness of our customers, particularly customers who are subject to firm fee contracts;
our ability to source, complete and integrate acquisitions;
the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of natural gas, NGLs, crude oil and other hydrocarbons;
the actual and anticipated future prices, and the volatility thereof, of natural gas, crude oil and other commodities;
changes in the fees we charge for our services, including firm services and interruptible services;
our ability to identify, develop, and complete internal growth projects or expansion capital expenditures on favorable terms to improve optimization of our current assets;
regional, domestic and foreign supply and perceptions of supply of natural gas, crude oil and other hydrocarbons;
the level of demand and perceptions of demand in end-user markets we directly or indirectly serve;
applicable laws and regulations affecting our and our customers' business, including the market for natural gas, crude oil, other hydrocarbons and water, the rates we can charge on our assets, how we contract for services, our existing contracts, our operating costs or our operating flexibility;
the effect of worldwide energy conservation measures;
prevailing economic conditions;
the effect of seasonal variations in temperature and climate on the amount of customer products we are able to transport, store, process, gather, treat and dispose using our assets;
the realized pricing impacts on revenues and expenses that are directly related to commodity prices;
the level of competition from other midstream energy companies in our geographic markets;
the level of our operating and maintenance costs;
damage to our assets and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters or acts of terrorism;
outages in our assets;
the relationship between natural gas and NGL prices and resulting effect on processing margins; and
leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise.
In addition, the actual amount of cash we will have available for dividend will depend on other factors, including:
our ability to borrow funds and access capital markets;
the level, timing and characterization of capital expenditures we make;
the level of our general and administrative expenses, including reimbursements to our general partner and its business. For a descriptionaffiliates, for services provided to us;
the cost of certain factors that can cause pursuing and completing acquisitions and capital expansion projects, if any;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
restrictions contained in our debt agreements;
the amount of cash reserves established by our general partner; and
other business risks affecting our cash levels.
If we are not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, our financial condition, results of operations, cash flows and ability to make quarterly cash dividends to our Class A shareholders will be adversely affected.
A substantial majority of our contracts for transporting, storing, and processing our customers' products on our systems are long-term firm fee contracts with terms of various durations. For the year ended December 31, 2018, approximately 92% of our natural gas transportation and storage revenues were generated under firm fee transportation and storage contracts and approximately 87% of our crude oil transportation revenues were generated under firm fee transportation contracts. As of December 31, 2018, the weighted average remaining life of our long-term natural gas transportation contracts and natural gas storage contracts at TIGT and Trailblazer was approximately five years and four years, respectively, and the weighted average remaining life of our crude oil transportation contracts at Pony Express was approximately two years. In addition, a majority of Rockies Express' west-to-east pipeline capacity is subject to long-term firm fee contracts that TEPexpire in 2019 and a significant amount of Rockies Express' revenue in 2018 was derived under these contracts.
We may be unable to maintain the long-term nature and economic structure of our current contract portfolio over time. Depending on prevailing market conditions at the time of a contract renewal, our natural gas transportation, storage and processing customers with long-term fee-based contracts may desire to enter into contracts with reduced fees, and may be unwilling to enter into long-term contracts at all. In addition, a significant portion of the long-term contracts for the Pony Express Pipeline expire in 2019 and those customers may unilaterally decide whether to renew such contracts. If these contracts are not renewed, Pony Express' ability to enter into replacement long-term contracts would be limited. Under current FERC policy, Pony Express is generally prohibited from entering into new long-term contracts that grant contract shippers priorities in prorationing under the ICA unless such contract relates to an increase in the capacity of the Pony Express Pipeline.
Our ability to renew or replace our expiring contracts on terms similar to, or more attractive than, those of our existing contracts is uncertain and depends on a number of factors beyond our control, including:
the level of existing and new competition to provide competing services to our markets;
the macroeconomic factors affecting crude oil and natural gas economics for our current and potential customers;
the balance of supply and demand for natural gas, crude oil and other hydrocarbons, on a short-term, seasonal and long-term basis, in the markets we directly and indirectly serve;
the extent to which the current and potential customers in our markets are willing to provide firm fee commitments on a long-term basis; and
the effects of federal, state or local laws or regulations on the contracting practices of our customers.
During periods of price reduction and high volatility in the commodity markets, we expect customers will generally be less likely to enter into long-term firm fee contracts, and even if they enter into such contracts, may only be willing to provide acreage dedications to our assets rather than firm fee commitments. Acreage dedications typically do not require our customers to pay us unless they utilize our assets, and they may also be subject to challenge in bankruptcy proceedings.
To the extent we are unable to renew or replace our existing contracts on terms that are favorable to us or successfully manage the long-term nature and economic structure of our contract profile over time, our revenues and cash flows could decline and our ability to make quarterly cash dividends to our Class A shareholders could be materially and adversely affected.
We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial condition, cash flows, and operating results.
Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders. Our long-term firm fee contracts obligate our customers to pay demand charges regardless of whether they utilize our assets, except for certain circumstances outlined in applicable customer agreements. As a result, during the term of our long-term firm fee contracts and absent an event of force majeure, our revenues will generally depend on our customers' financial condition and their ability to pay rather than upon the extent to which our customers actually utilize our assets. Periods of price reduction and high volatility in the commodity markets could impact their ability to meet their financial obligations to us. Further, our contract counterparties may not perform or adhere to our existing or future contractual arrangements. To the extent one or more of our contract counterparties is in financial distress or commences bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material nonpayment or nonperformance by our contract counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could have a material adverse impact on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders.
For example, in 2016, Ultra Resources, Inc., or Ultra, defaulted on its firm transportation service agreement with Rockies Express for approximately 0.2 Bcf/d through November 11, 2019, and as a result, Rockies Express filed a lawsuit seeking approximately $303 million in damages and other relief. Approximately 13% of Rockies Express' revenue in 2015 was derived from the Ultra contract. In April 2016, Ultra filed for bankruptcy protection and in January 2017, Rockies Express and Ultra agreed to settle Rockies Express' claim against Ultra's bankruptcy estate. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of $150 million on July 12, 2017, and entered into a new, seven-year firm transportation agreement with Rockies Express commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate of approximately $0.37, or approximately $26.8 million annually.
In addition, Triad Hunter, LLC, or Triad, sought bankruptcy relief in December 2015. At the time Triad commenced the bankruptcy proceedings, Triad and Rockies Express generateswere parties to a precedent agreement that provided Triad with an approximate 0.1 Bcf/d of firm capacity in connection with the Rockies Express Zone 3 Capacity Enhancement Project. In order to settle its claim, Rockies Express agreed to amend certain material terms of the precedent agreement, including reducing Triad's firm capacity under the precedent agreement to an approximate 0.05 Bcf/d.
Although the Triad and Ultra claims were ultimately settled, and on terms we view as favorable, future bankruptcy proceedings with a counterparty may not result in a favorable settlement for us.
The procedures and policies we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. In accordance with FERC regulations and our own internal credit policies, counterparties with investment grade credit ratings are deemed able to meet their financial obligations to us without requiring credit support in the form of a letter of credit or prepayment. Although we generally ask for credit support from its business, please readcustomers we deem to not be creditworthy or upon a deterioration of the section entitled "Risks Relatedfinancial condition of an existing customer, some customers may be unwilling or unable to TEP'sprovide it due to liquidity constraints. To the extent our procedures and policies prove to be inadequate or we are unable to obtain credit support, our financial position and results of operations may be negatively impacted.
Some of our counterparties may be highly leveraged or have limited financial resources and are subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. As seen with the decline and volatility in crude oil prices from the second half of 2014 through the first half of 2016 and in the second half of 2018, prices for crude oil and natural gas are subject to large fluctuations in response to changes in supply and demand, market uncertainty and a variety of other factors that are beyond our control. Such volatility in commodity prices might have an impact on many of our counterparties and their ability to borrow and obtain additional capital on attractive terms, which, in turn, could have a negative impact on their ability to meet their obligations to us.
Any material nonpayment or nonperformance by our counterparties could require us to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.
We depend on certain key customers for a significant portion of our revenues and are exposed to credit risks of these customers. The loss of or material nonpayment or nonperformance by any of these key customers could adversely affect our cash flow and results of operations.
We rely on certain key customers for a portion of revenues. For example, for the year ended December 31, 2018, Continental Resources accounted for approximately 10% of our revenues on a consolidated basis. In addition, for the year ended December 31, 2018, approximately 47% of our consolidated revenues were represented by the top ten customers on our Pony Express System. We own a 75% membership interest in Rockies Express, which is not consolidated for financial reporting purposes. Approximately 18%, 13%, and 12%, respectively, of Rockies Express' Business.total revenues for the year ended December 31, 2018 were represented by Rockies Express' three largest non-affiliated shippers.
We may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms. For additional detail, see " TEP—If we are not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, our financial condition, results of operations, cash flows and ability to make quarterly cash dividends to our Class A shareholders will be adversely affected."
In addition, some of these key customers may experience financial problems that could have a significant effect on their creditworthiness. For example, Rockies Express terminated its contract with its third largest non-affiliated shipper by total 2015 revenue, Ultra, in March 2016. For more detail regarding Ultra, see "—We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial condition, cash flows, and operating results."
Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. To the extent one or more of our key customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Additionally, many of our customers finance their activities through cash flow from operations, the incurrence of indebtedness or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers' liquidity and limit their ability to make payments or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. The loss of all or even a portion of the contracted volumes of these key customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our business, cash flows, ability to make quarterly cash dividends to our Class A shareholders, the price of our Class A shares, our results of operations and ability to conduct our business.
If we are unable to make acquisitions on economically acceptable terms, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per share basis.
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per share basis.
The acquisition component of our strategy is based, in part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. Many factors could impair our access to future midstream assets. A material decrease in divestitures of midstream energy assets by industry participants would limit our opportunities for future acquisitions and could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders. Prior to February 7, 2018, Tallgrass Development was our primary source of acquisitions. Now that Tallgrass Development has divested its entire asset portfolio and merged out of existence, our growth through acquisitions will rely almost exclusively on buying assets or businesses from third parties.
Our future growth and ability to maintain or increase dividends will be limited if we are unable to make accretive acquisitions because, among other reasons, (i) we are unable to identify attractive acquisition opportunities, (ii) we are unable to negotiate acceptable purchase contracts, (iii) we are unable to obtain financing for these acquisitions on economically acceptable terms, (iv) we are outbid by competitors or (v) we are unable to obtain necessary governmental or third-party consents. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per share basis. For example, we completed a number of acquisitions in 2018, including the acquisition of an additional 25.01% membership interest in Rockies Express from Tallgrass Development, a 100% membership interest in NGL Water Solutions Bakken, LLC from NGL Energy Partners, a 51% membership interest in Pawnee Terminal from Zenith Energy, and a 38% membership interest in Deeprock North from Kinder Morgan. If certain risks or unanticipated liabilities were to arise, the desired benefits of these acquisition may not have sufficientbe fully realized and our future financial performance and results of operations could be negatively impacted.
Any acquisition involves potential risks, including, among other things:
mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;
an inability to maintain or secure adequate customer commitments to use the acquired systems or facilities;
an inability to successfully integrate the assets or businesses we acquire;
the assumption of unknown liabilities for which we are not indemnified or for which its indemnity is inadequate;
the diversion of management's and employees' attention from other business concerns;
unforeseen difficulties operating in new geographic areas or business lines; and
a decrease in liquidity and increased leverage as a result of using significant amounts of available cash or debt to continue paying distributionsfinance an acquisition.
If any acquisition eventually proves not to be accretive to our cash available for dividend per share, it could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders.
Constructing new assets subjects us to risks of project delays, cost overruns and lower-than-anticipated volumes of natural gas or crude oil once a project is completed. Our operating cash flows from our capital projects may not be immediate or meet our expectations.
One of the ways we may grow our business is by constructing additions or modifications to our existing facilities. We also may construct new facilities, either near our existing operations or in new areas. Construction projects require significant amounts of capital and involve numerous regulatory, environmental, political, legal and operational uncertainties, many of which are beyond our control. We may be unable to complete announced construction projects on schedule, at the current levelbudgeted cost, or at all, which could have a material adverse effect on our business and results of operations. For example, in June 2014, Michels Corporation, or Michels, filed a complaint and request for relief against Rockies Express as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit, and also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due. In February 2017, Rockies Express and Michels resolved the claims brought by Michels in exchange for a $10 million cash payment by Rockies Express.
Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:
denial or delay in issuing requisite regulatory approvals and/or permits, which for many of our projects includes a requirement to obtain a certificate from the FERC authorizing the project before construction can commence;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions, explosions, fires, releases) affecting our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
changes in market conditions impacting long lead-time projects;
market-related increases in a project's debt or equity financing costs; and
nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.
These projects also involve numerous economic uncertainties and the cash flow generated from these projects may not meet expectations or project estimates. Moreover, we may not receive any material increase in operating cash flow from a project for some time or at all. For instance, we incurred construction expenditures in 2018 for the construction of the Iron Horse Pipeline and the Cheyenne Connector Pipeline. However, we will not receive any increases in cash flow from these projects until such project is completed and placed in-service.
The project specifications and expectations regarding project cost, timing, asset performance, investment returns and other matters usually rely in part on the expertise of third parties such as engineers, technical experts and construction contractors. These estimates may prove to be inaccurate because of numerous operational, technological, economic and other uncertainties. We also rely in part on estimates from producers regarding the timing and volume of anticipated natural gas and crude oil production. Production estimates are subject to numerous uncertainties, nearly all of which are beyond our control. These estimates may prove to be inaccurate, and new facilities may not attract sufficient volumes to achieve our expected cash flow and investment return.
If TEP reduceswe are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make quarterly cash dividends may be diminished or our financial leverage could increase.
In order to expand our asset base through acquisitions or capital projects, we may need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash dividends. We could be required to use cash from our operations or incur borrowings or sell additional Class A shares or other limited partner interests in order to fund our expansion capital expenditures. Using cash from operations will reduce cash available for dividends to our Class A shareholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay quarterly cash dividends to our Class A shareholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant dilution of Class A shareholders and increase the aggregate amount of cash required to maintain the then-current dividend rate, which could materially decrease our ability to pay quarterly cash dividends at the then-current dividend rate. We do not currently have any commitment with our general partner or other affiliates, including Tallgrass Energy Holdings, for them to provide any direct or indirect financial assistance to us.
The Throughput and Deficiency Agreements for the Pony Express System and some of our service agreements with respect to our water business services contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.
The Throughput and Deficiency Agreements, or TDAs, for the Pony Express System and some of our service agreements with respect to our water services business are firm fee contracts with minimum volume commitments that are designed to generate stable cash flows and minimize direct commodity price risk. Under these minimum volume commitments, our customers agree to ship a minimum volume of crude oil or to have a minimum volume of water serviced, as the case may be, over certain periods during the term of the applicable agreement.
If a customer's actual throughput volumes or volumes serviced are less than its minimum volume commitment for the applicable period, it must make a deficiency payment at the end of the applicable period based upon the difference between the minimum volume commitment and the actual amounts serviced. A customer may apply any deficiency payments it makes as a credit against payment for volumes transported or serviced by us in excess of its minimum volume commitment in future periods. Upon termination of the Pony Express TDAs, customers may continue to use any remaining deficiency credits against any volumes serviced by us for a period of six months following termination, even though such customers may no longer have a minimum volume commitment.
To the extent that a customer's actual throughput volumes or volumes serviced are above its minimum volume commitment for the applicable period, the customer may use the excess volumes to credit against future deficiency payments in subsequent periods. As of December 31, 2018, Pony Express had a cumulative net deficiency balance of $97.1 million and a cumulative shipper incremental balance of $4.9 million.
Some or all of these provisions can apply in combination with one another. As a result, in the future we may not receive any cash payments for volumes shipped or serviced by us, and we may not receive deficiency payments as a result of excess volumes shipped in prior periods. This would result in reduced revenue and cash flows to us and could have a material adverse effect on our ability to make quarterly cash dividends to our Class A shareholders.
We may not be able to compete effectively in our midstream services activities and our business is subject to the risk of a capacity overbuild of midstream energy infrastructure in the areas where we operate.
We face competition in all aspects of our business and may not be able to compete effectively against our competitors. In general, competition comes from a wide variety of players in a wide variety of contexts, including new entrants and existing players and in connection with day-to-day business, expansion capital projects, acquisitions and joint venture activities. Some of our competitors have capital resources greater than ours and control greater supplies of crude oil, natural gas or NGLs.
Our ability to renew or replace our existing contracts at rates sufficient to maintain current revenues and current cash flows could be adversely affected by the activities of our competitors. Some of our competitors have assets in closer proximity to certain hydrocarbon supplies and have available idle capacity in existing assets that may require no or minimal capital investments for use. For example, several pipelines access many of the same basins as our assets and provide transport to customers in the Rocky Mountain, Appalachian Mountain and Midwest regions of the United States, such as the Dakota Access Pipeline, Saddlehorn-Grand Mesa Pipeline and White Cliffs Pipeline that compete with the Pony Express Pipeline. Pony Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers looking to capitalize on basis differentials between two primary crude oil benchmarks (West Texas Intermediate Crude and Brent Crude). Furthermore, Tallgrass Energy Holdings and its affiliates are not limited in their ability to compete with us.
Our competitors may expand or construct new midstream services assets that would create additional competition for the services we provide to our customers, or our customers may develop their own facilities in lieu of using ours. A significant driver of competition in some of the markets where we operate (including, for example, the Rocky Mountain and Appalachian Mountain regions) has been the rapid development of new midstream energy infrastructure capacity in recent years. As a result, we are exposed to the risk that the areas in which we operate become overbuilt, resulting in an excess of midstream energy infrastructure capacity. If we experience a significant capacity overbuild in one or more of the areas where we operate, it could have a significant adverse impact on our financial position, cash flows and ability to maintain or increase dividends to our Class A shareholders. For example, our competitors in these areas could substantially decrease the prices at which they offer their services, and we may be unable to compete effectively. This could materially impair our cash flows and ability to make quarterly cash dividends to our Class A shareholders.
Further, natural gas as a fuel, and fuels derived from crude oil, compete with other forms of energy available to users, including electricity, coal, other fuels and alternative energy. Increased demand for such forms of energy at the expense of natural gas or fuels derived from crude oil could lead to a reduction in demand for our services.
All of these competitive pressures could make it more difficult for us to renew our existing long-term firm fee contracts when they expire or to attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas and crude oil in the markets we serve, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions decreasing demand.
We have certain long-term fixed priced natural gas and crude oil transportation contracts that cannot be adjusted even if our costs increase. As a result, our costs could exceed our revenues.
As of December 31, 2018, approximately 53% of our contracted natural gas transportation firm capacity was provided under long-term, fixed price "negotiated or discount rate" contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts. It is possible that costs to perform services under our "negotiated or discount rate" contracts will exceed the negotiated or discounted rates. It is also possible with respect to discounted rates that if our filed "recourse rates" should ever be reduced below applicable discounted rates, we would only be allowed by the FERC to charge the lower recourse rates, since FERC policy does not allow discount rates to be charged to the extent that they exceed applicable recourse rates. If these events were to occur, it could decrease the cash flow realized by our assets and, therefore, the cash we have available for dividends to our Class A shareholders.
Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a "negotiated rate," which is generally fixed between the natural gas pipeline and the shipper for the contract term and does not necessarily vary with changes in the level of cost-based "recourse rates," provided that the affected customer is willing to agree to such rates and that the FERC has accepted the negotiated rate agreement. These "negotiated or discount rate" contracts are not generally subject to adjustment for increased costs which could be caused by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between "recourse rates" (if higher) and negotiated or discounted rates, under current FERC policy, may be recoverable from other shippers in certain circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future rate case. However, if the FERC were to disallow the recovery of such costs from other customers, it could decrease the cash flow realized by our assets and, therefore, the cash we have available for dividends to our Class A shareholders.
Rates under Pony Express' TDAs are typically subject to change only per unit distributioncontract terms and conditions, including Pony Express' right to file changes to contract rates to reflect annual index percentage adjustments published by the FERC. We generally cannot file for rate increases with respect to committed shippers who have signed TDAs, other than to reflect annual index adjustments or to recover compliance costs imposed by governmental actions.
A significant amount of the revenue currently generated by the Pony Express System and the Rockies Express reducesPipeline are from contracts that contain most favored nations rights, limiting flexibility to offer certain capacity to new shippers.
Approximately 93% of the Pony Express System's current available contractible capacity is provided to committed shippers under long-term TDAs. Some of the TDAs contain most favored nations rights, or MFNs, which could result in lower rates being charged to certain committed shippers to ensure that the rates such shippers are paying are no greater than ninety to one hundred percent of the rates being charged to other similarly situated shippers for similar service at similar volumes and terms. Triggering the MFNs on the TDAs could lead to a reduction in revenue generated by Pony Express, which could have a material adverse effect on our revenues, cash flow, results of operations, and our ability to make quarterly cash dividends to our Class A shareholders.
Rockies Express' foundation and anchor shippers for west-to-east service hold certain MFNs granting them a right to a rate reduction in certain instances where Rockies Express provides service to another shipper at a rate lower than the foundation or anchor shipper rate for a term of one year or greater or, in the case of the foundation shipper, from certain specified receipt locations. The MFNs effectively limit Rockies Express' flexibility in negotiating rates for some of its services with other shippers, because triggering the MFNs of the foundation and anchor shippers could lead to a reduction in the rates that Rockies Express charges, which could have a material adverse effect on Rockies Express' revenues, cash flow and results of operations, which in turn could impair Rockies Express' ability to make distributions to its members,equity holders and our ability to make quarterly cash dividends to our Class A shareholders.
If third-party pipelines or other facilities interconnected to our systems become partially or fully unavailable, if the volumes we transport do not meet the quality requirements of such pipelines or facilities, or if claims are made against us for events that occur downstream of our interconnection with third-party facilities, our revenues and our ability to make quarterly cash dividends to our Class A shareholders could be adversely affected.
Our assets typically connect to other pipelines or facilities owned, leased and/or operated by unaffiliated third parties, such as ONEOK Bakken Pipeline, L.L.C., Whiting Petroleum, and others. For example, our Pony Express System connects to upstream joint tariff pipelines, including the Belle Fourche Pipeline owned by the True Companies (which also own and operate the Bridger Pipeline upstream of the Belle Fourche Pipeline) and the Double H Pipeline owned by Kinder Morgan, which are responsible for delivering a substantial portion of the crude oil for transportation on the Pony Express System. In addition, part of the crude oil we transport on the Pony Express System is either stored in crude oil tanks located on, or pumped over to downstream pipelines that interconnect through, the Cushing Terminal, which we do not operate.
The continuing operation of such third-party facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable to us for any number of reasons, including because of testing, turnarounds, line repair, extended unscheduled maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements, conversion to another form of commodity transportation service, cessation of operations, curtailments of receipt or deliveries due to insufficient capacity or because of damage from weather events or other operational hazards. For example, the operations of the Bridger Pipeline's Poplar System were down for approximately five months during the first half of 2015 due to a pipeline release. Bridger declared a force majeure as a result of this event and temporarily lacked the capacity to make up volumes on other lines that directly or indirectly deliver crude oil into designated origin points on the Pony Express System or the Belle Fourche Pipeline. The largest committed shipper on the Pony Express System also declared a force majeure as a result of this incident.
In addition, our interconnection with third-party facilities may result in claims being made against us for events that occur downstream of our pipelines. For example, TIGT has been named as a defendant in a lawsuit for damages arising from a gas leak and home explosion that occurred in June 2014 in Finney County, Kansas. Although TIGT did not directly distribute natural gas to the home in question, the plaintiffs nonetheless allege that TIGT committed torts and otherwise violated federal safety laws. TIGT believes the claims are without merit and intends to vigorously defend them.
If the costs to us to access and transport on these third-party pipelines or any alternative pipelines significantly increase, if any of these pipelines or other midstream facilities become unable to receive, transport, store or process products from our assets, if the volumes we transport or process do not meet the quality requirements of such pipelines or facilities, or if claims are made against us for events that occur downstream of our interconnection with third-party facilities, our revenues and our ability to make quarterly cash flow, higher expenses, capital requirementsdividends to our Class A shareholders could be adversely affected.
The lack of diversification of our assets and geographic locations could adversely affect our ability to make quarterly cash dividends to our Class A shareholders.
We rely on revenues generated from our assets, which are primarily located in the Rocky Mountain, Appalachian Mountain and Midwest regions of the United States. Revenues on our assets primarily depend on exploration and production activities of our customers located in these regions. Due to our lack of diversification in assets and geographic location, an adverse development in these businesses or otherwise, we willour customers' areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in supply or demand for hydrocarbons, could have lessa significantly greater impact on our results of operations and cash available for distributiondividends to youour Class A shareholders than if we maintained more diverse assets and locations. For example, our water business services are provided through a limited number of assets with a relatively high concentration in Weld County, Colorado. Thus, the growth and profitability of our water business services will be especially vulnerable to conditions and fluctuations in the local Weld County economy and subject to changes in local government regulations and priorities. In addition, a number of our other assets are also located in Colorado. Certain interest groups in Colorado generally opposed to the development of oil, natural gas and NGLs, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives aimed at significantly limiting or preventing the development of oil, natural gas and NGLs. For example, a Colorado ballot initiative, Proposition 112, would likelyhave substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and gas development in the state. Although Proposition 112 was defeated in the November 2018 elections, similar efforts in Colorado, if passed, could restrict oil and gas development in the future which could result in a reduction in demand for our services.
Our operations are dependent on our rights and ability to receive or renew the required permits and other approvals from governmental authorities and other third parties.
Performance of our operations requires that we obtain and maintain numerous environmental and land use permits and other approvals authorizing our business activities. A decision by a governmental authority or other third party to deny, delay or restrictively condition the issuance of a new or renewed permit or other approval, or to revoke or substantially modify an existing permit or other approval, could have a material adverse effect on our ability to initiate or continue operations at the affected location or facility. Expansion of our existing operations and construction of new assets are both also predicated on securing the necessary environmental or land use permits and other approvals, which we may not receive in a timely manner or at all.
In order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time needed to develop a site or pipeline alignment. Also, obtaining or renewing required permits or other approvals is sometimes delayed or prevented due to community opposition and other factors beyond our control. The denial of a permit or other approval essential to our operations or the imposition of restrictive conditions with which it is not practicable or feasible to comply could impair or prevent our ability to develop or expand a property or right-of-way. Significant opposition to a permit or other approval by neighboring property owners, members of the public or non-governmental organizations, or other third parties or delay in the environmental review and permitting process also could impair or delay our ability to develop or expand a property or right-of-way. New legal requirements, including those related to the protection of the environment, could be adopted at the federal, state and local levels that could materially adversely affect our operations, our cost structure or our customers' ability to use our services. Such current or future regulations could have a material adverse effect on our business and we may not be able to obtain or renew permits or other approvals in the future.
Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect our business and results of operations.
Our business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are reduced energy demand and lower prices for our services and increased difficulty in collecting amounts owed to us by our customers which could reduce our per share distributionaccess to you. You should alsocredit markets, raise the cost of such access or require us to provide additional collateral to our counterparties. Our ability to access available capacity under the TEP revolving credit facility could be aware that theimpaired if one or more of our lenders fails to honor its contractual obligation to lend to us. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.
The amount of cash TEP haswe have available for distributiondividend to Class A shareholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making dividends, even during periods in which we record net income.
The amount of cash we have available for dividends depends primarily upon TEP's distributableour cash flow including cash flow from the release of financial reserves as well as borrowings,and not solely on profitability, which will be affected by non-cash items. As a result, TEPwe may make cash distributionsdividends during periods when it recordswe record losses for financial accounting purposes and may not make cash distributionsdividends during periods when we record net earnings for financial accounting purposes.
The revenue in our Gathering, Processing & Terminalling segment largely depends on the amount of natural gas that our customers actually deliver to our natural gas processing plants.
During the year ended December 31, 2018, approximately 12%, 51%, and 37% of TMID's Adjusted EBITDA came from firm fee, volumetric fee, and commodity sensitive contracts, respectively. On these volumetric fee contracts, our revenue is largely tied to the amount of natural gas that our customers actually deliver to our Casper and Douglas plants for processing. Unlike many pipeline transportation customers, our natural gas processing customers are not generally subject to "take or pay" obligations. Thus, if our natural gas processing customers do not produce natural gas and deliver that natural gas to our processing plants to be processed, revenue for our Gathering, Processing & Terminalling segment will decline. As natural gas, crude oil or NGL prices decline, our customers will likely make less money from the production of natural gas, crude oil or NGLs than it records profits.costs them to produce it. If that happens, our customers may not continue to produce natural gas and our revenue will decline. The decreased commodity prices in late 2014 through 2016 contributed to a significant drop in actual volumes from several producers from which TMID receives natural gas for processing. If processing volumes at TMID do not continue recovering over time, we could have an impairment of the goodwill at the TMID reporting unit, which is a component of our Gathering, Processing & Terminalling segment, and our revenue will decline. In addition, the fees our customers pay to reserve capacity at our processing plants may not deter those customers from processing their natural gas volumes at other facilities, with whom they may have had prior arrangements or otherwise.
Furthermore, Tallgrass Equity's abilityWe are exposed to distributedirect commodity price risk with respect to some of our processing revenues and the utilization of commodity derivatives by Stanchion, and our exposure to direct commodity price risk may increase in the future.
Our Gathering, Processing & Terminalling segment operates under three types of contracts, two of which directly expose our cash flows to increases and decreases in the price of natural gas and NGLs: percent of proceeds and keep whole processing contracts. We do not currently hedge the commodity exposure inherent in these types of processing contracts, and as a result, our revenues and results of operations are impacted by fluctuations in the prices of natural gas and NGLs.
Percent of proceeds processing contracts generally provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under keep whole processing contracts, our revenues and our cash flows generally increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for us to process natural gas under keep whole arrangements. When natural gas prices are high relative to NGL prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed at some of our plants. In addition, NGL prices have historically been related to the market price of oil and as a result any significant changes in oil prices could also indirectly impact our operations. Indirectly, reduced commodity prices impact us through reduced exploration and production activity, which results in fewer opportunities for new business to offset natural volume declines. NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. For example, from the second half of 2014 through the first half of 2016, natural gas and crude oil prices declined substantially and these declines directly and indirectly resulted in lower processing volumes and realizations on our percent of proceeds and keep whole processing contracts.
In 2017, we also began utilizing commodity derivatives in connection with the operations of our crude oil marketing subsidiary, Stanchion. Our portfolio of derivative and other energy contracts may consist of contracts to buy and sell commodities that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. If a performance failure were to occur in one of our contracts, we might incur losses in addition to amounts, if any, already recognized in our financial statements or paid to, or received from, counterparties. As a result, our business, results of operations, financial condition and ability to distributepay quarterly cash received from Tallgrass Equitydividends to our Class A shareholders is limited by a number of factors, including:
Tallgrass Equity's payment of costs and expenses associated with our, our general partner's, Tallgrass Energy Holdings', and Tallgrass Equity's respective operations, including expenses we incur as a result of being a public company, which costs and expenses are not subject to a limit pursuant to the TEGP Omnibus Agreement;
our payment of any income taxes;may be adversely affected.
interest expenseOur success depends on the supply and principal payments on any indebtedness incurred by TEP, Rockies Express, Tallgrass Equity, TEP GP or us;demand for natural gas and crude oil.
restrictions on distributions contained in Tallgrass Equity's, TEP's and Rockies Express' respective revolving credit facilities, the indenture governing TEP's 5.50% senior notes due 2024 and any future debt agreements entered into by Tallgrass Equity, TEP, TEP GP, Rockies Express or us;
reserves created by our general partner as necessary to permit Tallgrass Equity to make capital contributions to TEP GP, including for it to attain up to a 2.0% general partner interest in TEP; and
reserves our general partner or TEP GP establish for the proper conductThe success of our Tallgrass Equity's or TEP's business is in many ways impacted by the supply and demand for natural gas and crude oil. For example, our business can be negatively impacted by sustained downturns in supply and demand for natural gas and crude oil in the markets that we and our customers serve, including reserves to comply with applicable law or any agreement binding on us for future distributions, our subsidiaries, Tallgrass Equity, Tallgrass Equity's subsidiaries, TEP and TEP's subsidiaries, which reserves are not subject to a limit pursuant to our partnership agreement, TEP's partnership agreement or Tallgrass Equity's limited liability company agreement.
A material increasereductions in amounts paid or reserved with respect to any of these factors could restrict our ability to pay quarterly distributionsrenew contracts on favorable terms and to construct new infrastructure. Further, a portion of the demand for our water business services depends substantially on the level of expenditures by the oil and gas industry for the exploration, development and production of oil and natural gas reserves. These expenditures are generally dependent on the industry's view of future oil and natural gas prices and are sensitive to the industry's view of future economic growth and the resulting impact on demand for oil and natural gas. Declines, as well as anticipated declines, in oil and gas prices could also result in project modifications, delays or cancellations, general business disruptions, and delays in, or nonpayment of, amounts that are owed to us. These effects could have a material adverse effect on our financial condition, results of operations and cash flows.
One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation rather than alternative energy sources. One of the major factors impacting domestic natural gas and crude oil supplies has been the significant growth in unconventional sources such as shale plays and the continued progression of hydraulic fracturing technology. The supply and demand for natural gas and crude oil, and therefore the future rate of growth of our business, depends on these and many other factors outside of our control, including, but not limited to:
adverse changes in general global economic conditions;
adverse changes in domestic laws and regulations;
technological advancements that may drive further increases in production and reduction in costs of developing crude oil and natural gas shale plays;
the price and availability of other forms of energy, including alternative energy which may benefit from government subsidies;
adoption of various energy efficiency and conservation measures;
prices for natural gas, crude oil and NGLs;
decisions of the members of the Organization of the Petroleum Exporting Countries, or OPEC, regarding price and production controls;
increased costs to explore for, develop, produce, gather, process and transport natural gas or crude oil;
weather conditions, seasonal trends and hurricane disruptions;
the nature and extent of, and changes in, governmental regulation, for example GHG legislation, taxation and hydraulic fracturing;
perceptions of customers on the availability and price volatility of our services and natural gas and crude oil prices, particularly customers' perceptions on the volatility of natural gas and crude oil prices over the long-term;
capacity and transportation service into, or out of, our markets; and
petrochemical demand for NGLs.
The oil and gas industry historically has experienced periodic downturns. For example, from the second half of 2014 through the first half of 2016, the oil and gas industry experienced a sustained period of decline and volatility in natural gas and crude oil prices. Any prolonged downturns in the oil and gas industry could result in a reduction in demand for our services and could adversely affect our financial condition, results of operations and cash flows.
Any significant decrease in available supplies of hydrocarbons in our areas of operation, or redirection of existing hydrocarbon supplies to other markets, could adversely affect our business and operating results. Persistent low commodity prices could result in lower throughput volumes and reduced cash flows.
Our business is dependent on the continued availability of natural gas and crude oil production and reserves. Production from existing wells and natural gas and crude oil supply basins with access to our Class A shareholders.assets will naturally decline over time. The amount of natural gas and crude oil reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the contracted capacity and/or the volume of products utilizing our assets, our customers must continually obtain adequate supplies of natural gas and crude oil.
We
However, the development of additional natural gas and crude oil reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, storage, transportation and other facilities that permit natural gas and crude oil to be produced and products delivered to our facilities. In addition, low prices for natural gas and crude oil, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could have a material adverse effect on the development and production of additional reserves, as well as storage, pipeline transportation, and import and export of natural gas and crude oil supplies. The volatility and sustained lower prices for crude oil and refined products from the second half of 2014 through the first half of 2016 led to a decline in drilling activity, production and refining of crude oil, and import levels in these areas. For example, in response to this volatility and lower prices, a number of producers in our areas of operation significantly reduced their capital budgets and drilling plans in 2015 through 2017. Although producers in areas we serve increased their production in 2018 and are expected to continue this increase in 2019, it may limit, modify or eliminatetake a prolonged period before the incentive distributions that Tallgrass Equity is entitled to receive through its ownershipincreased production has the possibility of TEP's incentive distribution rights without the consentresulting in increased utilization of our shareholders, whichassets. In addition, production may reduce cash distributions to you.
We own a 31.43% membership interestfluctuate for other reasons, including, for example, in Tallgrass Equity, which, through its ownershipthe case of all the membership interests in TEP GP, is entitled to receive increasing percentages (up to a maximum of 48%, tocrude oil, the extent not modified or eliminated)to which the members of any cash distributedOPEC abide by TEP in excess of $0.3048 per TEP common unit in any quarter. The majority of the cash flow we received from Tallgrass Equity in 2017 was derived from its ownership of these IDRs.
TEP, likeagreements regarding production controls. Furthermore, competition for natural gas and crude oil supplies to serve other publicly traded partnerships, generally targets acquisitions or expansion capital projects that, after giving effect to related costs and expenses, would be expected to be accretive, meaning they would increase cash distributions per unit in future periods. Because Tallgrass Equity, through its ownership of TEP GP, currently participates in the IDRs at all levels, including the highest sharing level of 48%, it is harder for an acquisition or capital project to show accretion for the common unitholders of TEP than if the IDRs received less incremental cash flow. As a result, our general partner may agree to allow TEP's general partner to modify, reduce or eliminate the IDRs to facilitate a particular acquisition or expansion capital project. Any such modification, reduction or elimination of IDRs would likelymarkets could reduce the amount of cash that would have otherwise been distributed by Tallgrass Equity to us, which could in turn reduce the cash distributions we would otherwise be able to pay to you. Our shareholders are not able to vote on or otherwise prohibit TEP's general partner from modifying or eliminating the TEP IDRs,natural gas and crude oil supply available for our general partner may agree to allow TEP's general partner to reduce, modify or eliminate the IDRs without considering the interests of the holders of our Class A shares. In addition, there can be no guarantee that the expected benefits of any IDR modification, reduction or elimination will be realized.
A reduction in TEP's distributions will disproportionately affect the amount of cash distributions to which Tallgrass Equity is currently entitled.
Tallgrass Equity's indirect ownership of TEP's IDRs entitle it to receive increasing percentages, ranging from 13% up to 48%, to the extent not reduced, modified or eliminated, of all cash distributed by TEP in excess of $0.3048 per TEP common unit per quarter. A decrease in the amount of distributions paid by TEP to less than $0.4313 per TEP common unit per quarter would reduce Tallgrass Equity's percentage of incremental cash distributions in excess of $0.3048 per TEP common unit per quarter from 48% to as low as 13%. A decrease in the amount of distributions paid by TEP to less than $0.3048 per TEP common unit per quarter would result in Tallgrass Equity not receiving any incremental cash distributions with respect to the IDRs for such quarter. As a result, any such reduction in quarterly cash distributions from TEP would have the effect of disproportionately reducing the amount of distributions that Tallgrass Equity receives from TEP in respect of the IDRs as compared to cash distributions TEP makes with respect to its common units and general partner interest.
Our distributions to our Class A shareholders are not cumulative.
Our distributions to our Class A shareholders are not cumulative. Consequently, if distributions on our Class A shares are not paid with respect to any fiscal quarter then our Class A shareholders will not be entitled to receive that quarter's payments in the future.
The amount of cash that we and TEP distribute each quarter may limit our ability to grow.
Because we distribute all our available cash, our growth may not be as fast as the growth of businesses that reinvest their available cash to expand ongoing operations. In fact, because our cash flow is generated solely from distributions we receive from Tallgrass Equity, which are derived from Tallgrass Equity's direct and indirect partnership interests in TEP and its
membership interest in Rockies Express, our growth is currently completely dependent upon TEP and Rockies Express. The amount of distributions received by Tallgrass Equity, including distributions in respect of the IDRs, is based on distributions paid on each TEP common unit, the number of TEP common units outstanding, the number of TEP common units owned by Tallgrass Equity and the general partnership interest owned by TEP GP. If we issue additional Class A shares without canceling an equivalent number of Class B shares, Tallgrass Equity incurs additional debt, we incur debt or we or Tallgrass Equity are required to pay taxes, the payment of distributions on those additional Class A shares or interest on that debt or payment of such taxes could increase the risk that we will be unablecustomers. Accordingly, to maintain or increase the contracted capacity and/or the volume of products utilizing our cash distribution levels.assets, our customers must compete with others to obtain adequate supplies of natural gas and crude oil.
Our rateIf new supplies of growthnatural gas and crude oil are not obtained to replace the natural decline in volumes from existing supply basins, if natural gas and crude oil supplies are diverted to serve other markets, if environmental regulations restrict new natural gas and crude oil drilling or if OPEC does not maintain production controls, the overall demand for services on our systems will be reduced to the extent we purchase additional equity interests from TEP,likely decline, which will reduce the percentage of our cash flow that we receive from the IDRs.
Our business strategy includes, where appropriate, supporting the growth of TEP through the use of our capital resources, including by potentially purchasing TEP common units or lending funds to TEP to finance acquisitions or internal growth projects. To the extent we purchase common units or securities not entitled tocould have a current distribution from TEP, the rate of our distribution growth will be reduced, at least in the short-term, because a smaller percentage of our cash distributions would come from our ownership of the IDRs, which increase at a faster rate than TEP's common units and any similar equity interests TEP may issue in the future. For example,material adverse effect on February 7, 2018, Tallgrass Equity acquired an additional 5,619,218 TEP common units in connection with the merger of Tallgrass Development into Tallgrass Development Holdings. However, Tallgrass Equity will not receive the quarterly distribution on such units for the fourth quarter of 2017 as the record date for such distributions was January 31, 2018.
Restrictions in Tallgrass Equity's, TEP's and Rockies Express' respective revolving credit facilities and the indentures governing TEP's and Rockies Express' existing senior notes could limit Tallgrass Equity's ability to make distributions to us, thereby limiting our ability to make distributions torenew or replace our Class A shareholders. Any credit facility we enter into in the future could pose similar restrictions that would further limit our ability to make distributions.
Tallgrass Equity's, TEP'scurrent customer contracts when they expire and Rockies Express' respective revolving credit facilities and the indentures governing TEP's and Rockies Express' existing senior notes contain various operating and financial restrictions and covenants. Tallgrass Equity's, TEP's and Rockies Express' respective ability to comply with these restrictions and covenants may be affected by events beyond their control, including prevailing economic, financial and industry conditions. If Tallgrass Equity, TEP or Rockies Express is unable to comply with these restrictions and covenants, any indebtedness under these revolving credit facilities and indentures may become immediately due and payable and Tallgrass Equity's, TEP's and Rockies Express' respective lenders' commitment to make further loans under these revolving credit facilities may terminate. Tallgrass Equity, TEP and Rockies Express might not have, or be able to obtain, sufficient funds to make these accelerated payments.
Tallgrass Equity's payment of principal and interest on indebtedness reduces its cash distributions to us, thereby reducing our cash available for distribution on our Class A shares. Tallgrass Equity's revolving credit facility would effectively prevent us from paying distributions to our Class A shareholders to the extent Tallgrass Equity is prohibited from making cash distributions during an event of default or if an event of default would result from the distribution.
We may enter into a credit facility in the future that would impose similar restrictions to those discussed above. In addition, our payment of principal and interest on any future indebtedness would reduce our cash available for distribution to our Class A shares.
For more information regarding Tallgrass Equity's revolving credit facility, please see Note 11 – Long-term Debt to the Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data. For more information regarding TEP's revolving credit facility and the indentures governing TEP's existing senior notes, please see the section "—Risks Related to TEP's and Rockies' Express Business - TEP's revolving credit facility and the indentures governing TEP's existing senior notes contain certain restrictions which could adversely affect its business, financial condition, results of operations and ability to make quarterly cash distributionsdividends to our Class A shareholders.
Our natural gas, crude oil and liquids operations are subject to extensive regulation by federal, state and local regulatory authorities, which could have a material adverse effect on our business, financial condition, and results of operations.
We provide open-access interstate transportation service on our interstate natural gas transportation systems pursuant to tariffs approved by the FERC. Our interstate natural gas transportation and storage operations are regulated by the FERC, under the NGA, the NGPA, and the EPAct 2005. The Rockies Express Pipeline, the TIGT System and the Trailblazer Pipeline each operate under a tariff approved by the FERC that establishes rates and terms and conditions of service to our customers. The rates and terms of service on the Pony Express System and PRE Pipeline are subject to regulation by the FERC under the ICA, and the Energy Policy Act of 1992. We provide interstate crude oil transportation service on the Pony Express System and PRE Pipeline pursuant to tariffs on file with the FERC. Our NGL pipeline that interconnects with Overland Pass Pipeline is leased to a third party that has obtained a FERC waiver from the tariff, filing and reporting requirements of the ICA, and our NGL pipeline that interconnects with ONEOK's Bakken NGL Pipeline is leased to a third party that is obligated to operate the leased pipeline in conformance with the ICA as a FERC-regulated NGL pipeline.
Generally, the FERC's authority over natural gas facilities extends to:
rates, operating terms and conditions of service;
the form of tariffs governing service;
the types of services we may offer to our customers;
the certification and construction of new, or the expansion of existing, facilities;
the acquisition, extension, disposition or abandonment of facilities;
customer creditworthiness and credit support requirements;
the maintenance of accounts and records;
relationships among affiliated companies involved in certain aspects of the natural gas business;
depreciation and amortization policies; and
the initiation and discontinuation of services.
The FERC's authority over crude oil and NGL pipelines is less broad, extending to:
rates, rules and regulations of service;
the form of tariffs governing rates and service;
the maintenance of accounts and records; and
depreciation and amortization policies.
Interstate natural gas pipelines subject to the jurisdiction of the FERC may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust, unreasonable, unduly discriminatory, or preferential. The maximum recourse rates that we may charge for our natural gas transportation and storage services are established through the FERC's ratemaking process. The maximum applicable recourse rates and terms and conditions for service are set forth in our FERC-approved tariffs.
On June 29, 2018, Trailblazer filed a general rate case with the FERC proposing, among other things, an increase in rates on Trailblazer's Existing System Firm Transportation Service and a decrease in rates for Expansion System Firm Transportation Service and interruptible services. On July 31, 2018, the FERC issued an Order: (1) approving the as-filed rate decreases for Expansion System Firm Transportation Service and interruptible services, effective August 1, 2018; (2) accepting and suspending the rest of the rate case filing (including the proposed rate increases) to become effective January 1, 2019 subject to refund, and establishing hearing and settlement procedures; and (3) establishing a paper hearing to examine the extent to which Trailblazer is entitled to an Income Tax Allowance. Resolution of these issues remains pending before the FERC. In the event that Trailblazer is not able to recover its full cost of service as a result of the outcome of this proceeding, Trailblazer's cash flows and its results of operations could be adversely affected.
TIGT filed a general rate case with the FERC pursuant to Section 4 of the NGA in October 2015, which resulted in a settlement that was approved by an order issued by the FERC on November 2, 2016. The settlement established settlement rates to be effective through at least April 30, 2019. In the event the assumptions relied upon during settlement negotiations were incorrect or the actual costs incurred to operate the TIGT System increase, TIGT's cash flows and its results of operations could be adversely affected.
Pursuant to the NGA, existing interstate natural gas transportation and storage rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases and changes to terms and conditions of service proposed by a regulated interstate pipeline may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) "recourse rates" (i.e., the maximum cost-based rates an interstate natural gas pipeline may charge for its services under its tariff); (ii) "discount rates" (i.e., rates offered by the natural gas pipeline to shippers at discounts vis-à-vis the recourse rates and that fall within the cost-based maximum and minimum rate levels set forth in the natural gas pipeline's tariff); and (iii) "negotiated rates" (i.e., rates negotiated and agreed to by the pipeline and the shipper for the contract term that may fall within or outside of the cost-based maximum and minimum rate levels set forth in the tariff, and which are individually filed with the FERC for review and acceptance). When capacity is available and offered for sale, the rates (which include reservation, commodity, surcharges, and fixed fuel and lost and unaccounted for charges) at which such capacity is sold are subject to regulatory approval and oversight. Regulators and customers on our natural gas pipeline systems have the right to protest or otherwise challenge the rates that we charge under a process prescribed by applicable regulations. The FERC may also initiate reviews of our rates. Customers on our interstate natural gas pipeline systems may also dispute terms and conditions contained in our agreements, as well as the interpretation and application of our tariffs, among other things.
Rates for interstate crude oil transportation service must be filed as a tariff with the FERC and are subject to applicable FERC regulation. The filed tariff rates include contract rates entered into with shippers willing to make long-term commitments to the pipeline to support new pipeline capacity. Contract rates generally are not subject to regulation or change by the FERC. Non-contract "walk-up" rates are available to uncommitted non-contract shippers and generally are subject to regulation and change by the FERC. Interstate crude oil pipelines typically must reserve at least ten percent of their capacity for walk-up shippers. Contract tariff rates may be changed by Pony Express on an annual basis to reflect annual FERC index adjustments to the extent permitted by contract. Non-contract rates may be adjusted, positively or negatively, on an annual basis pursuant to a FERC indexing procedure. An interstate crude oil pipeline may also file new tariff rates at any time, subject to contract restrictions and provisions, and FERC regulatory procedures. The filing of any indexed rate increase or other rate increase may be protested by parties having standing, subject to applicable regulatory and contract provisions, and thereby be subjected to cost-of-service review by the FERC to determine whether the proposed new rate is just and reasonable.
Under the ICA, which applies to the Pony Express System and the PRE Pipeline, parties having standing and not restricted by contract may protest newly filed rates and terms and conditions of service within a prescribed notice period. Currently, shippers party to a TDA for the Pony Express System are generally limited from protesting certain rates on the Pony Express System, but this limitation will not apply to such shipper upon expiration of their TDA. The FERC is authorized to suspend, subject to refund, the effectiveness of a protested rate for up to seven months while it determines if the protested rate is just and reasonable. Our rates may be reduced and we may be required to issue refunds as a result of settlement or by an order of the FERC following a hearing finding that a protested rate is unjust and unreasonable. Parties having standing and not restricted by contract may file a complaint at any time regarding existing rates and terms and conditions of service. If the complaint is not resolved by settlement, the FERC may conduct a hearing and order the crude oil pipeline to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. We cannot guarantee that any new or existing local or joint tariff rate for service on the Pony Express System or the PRE Pipeline would not be rejected or modified by the FERC, or subjected to refunds or reparations. While the FERC regulates rates and terms and conditions of service for transportation of crude oil in interstate commerce by pipeline, state agencies may also regulate facilities (including construction, acquisition, disposition, financing, and abandonment), rates, and terms and conditions of service for crude oil pipeline transportation in intrastate commerce. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on our business, financial condition and results of operations.
Pony Express Pipeline's tariff rates may not always be eligible for increases to reflect a FERC index adjustment. For example, on November 2, 2016, the FERC issued an Advanced Notice of Proposed Rulemaking, under which the FERC is proposing changes to its unitholders.policies regarding the permissible scope of rate increases based on its annual issuance of changes to the generic oil pipeline index, based on specific pipelines' earnings or their specific changes to costs. The FERC's Advanced Notice of Proposed Rulemaking does not propose specific regulations, and may be followed by a Notice of Proposed Rulemaking proposing specific regulations or a Policy Statement announcing new or changed policies. This proceeding is pending before the FERC.
The FERC's jurisdiction over natural gas facilities extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to, acquisitions, facility maintenance and upgrades, expansions, and abandonment of facilities and services. With some exceptions applicable to smaller projects, auxiliary facilities, and certain facility replacements, prior to commencing construction and/or operation of new or existing interstate natural gas transportation and storage facilities, an interstate natural gas pipeline must obtain a certificate authorizing the construction from, or file to amend its existing certificate with, the FERC. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any delay or refusal by an agency to issue authorizations or permits as requested for one or more of these projects may mean that they will be constructed in a manner or with capital requirements that we did not anticipate or that we will not be able to pursue these projects. Such delay, modification or refusal could materially and negatively impact the additional revenues expected from these projects. The FERC does not regulate the construction, expansion, or abandonment of crude oil or NGL pipelines, whether interstate or intrastate, nor the initiation or discontinuation of services on those pipelines, provided that the action taken is not discriminatory or preferential among similarly situated shippers.
The FERC has the authority to conduct audits of regulated entities to assess compliance with FERC regulations and policies. The FERC also conducts audits to verify that the websites of interstate natural gas pipelines accurately provide information on the operations and availability of services on the pipeline. FERC regulations also require entities providing interstate natural gas and crude oil transportation services to comply with uniform terms and conditions for service, as set forth in publicly available tariffs or, as it concerns natural gas facilities, agreements for transportation and storage services executed between interstate pipelines and their customers. Natural gas transportation service agreements are generally required to conform, in all material respects, with the standard form of service agreements set forth in the natural gas pipeline's FERC-approved tariff. The pipeline and a customer may choose to enter into a non-conforming service agreement so long as the agreement is filed with, and accepted by, the FERC. In the event that the FERC finds that a natural gas transportation agreement, in whole or part, is materially non-conforming, the FERC could reject the agreement or require us to modify the agreement, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers. Transportation agreements entered into with crude oil shippers are generally not subject to FERC regulation or required to be available for FERC or public review, but the rates and terms and services provided to similarly situated shippers may not be unduly discriminatory or preferential.
The FERC has promulgated rules and policies covering many aspects of our natural gas pipeline business, including regulations that require us to provide firm and interruptible transportation service on an open access basis that is not unduly discriminatory or preferential, provide internet access to current information about our available pipeline capacity and other relevant transmission information, and permit pipeline shippers to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. FERC regulations also prevent interstate natural gas pipelines from sharing customer information with marketing affiliates, and restrict how interstate natural gas pipelines share transportation information with marketing affiliates. FERC regulations require that certain transmission function personnel of interstate natural gas pipelines function independently of personnel engaged in natural gas marketing functions. Crude oil pipelines subject to the ICA must comply with FERC regulations that require the pipeline to act as a common carrier and not engage in undue discrimination or preferential treatment with respect to shippers. The ICA also prevents crude oil and NGL pipelines from disclosing certain shipper information without the shipper's consent.
FERC policies also govern how interstate natural gas pipelines respond to interconnection requests from third party facilities, including other pipelines. Generally, an interstate natural gas pipeline must grant an interconnection request upon the satisfaction of several conditions. As a consequence, an interstate natural gas pipeline faces the risk that an interconnecting third-party pipeline may pose a risk of additional competition to serve a particular market or customer. Failure to comply with applicable provisions of the NGA, NGPA, EPAct 2005 and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of more than $1 million per day, per violation. Violations of the ICA, the Energy Policy Act of 1992, or regulations and orders promulgated by the FERC are also subject to administrative and criminal penalties and remedies, including forfeiture and individual liability.
In addition, new laws or regulations or different interpretations of existing laws or regulations applicable to our pipeline systems or midstream facilities could have a material adverse effect on our business, financial condition, results of operations and prospects. For example, on November 22, 2017, in FERC Docket No. OR17-2-000, the FERC issued an Order on Petition for Declaratory Order addressing whether certain specific hypothetical transactions between a petroleum liquids pipeline and its marketing affiliate proposed by the petitioner, Magellan Midstream Partners, L.P., would violate the requirements of the ICA or the FERC's regulations and policies. The FERC concluded that certain transactions proposed by the petitioner could be inconsistent with the ICA and the FERC's policies. Various market participants filed requests for clarification or, in the alternative, rehearing of the November 22, 2017 declaratory order. On January 22, 2018, the FERC issued an order granting rehearing for further consideration, which afforded the FERC additional time to consider and rule on the pending clarification/rehearing requests. The outcome of this proceeding and any related proceeding(s) may require us to modify the business practices between our petroleum liquids pipelines regulated by the FERC and our affiliated marketer, Stanchion. To the extent the foregoing proceedings result in substantial new restrictions on the transactions between petroleum liquids pipelines and their affiliated shippers, the business activities of Stanchion could be affected.
The FERC may also not continue to pursue its approach of pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. Further, the FERC is reviewing, and may possibly revise, its policies for analyzing whether proposed natural gas facilities are in the public convenience and necessity, including its Policy Statement on Certification of New Interstate Natural Gas Facilities issued in 1999. A change in such policies could delay or prevent the FERC's approval of proposed natural gas facilities, which could have a material impact on our business. We may face challenges to our rates or terms of service in the future. Any successful challenge could materially and adversely affect our future earnings and cash flows.
The rates and terms and conditions of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders.
Our shippers or other interested stakeholders, such as state natural gas utility regulatory agencies, may challenge the rates or the terms and conditions of service applicable to our natural gas or crude oil pipeline tariffs, unless they have entered into agreements not to challenge such tariffs. The FERC has authority to investigate our rates and terms and conditions of service pursuant to NGA Section 5 for natural gas pipelines and the ICA for common carrier oil pipelines. Our crude oil contract shippers have generally agreed not to complain or protest rates unless they are in conflict with their contracts. The FERC generally does not regulate crude oil transportation contracts, but contract rates must be filed with the FERC and tariff rules and regulations generally apply to contract shippers.
On our interstate crude oil pipeline systems, the Pony Express System and the PRE Pipeline, shippers may generally challenge new or existing rates at any time unless they have contractually agreed not to. Currently, shippers party to a TDA for the Pony Express System are generally limited from protesting certain rates on the Pony Express System, but this limitation will not apply to such shipper upon expiration of their TDA. As a result of settlement or by order of the FERC following hearing, its rates may be reduced. If a shipper files a lawful complaint, and if the complaint is not resolved with that shipper, to the extent the FERC determines after hearing that we have collected payment on rates that were not previously just and reasonable, we may be required to pay reparations to that shipper for up to two years prior to the date on which a complaint was filed. Regardless of the prospective just and reasonable rate, reparations may not be required below the last rates determined by the FERC to be just and reasonable. In other words, crude oil pipelines are not required to make reparations that refund revenues collected pursuant to rates previously determined to be just and reasonable.
The FERC has historically permitted regulated interstate crude oil and natural gas pipelines to include an income tax allowance in their cost of service used to calculate cost-based transportation rates. The allowance is intended to reflect the actual or potential tax liability attributable to the regulated entity’s operating income, regardless of the form of ownership. On July 1, 2016, in United Airlines, Inc. v FERC, the United States Court of Appeals for the D.C. Circuit vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned by a Master Limited Partnership ("MLP") to include an income tax allowance in its cost-of-service rates. The D.C. Circuit held that the FERC had failed to demonstrate that the inclusion of both an income tax allowance in the pipeline’s rates and a return on equity determined using a discounted cash flow methodology would not lead to a double-recovery of income tax costs for pipelines organized as an MLP.
Following the D.C. Circuit’s decision, the FERC issued its Revised Policy Statement on Treatment of Income Taxes in Docket No. PL17-1-000 on March 15, 2018 which eliminates the recovery of an income tax allowance by MLP crude oil and natural gas pipelines in cost-of-service-based rates. The FERC directed MLP crude oil pipelines to reflect the elimination of the income tax allowance in their Form No. 6, page 700 reporting and stated that it will incorporate the effects of this Revised Policy on industry-wide crude oil pipeline costs in the 2020 five-year review of the crude oil pipeline index level. The Commission also stated that it would address income tax allowances for other "pass-through" entities that are not MLPs in future proceedings.
While we are not an MLP, our ownership of our FERC regulated pipelines is held through our ownership in Tallgrass Equity which is a "pass-through" entity. The FERC could determine to apply the elimination of the income tax allowance to "pass-through" entities like Tallgrass Equity. To the extent that we charge cost-of-service based rates, those rates could be affected by the elimination of the income tax allowance if our rates are subject to complaint or challenge raised by shippers or by the FERC acting on its own initiative, or if we propose new cost-of-service rates or changes to our existing rates. In such instances, it is possible that certain tariff rates could be reduced, which could adversely affect our financial position, results of operations and ability to make quarterly cash dividends to our Class A shareholders.
On December 22, 2017, federal legislation known as the "Tax Cuts and Jobs Act" was enacted, which made various changes to the United States tax laws, including reducing the highest marginal U.S. federal corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017, adjusting the individual income tax brackets, and establishing limited deductions for certain income from "pass-through" entities. In late 2018, Rockies Express and TIGT each submitted one-time informational filings in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and the FERC's changes to its Income Tax Policy Statement following the decision of the U.S. Court of Appeals for the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. The FERC has indicated that it will review these filings to determine whether a pipeline's rates should be set for investigation under Section 5 of the Natural Gas Act or instead no action should be taken on the filing. The filings of Rockies Express and TIGT are pending before the FERC. If the FERC requires us to establish new tariff rates that reflect changes resulting from the Tax Cuts and Jobs Act, it is possible that certain tariff rates could be reduced, which could adversely affect our financial position, results of operations and ability to make quarterly cash dividends to our Class A shareholders.
Successful challenges to rates charged on our natural gas and crude oil pipeline systems, or to the terms and conditions of service on those systems, could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders.
We are subject to numerous hazards and operational risks.
Our operations are subject to all the risks and hazards typically associated with transportation, storage, terminalling, processing, gathering and disposing of hydrocarbons and water. These operating risks include, but are not limited to:
damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires or other adverse weather conditions and other natural disasters and acts of terrorism;
inadvertent damage from construction, vehicles, farm and utility equipment;
uncontrolled releases of crude oil, natural gas and other hydrocarbons or hazardous materials, including water from hydraulic fracturing;
leaks, migrations or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities;
outages at our facilities;
ruptures, fires, leaks and explosions; and
other hazards that could also result in personal injury and loss of life, pollution and other environmental risks, and suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of our assets, including certain segments of our pipeline systems in or near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas could increase the level of damages resulting from these risks. Despite the precautions we take, events could cause considerable harm to people or property, could result in loss of service available to customers, and could have a material adverse effect on our financial condition and results of operations and ability to make quarterly cash dividends to Class A shareholders.
For example, on January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations. However, the release required Rockies Express to shut off the flow through the segment until February 27, 2018, when temporary repairs were completed allowing the segment to be placed back into service. Permanent repairs were completed in September 2018 and the total cost of remediation was approximately $6.1 million prior to any insurance recoveries. As an additional example, approximately 10,000 bbls of crude oil were released at the Sterling Terminal in January 2017 as a result of a defective roof drain system on a storage tank. While the release was restricted to the containment area designed for such purpose and approximately 9,000 bbls were ultimately recovered, the total cost to remediate the release was approximately $600,000.
In addition, maintenance, repair and remediation activities could result in service interruptions on segments of our systems or alter the operational profile of our systems. Any such service interruption or alteration could limit our ability to satisfy customer requirements, could obligate us to provide reservation charge credits to customers for constrained capacity, or could allow existing customers to be solicited by other companies for potential new projects that would compete directly with our services.
We could be required by regulatory authorities to test or undertake modifications to our systems, operations or both that could result in a material adverse impact on our business, financial condition and results of operations. Such actions, including those required by PHMSA, could materially and adversely impact our ability to meet contractual obligations and retain customers, with a resulting material adverse impact on our business and results of operations, and could also limit or prevent our ability to make quarterly cash dividends to our Class A shareholders. Some or all of our costs arising from these operational risks may not be recoverable under insurance, contractual indemnification or increases in rates charged to our customers.
Our business could be negatively impacted by security threats, including cyber security threats, and related disruptions.
We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. We may face cyber security and other security threats to our information technology infrastructure, which could include threats to our operational and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, "hacktivists," or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cyber security threats. We could also face attempts to gain access to information related to our assets through unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information, otherwise known as "social engineering."
Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, service interruptions, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position, results of operations and prospects. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective and detective measures or to investigate and remediate any vulnerability to cyber incidents.
If we are unable to protect our information and telecommunication systems against disruptions or failures, our operations could be disrupted.
We rely extensively on computer systems to process transactions, maintain information and manage our business. Disruptions in the availability of our computer systems could impact our ability to service our customers and adversely affect our sales and results of operations. We are dependent on internal and third-party information technology networks and systems, including the Internet, wired, and wireless communications, to process, transmit and store electronic information. Our computer systems are subject to damage or interruption due to system replacements, implementations and conversions, power outages, computer or telecommunication failures, computer viruses, security breaches, catastrophic events such as fires, tornadoes, snowstorms and floods and usage errors by our employees, consultants and contractors. If our computer systems are damaged or cease to function properly, we may have to make a significant investment to fix or replace them, and we may have interruptions in our ability to service our customers. Although we attempt to reduce these risks by using redundancy for certain critical systems, this disruption caused by the unavailability of our computer systems could nevertheless significantly disrupt our operations or may result in financial damage or loss due to, among other things, lost or misappropriated information.
Violations of data protection laws may carry fines and expose us to criminal sanctions and civil suits.
We are subject to data protection laws. Complying with varying jurisdictional requirements could increase the costs and complexity of compliance, and violations of applicable data protection laws could result in significant penalties. Non-compliance with data protection laws could expose us to regulatory investigations, which could result in fines and penalties. In addition to imposing fines, regulators may also issue orders to stop processing personal data, which could disrupt operations. We could also be subject to litigation from persons or corporations allegedly affected by data protection violations. Any violation of these laws or harm to our reputation could have a material adverse effect on our business, financial condition, results of operations and prospects.
Our insurance coverage may not be adequate.
We are not insured or fully insured against all risks that could affect our business, including losses from environmental accidents or cyber security threats. For example, we do not maintain business interruption insurance in the type and amount to cover all possible losses. In addition, we do not carry insurance for certain environmental exposures, including but not limited to potential environmental fines and penalties, certain business interruptions, named windstorm or hurricane exposures and, in limited circumstances, certain political risk exposures. Further, in the event there is a total or partial loss of one or more of our insured assets, any insurance proceeds that we may receive in respect thereof may be insufficient to effect a restoration of such asset to the condition that existed prior to such loss. In addition, we are either not insured or not fully insured with respect to the legal proceedings described in Note 19 – Legal and Environmental Matters and may, depending upon the circumstances, need to pay self-insured retention amounts prior to having losses covered by the insurance providers. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates, and we have elected and may elect in the future to self-insure a portion of our risks of loss. As a result of market conditions, premiums and deductibles for certain types of insurance policies may substantially increase, and in some instances, certain types of insurance could become unavailable or available only for reduced amounts of coverage. Any insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses.
Our pipeline integrity program may impose significant costs and liabilities on us, while increased regulatory requirements relating to the integrity of our pipeline systems may require us to make additional capital and operating expenditures to comply with such requirements.
We are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal requirements set by PHMSA for owners and operators of pipelines in the areas of pipeline design, construction, and testing, the qualification of personnel and the development of operations and emergency response plans. The rules require pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as HCAs.
Our pipeline operations are subject to pipeline safety regulations administered by PHMSA. These regulations, among other things, include requirements to monitor and maintain the integrity of our pipeline systems and determine the pressures at which our pipeline systems can operate. The Pipeline Safety Act of 2011, enacted January 3, 2012, amends the Pipeline Safety Improvement Act of 2002 in a number of significant ways, including:
reauthorizing funding for federal pipeline safety programs, increasing penalties for safety violations and establishing additional safety requirements for newly constructed pipelines;
requiring PHMSA to adopt appropriate regulations within two years and requiring the use of automatic or remote- controlled shutoff valves on new or rebuilt pipeline facilities;
requiring operators of pipelines to verify MAOP and report exceedances within five days; and
requiring studies of certain safety issues that could result in the adoption of new regulatory requirements for new and existing pipelines, including changes to integrity management requirements for HCAs, and expansion of those requirements to areas outside of HCAs.
In August 2012, PHMSA published rules to update pipeline safety regulations to reflect provisions included in the Pipeline Safety Act of 2011, including increasing maximum civil penalties from $0.1 million to $0.2 million per violation per day of violation and from $1.0 million to $2.0 million as a maximum amount for a related series of violations as well as changing PHMSA's enforcement process. In November 2018, PHMSA issued a final rule that increased the per-day violation penalty from $209,002 to $213,268 and the maximum penalty for a related series of violations from $2,090,022 to $2,132,679, effective November 27, 2018. On January 13, 2017, PHMSA finalized new hazardous liquid pipeline safety regulations extending certain regulatory reporting requirements to all hazardous liquid gathering (including oil) pipelines. The final rule would have required additional event-driven and periodic inspections, required the use of leak detection systems on all hazardous liquid pipelines, modified repair criteria, and required certain pipelines to eventually accommodate in-line inspection tools. However, on January 24, 2017, this rule was withdrawn for further review by the Trump Administration and was never published in the Federal Register. In addition, on April 8, 2016, PHMSA published a notice of proposed rule-making, or NPRM, addressing natural gas transmission and gathering lines. The proposed rule would include changes to existing integrity management requirements and would expand assessment and repair requirements to pipelines in MCAs, along with other changes. Further, this NPRM would build on the requirements in an Advisory Bulletin PHMSA issued in May 2012, which advised pipeline operators of anticipated changes in annual reporting requirements and that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Comments on the NPRM were due on July 7, 2016; further action is pending. We are still monitoring and evaluating the effects of these proposed and recently finalized requirements on our operations.
The PIPES Act, enacted on June 22, 2016, reauthorized PHMSA's oil and gas pipeline programs through 2019 and provided for the following new mandates, among others:
Empowers PHMSA to issue emergency orders to individual operators, groups of operators, or the industry upon a written finding that an unsafe condition or practice constitutes or is causing an imminent hazard;
Requires PHMSA, in consultation with other federal agencies, to issue minimum safety standards for underground natural gas storage facilities within two years;
Requires PHMSA to conduct post-inspection briefings outlining any concerns within 30 days and providing written preliminary findings within 90 days to the extent practicable;
Requires liquid pipeline operators to provide safety data sheets on spilled product to the designated federal on-scene coordinator and appropriate state and local emergency responders within 6 hours of telephonic or electronic notice of an accident to the National Response Center; and
Requires PHMSA to publish updates on its website every 90 days on the status of an outstanding final rule required by a statutory mandate.
On December 14, 2016, PHMSA issued an IFR that addresses safety issues related to downhole facilities, including well integrity, well bore tubing and casing at underground natural gas storage facilities. The IFR incorporates by reference two of the American Petroleum Institute's Recommended Practice standards and mandates certain reporting requirements for operators of underground natural gas storage facilities. Operators of natural gas storage facilities were given one year from January 18, 2017, the effective date of the IFR, to implement this first set of PHMSA regulations governing underground storage fields. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the IFR that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule.
In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline.
The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline's integrity and changes to the amount of pipe determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs, such as the MCAs proposed by the April 2016 NPRM, can have a significant impact on the costs to perform integrity testing and repairs.
For example, starting in 2014, Trailblazer's operating capacity was decreased as a result of smart tool surveys that identified approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing subscription levels or had a material adverse financial impact on us. However, Trailblazer continued performing remediation to increase and maximize its operating capacity over the long-term and spent approximately $21 million during 2018 for this pipe replacement and remediation work. As of October 2018, the pipeline was returned to its maximum allowable operating capacity. Trailblazer is exploring all possible cost recovery options to recover expenditures, including recovery through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.
Additionally, in connection with certain crack tool runs on the Pony Express System completed in 2015, 2016 and 2017, Pony Express completed approximately $18 million of remediation for anomalies identified on the Pony Express System associated with portions of the pipeline converted from natural gas to crude oil service. Remediation work was substantially complete as of March 31, 2018.
There can be no assurance as to the amount or timing of future expenditures required to remediate or resolve these issues, and actual future expenditures may be different from the amounts we currently anticipate. These integrity issues could have a material adverse effect on our business, financial position, results of operations and prospects.
We will continue pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the U.S. Department of Transportation regulations. The results of these tests could cause us to incur potentially material unanticipated capital and operating expenditures for repairs or upgrades.
Further, additional laws, regulations and policies that may be enacted or adopted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. For example, PHMSA issued an Advisory Bulletin in May 2012 which advised pipeline operators that they must have records to document the MAOP for each section of their pipeline and that the records must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of verifiable pressures, could significantly increase costs. TIGT continues to investigate and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for MAOP. We are currently undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally, failure to locate such records or verify maximum pressures could require us to operate at reduced pressures, which would reduce available capacity on our natural gas pipeline systems. These specific requirements do not currently apply to crude oil pipelines, but proposed regulations implementing the Pipeline Safety Act of 2011 and future regulations implementing the PIPES Act likely will expand the scope of regulation applicable to crude oil pipelines. There can be no assurance as to the amount or timing of future expenditures required to comply with pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. In addition, we may be subject to enforcement actions and penalties for failure to comply with pipeline regulations. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial position, results of operations and prospects. In addition, we may be subject to enforcement actions and penalties for failure to comply with pipeline regulations.
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities and expenditures that could exceed our current expectations.
Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in our crude oil transportation, storage, gathering and terminalling, natural gas transportation, storage, gathering and processing, NGL transportation and water business services, and as a result, we may be required to make substantial expenditures that could exceed current expectations. Our operations are subject to extensive federal, state, and local laws and regulations governing health and safety aspects of our operations, environmental protection, including the discharge of materials into the environment, and the security of chemical and industrial facilities. These laws include, but are not limited to, the following:
CAA and analogous state and local laws, which impose obligations related to air emissions and which the EPA has relied upon as authority for adopting climate change regulatory initiatives;
CWA and analogous state and local laws, which regulate discharge of pollutants or fill material from our facilities to state and federal waters, including wetlands and which require compliance with state water quality standards;
CERCLA and analogous state and local laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;
RCRA and analogous state and local laws, which impose requirements for the handling and discharge of hazardous and nonhazardous solid waste from our facilities;
The SDWA, which ensures the quality of the nation's public drinking water through adoption of drinking water standards and controls the waste fluids from disposal wells into below-ground formations;
OSHA and analogous state and local laws, which establish workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;
NEPA and analogous state and local laws, which require federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;
The Migratory Bird Treaty Act, or MBTA, and analogous state and local laws, which implement various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;
ESA and analogous state and local laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species;
Bald and Golden Eagle Protection Act, or BGEPA, and analogous state and local laws, which prohibit anyone, without a permit issued by the Secretary of the Interior, from "taking" bald or golden eagles, including their parts, nests, or eggs, and defines "take" as "pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, molest or disturb;"
OPA and analogous state and local laws, which impose liability for discharges of oil into waters of the United States and requires facilities which could be reasonably expected to discharge oil into waters of the United States to maintain and implement appropriate spill contingency plans; and
National Historic Preservation Act, or NHPA, and analogous state and local laws, which are intended to preserve and protect historical and archeological sites.
Various governmental authorities, including but not limited to the EPA, the U.S. Department of the Interior, the U.S. Department of Homeland Security, and analogous federal, state and local agencies have the power to enforce compliance with these and other similar laws and regulations and the permits and related plans issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these and other similar laws, regulations, permits, plans and agreements may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays in granting permits.
There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products we transport, process, treat, dispose, gather or store, air emissions related to our operations, historical industry operations, and waste disposal practices, such as the prior use of flow meters and manometers containing mercury. These activities are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and natural and cultural resources. These laws and regulations can restrict or impact our business activities in many ways, such as restricting the way we handle or dispose of wastes or requiring remedial action to mitigate pollution conditions that may be caused by our operations or that are attributable to former operators. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including but not limited to CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of materials associated with oil, natural gas and wastes on, under, or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses. We are currently conducting remediation at several sites to address contamination. For these ongoing environmental remediation projects, we spent approximately $568,000 in 2017, approximately $362,000 in 2018 and we have budgeted approximately $1.1 million for 2019.
Private parties, including but not limited to the owners of properties through which our pipelines pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws, regulations and permits issued thereunder, or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage, processing, operations or other facilities, and there is a risk that contamination has migrated from those sites to ours that could result in remedial action. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance does not cover all environmental risks and costs and may not provide sufficient coverage if an environmental claim is made against us.
In June 2016, the EPA extended its National Enforcement Initiatives, enforcement priorities list, including an initiative related to Energy Extraction Activities, for 2017 through 2019, and the EPA is retaining the Energy Extraction Activities initiative for an additional three years, effective October 2016. The EPA has clarified that it will focus on significant public health and environmental problems: exposure to significant releases of volatile organic compounds, reducing non-attainment, and reducing water quality impairment. We cannot predict what the results of the current initiative or any future initiative will be, or whether federal, state or local laws or regulations will be enacted in this area. If new regulations are imposed related to oil and gas extraction, the volumes of products, including hydrocarbons and water, that we transport, store, gather, dispose and/or process could decline and our results of operations could be materially and adversely affected.
Our business may be materially and adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits or plans developed thereunder. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations, or may have to implement contingencies or conditions in order to obtain such approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation, maintenance or construction of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows. For instance, on November 25, 2014, the Wyoming Department of Environmental Quality issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Casper Gas Plant Depropanizer project. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014 and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of the CAA's NSPS Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing. Costs associated with penalties and to comply with the terms of any consent decree or settlement, as well as with Subpart OOOO, could be material.
We are also generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses. As an example, in August 2011, the EPA and the Wyoming Department of Environmental Quality conducted an inspection of the Leak Detection and Repair Program, or LDAR, at the Casper Plant in Wyoming. In September 2011, TMID received a letter from the EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the CAA. TMID received a letter from the EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. In July 2014, the EPA provided TMID with a draft Consent Decree that has been the basis for subsequent settlement negotiations. Subsequently, the EPA indicated that it intends to join TIGT as a defendant in this matter based on TIGT's ownership of the compressor station located adjacent to the Casper Gas Plant in order to address alleged LDAR issues at the compressor station. Settlement negotiations are continuing between the parties. We are not currently able to estimate the costs that may be associated with a settlement or other resolution of this matter, which could be material.
We have agreed to a number of conditions in our environmental permits and associated plans, approvals and authorizations that require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve, among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas where we currently operate, and would operate if our facilities are extended or expanded, or if we construct new facilities, and we are unable to predict the effect that any such measures would have on our business, financial position, results of operations or prospects.
Also, on June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or Corps, issued a final rule to clarify the term "waters of the United States" as it pertains to federal jurisdiction under the CWA. Many interested parties believe that the rule expands federal jurisdiction under the CWA. This rule was initially challenged in federal courts at both the appellate and district court levels. It was stayed nationwide by the U.S. Court of Appeals for the Sixth Circuit, but based on a January 2018 U.S. Supreme Court decision determining that only the district courts have jurisdiction to hear the challenges, the Sixth Circuit stay was withdrawn. Some federal district courts have enjoined the rule, but the rule is currently effective in over 20 states. In February 2018, the agencies also published a final rule adding a February 6, 2020 applicability date to the 2015 rule, but this rule was enjoined nationwide in August 2018. In December 2018, the EPA and the U.S. Army Corp of Engineers released a proposed rule to redefine the extent of CWA jurisdiction. If finalized, this rule would replace the 2015 rule defining "waters of the United States" and the scope of federal jurisdiction. Although it is unclear how or whether the Corps and the EPA will implement the 2015 rule in states in which we have operations at this time, the rule may require additional Corps or EPA authorizations or involvement in our future operations, for instance, if we extend its pipelines into or across areas (such as certain ditches) newly considered "waters of the United States" under the 2015 final rule.
Certain interest groups generally opposed to the development of oil, natural gas and NGLs, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives aimed at significantly limiting or preventing the development of oil, natural gas and NGLs. For example, a Colorado ballot initiative, Proposition 112, would have substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and gas development in the state. Although Proposition 112 was defeated in the November 2018 elections, similar efforts in Colorado or elsewhere, if passed, could restrict oil and gas development in the future which could result in a reduction in demand for our services.
The general trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be materially different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.
Climate change regulation at the federal, state or regional levels could result in increased operating and capital costs for us and reduced demand for our services.
The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. On April 22, 2016, 175 countries, including the United States, signed the Paris Agreement. The Paris Agreement will require countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in August of 2017, the United States informed the United Nations of its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is November 2020.
Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA also expanded its existing GHG emissions reporting requirements to include upstream petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year. Some of our facilities are required to report under this rule, and operational and/or regulatory changes could require additional facilities to comply with GHG emissions reporting requirements. Furthermore, the EPA adopted a final rule, effective August 2, 2016, imposing more stringent controls on methane and volatile organic compounds emissions from oil and gas development, production, and transportation operations under the New Source Performance Standard, or NSPS, program. In October 2018, the EPA proposed a rule to reconsider and amend various requirements of the NSPS standard. However, the rule currently remains in effect. In 2016, the EPA also finalized a rule regarding the alternative criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements across the oil and gas industry. The BLM also adopted new rules, effective January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. This rule was suspended, stayed, and reinstated before the BLM issued a final rule in September 2018 that rescinds and revises many of the requirements of the 2017 rule. The revision rule is being challenged in the U.S. District Court for the Northern District of California but currently remains in effect. In addition, many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.
Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, to acquire and surrender emission allowances with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.
The adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur additional costs to reduce emissions of GHGs associated with our operations, could adversely affect our operations in the absence of any permits that may be required to regulate emission of GHGs, or could adversely affect demand for the crude oil and natural gas we gather, process, or otherwise handle. For instance, the EPA's recently finalized NSPS rules or future rules under CAA Section 111(d) could result in the direct regulation of GHGs associated with our operations, including the operations of Rockies Express. We are not able at this time to estimate such increased costs; however, they could be significant. While we may be able to recover some or all of such increased costs in the rates charged by our processing facilities, such recovery of costs is uncertain and may depend on the terms of our contracts with our customers.
If new laws or regulations that significantly restrict GHGs are adopted, such laws could also make it more difficult or costly for our customers to operate, which could reduce our customers' production and therefore the demand for our services. While we are not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for us. Restrictions on GHG emissions could also reduce the volume of natural gas that our customers produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for us and our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business. In addition, to the extent financial markets view climate change and GHG emissions as a financial risk, this could materially and adversely impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change, or incentives to conserve energy or use alternative energy sources, could also affect the markets for our services by making natural gas and crude oil products less desirable than competing sources of energy. In addition, in response to concerns related to climate change, certain investors may divest oil and gas investments. For example, officials in New York state and New York City have announced their intent to divest the state and city pension funds' holdings in fossil fuel companies. Such divestments could adversely impact our costs of and access to capital.
Increased regulation of hydraulic fracturing and other oil and natural gas processing operations could affect our operations and result in reductions or delays in production by our customers, which could have a material adverse impact on our revenues.
A sizeable portion of our customers' production comes from hydraulically fractured wells. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process typically involves the injection of water, sand and a small percentage of chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state's oil and gas commission; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the SDWA and has released draft permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where the EPA is the permitting authority. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, on May 19, 2014, the EPA published an advance notice of rulemaking under the Toxic Substances Control Act, to gather information regarding the potential regulation of chemical substances and mixtures used in oil and gas exploration and production. In May 2016, the EPA issued final rules that update new source performance standard requirements and that will impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. In October 2018, the EPA proposed a rule to reconsider and amend various requirements of the NSPS standard. However, the rule currently remains in effect. The EPA also issued a final rule in June 2016 that prohibits the discharge of hydraulic fracturing wastewater from onshore unconventional oil and gas extraction facilities into publicly owned sewage treatment plants; however, facilities that were lawfully discharging this wastewater to publicly owned sewage treatment plants on April 17, 2015 have until August 29, 2019 to comply with this rule. Also, effective June 24, 2015, the BLM adopted rules regarding well stimulation, chemical disclosures, water management, and other requirements for hydraulic fracturing on federal and Indian lands. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The rescission is currently subject to legal challenge. Also, the BLM adopted new rules effective January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. This rule was suspended, stayed, and reinstated before the BLM issued a final rule in September 2018 that rescinds and revises many of the requirements of the 2017 rule. The revision rule is being challenged in the U.S. District Court for the Northern District of California but currently remains in effect.
Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, and in some cases, may seek to ban hydraulic fracturing entirely. Some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing, including temporary or permanent bans, additional permit requirements, operational restrictions and chemical disclosure obligations on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. Other governmental agencies, including the U.S. Department of Energy and the EPA, have evaluated or are evaluating various other aspects of hydraulic fracturing such as the potential environmental effects of hydraulic fracturing on drinking water and groundwater. On December 13, 2016, the EPA released a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, concluding that there is scientific evidence that hydraulic fracturing activities potentially can impact drinking water resources in the United States under some circumstances.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or significantly more costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of crude oil, natural gas or other hydrocarbons that our customers produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for us and our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business.
Our produced water disposal operations may be subject to additional regulation and liability or claims of environmental damages.
We operate produced water disposal wells which are regulated under the federal SDWA as Class II wells and under state laws. State laws and regulations that govern these operations can be more stringent than the SDWA. In addition, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may also incur material environmental costs and liabilities. Furthermore, our insurance may not provide sufficient coverage in the event an environmental claim is made against us. In addition, although the disposal wells have received certain governmental regulatory licenses, permits or approvals, this does not shield us from potential claims from third parties claiming contamination of their water supply or other environmental damages. Remediation of environmental contamination or damages can be extremely costly and such costs, if we are found liable, may have a material adverse effect on our business, financial condition and results of operations.
Produced water injection well operations and hydraulic fracturing may cause induced seismicity.
State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In a few instances, operators of produced water injection wells in the vicinity of seismic events have been ordered to reduce produced water injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado and Texas, have modified their regulations to account for induced seismicity. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In 2015, the United States Geological Study identified eight states, including Colorado, Oklahoma and Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. The USGS also produced a one-year 2017 induced seismicity model that forecast an elevated hazard from induced seismicity in Oklahoma compared to the hazard calculated for seismicity before 2009. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that produced water disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. The Oklahoma Corporation Commission, or OCC, has adopted a plan calling for mandatory reductions in oil and gas wastewater disposal well volumes, the implementation of which has involved reductions of injection or shut-ins of disposal wells. The OCC has also released guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing activities. These developments could result in additional regulation and restrictions on the use of produced water injection wells and hydraulic fracturing. Such regulations and restrictions could have a material adverse effect on our business, financial condition and results of operations.
We are exposed to costs associated with lost and unaccounted for volumes.
A certain amount of natural gas and crude oil may be lost or unaccounted for in normal operations in connection with their transportation across a pipeline system. Under our tariffs and contractual arrangements with our customers we are entitled to retain a specified volume of natural gas and crude oil in order to compensate us for such lost and unaccounted for volumes, as well as the natural gas used to run our natural gas compressor stations, which we refer to collectively as fuel usage. Our pipeline tariffs currently contain fuel usage true-up mechanisms. The use of fuel (natural gas, electric and lost and unaccounted for gas) trackers on the Rockies Express'Express Pipeline, the TIGT System, and the Trailblazer Pipeline, while minimizing risk over time, nevertheless leaves the systems exposed to the possibility of under- or over-collections on an annual basis. The level of lost and unaccounted for volumes, and natural gas fuel usage, on our pipeline systems may exceed the natural gas and crude oil volumes retained from our customers as compensation for our lost and unaccounted for volumes, and fuel usage, pursuant to our tariffs and contractual agreements, and it may be necessary to purchase natural gas or crude oil in the market to make up for the difference, which exposes us to commodity price risk. Future exposure to the volatility of natural gas and crude oil prices as a result of lost and unaccounted for volume imbalances could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash dividends to our Class A shareholders.
Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our natural gas storage business.
Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for our storage services. The natural gas storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for our services and the rates we are able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, then demand for our storage services and the prices that we will be able to charge for those services may decline.
In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated storage expansion activities. Alternatively, an extended period of low seasonal volatility in natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on our business, financial condition, results of operations and ability to make quarterly cash dividends to our Class A shareholders.
Certain portions of our transportation, storage and processing facilities have been in service for several decades. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our facilities that could have a material adverse effect on our business and results of operations.
Significant portions of our transportation, storage and processing systems have been in service for several decades. The age and condition of our facilities could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our facilities could adversely affect our business and results of operations and our ability to make quarterly cash dividends to our Class A shareholders.
The TEP revolving credit facility and the indentures governing Rockies Express' existingthe TEP senior notes please seecontain certain restrictions which could adversely affect our business, financial condition, results of operations and ability to make quarterly cash dividends to our Class A shareholders.
We are dependent upon certain earnings and cash flow generated by our operations in order to meet our debt service obligations. The TEP revolving credit facility, the sectionsindenture governing its 4.75% senior notes due 2023 (the "2023 Notes") the indenture governing its 5.50% senior notes due 2024 (the "2024 Notes"), and the indenture governing its 5.50% senior notes due 2028 (the "2028 Notes") contain, and any future financing agreements may contain, operating and financial restrictions and covenants that could restrict our ability to finance future operations or capital needs, or to expand or pursue our business activities, which may, in turn, limit our ability to make quarterly cash dividends. For example, the TEP revolving credit facility limits TEP's ability and the ability of its restricted subsidiaries to, among other things:
incur or guarantee additional indebtedness;
redeem or repurchase units or pay distributions under certain circumstances;
make certain investments and acquisitions;
incur certain liens or permit them to exist;
enter into certain types of transactions with affiliates;
merge or consolidate with another company; and
transfer, sell or otherwise dispose of assets.
The TEP revolving credit facility also contains covenants requiring TEP to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that TEP will meet those ratios and tests. Further, TEP's obligations under the revolving credit facility are (i) guaranteed by TEP and each of its existing and subsequently acquired or organized direct or indirect wholly-owned domestic subsidiaries, subject to its ability to designate certain subsidiaries as "Unrestricted Subsidiaries,"— and (ii) secured by a first priority lien on substantially all of the present and after acquired property owned by TEP and each guarantor (other than real property interests related to its pipelines).
Similarly, the indenture governing the 2024 Notes contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all its properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates.
In addition, the indentures governing the 2023 Notes and the 2028 Notes contain covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all of its properties to, another person.
The provisions of the TEP revolving credit facility and the indentures governing its senior notes may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the TEP revolving credit facility or the indentures governing its senior notes, including a failure to meet any of the required financial ratios and tests, could result in a default or an event of default that could enable its lenders or the holders of the senior notes to declare the outstanding principal of that indebtedness, together with accrued and unpaid interest, to be immediately due and payable, and in the case of the TEP revolving credit facility, would prohibit TEP's ability to make distributions. If the payment of the indebtedness under the TEP revolving credit facility is accelerated and we are unable to repay the indebtedness in full, the lenders could foreclose on the assets pledged by TEP and the guarantors under the TEP revolving credit facility. In that case, these assets may be insufficient to repay such indebtedness in full, and our Class A shareholders could experience a partial or total loss of their investment.
Our future indebtedness levels may limit our flexibility to obtain financing and to pursue other business opportunities.
Our level of indebtedness could have important consequences to us, including the following:
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
our funds available for operations, future business opportunities and dividends to Class A shareholders will be reduced by that portion of our cash flow required to make interest payments on our indebtedness;
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our indebtedness depends upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. Taking any of these actions is likely to reduce the value of an investment in us. Plus, we may not be able to effect any of these actions on satisfactory terms or at all.
Increases in interest rates could adversely impact our Class A share price, our ability to issue equity or incur indebtedness for acquisitions or other purposes and our ability to make quarterly cash dividends at our intended levels.
The interest rate on borrowings under the TEP revolving credit facility float based upon one or more of the prime rate, the U.S. federal funds rate or LIBOR. As a result, those borrowings, as well as borrowings under possible future credit facilities or debt offerings, could be higher than current levels, causing our financing costs to increase accordingly. We do not currently hedge the interest rate risk on borrowings under the TEP revolving credit facility.
As with other yield-oriented securities, our Class A share price may be impacted by the level of our cash dividend and implied dividend yield. The dividend yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our Class A shares, and a rising interest rate environment could have an adverse impact on our Class A share price, our ability to issue equity or incur indebtedness for acquisitions or other purposes and our ability to maintain or increase quarterly cash dividends on our Class A shares.
Rockies Express has a substantial amount of indebtedness and Rockies Express may not be able to generate a sufficient amount of cash flow to meet its debt service obligations."
As of January 31, 2019, Rockies Express had $1.5 billion of senior notes outstanding, of which $750 million will mature on April 15, 2020, $250 million will mature in 2038 and "—$500 million will mature in 2040. In addition, Rockies Express'Express has $525 million of outstanding indebtedness pursuant to a term loan facility that provides for a one-time principal payment due on the January 7, 2020 maturity date. Further, Rockies Express has a revolving credit facility containswith $150 million of borrowing capacity that matures on January 31, 2020.
The substantial indebtedness held by Rockies Express could have important consequences. For example, it could:
make it more difficult for Rockies Express to satisfy its obligations with respect to its indebtedness;
increase the vulnerability of Rockies Express to general adverse economic and industry conditions;
limit the ability of Rockies Express to obtain additional financing for future working capital, capital expenditures and other general business purposes;
require Rockies Express to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of cash flow for operations and other purposes;
limit its flexibility in planning for, or reacting to, changes in its business and the industry in which Rockies Express operates;
place Rockies Express at a competitive disadvantage compared to its competitors that have less indebtedness; and
have a material adverse effect if Rockies Express fails to comply with the covenants in the indenture relating to its notes or in the instruments governing its other indebtedness.
The terms of the indentures governing the existing Rockies Express notes do not restrict the amount of additional unsecured indebtedness Rockies Express may incur, and the agreements governing its term loan credit facility and revolving credit facility permit additional unsecured borrowings. If new indebtedness is added to the current indebtedness levels, these related risks could increase.
Rockies Express' ability to make scheduled payments or to refinance its obligations with respect to its indebtedness will depend on its financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business, and other factors beyond its control. In addition, a significant amount of Rockies Express' revenue in 2018 was generated by long-term contracts that expire in 2019 and Rockies Express may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis, which may result in lower cash flows in periods subsequent to 2019. We cannot assure you that Rockies Express' operating performance, cash flow and capital resources will be sufficient for payment of its indebtedness in the future. In the event that Rockies Express is required to dispose of material assets or restructure its indebtedness to meet its debt service and other obligations, we cannot assure you as to the terms of any such transaction or how soon any such transaction could be completed.
If Rockies Express' cash flow and capital resources are insufficient to fund its debt service obligations, it may be forced to sell material assets, obtain additional capital, including through capital contributions from its members, or restructure its indebtedness. The payment of additional capital contributions by us to Rockies Express to fund such obligations would reduce the amount of cash available to make dividends to our Class A shareholders.
Rockies Express' term loan credit facility and revolving credit facility contain certain restrictions which could limit its financial flexibility and increase its financing costs."
Tallgrass Equity's ownership in TEP's IDRs, TEP's common unitsRockies Express' term loan credit facility and TEP's general partner interest, are pledged under Tallgrass Equity's revolving credit facility.
Tallgrass Equity's direct ownership of the 25,619,218 TEP common units and its direct ownership of TEP's general partner (which owns the IDRs and general partner interest) are pledged as security under Tallgrass Equity's revolving credit facility. Tallgrass Equity's revolving credit facility contains customarycontain restrictive covenants that may prevent it from engaging in various transactions that Rockies Express deems beneficial and other events of default. Upon an event of default,that may be beneficial to Rockies Express. The term loan credit facility and the lenders under Tallgrass Equity's revolving credit facility could foreclosegenerally require Rockies Express to comply with various affirmative and negative covenants, including a limit on Tallgrass Equity's ownership interestthe leverage ratio (as defined in TEP GPeach credit agreement) of Rockies Express and the 25,619,218 TEP common units owned by Tallgrass Equity, which are the assets from which a significant amount of our cashrestrictions on:
incurring secured indebtedness;
flowsentering into mergers, consolidations and sales of assets;
granting liens;
entering into transactions with affiliates; and
making restricted payments.
Instruments governing any future indebtedness at Rockies Express may contain similar or more restrictive provisions. Rockies Express' ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.
We do not own most of the land on which our assets are derived. Additionally, this foreclosurelocated, which could ultimately resultdisrupt our operations and subject us to increased costs.
We do not own in fee but rather have leases, easements, rights-of-way, permits, surface use agreements, and licenses for most of the land on which our assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid interests in the land, if such interests in the land lapse or terminate or if our facilities are not properly located within the boundaries of such interests in the land. For example, the West Frenchie Draw treating facility is located on land leased from the Wyoming Board of Land Commissioners pursuant to a changecontract that can be terminated at any time. Although many of these rights are perpetual in controlnature, we occasionally obtain the right to construct and operate pipelines on other owners' land for a specific period of TEP GP,time. If we were to be unsuccessful in renegotiating our leases, easements, rights-of-way, permits, surface use agreements and licenses, we might incur increased costs to maintain our assets, which would constitute an immediate event of default under TEP's credit facility. This wouldcould have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders. In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.
Some leases, easements, rights-of-way, permits, surface use agreements and licenses for our assets are shared with other pipeline systems and other assets owned by third parties. We or owners of the other pipeline systems or assets may not have commenced or concluded eminent domain proceedings for some rights-of-way. In some instances, lands over which leases, easements, rights-of-way, permits, surface use agreements and licenses have been obtained are subject to prior liens which have not been subordinated to the grants to us.
Our interstate natural gas pipeline systems have federal eminent domain authority in certain instances. To the extent federal eminent domain authority is not available, the availability of eminent domain for future crude oil or natural gas pipeline expansions varies from state to state, depending upon the laws of the particular state and in some states it may not be available at all. Regardless, we must compensate landowners for the use of their property, which may include any loss of value to the remainder of their property not being used by us, which are sometimes referred to as "severance damages." Severance damages are often difficult to quantify and their amount can be significant. In eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our crude oil or natural gas pipeline systems are located.
A shortage of skilled labor in the midstream industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.
Our shareholders do not voteThe transportation, storage and terminalling of crude oil, the transportation, storage and processing of natural gas, and the transportation, gathering, recycling and disposal of water requires skilled laborers in the electionmultiple disciplines such as equipment operators, mechanics and engineers, among others. If we experience shortages of our general partner's directors. The Exchange Right Holders own a sufficient number of shares to allow them to prevent the removal of our general partner.
Our shareholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. The board of directors of our general partner, including our independent directors, is designated and elected by Tallgrass Energy Holdings or its designees. Our shareholders do not have the ability to elect our general partner or the members of the board of directors of our general partner.
In addition, if our Class A shareholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. Our general partner may not be removed except by vote of the holders of at least 80% of our outstanding shares, voting together as a single class. The Exchange Right Holders own 68.57% of our outstanding shares. This ownership level enables the Exchange Right Holders to prevent our general partner's removal.
As a result of these provisions, the price at which our shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
If TEP's unitholders remove TEP GP, TEP GP may be required to sell or exchange its IDRs and general partner interest and TEP GP would lose the ability to manage and control TEP.
TEP's partnership agreement gives unitholders of TEP the right to remove TEP GP upon the affirmative vote of holders of 66 2/3% of TEP's outstanding units. If TEP GP withdraws as general partner in compliance with TEP's partnership agreement or is removed as general partner of TEP where cause (as defined in TEP's partnership agreement) does not exist and a successor general partner is elected in accordance with TEP's partnership agreement, TEP GP could elect to receive cash in exchange for its IDRs and general partner interest. If TEP GP withdraws in circumstances other than those described in the preceding sentence and a successor general partner is elected in accordance with TEP's partnership agreement, the successor general partner will have the option to purchase the IDRs and general partner interest for their fair market value. If TEP GP or the successor general partner do not exercise their options, TEP GP's interests would be converted into common units based on an independent valuation. In each case, TEP GP would also lose its ability to manage TEP.
In addition, if TEP GP is removed as general partner of TEP, we would face an increased risk of being deemed an investment company. Please read the section entitled "—Ifskilled labor in the future, we cease to manageour labor and control TEP, we may be deemed to be an investment company under the Investment Company Act of 1940."
Our general partner may cause us to issue additional Class A sharesoverall productivity or other equity securities, including equity securities that are senior to our Class A shares, without your approval, which may adversely affect you.
Our general partner may cause us to issue an unlimited number of additional Class A shares, or other equity securities of equal rank with the Class A shares, without shareholder approval. In addition, we may issue an unlimited number of shares that are senior to our Class A shares in right of distribution, liquidation and voting. Except for Class A shares issued in connection with the exercise by any Exchange Right Holder of its right to exchange a Class B share for a Class A share (the "Exchange Right"), each of which will result in the cancellation of an equivalent number of Class B shares and therefore have no effect on the total number of outstanding shares, the issuance of additional Class A shares, or other equity securities of equal or senior rank, may have the following effects:
each shareholder's proportionate ownership interest in us may decrease;
the amount of cash available for distribution on each Class A share may decrease;
the relative voting strength of each previously outstanding Class A share may be diminished;
the ratio of taxable income to distributions may increase; and
the market price of the Class A shares may decline.
You may not have limited liability if a court finds that shareholder action constitutes control of our business.
Under Delaware law, youcosts could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our shareholders (who hold limited partner interests despite the fact that we use the term "shareholder" in this Annual Report) as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the "control" of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities of a limited partnership have not been clearly established in many jurisdictions.
Furthermore, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a shareholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
If in the future we cease to manage and control TEP we may be deemed to be an investment company under the Investment Company Act of 1940.
If we cease to indirectly manage and control TEP and are deemed to be an investment company under the Investment Company Act of 1940, we would have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contractual rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict the ability of TEP GP, Tallgrass Equity, TEP and us to borrow funds or engage in other transactions involving leverage, require us to add additional directors who are independent of us and our affiliates, and adversely affect the priceaffected. If our labor prices increase or if we experience materially increased health and benefit costs for employees, our results of our Class A shares.
Our partnership agreement restricts the rights of shareholders owning 20% or more of our shares.
Our shareholders' voting rights are restricted by the provision in our partnership agreement generally providing that any shares held by a person or group that owns 20% or more of any class of shares then outstanding, other than our general partner, the Exchange Right Holders or their respective affiliatesoperations could be materially and persons who acquired such shares with the prior approval of our general partner's board of directors, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our shareholders to call meetings or to acquire information about our operations, as well as other provisions limiting our shareholders' ability to influence the manner or direction of our management. As a result, the price at which our Class A shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
If TEP GP, which is owned by Tallgrass Equity, is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of TEP, its value, and, therefore, the value of our Class A shares, could decline.
TEP GP and its affiliates may make expenditures on behalf of TEP for which TEP GP will seek reimbursement from TEP. Under Delaware partnership law, TEP GP has unlimited liability for the obligations of TEP, such as its debts and environmental liabilities, except for those contractual obligations of TEP that are expressly made without recourse to the general partner. To the extent TEP GP incurs obligations on behalf of TEP, it is entitled to be reimbursed or indemnified by TEP. If TEP is unable or unwilling to reimburse or indemnify TEP GP, TEP GP may not be able to satisfy those liabilities or obligations, which would reduce TEP GP's cash distributions to Tallgrass Equity and ultimately to us for the benefit of our Class A shareholders.
Our Class A shares and TEP's common units may not trade in relation or proportion to one another.
Our Class A shares and TEP's common units may not trade in simple relation or proportion to one another. Instead, while the trading prices of our Class A shares and TEP's common units may follow generally similar broad trends, the trading prices may diverge because, among other things:
TEP's cash distributions to its common unitholders have a priority over distributions on its IDRs;
we participate in the distributions on the IDRs and general partner interest in TEP while TEP's common unitholders do not;
we expect to pay U.S. federal income taxes in the future; and
we may pursue business opportunities separate and apart from TEP or any of its affiliates.
An increase in interest rates may cause the market price of our shares to decline.
Like all equity investments, an investment in our Class A shares is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partner interests. Reduced demand for our Class A shares resulting from investors seeking other more favorable investment opportunities may cause the trading price of our Class A shares to decline.
Future sales of our Class A shares in the public market, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, could reduce our Class A share price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
Subject to certain limitations and exceptions, the Exchange Right Holders may cause the exchange of their Tallgrass Equity units (together with a corresponding number of Class B shares) for Class A shares (on a one-for-one basis, subject to customary
conversion rate adjustments for equity splits and reclassification and other similar transactions) and then sell those Class A shares. Pursuant to a shareholder and registration rights agreement entered into with the Exchange Right Holders, we have registered the resale of 109,504,440 Class A shares issuable upon exercise of the Exchange Right pursuant to our Form S-3/A (File No. 333-210976) filed with the SEC on August 8, 2016, which became effective August 10, 2016. Following such registration, certain participating Exchange Right Holders sold 10,350,000 Class A Shares in a secondary offering that closed on November 22, 2016. We may also issue additional Class A shares or convertible securities in subsequent public or private offerings. We have also agreed to register the 27,554,785 Class A shares issuable upon the exercise of the Exchange Right with respect to the 27,554,785 units and Class B Shares, respectively, issued in connection with the acquisition of the 25.01% membership interest in Rockies Express and the 5,619,218 additional TEP common units acquired by Tallgrass Equity on February 7, 2018.
We cannot predict the size of future issuances of our Class A shares or securities convertible into Class A shares or the effect, if any, that future issuances and sales of our Class A shares, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, will have on the market price of our Class A shares. Sales of substantial amounts of our Class A shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A shares.
Tallgrass Energy Holdings has sole authority to elect the board of directors of our general partner.
Tallgrass Energy Holdings has the ability to elect all of the members of our board of directors. In addition, Tallgrass Energy Holdings is able to determine the outcome of nearly all matters requiring shareholder approval, including certain mergers and other material transactions, and is able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our shareholders of an opportunity to receive a premium for their Class A shares as part of a sale of our company. Certain of the Exchange Right Holders currently own 100% of the voting interests in Tallgrass Energy Holdings and entities and/or investment funds affiliated with (i) The Energy & Minerals Group, (ii) Kelso & Company and (iii) members of our and TEP's management each have the right to designate two members of the board of managers of Tallgrass Energy Holdings for so long as they maintain certain ownership percentages in Tallgrass Energy Holdings. Tallgrass Energy Holdings currently has a six-person board of managers. Tallgrass Energy Holdings continues to be able to strongly influence all matters requiring shareholder approval, regardless of whether or not shareholders believe that the transaction is in their own best interests.
A valuation allowance on our deferred tax asset could reduce our earnings.
A significant deferred tax asset was recorded as a result of certain reorganization transactions completed in connection with the TEGP IPO. In November 2016, TEGP completed a Secondary Offering of Class A shares, which resulted in the recognition of an additional deferred tax asset. The aggregate deferred tax asset was $313.0 million as of December 31, 2017. GAAP requires that a valuation allowance must be established for deferred tax assets when it is more likely than not that they will not be realized. If we were to determine that a valuation allowance was appropriate for our deferred tax asset, we would be required to take an immediate charge to earnings with a corresponding reduction of partners' equity and increase in balance sheet leverage as measured by debt to total capitalization.
The NYSE does not require a limited partnership like us or TEP to comply with certain of its corporate governance requirements.
Because we and TEP are limited partnerships, the NYSE does not require our general partner or TEP's general partner to have a majority of independent directors on their respective board of directors. The NYSE also does not require our general partner or TEP's general partner to establish a compensation committee or a nominating and corporate governance committee. Accordingly, our shareholders and TEP's unitholders do not have the same protections afforded to certain corporations that are subject to all the NYSE corporate governance requirements. In addition, as limited partnerships, we and TEP are not required to seek shareholder or unitholder approval, as appropriate, for issuances of Class A shares or TEP common units, respectively, including issuances in excess of 20% of outstanding equity securities, or for issuances of equity to certain affiliates.
We may incur liability as a result of our ownership of TEP's general partner.
Under Delaware law, a general partner of a limited partnership is generally liable for the debts and liabilities of the partnership for which it serves as general partner, subject to the terms of any indemnification agreements contained in the partnership agreement and except to the extent the partnership's contracts are non-recourse to the general partner. As a result of our structure, we indirectly own and control the general partner of TEP. To the extent the indemnification provisions in TEP's partnership agreement or non-recourse provisions in our contracts are not sufficient to protect TEP GP from such liability, we may in the future incur liabilities as a result of our indirect ownership of TEP's general partner. Please read the section entitled "—Risks Related to Conflicts of Interest."
affected.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, shareholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A shares.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results will be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A shares.
New technologies, including those involving recycling of produced water or the replacement of water in fracturing fluid, may adversely affect our future results of operations and financial condition.
The produced water disposal industry is subject to the introduction of new waste treatment and disposal techniques and services using new technologies including those involving recycling of produced water, some of which may be subject to patent protection. As competitors and others use or develop new technologies or technologies comparable to our water business services in the future, we may lose market share or be placed at a competitive disadvantage. For example, some companies have successfully used propane as the fracturing fluid instead of water. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or products at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations or reduce the amount of waste produced in oil and natural gas drilling and production activities, thereby reducing or eliminating the need for third-party disposal. Limits on our ability to effectively use or implement new technologies, including in its water business services, may have a material adverse effect on our business, financial condition and results of operations.
Rockies Express is a joint venture and our investment could be adversely affected by our lack of sole decision-making authority.
We and TEP do not control Rockies Express through our collective ownership of a 75% membership interest. Under the limited liability company agreement of Rockies Express, as amended, substantially all matters are decided by a vote of 80% of the membership interests, other than certain fundamental decisions that require a vote of 90% of the membership interests. As a result, all the decisions of the Rockies Express members effectively require unanimous approval of all three membersus and the other member of Rockies Express, including Phillips 66. Thus, our investment in Rockies Express involves risks that are not present when we and TEP are able to exercise control over an asset, including the possibility that the unaffiliated third-party member of Rockies Express might become bankrupt, fail to fund its required capital contributions or otherwise attempt to make business decisions with respect to Rockies Express that we do not believe are in its best interest. Moreover, under the Rockies Express limited liability company agreement, we are required to provide certain capital contributions in order to fund expenditures contemplated by Rockies Express' annual budget, and may be required to provide capital contributions under certain circumstances specified in the Rockies Express limited liability company agreement if determined to be reasonably necessary by a vote of Rockies Express' members.
TheAs an unaffiliated third-party member of Rockies Express, Phillips 66 may have economic or other business interests or goals that are inconsistent with our and TEP's business interests or goals. Although we generally anticipate that we will agree with TEP on managerial decisions at Rockies Express, we do not have a voting trust or other arrangement in place requiring Tallgrass Equity and TEP to vote jointly. Plus, theThe Rockies Express limited liability company agreement expressly permits Rockies Express members (including TEP) to make decisions with respect to their ownership interest without taking into account the interests of Rockies Express or any other member of Rockies Express.
Our membership interest in Rockies Express is subject to a right of first refusal, which may make it more difficult to sell our interest in Rockies Express in the future.
Under the terms of Rockies Express' limited liability company agreement, if any member desires to transfer its membership interest to an unaffiliated third party, each other member first has a right to purchase its proportionate share of the membership interest being sold. If we desire to sell all or any portion of our interest in Rockies Express to an unaffiliated third-party in the future, we will be required to first offer the sale of our membership interest to the other members, who will have 30 days to elect to purchase their proportionate interest before any sale or transfer to a third party may be consummated. This requirement could make it difficult for us to sell our interest in Rockies Express.
Risks Inherent in an Investment in Us
Our quarterly cash dividends to our Class A shareholders are not cumulative.
Our quarterly cash dividends to our Class A shareholders are not cumulative. Consequently, if cash dividends on our Class A shares are not paid with respect to any fiscal quarter then our Class A shareholders will not be entitled to receive that quarter's payments in the future.
Our partnership agreement requires that we distribute our available cash on a quarterly basis, which could limit our ability to grow and make acquisitions.
Our partnership agreement requires us to distribute our available cash to our Class A shareholders on a quarterly basis. Accordingly, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we intend to dividend our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional shares in connection with any acquisitions or expansion capital expenditures, the payment of dividends on those additional shares may increase the risk that we will be unable to maintain or increase our per share dividend level. There are no limitations in our partnership agreement on our ability to issue additional shares, including shares ranking senior to the Class A shares. The incurrence of additional commercial borrowings or other indebtedness to finance our growth strategy would result in increased interest expense, which in turn may impact the cash available for dividends to our Class A shareholders.
If we issue additional Class A shares without canceling an equivalent number of Class B shares, Tallgrass Equity incurs additional debt, we incur debt or we or Tallgrass Equity are required to pay taxes, the payment of distributions on those additional Class A shares or interest on that debt or payment of such taxes could increase the risk that we will be unable to maintain or increase our cash dividend levels.
Restrictions in TEP's and Rockies Express' respective credit facilities and the indentures governing TEP's and Rockies Express' existing senior notes could limit Tallgrass Equity's ability to make distributions to us, thereby limiting our ability to make quarterly cash dividends to our Class A shareholders. Any credit facility we enter into in the future could pose similar restrictions that would further limit our ability to make quarterly cash dividends.
TEP's and Rockies Express' respective credit facilities and the indentures governing TEP's and Rockies Express' existing senior notes contain various operating and financial restrictions and covenants. Tallgrass Equity's, TEP's and Rockies Express' respective ability to comply with these restrictions and covenants may be affected by events beyond their control, including prevailing economic, financial and industry conditions. If TEP or Rockies Express are unable to comply with these restrictions and covenants, any indebtedness under these credit facilities and indentures may become immediately due and payable and TEP's and Rockies Express' respective lenders' commitment to make further loans under their revolving credit facilities may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.
We may enter into a credit facility in the future that would impose similar restrictions to those discussed above. In addition, our payment of principal and interest on any future indebtedness would reduce our cash available for dividends to our Class A shares.
For more information regarding the TEP revolving credit facility and the indentures governing TEP's existing senior notes, please see the section above "—The TEP revolving credit facility and the indentures governing the TEP senior notes contain certain restrictions which could adversely affect our business, financial condition, results of operations and ability to make quarterly cash dividends to our Class A shareholders." For more information regarding Rockies Express' revolving credit facility and the indentures governing Rockies Express' existing senior notes, please see the sections above "—Rockies Express has a substantial amount of indebtedness and Rockies Express may not be able to generate a sufficient amount of cash flow to meet its debt service obligations." and "—Rockies Express' term loan credit facility and revolving credit facility contain certain restrictions which could limit its financial flexibility and increase its financing costs."
Our shareholders do not vote in the election of our general partner's directors. The Exchange Right Holders own a sufficient number of shares to allow them to prevent the removal of our general partner.
Our shareholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. The board of directors of our general partner, including our independent directors, is currently designated and elected by Tallgrass Energy Holdings or its designees. Our shareholders do not have the ability to elect our general partner or the members of the board of directors of our general partner.
In addition, if our Class A shareholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. Our general partner may not be removed except by vote of the holders of at least 80% of our outstanding shares, voting together as a single class. The Exchange Right Holders own all of our Class B shares, which collectively represents 44.21% of our total outstanding Class A and Class B shares. This ownership level enables the Exchange Right Holders to prevent our general partner's removal.
As a result of these provisions, the price at which our shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
Our general partner may cause us to issue additional Class A shares or other equity securities, including equity securities that are senior to our Class A shares, without your approval, which may adversely affect you.
Our general partner may cause us to issue an unlimited number of additional Class A shares, or other equity securities of equal rank with the Class A shares, without shareholder approval. In addition, we may issue an unlimited number of shares that are senior to our Class A shares in right of dividend, liquidation and voting. Except for Class A shares issued in connection with the exercise by any Exchange Right Holder of its right to exchange a Class B share for a Class A share (the "Exchange Right"), each of which will result in the cancellation of an equivalent number of Class B shares and therefore have no effect on the total
number of outstanding shares, the issuance of additional Class A shares, or other equity securities of equal or senior rank, may have the following effects:
each shareholder's proportionate ownership interest in us may decrease;
the amount of cash available for dividends on each Class A share may decrease;
the relative voting strength of each previously outstanding Class A share may be diminished;
the date upon which we begin paying material U.S. federal income taxes, or upon which a material portion of our dividends constitute taxable dividend income for U.S. federal income tax purposes, could be accelerated; and
the market price of the Class A shares may decline.
You may not have limited liability if a court finds that shareholder action constitutes control of our business.
Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our shareholders (who hold limited partner interests despite the fact that we use the term "shareholder" in this Annual Report) as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the "control" of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities of a limited partnership have not been clearly established in many jurisdictions.
Furthermore, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a shareholder may be liable to us for the amount of a dividend for a period of three years from the date of the dividend.
Our partnership agreement restricts the rights of shareholders owning 20% or more of our shares.
Our shareholders' voting rights are restricted by the provision in our partnership agreement generally providing that any shares held by a person or group that owns 20% or more of any class of shares then outstanding, other than our general partner, the Exchange Right Holders or their respective affiliates and persons who acquired such shares with the prior approval of our general partner's board of directors, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our shareholders to call meetings or to acquire information about our operations, as well as other provisions limiting our shareholders' ability to influence the manner or direction of our management. As a result, the price at which our Class A shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
Future sales of our Class A shares in the public market, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, could reduce our Class A share price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
Subject to certain limitations and exceptions, the Exchange Right Holders may cause the exchange of their Tallgrass Equity units (together with a corresponding number of Class B shares) for Class A shares (on a one-for-one basis, subject to customary conversion rate adjustments for equity splits and reclassification and other similar transactions) and then sell those Class A shares. For example, in November 2016 certain participating Exchange Right Holders sold 10,350,000 Class A Shares in a secondary offering. Further, in accordance with a shareholder and registration rights agreement entered into with the Exchange Right Holders, we have registered the resale of 125,291,659 Class A shares issuable upon exercise of the Exchange Right pursuant to our Form S-3 (File No. 333-225382) filed with the SEC on June 1, 2018, which became effective June 13, 2018.
We may also issue additional Class A shares or convertible securities in subsequent public or private offerings. We cannot predict the size of future issuances of our Class A shares or securities convertible into Class A shares or the effect, if any, that future issuances and sales of our Class A shares, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, will have on the market price of our Class A shares. Sales of substantial amounts of our Class A shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A shares.
Tallgrass Energy Holdings currently has sole authority to elect the board of directors of our general partner, and following consummation of the Blackstone Acquisition, BIP will have such authority.
Tallgrass Energy Holdings currently has the ability to elect all of the members of our board of directors. In addition, Tallgrass Energy Holdings is able to determine the outcome of nearly all matters requiring shareholder approval, including certain mergers and other material transactions, and is able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our shareholders of an opportunity to receive a premium for their Class A shares as part of a sale of our company. Certain of the Exchange Right Holders currently own 100% of the voting interests in Tallgrass Energy Holdings and EMG, Kelso and Tallgrass KC each have the right to designate two members to the six-person board of managers of Tallgrass Energy Holdings for so long as they maintain certain ownership percentages in
Tallgrass Energy Holdings. Following consummation of the Blackstone Acquisition, BIP will own 100% of the membership interests in our general partner and will have the ability to elect all of the members of the board of directors of our general partner, subject to certain contractual rights to designate directors, including those granted to our chief executive officer, Mr. Dehaemers, to (i) designate one individual from the three specified executive officers to serve as a member of the board of directors of our general partner until December 31, 2020, for so long as Mr. Dehaemers remains a member of the board of directors of our general partner, and (ii) under certain circumstances, designate one individual to serve as an independent member of the board of directors of our general partner, for so long as Mr. Dehaemers is employed as the chief executive officer of our general partner. Prior to the Blackstone Acquisition, Tallgrass Energy Holdings continues to be able to, and following consummation of the Blackstone Acquisition, BIP will be able to, strongly influence all matters requiring shareholder approval, regardless of whether or not shareholders believe that the transaction is in their own best interests.
A valuation allowance on our deferred tax asset could reduce our earnings.
A significant deferred tax asset was recorded as a result of certain reorganization transactions completed in connection with the TGE IPO. In November 2016, we completed a Secondary Offering of Class A shares, which resulted in the recognition of an additional deferred tax asset. The aggregate deferred tax asset was $273.5 million as of December 31, 2018. GAAP requires that a valuation allowance must be established for deferred tax assets when it is more likely than not that they will not be realized. If we were to determine that a valuation allowance was appropriate for our deferred tax asset, we would be required to take an immediate charge to earnings with a corresponding reduction of partners' equity and increase in balance sheet leverage as measured by debt to total capitalization.
The NYSE does not require a limited partnership like us to comply with certain of its corporate governance requirements.
Because we are a limited partnership, the NYSE does not require our general partner to have a majority of independent directors on its board of directors. The NYSE also does not require our general partner to establish a compensation committee or a nominating and corporate governance committee. Accordingly, our shareholders do not have the same protections afforded to certain corporations that are subject to all the NYSE corporate governance requirements. In addition, as a limited partnership, we are not required to seek shareholder approval for issuances of Class A shares including issuances in excess of 20% of outstanding equity securities, or for issuances of equity to certain affiliates.
We may incur liability as a result of our ownership of TEP's general partner.
Under Delaware law, a general partner of a limited partnership is generally liable for the debts and liabilities of the partnership for which it serves as general partner, subject to the terms of any indemnification agreements contained in the partnership agreement and except to the extent the partnership's contracts are non-recourse to the general partner. As a result of our structure, we indirectly own and control the general partner of TEP. To the extent the indemnification provisions in TEP's partnership agreement or non-recourse provisions in our contracts are not sufficient to protect TEP GP from such liability, we may in the future incur liabilities as a result of our indirect ownership of TEP's general partner. Please read the section entitled "—Risks Related to Conflicts of Interest."
Risks Related to Conflicts of Interest
Our existing organizational structure and the relationships among us, TEP, our respective general partners,partner, Tallgrass Energy Holdings, the owners of Tallgrass Energy Holdings, including the Exchange Right Holders, and their affiliated entities present the potential for conflicts of interest. Moreover, additional conflicts of interest may arise in the future among us and the entities affiliated with any general partner or similar interests we acquire or among TEP and such entities.acquire.
Conflicts of interest may arise as a result of our organizational structure and the relationships among us, TEP, our respective general partners, TEGP,partner, and its direct and indirect owners, which include Tallgrass Energy Holdings, the owners of Tallgrass Energy Holdings, including the Exchange Right Holders, and their affiliated entities.entities prior to the Blackstone Acquisition, and BIP, GIC SI and their affiliated entities following consummation of the Blackstone Acquisition.
Our partnership agreement defines the duties of our general partner (and, by extension, its officers and directors). Our general partner's board of directors or its conflicts committee has authority on our behalf to resolve any conflict involving us and they have broad latitude to consider the interests of all parties to the conflict.
Conflicts of interest may arise between us and our shareholders, on the one hand, and our general partner and its direct and indirect owners, includingon the other hand, which include Tallgrass Energy Holdings and the Exchange Right Holders, and affiliated entities onprior to the other hand,
or between usBlackstone Acquisition, and our shareholders, onBIP, GIC SI and their affiliated entities following consummation of the one hand, and TEP and its unitholders, on the other hand.Blackstone Acquisition. The resolution of these conflicts may not always be in our best interest or that of our shareholders.
Certain of the Exchange Right Holders own 100% of the voting interests in Tallgrass Energy Holdings and the Exchange Right Holders hold a majoritycontrol all of our Class B shares, which represents approximately 44.21% of the combined voting power of our Class A and Class B shares.
CertainAs of February 8, 2019, certain of the Exchange Right Holders own 100% of the voting interests in Tallgrass Energy Holdings and the Exchange Right Holders hold Class B shares representing approximately 68.57%44.21% of the combined voting power of our Class A and Class B shares. Although each of the Exchange Right Holders are entitled to act separately in their own respective interests with respect to their ownership interest in Tallgrass Energy Holdings and us, certain of the Exchange Right Holders collectively have the ability to elect all the members of Tallgrass Energy Holdings' board of managers, each of whom also serves as a member of the board of directors of our general partner. So long as any of the Exchange Right Holders continue to own a significant amount of the voting interests in Tallgrass Energy Holdings, they will continue to be able to control our management and affairs.
Tallgrass Energy Holdings may have Following consummation of the Blackstone Acquisition, BIP will own 100% of the membership interests that conflict with holdersin our general partner, and will, subject to certain contractual restrictions, control approximately 44% of the combined voting power of our Class A shares.
Tallgrass Energy Holdings owns our general partnershares and may have conflicting interests with holders of Class AB shares.
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Tallgrass Energy Holdings or TEP, on the other hand, concerning, among other things, a decision whether to modify or limit the IDRs in the future or potential competitive business activities or business opportunities. These conflicts of interest may not be resolved in our favor.
Our partnership agreement replaces our general partner's fiduciary duties to holders of our Class A shares with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our shareholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the shareholders where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our shareholders. Examples of decisions that our general partner may make in its individual capacity include:
how to allocate business opportunities among us and its affiliates;
whether to exercise its limited call right;
whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;
how to exercise its voting rights with respect to the units it owns; and
whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the partnership agreement.
In addition, our partnership agreement provides that any construction or interpretation of our partnership agreement and any action taken pursuant thereto or any determination, in each case, made by our general partner in good faith, shall be conclusive and binding on all shareholders.
By purchasing shares, you agree to become bound by the provisions in the partnership agreement, including the provisions discussed above.
Our partnership agreement restricts the remedies available to holders of our Class A shares for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to shareholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as
specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
our general partner will not have any liability to us or our shareholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our shareholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
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| ◦ | approved by the conflicts committee of the board of directors of our general partner (although our general partner is not obligated to seek such approval); |
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| ◦ | approved by the vote of a majority of the outstanding voting shares, excluding any shares owned by our general partner and its affiliates; |
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| ◦ | determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
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| ◦ | determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our shareholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the last two bullets above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our general partner's affiliates and Tallgrass Energy Holdings may compete with us.
Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. The restrictions contained in our general partner's limited liability company agreement are subject to a number of exceptions. For example, affiliates of our general partner, including Tallgrass Energy Holdings, the Exchange Right Holders, and their respective affiliates, including Kelso and EMG, are not prohibited from engaging in other businesses or activities that might be in direct competition with us.
Our general partner has a call right that may require you to sell your Class A shares at an undesirable time or price.
If at any time more than 80% of our outstanding shares (including Class A shares issuable upon the exchange of Class B shares) are owned by our general partner, Tallgrass Energy Holdings or their respective affiliates, our general partner has the right (which it may assign to any of its affiliates, Tallgrass Energy Holdings or us), but not the obligation, to acquire all, but not less than all, of the remaining Class A shares held by public shareholders at a price equal to the greater of (x) the highest cash price paid by our general partner, Tallgrass Energy Holdings, or their respective affiliates for any shares purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those shares and (y) the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed. As a result, you may be required to sell your Class A shares at an undesirable time or price and may not receive any return of or on your investment. You may also incur a tax liability upon a sale of your Class A shares.
Risks Related to TEP's and Rockies Express' Business
TEP may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to its general partner and its affiliates, to enable TEP to pay the quarterly distribution at the current distribution level, or at all, to holders of its common units.
TEP may not have sufficient available cash from operating surplus each quarter to enable it to pay the quarterly distribution at the current distribution level, at the minimum quarterly distribution level, or at all. The amount of cash TEP can distribute on its units principally depends upon the amount of cash TEP generates from its operations, which will fluctuate from quarter to quarter based on, among other things:
the level of firm services TEP provides to customers pursuant to firm fee contracts and the volume of customer products TEP transports, stores, processes, gathers, treats and disposes using its assets;
its ability to renew or replace expiring long-term firm fee contracts with other long-term firm fee contracts;
the creditworthiness of its customers, particularly customers who are subject to firm fee contracts;
its ability to complete and integrate acquisitions;
the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of natural gas, NGLs, crude oil and other hydrocarbons;
the actual and anticipated future prices, and the volatility thereof, of natural gas, crude oil and other commodities;
changes in the fees TEP charges for its services, including firm services and interruptible services;
TEP's ability to identify, develop, and complete internal growth projects or expansion capital expenditures on favorable terms to improve optimization of its current assets;
regional, domestic and foreign supply and perceptions of supply of natural gas, crude oil and other hydrocarbons;
the level of demand and perceptions of demand in end-user markets TEP directly or indirectly serves;
applicable laws and regulations affecting TEP and its customers' business, including the market for natural gas, crude oil, other hydrocarbons and water, the rates TEP can charge on its assets, how TEP contracts for services, its existing contracts, its operating costs or its operating flexibility;
the effect of worldwide energy conservation measures;
prevailing economic conditions.
the effect of seasonal variations in temperature and climate on the amount of customer products TEP is able to transport, store, process, gather, treat and dispose using its assets;
the realized pricing impacts on revenues and expenses that are directly related to commodity prices;
the level of competition from other midstream energy companies in its geographic markets;
the level of its operating and maintenance costs;
damage to its assets and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters or acts of terrorism;
outages in its assets;
the relationship between natural gas and NGL prices and resulting effect on processing margins; and
leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise.
In addition, the actual amount of cash TEP will have available for distribution will depend on other factors, including:
its ability to borrow funds and access capital markets;
the level, timing and characterization of capital expenditures TEP makes;
the level of its general and administrative expenses, including reimbursements to its general partner and its affiliates, for services provided to TEP;
the cost of pursuing and completing acquisitions and capital expansion projects, if any;
its debt service requirements and other liabilities;
fluctuations in its working capital needs;
restrictions contained in its debt agreements;
the amount of cash reserves established by its general partner; and
other business risks affecting its cash levels.
If TEP is not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, its financial condition, results of operations, cash flows and ability to make cash distributions to its unitholders will be adversely affected.
A substantial majority of TEP's contracts for transporting, storing, and processing its customers' products on TEP's systems are long-term firm fee contracts with terms of various durations. For the year ended December 31, 2017, approximately 92% of its natural gas transportation and storage revenues were generated under firm fee transportation and storage contracts and approximately 88% of its crude oil transportation revenues were generated under firm fee transportation contracts. As of December 31, 2017, the weighted average remaining life of its long-term natural gas transportation contracts and natural gas storage contracts at TIGT and Trailblazer was approximately four years each, and the crude oil transportation contracts was approximately three years, reflective of the Continental Resources contract extension effective January 1, 2018. In addition, a majority of Rockies Express' west-to-east pipeline capacity is subject to long-term firm fee contracts that expire in 2019 and a significant amount of Rockies Express' revenue in 2017 was derived under these contracts.
TEP may be unable to maintain the long-term nature and economic structure of its current contract portfolio over time. Depending on prevailing market conditions at the time of a contract renewal, its natural gas transportation, storage and processing customers with long-term fee-based contracts may desire to enter into contracts with reduced fees, and may be unwilling to enter into long-term contracts at all. In addition, a significant portion of the long-term contracts for the Pony Express Pipeline expire in 2019 and those customers may unilaterally decide whether to renew such contracts. If these contracts are not renewed, Pony Express' ability to enter into replacement long-term contracts would be limited. Under current FERC policy, Pony Express is generally prohibited from entering into new long-term contracts that grant contract shippers priorities in prorationing under the ICA unless such contract relates to an increase in the capacity of the Pony Express Pipeline.
TEP's ability to renew or replace its expiring contracts on terms similar to, or more attractive than, those of its existing contracts is uncertain and depends on a number of factors beyond its control, including:
the level of existing and new competition to provide competing services to its markets;
the macroeconomic factors affecting crude oil and natural gas economics for our current and potential customers;
the balance of supply and demand for natural gas, crude oil and other hydrocarbons, on a short-term, seasonal and long-term basis, in the markets TEP directly and indirectly serves;
the extent to which the current and potential customers in its markets are willing to provide firm fee commitments on a long-term basis; and
the effects of federal, state or local laws or regulations on the contracting practices of its customers.
During periods of price reduction and high volatility in the commodity markets, TEP expects customers will generally be less likely to enter into long-term firm fee contracts, and even if they enter into such contracts, may only be willing to provide acreage dedications to our assets rather than firm fee commitments. Acreage dedications typically do not require TEP's customers to pay us unless they utilize our assets, and they may also be subject to challenge in bankruptcy proceedings.
To the extent TEP is unable to renew or replace its existing contracts on terms that are favorable to TEP or successfully manage the long-term nature and economic structure of its contract profile over time, TEP's revenues and cash flows could decline and its ability to make distributions to its unitholders could be materially and adversely affected.
TEP is exposed to the creditworthiness and performance of its customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect its financial condition, cash flows, and operating results.
Although TEP attempts to assess the creditworthiness of its customers, suppliers and contract counterparties, there can be no assurance that its assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on its business, results of operations, financial condition and ability to make cash distributions to its unitholders. TEP's long-term firm fee contracts obligate its customers to pay demand charges regardless of whether they utilize its assets, except for certain circumstances outlined in applicable customer agreements. As a result, during the term of its long-term firm fee contracts and absent an event of force majeure, its revenues will generally depend on its customers' financial condition and their ability to pay rather than upon the extent to which our customers actually utilize our assets. Periods of price reduction and high volatility in the commodity markets could impact their ability to meet
their financial obligations to TEP. Further, TEP's contract counterparties may not perform or adhere to TEP's existing or future contractual arrangements. To the extent one or more of TEP's contract counterparties is in financial distress or commences bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material nonpayment or nonperformance by TEP's contract counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could have a material adverse impact on its business, results of operations, financial condition and ability to make cash distributions to its unitholders.
For example, in 2016, Ultra Resources, Inc., or Ultra, defaulted on its firm transportation service agreement with Rockies Express for approximately 0.2 Bcf/d through November 11, 2019, and as a result, Rockies Express filed a lawsuit seeking approximately $303 million in damages and other relief. Approximately 13% of Rockies Express' revenue in 2015 was derived from the Ultra contract. In April 2016, Ultra filed for bankruptcy protection and in January 2017, Rockies Express and Ultra agreed to settle Rockies Express’ claim against Ultra's bankruptcy estate. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of $150 million on July 12, 2017, and entered into a new, seven-year firm transportation agreement with Rockies Express commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate of approximately $0.37, or approximately $26.8 million annually.
In addition, Triad Hunter, LLC, or Triad, sought bankruptcy relief in December 2015. At the time Triad commenced the bankruptcy proceedings, Triad and Rockies Express were parties to a precedent agreement that provided Triad with an approximate 0.1 Bcf/d of firm capacity in connection with the Rockies Express Zone 3 Capacity Enhancement Project. In order to settle its claim, Rockies Express agreed to amend certain material terms of the precedent agreement, including reducing Triad's firm capacity under the precedent agreement to an approximate 0.05 Bcf/d.
Although the Triad and Ultra claims were ultimately settled, and on terms TEP views as favorable, future bankruptcy proceedings with a counterparty may not result in a favorable settlement for TEP.
The procedures and policies TEP uses to manage its exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. In accordance with FERC regulations and its own internal credit policies, counterparties with investment grade credit ratings are deemed able to meet their financial obligations to TEP without requiring credit support in the form of a letter of credit or prepayment. Although TEP asks for credit support from customers it deems to not be creditworthy or upon a deterioration of the financial condition of an existing customer, some customers may be unwilling or unable to provide it due to liquidity constraints. To the extent its procedures and policies prove to be inadequate or TEP is unable to obtain credit support, its financial position and results of operations may be negatively impacted.
Some of TEP's counterparties may be highly leveraged or have limited financial resources and are subject to their own operating and regulatory risks. Even if its credit review and analysis mechanisms work properly, TEP may experience financial losses in its dealings with such parties. As seen with the decline and volatility in crude oil prices from the second half of 2014 through the first half of 2016, prices for crude oil and natural gas are subject to large fluctuations in response to changes in supply and demand, market uncertainty and a variety of other factors that are beyond its control. Such volatility in commodity prices might have an impact on many of TEP's counterparties and their ability to borrow and obtain additional capital on attractive terms, which, in turn, could have a negative impact on their ability to meet their obligations to TEP.
Any material nonpayment or nonperformance by TEP's counterparties could require TEP to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.
TEP depends on certain key customers for a significant portion of its revenues and is exposed to credit risks of these customers. The loss of or material nonpayment or nonperformance by any of these key customers could adversely affect its cash flow and results of operations.
TEP relies on certain key customers for a portion of revenues. For example, for the year ended December 31, 2017, Continental Resources accounted for approximately 15% of our revenues on a consolidated basis. In addition, for the year ended December 31, 2017, approximately 51% of its consolidated revenues were represented by the top ten customers on its Pony Express System. TEP owns a 49.99% membership interest in Rockies Express and Tallgrass Equity owns a 25.01% membership interest in Rockies Express, which is not consolidated for financial reporting purposes. Approximately 20%, 13%, and 12%, respectively, of Rockies Express' total revenues as of December 31, 2017 were represented by Rockies Express' three largest non-affiliated shippers.
TEP may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms. For additional detail, see "—If TEP is not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, its financial condition, results of operations, cash flows and ability to make cash distributions to its unitholders will be adversely affected."
In addition, some of these key customers may experience financial problems that could have a significant effect on their creditworthiness. For example, Rockies Express terminated its contract with its third largest non-affiliated shipper by total 2015 revenue, Ultra, in March 2016. For more detail regarding Ultra, see "—TEP is exposed to the creditworthiness and performance of its customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect its financial condition, cash flows, and operating results."
Severe financial problems encountered by its customers could limit its ability to collect amounts owed to TEP, or to enforce performance of obligations under contractual arrangements. To the extent one or more of TEP's key customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Additionally, many of its customers finance their activities through cash flow from operations, the incurrence of indebtedness or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of TEP's customers' liquidity and limit their ability to make payments or perform on their obligations to TEP. Furthermore, some of TEP's customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to TEP. The loss of all or even a portion of the contracted volumes of these key customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on its business, cash flows, ability to make distributions to its unitholders, the price of its units, its results of operations and ability to conduct its business.
If TEP is unable to make acquisitions on economically acceptable terms, its future growth will be limited, and the acquisitions TEP does make may reduce, rather than increase, its cash generated from operations on a per unit basis.
TEP's ability to grow depends, in part, on its ability to make acquisitions that increase its cash generated from operations on a per unit basis.
The acquisition component of TEP's strategy is based, in part, on its expectation of ongoing divestitures of midstream energy assets by industry participants. Many factors could impair TEP's access to future midstream assets. A material decrease in divestitures of midstream energy assets by industry participants would limit TEP's opportunities for future acquisitions and could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders. Prior to February 7, 2018, Tallgrass Development was TEP's primary source of acquisitions. Now that Tallgrass Development has divested its entire asset portfolio and merged out of existence, TEP's growth through acquisitions will rely almost exclusively on buying assets or businesses from third parties.
TEP's future growth and ability to increase distributions will be limited if TEP is unable to make accretive acquisitions because, among other reasons, (i) TEP is unable to identify attractive acquisition opportunities, (ii) TEP is unable to negotiate acceptable purchase contracts, (iii) TEP is unable to obtain financing for these acquisitions on economically acceptable terms, (iv) TEP is outbid by competitors or (v) TEP is unable to obtain necessary governmental or third-party consents. Furthermore, even if TEP does make acquisitions that TEP believes will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis. For example, TEP completed a number of acquisitions in 2017, including the acquisition of 100% of the membership interests in Terminals and 100% of the membership interests in NatGas from Tallgrass Development in January 2017, an additional 24.99% membership interest in Rockies Express from Tallgrass Development in March 2017, 100% of the membership interests in DCP Douglas, LLC from DCP Midstream in June 2017, an additional 40% membership interest in Deeprock Development from Kinder Morgan in July 2017, and 100% of the membership interests of TCG from Outrigger Energy in August 2017. If certain risks or unanticipated liabilities were to arise, the desired benefits of these acquisition may not be fully realized and TEP's future financial performance and results of operations could be negatively impacted.
Any acquisition involves potential risks, including, among other things:
mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;
an inability to maintain or secure adequate customer commitments to use the acquired systems or facilities;
an inability to successfully integrate the assets or businesses TEP acquires;
the assumption of unknown liabilities for which TEP is not indemnified or for which its indemnity is inadequate;
the diversion of management's and employees' attention from other business concerns;
unforeseen difficulties operating in new geographic areas or business lines; and
a decrease in liquidity and increased leverage as a result of using significant amounts of available cash or debt to finance an acquisition.
If any acquisition eventually proves not to be accretive to TEP's distributable cash flow per unit, it could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.
If TEP is unable to obtain needed capital or financing on satisfactory terms to fund expansions of its asset base, its ability to make quarterly cash distributions may be diminished or its financial leverage could increase.
In order to expand TEP's asset base through acquisitions or capital projects, TEP may need to make expansion capital expenditures. If TEP does not make sufficient or effective expansion capital expenditures, TEP will be unable to expand its business operations and may be unable to maintain or raise the level of its quarterly cash distributions. TEP could be required to use cash from its operations or incur borrowings or sell additional common units or other limited partner interests in order to fund its expansion capital expenditures. Using cash from operations will reduce cash available for distribution to its common unitholders. TEP's ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by its financial condition at the time of any such financing or offering as well as the covenants in its debt agreements, general economic conditions and contingencies and uncertainties that are beyond its control. Even if TEP is successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit its ability to pay distributions to its common unitholders. In addition, incurring additional debt may significantly increase its interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease its ability to pay distributions at the then-current distribution rate. TEP does not currently have any commitment with its general partner or other affiliates, including Tallgrass Energy Holdings, for them to provide any direct or indirect financial assistance to TEP.
The Throughput and Deficiency Agreements for the Pony Express System and some of TEP's service agreements with respect to its water business services contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.
The Throughput and Deficiency Agreements, or TDAs, for the Pony Express System and some of TEP's service agreements with respect to its water services business are firm fee contracts with minimum volume commitments that are designed to generate stable cash flows and minimize direct commodity price risk. Under these minimum volume commitments, its customers agree to ship a minimum volume of crude oil or to have a minimum volume of water serviced, as the case may be, over certain periods during the term of the applicable agreement.
If a customer's actual throughput volumes or volumes serviced are less than its minimum volume commitment for the applicable period, it must make a deficiency payment at the end of the applicable period based upon the difference between the minimum volume commitment and the actual amounts serviced. A customer may apply any deficiency payments it makes as a credit against payment for volumes transported or serviced by TEP in excess of its minimum volume commitment in future periods. Upon termination of the Pony Express TDAs, customers may continue to use any remaining deficiency credits against any volumes serviced by TEP for a period of six months following termination, even though such customers may no longer have a minimum volume commitment.
To the extent that a customer's actual throughput volumes or volumes serviced are above its minimum volume commitment for the applicable period, the customer may use the excess volumes to credit against future deficiency payments in subsequent periods. As of December 31, 2017, Pony Express had a cumulative net deficiency balance of $88.4 million and a cumulative shipper incremental balance of $1.5 million.
Some or all of these provisions can apply in combination with one another. As a result, in the future TEP may not receive any cash payments for volumes shipped or serviced by TEP, and TEP may not receive deficiency payments as a result of excess volumes shipped in prior periods. This would result in reduced revenue and cash flows to TEP.
TEP may not be able to compete effectively in its midstream services activities and its business is subject to the risk of a capacity overbuild of midstream energy infrastructure in the areas where TEP operates.
TEP faces competition in all aspects of its business and may not be able to compete effectively against its competitors. In general, competition comes from a wide variety of players in a wide variety of contexts, including new entrants and existing players and in connection with day-to-day business, expansion capital projects, acquisitions and joint venture activities. Some of its competitors have capital resources greater than TEP's and control greater supplies of crude oil, natural gas or NGLs.
TEP's ability to renew or replace its existing contracts at rates sufficient to maintain current revenues and current cash flows could be adversely affected by the activities of its competitors. Some of its competitors have assets in closer proximity to certain hydrocarbon supplies and have available idle capacity in existing assets that may require no or minimal capital investments for use. For example, several pipelines access many of the same basins as TEP's assets and provide transport to customers in the Rocky Mountain, Appalachian Mountain and Midwest regions of the United States, such as the Dakota Access Pipeline, Saddlehorn-Grand Mesa Pipeline and White Cliffs Pipeline that compete with the Pony Express Pipeline. Pony
Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers looking to capitalize on basis differentials between two primary crude oil benchmarks (West Texas Intermediate Crude and Brent Crude). Furthermore, Tallgrass Energy Holdings and its affiliates are not limited in their ability to compete with TEP.
TEP's competitors may expand or construct new midstream services assets that would create additional competition for the services TEP provides to its customers, or its customers may develop their own facilities in lieu of using TEP's. A significant driver of competition in some of the markets where TEP operates (including, for example, the Rocky Mountain and Appalachian Mountain regions) has been the rapid development of new midstream energy infrastructure capacity in recent years. As a result, TEP is exposed to the risk that the areas in which TEP operates become overbuilt, resulting in an excess of midstream energy infrastructure capacity. If TEP experiences a significant capacity overbuild in one or more of the areas where TEP operates, it could have a significant adverse impact on its financial position, cash flows and ability to pay or increase distributions to its unitholders. For example, TEP's competitors in these areas could substantially decrease the prices at which they offer their services, and TEP may be unable to compete effectively. This could materially impair its cash flows and ability to make distributions to its unitholders.
Further, natural gas as a fuel, and fuels derived from crude oil, compete with other forms of energy available to users, including electricity, coal, other fuels and alternative energy. Increased demand for such forms of energy at the expense of natural gas or fuels derived from crude oil could lead to a reduction in demand for TEP's services.
All of these competitive pressures could make it more difficult for TEP to renew its existing long-term firm fee contracts when they expire or to attract new customers as TEP seeks to expand its business, which could have a material adverse effect on its business, financial condition, results of operations and prospects. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas and crude oil in the markets TEP serves, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions decreasing demand.
Constructing new assets subjects TEP to risks of project delays, cost overruns and lower-than-anticipated volumes of natural gas or crude oil once a project is completed. TEP's operating cash flows from its capital projects may not be immediate or meet its expectations.
One of the ways TEP may grow its business is by constructing additions or modifications to its existing facilities. TEP also may construct new facilities, either near its existing operations or in new areas. Construction projects require significant amounts of capital and involve numerous regulatory, environmental, political, legal and operational uncertainties, many of which are beyond its control. TEP may be unable to complete announced construction projects on schedule, at the budgeted cost, or at all, which could have a material adverse effect on its business and results of operations. For example, in June 2014, Michels Corporation, or Michels, filed a complaint and request for relief against Rockies Express as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit, and also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due. In February 2017, Rockies Express and Michels resolved the claims brought by Michels in exchange for a $10 million cash payment by Rockies Express.
Although TEP evaluates and monitors each capital spending project and tries to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond its control, including:
denial or delay in issuing requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions, explosions, fires, releases) affecting TEP’s facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
changes in market conditions impacting long lead-time projects;
market-related increases in a project's debt or equity financing costs; and
nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.
These projects also involve numerous economic uncertainties and the cash flow generated from these projects may not meet expectations or project estimates. Moreover, TEP may not receive any material increase in operating cash flow from a project for some time or at all. For instance, with respect to the Rockies Express Zone 3 Capacity Enhancement Project, substantially all the construction expenditures were incurred during 2015 and 2016, yet Rockies Express only received increases in cash flow from the project after it was placed in service in January 2017. In 2017, TEP began incurring construction expenditures in connection with commencing construction of the Platteville Extension Project on the Pony Express
System and the Cheyenne Connector Pipeline. However, TEP will not receive any increases in cash flow from these projects until such project is completed and placed in-service.
The project specifications and expectations regarding project cost, timing, asset performance, investment returns and other matters usually rely in part on the expertise of third parties such as engineers, technical experts and construction contractors. These estimates may prove to be inaccurate because of numerous operational, technological, economic and other uncertainties. TEP also relies in part on estimates from producers regarding the timing and volume of anticipated natural gas and crude oil production. Production estimates are subject to numerous uncertainties, nearly all of which are beyond its control. These estimates may prove to be inaccurate, and new facilities may not attract sufficient volumes to achieve its expected cash flow and investment return.
TEP has certain long-term fixed priced natural gas and crude oil transportation contracts that cannot be adjusted even if its costs increase. As a result, its costs could exceed its revenues.
As of December 31, 2017, approximately 45% of TEP's contracted natural gas transportation firm capacity was provided under long-term, fixed price "negotiated or discount rate" contracts that are not subject to adjustment, even if its cost to perform such services exceeds the revenues received from such contracts, and, as a result, its costs could exceed its revenues received under such contracts. It is possible that costs to perform services under its "negotiated or discount rate" contracts will exceed the negotiated or discounted rates. It is also possible with respect to discounted rates that if its filed "recourse rates" should ever be reduced below applicable discounted rates, TEP would only be allowed by the FERC to charge the lower recourse rates, since FERC policy does not allow discount rates to be charged to the extent that they exceed applicable recourse rates. If these events were to occur, it could decrease the cash flow realized by TEP's assets and, therefore, the cash TEP has available for distributions to its unitholders.
Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a "negotiated rate," which is generally fixed between the natural gas pipeline and the shipper for the contract term and does not necessarily vary with changes in the level of cost-based "recourse rates," provided that the affected customer is willing to agree to such rates and that the FERC has accepted the negotiated rate agreement. These "negotiated or discount rate" contracts are not generally subject to adjustment for increased costs which could be caused by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between "recourse rates" (if higher) and negotiated or discounted rates, under current FERC policy, may be recoverable from other shippers in certain circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future rate case. However, if the FERC were to disallow the recovery of such costs from other customers, it could decrease the cash flow realized by its assets and, therefore, the cash TEP has available for distributions to its unitholders.
Rates under Pony Express' TDAs are typically subject to change only per contract terms and conditions, including Pony Express' right to file changes to contract rates to reflect annual index percentage adjustments published by the FERC. TEP generally cannot file for rate increases with respect to committed shippers who have signed TDAs, other than to reflect annual index adjustments or to recover compliance costs imposed by governmental actions.
A significant amount of the revenue currently generated by the Pony Express System and the Rockies Express Pipeline are from contracts that contain most favored nations rights, limiting flexibility to offer certain capacity to new shippers.
Approximately 90% of the Pony Express System's current available capacity is provided to committed shippers under long-term TDAs. Some of the TDAs contain most favored nations rights, or MFNs, which could result in lower rates being charged to certain committed shippers to ensure that the rates such shippers are paying are no greater than ninety to one hundred percent of the rates being charged to other similarly situated shippers for similar service at similar volumes and terms. Triggering the MFNs on the TDAs could lead to a reduction in revenue generated by Pony Express, which could have a material adverse effect on our revenues, cash flow, results of operations, and TEP's ability to make distributions to its unitholders.
Rockies Express' foundation and anchor shippers for west-to-east service hold certain MFNs granting them a right to a rate reduction in certain instances where Rockies Express provides service to another shipper at a rate lower than the foundation or anchor shipper rate for a term of one year or greater or, in the case of the foundation shipper, from certain specified receipt locations. The MFNs effectively limit Rockies Express' flexibility in negotiating rates for some of its services with other shippers, because triggering the MFNs of the foundation and anchor shippers could lead to a reduction in the rates that Rockies Express charges, which could have a material adverse effect on Rockies Express' revenues, cash flow and results of operations, which in turn could impair TEP's and Rockies Express' ability to make distributions to its equity holders and our ability to make distributions to our shareholders.
If third-party pipelines or other facilities interconnected to TEP's systems become partially or fully unavailable, if the volumes TEP transports do not meet the quality requirements of such pipelines or facilities, or if claims are made against TEP for events that occur downstream of its interconnection with third-party facilities, its revenues and its ability to make distributions to its unitholders could be adversely affected.
TEP's assets typically connect to other pipelines or facilities owned, leased and/or operated by unaffiliated third parties, such as ONEOK Bakken Pipeline, L.L.C., Whiting Petroleum, and others. For example, TEP's Pony Express System connects to upstream joint tariff pipelines, including the Belle Fourche Pipeline owned by the True Companies (which also own and operate the Bridger Pipeline upstream of the Belle Fourche Pipeline) and the Double H Pipeline owned by Kinder Morgan, which are responsible for delivering a substantial portion of the crude oil for transportation on the Pony Express System. In addition, part of the crude oil TEP transports on the Pony Express System is either stored in crude oil tanks located on, or pumped over to downstream pipelines that interconnect through, the Cushing Terminal, which TEP does not operate.
The continuing operation of such third-party facilities and other midstream facilities is not within its control. These pipelines, plants and other midstream facilities may become unavailable to TEP for any number of reasons, including because of testing, turnarounds, line repair, extended unscheduled maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements, conversion to another form of commodity transportation service, cessation of operations, curtailments of receipt or deliveries due to insufficient capacity or because of damage from weather events or other operational hazards. For example, the operations of the Bridger Pipeline's Poplar System were down for approximately five months during the first half of 2015 due to a pipeline release. Bridger declared a force majeure as a result of this event and temporarily lacked the capacity to make up volumes on other lines that directly or indirectly deliver crude oil into designated origin points on the Pony Express System or the Belle Fourche Pipeline. The largest committed shipper on the Pony Express System also declared a force majeure as a result of this incident.
In addition, TEP's interconnection with third-party facilities may result in claims being made against it for events that occur downstream of its pipelines. For example, TIGT has been named as a defendant in a lawsuit for damages arising from a gas leak and home explosion that occurred in June 2014 in Finney County, Kansas. Although TIGT did not directly distribute natural gas to the home in question, the plaintiffs nonetheless allege that TIGT committed torts and otherwise violated federal safety laws. TIGT believes the claims are without merit and intends to vigorously defend them.
If the costs to TEP to access and transport on these third-party pipelines or any alternative pipelines significantly increase, if any of these pipelines or other midstream facilities become unable to receive, transport, store or process products from its assets, if the volumes TEP transports or processes do not meet the quality requirements of such pipelines or facilities, or if claims are made against TEP for events that occur downstream of its interconnection with third-party facilities, its revenues and its ability to make quarterly cash distributions to its unitholders could be adversely affected.
The lack of diversification of TEP's assets and geographic locations could adversely affect its ability to make distributions to its common unitholders.
TEP relies on revenues generated from its assets, which are primarily located in the Rocky Mountain, Appalachian Mountain and Midwest regions of the United States. Revenues on its assets primarily depend on exploration and production activities of its customers located in these regions. Due to its lack of diversification in assets and geographic location, an adverse development in these businesses or its customers' areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in supply or demand for hydrocarbons, could have a significantly greater impact on its results of operations and cash available for distribution to its common unitholders than if TEP maintained more diverse assets and locations. For example, its water business services are provided through a limited number of assets with a relatively high concentration in Weld County, Colorado. Thus, the growth and profitability of its water business services will be especially vulnerable to conditions and fluctuations in the local Weld County economy and subject to changes in local government regulations and priorities.
TEP's operations are dependent on its rights and ability to receive or renew the required permits and other approvals from governmental authorities and other third parties.
Performance of TEP's operations requires that TEP obtains and maintains numerous environmental and land use permits and other approvals authorizing its business activities. A decision by a governmental authority or other third party to deny, delay or restrictively condition the issuance of a new or renewed permit or other approval, or to revoke or substantially modify an existing permit or other approval, could have a material adverse effect on its ability to initiate or continue operations at the affected location or facility. Expansion of its existing operations and construction of new assets are both also predicated on securing the necessary environmental or land use permits and other approvals, which TEP may not receive in a timely manner or at all.
In order to obtain permits and renewals of permits and other approvals in the future, TEP may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed activities may have on the
environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time needed to develop a site or pipeline alignment. Also, obtaining or renewing required permits or other approvals is sometimes delayed or prevented due to community opposition and other factors beyond its control. The denial of a permit or other approval essential to its operations or the imposition of restrictive conditions with which it is not practicable or feasible to comply could impair or prevent its ability to develop or expand a property or right-of-way. Significant opposition to a permit or other approval by neighboring property owners, members of the public or non-governmental organizations, or other third parties or delay in the environmental review and permitting process also could impair or delay its ability to develop or expand a property or right-of-way. New legal requirements, including those related to the protection of the environment, could be adopted at the federal, state and local levels that could materially adversely affect its operations, its cost structure or its customers' ability to use its services. Such current or future regulations could have a material adverse effect on its business and TEP may not be able to obtain or renew permits or other approvals in the future.
Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect TEP's business and results of operations.
TEP's business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are reduced energy demand and lower prices for its services and increased difficulty in collecting amounts owed to TEP by its customers which could reduce its access to credit markets, raise the cost of such access or require TEP to provide additional collateral to its counterparties. TEP's ability to access available capacity under its revolving credit facility could be impaired if one or more of its lenders fails to honor its contractual obligation to lend to TEP. If financing is not available when needed, or is available only on unfavorable terms, TEP may be unable to implement its business plans or otherwise take advantage of business opportunities or respond to competitive pressures.
The amount of cash TEP has available for distribution to unitholders depends primarily on its cash flow rather than on its profitability, which may prevent TEP from making distributions, even during periods in which TEP records net income.
The amount of cash TEP has available for distribution depends primarily upon its cash flow and not solely on profitability, which will be affected by non-cash items. As a result, TEP may make cash distributions during periods when TEP records losses for financial accounting purposes and may not make cash distributions during periods when TEP records net earnings for financial accounting purposes.
The revenue in TEP's Gathering, Processing & Terminalling segment largely depends on the amount of natural gas that its customers actually deliver to its natural gas processing plants.
During the year ended December 31, 2017, approximately 17%, 53%, and 30% of TMID's operating income came from firm fee, volumetric fee, and commodity sensitive contracts, respectively. On these volumetric fee contracts, TEP's revenue is largely tied to the amount of natural gas that its customers actually deliver to TEP's Casper and Douglas plants for processing. Unlike many pipeline transportation customers, TEP's natural gas processing customers are not generally subject to "take or pay" obligations. Thus, if its natural gas processing customers do not produce natural gas and deliver that natural gas to its processing plants to be processed, revenue for its Gathering, Processing & Terminalling segment will decline. As natural gas, crude oil or NGL prices decline, TEP's customers will likely make less money from the production of natural gas, crude oil or NGLs than it costs them to produce it. If that happens, its customers may not continue to produce natural gas and its revenue will decline. The decreased commodity prices in late 2014 through 2016 contributed to a significant drop in actual volumes from several producers from which TMID receives natural gas for processing. If processing volumes at TMID do not continue recovering over time, we could have an impairment of the goodwill at the TMID reporting unit, which is a component of our Gathering, Processing & Terminalling segment, and our revenue will decline. In addition, the fees its customers pay to reserve capacity at its processing plants may not deter those customers from processing their natural gas volumes at other facilities, with whom they may have had prior arrangements or otherwise.
TEP is exposed to direct commodity price risk with respect to some of its processing revenues and the utilization of commodity derivatives by Stanchion, and its exposure to direct commodity price risk may increase in the future.
TEP's Gathering, Processing & Terminalling segment operates under three types of contracts, two of which directly expose its cash flows to increases and decreases in the price of natural gas and NGLs: percent of proceeds and keep whole processing contracts. TEP does not currently hedge the commodity exposure inherent in these types of processing contracts, and as a result, its revenues and results of operations are impacted by fluctuations in the prices of natural gas and NGLs.
Percent of proceeds processing contracts generally provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under keep whole processing contracts, TEP's revenues and its cash flows generally increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas
prices and NGL prices may also affect its profitability. When natural gas prices are low relative to NGL prices, it is more profitable for TEP to process natural gas under keep whole arrangements. When natural gas prices are high relative to NGL prices, it is less profitable for TEP and its customers to process natural gas both because of the higher value of natural gas and the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, TEP may experience periods in which higher natural gas prices relative to NGL prices reduce its processing margins or reduce the volume of natural gas processed at some of its plants. In addition, NGL prices have historically been related to the market price of oil and as a result any significant changes in oil prices could also indirectly impact its operations. Indirectly, reduced commodity prices impact TEP through reduced exploration and production activity, which results in fewer opportunities for new business to offset natural volume declines. NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. For example, from the second half of 2014 through the first half of 2016, natural gas and crude oil prices declined substantially and these declines directly and indirectly resulted in lower processing volumes and realizations on its percent of proceeds and keep whole processing contracts.
In 2017, TEP also began utilizing commodity derivatives in connection with the operations of its crude oil marketing subsidiary, Stanchion. TEP's portfolio of derivative and other energy contracts may consist of contracts to buy and sell commodities that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that TEP does not anticipate or cannot manage, it could negatively affect TEP's results of operations. If a performance failure were to occur in one of TEP's contracts, TEP might incur losses in addition to amounts, if any, already recognized in its financial statements or paid to, or received from, counterparties. As a result, TEP's business, results of operations, financial condition and ability to pay distributions to TEP's unitholders may be adversely affected.
TEP's success depends on the supply and demand for natural gas and crude oil.
The success of TEP's business is in many ways impacted by the supply and demand for natural gas and crude oil. For example, its business can be negatively impacted by sustained downturns in supply and demand for natural gas and crude oil in the markets that TEP and its customers serve, including reductions in its ability to renew contracts on favorable terms and to construct new infrastructure. Further, a portion of the demand for its water business services depends substantially on the level of expenditures by the oil and gas industry for the exploration, development and production of oil and natural gas reserves. These expenditures are generally dependent on the industry's view of future oil and natural gas prices and are sensitive to the industry's view of future economic growth and the resulting impact on demand for oil and natural gas. Declines, as well as anticipated declines, in oil and gas prices could also result in project modifications, delays or cancellations, general business disruptions, and delays in, or nonpayment of, amounts that are owed to TEP. These effects could have a material adverse effect on its financial condition, results of operations and cash flows.
One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation. One of the major factors impacting domestic natural gas and crude oil supplies has been the significant growth in unconventional sources such as shale plays and the continued progression of hydraulic fracturing technology. The supply and demand for natural gas and crude oil, and therefore the future rate of growth of TEP's business, depends on these and many other factors outside of its control, including, but not limited to:
adverse changes in general global economic conditions;
adverse changes in domestic laws and regulations;
technological advancements that may drive further increases in production and reduction in costs of developing crude oil and natural gas shale plays;
the price and availability of other forms of energy, including alternative energy which may benefit from government subsidies;
adoption of various energy efficiency and conservation measures;
prices for natural gas, crude oil and NGLs;
decisions of the members of the Organization of the Petroleum Exporting Countries, or OPEC, regarding price and production controls;
increased costs to explore for, develop, produce, gather, process and transport natural gas or crude oil;
weather conditions, seasonal trends and hurricane disruptions;
the nature and extent of, and changes in, governmental regulation, for example GHG legislation, taxation and hydraulic fracturing;
perceptions of customers on the availability and price volatility of its services and natural gas and crude oil prices, particularly customers' perceptions on the volatility of natural gas and crude oil prices over the long-term;
capacity and transportation service into, or out of, its markets; and
petrochemical demand for NGLs.
The oil and gas industry historically has experienced periodic downturns, and from the second half of 2014 through the first half of 2016 experienced a sustained period of decline and volatility in natural gas and crude oil prices. Any prolonged downturns in the oil and gas industry could result in a reduction in demand for TEP's services and could adversely affect its financial condition, results of operations and cash flows.
Any significant decrease in available supplies of hydrocarbons in TEP's areas of operation, or redirection of existing hydrocarbon supplies to other markets, could adversely affect its business and operating results. If recent lower commodity prices are prolonged beyond its contract lives, TEP will likely experience lower throughput volumes and reduced cash flows.
TEP's business is dependent on the continued availability of natural gas and crude oil production and reserves. Production from existing wells and natural gas and crude oil supply basins with access to its assets will naturally decline over time. The amount of natural gas and crude oil reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the contracted capacity and/or the volume of products utilizing its assets, its customers must continually obtain adequate supplies of natural gas and crude oil.
However, the development of additional natural gas and crude oil reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, storage, transportation and other facilities that permit natural gas and crude oil to be produced and products delivered to TEP's facilities. In addition, low prices for natural gas and crude oil, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could have a material adverse effect on the development and production of additional reserves, as well as storage, pipeline transportation, and import and export of natural gas and crude oil supplies. The volatility and sustained lower prices for crude oil and refined products from the second half of 2014 through the first half of 2016 led to a decline in drilling activity, production and refining of crude oil, and import levels in these areas. For example, in response to this volatility and lower prices, a number of producers in its areas of operation significantly reduced their capital budgets and drilling plans in 2015 through 2017. Even if those producers increase their capital budgets in areas TEP serves in 2018, it may take months before the increased capital spending has the possibility of resulting in increased utilization of TEP's assets. In addition, production may fluctuate for other reasons, including, for example, in the case of crude oil, the extent to which the members of OPEC abide by agreements regarding production controls. Furthermore, competition for natural gas and crude oil supplies to serve other markets could reduce the amount of natural gas and crude oil supply available for its customers. Accordingly, to maintain or increase the contracted capacity and/or the volume of products utilizing its assets, its customers must compete with others to obtain adequate supplies of natural gas and crude oil.
If new supplies of natural gas and crude oil are not obtained to replace the natural decline in volumes from existing supply basins, if natural gas and crude oil supplies are diverted to serve other markets, if environmental regulations restrict new natural gas and crude oil drilling or if OPEC does not maintain production controls, the overall demand for services on TEP's systems will likely decline, which could have a material adverse effect on its ability to renew or replace its current customer contracts when they expire and on its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.
TEP's natural gas, crude oil and liquids operations are subject to extensive regulation by federal, state and local regulatory authorities, which could have a material adverse effect on its business, financial condition, and results of operations.
TEP provides open-access interstate transportation service on its interstate natural gas transportation systems pursuant to tariffs approved by the FERC. TEP's interstate natural gas transportation and storage operations are regulated by the FERC, under the NGA, the NGPA, and the EPAct 2005. The Rockies Express Pipeline, the TIGT System and the Trailblazer Pipeline each operate under a tariff approved by the FERC that establishes rates and terms and conditions of service to its customers. The rates and terms of service on the Pony Express System are subject to regulation by the FERC under the ICA, and the Energy Policy Act of 1992. TEP provides interstate transportation service on the Pony Express System pursuant to tariffs on file with the FERC. TEP's NGL pipeline that interconnects with Overland Pass Pipeline is leased to a third party that has obtained a FERC waiver from the tariff, filing and reporting requirements of the ICA, and TEP's NGL pipeline that interconnects with ONEOK's Bakken NGL Pipeline is leased to a third party that is obligated to operate the leased pipeline in conformance with the ICA as a FERC-regulated NGL pipeline.
Generally, the FERC's authority over natural gas facilities extends to:
rates, operating terms and conditions of service;
the form of tariffs governing service;
the types of services TEP may offer to its customers;
the certification and construction of new, or the expansion of existing, facilities;
the acquisition, extension, disposition or abandonment of facilities;
customer creditworthiness and credit support requirements;
the maintenance of accounts and records;
relationships among affiliated companies involved in certain aspects of the natural gas business;
depreciation and amortization policies; and
the initiation and discontinuation of services.
The FERC's authority over crude oil and NGL pipelines is less broad, extending to:
rates, rules and regulations of service;
the form of tariffs governing rates and service;
the maintenance of accounts and records; and
depreciation and amortization policies.
Interstate natural gas pipelines subject to the jurisdiction of the FERC may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust, unreasonable, unduly discriminatory, or preferential. The maximum recourse rates that TEP may charge for its natural gas transportation and storage services are established through the FERC's ratemaking process. The maximum applicable recourse rates and terms and conditions for service are set forth in its FERC-approved tariffs.
For example, TIGT filed a general rate case with the FERC pursuant to Section 4 of the NGA in October 2015, which resulted in a settlement that was approved by an order issued by the FERC on November 2, 2016. The settlement established settlement rates to be effective through at least April 30, 2019. In the event the assumptions relied upon during settlement negotiations were incorrect or the actual costs incurred to operate the TIGT System increase, TIGT's cash flows and its results of operations could be adversely affected.
Pursuant to the NGA, existing interstate natural gas transportation and storage rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases and changes to terms and conditions of service proposed by a regulated interstate pipeline may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC. TEP currently holds authority from the FERC to charge and collect (i) "recourse rates" (i.e., the maximum cost-based rates an interstate natural gas pipeline may charge for its services under its tariff); (ii) "discount rates" (i.e., rates offered by the natural gas pipeline to shippers at discounts vis-à-vis the recourse rates and that fall within the cost-based maximum and minimum rate levels set forth in the natural gas pipeline's tariff); and (iii) "negotiated rates" (i.e., rates negotiated and agreed to by the pipeline and the shipper for the contract term that may fall within or outside of the cost-based maximum and minimum rate levels set forth in the tariff, and which are individually filed with the FERC for review and acceptance). When capacity is available and offered for sale, the rates (which include reservation, commodity, surcharges, and fixed fuel and lost and unaccounted for charges) at which such capacity is sold are subject to regulatory approval and oversight. Regulators and customers on its natural gas pipeline systems have the right to protest or otherwise challenge the rates that TEP charges under a process prescribed by applicable regulations. The FERC may also initiate reviews of its rates. Customers on its interstate natural gas pipeline systems may also dispute terms and conditions contained in its agreements, as well as the interpretation and application of its tariffs, among other things.
Rates for interstate crude oil transportation service must be filed as a tariff with the FERC and are subject to applicable FERC regulation. The filed tariff rates include contract rates entered into with shippers willing to make long-term commitments to the pipeline to support new pipeline capacity. Contract rates generally are not subject to regulation or change by the FERC. Non-contract "walk-up" rates are available to uncommitted non-contract shippers and generally are subject to regulation and change by the FERC. Interstate crude oil pipelines typically must reserve at least ten percent of their capacity for walk-up shippers. Contract tariff rates may be changed by Pony Express on an annual basis to reflect annual FERC index adjustments to the extent permitted by contract. Non-contract rates may be adjusted, positively or negatively, on an annual basis pursuant to a FERC indexing procedure. An interstate crude oil pipeline may also file new tariff rates at any time, subject to contract
restrictions and provisions, and FERC regulatory procedures. The filing of any indexed rate increase or other rate increase may be protested by parties having standing, subject to applicable regulatory and contract provisions, and thereby be subjected to cost-of-service review by the FERC to determine whether the proposed new rate is just and reasonable.
Under the ICA, which applies to the Pony Express System, parties having standing and not restricted by contract may protest newly filed rates and terms and conditions of service within a prescribed notice period. The FERC is authorized to suspend, subject to refund, the effectiveness of a protested rate for up to seven months while it determines if the protested rate is just and reasonable. TEP's rates may be reduced and TEP may be required to issue refunds as a result of settlement or by an order of the FERC following a hearing finding that a protested rate is unjust and unreasonable. Parties having standing and not restricted by contract may file a complaint at any time regarding existing rates and terms and conditions of service. If the complaint is not resolved by settlement, the FERC may conduct a hearing and order the crude oil pipeline to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. TEP cannot guarantee that any new or existing local or joint tariff rate for service on the Pony Express System would not be rejected or modified by the FERC, or subjected to refunds or reparations. While the FERC regulates rates and terms and conditions of service for transportation of crude oil in interstate commerce by pipeline, state agencies may also regulate facilities (including construction, acquisition, disposition, financing, and abandonment), rates, and terms and conditions of service for crude oil pipeline transportation in intrastate commerce. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on its business, financial condition and results of operations.
Pony Express Pipeline's tariff rates may not always be eligible for increases to reflect a FERC index adjustment. For example, on November 2, 2016, the FERC issued an Advanced Notice of Proposed Rulemaking, under which the FERC is proposing changes to its policies regarding the permissible scope of rate increases based on its annual issuance of changes to the generic oil pipeline index, based on specific pipelines' earnings or their specific changes to costs. The FERC's Advanced Notice of Proposed Rulemaking does not propose specific regulations, and may be followed by a Notice of Proposed Rulemaking proposing specific regulations or a Policy Statement announcing new or changed policies. This proceeding is pending before the FERC.
The FERC's jurisdiction over natural gas facilities extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to, acquisitions, facility maintenance and upgrades, expansions, and abandonment of facilities and services. With some exceptions applicable to smaller projects, auxiliary facilities, and certain facility replacements, prior to commencing construction and/or operation of new or existing interstate natural gas transportation and storage facilities, an interstate natural gas pipeline must obtain a certificate authorizing the construction from, or file to amend its existing certificate with, the FERC. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any delay or refusal by an agency to issue authorizations or permits as requested for one or more of these projects may mean that they will be constructed in a manner or with capital requirements that TEP did not anticipate or that TEP will not be able to pursue these projects. Such delay, modification or refusal could materially and negatively impact the additional revenues expected from these projects. The FERC does not regulate the construction, expansion, or abandonment of crude oil or NGL pipelines, whether interstate or intrastate, nor the initiation or discontinuation of services on those pipelines, provided that the action taken is not discriminatory or preferential among similarly situated shippers.
The FERC has the authority to conduct audits of regulated entities to assess compliance with FERC regulations and policies. The FERC also conducts audits to verify that the websites of interstate natural gas pipelines accurately provide information on the operations and availability of services on the pipeline. FERC regulations also require entities providing interstate natural gas and crude oil transportation services to comply with uniform terms and conditions for service, as set forth in publicly available tariffs or, as it concerns natural gas facilities, agreements for transportation and storage services executed between interstate pipelines and their customers. Natural gas transportation service agreements are generally required to conform, in all material respects, with the standard form of service agreements set forth in the natural gas pipeline's FERC-approved tariff. The pipeline and a customer may choose to enter into a non-conforming service agreement so long as the agreement is filed with, and accepted by, the FERC. In the event that the FERC finds that a natural gas transportation agreement, in whole or part, is materially non-conforming, the FERC could reject the agreement or require TEP to modify the agreement, or alternatively require TEP to modify its tariff so that the non-conforming provisions are generally available to all customers. Transportation agreements entered into with crude oil shippers are generally not subject to FERC regulation or required to be available for FERC or public review, but the rates and terms and services provided to similarly situated shippers may not be unduly discriminatory or preferential.
The FERC has promulgated rules and policies covering many aspects of its natural gas pipeline business, including regulations that require TEP to provide firm and interruptible transportation service on an open access basis that is not unduly discriminatory or preferential, provide internet access to current information about its available pipeline capacity and other relevant transmission information, and permit pipeline shippers to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. FERC regulations also prevent interstate natural gas
pipelines from sharing customer information with marketing affiliates, and restrict how interstate natural gas pipelines share transportation information with marketing affiliates. FERC regulations require that certain transmission function personnel of interstate natural gas pipelines function independently of personnel engaged in natural gas marketing functions. Crude oil pipelines subject to the ICA must comply with FERC regulations that require the pipeline to act as a common carrier and not engage in undue discrimination or preferential treatment with respect to shippers. The ICA also prevents crude oil and NGL pipelines from disclosing certain shipper information without the shipper's consent.
FERC policies also govern how interstate natural gas pipelines respond to interconnection requests from third party facilities, including other pipelines. Generally, an interstate natural gas pipeline must grant an interconnection request upon the satisfaction of several conditions. As a consequence, an interstate natural gas pipeline faces the risk that an interconnecting third-party pipeline may pose a risk of additional competition to serve a particular market or customer. Failure to comply with applicable provisions of the NGA, NGPA, EPAct 2005 and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of more than $1 million per day, per violation. Violations of the ICA, the Energy Policy Act of 1992, or regulations and orders promulgated by the FERC are also subject to administrative and criminal penalties and remedies, including forfeiture and individual liability.
In addition, new laws or regulations or different interpretations of existing laws or regulations applicable to TEP's pipeline systems or midstream facilities could have a material adverse effect on its business, financial condition, results of operations and prospects. For example, on November 22, 2017, in FERC Docket No. OR17-2-000, the FERC issued an Order on Petition for Declaratory Order addressing whether certain specific hypothetical transactions between a petroleum liquids pipeline and its marketing affiliate proposed by the petitioner, Magellan Midstream Partners, L.P., would violate the requirements of the ICA or the FERC’s regulations and policies. The FERC concluded that certain transactions proposed by the petitioner could be inconsistent with the ICA and the FERC’s policies. Various market participants filed requests for clarification or, in the alternative, rehearing of the November 22, 2017 declaratory order. On January 22, 2018, the FERC issued an order granting rehearing for further consideration, which afforded the FERC additional time to consider and rule on the pending clarification/rehearing requests. The outcome of this proceeding and any related proceeding(s) may require TEP to modify the business practices between its petroleum liquids pipelines regulated by FERC and its affiliated marketer, Stanchion. To the extent the foregoing proceedings result in substantial new restrictions on the transactions between petroleum liquids pipelines and their affiliated shippers, the business activities of Stanchion could be affected.
The FERC may also not continue to pursue its approach of pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. Further, the FERC is reviewing, and may possibly revise, its policies for analyzing whether proposed natural gas facilities are in the public convenience and necessity, including its Policy Statement on Certification of New Interstate Natural Gas Facilities issued in 1999. A change in such policies could delay or prevent the FERC's approval of proposed natural gas facilities, which could have a material impact on TEP's business. TEP may face challenges to its rates or terms of service in the future. Any successful challenge could materially and adversely affect its future earnings and cash flows.
The rates and terms and conditions of TEP's regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.
TEP's shippers or other interested stakeholders, such as state natural gas utility regulatory agencies, may challenge the rates or the terms and conditions of service applicable to its natural gas or crude oil pipeline tariffs, unless they have entered into agreements not to challenge such tariffs. The FERC has authority to investigate its rates and terms and conditions of service pursuant to NGA Section 5 for natural gas pipelines and the ICA for common carrier oil pipelines. TEP's crude oil contract shippers have generally agreed not to complain or protest rates unless they are in conflict with their contracts. FERC generally does not regulate crude oil transportation contracts, but contract rates must be filed with FERC and tariff rules and regulations generally apply to contract shippers.
On TEP's interstate crude oil pipeline system, the Pony Express System, shippers may generally challenge new or existing rates at any time unless they have contractually agreed not to. As a result of settlement or by order of the FERC following hearing, its rates may be reduced. If a shipper files a lawful complaint, and if the complaint is not resolved with that shipper, to the extent the FERC determines after hearing that TEP has collected payment on rates that were not previously just and reasonable, TEP may be required to pay reparations to that shipper for up to two years prior to the date on which a complaint was filed. Regardless of the prospective just and reasonable rate, reparations may not be required below the last rates determined by the FERC to be just and reasonable. In other words, crude oil pipelines are not required to make reparations that refund revenues collected pursuant to rates previously determined to be just and reasonable.
Further, the FERC's actions are subject to court challenge, which may have broader implications for other regulated pipelines. For example, in July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion
in United Airlines, Inc., et al. v. FERC, finding that the FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline partnership owners double-recovering their income taxes. The court vacated the FERC's order and remanded to the FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance.
On December 15, 2016, the FERC issued a Notice of Inquiry regarding the FERC's policy for recovery of income tax costs in pipeline cost of service rates. The FERC sought comments regarding how to address any double recovery resulting from the FERC's current income tax allowance and rate of return policies following the holding in United Airlines, Inc., et al. v. FERC. Comments have been filed with the FERC by interested parties and the proceeding is pending before the FERC. There is not likely to be a definitive resolution of these issues for some time, and the ultimate outcome of this proceeding is not certain and could result in changes going forward to the FERC's treatment of income tax allowances in the cost of service or to the discounted cash flow return on equity. Depending upon the resolution of these issues, the cost of service rates of TEP's interstate natural gas pipelines and interstate crude oil pipeline could be affected to the extent TEP proposes new rates or changes to its existing rates or if its rates are subject to complaint or challenge by the FERC.
On December 22, 2017, federal legislation known as the “Tax Cuts and Jobs Act” was enacted, which made various changes to the United States tax laws, including reducing the highest marginal U.S. federal corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017, adjusting the individual income tax brackets, and establishing limited deductions for certain income from “pass-through” entities. If FERC requires TEP to establish new tariff rates that reflect changes resulting from the Tax Cuts and Jobs Act, it is possible that certain tariff rates could be reduced, which could adversely affect TEP's financial position, results of operations and ability to make cash distributions to its unitholders.
Successful challenges to rates charged on TEP's natural gas and crude oil pipeline systems, or to the terms and conditions of service on those systems, could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.
TEP is subject to numerous hazards and operational risks.
TEP's operations are subject to all the risks and hazards typically associated with transportation, storage, terminalling, processing, gathering and disposing of hydrocarbons and water. These operating risks include, but are not limited to:
damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires or other adverse weather conditions and other natural disasters and acts of terrorism;
inadvertent damage from construction, vehicles, farm and utility equipment;
uncontrolled releases of crude oil, natural gas and other hydrocarbons or hazardous materials, including water from hydraulic fracturing;
leaks, migrations or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities;
outages at its facilities;
ruptures, fires, leaks and explosions; and
other hazards that could also result in personal injury and loss of life, pollution and other environmental risks, and suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of TEP's assets, including certain segments of its pipeline systems in or near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas could increase the level of damages resulting from these risks. Despite the precautions TEP takes, events could cause considerable harm to people or property, could result in loss of service available to customers, and could have a material adverse effect on its financial condition and results of operations and ability to make distributions to unitholders.
For example, on January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations, however, the release required Rockies Express to shut off the flow through the segment. Repairs are underway to return the segment to service as soon as possible and a root cause investigation is ongoing. As an additional example, approximately 10,000 bbls of crude oil were released at the Sterling Terminal in January 2017 as a result of a defective roof drain system on a storage tank. While the release was restricted to the containment area designed for such purpose and approximately 9,000 bbls were ultimately recovered, the total cost to remediate the release was approximately $600,000.
In addition, maintenance, repair and remediation activities could result in service interruptions on segments of TEP's systems or alter the operational profile of its systems. Any such service interruption or alteration could limit TEP's ability to satisfy customer requirements, could obligate TEP to provide reservation charge credits to customers for constrained capacity, or could allow existing customers to be solicited by other companies for potential new projects that would compete directly with TEP's services.
TEP could be required by regulatory authorities to test or undertake modifications to its systems, operations or both that could result in a material adverse impact on its business, financial condition and results of operations. Such actions, including those required by PHMSA, could materially and adversely impact its ability to meet contractual obligations and retain customers, with a resulting material adverse impact on its business and results of operations, and could also limit or prevent its ability to make quarterly cash distributions to its unitholders. Some or all of its costs arising from these operational risks may not be recoverable under insurance, contractual indemnification or increases in rates charged to its customers.
TEP's insurance coverage may not be adequate.
TEP is not insured or fully insured against all risks that could affect its business, including losses from environmental accidents or cyber security threats. For example, TEP does not maintain business interruption insurance in the type and amount to cover all possible losses. In addition, TEP does not carry insurance for certain environmental exposures, including but not limited to potential environmental fines and penalties, certain business interruptions, named windstorm or hurricane exposures and, in limited circumstances, certain political risk exposures. Further, in the event there is a total or partial loss of one or more of its insured assets, any insurance proceeds that TEP may receive in respect thereof may be insufficient to effect a restoration of such asset to the condition that existed prior to such loss. In addition, TEP is either not insured or not fully insured with respect to the legal proceedings described in Note 19 – Legal and Environmental Matters and may, depending upon the circumstances, need to pay self-insured retention amounts prior to having losses covered by the insurance providers. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on its business, financial condition, results of operations and cash flows.
Furthermore, TEP may not be able to maintain or obtain insurance of the type and amount TEP desires at reasonable rates, and TEP has elected and may elect in the future to self-insure a portion of its risks of loss. As a result of market conditions, premiums and deductibles for certain types of insurance policies may substantially increase, and in some instances, certain types of insurance could become unavailable or available only for reduced amounts of coverage. Any insurance coverage TEP does obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses.
TEP's pipeline integrity program may impose significant costs and liabilities on TEP, while increased regulatory requirements relating to the integrity of its pipeline systems may require TEP to make additional capital and operating expenditures to comply with such requirements.
TEP is subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal requirements set by PHMSA for owners and operators of pipelines in the areas of pipeline design, construction, and testing, the qualification of personnel and the development of operations and emergency response plans. The rules require pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as HCAs.
TEP's pipeline operations are subject to pipeline safety regulations administered by PHMSA. These regulations, among other things, include requirements to monitor and maintain the integrity of its pipeline systems and determine the pressures at which its pipeline systems can operate. The Pipeline Safety Act of 2011, enacted January 3, 2012, amends the Pipeline Safety Improvement Act of 2002 in a number of significant ways, including:
reauthorizing funding for federal pipeline safety programs, increasing penalties for safety violations and establishing additional safety requirements for newly constructed pipelines;
requiring PHMSA to adopt appropriate regulations within two years and requiring the use of automatic or remote- controlled shutoff valves on new or rebuilt pipeline facilities;
requiring operators of pipelines to verify MAOP and report exceedances within five days; and
requiring studies of certain safety issues that could result in the adoption of new regulatory requirements for new and existing pipelines, including changes to integrity management requirements for HCAs, and expansion of those requirements to areas outside of HCAs.
In August 2012, PHMSA published rules to update pipeline safety regulations to reflect provisions included in the Pipeline Safety Act of 2011, including increasing maximum civil penalties from $0.1 million to $0.2 million per violation per day of violation and from $1.0 million to $2.0 million as a maximum amount for a related series of violations as well as changing PHMSA's enforcement process. In April 2017, PHMSA issued a final rule that increased the per-day violation penalty to $209,002 and the maximum penalty for a related series of violations to $2,090,022 effective April 27, 2017. On January 13,
2017, PHMSA finalized new hazardous liquid pipeline safety regulations extending certain regulatory reporting requirements to all hazardous liquid gathering (including oil) pipelines. The final rule requires additional event-driven and periodic inspections, requires the use of leak detection systems on all hazardous liquid pipelines, modifies repair criteria, and requires certain pipelines to eventually accommodate in-line inspection tools. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump Administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. Accordingly, the anticipated January 2017 rulemaking was never published in the Federal Register. In addition, on April 8, 2016, PHMSA published a notice of proposed rule-making, or NPRM, addressing natural gas transmission and gathering lines. The proposed rule would include changes to existing integrity management requirements and would expand assessment and repair requirements to pipelines in MCAs, along with other changes. Further, this NPRM would build on the requirements in an Advisory Bulletin PHMSA issued in May 2012, which advised pipeline operators of anticipated changes in annual reporting requirements and that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Comments on the NPRM were due on July 7, 2016; further action is pending. TEP is still monitoring and evaluating the effects of these proposed and recently finalized requirements on its operations.
On June 22, 2016, President Obama signed the PIPES Act, that reauthorizes PHMSA's oil and gas pipeline programs through 2019 and provides for the following new mandates, among others:
Empowers PHMSA to issue emergency orders to individual operators, groups of operators, or the industry upon a written finding that an unsafe condition or practice constitutes or is causing an imminent hazard;
Requires PHMSA, in consultation with other federal agencies, to issue minimum safety standards for underground natural gas storage facilities within two years;
Requires PHMSA to conduct post-inspection briefings outlining any concerns within 30 days and providing written preliminary findings within 90 days to the extent practicable;
Requires liquid pipeline operators to provide safety data sheets on spilled product to the designated federal on-scene coordinator and appropriate state and local emergency responders within 6 hours of telephonic or electronic notice of an accident to the National Response Center; and
Requires PHMSA to publish updates on its website every 90 days on the status of an outstanding final rule required by a statutory mandate.
On December 14, 2016, PHMSA issued an IFR that addresses safety issues related to downhole facilities, including well integrity, well bore tubing and casing at underground natural gas storage facilities. The IFR incorporates by reference two of the American Petroleum Institute’s Recommended Practice standards and mandates certain reporting requirements for operators of underground natural gas storage facilities. Operators of natural gas storage facilities were given one year from January 18, 2017, the effective date of the IFR, to implement this first set of PHMSA regulations governing underground storage fields. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the IFR that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule.
The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline's integrity and changes to the amount of pipe determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs, such as the MCAs proposed by the April 2016 NPRM, can have a significant impact on the costs to perform integrity testing and repairs.
For example, starting in 2014, Trailblazer’s operating capacity was decreased as a result of smart tool surveys that identified approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing subscription levels or had a material adverse financial impact on us. However, Trailblazer intends to continue performing remediation to increase and maximize its operating capacity over the long-term and expects to spend in excess of $20 million during 2018 for this pipe replacement and remediation work. Trailblazer is exploring all possible cost recovery options to recover expenditures, including recovery through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.
Additionally, in connection with certain crack tool runs on the Pony Express System completed in 2015 and 2016, Pony Express completed approximately $10 million of remediation in 2016 for anomalies identified on the Pony Express System associated with portions of the pipeline converted from natural gas to crude oil service, and completed additional remediation in 2017 on the Pony Express System of approximately $8.2 million.
There can be no assurance as to the amount or timing of future expenditures required to remediate or resolve these issues, and actual future expenditures may be different from the amounts we currently anticipate. These integrity issues could have a material adverse effect on our business, financial position, results of operations and prospects.
We will continue pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the U.S. Department of Transportation regulations. The results of these tests could cause us to incur potentially material unanticipated capital and operating expenditures for repairs or upgrades.
Further, additional laws, regulations and policies that may be enacted or adopted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. For example, PHMSA issued an Advisory Bulletin in May 2012 which advised pipeline operators that they must have records to document the MAOP for each section of their pipeline and that the records must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of verifiable pressures, could significantly increase its costs. TIGT continues to investigate and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for MAOP. TEP is currently undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally, failure to locate such records or verify maximum pressures could require TEP to operate at reduced pressures, which would reduce available capacity on its natural gas pipeline systems. These specific requirements do not currently apply to crude oil pipelines, but proposed regulations implementing the Pipeline Safety Act of 2011 and future regulations implementing the PIPES Act likely will expand the scope of regulation applicable to crude oil pipelines. There can be no assurance as to the amount or timing of future expenditures required to comply with pipeline integrity regulation, and actual future expenditures may be different from the amounts TEP currently anticipates. In addition, TEP may be subject to enforcement actions and penalties for failure to comply with pipeline regulations. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on its business, financial position, results of operations and prospects. In addition, TEP may be subject to enforcement actions and penalties for failure to comply with pipeline regulations.
TEP's operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose TEP to significant costs, liabilities and expenditures that could exceed its current expectations.
Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in TEP's crude oil transportation, storage, gathering and terminalling, natural gas transportation, storage, gathering and processing, NGL transportation and water business services, and as a result, TEP may be required to make substantial expenditures that could exceed current expectations. TEP's operations are subject to extensive federal, state, and local laws and regulations governing health and safety aspects of its operations, environmental protection, including the discharge of materials into the environment, and the security of chemical and industrial facilities. These laws include, but are not limited to, the following:
CAA and analogous state and local laws, which impose obligations related to air emissions and which the EPA has relied upon as authority for adopting climate change regulatory initiatives;
CWA and analogous state and local laws, which regulate discharge of pollutants or fill material from its facilities to state and federal waters, including wetlands and which require compliance with state water quality standards;
CERCLA and analogous state and local laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by TEP or locations to which TEP has sent wastes for disposal;
RCRA and analogous state and local laws, which impose requirements for the handling and discharge of hazardous and nonhazardous solid waste from its facilities;
The SDWA, which ensures the quality of the nation's public drinking water through adoption of drinking water standards and controls the waste fluids from disposal wells into below-ground formations;
OSHA and analogous state and local laws, which establish workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;
NEPA and analogous state and local laws, which require federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;
The Migratory Bird Treaty Act, or MBTA, and analogous state and local laws, which implement various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;
ESA and analogous state and local laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species;
Bald and Golden Eagle Protection Act, or BGEPA, and analogous state and local laws, which prohibit anyone, without a permit issued by the Secretary of the Interior, from "taking" bald or golden eagles, including their parts, nests, or eggs, and defines "take" as "pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, molest or disturb;"
OPA and analogous state and local laws, which impose liability for discharges of oil into waters of the United States and requires facilities which could be reasonably expected to discharge oil into waters of the United States to maintain and implement appropriate spill contingency plans; and
National Historic Preservation Act, or NHPA, and analogous state and local laws, which are intended to preserve and protect historical and archeological sites.
Various governmental authorities, including but not limited to the EPA, the U.S. Department of the Interior, the U.S. Department of Homeland Security, and analogous federal, state and local agencies have the power to enforce compliance with these and other similar laws and regulations and the permits and related plans issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these and other similar laws, regulations, permits, plans and agreements may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of TEP's operations, and delays in granting permits.
There is inherent risk of the incurrence of environmental costs and liabilities in TEP's business, some of which may be material, due to its handling of the products TEP transports, processes, treats, disposes, gathers, or stores, air emissions related to its operations, historical industry operations, and waste disposal practices, such as the prior use of flow meters and manometers containing mercury. These activities are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and natural and cultural resources. These laws and regulations can restrict or impact its business activities in many ways, such as restricting the way TEP handles or disposes of wastes or requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including but not limited to CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of materials associated with oil, natural gas and wastes on, under, or from its properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under its control. TEP is generally responsible for all liabilities associated with the environmental condition of its facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, TEP could acquire, or be required to provide indemnification against, environmental liabilities that could expose TEP to material losses, which may not be covered by insurance. In addition, the steps TEP could be required to take to bring certain facilities into compliance could be prohibitively expensive, and TEP might be required to shut down, divest or alter the operation of those facilities, which might cause TEP to incur losses. TEP is currently conducting remediation at several sites to address contamination. For these ongoing environmental remediation projects, TEP spent approximately $990,000 in 2016, approximately $568,000 in 2017 and TEP has budgeted approximately $620,000 for 2018.
Private parties, including but not limited to the owners of properties through which TEP's pipelines pass and facilities where its wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws, regulations and permits issued thereunder, or for personal injury or property damage arising from its operations. Some sites at which TEP operates are located near current or former third-party hydrocarbon storage, processing, operations or other facilities, and there is a risk that contamination has migrated from those sites to TEP's that could result in remedial action. In addition, increasingly strict laws, regulations and enforcement policies could materially increase its compliance costs and the cost of any remediation that may become necessary. TEP's insurance does not cover all environmental risks and costs and may not provide sufficient coverage if an environmental claim is made against TEP.
In June 2016, the EPA extended its National Enforcement Initiatives, enforcement priorities list, including an initiative related to Energy Extraction Activities, for 2017 through 2019, and the EPA is retaining the Energy Extraction Activities initiative for an additional three years, effective October 2016. TEP cannot predict what the results of the current initiative or any future initiative will be, or whether federal, state or local laws or regulations will be enacted in this area. If new regulations
are imposed related to oil and gas extraction, the volumes of products, including hydrocarbons and water, that TEP transports, stores, gathers, disposes and/or processes could decline and its results of operations could be materially and adversely affected.
TEP's business may be materially and adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits or plans developed thereunder. Also, TEP might not be able to obtain or maintain from time to time all required environmental regulatory approvals for its operations, or may have to implement contingencies or conditions in order to obtain such approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if TEP fails to obtain and comply with them, the operation, maintenance or construction of its facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to its business, financial condition, results of operations and cash flows. For instance, on November 25, 2014, the Wyoming Department of Environmental Quality issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Casper Gas Plant Depropanizer project. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014 and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of the CAA's NSPS Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing. Costs associated with penalties and to comply with the terms of any consent decree or settlement, as well as with Subpart OOOO, could be material.
TEP is also generally responsible for all liabilities associated with the environmental condition of its facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, TEP could acquire, or be required to provide indemnification against, environmental liabilities that could expose TEP to material losses, which may not be covered by insurance. In addition, the steps TEP could be required to take to bring certain facilities into compliance could be prohibitively expensive, and TEP might be required to shut down, divest or alter the operation of those facilities, which might cause TEP to incur losses. As an example, in August 2011, the EPA and the Wyoming Department of Environmental Quality conducted an inspection of the Leak Detection and Repair Program, or LDAR, at the Casper Plant in Wyoming. In September 2011, TMID received a letter from the EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the CAA. TMID received a letter from the EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. In July 2014, the EPA provided TMID with a draft Consent Decree that has been the basis for subsequent settlement negotiations. Subsequently, the EPA indicated that it intends to join TIGT as a defendant in this matter based on TIGT's ownership of the compressor station located adjacent to the Casper Gas Plant in order to address alleged LDAR issues at the compressor station. Settlement negotiations are continuing between the parties. TEP is not currently able to estimate the costs that may be associated with a settlement or other resolution of this matter, which could be material.
TEP has agreed to a number of conditions in its environmental permits and associated plans, approvals and authorizations that require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve, among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas where TEP currently operates, and would operate if its facilities are extended or expanded, or if TEP constructs new facilities, and TEP is unable to predict the effect that any such measures would have on its business, financial position, results of operations or prospects.
Also, on June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or Corps, issued a final rule to clarify the term "waters of the United States" as it pertains to federal jurisdiction under the CWA. This rule has been challenged in federal courts at both the appellate and district court levels. Based on a January 2018 U.S. Supreme Court decision, only the district courts were determined to have jurisdiction to hear the challenges. As a result, stays entered by district courts remain in effect, however, a stay previously issued by the Sixth Circuit is expected to be withdrawn. Accordingly, although the rule is currently stayed in several states pursuant to a district court decision, it could become effective in other states absent additional agency or judicial action. In July 2017 the EPA and the U.S. Army Corps of Engineers published a proposed rule to rescind the 2015 rule. In February 2018, the agencies also published a final rule adding a February 6, 2020 applicability date to the 2015 rule. The final rule adding this applicability date is currently subject to litigation. Although it is unclear how the Corps and the EPA will implement the 2015 rule at this time, the rule may require additional Corps or EPA authorizations or involvement in TEP's future operations, for instance, if TEP extends its pipelines into or across areas (such as certain ditches) newly considered "waters of the United States" under the final rule.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be materially different from the amounts TEP currently anticipates. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are
not fully recoverable from its customers, could have a material adverse effect on TEP's business, financial position, results of operations and prospects.
Climate change regulation at the federal, state or regional levels could result in increased operating and capital costs for TEP and reduced demand for its services.
The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. On April 22, 2016, 175 countries, including the United States, signed the Paris Agreement. The Paris Agreement will require countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in August of 2017, the United States informed the United Nations of its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is November 2020.
Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA also expanded its existing GHG emissions reporting requirements to include upstream petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year. Some of our facilities are required to report under this rule, and operational and/or regulatory changes could require additional facilities to comply with GHG emissions reporting requirements. Furthermore, the EPA adopted a final rule, effective August 2, 2016, imposing more stringent controls on methane and volatile organic compounds emissions from oil and gas development, production, and transportation operations under the New Source Performance Standard, or NSPS, program. The EPA is currently reconsidering the rule and has proposed to stay its requirements. However, the rule currently remains in effect. The EPA also finalized a rule regarding the alternative criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements across the oil and gas industry. The BLM also adopted new rules, effective January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. In December 2017, the BLM issued a final rule that temporarily suspends or delays these requirements until January 2019, while BLM considers revising or rescinding these requirements. In addition, many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, to acquire and surrender emission allowances with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.
The adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, TEP's equipment and operations could require TEP to incur additional costs to reduce emissions of GHGs associated with its operations, could adversely affect its operations in the absence of any permits that may be required to regulate emission of GHGs, or could adversely affect demand for the crude oil and natural gas TEP gathers, processes, or otherwise handles. For instance, the EPA's recently finalized NSPS rules or future rules under CAA Section 111(d) could result in the direct regulation of GHGs associated with its operations, including the operations of Rockies Express. TEP is not able at this time to estimate such increased costs; however, they could be significant. While TEP may be able to recover some or all of such increased costs in the rates charged by its processing facilities, such recovery of costs is uncertain and may depend on the terms of its contracts with its customers.
If new laws or regulations that significantly restrict GHGs are adopted, such laws could also make it more difficult or costly for TEP's customers to operate, which could reduce its customers' production and therefore the demand for its services. While TEP is not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for TEP. Restrictions on GHG emissions could also reduce the volume of natural gas that its customers produce, and could thereby adversely affect its revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for TEP and its customers, which could ultimately decrease end-user demand for its services and could have a material adverse effect on its business. In addition, to the extent financial markets view climate change and GHG emissions as a financial risk, this could materially and adversely impact its cost of and access to capital. Legislation or regulations that may be adopted to address climate change, or incentives to conserve energy or use alternative energy sources, could also affect the markets for its services by making natural gas and crude oil products less desirable than competing sources of energy. In addition, in response to concerns related to climate change, certain investors may divest oil and gas investments. For example, officials in New York state and New York City have announced their intent to divest
the state and city pension funds’ holdings in fossil fuel companies. Such divestments could adversely impact TEP’s costs of and access to capital.
Increased regulation of hydraulic fracturing and other oil and natural gas processing operations could affect TEP's operations and result in reductions or delays in production by its customers, which could have a material adverse impact on its revenues.
A sizeable portion of the production by TEP's customers comes from hydraulically fractured wells. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process typically involves the injection of water, sand and a small percentage of chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state's oil and gas commission; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the SDWA and has released draft permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where the EPA is the permitting authority. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, on May 19, 2014, the EPA published an advance notice of rulemaking under the Toxic Substances Control Act, to gather information regarding the potential regulation of chemical substances and mixtures used in oil and gas exploration and production. In May 2016, the EPA issued final rules that update new source performance standard requirements and that will impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. The EPA is currently reconsidering the rule and has proposed to stay its requirements. However, the rule currently remains in effect. The EPA also issued a final rule in June 2016 that prohibits the discharge of hydraulic fracturing wastewater from onshore unconventional oil and gas extraction facilities into publicly owned sewage treatment plants. Also, effective June 24, 2015, the BLM adopted rules regarding well stimulation, chemical disclosures, water management, and other requirements for hydraulic fracturing on federal and Indian lands. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The BLM also adopted new rules effective January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. In December 2017, the BLM issued a final rule that temporarily suspends or delays these requirements until January 2019, while BLM considers revising or rescinding these requirements.
Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, and in some cases, may seek to ban hydraulic fracturing entirely. Some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing, including temporary or permanent bans, additional permit requirements, operational restrictions and chemical disclosure obligations on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. Other governmental agencies, including the U.S. Department of Energy and the EPA, have evaluated or are evaluating various other aspects of hydraulic fracturing such as the potential environmental effects of hydraulic fracturing on drinking water and groundwater. On December 13, 2016, the EPA released a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, concluding that there is scientific evidence that hydraulic fracturing activities potentially can impact drinking water resources in the United States under some circumstances.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or significantly more costly for TEP's customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of crude oil, natural gas or other hydrocarbons that its customers produce, and could thereby adversely affect its revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for TEP and its customers, which could ultimately decrease end-user demand for its services and could have a material adverse effect on its business.
TEP's produced water disposal operations may be subject to additional regulation and liability or claims of environmental damages.
TEP operates produced water disposal wells which are regulated under the federal SDWA as Class II wells and under state laws. State laws and regulations that govern these operations can be more stringent than the SDWA. In addition, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase its compliance costs and the cost of any remediation that may become necessary. TEP may also incur material environmental costs and liabilities. Furthermore, its insurance may not provide sufficient coverage in the event an environmental claim is made against TEP. In addition, although the disposal wells have received certain governmental regulatory licenses, permits or approvals, this does not shield TEP from potential claims from third parties claiming contamination of their water supply or other environmental damages. Remediation
of environmental contamination or damages can be extremely costly and such costs, if TEP were found liable, may have a material adverse effect on its business, financial condition and results of operations.
Produced water injection well operations and hydraulic fracturing may cause induced seismicity.
State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In a few instances, operators of produced water injection wells in the vicinity of seismic events have been ordered to reduce produced water injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado and Texas, have modified their regulations to account for induced seismicity. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In 2015, the United States Geological Study identified eight states, including Colorado, Oklahoma and Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that produced water disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. The Oklahoma Corporation Commission, or OCC, has adopted a plan calling for mandatory reductions in oil and gas wastewater disposal well volumes, the implementation of which, has involved reductions of injection or shut-ins of disposal wells. The OCC has also released guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing activities. These developments could result in additional regulation and restrictions on the use of produced water injection wells and hydraulic fracturing. Such regulations and restrictions could have a material adverse effect on TEP's business, financial condition and results of operations.
TEP is exposed to costs associated with lost and unaccounted for volumes.
A certain amount of natural gas and crude oil may be lost or unaccounted for in normal operations in connection with their transportation across a pipeline system. Under TEP's tariffs and contractual arrangements with its customers TEP is entitled to retain a specified volume of natural gas and crude oil in order to compensate TEP for such lost and unaccounted for volumes, as well as the natural gas used to run its natural gas compressor stations, which we refer to collectively as fuel usage. TEP's pipeline tariffs currently contain fuel usage true-up mechanisms. The use of fuel (natural gas, electric and lost and unaccounted for gas) trackers on the Rockies Express Pipeline, the TIGT System, and the Trailblazer Pipeline, while minimizing risk over time, nevertheless leaves the systems exposed to the possibility of under- or over-collections on an annual basis. The level of lost and unaccounted for volumes, and natural gas fuel usage, on its pipeline systems may exceed the natural gas and crude oil volumes retained from its customers as compensation for its lost and unaccounted for volumes, and fuel usage, pursuant to its tariffs and contractual agreements, and it may be necessary to purchase natural gas or crude oil in the market to make up for the difference, which exposes TEP to commodity price risk. Future exposure to the volatility of natural gas and crude oil prices as a result of lost and unaccounted for volume imbalances could have a material adverse effect on its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.
Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on TEP's natural gas storage business.
Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for TEP's storage services. The natural gas storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for its services and the rates TEP is able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, then demand for its storage services and the prices that TEP will be able to charge for those services may decline.
In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated storage expansion activities. Alternatively, an extended period of low seasonal volatility in natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on TEP's business, financial condition, results of operations and ability to make distributions to its unitholders.
Certain portions of TEP's transportation, storage and processing facilities have been in service for several decades. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with its facilities that could have a material adverse effect on its business and results of operations.
Significant portions of TEP's transportation, storage and processing systems have been in service for several decades. The age and condition of its facilities could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce its revenue. Any significant increase in maintenance
and repair expenditures or loss of revenue due to the age or condition of its facilities could adversely affect its business and results of operations and its ability to make cash distributions to its unitholders.
TEP's revolving credit facility and the indentures governing TEP's senior notes contain certain restrictions which could adversely affect its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.
TEP is dependent upon certain earnings and cash flow generated by its operations in order to meet its debt service obligations. TEP's revolving credit facility, the indenture governing its 5.50% senior notes due 2024 (the "2024 Notes"), and the indenture governing its 5.50% senior notes due 2028 (the "2028 Notes") contain, and any future financing agreements may contain, operating and financial restrictions and covenants that could restrict its ability to finance future operations or capital needs, or to expand or pursue our business activities, which may, in turn, limit its ability to make cash distributions to its unitholders. For example, TEP's revolving credit facility limits our ability to, among other things:
incur or guarantee additional indebtedness;
redeem or repurchase units or make distributions under certain circumstances;
make certain investments and acquisitions;
incur certain liens or permit them to exist;
enter into certain types of transactions with affiliates;
merge or consolidate with another company; and
transfer, sell or otherwise dispose of assets.
TEP's revolving credit facility also contains covenants requiring TEP to maintain certain financial ratios. TEP's ability to meet those financial ratios and tests can be affected by events beyond its control, and TEP cannot assure you that it will meet those ratios and tests. Further, TEP's obligations under the revolving credit facility are (i) guaranteed by TEP and each of its existing and subsequently acquired or organized direct or indirect wholly-owned domestic subsidiaries, subject to its ability to designate certain subsidiaries as "Unrestricted Subsidiaries," and (ii) secured by a first priority lien on substantially all of the present and after acquired property owned by TEP and each guarantor (other than real property interests related to its pipelines).
Similarly, the indenture governing TEP's 2024 Notes contains covenants that, among other things, limit its ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all its properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates.
In addition, the indenture governing TEP's 2028 Notes contains covenants that, among other things, limit its ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all of its properties to, another person.
The provisions of TEP's revolving credit facility and the indentures governing TEP's senior notes may affect TEP's ability to obtain future financing and pursue attractive business opportunities and its flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of its revolving credit facility or the indentures governing TEP's senior notes, including a failure to meet any of the required financial ratios and tests, could result in a default or an event of default that could enable its lenders or the holders of the senior notes to declare the outstanding principal of that indebtedness, together with accrued and unpaid interest, to be immediately due and payable, and in the case of the revolving credit facility, would prohibit TEP's ability to make quarterly distributions. If the payment of its indebtedness is accelerated and TEP is unable to repay the indebtedness in full, its lenders could foreclose on the assets pledged by TEP and the guarantors under the revolving credit facility. In that case, its assets may be insufficient to repay such indebtedness in full, and its unitholders could experience a partial or total loss of their investment.
Tallgrass Equity's ownership in TEP's IDRs, TEP's common units and TEP's general partner interest, are pledged under Tallgrass Equity's revolving credit facility.
Tallgrass Equity's direct ownership of 25,619,218 TEP common units and its direct ownership of its general partner (which owns TEP's IDRs and general partner interest), are pledged as security under Tallgrass Equity's revolving credit facility. Tallgrass Equity's revolving credit facility contains customary and other events of default. Upon an event of default, the lenders under Tallgrass Equity's revolving credit facility could foreclose on Tallgrass Equity's ownership interest in TEP GP and the 25,619,218 TEP common units owned by Tallgrass Equity. This could ultimately result in a change in control of TEP GP, which
would constitute an immediate event of default under TEP's credit facility. This would have a material adverse effect on TEP's business, financial condition and results of operations.
TEP's future indebtedness levels may limit its flexibility to obtain financing and to pursue other business opportunities.
TEP's level of indebtedness could have important consequences to TEP, including the following:
its ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
its funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of its cash flow required to make interest payments on its indebtedness;
TEP may be more vulnerable to competitive pressures or a downturn in its business or the economy generally; and
its flexibility in responding to changing business and economic conditions may be limited.
TEP's ability to service its indebtedness depends upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond its control. If its operating results are not sufficient to service its current or future indebtedness, TEP will be forced to take actions such as reducing distributions, reducing or delaying its business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. Taking any of these actions is likely to reduce the value of an investment in TEP. Plus, TEP may not be able to effect any of these actions on satisfactory terms or at all.
Increases in interest rates could adversely impact TEP's unit price, its ability to issue equity or incur indebtedness for acquisitions or other purposes and its ability to make cash distributions at its intended levels.
The interest rate on borrowings under TEP's revolving credit facility float based upon one or more of the prime rate, the U.S. federal funds rate or LIBOR. As a result, those borrowings, as well as borrowings under its possible future credit facilities or debt offerings, could be higher than current levels, causing its financing costs to increase accordingly. TEP does not currently hedge the interest rate risk on borrowings under its revolving credit facility.
As with other yield-oriented securities, TEP's unit price is impacted by the level of its cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in its units, and a rising interest rate environment could have an adverse impact on its unit price, its ability to issue equity or incur indebtedness for acquisitions or other purposes and its ability to make cash distributions at its intended levels.
Rockies Express has a substantial amount of indebtedness and Rockies Express may not be able to generate a sufficient amount of cash flow to meet its debt service obligations.
As of December 31, 2017, Rockies Express had approximately $2.575 billion of total indebtedness outstanding. In addition, Rockies Express has a revolving credit facility, which will mature on January 31, 2020, with $150 million of additional borrowing capacity available as of December 31, 2017.
The scheduled maturities of Rockies Express' outstanding indebtedness balances as of December 31, 2017 are summarized as follows (in millions):
|
| | | | |
| Year | | Scheduled Maturities |
| 2018 | | $ | 550.0 |
|
| 2019 | | 525.0 |
|
| 2020 | | 750.0 |
|
| Thereafter | | 750.0 |
|
The substantial indebtedness held by Rockies Express could have important consequences. For example, it could:
make it more difficult for Rockies Express to satisfy its obligations with respect to its indebtedness;
increase the vulnerability of Rockies Express to general adverse economic and industry conditions;
limit the ability of Rockies Express to obtain additional financing for future working capital, capital expenditures and other general business purposes;
require Rockies Express to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of cash flow for operations and other purposes;
limit its flexibility in planning for, or reacting to, changes in its business and the industry in which Rockies Express operates;
place Rockies Express at a competitive disadvantage compared to its competitors that have less indebtedness; and
have a material adverse effect if Rockies Express fails to comply with the covenants in the indenture relating to its notes or in the instruments governing its other indebtedness.
The terms of the indentures governing the existing Rockies Express notes do not restrict the amount of additional unsecured indebtedness Rockies Express may incur, and the agreement governing its credit facility permits additional unsecured borrowings. If new indebtedness is added to the current indebtedness levels, these related risks could increase.
Rockies Express' ability to make scheduled payments or to refinance its obligations with respect to its indebtedness will depend on its financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business, and other factors beyond its control. In addition, a significant amount of Rockies Express' revenue in 2017 was generated by long-term contracts that expire in 2019 and Rockies Express may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis, which may result in lower cash flows in periods subsequent to 2019. We cannot assure you that Rockies Express' operating performance, cash flow and capital resources will be sufficient for payment of its indebtedness in the future. In the event that Rockies Express is required to dispose of material assets or restructure its indebtedness to meet its debt service and other obligations, we cannot assure you as to the terms of any such transaction or how soon any such transaction could be completed.
If Rockies Express' cash flow and capital resources are insufficient to fund its debt service obligations, it may be forced to sell material assets, obtain additional capital, including through capital contributions from its members, or restructure its indebtedness. The payment of additional capital contributions by TEP and Tallgrass Equity to Rockies Express to fund such obligations would reduce the amount of cash available to make distributions to TEP's unitholders and Tallgrass Equity's unitholders.
Rockies Express' revolving credit facility contains certain restrictions which could limit its financial flexibility and increase its financing costs.
Rockies Express' revolving credit facility contains restrictive covenants that may prevent it from engaging in various transactions that Rockies Express deems beneficial and that may be beneficial to Rockies Express. The revolving credit facility generally requires Rockies Express to comply with various affirmative and negative covenants, including a limit on the leverage ratio (as defined in the credit agreement) of Rockies Express and restrictions on:
incurring secured indebtedness;
entering into mergers, consolidations and sales of assets;
granting liens;
entering into transactions with affiliates; and
making restricted payments.
Instruments governing any future indebtedness at Rockies Express may contain similar or more restrictive provisions. Rockies Express' ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.
TEP does not own most of the land on which its assets are located, which could disrupt its operations and subject TEP to increased costs.
TEP does not own in fee but rather have leases, easements, rights-of-way, permits, surface use agreements, and licenses for most of the land on which its assets are located, and TEP is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if TEP does not have valid interests in the land, if such interests in the land lapse or terminate or if its facilities are not properly located within the boundaries of such interests in the land. For example, the West Frenchie Draw treating facility is located on land leased from the Wyoming Board of Land Commissioners pursuant to a contract that can be terminated at any time. Although many of these rights are perpetual in nature, TEP occasionally obtains the right to construct and operate pipelines on other owners' land for a specific period of time. If TEP was to be unsuccessful in renegotiating its leases, easements, rights-of-way, permits, surface use agreements and licenses, TEP might incur increased costs to maintain its assets, which could have a material adverse effect on its business, results of operations, financial condition and ability to make distributions to its unitholders. In addition, TEP is subject to the possibility of increased costs under its rental agreements with landowners, primarily through rental increases and renewals of expired agreements.
Some leases, easements, rights-of-way, permits, surface use agreements and licenses for TEP's assets are shared with other pipeline systems and other assets owned by third parties. TEP or owners of the other pipeline systems or assets may not have
commenced or concluded eminent domain proceedings for some rights-of-way. In some instances, lands over which leases, easements, rights-of-way, permits, surface use agreements and licenses have been obtained are subject to prior liens which have not been subordinated to the grants to TEP.
TEP's interstate natural gas pipeline systems have federal eminent domain authority in certain instances. To the extent federal eminent domain authority is not available, the availability of eminent domain for future crude oil or natural gas pipeline expansions varies from state to state, depending upon the laws of the particular state. Regardless, TEP must compensate landowners for the use of their property, which may include any loss of value to the remainder of their property not being used by TEP, which are sometimes referred to as "severance damages." Severance damages are often difficult to quantify and their amount can be significant. In eminent domain actions, such compensation may be determined by a court. TEP's inability to exercise the power of eminent domain could negatively affect its business if TEP was to lose the right to use or occupy the property on which its crude oil or natural gas pipeline systems are located.
A shortage of skilled labor in the midstream industry could reduce labor productivity and increase costs, which could have a material adverse effect on TEP's business and results of operations.
The transportation, storage and terminalling of crude oil, the transportation, storage and processing of natural gas, and the transportation, gathering and disposal of water requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. If TEP experiences shortages of skilled labor in the future, its labor and overall productivity or costs could be materially and adversely affected. If its labor prices increase or if TEP experiences materially increased health and benefit costs for employees, its results of operations could be materially and adversely affected.
If TEP fails to develop or maintain an effective system of internal controls, TEP may not be able to report its financial results accurately or prevent fraud, which would likely have a negative impact on the market price of its common units.
Upon the completion of the TEP IPO, TEP became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended. Effective internal controls are necessary for TEP to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. TEP's efforts to develop and maintain its internal controls may not be successful, and TEP may be unable to maintain effective controls over its financial processes and reporting in the future or to comply with its obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires TEP, among other things, to annually review and report on, and its independent registered public accounting firm to attest to, the effectiveness of its internal controls over financial reporting. Any failure to develop, implement or maintain effective internal controls or to improve its internal controls could harm its operating results or cause TEP to fail to meet its reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, TEP can provide no assurance as to its, or TEP's independent registered public accounting firm's, conclusions about the effectiveness of its internal controls, and TEP may incur significant costs in its efforts to comply with Section 404. Ineffective internal controls will subject TEP to regulatory scrutiny and a loss of confidence in its reported financial information, which could have an adverse effect on its business and would likely have a negative effect on the trading price of its units.
New technologies, including those involving recycling of produced water or the replacement of water in fracturing fluid, may adversely affect TEP's future results of operations and financial condition.
The produced water disposal industry is subject to the introduction of new waste treatment and disposal techniques and services using new technologies including those involving recycling of produced water, some of which may be subject to patent protection. As competitors and others use or develop new technologies or technologies comparable to TEP's water business services in the future, TEP may lose market share or be placed at a competitive disadvantage. For example, some companies have successfully used propane as the fracturing fluid instead of water. Further, TEP may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of its competitors may have greater financial, technical and personnel resources than TEP does, which may allow them to gain technological advantages or implement new technologies before TEP can. Additionally, TEP may be unable to implement new technologies or products at all, on a timely basis or at an acceptable cost. New technology could also make it easier for TEP's customers to vertically integrate their operations or reduce the amount of waste produced in oil and natural gas drilling and production activities, thereby reducing or eliminating the need for third-party disposal. Limits on its ability to effectively use or implement new technologies, including in its water business services, may have a material adverse effect on its business, financial condition and results of operations.
TEP's business could be negatively impacted by security threats, including cyber security threats, and related disruptions.
TEP relies on its information technology infrastructure to process, transmit and store electronic information, including information TEP uses to safely operate its assets. TEP may face cyber security and other security threats to its information technology infrastructure, which could include threats to its operational and safety systems that operate its pipelines, plants and assets. TEP could face unlawful attempts to gain access to its information technology infrastructure, including coordinated
attacks from hackers, whether state-sponsored groups, "hacktivists," or private individuals. The age, operating systems or condition of its current information technology infrastructure and software assets and its ability to maintain and upgrade such assets could affect its ability to resist cyber security threats. TEP could also face attempts to gain access to information related to its assets through unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information, otherwise known as "social engineering."
TEP's information technology infrastructure is critical to the efficient operation of its business and essential to its ability to perform day-to-day operations. Breaches in its information technology infrastructure or physical facilities, or other disruptions, could result in damage to its assets, service interruptions, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on its operations, financial position, results of operations and prospects.
If TEP is unable to protect its information and telecommunication systems against disruptions or failures, its operations could be disrupted.
TEP relies extensively on computer systems to process transactions, maintain information and manage its business. Disruptions in the availability of its computer systems could impact its ability to service its customers and adversely affect its sales and results of operations. TEP is dependent on internal and third-party information technology networks and systems, including the Internet, wired, and wireless communications, to process, transmit and store electronic information. TEP's computer systems are subject to damage or interruption due to system replacements, implementations and conversions, power outages, computer or telecommunication failures, computer viruses, security breaches, catastrophic events such as fires, tornadoes, snowstorms and floods and usage errors by its employees, consultants and contractors. If its computer systems are damaged or cease to function properly, TEP may have to make a significant investment to fix or replace them, and TEP may have interruptions in its ability to service its customers. Although TEP attempts to reduce these risks by using redundancy for certain critical systems, this disruption caused by the unavailability of TEP's computer systems could nevertheless significantly disrupt its operations or may result in financial damage or loss due to, among other things, lost or misappropriated information.
Tax Risks
As our only cash-generating assets consist of our membership interest in Tallgrass Equity and its related direct and indirect interests in TEP, our tax risks are primarily derivative of the tax risks associated with an investment in TEP.
The tax treatment of TEP depends on its status as a partnership for U.S. federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat TEP as a corporation for U.S. federal income tax purposes or TEP becomes subject to material additional amounts of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distributiondividends to us and increase the portion of our distributionsdividends treated as taxable dividends.
We own a 31.43%55.79% membership interest in Tallgrass Equity, which directly owns the Acquired TEP Units and indirectly owns all TEP's IDRs and TEP's general partner interest (which was approximately 1.13% as of February 13, 2018).the partnership interests in TEP. Accordingly, the value of our indirect investment in TEP, as well as the anticipated after-tax economic benefit of an investment in our Class A shares, depends largely on TEP being treated as a partnership for U.S. federal income tax purposes, which requires that 90% or more of TEP's gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code of 1986, as amended (the "Code").
Despite the fact that TEP is a limited partnership under Delaware law and, unlike us, has not elected to be treated as a corporation for U.S. federal income tax purposes, it is possible, under certain circumstances, for a publicly traded partnership such as TEP to be treated as a corporation for U.S. federal income tax purposes. Although we do not believe based upon TEP's current operations that TEP is so treated, a change in TEP's business could cause it to be treated as a corporation for U.S. federal income tax purposes or otherwise subject it to U.S. federal income taxation as an entity.
For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the U.S. federal income tax laws that affect publicly traded partnerships. TEP is unable to predict whether any such changes or proposals will be considered or will ultimately be enacted or whether judicial or administrative interpretations of applicable law will change. Any such changes could negatively impact the value of our indirect investment in TEP. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.
If TEP were treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax on its taxable income at the corporate tax rate, which is currently 21%, and would likely pay state income taxes at varying rates. Distributions to TEP's partners, including Tallgrass Equity, would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to TEP's partners. Because a tax would be imposed upon TEP as a corporation, its cash available for distribution would be substantially reduced. Therefore, treatment of TEP as a corporation would result in a material reduction in TEP's anticipated cash flow and after-tax return to us, likely causing a substantial reduction in the value of our Class A shares.
At the state level, severalSeveral states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such a tax on TEP by any state will reduce the cash available for distributions to TEP unitholders, likely causing a substantial reduction in the value of our Class A shares.
TEP's partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects TEP to taxation as a corporation or otherwise subjects TEP to entity-level taxation for U.S. federal income tax purposes, TEP's minimum quarterly distribution and target distribution amounts will be adjusted to reflect the impact of that law on TEP. If this were to happen, the amount of distributions Tallgrass Equity receives from TEP and our resulting cash flows could be reduced substantially, which would adversely affect our ability to pay distributions.
Moreover, if TEP were treated as a corporation, we would not be entitled to the deductions associated with our initial acquisition of interests in Tallgrass Equity or subsequent exchanges of retained Tallgrass Equity interests and Class B shares for our Class A shares. As a result, if TEP were treated as a corporation, (i) our liability for taxes would likely be higher, further reducing our cash available for distribution and (ii) a greater portion of the cash we are able to distribute would be treated as a taxable dividend.
We may incur substantial corporate income tax liabilities on our allocable share of TEP income.
We are classified as a corporation for U.S. federal income tax purposes and, in most states in which TEP does business, for state income tax purposes. To the extent that TEP allocates to us net taxable income in any year, current law provides that we will be subject to U.S. federal income tax at a rate of 21%, and to state income tax at rates that vary from state to state. The amount of cash available for distributiondividends to you will be reduced by the amount of any such income taxes payable by us for which we establish reserves.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal and state income tax laws and transactional tax laws such as excise, sales/use, payroll, franchise and ad valorem tax laws. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Further, taxing authorities may change their application of existing taxes, so that additional entities or transactions may become subject to an existing tax. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional tax payments, as well as interest and penalties. In one such audit, Rockies Express has appealed an excise tax assessment on the gross receipts from certain transactions issued by the Ohio Department of Taxation. If the appeal is unsuccessful, Rockies Express may be subject to substantial additional excise taxes in the future, and imposition of such excise taxes could reduce the cash available for distributiondividends to our Class A shareholders.
If the IRS makes audit adjustments to TEP's income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from TEP, in which case TEP may require its unitholders and former unitholders to reimburse it for such taxes (including any applicable penalties or interest) or, if TEP is required to bear such payment, TEP's cash available for distribution to TEP's unitholders might be substantially reduced.
If the IRS makes audit adjustments to TEP's income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from TEP. TEP will generally have the ability to shift any such tax liability to its general partner and its unitholders in accordance with their interests in TEP during the year under audit, but there can be no assurance that TEP will be able to (or will choose to) do so under all circumstances. If TEP is required to make payments of taxes, penalties and interest resulting from audit adjustments, it may require its unitholders and former unitholders to reimburse it for such taxes (including any applicable penalties or interest) or, if TEP is required to bear such payment, its cash available for distribution to its unitholders might be substantially reduced.
Taxable gain or loss on the sale of our Class A shares could be more or less than expected.
If a holder sells our Class A shares, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder's tax basis in those Class A shares. To the extent that the amount of our distributionsdividends exceeds our current and accumulated earnings and profits, the distributionsdividends will be treated as a tax-free return of capital and will reduce a holder's tax basis in the Class A shares. Because our distributionsdividends in excess of our earnings and profits decrease a holder's tax basis in Class A shares, such excess distributionsdividends will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the Class A shares.
Our current tax treatment may change, which could affect the value of our Class A shares or reduce our cash available for distribution.dividends.
Changes in U.S. federal income tax law relating to our tax treatment as a corporation could result in (i) our being subject to additional taxation at the entity level with the result that we would have less cash available for distributiondividends and (ii) a greater portion of our distributionsdividends being treated as taxable dividends. Moreover, we are subject to tax in numerous jurisdictions. Changes in current law in these jurisdictions, particularly relating to the treatment of deductions attributable to acquisitions of
interests in Tallgrass Equity, could result in our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution.dividends.
Any decrease in our Class A share price could adversely affect our amount of cash available for distribution.dividends.
Changes in certain market conditions may cause our Class A share price to decrease. If the Exchange Right Holders exercise their Exchange Right when our Class A share price is less than the price at which the Class A shares were sold in the TEGPTGE IPO, the ratio of our income tax deductions to gross income would decline. This decline could result in our being subject to tax sooner than expected, our tax liability being greater than expected, or a greater portion of our distributionsdividends being treated as taxable dividends.
The IRS Form 1099-DIV that you receive from your broker may over-report your dividend income with respect to our shares for U.S. federal income tax purposes, and failure to report your dividend income in a manner consistent with the IRS Form 1099-DIV that you receive from your broker may cause the IRS to assert audit adjustments to your U.S. federal income tax return. If you are a non-U.S. holder of our shares, your broker or other withholding agent may overwithhold taxes from dividends paid to you, in which case you generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to claim a refund of the overwithheld taxes.
DistributionsDividends we pay with respect to our Class A shares will constitute "dividends" for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. DistributionsDividends we pay in excess of our earnings and profits will not be treated as "dividends" for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of your tax basis in your shares and then as capital gain realized on the sale or exchange of such shares. We may be unable to timely determine the portion of our distributionsdividends that is a "dividend" for U.S. federal income tax purposes.
If you are a U.S. holder of our Class A shares, the IRS Form 1099-DIV may not be consistent with our determination of the amount that constitutes a "dividend" to you for U.S. federal income tax purposes or you may receive a corrected IRS Form 1099-DIV (and you may therefore need to file an amended federal, state or local income tax return). We will attempt to timely notify you of available information to assist you with your income tax reporting (such as posting the correct information on our website). However, the information that we provide to you may be inconsistent with the amounts reported to you by your broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to your tax return.
If you are a non-U.S. holder of our Class A shares, "dividends" for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax treaty) unless the dividends are effectively connected with your conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our distributionsdividends that is a "dividend" for U.S. federal income tax purposes, or your broker or withholding agent chooses to withhold taxes from distributionsdividends in a manner inconsistent with our determination of the amount that constitutes a "dividend" for such purposes, your broker or other withholding agent may overwithhold taxes from distributionsdividends paid to you. In such a case, you generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.
We expect that our ability to use net operating losses arising prior to the TEP Merger to offset future income will be limited as a result of the TEP Merger, and our ability to use net operating losses arising after the TEP Merger to offset future income may be limited.
We expect that our ability to use any net operating losses ("NOLs") generated by us prior to the TEP Merger to offset future income will be limited due to experiencing an "ownership change" as defined under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"), as a result of the TEP Merger. Our ability to use NOLs arising after the TEP Merger to offset future income may be substantially limited if we were to experience another ownership change.
In general, an ownership change occurs if our "5-percent shareholders," as defined under Section 382 of the Code, including certain groups of persons treated as 5-percent shareholders, collectively increased their ownership in Class A shares by more than 50 percentage points over a rolling three-year period. An ownership change can occur as a result of a public offering of Class A shares, as well as through secondary market purchases of Class A shares and certain types of reorganization transactions. As a result of the exchange of TEP common units for Class A shares in the TEP Merger, we expect that the TEP Merger caused us to experience an ownership change.
A corporation (including any entity such as us that is treated as a corporation for U.S. federal income tax purposes) that experiences an ownership change will generally be subject to an annual limitation on the use of its pre-ownership change NOLs (and certain other losses and credits) equal to the equity value of the corporation immediately before the ownership change, multiplied by the long-term tax-exempt rate (as determined by the Internal Revenue Service) for the month in which the ownership change occurs. Such a limitation could, for any given year, have the effect of increasing the amount of our U.S. federal income tax liability, which would negatively impact the amount of after-tax cash available for dividends to holders of Class A shares and our financial condition.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
A description of our properties is contained in Item 1.—Business, "Our Assets" of this Annual Report.
Our principal executive offices are located at 4200 W. 115th Street, Suite 350, Leawood, KS 66211 and our telephone number is 913-928-6060.
We own two office buildings in Lakewood, Colorado, with a portion being leased to a third party pursuant to a lease with an initial term through March 2020. In addition, we lease our principal executive offices in Leawood, Kansas. Tallgrass Energy Holdings and its affiliates pay a proportionate share of the costs to occupy the building to us pursuant to the TEP Omnibus Agreement.
Item 3. Legal Proceedings
See Note 19 – Legal and Environmental Matters, which is incorporated by reference into this Part I—Item 3 of this Annual Report.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
OurOn July 2, 2018, in connection with the TEP Merger, the ticker symbol for our Class A shares have been listed on the NYSE under the symbolwas changed from "TEGP" since the completion of the TEGP IPO on May 12, 2015.to "TGE." Our Class B shares are not listed or traded on any stock exchange. The following table sets forth the high and low sales prices of the Class A shares, as reported by the NYSE, as well as the amount of cash distributions per share declared for the periods indicated:
|
| | | | | | | | | | | | |
| Quarter Ended | | High | | Low | | Distribution per Class A Share |
| December 31, 2017 | | $ | 28.94 |
| | $ | 21.79 |
| | $ | 0.3675 |
|
| September 30, 2017 | | $ | 28.69 |
| | $ | 23.42 |
| | $ | 0.3550 |
|
| June 30, 2017 | | $ | 29.50 |
| | $ | 22.40 |
| | $ | 0.3425 |
|
| March 31, 2017 | | $ | 29.30 |
| | $ | 25.64 |
| | $ | 0.2875 |
|
| December 31, 2016 | | $ | 27.29 |
| | $ | 21.74 |
| | $ | 0.2775 |
|
| September 30, 2016 | | $ | 25.99 |
| | $ | 21.88 |
| | $ | 0.2625 |
|
| June 30, 2016 | | $ | 26.81 |
| | $ | 16.14 |
| | $ | 0.2450 |
|
| March 31, 2016 | | $ | 18.68 |
| | $ | 9.66 |
| | $ | 0.2100 |
|
Holders
As of February 13, 2018,6, 2019, there were three33 shareholders of record of our Class A shares. This number does not include shareholders whose shares are held in trust by other entities. The actual number of beneficial shareholders is greater than the number of holders of record. In addition, as of February 13, 2018, 116, 2019, 10 shareholders of record owned all 126,709,225123,887,893 of our Class B shares.
Equity Compensation Plan
See Item 12.—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for information regarding our Equity Compensation Plan.
Distributions of Available Cash
General. Our partnership agreement requires that, within 55 days after the end of each quarter, beginning with the quarter ended June 30, 2015, we distribute our available cash to Class A Shareholders of record on the applicable record date.
Definition of Available Cash. Available cash is defined in our partnership agreement and generally means, with respect to any calendar quarter, all cash and cash equivalents on hand at the date of determination of available cash for the distribution in respect of such quarter (including expected distributions from Tallgrass Equity in respect of such quarter), less the amount of cash reserves established by our general partner, which willare not be subject to a cap, to:to, among other things:
comply with applicable law;
comply with any agreement binding upon us or our subsidiaries (exclusive of TEP and its subsidiaries);
provide for future capital expenditures, debt service and other credit needs as well as any federal, state, provincial or other income tax that may affect us in the future;
permit us to pay a ratable amount to Tallgrass Equity as necessary to permit Tallgrass Equity to make capital contributions to TEP GP for it to maintain or attain up to a 2.0% general partner interest in TEP; or
otherwise provide for the proper conduct of our business.
Our available cash includes cash on hand resulting from borrowings made after the end of the quarter.
Our Sources of Available Cash. Our sole cash-generating asset is an approximate 31.43%55.79% membership interest in Tallgrass Equity. Tallgrass Equity's sole cash generating assets consist of its direct and indirect partnershipequity interests in its subsidiaries, including TEP and its 75% membership interest in Rockies Express. Therefore, our cash flow and resulting ability to make distributions will be completely dependent upon the ability of TEPTallgrass Equity's subsidiaries and Rockies Express to make distributions.
The actual amount of cash that TEPTallgrass Equity's subsidiaries and Rockies Express, and correspondingly Tallgrass Equity, will have available for distribution will primarily depend on the amount of cash TEPTallgrass Equity's subsidiaries and Rockies Express generates from their operations. For a description of factors that may impact our results, please read "Item 1A.—Risk Factors."
In addition, the actual amount of cash that TEP,Tallgrass Equity's subsidiaries, Rockies Express, and Tallgrass Equity will have available for distribution will depend on other factors, some of which are beyond our control, including:
the level of revenue TEPTallgrass Equity's subsidiaries and Rockies Express are able to generate from their respective businesses;
the level of capital expenditures TEP,Tallgrass Equity, Tallgrass Equity's subsidiaries, or Rockies Express or Tallgrass Equity makes;
the level of TEP's,Tallgrass Equity, Tallgrass Equity's subsidiaries, and Rockies Express' and Tallgrass Equity's operating, maintenance and general and administrative expenses or related obligations;
the cost of acquisitions, if any;
TEP's,Tallgrass Equity's, Tallgrass Equity's subsidiaries', and Rockies Express' and Tallgrass Equity's debt service requirements and other liabilities;
TEP's,Tallgrass Equity's, Tallgrass Equity's subsidiaries' and Rockies Express' and Tallgrass Equity's working capital needs;
restrictions on distributions contained in TEP's,Tallgrass Equity's, Tallgrass Equity's subsidiaries', or Rockies Express' or Tallgrass Equity's debt agreements and any future debt agreements;
TEP's,Tallgrass Equity's subsidiaries', and Rockies Express' and Tallgrass Equity's ability to borrow under their respective revolving credit agreements to make distributions; and
the amount, if any, of cash reserves established by each of TEP GP and our general partner, in theirits sole discretion, for the proper conduct of TEP's and our business.
Performance Graph
The following performance graph compares the performance of our Class A shares with the NYSE Composite Index Total Return and the Alerian MLP Infrastructure Index Total Return MLP Index during the period beginning on May 12, 2015, and ending on December 31, 2017.2018. The graph assumes a $100 investment in our Class A shares and in each of the indices at the beginning of the period and a reinvestment of distributions/dividends paid on such investments throughout the period.
Recent Sales of Unregistered Equity Securities
None.
Repurchase of Equity by Tallgrass Energy, GP, LP or Affiliated Purchasers
None.
Item 6. Selected Financial Data
The historical financial statements included in this Annual Report reflect the consolidated results of operations of TEGP'sTGE's membership interest in Tallgrass Equity and Tallgrass Equity's 100% membership interest in TEP GP, which owns all the IDRs, and all the outstanding general partner units in TEP, and Tallgrass Equity's 20 million TEP common units it acquired at the closing of the TEGP IPO.TEP. In connection with the closing of the TEGPTGE IPO on May 12, 2015, the following transactions (the "Reorganization Transactions") occurred (i) Tallgrass Equity distributed its interests in Tallgrass Energy Holdings and Tallgrass Energy Holdings distributed its existing limited partner interest in TEGP,TGE, respectively, to certain of the Exchange Right Holders, that also collectively own 100% of the voting power of Tallgrass Energy Holdings; (ii) TEGPTGE issued 47,725,000 Class A shares to the public (including 6,225,000 Class A shares issued in connection with the underwriters' exercise of the overallotment option) for net proceeds of approximately $1.3 billion; (iii) the existing limited partner interests in TEGPTGE held by certain of the Exchange Right Holders were converted into 115,729,440 Class B shares, 6,225,000 of which were automatically cancelled in connection with the underwriters' exercise of its overallotment option; (iv) Tallgrass Equity issued 41,500,000 Tallgrass Equity units to TEGPTGE in exchange for approximately $1.1 billion in net proceeds from the issuance of TEGP'sTGE's Class A shares to the public and amended the limited liability company agreement of Tallgrass Equity to, among other things, provide that TEGPTGE is the managing member of Tallgrass Equity; (v) TEGPTGE used the net proceeds from the purchase of the 6,225,000 overallotment option shares to purchase a like amount of Tallgrass Equity units from certain of the Exchange Right Holders; and (vi) Tallgrass Equity entered into a $150 million revolving credit facility and borrowed $150 million thereunder, using the aggregate proceeds from such borrowings, together with the net proceeds from the TEGPTGE IPO that Tallgrass Equity received from TEGP,TGE, to purchase 20 million TEP common units from Tallgrass Development, LP at $47.68 per TEP common unit (the "Acquired TEP Units") and pay offering expenses and other transaction costs. Tallgrass Equity distributed the remaining proceeds (the "Excess Proceeds") to certain of the Exchange Right Holders. The following discussion analyzes the financial condition and results of operations of TEGP,TGE, which for periods prior to the completion of the TEGPTGE IPO on May 12, 2015 includes the financial condition and results of operations of TEGPTGE Predecessor, which refers to TEGPTGE as recast to show the effects of the Reorganization Transactions.
In certain circumstances and for ease of reading we discuss the financial results of these entities prior to their respective acquisitions as being "our" financial results during historic periods, although Trailblazer was owned by TD from November 13, 2012 to March 31, 2014, Pony Express was wholly-owned by TD from November 13, 2012 to August 31, 2014, and Terminals and NatGas were owned by TD from November 13, 2012 to December 31, 2016. As used in this Annual Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TEGP""TGE" and similar terms refer to Tallgrass Energy, GP, LP, together with its consolidated subsidiaries (including Tallgrass Equity, TEP and their respective subsidiaries). The term our "general partner" refers to TEGP Management,Tallgrass Energy GP, LLC. References to "Tallgrass Development" or "TD" refer to Tallgrass Development, LP.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes thereto included elsewhere in this Annual Report. A reference to a "Note" herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8.—Financial Statements. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding certain risks inherent in our business.
The following table shows selected historical financial and operating data of TEGPTGE for the periods and as of the dates indicated. The selected historical financial data for periods prior to the completion of the TEGPTGE IPO on May 12, 2015 includes the financial condition and results of operations of TEGPTGE Predecessor, which refers to TEGPTGE as recast to show the effects of the Reorganization Transactions.
We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the consolidated financial statements and the accompanying notes included elsewhere in this Annual Report.
Our operating results incorporate a number of significant estimates and uncertainties. Such matters could cause the data included herein to not be indicative of our future financial condition or results of operations. A discussion of our critical accounting estimates is included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7.
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Statement of operations data: | (in thousands, except per unit amounts) | (in thousands, except per share amounts) |
| Revenue | $ | 655,898 |
| | $ | 611,662 |
| | $ | 542,661 |
| | $ | 377,313 |
| | $ | 295,873 |
| $ | 793,259 |
| | $ | 655,898 |
| | $ | 611,662 |
| | $ | 542,661 |
| | $ | 377,313 |
|
| Operating income | $ | 271,847 |
| | $ | 258,418 |
| | $ | 206,229 |
| | $ | 58,970 |
| | $ | 39,346 |
| $ | 350,631 |
| | $ | 271,847 |
| | $ | 258,418 |
| | $ | 206,229 |
| | $ | 58,970 |
|
Equity in earnings of unconsolidated investments (1) | $ | 237,110 |
| | $ | 54,531 |
| | $ | 2,759 |
| | $ | 1,617 |
| | $ | — |
| $ | 306,819 |
| | $ | 237,110 |
| | $ | 54,531 |
| | $ | 2,759 |
| | $ | 1,617 |
|
| Net income before tax | $ | 432,443 |
| | $ | 267,780 |
| | $ | 193,071 |
| | $ | 65,786 |
| | $ | 12,971 |
| $ | 523,380 |
| | $ | 432,443 |
| | $ | 267,780 |
| | $ | 193,071 |
| | $ | 65,786 |
|
| Net income | $ | 223,985 |
| | $ | 250,039 |
| | $ | 200,348 |
| | $ | 65,786 |
| | $ | 12,971 |
| $ | 467,671 |
| | $ | 223,985 |
| | $ | 250,039 |
| | $ | 200,348 |
| | $ | 65,786 |
|
| Net (loss) income attributable to TEGP subsequent to May 12, 2015 | $ | (128,729 | ) | | $ | 26,794 |
| | $ | 24,563 |
| (2) | N/A |
| | N/A |
| |
| Basic net (loss) income per Class A share | $ | (2.22 | ) | | $ | 0.55 |
| | $ | 0.51 |
| (2) | N/A |
| | N/A |
| |
| Diluted net (loss) income per Class A share | $ | (2.22 | ) | | $ | 0.55 |
| | $ | 0.51 |
| (2) | N/A |
| | N/A |
| |
| Net income (loss) attributable to TGE, excluding predecessor operations interest | | $ | 137,127 |
| | $ | (128,729 | ) | | $ | 26,794 |
| | $ | 24,563 |
| (2) | N/A |
|
| Basic net income (loss) per Class A share | | $ | 1.27 |
| | $ | (2.22 | ) | | $ | 0.55 |
| | $ | 0.51 |
| (2) | N/A |
|
| Diluted net income (loss) per Class A share | | $ | 1.27 |
| | $ | (2.22 | ) | | $ | 0.55 |
| | $ | 0.51 |
| (2) | N/A |
|
| Balance sheet data (at end of period): | | | | | | | | | | | | | | | | | | |
| Property, plant and equipment, net | $ | 2,394,337 |
| | $ | 2,079,232 |
| | $ | 2,079,567 |
| | $ | 1,853,081 |
| | $ | 1,116,806 |
| $ | 2,802,429 |
| | $ | 2,394,337 |
| | $ | 2,079,232 |
| | $ | 2,079,567 |
| | $ | 1,853,081 |
|
Unconsolidated investments (1) | $ | 909,531 |
| | $ | 475,625 |
| | $ | 13,565 |
| | $ | 15,071 |
| | $ | 1,255 |
| $ | 1,861,686 |
| | $ | 909,531 |
| | $ | 475,625 |
| | $ | 13,565 |
| | $ | 15,071 |
|
| Total assets | $ | 4,292,013 |
| | $ | 3,625,480 |
| | $ | 3,088,635 |
| | $ | 2,476,599 |
| | $ | 1,631,879 |
| $ | 5,893,509 |
| | $ | 4,292,013 |
| | $ | 3,625,480 |
| | $ | 3,088,635 |
| | $ | 2,476,599 |
|
| Long-term debt, net | $ | 2,292,993 |
| | $ | 1,555,981 |
| | $ | 901,000 |
| | $ | 559,000 |
| | $ | 135,000 |
| $ | 3,205,958 |
| | $ | 2,292,993 |
| | $ | 1,555,981 |
| | $ | 901,000 |
| | $ | 559,000 |
|
| Other: |
| | | | | | | | |
| | | | | | | | |
| Distributions declared per Class A share | $ | 1.35 |
| | $ | 1.00 |
| | $ | 0.39 |
| | N/A |
| | N/A |
| |
| Dividends declared per Class A share | | $ | 2.02 |
| | $ | 1.35 |
| | $ | 1.00 |
| | $ | 0.39 |
| | N/A |
|
| |
(1) | For more information see Note 97 – Investments in Unconsolidated Affiliates. |
| |
(2) | The netNet income attributed to TEGPTGE was based upon the number of days between the closing of the IPO on May 12, 2015 to December 31, 2015. |
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
As discussed further in Note 2 – Summary of Significant Accounting Policies, our financial statements for historical periods prior to January 1, 2017 have been recast to reflect the operations of Terminals and NatGas, which were acquired effective January 1, 2017.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes thereto included elsewhere in this Annual Report.
Overview
TEGPTGE is a limited partnership that owns, operates, acquires and develops midstream energy assets in North America and has elected to be treated as a corporation for U.S. federal income tax purposes. We were formed as part of a reorganization involving entities that were previously controlled by Tallgrass Equity to effect the TEGP IPO, which was completed on May 12, 2015.
Our sole cash-generating asset is an approximate 31.43% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generatingoperations are conducted through, and our operating assets consist of theare owned by, our direct and indirect partnership interestssubsidiaries, including Tallgrass Equity, in TEP and itswhich we directly own an approximate 55.79% membership interest in Rockies Express as described below:
100% of the outstanding membership interests in TEP GP, which owns all the general partner interest in TEP as well as all the TEP IDRs. The general partner interest in TEP is represented by 834,391 general partner units, representing an approximate 1.13% general partner interest in TEP at February 13, 2018.
25,619,218 TEP common units, representing an approximate 34.60% limited partner interest in TEP at February 13, 2018, inclusive of the additional 5,619,218 TEP common units acquired from Tallgrass Development on February 7, 2018 as described below.
On February 7, 2018, Tallgrass Development merged into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity ("Tallgrass Development Holdings"), and as a result of the merger, Tallgrass Equity acquired a 25.01% membership in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TEGP and Tallgrass Equity issued 27,554,785 unregistered TEGP Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of Tallgrass Development.
TEP is a publicly traded, growth-oriented limited partnership formed in 2013 to own, operate, acquire and develop midstream energy assets in North America. TEP's operations8, 2019. We are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations.
TEP intends to continue to utilize the significant experience of its management team to execute its growth strategy of acquiring midstream assets, increasing utilization of its existing assets and expanding its systems through construction of additional assets.
Our reportable business segments are:
Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and an integrated natural gas storage facilities;facility;
Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system;systems; and
Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering and processing facilities; crude oil gathering, storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs.
Additional information about TEP'sour operations and assets is contained in the business overview included in Item 1.—Business under "Overview" and "TEP'sOur Assets."
Financial Presentation
TEGP has noTGE's operations outside of itsare conducted through our direct and indirect ownership interestssubsidiaries in Rockies ExpressTallgrass Equity and TEP. TEGPTGE is the managing member of and therefore controls Tallgrass Equity. Tallgrass Equity, in turn, controls TEP through the direct ownership of 100% of Tallgrass MLP GP, LLC ("TEP GP,GP"), TEP's general partner. As a result, under GAAP, TEGPTGE consolidates Tallgrass Equity, TEP GP, TEP, and TEP's subsidiaries. As such, TEGP'sTGE's results of operations will not differ materially from the results of operations of TEP. The most noteworthy reconciling items between TEGP'sTGE's consolidated financial statements and TEP's consolidated financial statements primarily relate to (i) the inclusion of the Tallgrass Equity revolving credit facility prior to repayment and termination on July 26, 2018, (ii) the impact of TEGP'sTGE's election to be treated as a corporation for U.S. federal income tax purposes, and (iii) the presentation of noncontrolling interests in Tallgrass Equity and, prior to the TEP Merger, TEP. The interests in Tallgrass Equity and TEP that are not directly or indirectly owned by TEGPTGE will be reflected as being attributable to noncontrolling interests in TEGP'sTGE's consolidated financial statements.
In addition, historical results of operations for periods prior to May 12, 2015 do not reflect TEGP's incremental general and administrative costs associated with becoming a separate publicly traded entity, including expenses associated with (i) compensation for new directors, (ii) incremental director and officer liability insurance, (iii) listing on the NYSE, (iv) investor relations, (v) legal, (vi) tax and (vii) accounting.
Summary of Results for the Year Ended December 31, 20172018
During 2017, TEP2018, we completed the TEP Merger as discussed in Note 1 – Description of Business, as well as acquisitions of a 100% membership interest in each of Terminals and NatGas,BNN North Dakota, an additional 24.99%2% membership interest in Pony Express, an additional 25.01% membership interest in Rockies Express, a 100%51% membership interest in DCP Douglas, an aggregate additional 49% membership interest in Deeprock Development,Pawnee Terminal and a 100% membership interest in Outrigger Powder River Operating.NGL Water Solutions Bakken, LLC. In addition, TEPwe issued $350$500 million in aggregate principal amount of 5.50%4.75% senior notes due 20242023 (the "2024 Notes") and $750 million in aggregate principal amount of 5.50% senior notes due 2028 (the "2028"2023 Notes"), the proceeds of which were used to repay borrowings under TEP's revolving credit facility.
OperatingNet income for the year ended December 31, 2018 was $467.7 million, with Adjusted EBITDA and Cash Available for Dividends (each as defined below under "Non-GAAP Financial Measures") of $654.4 million and $548.7 million, respectively, compared to net income for the year ended December 31, 2017 was $271.8of $224.0 million, compared to $258.4with Adjusted EBITDA and Cash Available for Dividends of $300.3 million for the year ended December 31, 2016.and $268.4 million, respectively. The increase in operatingnet income, was primarily driven by increased fresh water supplyAdjusted EBITDA, and produced water disposal volumes and TEP's acquisitions in 2017, as discussed further under "Results of Operations" below. Net incomeCash Available for the year ended December 31, 2017 was $224.0 million compared to $250.0 million for the year ended December 31, 2016. The decrease in net incomeDividends was largely driven by a significant increaseour increased ownership in deferred tax expenseTEP due to the remeasurement of the deferred tax assetTEP Merger, as a result of the federal rate change, partially offset bywell as our acquisition of an additional 24.99%25.01% membership interest in Rockies Express, as discussed further under "Results of Operations" below, and the increase in operating income.below.
Recent Developments
TEGP Distribution DeclaredTGE Dividend Announced
On January 8, 2018,15, 2019, the Board of Directors of our general partner declared a cash distributiondividend for the quarter ended December 31, 20172018 of $0.3675$0.5200 per Class A share. The distribution will be paid on February 14, 2018,2019, to Class A shareholders of record on January 31, 2018.2019.
TEP Distribution DeclaredPowder River Gateway
On January 8, 2018, the Board of Directors of TEP's general partner declared a cash distribution for the quarter ended December 31, 2017 of $0.9650 per common unit. The distribution was paid on February 14, 2018, to TEP unitholders of record on January 31, 2018.
Deeprock North Acquisition and Merger with Deeprock Development
On January 2, 2018, Terminals acquired an approximate 38% membership interest in Deeprock North, LLC ("Deeprock North") from Kinder Morgan Deeprock North Holdco LLC for cash consideration of $19.5 million. Immediately following the acquisition, Deeprock North was merged into Deeprock Development. After the acquisition and merger, Terminals owns an approximately 60% membership interest in the combined entity.
BNN North Dakota Acquisition
In January 2018, Water Solutions acquired a 100% membership interest in Buckhorn Energy Services, LLC and Buckhorn SWD Solutions, LLC (collectively, "BNN North Dakota") for cash consideration2019, we closed on an expansion of approximately $95.0 million, subject to working capital adjustments. BNN North Dakota owns a produced water gathering and disposal system in the Bakken basinour joint venture with approximately 133,000 acres under dedication.
Potential Acquisition of Pawnee Terminal
OnSilver Creek. Effective January 2, 2018, Terminals entered into an agreement to acquire1, 2019, we own a 51% membership interest in Powder River Gateway, which holds the Pawnee, ColoradoIron Horse Pipeline, the PRE Pipeline, and crude oil terminal (“Pawnee Terminal”) from Zenith Energy Terminals Holdings, LLC for cash considerationfacilities in Guernsey, Wyoming. For additional information, see Note 3 – Acquisitions and Dispositions.
Blackstone Acquisition
On January 31, 2019, we announced that BIP had entered into a definitive purchase agreement with Kelso, EMG, and Tallgrass KC pursuant to which BIP will acquire 100% of approximately $31 million, subjectthe membership interests in our general partner and an approximate 44% economic interest in us. Subject to working capital adjustments. Terminals expectscustomary closing conditions, the transactionBlackstone Acquisition is expected to close inwithin the first quarter of 2018, subject to certain closing conditions.2019.
Acquisition of Additional Interest in Pony Express
Effective February 1, 2018, TEP acquired the remaining 2% membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from Tallgrass Development for cash consideration of approximately $60 million, bringing its aggregate membership interest in Pony Express to 100%.
Potential Joint Venture and Sale of TCG
On February 6, 2018, TEP entered into an agreement with an affiliate of Silver Creek to form Iron Horse Pipeline, a new joint venture pipeline to transport crude oil from the Powder River Basin. In addition to forming the joint venture, TEP has also agreed to sell to Silver Creek its 100% membership interest in TCG, which owns a 50-mile crude oil gathering system in the Powder River Basin. TEP expects to close the sale of TCG and the formation of the joint venture in February 2018.
Tallgrass Equity Acquisitions
On February 7, 2018, Tallgrass Development merged into Tallgrass Development Holdings, a wholly-owned subsidiary of Tallgrass Equity, and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TEGP and Tallgrass Equity issued 27,554,785 unregistered TEGP Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of Tallgrass Development. The equity issued by TEGP and Tallgrass Equity was based on a discounted 30-day volume weighted average price of TEGP Class A shares. The 25.01% membership interest was valued at approximately $400 million and the 5,619,218 TEP common units were valued at approximately $256.2 million based on a 30-day volume weighted average price.
Seneca Lateral
On January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations, however, the release required Rockies Express to shut off the flow through the segment. Repairs are underway to return the segment to service as soon as possible and a root cause investigation is ongoing.
Factors and Trends Impacting Our Business
Our sole cash-generating asset is an approximate 31.43% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of direct and indirect partnership interests in TEP and Rockies Express, as detailed above in "—Overview". As a result, weWe expect to continue to be affected by certain key factors and trends impacting TEP's business as described below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. See also Item 1A.—Risk Factors.
Long-Term U.S. Crude Oil and Natural Gas Prospects
Crude oil, natural gas, and products derived from both continue to be critical components of energy supply and demand in the United States. Crude oil and natural gas prices declined significantly from the second half of 2014 through the first half of 2016 and crude oil experienced significant volatility during that time. However, prices generally stabilized during 2017.2017 and early 2018, experiencing some volatility in the second half of 2018. Although price declines and volatility could occasionally return tomay occur in commodity markets at points in the future, we believe long-term prospects for continued domestic crude oil and natural gas production increases are favorable.
We believe long-term growth will be driven, in part, by a combination of increased domestic demand resulting from population and economic growth, higher industrial consumption in the U.S. spurred by the lower commodity price of feedstock and fuel, and a desire to reduce domestic reliance on imports. One example is that we expect natural gas to gradually displace coal-fired electricity generation due to the low prices of natural gas and stricter environmental regulations on the mining and burning of coal. Additionally, we believe that the U.S. will continue to increase its total volume exported of both natural gas and crude oil as new and additional infrastructure is developed to export these commodities. We expect productivity of oil and natural gas wells to continue increasing over the long-term in some basins across the United States because of the increasing precision and efficiency of horizontal drilling and hydraulic fracturing in oil and natural gas extraction. We also believe there is a substantial inventory of drilled but uncompleted wells in the basins we serve, including the Bakken shale and Denver-Julesburg basin, that are likely to be completed and turned into production as commodity prices stabilize and continue to recover and stabilize.recover.
Current Commodity Environment
Starting in the second half of 2014 and through the first half of 2016, the prices of crude oil, natural gas, and NGLs were extremely volatile and declined significantly. During 2017 and early 2018, price stability appearsappeared to have generally been restored to the market, andbut in the second half of 2018 some of our customers are showing a renewed interest in entering into long-term, fixed obligation contracts.volatility returned. To the extent some of our customers remain concerned about extended unfavorably low prices, it may be due to concerns over excess supply, truncation of current OPEC production cuts and increased mainstream use of alternative sources of energy.
Demand for our services depends, in part, on the development of additional natural gas and crude oil reserves by third parties. This requires significant capital expenditures by others to install facilities that extract natural gas and crude oil. However, the possibility for low commodity prices may result in a lack of available capital for these types of expenditures. To the extent our customers cannot finance these activities, we expect they may be less likely to enter into demand based, long-term firm fee contracts. Low commodity prices may also negatively impact the financial condition of our customers and could impact their ability to meet their financial obligations to us.
Additionally, lower commodity prices may lead to reduced utilization of our assets. For example, reduced utilization could result in increased deficiency balances held by customers of our Pony Express System. For additional information, see Item 1A.—Risk Factors, "The Throughput and Deficiency Agreements for the Pony Express System and some of TEP'sour service agreements with respect to itsour water business services contain provisions that can reduce the cash flow stability that the agreements were designed to achieve."
Growth Associated with Acquisitions and Expansion Projects
Growth associated with acquisitions
We believe that we are well-positioned to grow through accretive acquisitions due to our stable financial profile and diverse asset base that presents many logical strategic opportunities. In the past, we heavily relied on acquiring assets from TD's portfolio of midstream assets. Now that TD has divested its entire asset portfolio, our growth through acquisitions will rely almost exclusively on buying assets or businesses from third parties. Third party acquisitions present different risks than those associated with acquiring assets from TD. Sourcing attractive, accretive opportunities and performing diligence on those opportunities requires significantly more time from our employees. Most third-partythird party acquisitions involve competition from other buyers, which generally increases the purchase price. If we are able to execute a third-party transaction, we may encounter challenges when integrating different work cultures and operational systems. During 2018, we executed several third party acquisitions, including BNN North Dakota, Deeprock North, an interest in Pawnee Terminal, and NGL Water Solutions Bakken. For additional information, see Note 3 – Acquisitions and Dispositions.
Growth associated with expansion projects
We also believe that we are well positioned to increase volumes to our systems through cost-effective capacity expansions and other methods for improving efficiency. For example, in January 2017, Rockies Express placed in servicein-service the Rockies Express Zone 3 Capacity Enhancement Project that added an incremental 0.8 Bcf/d of east-to-west capacity within Zone 3 of the Rockies Express Pipeline. In the second quarter of 2018, Pony Express Pipeline placed in-service the Platteville Extension Project. During 2017 and 2018, we also announced and are currently executing on the Platteville Extension Project on the Pony Express SystemCheyenne Connector Pipeline and the Cheyenne ConnectorIron Horse Pipeline.
Energy Capital Markets and Interest Rates
During the second half of 2015 and into mid-2016, the energy credit markets experienced a material increase in the yields for long-term debt, which caused an issuance of senior unsecured notes to be a less attractive financing option until the third quarter of 2016, when we were able to issue the 2024 Notes. At the same time, the downturn in commodity prices generally limited the availability of capital through traditional public issuances of common units for much of 2016. While the downturn did not change our business plans, including our growth through acquisitions and expansion projects, it did temporarily alter some of our financing strategies. In 2017 and 2018, TEP was able to issue an additional $350 million$1.6 billion in aggregate principal amount of 2024 Notes and $750 million in aggregate principal amount of 2028 Notes, both at a rate ofsenior notes with rates from 4.75% to 5.5%.
In addition, the Federal Reserve increasedhas continued to incrementally increase short-term interest rates, which marginally impactedimpacts the rates on our floating rate revolving credit facility. Changes in the short-term interest rates also affect how our Class A shares are compared and ranked with other yield-oriented securities for investment decision-making purposes. If the economy continues to strengthen, it is likely that monetary policy will continue to tighten, resulting in higher interest rates to counter possible inflation. If this occurs, interest rates on our floating rate credit facilities and future offerings in the debt capital markets could be at higher rates, causing our financing costs to increase accordingly. Further, investors could require a higher yield on our Class A shares, potentially decreasing their price, which in turn could limit our ability to complete future equity offerings at favorable pricing. For additional information, please read Item 7A.—Quantitative and Qualitative Disclosures About Market Risk.
How We Evaluate Our Operations
We evaluate our results using, among other measures, cash distributions received from Tallgrass Equity, contract profile and volumes, at TEP and Rockies Express, and operating costs and expenses, of TEGPAdjusted EBITDA and its consolidated subsidiaries.
Cash Distributions Received from Tallgrass Equity
Our cash flow is currently generated solely by distributions received from Tallgrass Equity. Tallgrass Equity currently receives all its cash flows from distributions on its directAvailable for Dividends. Adjusted EBITDA and indirect partnership interests in TEPCash Available for Dividends are non-GAAP measures and Rockies Express. Tallgrass Equity is therefore entirely dependent upon the ability of TEP and Rockies Express to make cash distributions to its partners.are defined below.
Contract Profile and Volumes
Our results are driven primarily by the volume of natural gas transportation and storage capacity, crude oil transportation, storage, gathering and terminalling capacity, NGL transportation capacity, and water transportation, gathering, recycling and disposal capacity under firm fee contracts, as well as the volume of natural gas that it gatherswe gather and processesprocess and the fees assessed for such services.
Operating Costs and Expenses
The primary components of operating costs and expenses that we evaluate include cost of sales, cost of transportation services, operations and maintenance and general and administrative costs. Operating expenses are driven primarily by expenses related to the operation, maintenance and growth of itsour asset base.
Adjusted EBITDA and Cash Available for Dividends
Adjusted EBITDA and Cash Available for Dividends are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
our operating performance as compared to other publicly traded midstream infrastructure companies, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;
the ability of our assets to generate sufficient cash flow to make dividends to our shareholders;
our ability to incur and service debt and fund capital expenditures; and
the viability of acquisitions and other capital expenditure projects and the returns on investment of various expansion and growth opportunities.
We believe that the presentation of Adjusted EBITDA and Cash Available for Dividends provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and Cash Available for Dividends should not be considered alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, nor should Adjusted EBITDA and Cash Available for Dividends be considered alternatives to available cash or other definitions in our partnership agreement. Adjusted EBITDA and Cash Available for Dividends have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and Cash Available for Dividends may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and Cash Available for Dividends may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
Non-GAAP Financial Measures
We generally define Adjusted EBITDA as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments and deficiency payments received from or utilized by our customers. We also use Cash Available for Dividends, which we generally define as Adjusted EBITDA, less cash interest costs, maintenance capital expenditures, and certain cash reserves permitted by our governing documents. Adjusted EBITDA and Cash Available for Dividends are both calculated and presented at the Tallgrass Equity level, before consideration of noncontrolling interest associated with the Exchange Right Holders or calculating distributions from Tallgrass Equity to us, on one hand, and to the Exchange Right Holders, on the other. We believe calculating these measures at Tallgrass Equity provides investors the most complete picture of our overall financial and operational results and provides a consistent metric for period over period comparisons that is not impacted by any future exercises by the Exchange Right Holders of the Exchange Right, which does not have a dilutive effect on TGE's net income per share.
Maintenance capital expenditures are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements, and are presented net of noncontrolling interest and reimbursements. We collect deficiency payments for volumes committed by our customers to be transported in a month but not physically received for transport or delivered to the customers' agreed upon destination point. These deficiency payments are recorded as a deferred liability until the barrels are physically transported and delivered, or when the likelihood that the customer will utilize the deficiency balance becomes remote.
Adjusted EBITDA and Cash Available for Dividends are not presentations made in accordance with GAAP. The following table presents a reconciliation of Adjusted EBITDA to Net income attributable to TGE and net cash provided by operating activities and a reconciliation of Cash Available for Dividends to net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in thousands) |
| Reconciliation of Tallgrass Equity Adjusted EBITDA to Net income (loss) attributable to TGE | | | | | |
| Net income (loss) attributable to TGE | $ | 137,127 |
| | $ | (128,729 | ) | | $ | 33,789 |
|
| Add: | | | | | |
Interest expense, net (1) | 95,465 |
| | 29,403 |
| | 16,632 |
|
Depreciation and amortization expense (1) | 74,998 |
| | 26,131 |
| | 25,567 |
|
Distributions from unconsolidated investments (1) | 302,364 |
| | 86,551 |
| | 22,085 |
|
Deficiency payments, net (1) | 14,443 |
| | 7,701 |
| | 9,672 |
|
Non-cash compensation expense (1)(2) | 8,634 |
| | 2,682 |
| | 1,862 |
|
| Loss on debt retirement | 2,245 |
| | — |
| | — |
|
| Deferred income tax expense | 55,709 |
| | 208,458 |
| | 17,741 |
|
| Net income attributable to Exchange Right Holders | 208,618 |
| | 137,849 |
| | 95,882 |
|
| Less: | | | | | |
Equity in earnings of unconsolidated investments (1) | (237,197 | ) | | (66,922 | ) | | (15,287 | ) |
(Gain) loss on disposal of assets (1) | (4,630 | ) | | (189 | ) | | 526 |
|
| Non-cash (gain) loss related to derivative instruments | (3,340 | ) | | 64 |
| | 650 |
|
Gain on remeasurement of unconsolidated investment (1) | — |
| | (2,744 | ) | | — |
|
| Tallgrass Equity Adjusted EBITDA | $ | 654,436 |
| | $ | 300,255 |
| | $ | 209,119 |
|
| Reconciliation of Tallgrass Equity Adjusted EBITDA and Cash Available for Dividends to Net Cash Provided by Operating Activities | | | | | |
| Net cash provided by operating activities | $ | 672,525 |
| | $ | 571,396 |
| | $ | 413,298 |
|
| Add: | | | | | |
Interest expense, net (1) | 95,465 |
| | 29,403 |
| | 16,632 |
|
Other, including changes in operating working capital (1) | (113,554 | ) | | (300,544 | ) | | (220,811 | ) |
| Tallgrass Equity Adjusted EBITDA | $ | 654,436 |
| | $ | 300,255 |
| | $ | 209,119 |
|
| Less: | | | | | |
Cash interest cost (1) | (91,590 | ) | | (27,669 | ) | | (15,168 | ) |
Maintenance capital expenditures, net (1) | (14,176 | ) | | (4,179 | ) | | (3,270 | ) |
| Cash flow attributable to predecessor operations | — |
| | — |
| | (2,743 | ) |
| Tallgrass Equity Cash Available for Dividends | $ | 548,670 |
| | $ | 268,407 |
| | $ | 187,938 |
|
| |
(1) | Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity. |
| |
(2) | Represents TGE's portion of non-cash compensation expense related to Equity Participation Shares and TEP's Equity Participation Units, excluding amounts allocated to TD prior to the merger of TD into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity, on February 7, 2018. |
The following table presents a reconciliation of Adjusted EBITDA by segment to segment operating income, the most directly comparable GAAP financial measure, for each of the periods indicated: |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in thousands) |
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Natural Gas Transportation Segment (1) | | | | | |
| Operating income | $ | 69,586 |
| | $ | 67,434 |
| | $ | 56,135 |
|
| Add: | | | | | |
Depreciation and amortization expense (2) | 13,102 |
| | 5,421 |
| | 6,099 |
|
Distributions from unconsolidated investment (2) | 297,496 |
| | 85,994 |
| | 21,245 |
|
Other, net (2) | 2,359 |
| | 1,424 |
| | 1,722 |
|
| Less: | | | | | |
| Adjusted EBITDA attributable to noncontrolling interests | (5,319 | ) | | 20,738 |
| | (10,205 | ) |
Non-cash (gain) loss related to derivative instruments (2) | — |
| | (33 | ) | | 33 |
|
| Tallgrass Equity Segment Adjusted EBITDA | $ | 377,224 |
| | $ | 180,978 |
| | $ | 75,029 |
|
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Crude Oil Transportation Segment (1) | | | | | |
| Operating income | $ | 258,308 |
| | $ | 190,170 |
| | $ | 215,784 |
|
| Add: | | | | | |
Depreciation and amortization expense (2) | 36,578 |
| | 16,156 |
| | 15,211 |
|
Deficiency payments, net (2) | 4,858 |
| | 7,967 |
| | 9,123 |
|
| Less: | | | | | |
| Adjusted EBITDA attributable to noncontrolling interests | (60,414 | ) | | (73,385 | ) | | (108,093 | ) |
Non-cash (gain) loss related to derivative instruments (2) | — |
| | (123 | ) | | 129 |
|
| Tallgrass Equity Segment Adjusted EBITDA | $ | 239,330 |
| | $ | 140,785 |
| | $ | 132,154 |
|
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Gathering, Processing & Terminalling Segment (1) | | | | | |
| Operating income (loss) | $ | 51,565 |
| | $ | 33,453 |
| | $ | (903 | ) |
| Add: | | | | | |
Depreciation and amortization expense (2) | 21,665 |
| | 4,554 |
| | 4,257 |
|
Non-cash (gain) loss related to derivative instruments (2) | (3,340 | ) | | 750 |
| | (84 | ) |
Distributions from unconsolidated investments (2) | 4,868 |
| | 557 |
| | 773 |
|
Deficiency payments, net (2) | 8,540 |
| | (458 | ) | | 550 |
|
Other, net (2) | 182 |
| | 142 |
| | — |
|
| Less: | | | | | |
(Gain) loss on disposal of assets (2) | (4,630 | ) | | (189 | ) | | 526 |
|
| Adjusted EBITDA attributable to noncontrolling interests | (19,647 | ) | | (22,726 | ) | | (1,041 | ) |
| Tallgrass Equity Segment Adjusted EBITDA | $ | 59,203 |
| | $ | 16,083 |
| | $ | 4,078 |
|
| Total Tallgrass Equity Segment Adjusted EBITDA | $ | 675,757 |
| | $ | 337,846 |
| | $ | 211,261 |
|
| Corporate general and administrative costs | (21,321 | ) | | (37,591 | ) | | (2,142 | ) |
| Total Tallgrass Equity Adjusted EBITDA | $ | 654,436 |
| | $ | 300,255 |
| | $ | 209,119 |
|
| |
(1) | Segment results as presented represent total operating income and Adjusted EBITDA, including intersegment activity, for the Natural Gas Transportation, Crude Oil Transportation, and Gathering, Processing & Terminalling segments. For reconciliations to the consolidated financial data, see Note 20 – Reportable Segments to the accompanying consolidated financial statements. |
| |
(2) | Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity. |
Results of Operations
The following provides a summary of our operating metrics for the periods indicated: | | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands, except operating data) | (in thousands, except operating data) |
| Natural Gas Transportation Segment: | | | | | | | | | | |
Gas transportation average firm contracted volumes (MMcf/d) (1) | 1,711 |
| | 1,627 |
| | 1,679 |
| |
TIGT and Trailblazer average firm contracted volumes (MMcf/d) (1) | | 1,636 |
| | 1,711 |
| | 1,627 |
|
Rockies Express average firm contracted volumes (MMcf/d) (2) | | 4,101 |
| | 4,101 |
| | 3,384 |
|
| Crude Oil Transportation Segment: | | | | | | | | | | |
| Crude oil transportation average contracted capacity (Bbls/d) | 301,936 |
| | 295,435 |
| | 252,374 |
| 306,936 |
| | 301,936 |
| | 295,435 |
|
Crude oil transportation average throughput (Bbls/d)(2) | 267,734 |
| | 285,507 |
| | 236,256 |
| |
| Crude oil transportation average throughput (Bbls/d) | | 336,314 |
| | 267,734 |
| | 285,507 |
|
| Gathering, Processing & Terminalling Segment: | | | | | | | | | | |
| Natural gas processing inlet volumes (MMcf/d) | 109 |
| | 103 |
| | 122 |
| 122 |
| | 109 |
| | 103 |
|
| Freshwater average volumes (Bbls/d) | 69,139 |
| | 13,201 |
| | 14,579 |
| 17,849 |
| | 69,139 |
| | 13,201 |
|
| Produced water gathering and disposal average volumes (Bbls/d) | 31,511 |
| | 11,307 |
| | 7,951 |
| 98,489 |
| | 31,511 |
| | 11,307 |
|
| |
(1) | Volumes transported under firm fee contracts, excluding Rockies Express. |
| |
(2) | Approximate average daily throughput for the year ended December 31, 2015 is reflective of the volumetric ramp up due to commercial in-service of the Pony Express System beginning in October 2014, including the lateral in Northeast Colorado in the second quarter of 2015, and delays in the construction and expansion efforts of third-party pipelines with which Pony Express shares joint tariffs.Volumes transported under long-term firm fee contracts. |
The following provides a summary of our consolidated results of operations for the periods indicated:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands, except operating data) | (in thousands) |
| Revenues: | | | | | | | | | | |
| Crude oil transportation services | $ | 345,733 |
| | $ | 374,949 |
| | $ | 300,436 |
| $ | 398,334 |
| | $ | 345,733 |
| | $ | 374,949 |
|
| Natural gas transportation services | 122,364 |
| | 119,962 |
| | 119,895 |
| 126,894 |
| | 122,364 |
| | 119,962 |
|
| Sales of natural gas, NGLs, and crude oil | 108,503 |
| | 77,123 |
| | 82,133 |
| 168,586 |
| | 108,503 |
| | 77,123 |
|
| Processing and other revenues | 79,298 |
| | 39,628 |
| | 40,197 |
| 99,445 |
| | 79,298 |
| | 39,628 |
|
| Total Revenues | 655,898 |
| | 611,662 |
| | 542,661 |
| 793,259 |
| | 655,898 |
| | 611,662 |
|
| Operating Costs and Expenses: | | | | | | | | | | |
| Cost of sales | 91,213 |
| | 71,650 |
| | 75,285 |
| 114,815 |
| | 91,213 |
| | 71,650 |
|
| Cost of transportation services | 46,200 |
| | 47,669 |
| | 46,840 |
| 53,068 |
| | 46,200 |
| | 47,669 |
|
| Operations and maintenance | 62,069 |
| | 55,070 |
| | 50,823 |
| 72,460 |
| | 62,069 |
| | 55,070 |
|
| Depreciation and amortization | 90,800 |
| | 86,247 |
| | 84,258 |
| 110,862 |
| | 90,800 |
| | 86,247 |
|
| General and administrative | 65,536 |
| | 57,298 |
| | 52,635 |
| 70,656 |
| | 65,536 |
| | 57,298 |
|
| Taxes, other than income taxes | 28,832 |
| | 25,400 |
| | 21,796 |
| 31,810 |
| | 28,832 |
| | 25,400 |
|
| Contract termination | — |
| | 8,061 |
| | — |
| — |
| | — |
| | 8,061 |
|
| (Gain) loss on disposal of assets | (599 | ) | | 1,849 |
| | 4,795 |
| (11,043 | ) | | (599 | ) | | 1,849 |
|
| Total Operating Costs and Expenses | 384,051 |
| | 353,244 |
| | 336,432 |
| 442,628 |
| | 384,051 |
| | 353,244 |
|
| Operating Income | 271,847 |
| | 258,418 |
| | 206,229 |
| 350,631 |
| | 271,847 |
| | 258,418 |
|
| Other Income (Expense): | | | | | | | | | | |
| Equity in earnings of unconsolidated investments | | 306,819 |
| | 237,110 |
| | 54,531 |
|
| Interest expense, net | (89,348 | ) | | (45,601 | ) | | (18,330 | ) | (133,319 | ) | | (89,348 | ) | | (45,601 | ) |
| Unrealized gain (loss) on derivative instrument | 1,885 |
| | (1,291 | ) | | — |
| |
| Equity in earnings of unconsolidated investments | 237,110 |
| | 54,531 |
| | 2,759 |
| |
| Gain on remeasurement of unconsolidated investment | 9,728 |
| | — |
| | — |
| — |
| | 9,728 |
| | — |
|
| Other income, net | 1,221 |
| | 1,723 |
| | 2,413 |
| |
| Other (expense) income, net | | (751 | ) | | 3,106 |
| | 432 |
|
| Total Other Income (Expense) | 160,596 |
| | 9,362 |
| | (13,158 | ) | 172,749 |
| | 160,596 |
| | 9,362 |
|
| Net income before tax | 432,443 |
| | 267,780 |
| | 193,071 |
| 523,380 |
| | 432,443 |
| | 267,780 |
|
| Deferred income tax (expense) benefit | (208,458 | ) | | (17,741 | ) | | 7,277 |
| |
| Deferred income tax expense | | (55,709 | ) | | (208,458 | ) | | (17,741 | ) |
| Net income | 223,985 |
| | 250,039 |
| | 200,348 |
| 467,671 |
| | 223,985 |
| | 250,039 |
|
| Net income attributable to noncontrolling interests | (352,714 | ) | | (216,250 | ) | | (156,035 | ) | (330,544 | ) | | (352,714 | ) | | (216,250 | ) |
| Net (loss) income attributable to TEGP | $ | (128,729 | ) | | $ | 33,789 |
| | $ | 44,313 |
| |
| Net income (loss) attributable to TGE | | $ | 137,127 |
| | $ | (128,729 | ) | | $ | 33,789 |
|
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Revenues. Total revenues were $793.3 million for the year ended December 31, 2018 compared to $655.9 million for the year ended December 31, 2017, which represents an increase of $137.4 million, or 21%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $93.5 million and $79.9 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by a $35.4 million increase in eliminations of intersegment revenue and decreased revenues of $0.6 million in the Natural Gas Transportation segment, as discussed further below.
Operating costs and expenses. Operating costs and expenses were $442.6 million for the year ended December 31, 2018 compared to $384.1 million for the year ended December 31, 2017, which represents an increase of $58.6 million, or 15%. The overall increase in operating costs and expenses is driven by increased operating costs and expenses of $75.3 million and $11.7 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by decreased operating costs and expenses of $25.7 million and $2.7 million in the Corporate and Other and Natural Gas Transportation segments, as discussed further below. The decrease in Corporate and Other expenses was primarily driven by a $35.4 million increase in eliminations of intersegment operating costs and expenses, partially offset by a $4.9 million increase in corporate general and administrative costs and a $4.8 million increase in depreciation and amortization costs due to the administrative assets acquired from TD in February 2018. The increase in corporate general and administrative costs was
primarily due to expenses at TEP and Tallgrass Equity attributable to the Merger Agreement and the transactions contemplated by the Merger Agreement, as well as Tallgrass Equity's acquisition of an additional 25.01% membership interest in Rockies Express and additional TEP common units.
Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $306.8 million and $237.1 million for the years ended December 31, 2018 and 2017, respectively. Equity in earnings of unconsolidated investments of $306.8 million for the year ended December 31, 2018 primarily reflects our portion of earnings and the $35.9 million of amortization of a negative basis difference associated with our aggregate 75% membership interest in Rockies Express, inclusive of the additional 25.01% membership interest acquired in February 2018, as well as $4.2 million of equity in earnings related to our 51% membership interest in Pawnee Terminal. Equity in earnings of unconsolidated investments of $237.1 million for the year ended December 31, 2017 primarily reflects our portion of earnings and the $23.2 million of amortization of a negative basis difference associated with our 49.99% membership interest in Rockies Express as well as $1.5 million of equity in earnings related to our 20% membership interest in Deeprock Development prior to our acquisition of a controlling financial interest in Deeprock Development in July 2017. During the year ended December 31, 2017, Rockies Express recognized a $150 million gain on settlement of the Ultra litigation as discussed in Note 19 – Legal and Environmental Matters.
Interest expense, net. Interest expense of $133.3 million for the year ended December 31, 2018 was primarily composed of interest and fees associated with the Senior Notes, as defined in Note 10 – Long-term Debt, and the TEP and Tallgrass Equity revolving credit facilities. Interest expense of $89.3 million for the year ended December 31, 2017 was primarily composed of interest and fees associated with TEP and Tallgrass Equity revolving credit facilities and the 2024 Notes issued on September 1, 2016 and May 16, 2017, and the 2028 Notes issued on September 15, 2017 and December 11, 2017. The increase in interest and fees is primarily due to increased borrowings to fund a portion of our 2017 and 2018 acquisitions, as well as the higher borrowing rate on the Senior Notes, the proceeds of which were used to repay borrowings under TEP's revolving credit facility.
Gain on remeasurement of unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.7 million for the year ended December 31, 2017 was related to the remeasurement to fair value of our existing 20% membership interest in Deeprock Development in connection with our acquisition of a controlling financial interest in Deeprock Development in July 2017. For additional information, see Note 3 – Acquisitions and Dispositions.
Other (expense) income, net. Other (expense) income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other expense for the year ended December 31, 2018 was $0.8 million compared to other income of $3.1 million for the year ended December 31, 2017. Other expense of $0.8 million for the year ended December 31, 2018 included a $2.2 million loss on debt retirement associated with the write off of deferred financing costs associated with the Amendment to the TEP revolving credit facility and the termination of the Tallgrass Equity revolving credit facility. Other income of $3.1 million for the year ended December 31, 2017 included a $1.9 million unrealized gain on derivative instrument related to the change in fair value of the call option received from TD as part of the acquisition of an additional 31.3% membership interest in Pony Express as discussed further in Note 9 – Risk Management.
Deferred income tax expense. Deferred income tax expense for the year ended December 31, 2018 was $55.7 million compared to a deferred income tax expense of $208.5 million for the year ended December 31, 2017. The decrease in deferred income tax expense was primarily driven by the remeasurement of the deferred tax asset during the year ended December 31, 2017 as a result of the federal rate change under the tax legislation referred to as the Tax Cuts and Jobs Act that was signed into law on December 22, 2017, partially offset by our increased ownership in TEP due to the TEP Merger and the resulting increase in income allocated to TGE. For additional information, see Note 17 – Income Taxes.
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Revenues. Total revenues were $655.9 million for the year ended December 31, 2017 compared to $611.7 million for the year ended December 31, 2016, which represents an increase of $44.2 million, or 7%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $72.7 million and $5.9 million in the Gathering, Processing & Terminalling and Natural Gas Transportation segments, respectively, partially offset by decreased revenues of $15.9 million in the Crude Oil Transportation segment, as discussed further below.
Operating costs and expenses. Operating costs and expenses were $384.1 million for the year ended December 31, 2017 compared to $353.2 million for the year ended December 31, 2016, which represents an increase of $30.8 million, or 9%. The overall increase in operating costs and expenses iswas driven by increased operating costs and expenses of $38.3 million and $9.7 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by decreased operating costs and expenses of $11.8 million in the Corporate and Other segment and $5.4 million in the Natural Gas Transportation segment, as discussed further below. The decrease in Corporate and Other expenses was primarily driven by an $18.4 million increase in eliminations of intersegment operating costs and expenses, partially offset by a $6.6 million increase in corporate general and administrative costs primarily due to new equity-based compensation grants issued
during the year ended December 31, 2017 as well as payroll taxes associated with the vesting of TEP common units associated with equity-based compensation grants under the TEP GP Long-term Incentive Plan.
Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $237.1 million and $54.5 million for the years ended December 31, 2017 and 2016, respectively. Equity in earnings of unconsolidated investments of $237.1 million for the year ended December 31, 2017 primarily reflects our portion of earnings and the $23.2 million of amortization of a negative basis difference associated with our 49.99% membership interest in Rockies Express, as well as $1.5 million of equity in earnings related to our 20% membership interest in Deeprock Development prior to our acquisition of a controlling financial interest in Deeprock Development in July 2017, as discussed in Note 3 – Acquisitions and Dispositions. The equity in earnings for the year ended December 31, 2017 includes recognition of our portion of the $150 million gain on settlement of the Ultra litigation as discussed above. Equity in earnings of unconsolidated investments of $54.5 million for the year ended December 31, 2016 primarily reflects our portion of earnings and the $9.1 million of amortization of a negative basis difference associated with our acquisition of a 25% membership interest in Rockies Express effective May 6, 2016, as well as $2.8 million related to our 20% membership interest in Deeprock Development during the year ended December 31, 2016. The equity in earnings for the year ended December 31, 2016 includes recognition of our portion of the $65 million settlement received by Rockies Express related to the lawsuit between Mineral Management Service, a former unit of the U.S. Department of Interior (collectively "Interior") and Rockies Express as discussed in Note 19 – Legal and Environmental Matters.
Interest expense, net. Interest expense of $89.3 million for the year ended December 31, 2017 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities and the 2024 Notes issued on September 1, 2016 and May 16, 2017, and the 2028 Notes issued on September 15, 2017 and December 11, 2017. Interest expense of $45.6 million for the year ended December 31, 2016 was primarily composed of interest and fees associated with TEP and Tallgrass Equity revolving credit facilities and the 2024 Notes issued on September 1, 2016. The increase in interest and fees is primarily due to increased borrowings to fund a portion of our acquisitions, as discussed further in Note 43 – Acquisitions and Dispositions, as well as the higher borrowing rate on the 2024 and 2028 Notes, the proceeds of which were used to repay borrowings under TEP's revolving credit facility.
Unrealized gain (loss) on derivative instrument. Unrealized gain on derivative instrument of $1.9 million and unrealized loss on derivative instrument of $1.3 million for the years ended December 31, 2017 and 2016, respectively, represents the change in fair value of the call option received from TD as part of the acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016. As of February 1, 2017, no common units remained subject to the call option.
Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $237.1 million and $54.5 million for the years ended December 31, 2017 and 2016, respectively. Equity in earnings of unconsolidated investments of $237.1 million for the year ended December 31, 2017 primarily reflects our portion of earnings and the amortization of a negative basis difference of $23.2 million associated with our 49.99% membership interest in Rockies Express, as well as $1.5 million of equity in earnings related to our 20% membership interest in Deeprock Development prior to TEP's acquisition of a controlling financial interest in Deeprock Development in July 2017, as discussed in Note 4 – Acquisitions. The equity in earnings for the year ended December 31, 2017 includes recognition of our portion of the $150 million gain on settlement of the Ultra litigation as discussed in Note 19 – Legal and Environmental Matters. Equity in earnings of unconsolidated investments of $54.5 million for the year ended December 31, 2016 primarily reflects our portion of earnings and the amortization of a negative basis difference of $9.1 million associated with TEP's acquisition of a 25% membership interest in Rockies Express effective May 6, 2016, as well as $2.8 million related to our 20% membership interest in Deeprock Development during the year ended December 31, 2016. The equity in earnings for the year ended December 31, 2016 includes recognition of our portion of the $65 million settlement received by Rockies Express related to the lawsuit between Mineral Management Service, a former unit of the U.S. Department of Interior (collectively "Interior") and Rockies Express as discussed in Note 19 – Legal and Environmental Matters. For additional information, see Note 9 – Investments in Unconsolidated Affiliates.
Gain on remeasurement of unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.7 million for the year ended December 31, 2017 was related to the remeasurement to fair value of our existing 20% membership interest in Deeprock Development in connection with TEP's acquisition of a controlling financial interest in Deeprock Development in July 2017. For additional information, see Note 43 – Acquisitions.Acquisitions and Dispositions.
Other income, net. net. Other income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other income for the year ended December 31, 2017 was $1.2$3.1 million compared to $1.7$0.4 million for the year ended December 31, 2016. The decrease in otherOther income was driven by lower incomeof $3.1 million and $0.4 million for the years ended December 31, 2017 and 2016 included a $1.9 million unrealized gain and a $1.3 million unrealized loss, respectively, on derivative instrument related to reimbursable projects at TIGT due to contract modifications.the change in fair value of the call option received from TD as part of the acquisition of an additional 31.3% membership interest in Pony Express as discussed further in Note 9 – Risk Management.
Deferred income tax (expense) benefit.expense. Deferred income tax expense for the year ended December 31, 2017 was $208.5 million compared to a deferred income tax expense of $17.7 million for the year ended December 31, 2016. The increase in deferred income tax expense was primarily driven by the remeasurement of the deferred tax asset as a result of the federal rate change under the tax legislation referred to as the Tax Cuts and Jobs Act that was signed into law on December 22, 2017, as well as the increase in taxable income, primarily attributable to the increased equity in earnings associated with Rockies Express as a result of the Ultra settlement. For additional information, see Note 17 – Income Taxes.
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Revenues. Total revenues were $611.7 million for the year ended December 31, 2016, compared to $542.7 million for the year ended December 31, 2015, which represents an increase of $69.0 million, or 13%, in total revenues. The overall increase in revenue was primarily driven by increased revenues of $76.3 million in the Crude Oil Transportation segment, partially offset by decreased revenues of $2.9 million in the Natural Gas Transportation segment, as discussed further below.
Operating costs and expenses. Operating costs and expenses were $353.2 million for the year ended December 31, 2016 compared to $336.4 million for the year ended December 31, 2015, which represents an increase of $16.8 million, or 5%. The overall increase in operating costs and expenses was primarily driven by increased operating costs and expenses of $20.0 million and $9.0 million in the Crude Oil Transportation and the Gathering, Processing & Terminalling segments, respectively, partially offset by decreased operating costs and expenses of $10.9 million in the Natural Gas Transportation segment, as discussed further below, as well as a $1.3 million decrease in the Corporate and Other segment primarily driven by an $4.5 million increase in eliminations of intersegment operating costs and expenses, partially offset by a $3.2 million increase in corporate general and administrative costs due to increased overhead costs allocated from TD.
Interest expense, net. Interest expense of $45.6 million for the year ended December 31, 2016 was primarily composed of interest and fees associated with TEP's and Tallgrass Equity's revolving credit facilities and the 2024 Notes issued on September 1, 2016. Interest expense of $18.3 million for the year ended December 31, 2015 was primarily composed of interest and fees associated with TEP's revolving credit facility, partially offset by interest income of $0.4 million on the cash balance swept to TD under the Pony Express cash management agreement. The increase in interest and fees is primarily due to increased borrowings under TEP's revolving credit facility to fund a portion of TEP's 2016 and 2015 acquisitions, as discussed further in Note 4 – Acquisitions, as well as the higher borrowing rate on the 2024 Notes, the proceeds of which we used to repay borrowings under TEP's revolving credit facility, and a full period of interest and fees associated with outstanding borrowings under the Tallgrass Equity revolving credit facility.
Unrealized gain (loss) on derivative instrument. Unrealized loss on derivative instrument of $1.3 million represents the change in fair value of the call option received from TD as part of the acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016.
Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $54.5 million and $2.8 million for the years ended December 31, 2016 and 2015, respectively. Equity in earnings of unconsolidated investments of $54.5 million for the year ended December 31, 2016 reflects our portion of earnings and the amortization of a negative basis difference of $9.1 million associated with our acquisition of a 25% membership interest in Rockies Express effective May 6, 2016, as well as $2.8 million related to our 20% membership interest in Deeprock Development. The equity in earnings of Rockies Express for the year ended December 31, 2016 includes recognition of our portion of the $65 million settlement received by Rockies Express related to the lawsuit between Interior and Rockies Express as discussed in Note 19 – Legal and Environmental Matters. Equity in earnings of unconsolidated investments of $2.8 million for the year ended December 31, 2015 represents earnings associated with our 20% membership interest in Deeprock Development. For additional information, see Note 9 – Investments in Unconsolidated Affiliates.
Other income, net. Other income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other income for the year ended December 31, 2016 was $1.7 million compared to $2.4 million for the year ended December 31, 2015. The decrease in other income was driven by lower income related to reimbursable projects at TIGT due to a contract termination during the year ended December 31, 2016.
Deferred income tax (expense) benefit. Deferred income tax expense for the year ended December 31, 2016 was $17.7 million compared to a deferred income tax benefit of $7.3 million for the year ended December 31, 2015. The increase in deferred income tax expense was primarily driven by the increase in net income before taxes and a full year of taxable income in 2016 compared to the period subsequent to the closing of the TEGP IPO from May 12, 2015 to December 31, 2015, as well as a higher effective tax rate for the year ended December 31, 2016 compared to the year ended December 31, 2015 as a result of our acquisition of a 25% membership interest in Rockies Express during the second quarter of 2016. The year ended December 31, 2015 also included a $13.8 million deferred income tax benefit associated with a change in applicable state apportionment percentages, which increased the value of expected future state benefits attributable to the excess tax basis of our investment in Tallgrass Equity.
The following provides a summary of our Natural Gas Transportation segment results of operations for the periods indicated:
| | Segment Financial Data – Natural Gas Transportation (1) | Year Ended December 31, | Year Ended December 31, |
| 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
| Revenues: | | | | | | | | | | |
| Natural gas transportation services | $ | 129,058 |
| | $ | 125,603 |
| | $ | 125,279 |
| $ | 131,555 |
| | $ | 129,058 |
| | $ | 125,603 |
|
| Sales of natural gas, NGLs, and crude oil | 3,412 |
| | 3,241 |
| | 6,346 |
| 1,195 |
| | 3,412 |
| | 3,241 |
|
| Processing and other revenues | 8,551 |
| | 6,253 |
| | 6,363 |
| 7,709 |
| | 8,551 |
| | 6,253 |
|
| Total revenues | 141,021 |
| | 135,097 |
| | 137,988 |
| 140,459 |
| | 141,021 |
| | 135,097 |
|
| Operating costs and expenses: | | | | | | | | | | |
| Cost of sales | 2,767 |
| | 3,804 |
| | 6,342 |
| 1,382 |
| | 2,767 |
| | 3,804 |
|
| Cost of transportation services | 2,852 |
| | 5,051 |
| | 10,927 |
| 2,990 |
| | 2,852 |
| | 5,051 |
|
| Operations and maintenance | 28,910 |
| | 28,458 |
| | 27,767 |
| 27,185 |
| | 28,910 |
| | 28,458 |
|
| Depreciation and amortization | 19,180 |
| | 20,976 |
| | 22,927 |
| 19,442 |
| | 19,180 |
| | 20,976 |
|
| General and administrative | 15,385 |
| | 16,335 |
| | 17,052 |
| 15,279 |
| | 15,385 |
| | 16,335 |
|
| Taxes, other than income taxes | 4,493 |
| | 4,338 |
| | 4,840 |
| 4,595 |
| | 4,493 |
| | 4,338 |
|
| Total operating costs and expenses | 73,587 |
| | 78,962 |
| | 89,855 |
| 70,873 |
| | 73,587 |
| | 78,962 |
|
| Operating income | $ | 67,434 |
| | $ | 56,135 |
| | $ | 48,133 |
| $ | 69,586 |
| | $ | 67,434 |
| | $ | 56,135 |
|
| |
(1) | Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 20 – Reportable Segments. |
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Revenues. Natural Gas Transportation segment revenues were $140.5 million for the year ended December 31, 2018 compared to $141.0 million for the year ended December 31, 2017, which represents a decrease of $0.6 million in segment revenues due to a $2.2 million decrease in sales of natural gas driven by decreased volumes sold and a $0.8 million decrease in other revenues driven by a decrease in the management fee received by NatGas as a result of the Ultra settlement recognized during the year ended December 31, 2017, as discussed in Note 19 – Legal and Environmental Matters, partially offset by a $2.5 million increase in natural gas transportation services due to increased revenue associated with increased throughput and contracted capacity in the second quarter of 2018 and colder weather in the first quarter of 2018, both resulting in higher volumes transported during the first half of 2018.
Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $70.9 million for the year ended December 31, 2018 compared to $73.6 million for the year ended December 31, 2017, which represents a decrease of $2.7 million, or 4%. The overall decrease in operating costs and expenses was primarily due to a $1.7 million decrease in operations and maintenance costs driven by decreased pipeline integrity work and a $1.4 million decrease in cost of sales driven by decreased volumes of natural gas sold, partially offset by a $0.3 million increase in depreciation and amortization costs.
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Revenues. Natural Gas Transportation segment revenues were $141.0 million for the year ended December 31, 2017 compared to $135.1 million for the year ended December 31, 2016, which represents an increase of $5.9 million, or 4%, in segment revenues primarily due to a $3.5 million increase in natural gas transportation services, a $2.3 million increase in other revenue, and a $0.2 million increase in sales of natural gas, NGLs, and crude oil.gas. The $3.5 million increase in natural gas transportation services was driven by increased tariff rates at TIGT, partially offset by a change in the fuel recovery structure, beginning May 1, 2016 as a result of the rate case settlement discussed in Note 18 – Regulatory Matters, as well as increased throughput volumes at Trailblazer. The $2.3 million increase in other revenues was primarily attributable to the increased management fee received by NatGas as a result of the Ultra settlement recognized during the year ended December 31, 2017, as discussed in Note 19 – Legal and Environmental Matters.above.
Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $73.6 million for the year ended December 31, 2017 compared to $79.0 million for the year ended December 31, 2016, which represents a decrease of $5.4 million, or 7%. The overall decrease in operating costs and expenses was primarily due to a $2.2 million decrease in the cost of transportation services, a $1.8 million decrease in depreciation and amortization, and a $1.0 million decrease in cost of sales. The $2.2 million decrease in the cost of transportation services was driven by lower costs associated
with fuel reimbursements as a result of changes to TIGT's fuel recovery structure and the $1.8 million decrease in depreciation and amortization was driven by changes in depreciation rates at TIGT, both as a result of the 2016 rate case settlement discussed above. The $1.0 million decrease in cost of sales was driven by decreased volumes sold as well as a lower of cost and net realizable value inventory adjustment during the year ended December 31, 2016.
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Revenues. Natural Gas Transportation segment revenues were $135.1 million for the year ended December 31, 2016, compared to $138.0 million for the year ended December 31, 2015, which represents a decrease of $2.9 million, or 2%, in segment revenues driven by a $3.1 million decrease in the sales of natural gas, NGLs, and crude oil as a result of lower volumes of natural gas sold. The decrease in sales of natural gas, NGLs, and crude oil was partially offset by a $0.3 million increase in natural gas transportation services primarily driven by a $2.3 million increase at TIGT, partially offset by a $1.9 million decrease at Trailblazer due to warmer weather in the first quarter of 2016, resulting in lower volumes transported during the year ended December 31, 2016. The increase in natural gas transportation services revenue at TIGT was primarily driven by increased tariff rates, partially offset by a change in the fuel recovery structure, beginning May 1, 2016 as a result of the rate case settlement discussed in Note 18 – Regulatory Matters.
Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $79.0 million for the year ended December 31, 2016 compared to $89.9 million for the year ended December 31, 2015, which represents a decrease of $10.9 million, or 12%. The overall decrease in operating costs and expenses was primarily driven by a $5.9 million decrease in cost of transportation services due to lower costs associated with fuel reimbursements as a result of the change in the fuel recovery structure discussed above, a $2.5 million decrease in cost of sales due to lower volumes of natural gas sold, and a $2.0 million decrease in depreciation and amortization due to lower depreciation rates as of May 1, 2016 as a result of the TIGT rate case settlement.
The following provides a summary of our Crude Oil Transportation segment results of operations for the periods indicated:
| | | | Year Ended December 31, | |
Segment Financial Data – Crude Oil Transportation (1) | | Year Ended December 31, |
| 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
| Revenues: | | | | | | | | | | |
| Crude oil transportation services | $ | 353,395 |
| | $ | 374,949 |
| | $ | 300,436 |
| $ | 437,653 |
| | $ | 353,395 |
| | $ | 374,949 |
|
| Sales of natural gas, NGLs, and crude oil | 11,179 |
| | 5,554 |
| | 3,791 |
| 6,290 |
| | 11,179 |
| | 5,554 |
|
| Processing and other revenues | | 511 |
| | — |
| | — |
|
| Total revenues | 364,574 |
| | 380,503 |
| | 304,227 |
| 444,454 |
| | 364,574 |
| | 380,503 |
|
| Operating costs and expenses: | | | | | | | | | | |
| Cost of sales | 9,680 |
| | 4,728 |
| | 4,257 |
| 8,334 |
| | 9,680 |
| | 4,728 |
|
| Cost of transportation services | 57,284 |
| | 55,519 |
| | 47,367 |
| 68,184 |
| | 57,284 |
| | 55,519 |
|
| Operations and maintenance | 11,838 |
| | 13,075 |
| | 8,795 |
| 12,896 |
| | 11,838 |
| | 13,075 |
|
| Depreciation and amortization | 52,364 |
| | 51,362 |
| | 47,168 |
| 54,237 |
| | 52,364 |
| | 51,362 |
|
| General and administrative | 20,906 |
| | 20,650 |
| | 20,620 |
| 18,486 |
| | 20,906 |
| | 20,650 |
|
| Taxes, other than income taxes | 22,332 |
| | 19,385 |
| | 16,553 |
| 24,009 |
| | 22,332 |
| | 19,385 |
|
| Total operating costs and expenses | 174,404 |
| | 164,719 |
| | 144,760 |
| 186,146 |
| | 174,404 |
| | 164,719 |
|
| Operating income | $ | 190,170 |
| | $ | 215,784 |
| | $ | 159,467 |
| $ | 258,308 |
| | $ | 190,170 |
| | $ | 215,784 |
|
| |
(1) | Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 20 – Reportable Segments. |
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Revenues. Crude Oil Transportation segment revenues were $444.5 million for the year ended December 31, 2018 compared to $364.6 million for the year ended December 31, 2017, which represents an increase of $79.9 million, or 22%, in segment revenues driven by an $84.3 million increase in crude oil transportation services, partially offset by a $4.9 million decrease in sales of crude oil primarily due to decreased volumes sold during the year ended December 31, 2018. The increase in crude oil transportation services revenue was primarily driven by a $55.4 million increase in committed volume shipments, a $37.2 million increase in walk-up barrels shipped, a $6.4 million increase due to the FERC annual index adjustments effective July 1, 2018, and a $5.6 million increase in PLA revenue. These increases were partially offset by a $24.4 million net decrease in revenue from a committed shipper that extended its contract during the fourth quarter of 2017, thereby paying a lower tariff rate, which was partially offset by increased volumes shipped.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $186.1 million for the year ended December 31, 2018 compared to $174.4 million for the year ended December 31, 2017, which represents an increase of $11.7 million, or 7%. The overall increase in operating costs and expenses was primarily driven by a $10.9 million increase in cost of transportation services driven by higher throughput volumes during the year ended December 31, 2018 compared to the year ended December 31, 2017, a $1.9 million increase in depreciation and amortization costs due to assets placed into service in 2018, and a $1.7 million increase in taxes, other than income taxes driven by an increase in property tax assessment estimates. These increases were partially offset by a $2.4 million decrease in general and administrative costs and a $1.3 million decrease in cost of sales driven by decreased volumes sold.
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Revenues. Crude Oil Transportation segment revenues were $364.6 million for the year ended December 31, 2017 compared to $380.5 million for the year ended December 31, 2016, which represents a decrease of $15.9 million, or 4%, in segment revenues driven by a $21.6 million decrease in crude oil transportation services, primarily due to a $27.1 million increase in shipper deficiency payments that are not recognized in revenue and a $9.9 million decrease in the incremental barrels delivered during the year ended December 31, 2017 compared to the year ended December 31, 2016, partially offset by a $7.8 million increase in committed barrels shipped and a $7.0 million increase in walk-up barrels shipped. The decrease in
crude oil transportation services was partially offset by a $5.6 million increase in sales of natural gas, NGLs, and crude oil primarily due to increased volumes of crude oil sold during the year ended December 31, 2017 compared to the year ended December 31, 2016.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $174.4 million for the year ended December 31, 2017 compared to $164.7 million for the year ended December 31, 2016 which represents an increase of $9.7 million, or 6%. The overall increase in operating costs and expenses was primarily driven by a $5.0 million increase in cost of sales primarily due to increased volumes of crude oil sold during the year ended December 31, 2017, a $2.9 million increase in taxes, other than income taxes, driven by assets placed in servicein-service throughout 2016, and a $1.8 million increase in cost of transportation services as a result of amendments to the Deeprock Terminal lease agreement, resulting in the non-cash write off of upfront payments in the fourth quarter of 2017, partially offset by lower lease payments during the third and fourth quarters of 2017. The increased cost of transportation services during the year ended December 31, 2017 as a result of the Deeprock Terminal lease was partially offset by higher electric costs as a result of pressure restrictions during the year ended December 31, 2016. The cost increases during the year ended December 31, 2017 were partially offset by a $1.2 million decrease in operations and maintenance costs due to the timing of pipeline integrity work.
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Revenues. Crude Oil Transportation segment revenues were $380.5 million for the year ended December 31, 2016 compared to $304.2 million for the year ended December 31, 2015 which represents an increase of $76.3 million, or 25%, in segment revenues due to a $74.5 million increase in crude oil transportation services revenue and a $1.8 million increase in sales of crude oil primarily due to increased volumes sold during the year ended December 31, 2016. The increase in crude oil transportation services was primarily driven by a $42.6 million increase in revenue from a full period of operations on the lateral in Northeast Colorado, which began commercial operations during the second quarter of 2015, a $19.6 million increase related to the activation of one of our joint tariffs in the second quarter of 2015, and lower revenue of $9.8 million during the year ended December 31, 2015 due to a force majeure at one of our joint tariff partners.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $164.7 million for the year ended December 31, 2016 compared to $144.8 million for the year ended December 31, 2015 which represents an increase of $20.0 million, or 14%. The overall increase in operating costs and expenses was primarily driven by an $8.2 million increase in cost of transportation services, primarily due to $4.2 million associated with drag-reduction agents and higher electrical costs at pump stations associated with increased transportation volumes, and increases of $4.3 million, $4.2 million, and $2.8 million in operations and maintenance costs, depreciation and amortization, and taxes, other than income taxes, respectively, all primarily driven by the costs associated with a full period of operations on the lateral in Northeast Colorado.
The following provides a summary of our Gathering, Processing & Terminalling segment results of operations for the periods indicated:
| | | | Year Ended December 31, | |
Segment Financial Data – Gathering, Processing & Terminalling (1) | | Year Ended December 31, |
| 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
| Revenues: | | | | | | | | | | |
| Sales of natural gas, NGLs, and crude oil | $ | 93,998 |
| | $ | 68,698 |
| | $ | 71,996 |
| $ | 161,101 |
| | $ | 93,998 |
| | $ | 68,698 |
|
| Processing and other revenues | 92,213 |
| | 44,835 |
| | 41,391 |
| 118,564 |
| | 92,213 |
| | 44,835 |
|
| Total revenues | 186,211 |
| | 113,533 |
| | 113,387 |
| 279,665 |
| | 186,211 |
| | 113,533 |
|
| Operating costs and expenses: | | | | | | | | | | |
| Cost of sales | 80,088 |
| | 63,746 |
| | 64,686 |
| 105,985 |
| | 80,088 |
| | 63,746 |
|
| Cost of transportation services | 20,650 |
| | 3,942 |
| | 1,487 |
| 52,327 |
| | 20,650 |
| | 3,942 |
|
| Operations and maintenance | 21,321 |
| | 13,537 |
| | 14,261 |
| 32,379 |
| | 21,321 |
| | 13,537 |
|
| Depreciation and amortization | 19,256 |
| | 13,909 |
| | 14,163 |
| 32,369 |
| | 19,256 |
| | 13,909 |
|
| General and administrative | 10,035 |
| | 7,715 |
| | 5,597 |
| 12,877 |
| | 10,035 |
| | 7,715 |
|
| Taxes, other than income taxes | 2,007 |
| | 1,677 |
| | 403 |
| 3,206 |
| | 2,007 |
| | 1,677 |
|
| Contract termination | — |
| | 8,061 |
| | — |
| — |
| | — |
| | 8,061 |
|
| (Gain) loss on disposal of assets | (599 | ) | | 1,849 |
| | 4,795 |
| (11,043 | ) | | (599 | ) | | 1,849 |
|
| Total operating costs and expenses | 152,758 |
| | 114,436 |
| | 105,392 |
| 228,100 |
| | 152,758 |
| | 114,436 |
|
| Operating income (loss) | $ | 33,453 |
| | $ | (903 | ) | | $ | 7,995 |
| $ | 51,565 |
| | $ | 33,453 |
| | $ | (903 | ) |
| |
(1) | Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 20 – Reportable Segments. |
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Revenues. Gathering, Processing & Terminalling segment revenues were $279.7 million for the year ended December 31, 2018 compared to $186.2 million for the year ended December 31, 2017, which represents a $93.5 million, or 50%, increase in segment revenues. The increase in segment revenues was primarily due to a $67.1 million increase in sales of natural gas, NGLs, and crude oil and a $26.4 million increase in processing and other revenues. The increase in sales of natural gas, NGLs, and crude oil was driven by (i) increased crude oil sales of $30.3 million at Stanchion, (ii) increased sales of NGLs of $24.2 million primarily due to higher throughput volumes and increased volumes sold driven by the Douglas Gathering System acquisition in June 2017 and higher NGL prices, and (iii) increased sales of natural gas of $12.3 million due to sales of residue gas from the Douglas Gathering System. The increase in processing and other revenues was driven by (i) increased terminal services revenue of $16.2 million driven by the acquisition of Deeprock North in January 2018 and the acquisition of a controlling interest in, and subsequent consolidation of, Deeprock Development in July 2017, (ii) increased water business services revenue of $7.6 million driven by the acquisition of BNN North Dakota in January 2018 and increased produced water disposal volumes, partially offset by decreased fresh water transportation volumes, and (iii) increased processing fee income of $3.9 million primarily driven by changes in the accounting treatment of certain commodities retained as consideration for
processing services to processing fee revenue beginning January 1, 2018 as discussed further in Note 12 – Revenue from Contracts with Customers.
Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were $228.1 million for the year ended December 31, 2018 compared to $152.8 million for the year ended December 31, 2017, which represents an increase of $75.3 million, or 49%. The increase in operating costs and expenses was primarily driven by (i) an increase of $31.7 million in cost of transportation services due to crude oil transportation fees paid by Stanchion, partially offset by decreased fresh water transportation volumes and associated costs, (ii) a $25.9 million increase in cost of sales primarily due to higher NGL prices, higher throughput volumes, and increased volumes sold driven by the Douglas Gathering System acquisition as discussed above, and (iii) increases of $13.1 million, $11.1 million, and $2.8 million in depreciation and amortization, operations and maintenance costs, and general and administrative costs, respectively, all primarily driven by the 2018 acquisitions of BNN North Dakota and Deeprock North and the 2017 acquisitions of the Douglas Gathering System and Deeprock Development. The increase in operating costs and expenses was partially offset by the $11.0 million gain on disposal of assets, primarily driven by the gain on the disposal of TCG during the year ended December 31, 2018, compared to the $0.6 million gain on disposal of assets during the year ended December 31, 2017.
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Revenues. Gathering, Processing & Terminalling segment revenues were $186.2 million for the year ended December 31, 2017 compared to $113.5 million for the year ended December 31, 2016, which represents a $72.7 million, or 64%, increase in segment revenues. The increase in segment revenues was primarily due to a $47.4 million increase in processing and other revenues and a $25.3 million increase in sales of natural gas, NGLs, and crude oil. The increase in processing and other revenues was driven by (i) increased water business services revenue of $29.8 million as a result of increased fresh water supply and produced water disposal volumes; (ii) increased terminalling services revenue of $11.0 million driven by the acquisition of a controlling interest in and subsequent consolidation of Deeprock Development in July 2017; and (iii) increased fee income of $6.1 million driven by the acquisition of the Douglas Gathering System in MayJune 2017. The increase in sales of natural gas, NGLs, and crude oil was driven by a 36% increase in NGL prices and sales of residue gas from the Douglas
Gathering System, partially offset by lower volumes of NGLs sold during the year ended December 31, 2017 as a result of take in kind elections in effect for parts of 2017 under two major processing agreements.
Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were $152.8 million for the year ended December 31, 2017 compared to $114.4 million for the year ended December 31, 2016, which represents an increase of $38.3 million, or 33%. The increase in operating costs and expenses was driven by (i) a $16.7 million increase in cost of transportation services primarily driven by increased volumes in water business services as discussed above and crude oil transportation fees paid by Stanchion during the year ended December 31, 2017; (ii) a $16.3 million increase in cost of sales primarily driven by higher producer settlements and higher NGL sales attributable to the acquisition of the Douglas Gathering System in 2017 as discussed above; and (iii) increases of $7.8 million, $5.3 million, and $2.3 million in operations and maintenance costs, depreciation and amortization, and general and administrative costs, respectively, all primarily driven by the 2017 acquisitions of the Douglas Gathering System, the PRB Crude System, and Deeprock Development. These increases were partially offset by a $8.1 million contract termination fee as a result of the buyout of an operating agreement at the Sterling Terminal during the year ended December 31, 2016 and a $2.4 million decrease in (gain) loss on disposal of assets primarily driven by a gain on disposal of assets from insurance proceeds received during the year ended December 31, 2017 related to assets destroyed by a fire caused by a lightning strike during the year ended December 31, 2016.
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Revenues. Gathering, Processing & Terminalling segment revenues were $113.5 million for the year ended December 31, 2016, compared to $113.4 million for the year ended December 31, 2015, which represents a $0.1 million increase in segment revenues. The increase in segment revenues was primarily due to a $3.4 million increase in processing and other revenues driven by increased terminalling services revenue of $4.4 million, resulting from a full year of operations at the Sterling Terminal, and increased water business services revenue of $4.0 million primarily attributable to the Western and West Texas asset acquisitions, partially offset by lower processing fees of $4.9 million due to decreased volumes processed. The increase in processing and other revenues was partially offset by a $3.3 million decrease in the sales of natural gas, NGLs, and crude oil driven by lower NGL and natural gas sales due to lower volumes processed, partially offset by increased NGL prices.
Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were $114.4 million for the year ended December 31, 2016 compared to $105.4 million for the year ended December 31, 2015, which represents an increase of $9.0 million, or 9%. The increase in operating costs and expenses was driven by (i) an $8.1 million contract termination fee during the year ended December 31, 2016 as discussed above; (ii) a $2.5 million increase in cost of transportation services due to costs associated with Western, which was acquired on December 16, 2015; (iii) a $2.1 million increase in general and administrative costs due to increased costs allocated to Water Solutions as a result of increased operating income related to our acquisitions of Western and West Texas; and (iv) a $1.3 million increase in taxes, other than income taxes due to higher property tax estimates for 2016 as a result of the Western acquisition and the Sterling Terminal which was placed in service during 2015. These increases were partially offset by (i) a $2.9 million decrease in (gain) loss on disposal of assets as a result of the $1.8 million loss on assets destroyed by fire as a result of a lightning strike during the year ended December 31, 2016, compared to a $4.8 million non-cash loss recognized on the sale of compressor and other assets in 2015; (ii) a $0.9 million decrease in cost of sales driven by decreased NGL volumes processed as discussed above; (iii) a $0.7 million decrease in operations and maintenance costs due to less downtime for plant maintenance activities during the year ended December 31, 2016 compared to the year ended December 31, 2015, partially offset by higher costs associated with the Western and West Texas assets acquired; and (iv) a $0.3 million decrease in depreciation and amortization driven by an intangible asset becoming fully amortized as of December 31, 2015, partially offset by increased depreciation related to the new NGL transportation line.
Liquidity and Capital Resources Overview
Our primary sources of liquidity for the year ended December 31, 20172018 were cash generated from operations, proceeds from TEP's issuance of long-term debt,senior notes, and borrowings under TEP's revolving credit facility, cash generated from operations, and proceeds from the issuance of TEP common units.facility. We expect our sources of liquidity in the future to include:
cash generated from our operations;
borrowing capacity available under TEP's revolving credit facility; and
future issuances of additional partnership unitsequity and/or debt securities.
We believe that cash on hand, cash generated from operations, and availability under TEP's revolving credit facility will be adequate to meet our operating needs, our planned short-term maintenance capital and debt service requirements, and our planned cash distributionsdividends to shareholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of cash generated from operations, borrowings under TEP's revolving credit facility and issuances of debt and/or equity securities at TEP.securities. For additional information regarding our revolving credit facilityfacilities and senior unsecured notes, see Note 1110 – Long-term Debt. For additional information regarding our equity transactions, see Note 1211 – Partnership Equity and Distributions.
Our total liquidity as of December 31, 20172018 and 20162017 was as follows:
| | | | December 31, 2017 | | December 31, 2016 | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
| Cash on hand | $ | 2,593 |
| | $ | 2,459 |
| $ | 9,596 |
| | $ | 2,593 |
|
Total capacity under the TEP revolving credit facility | 1,750,000 |
| | 1,750,000 |
| 2,250,000 |
| | 1,750,000 |
|
Less: Outstanding borrowings under the TEP revolving credit facility (1) | (661,000 | ) | | (1,015,000 | ) | (1,224,000 | ) | | (661,000 | ) |
| Less: Letters of credit issued under the TEP revolving credit facility | (94 | ) | | — |
| (94 | ) | | (94 | ) |
| Available capacity under the TEP revolving credit facility | 1,088,906 |
| | 735,000 |
| 1,025,906 |
| | 1,088,906 |
|
| Total capacity under the Tallgrass Equity revolving credit facility | 150,000 |
| | 150,000 |
| — |
| | 150,000 |
|
Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility | (146,000 | ) | | (148,000 | ) | — |
| | (146,000 | ) |
| Available capacity under the Tallgrass Equity revolving credit facility | 4,000 |
| | 2,000 |
| — |
| | 4,000 |
|
| Total liquidity | $ | 1,095,499 |
| | $ | 739,459 |
| $ | 1,035,502 |
| | $ | 1,095,499 |
|
| |
(1) | As of February 12,In July 2018, outstanding borrowings under the TEP revolving credit facility were approximately $0.9was amended, increasing the total capacity to $2.25 billion. See Note 10 – Long-term Debt for additional information. |
| |
(2) | On July 26, 2018, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility. See Note 10 – Long-term Debt for additional information. |
Working Capital
Working capital is the amount by which current assets exceed current liabilities. While various other factors may impact our working capital requirements from period to period, our working capital requirements have typically been, and we expect will continue to be, driven by changes in accounts receivable, accounts payable and deferred revenue. TEP manages itsWe manage our working capital needs through borrowings and repayments of borrowings under itsTEP's revolving credit facility. Factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers, payments to suppliers, and the level of spending for capital expenditures. Changes in the market prices of energy commodities that we buy and sell in the normal course of business can also impact the timing of changes in accounts receivable and accounts payable. Factors impacting deferred revenue include the volume of barrels transported, the amount of deficiency payments received, and the volume of prior deficiencies utilized during the period.
As of December 31, 2017,2018, we had a working capital deficit of $101.6$146.9 million compared to a working capital deficit of $37.7$101.6 million at December 31, 2016,2017, which represents an increase in the working capital deficit of $63.8$45.4 million. The overall increase in the working capital deficit was primarily attributable to changes in the following components:
an increase in accounts payable and accrued liabilities of $74.4$110.0 million primarily due to crude oil purchases at Stanchion, as well as increased expansionan increase in accrued payroll, an increase in capital accrualsexpenditures at Terminals, and payables related to BNN North Dakota and NGL Water Solutions Bakken acquired in January 2018 and November 2018, respectively, partially offset by a decrease in capital expenditures at Pony ExpressExpress;
an increase in other current liabilities of $31.7 million, primarily driven by the recognition of a $25 million liability at PLT as discussed in Note 3 – Acquisitions and Terminals, and increased settlement volumes at TMID as a result of the Douglas Gathering acquisition;Dispositions;
an increase in deferred revenue of $27.7$22.6 million primarily from deficiency payments collected by Pony Express;Express and deferred revenue at BNN Colorado, which was consolidated in December 2018; and
an increase in accrued liabilitiesinterest of $19.0$14.1 million primarily due to an increase in interest accrued at December 31, 2017 compared to December 31, 2016 due to increased borrowings andto fund a portion of our 2018 acquisitions, as well as the higher interest ratesborrowing rate on the 2024 and 2028Senior Notes, issued during 2017 comparedthe proceeds of which were used to repay borrowings under TEP's revolving credit facility; andfacility.
a decrease in derivative assets at fair value of $11.0 million as TEP exercised the remainder of the call option granted by TD
These working capital decreases were partially offset by:
an increase in accounts receivable of $60.4$116.1 million primarily due to crude oil sales at Stanchion;Stanchion, as well as receivables related to BNN North Dakota assets acquired during 2018, and BNN Colorado, which was consolidated in December 2018; and
an increase in inventoriesinventory of $8.5$12.7 million primarily due to crude oil purchases at Stanchion.
Stanchion and PLA barrels retained at Pony Express.
A material adverse change in operations, available financing under our revolving credit facility, or available financing from the equity or debt capital markets could impact our ability to fund our requirements for liquidity and capital resources in the future.
Cash Flows
The following table and discussion presents a summary of our cash flow for the periods indicated:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
| Net cash provided by (used in): | | | | | | | | | | |
| Operating activities | $ | 571,396 |
| | $ | 413,298 |
| | $ | 300,216 |
| $ | 672,525 |
| | $ | 571,396 |
| | $ | 413,298 |
|
| Investing activities | $ | (898,541 | ) | | $ | (595,539 | ) | | $ | (899,432 | ) | $ | (987,212 | ) | | $ | (898,541 | ) | | $ | (595,539 | ) |
| Financing activities | $ | 327,279 |
| | $ | 182,466 |
| | $ | 600,583 |
| $ | 321,690 |
| | $ | 327,279 |
| | $ | 182,466 |
|
Year Ended December 31, 20172018 Compared to the Year Ended December 31, 20162017
Operating Activities. Cash flows provided by operating activities were $571.4$672.5 million and $413.3$571.4 million for the years ended December 31, 20172018 and 2016,2017, respectively. The increase in net cash flows provided by operating activities of $158.1$101.1 million was primarily driven by the increase in operating results, as discussed above, and a $237.2$69.7 million increase in distributions received from unconsolidated affiliates, primarily Rockies Express, as a result of the Ultra settlement received in July 2017 as well as our increased membership interest duringeffective March 31, 2017 and February 7, 2018. These increases were partially offset by a net decrease in cash flows from changes in working capital driven by a $44.2 million decrease in net cash inflows from accounts receivable, primarily due to crude oil sales at Stanchion, partially offset by a $27.7 million decrease in net cash outflows from accounts payable, primarily due to crude oil purchases at Stanchion.
Investing Activities. Cash flows used in investing activities were $987.2 million for the year ended December 31, 2017.2018, primarily driven by:
contributions to unconsolidated investments in the amount of $473.9 million, primarily to fund our portion of the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018, as well as to fund our share of capital projects at Iron Horse and BNN Colorado;
Investing Activities.capital expenditures of $368.9 million, primarily due to spending on the Cheyenne Connector, a new 70-mile natural gas pipeline located in Colorado, additional water gathering infrastructure located in North Dakota, a 55-mile extension on the Pony Express system, construction of the Buckingham Terminal expansion, construction of the Guernsey, Natoma, and Grasslands Terminals, and pipe replacement and remediation work on the Trailblazer Pipeline system as discussed in Note 19 – Legal and Environmental Matters;
cash outflows of $95.0 million for the acquisition of a 100% membership interest in BNN North Dakota;
cash outflows of $91.0 million for the acquisition of a 100% membership interest in NGL Water Solutions Bakken;
cash outflows of $30.7 million for the initial capital contribution and formation of PLT;
cash outflows of $30.6 million for the acquisition of a 51% membership interest in Pawnee Terminal; and
cash outflows of $19.5 million for the acquisition of a 38% membership interest in Deeprock North.
These cash outflows were partially offset by cash inflows of:
$80.2 million of distributions received from unconsolidated affiliates in excess of cumulative earnings recognized, primarily Rockies Express; and
$50.0 million from the sale of TCG.
Cash flows used in investing activities were $898.5 million for the year ended December 31, 2017, primarily driven by:
cash outflows of $400.0 million for the acquisition of an additional 24.99% membership interest in Rockies Express;
capital expenditures of $145.1 million, primarily due to spending on an additional freshwater connection at Water Solutions, a connection to a refinery complex on the Pony Express System, a 55-mile extension on the Pony Express system,System, and remediation digs on the Pony Express System as discussed in Note 19 – Legal and Environmental Matters;
cash outflows of $140.0 million for the acquisition of Terminals and NatGas;
cash outflows of $128.5 million for the acquisition of the Douglas Gathering System;
cash outflows of $57.2 million for the acquisition of an additional 40% membership interest in Deeprock Development;
contributions to unconsolidated investments in the amount of $45.9 million, primarily to fund remaining costs associated with the Zone 3 Capacity Enhancement project at Rockies Express; and
cash outflows of $36.0 million for the acquisition of the PRB Crude System.
These cash outflows were partially offset by $69.4 million of distributions received from Rockies Express in excess of cumulative earnings recognized.
Financing Activities. Cash flows provided by financing activities were $321.7 million for the year ended December 31, 2018, primarily driven by:
proceeds of $500.0 million from the issuance of TEP's 2023 Notes; and
net borrowings under the revolving credit facilities of $417.0 million.
These financing cash inflows were partially offset by cash outflows of:
distributions to noncontrolling interests of $327.6 million, consisting of Tallgrass Equity distributions to the Exchange Right Holders of $223.7 million, distributions to TEP unitholders of $97.7 million, and distributions to Deeprock Development and Pony Express noncontrolling interests of $6.2 million;
dividends paid to Class A shareholders of $206.4 million; and
cash outflows of $50.0 million for the acquisition of an additional 2% membership interest in Pony Express.
Cash flows provided by financing activities were $327.3 million for the year ended December 31, 2017, primarily driven by:
proceeds from TEP's issuance of $1.1 billion in aggregate principal amount of 2024 and 2028 Notes; and
net cash proceeds of $112.4 million from the issuance of 2,341,061 TEP common units under its Equity Distribution Agreements.
These cash inflows were partially offset by cash outflows of:
net repayments under the revolving credit facilities of $356.0 million;
distributions to noncontrolling interests of $317.1 million, consisting of distributions to TEP unitholders of $185.7 million, Tallgrass Equity distributions to the Exchange Right Holders of $125.2 million, and distributions to Pony Express noncontrolling interests of $6.2 million;
dividends paid to Class A shareholders of $73.3 million;
$72.4 million for the exercise of the remainder of the call option granted by TD covering 1,703,094 TEP common units;
$35.3 million for the 736,262 TEP common units repurchased from TD; and
deferred financing costs of $22.4 million from the issuance of the 2024 and 2028 Notes and the amendment to TEP's revolving credit facility.
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Operating Activities. Cash flows provided by operating activities were $571.4 million and $413.3 million for the years ended December 31, 2017 and 2016, respectively. The increase in net cash flows provided by operating activities of $158.1 million was primarily driven by a $182.7 million increase in distributions received from Rockies Express as a result of the Ultra settlement received in July 2017 as well as our increased membership interest during the year ended December 31, 2017.
Investing Activities. Cash flows used in investing activities were $898.5 million for the year ended December 31, 2017. Investing cash outflows for the year ended December 31, 2017 were primarily driven by 2017 acquisitions, capital expenditures, and contributions to Rockies Express, as discussed above.
Cash flows used in investing activities were $595.5 million for the year ended December 31, 2016, primarily driven by:
cash outflows of $436.0 million for the acquisition of a 25% membership interest in Rockies Express;
capital expenditures of $84.5 million, primarily due to post in-service spending on Pony Express System projects, the Pipeline Integrity Management Program at Trailblazer, and costs associated with construction of the Buckingham Terminal;
contributions to unconsolidated investments in the amount of $50.1 million, primarily to fund costs associated with the Zone 3 Capacity Enhancement project at Rockies Express; and
cash outflows of $49.1 million for a portion of the acquisition of an additional 31.3% membership interest in Pony Express, the remainder of which is classified as a financing activity as discussed below; and
contributions to unconsolidated investments in the amount of $50.1 million, primarily to fund costs associated with the Zone 3 Capacity Enhancement project at Rockies Express.below.
These cash outflows were partially offset by $24.1 million of distributions received from Rockies Express in excess of cumulative earnings recognized.
Financing Activities.Cash flows provided by financing activities were $327.3 million for the year ended December 31, 2017, primarily driven by:
proceeds from TEP's issuance of $1.1 billion in aggregate principal amount of 2024 and 2028 Notes; and
net cash proceeds of $112.4 million from the issuance of 2,341,061 TEP common units under its Equity Distribution Agreements.
These financing cash inflows were partially offset by cash outflows of:
distributions to noncontrolling interests of $317.1 million, consisting of distributions to TEP unitholders of $185.7 million, Tallgrass Equity distributions to the Exchange Right Holders of $125.2 million, and distributions to Pony Express noncontrolling interests of $6.2 million;
net repayments under the revolving credit facilities of $356.0 million;
$72.4 million for the exercise of the remainder of the call option granted by TD covering 1,703,094 TEP common units;
$35.3 million for the 736,262 TEP common units repurchased from TD;
distributions to Class A shareholders of $73.3 million; and
deferred financing costs of $22.4 millionproceeds from the issuance of the 2024 and 2028 Notes and issuance of TEP common units, partially offset by net repayments under the amendment to TEP's revolving credit facility.facilities, distributions to noncontrolling interests, dividends paid to Class A shareholders, the partial exercise of the call option granted by TD, the repurchase of common units from TD, and payments for deferred financing costs, as discussed above.
Cash flows provided by financing activities were $182.5 million for the year ended December 31, 2016, primarily driven by:
•proceeds from TEP's issuance of $400.0 million in aggregate principal amount of 2024 Notes;
net cash proceeds of $337.7 million from the issuance of 7,696,708 TEP common units under its Equity Distribution Agreements;
•net borrowings under the TEP revolving credit facility of $262.0 million;
net cash proceeds of $90.0 million from TEP's issuance of 2,416,987 common units representing limited partnership interests in a private placement transaction; and
contributions from TD of $17.9 million, which consisted of contributions from TD to TEP in order to indemnify TEP for any out of pocket costs incurred between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, as discussed further in Note 19 – Legal and Environmental Matters.
These financing cash inflows were partially offset by cash outflows of:
$425.9 million for the portion of the acquisition of an additional 31.3% membership interest in Pony Express which exceeds the cumulative capital spending on the underlying assets acquired;
distributions to noncontrolling interests of $249.1 million, consisting of distributions to TEP unitholders of $145.1 million, Tallgrass Equity distributions to the Exchange Right Holders of $97.5 million, and distributions to Pony Express and Water Solutions noncontrolling interests of $6.5 million;
$204.6 million for TEP's partial exercise of the call option granted by TD covering 4,814,906 TEP common units; and
distributionsdividends paid to TEGPTGE Class A shareholders of $42.5 million.
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Operating Activities. Cash flows provided by operating activities were $413.3 million and $300.2 million for the years ended December 31, 2016 and 2015, respectively. The increase in net cash flows provided by operating activities of $113.1 million was primarily driven by the increase in operating results as discussed above, $51.8 million of distributions received from Rockies Express, and a net increase in cash inflows from changes in working capital, primarily driven by a $18.7 million increase in net cash inflows from accounts receivable due to collection of receivables during the year ended December 31, 2016 associated primarily with an increase in incremental barrels shipped at Pony Express, and a $13.2 million increase in deferred revenue associated primarily with deficiency payments collected by Pony Express during the year ended December 31, 2016.
Investing Activities. Cash flows used in investing activities were $595.5 million for the year ended December 31, 2016. Investing cash outflows for the year ended December 31, 2016 were primarily driven by 2016 acquisitions, capital expenditures, and contributions to Rockies Express, as discussed above.
Cash flows used in investing activities were $899.4 million for the year ended December 31, 2015, primarily driven by:
the cash outflow of $700.0 million for the acquisition of an additional 33.3% membership interest in Pony Express, which allowed TD to continue funding the pipeline construction at Pony Express;
capital expenditures of $120.7 million, primarily due to construction of the Pony Express System, including the lateral in Northeast Colorado, and costs associated with construction of the Sterling Terminal; and
the cash outflow of $75.0 million for the acquisition of Western.Dividends
Financing Activities. Cash flows provided by financing activities were $182.5 million for the year ended December 31, 2016, primarily driven by proceeds from the issuance of the 2024 Notes, issuance of TEP common units, net borrowings under the TEP revolving credit facility, and contributions from TD, partially offset by the portion of the TEP acquisition of the additional 31.3% membership interest in Pony Express which exceeds the cumulative capital spending on the underlying assets acquired, distributions to noncontrolling interests and Class A shareholders, and the partial exercise of the call option granted by TD as discussed above.
Cash flows provided by financing activities were $600.6 million for the year ended December 31, 2015, primarily driven by:
•$1.3 billion of net proceeds from the initial public offering of Class A shares in May 2015;
net cash proceeds of $554.1 million from the issuance of 11,200,000 TEP common units in a public offering and 65,744 TEP common units issued under the TEP Equity Distribution Agreements; and
•net borrowings under the revolving credit facilities of $342.0 million.
These financing cash inflows were partially offset by cash outflows of:
•$953.6 million for the acquisition of 20,000,000 TEP common units by Tallgrass Equity as part of the TEGP IPO;
$334.1 million for the distribution of proceeds from the TEGP IPO to the Exchange Right Holders as part of the reorganization of entities effective concurrent with the TEGP IPO;
$171.9 million for the acquisition of additional Tallgrass Equity units as part of the reorganization concurrent with the TEGP IPO; and
distributions to noncontrolling interests of $153.1 million, consisting on distributions to TEP unitholders of $99.1 million, Tallgrass Equity distributions to the Exchange Right Holders of $28.7 million, and distributions to Pony Express and Water Solutions noncontrolling interests of $25.3 million.
Distributions
DistributionsDividends to our Class A shareholders. We distribute 100% of ourTGE's available cash at the end of each quarter to Class A shareholders of record beginning with the quarter ended June 30, 2015. Our sole cash-generating asset is an approximate 31.43% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of direct and indirect partnership interests in TEP and its membership interest in Rockies Express, as detailed above in "—Overview". Available cash at TGE is generally defined in our partnership agreement as all our cash and cash equivalents on hand at the date of determination in respect of such quarter less reserves established in the discretion of our general partner for future requirements. For a discussion of factors and trends impacting TEP'sour business, which in turn impacts our ability to pay cash distributionsdividends to our Class A shareholders, please see "—Factors and Trends Impacting Our Business" above.
Our distributiondividend for the three months ended December 31, 2017,2018, in the amount of 0.3675$0.5200 per Class A share, or $21.3$81.3 million in the aggregate, was announced on January 8, 201815, 2019 and will be paid on February 14, 20182019 to Class A shareholders of record on January 31, 2018.2019.
Capital Requirements
The midstream energy business can be capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of, the following:
maintenance capital expenditures, which are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements; and
expansion capital expenditures, which are cash expenditures we expect will increase our operating income or operating capacity over the long-term. Expansion capital expenditures include acquisitions or capital improvements
(such (such as additions to or improvements on the capital assets owned, or acquisition or construction of new capital assets).
We expect to incur approximately $238 million for expansion capital projects and approximately $24 million for maintenance capital expenditures in 2018.
The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. We expect to incur approximately $270 million for expansion capital projects and approximately $40 million for maintenance capital expenditures in 2019. The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
| Maintenance capital expenditures | $ | 14,822 |
| | $ | 11,323 |
| | $ | 12,123 |
| $ | 20,956 |
| | $ | 14,822 |
| | $ | 11,323 |
|
| Expansion capital expenditures | 135,604 |
| | 44,348 |
| | 72,190 |
| 353,672 |
| | 135,604 |
| | 44,348 |
|
| Total capital expenditures incurred | $ | 150,426 |
| | $ | 55,671 |
| | $ | 84,313 |
| $ | 374,628 |
| | $ | 150,426 |
| | $ | 55,671 |
|
Capital expenditures incurred represent capital expenditures paid and accrued during the period. Capital expenditures are presented net of noncontrolling interest, and contributions and reimbursements received. The increase in maintenance capital expenditures to $21.0 million for the year ended December 31, 2018 from $14.8 million for the year ended December 31, 2017 from $11.3 million for the year ended December 31, 2016 is primarily driven by increased expenditures in the Crude Oil TransportationCorporate and Other and Gathering, Processing & Terminalling segments. Maintenance capital expenditures for the year ended December 31, 2018 in the Corporate and Other segment consisted primarily of spending on information technology assets as a result of our acquisition of these assets from TD in February 2018 as discussed in Note 3 – Acquisitions and Dispositions. Maintenance capital expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital expenditures naturally varies from year to year and from quarter to quarter. The increase in expansionExpansion capital expenditures were $353.7 million for the year ended December 31, 2018 compared to $135.6 million for the year ended December 31, 2017 from $44.3 million2017. Expansion capital expenditures for the year ended December 31, 2016 is2018 consisted primarily driven by increasedof spending on the Cheyenne Connector, additional water gathering infrastructure located in North Dakota, PLT, a 55-mile extension on the Pony Express system, construction of the Buckingham Terminal expansion, capital expendituresconstruction of the Guernsey, Natoma, and Grasslands Terminals, and pipe replacement and remediation work on the Trailblazer Pipeline system as discussed in the Gathering, Processing & TerminallingNote 19 – Legal and Crude Oil Transportation segments.Environmental Matters. Expansion capital expenditures for the year ended December 31, 2017 consisted primarily of spending on an additional freshwater connection at Water Solutions, construction of the Grasslands Terminal and the Natoma Terminal, a connection to a third-party refinery complex on the Pony Express System, and a 55-mile extension on the Pony Express system.System.
The increase in maintenance capital expenditures to $14.8 million for the year ended December 31, 2017 from $11.3 million for the year ended December 31, 2016 is primarily driven by increased expenditures in the Crude Oil Transportation and Gathering, Processing & Terminalling segments. Expansion capital expenditures ofwere $135.6 million for the year ended December 31, 2017 compared to $44.3 million for the year ended December 31, 2016. Expansion capital expenditures for
the year ended December 31, 2017 consisted primarily of spending at Water Solutions, the Grasslands Terminal and the Natoma Terminal, and the Pony Express system, as discussed above. Expansion capital expenditures for the year ended December 31, 2016 consisted primarily of post in-service spending on Pony Express System projects and costs associated with construction of the Buckingham Terminal.
The decrease in maintenance capital expenditures to $11.3 million forDuring the yearyears ended December 31, 2018, 2017, and 2016, from $12.1 million for the year ended December 31, 2015 is primarily driven by decreased maintenance capital expenditures in the Gathering, Processing & Terminalling segment. The decrease in expansion capital expenditures to $44.3 million for the year ended December 31, 2016 from $72.2 million for the year ended December 31, 2015 is primarily driven by decreased expansion capital expenditures in the Gathering, Processing & Terminalling segment. Expansion capital expenditures of $44.3 million for the year ended December 31, 2016 consisted primarily of post in-service spending on Pony Express System projects and costs associated with construction of the Buckingham Terminal. Expansion capital expenditures of $72.2 million for the year ended December 31, 2015 consisted primarily of costs associated with construction of the Sterling Terminal and spending on the NGL pipeline in Northeast Colorado. During the year ended December 31, 2015, substantially all the expansion capital expenditures related to Pony Express System projects were funded by TD.
During the year ended December 31, 2017, TEP acquired a new unconsolidated affiliate, BNN Colorado Water, LLC ("BNN Colorado") for approximately $7.0 million. In connection with the investment in BNN Colorado, TEP made commitments to fund the remaining construction of the pipeline system, estimated at $3.8 million as of December 31, 2017. In addition, TEPwe invested cash in unconsolidated affiliates, including Rockies Express, Iron Horse, and BNN Colorado and Deeprock Development,prior to our consolidation of BNN Colorado in December 2018, of $473.9 million, $45.9 million, and $50.1 million, and $0.4 million during the years ended December 31, 2017, 2016, and 2015, respectively, to fund itsour share of capital projects. TEP has also committedprojects, including (i) a special contribution of approximately $412.5 million to Rockies Express to fund our portion of the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018 and (ii) an initial contribution of $3.5 million to Iron Horse, a newly formed unconsolidated affiliate in proportion to its 49.99%February 2018. In connection with our 51% membership interest which it intendsin Powder River Gateway effective January 1, 2019, we made commitments to fund through borrowings under TEP's revolving credit facility.our proportionate share of the remaining cost to construct the Iron Horse pipeline, estimated at $25.4 million.
We intend to make cash distributionspay dividends to our Class A shareholders. Due to our cash distribution policy, we expect that we will distribute available cash to our Class A shareholders on a quarterly basis. We expect TEP to fund future capital expenditures with funds generated from its operations, borrowings under itsour revolving credit facility, the issuance of additional partnership units and/or the issuance of equity or long-term debt. If these sources are not sufficient, TEPwe may reduce itsour discretionary spending.
Contractual Obligations
Following is a summary of our contractual cash obligations in future periods, representing amounts that were fixed and determinable as of December 31, 2017:2018:
| | | | | Payments Due By Period | | Payments Due By Period |
| Contractual Obligations | | Total | | Less Than 1 Year | | 1-3 Years | | 3-5 Years | | More Than 5 Years | | Total | | Less Than 1 Year | | 1-3 Years | | 3-5 Years | | More Than 5 Years |
| | | (in thousands) | | (in thousands) |
Debt obligations (1) | | $ | 2,307,000 |
| | $ | — |
| | $ | 146,000 |
| | $ | 661,000 |
| | $ | 1,500,000 |
| | $ | 3,224,000 |
| | $ | — |
| | $ | — |
| | $ | 1,724,000 |
| | $ | 1,500,000 |
|
Interest on debt obligations (2) | | 816,565 |
| | 113,798 |
| | 223,698 |
| | 200,631 |
| | 278,438 |
| | 900,065 |
| | 158,624 |
| | 317,391 |
| | 228,342 |
| | 195,708 |
|
Operating lease and service contract obligations (3) | | 2,383 |
| | 506 |
| | 945 |
| | 464 |
| | 468 |
| | 3,230 |
| | 1,074 |
| | 1,405 |
| | 387 |
| | 364 |
|
Land site lease and right-of-way (4) | | 7,923 |
| | 720 |
| | 1,820 |
| | 1,457 |
| | 3,926 |
| |
Other purchase commitments (5) | | 23,594 |
| | 19,345 |
| | 4,161 |
| | 40 |
| | 48 |
| |
Capital lease obligations (4) | | | 20,015 |
| | 449 |
| | 898 |
| | 898 |
| | 17,770 |
|
Land site lease and right-of-way (5) | | | 6,029 |
| | 744 |
| | 1,408 |
| | 1,088 |
| | 2,789 |
|
Other purchase commitments (6) | | | 95,422 |
| | 53,098 |
| | 17,875 |
| | 11,218 |
| | 13,231 |
|
| Total | | $ | 3,157,465 |
| | $ | 134,369 |
| | $ | 376,624 |
| | $ | 863,592 |
| | $ | 1,782,880 |
| | $ | 4,248,761 |
| | $ | 213,989 |
| | $ | 338,977 |
| | $ | 1,965,933 |
| | $ | 1,729,862 |
|
| |
(1) | Debt obligations at December 31, 20172018 consisted of borrowings under the TEP and Tallgrass Equity revolving credit facilitiesfacility and the 2024 and 2028Senior Notes. For additional information, see Note 1110 – Long-term Debt. |
| |
(2) | Interest on debt obligations is estimated using current borrowings and interest rates as of December 31, 2017.2018. For additional information, see Note 1110 – Long-term Debt. |
| |
(3) | Operating leases and service contracts consist of leases for office space and equipment. For additional information, see Note 13 – Commitments & Contingent Liabilities. |
| |
(4) | Capital lease obligations consist of the PLT land site lease. For additional information, seeNote 13 – Commitments & Contingent Liabilities. |
| |
(5) | Land site lease and right-of-way contracts consist of payments to landowners, primarily in our Crude Oil Transportation and Natural Gas Transportation segments. For additional information, see Note 13 – Commitments & Contingent Liabilities. |
| |
(5)(6)
| Other purchase commitments primarily relate to planned non-reimbursable capital expenditures and operating and maintenance expenditures. |
On May 17, 2013, inAll of our employees are employed by Tallgrass Management, LLC ("Tallgrass Management"). Prior to July 1, 2018, Tallgrass Management was a wholly-owned subsidiary of Tallgrass Energy Holdings. In connection with the closing of TEP's IPO,the TEP initial public offering on May 17, 2013, TEP and its general partnerTEP GP entered into thean Omnibus Agreement with Tallgrass Energy Holdings and certain of its affiliates (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement which provides that, among other things, TEP will reimburse Tallgrass Energy Holdings and its affiliates for all expenses they incur and payments they make on TEP's
behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain centralized corporate functions performed by Tallgrass Energy Holdings and its affiliates, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP. In addition, in connection with the closing of the TEGP IPO, TEGPTGE initial public offering on May 12, 2015 (the "TGE IPO"), TGE entered into the TEGPan Omnibus Agreement (the "TGE Omnibus Agreement") with Tallgrass Energy GP, LLC (formerly known as TEGP Management, LLC,LLC), Tallgrass Equity and Tallgrass Energy Holdings (which acts as the general partner of TD). PursuantHoldings. Effective July 1, 2018, Tallgrass Management was contributed to the TEGP Omnibus Agreement, Tallgrass Equity paysin connection with the TEP Merger. As a quarterly reimbursement toresult, the costs of employer and director compensation and benefits are now incurred directly by Tallgrass Energy Holdings for costs associated with TEGP being a public company.Equity.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Critical Accounting Policies and Estimates
Our significant accounting policies and the anticipated impact of recently issued accounting standards are described in Note 2 – Summary of Significant Accounting Policies. Management's discussion and analysis of financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. The accounting policies discussed below are considered by management to be critical to an understanding of our financial statements as their application places the most significant demands on management's judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on our results of operations, equity or cash flows. For additional information concerning our other accounting policies, please read the notes to the financial statements included in this report.
|
| | | | |
| Description | | Judgments and Uncertainties | | Effect if Actual Results Differ from Assumptions |
| Business Combinations |
| We allocate the cost of each acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. If the initial accounting for the business combination is incomplete when the combination occurs, an estimate will be recorded. We are required to recognize intangible assets separately from goodwill. Any excess purchase price after the fair value of the net tangible and identifiable intangible assets acquired, as well as noncontrolling interest, if applicable, is determined is recognized as goodwill. | | We measure the fair value of assets acquired and liabilities assumed in business combinations using widely accepted valuation techniques, primarily discounted cash flow, cost approach, and market multiple analyses. These types of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. These analyses require management to apply significant judgment in estimating future cash flows as well as fair values of individual assets, including forecasting useful lives of the assets, assessing the probability of different outcomes, including anticipated volumes, contract renewals and changes in our regulated rates, and selecting the discount rate that reflects the risk inherent in future cash flows. | | If estimates or assumptions used to complete the purchase price allocation and estimate the fair value of acquired assets, liabilities and noncontrolling interests significantly differed from assumptions made, the allocation of purchase price between goodwill, intangibles, noncontrolling interests, equity method investments and property, plant, and equipment could significantly differ. Such a difference would impact future earnings through depreciation and amortization expense. In addition, if forecasts supporting the valuation of the intangible assets or goodwill are not achieved, impairments could arise. Further, if customer relationships terminate prior to the expected useful life, we will be required to record a charge to operations to write-off any remaining unamortized balance of the intangible asset assigned to that customer. |
|
| | | | |
| Description | | Judgments and Uncertainties | | Effect if Actual Results Differ from Assumptions |
| Impairment of Long-lived Assets |
| We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections expected to be realized over the remaining useful life of the primary asset. The carrying amount is not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset's carrying value over its fair value. | | We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Our impairment analyses require management to apply judgment in estimating future cash flows as well as asset fair values, including forecasting useful lives of the assets, assessing the probability of different outcomes, including anticipated volumes, contract renewals and changes in our regulated rates, and selecting the discount rate that reflects the risk inherent in future cash flows. If the carrying value is not recoverable, we assess the fair value of long-lived assets using a discounted cash flow model and other commonly accepted techniques.
| | Using the impairment review methodology described herein, we have not recorded any impairment charges on long-lived assets during the year ended December 31, 2017.2018. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge. A prolonged period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.
|
|
| | | | |
Description | | Judgments and Uncertainties | | Effect if Actual Results Differ from Assumptions |
| Impairment of Goodwill |
| We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. | | We use either the qualitative assessment option or proceed directly to the quantitative impairment test depending on facts and circumstances of the reporting unit, including the forecasted useful lives of the assets, the probability of different outcomes, including anticipated volumes, contract renewals and changes in our regulated rates, and the discount rate that reflects the risk inherent in future cash flows. When quantitative assessments are made, we determine fair value using widely accepted valuation techniques, primarily discounted cash flow and market multiple analyses. These techniques are also used when assigning the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. Our impairment analyses require management to apply judgment in estimating future cash flowsflows. We incorporate current market information, as well as asset fair values, including forecasting useful lives of the assets, assessing the probability of different outcomes, including anticipated volumes, contract renewalshistorical and changes inother factors, into our regulated rates, and selecting the discount rate that reflects the risk inherent in future cash flows. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations. | | We primarily use a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment.forecasted commodity prices. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows, including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporateIt is our policy to conduct impairment testing based on our current market information,business strategy in light of present industry and economic conditions, as well as historical and other factors, into our forecasted commodity prices. future expectations. | | If our assumptions are not appropriate, or future events indicate that our goodwill is impaired, our net income would be impacted by the amount by which the carrying value exceeds the fair value of the reporting unit, to the extent of the balance of goodwill. A prolonged period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future goodwill impairment for reporting units due to the potential impact on our operations and cash flows. We completed our impairment testing of goodwill in the third quarter of 20172018 using the methodology described herein, and determined there was no impairment. |
Risk Management Activities |
Derivative assets and liabilities are recorded on our consolidated balance sheets at their estimated fair value as of each reporting date. Changes in the fair value of derivative contracts are recognized in earnings in the period in which the change occurs. | | | | |
| Description | | When available, quoted market prices or prices obtained through external sources are usedJudgments and Uncertainties | | Effect if Actual Results Differ from Assumptions |
| Revenue Recognition |
| The majority of our revenue is derived from long-term contracts that can span several years. Accounting for long-term contracts involves the use of various techniques to estimate total contract revenue and determine the timing of revenue recognition. We periodically evaluate our estimates with respect to the probability of our customers exercising their rights and recognize revenue associated with contract liabilities when the probability becomes remote that the customer will exercise its remaining rights. | | We review our deferred revenue (contract liabilities) at each balance sheet date to determine a contract's fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical informationthe probability that our customers will exercise their remaining rights. We recognize revenue when the probability becomes remote that the customer will exercise its remaining rights. Our evaluation requires management to apply judgment in contract renewal assumptions and estimating future system capacity and the expected relationship with quoted market prices.ability of our customers to utilize that capacity. | | If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, the timing of fair value are inaccurate,our revenue recognition with respect to deferred revenue could be impacted and we may be exposed to losses or gains that could be material. See Item 7A.—Quantitative and Qualitative Disclosures About Market Risk for details regarding the impact of potentialexperience material changes in the commodity forward price curves on our derivative instruments at December 31, 2017. |
Income Taxes | | | | |
Current income tax expense is the amount of income taxes expected to be payable for the current year. A deferred income tax liability or asset is established for the expected future tax consequences resulting from the differences in the financial reporting and tax basis of the assets and liabilities. Each quarter we evaluate the reasonableness of the deferred tax assets and a valuation allowance is provided if it is more likely than not that some or all of the deferred tax assets will not be realized.
| | Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, which will result in taxable or deductible amounts in the future. In evaluating our ability to recover our deferred tax assets we consider all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. In projecting future taxable income, we begin with historical results adjusted for the results of discontinued operations and incorporate assumptions about the amount of future state and federal pretax operating income adjusted for items that do not have tax consequences. The assumptions about future taxable income require the use of significant judgment and are consistent with the plans and estimates we are using to manage the underlying businesses. | | If our valuation allowance does not appropriately adjust our deferred tax assets to reflect the actual future tax benefits or consequences from the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements: our balance sheet may be overstated or understated resulting in an overstated or understated Income Tax Expense on the Income Statement resulting in either understated or overstated Net Income after Income Tax.revenue. |
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Prior to our acquisition of the Douglas Gathering System on June 5, 2017, approximately 99% of our reserved natural gas processing capacity was subject to firm or volumetric fee contracts, with the majority of fee revenue based on the volumes actually processed. With our acquisition of the Douglas Gathering System, the largest existing firm fee contract was terminated because the counterparty to this contract, DCP Douglas, LLC, became our indirect wholly-owned subsidiary. In addition, we acquired a number of commodity sensitive gathering and processing contracts such as percent of proceeds or keep whole processing contracts in the acquisition. DuringFor the year ended December 31, 2017, approximately 17%, 53%, and 30%2018, the percentage of TMID's operating income came fromour firm fee, volumetric fee, and commodity sensitive contracts,exposed Adjusted EBITDA was 90%, 6%, and 4%, respectively. The profitability of our commodity sensitive processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices.
Historically, we have had a limited amount of direct commodity price exposure related to natural gas collected for electrical compression costs and lost and unaccounted for gas on theat TIGT, System. Accordingly, we have historically entered into derivative contracts with third parties for a substantial majority of the natural gas we expected to collect for the purpose of hedging our commodity price exposures. In 2016, we also entered into long natural gas swaps covering a portion of the natural gas thatused at TMID expected to purchase in 2017. In addition, we have a limited amount of direct commodity price exposure related toand crude oil collected as part of our contractual pipeline loss allowance at Pony Express and Terminals. During 2016,Accordingly, we began enteringhave historically entered into derivative contracts with third parties for all or a portion of these volumes for the salepurpose of crude oil inventory. During 2017,hedging our commodity price exposures. In addition, Stanchion began to transacttransacts in crude oil and enterenters into physical and financial derivative contracts in connection with these, and other, transactions.
We measure the risk of price changes in our crude oil and natural gas derivatives utilizing a sensitivity analysis model. The sensitivity analysis measures the potential income or loss (i.e., the change in fair value of the derivative instruments) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. We enter into derivative contracts primarily for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, both the sensitivity analysis model and the change in the market value of our outstanding derivative contracts are offset largely by changes in the value of the underlying physical commodity prices.
The following table summarizes our commodity derivatives and the change in fair value that would be expected from a 10% price increase or decrease as of December 31, 2017,2018, assuming a parallel shift in the forward curve through the end of 2017:curve:
|
| | | | | | | | | | | |
| | Fair Value | | Effect of 10% Price Increase | | Effect of 10% Price Decrease |
| | (in thousands) |
Crude oil derivative contracts (1) | $ | (2,368 | ) | | $ | (2,151 | ) | | $ | 2,151 |
|
|
| | | | | | | | | | | |
| | Fair Value | | Effect of 10% Price Increase | | Effect of 10% Price Decrease |
| | (in thousands) |
Crude oil derivative contract assets (1) | $ | 3,526 |
| | $ | (1,221 | ) | | $ | 1,221 |
|
Crude oil derivative contract liabilities (1) | $ | (1,642 | ) | | $ | (424 | ) | | $ | 424 |
|
| |
(1) | Represents the net forward sale of 356,000362,000 barrels of crude oil byin our Gathering, Processing & Terminalling segment which will settle throughout the first quarter of 2018.2019. |
Interest Rate Risk
As described in Note 1110 – Long-term Debt, on July 26, 2018, in connection with the Amendment to TEP's Credit Agreement, Tallgrass Equity currently has $146.0 million inrepaid all outstanding borrowings underand terminated its revolving credit facility. Borrowings under the credit facility bear interest, at Tallgrass Equity's option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin is 1.50%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin is 2.50%.
As of December 31, 2017,2018, TEP has issued $750 million$2.0 billion of 2024Senior Notes and $750 million of 2028 Notes. In addition, TEP currently has a $1.75$2.25 billion revolving credit facility with borrowings of $661.0 million.$1.22 billion. Borrowings under theTEP's revolving credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. The applicable margin ranges from 0.50%0.25% to 1.50%1.25% for base rate borrowings (previously 0.50% to 1.50% prior to the Amendment) and 1.50%1.25% to 2.50%2.25% for reserve adjusted Eurodollar rate borrowings (previously 1.50% to 2.50% prior to the Amendment), based upon ourTEP's total leverage ratio.
We do not currently hedge the interest rate risk on our borrowings under theTEP's revolving credit facilities.facility. However, in the future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the
fair value of the debt by $0.5$0.6 million based on our outstanding debt under ourTEP's revolving credit facilitiesfacility as of December 31, 2017.2018.
Credit Risk
We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We manage our exposure to credit risk associated with customers to whom we extend credit through a credit approval process which includes credit analysis, the establishment of credit limits and ongoing monitoring procedures. We may request letters of credit, cash collateral, prepayments or guarantees as forms of credit support.
A substantial majority of our revenue is produced under long-term firm fee contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with a majority of our revenues derived from customers who have BB+BBB- or Ba1Baa3 and better credit ratings or are part of corporate families with such credit ratings as of December 31, 2017.2018.
We also have indirect credit risk exposure with respect to our investment in Rockies Express. See Item 1A.—Risk Factors for additional information.
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Board of Directors of TEGP Management,Tallgrass Energy GP, LLC, the general partner of Tallgrass Energy, GP, LP, and the shareholders of Tallgrass Energy, GP, LP
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Tallgrass Energy, GP, LP and its subsidiaries (the "Partnership")as of December 31, 20172018 and 2016,2017, and the related consolidated statements of income, equity and cash flows for each of the three years in the period ended December 31, 2017,2018, including the related notes (collectively referred to as the “consolidated"consolidated financial statements”statements"). We also have audited the Partnership's internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 20172018 and 20162017,, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20172018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Change in Accounting Principle
As discussed in Note 2 and 12 to the consolidated financial statements, Rockies Express Pipeline LLC, an investment of the Partnership accounted for under the equity method, changed the manner in which it accounts for revenue in 2018.
Basis for Opinions
The Partnership's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’sManagement's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Partnership’sPartnership's consolidated financial statements and on the Partnership's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Report on Internal Control over Financial Reporting,management has excluded Terminals, the Douglas Gathering System, and Deeprock Development from its assessment of internal control over financial reporting as of December 31, 2017 because they were acquired by the Partnership during 2017. We have also excluded Terminals, the Douglas Gathering System, and Deeprock Development from our audit of internal control over financial reporting. Terminals and the Douglas Gathering System are wholly-owned subsidiaries and Deeprock Development is a 69% owned consolidated subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent 10% and 5%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2017.
Definition and Limitations of Internal Control over Financial Reporting
A company’scompany's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’scompany's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’scompany's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 13, 2018
8, 2019
We have served as the Partnership’sPartnership's auditor since 2015.
TALLGRASS ENERGY, GP, LP
CONSOLIDATED BALANCE SHEETS
| | | | December 31, 2017 | | December 31, 2016 | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
| ASSETS | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | 2,593 |
| | $ | 2,459 |
| $ | 9,596 |
| | $ | 2,593 |
|
| Accounts receivable, net | 119,955 |
| | 59,536 |
| 236,097 |
| | 119,955 |
|
| Gas imbalances | 1,990 |
| | 1,597 |
| |
| Inventories | 21,609 |
| | 13,093 |
| 34,316 |
| | 21,609 |
|
| Derivative assets | — |
| | 10,967 |
| |
| Prepayments and other current assets | 11,175 |
| | 7,628 |
| 11,816 |
| | 13,165 |
|
| Total Current Assets | 157,322 |
| | 95,280 |
| 291,825 |
| | 157,322 |
|
| Property, plant and equipment, net | 2,394,337 |
| | 2,079,232 |
| 2,802,429 |
| | 2,394,337 |
|
| Goodwill | 404,838 |
| | 343,288 |
| 421,983 |
| | 404,838 |
|
| Intangible assets, net | 97,731 |
| | 93,522 |
| 227,103 |
| | 97,731 |
|
| Unconsolidated investments | 909,531 |
| | 475,625 |
| 1,861,686 |
| | 909,531 |
|
| Deferred financing costs, net | 12,563 |
| | 6,042 |
| 10,990 |
| | 12,563 |
|
| Deferred tax asset | 312,997 |
| | 521,454 |
| 273,531 |
| | 312,997 |
|
| Deferred charges and other assets | 2,694 |
| | 11,037 |
| 3,962 |
| | 2,694 |
|
| Total Assets | $ | 4,292,013 |
| | $ | 3,625,480 |
| $ | 5,893,509 |
| | $ | 4,292,013 |
|
| LIABILITIES AND EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Accounts payable | $ | 98,882 |
| | $ | 24,449 |
| $ | 201,512 |
| | $ | 104,224 |
|
| Accounts payable to related parties | 5,342 |
| | 5,824 |
| |
| Gas imbalances | 1,663 |
| | 1,239 |
| |
| Derivative liabilities | 2,368 |
| | 556 |
| |
| Accrued taxes | 19,272 |
| | 16,996 |
| 20,734 |
| | 19,272 |
|
| Accrued interest | | 39,217 |
| | 25,167 |
|
| Accrued liabilities | 35,707 |
| | 16,755 |
| 23,287 |
| | 10,540 |
|
| Deferred revenue | 88,471 |
| | 60,757 |
| 111,095 |
| | 88,471 |
|
| Other current liabilities | 7,171 |
| | 6,446 |
| 42,910 |
| | 11,202 |
|
| Total Current Liabilities | 258,876 |
| | 133,022 |
| 438,755 |
| | 258,876 |
|
| Long-term debt, net | 2,292,993 |
| | 1,555,981 |
| 3,205,958 |
| | 2,292,993 |
|
| Other long-term liabilities and deferred credits | 18,965 |
| | 7,063 |
| 31,688 |
| | 18,965 |
|
| Total Long-term Liabilities | 2,311,958 |
| | 1,563,044 |
| 3,237,646 |
| | 2,311,958 |
|
| Commitments and Contingencies |
| |
|
| |
|
| Equity: | | | | | | |
| Predecessor Equity | — |
| | 82,295 |
| |
| Class A Shareholders (58,085,002 and 58,075,000 shares outstanding at December 31, 2017 and 2016, respectively) | 48,613 |
| | 250,967 |
| |
| Class B Shareholders (99,154,440 shares outstanding at December 31, 2017 and 2016) | — |
| | — |
| |
| Class A Shareholders (156,311,986 and 58,085,002 shares outstanding at December 31, 2018 and 2017, respectively) | | 1,725,537 |
| | 48,613 |
|
| Class B Shareholders (123,887,893 and 99,154,440 shares outstanding at December 31, 2018 and 2017, respectively) | | — |
| | — |
|
| Total Partners' Equity | 48,613 |
| | 333,262 |
| 1,725,537 |
| | 48,613 |
|
| Noncontrolling interests | 1,672,566 |
| | 1,596,152 |
| |
Noncontrolling interests (a) | | 491,571 |
| | 1,672,566 |
|
| Total Equity | 1,721,179 |
| | 1,929,414 |
| 2,217,108 |
| | 1,721,179 |
|
| Total Liabilities and Equity | $ | 4,292,013 |
| | $ | 3,625,480 |
| $ | 5,893,509 |
| | $ | 4,292,013 |
|
| |
(a) | See Note 11 - Partnership Equityfor a complete description of our noncontrolling interests. |
TALLGRASS ENERGY, GP, LP
CONSOLIDATED STATEMENTS OF INCOME
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands, except per unit amounts) | (in thousands, except per unit amounts) |
| Revenues: | | | | | | | | | | |
| Crude oil transportation services | $ | 345,733 |
| | $ | 374,949 |
| | $ | 300,436 |
| $ | 398,334 |
| | $ | 345,733 |
| | $ | 374,949 |
|
| Natural gas transportation services | 122,364 |
| | 119,962 |
| | 119,895 |
| 126,894 |
| | 122,364 |
| | 119,962 |
|
| Sales of natural gas, NGLs, and crude oil | 108,503 |
| | 77,123 |
| | 82,133 |
| 168,586 |
| | 108,503 |
| | 77,123 |
|
| Processing and other revenues | 79,298 |
| | 39,628 |
| | 40,197 |
| 99,445 |
| | 79,298 |
| | 39,628 |
|
| Total Revenues | 655,898 |
| | 611,662 |
| | 542,661 |
| 793,259 |
| | 655,898 |
| | 611,662 |
|
| Operating Costs and Expenses: | | | | | | | | | | |
| Cost of sales | 91,213 |
| | 71,650 |
| | 75,285 |
| 114,815 |
| | 91,213 |
| | 71,650 |
|
| Cost of transportation services | 46,200 |
| | 47,669 |
| | 46,840 |
| 53,068 |
| | 46,200 |
| | 47,669 |
|
| Operations and maintenance | 62,069 |
| | 55,070 |
| | 50,823 |
| 72,460 |
| | 62,069 |
| | 55,070 |
|
| Depreciation and amortization | 90,800 |
| | 86,247 |
| | 84,258 |
| 110,862 |
| | 90,800 |
| | 86,247 |
|
| General and administrative | 65,536 |
| | 57,298 |
| | 52,635 |
| 70,656 |
| | 65,536 |
| | 57,298 |
|
| Taxes, other than income taxes | 28,832 |
| | 25,400 |
| | 21,796 |
| 31,810 |
| | 28,832 |
| | 25,400 |
|
| Contract termination | — |
| | 8,061 |
| | — |
| — |
| | — |
| | 8,061 |
|
| (Gain) loss on disposal of assets | (599 | ) | | 1,849 |
| | 4,795 |
| (11,043 | ) | | (599 | ) | | 1,849 |
|
| Total Operating Costs and Expenses | 384,051 |
| | 353,244 |
| | 336,432 |
| 442,628 |
| | 384,051 |
| | 353,244 |
|
| Operating Income | 271,847 |
| | 258,418 |
| | 206,229 |
| 350,631 |
| | 271,847 |
| | 258,418 |
|
| Other Income (Expense): | | | | | | | | | | |
| Equity in earnings of unconsolidated investments | | 306,819 |
| | 237,110 |
| | 54,531 |
|
| Interest expense, net | (89,348 | ) | | (45,601 | ) | | (18,330 | ) | (133,319 | ) | | (89,348 | ) | | (45,601 | ) |
| Unrealized gain (loss) on derivative instrument | 1,885 |
| | (1,291 | ) | | — |
| |
| Equity in earnings of unconsolidated investments | 237,110 |
| | 54,531 |
| | 2,759 |
| |
| Gain on remeasurement of unconsolidated investment | 9,728 |
| | — |
| | — |
| — |
| | 9,728 |
| | — |
|
| Other income, net | 1,221 |
| | 1,723 |
| | 2,413 |
| |
| Other (expense) income, net | | (751 | ) | | 3,106 |
| | 432 |
|
| Total Other Income (Expense) | 160,596 |
| | 9,362 |
| | (13,158 | ) | 172,749 |
| | 160,596 |
| | 9,362 |
|
| Net income before tax | 432,443 |
| | 267,780 |
|
| 193,071 |
| 523,380 |
| | 432,443 |
|
| 267,780 |
|
| Deferred income tax (expense) benefit | (208,458 | ) | | (17,741 | ) | | 7,277 |
| |
| Deferred income tax expense | | (55,709 | ) | | (208,458 | ) | | (17,741 | ) |
| Net income | 223,985 |
| | 250,039 |
| | 200,348 |
| 467,671 |
| | 223,985 |
| | 250,039 |
|
| Net income attributable to noncontrolling interests | (352,714 | ) | | (216,250 | ) | | (156,035 | ) | (330,544 | ) | | (352,714 | ) | | (216,250 | ) |
| Net (loss) income attributable to TEGP | $ | (128,729 | ) | | $ | 33,789 |
| | $ | 44,313 |
| |
| Net income (loss) attributable to TGE | | $ | 137,127 |
| | $ | (128,729 | ) | | $ | 33,789 |
|
| Allocation of income: | | | | | | | | | | |
| Net (loss) income attributable to TEGP | $ | (128,729 | ) | | $ | 33,789 |
| | $ | 44,313 |
| |
| Net income (loss) attributable to TGE | | $ | 137,127 |
| | $ | (128,729 | ) | | $ | 33,789 |
|
| Predecessor operations interest in net income | — |
| | (6,995 | ) | | (12,357 | ) | — |
| | — |
| | (6,995 | ) |
| Net (loss) income attributable to TEGP, excluding predecessor operations interest | (128,729 | ) | | 26,794 |
| | 31,956 |
| |
| Net income attributable to TEGP prior to May 12, 2015 | — |
| | — |
| | (7,393 | ) | |
| Net (loss) income attributable to TEGP subsequent to May 12, 2015 | (128,729 | ) | | 26,794 |
| | 24,563 |
| |
| Basic net (loss) income per Class A share | $ | (2.22 | ) | | $ | 0.55 |
| | $ | 0.51 |
| |
| Diluted net (loss) income per Class A share | $ | (2.22 | ) | | $ | 0.55 |
| | $ | 0.51 |
| |
| Net income (loss) attributable to TGE, excluding predecessor operations interest | | 137,127 |
| | (128,729 | ) | | 26,794 |
|
| Basic net income (loss) per Class A share | | $ | 1.27 |
| | $ | (2.22 | ) | | $ | 0.55 |
|
| Diluted net income (loss) per Class A share | | $ | 1.27 |
| | $ | (2.22 | ) | | $ | 0.55 |
|
| Basic average number of Class A shares outstanding | 58,076 |
| | 48,856 |
| | 47,725 |
| 107,586 |
| | 58,076 |
| | 48,856 |
|
| Diluted average number of Class A shares outstanding | 58,076 |
| | 48,889 |
| | 47,808 |
| 109,817 |
| | 58,076 |
| | 48,889 |
|
TALLGRASS ENERGY, GP, LP
CONSOLIDATED STATEMENTS OF EQUITY
| | | | TEGP Predecessor Equity | | Predecessor Equity | | Partners' Capital | | Noncontrolling Interests | | Total Equity | Predecessor Equity | | Partners' Capital | | Noncontrolling Interests | | Total Equity |
| | | Class A Shares | | Class B Shares | | | Class A Shares | | Class B Shares | |
| | | Shares | | Amount | | Shares | | Amount | | | Shares | | Amount | | Shares | | Amount | |
| | (in thousands) | (in thousands) |
| Balance at January 1, 2015 | $ | 146,866 |
| | $ | 19,402 |
| | — |
| | $ | — |
| | — |
| | $ | — |
| | $ | 1,648,285 |
| | $ | 1,814,553 |
| |
| Net income for the period from January 1, 2015 to May 11, 2015 | 7,393 |
| | 2,235 |
| | — |
| | — |
| | — |
| | — |
| | 32,196 |
| | 41,824 |
| |
| Net income for the period from May 12, 2015 to December 31, 2015 | — |
| | 10,122 |
| | — |
| | 24,563 |
| | — |
| | — |
| | 123,839 |
| | 158,524 |
| |
| Issuance of TEP units to public, net of offering costs | 63,464 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 487,653 |
| | 551,117 |
| |
| Acquisition of additional 33.3% membership interest in Pony Express | (98,446 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (601,554 | ) | | (700,000 | ) | |
| Distributions to TEGP Predecessor | (4,108 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (9,425 | ) | | (13,533 | ) | |
| Issuance of Class A shares to the public, net of offering costs | — |
| | — |
| | 47,725 |
| | 1,314,738 |
| | — |
| | — |
| | — |
| | 1,314,738 |
| |
| Issuance of Class B shares to the Exchange Right Holders | — |
| | — |
| | — |
| | — |
| | 109,504 |
| | — |
| | — |
| | — |
| |
| Acquisition of Acquired TEP Units from TD | — |
| | — |
| | — |
| | (953,600 | ) | | — |
| | — |
| | — |
| | (953,600 | ) | |
| Distribution of excess TEGP IPO proceeds to Exchange Right Holders | — |
| | — |
| | — |
| | (334,068 | ) | | — |
| | — |
| | — |
| | (334,068 | ) | |
| Acquisition of Tallgrass Equity units from Exchange Right Holders | — |
| | — |
| | — |
| | (171,948 | ) | | — |
| | — |
| | — |
| | (171,948 | ) | |
| Consolidation of TEGP Predecessor Assets | (115,169 | ) | | — |
| | — |
| | 115,169 |
| | — |
| | — |
| | — |
| | — |
| |
| Contributions from Predecessor Entities, net | — |
| | 39,805 |
| | — |
| | | | — |
| | — |
| | — |
| | 39,805 |
| |
| Deferred tax asset | — |
| | — |
| | — |
| | 445,152 |
| | — |
| | — |
| | — |
| | 445,152 |
| |
| TEP LTIP units tendered by employees to satisfy tax withholding obligations | — |
| | — |
| | — |
| | (665 | ) | | — |
| | — |
| | (5,938 | ) | | (6,603 | ) | |
| Noncash compensation expense | — |
| | — |
| | — |
| | 493 |
| | — |
| | — |
| | 9,337 |
| | 9,830 |
| |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 110,127 |
| | 110,127 |
| |
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (197,402 | ) | | (197,402 | ) | |
| Distributions to TEP GP Members | — |
| | — |
| | — |
| | (7,465 | ) | | — |
| | — |
| | — |
| | (7,465 | ) | |
| Issuance of TEP units to public, net of offering costs | — |
| | — |
| | — |
| | 297 |
| | — |
| | — |
| | 2,670 |
| | 2,967 |
| |
| Distributions to Class A shareholders | — |
| | — |
| | — |
| | (10,356 | ) | | — |
| | — |
| | — |
| | (10,356 | ) | |
| Acquisition of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (600 | ) | | (600 | ) | |
| Balance at December 31, 2015 | $ | — |
| | $ | 71,564 |
| | 47,725 |
| | $ | 422,310 |
| | 109,504 |
| | $ | — |
| | $ | 1,599,188 |
| | $ | 2,093,062 |
| |
| Net income | — |
| | 6,995 |
| | — |
| | 26,794 |
| | — |
| | — |
| | 216,250 |
| | 250,039 |
| |
| Balance at January 1, 2016 | | $ | 71,564 |
| | 47,725 |
| | $ | 422,310 |
| | 109,504 |
| | $ | — |
| | $ | 1,599,188 |
| | $ | 2,093,062 |
|
| Net Income | | 6,995 |
| | — |
| | 26,794 |
| | — |
| | — |
| | 216,250 |
| | 250,039 |
|
| Acquisition of additional 31.3% membership interest in Pony Express | — |
| | — |
| | — |
| | (255,617 | ) | | — |
| | — |
| | (173,422 | ) | | (429,039 | ) | — |
| | — |
| | (255,617 | ) | | — |
| | — |
| | (173,422 | ) | | (429,039 | ) |
| Issuance of TEP units to public, net of offering costs | — |
| | — |
| | — |
| | 28,762 |
| | — |
| | — |
| | 308,909 |
| | 337,671 |
| — |
| | — |
| | 28,762 |
| | — |
| | — |
| | 308,909 |
| | 337,671 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (249,142 | ) | | (249,142 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | (249,142 | ) | | (249,142 | ) |
| Partial exercise of call option | — |
| | — |
| | — |
| | (27,312 | ) | | — |
| | — |
| | (211,315 | ) | | (238,627 | ) | — |
| | — |
| | (27,312 | ) | | — |
| | — |
| | (211,315 | ) | | (238,627 | ) |
| Issuance of TEP common units in a private placement, net of offering costs | — |
| | — |
| | — |
| | 7,592 |
| | — |
| | — |
| | 82,417 |
| | 90,009 |
| — |
| | — |
| | 7,592 |
| | — |
| | — |
| | 82,417 |
| | 90,009 |
|
| Deferred tax asset | — |
| | — |
| | — |
| | 86,766 |
| | — |
| | — |
| | — |
| | 86,766 |
| — |
| | — |
| | 86,766 |
| | — |
| | — |
| | — |
| | 86,766 |
|
| TEGP distributions to Class A shareholders | — |
| | — |
| | — |
| | (42,499 | ) | | — |
| | — |
| | — |
| | (42,499 | ) | |
| Dividends paid to Class A Shareholders | | — |
| | — |
| | (42,499 | ) | | — |
| | — |
| | — |
| | (42,499 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 9,304 |
| | 9,304 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 9,304 |
| | 9,304 |
|
| Noncash compensation expense | — |
| | — |
| | — |
| | 1,448 |
| | — |
| | — |
| | 7,879 |
| | 9,327 |
| — |
| | — |
| | 1,448 |
| | — |
| | — |
| | 7,879 |
| | 9,327 |
|
| Acquisition of membership interest in BNN | — |
| | — |
| | — |
| | (464 | ) | | — |
| | — |
| | (5,536 | ) | | (6,000 | ) | — |
| | — |
| | (464 | ) | | — |
| | — |
| | (5,536 | ) | | (6,000 | ) |
| Contributions from TD | — |
| | — |
| | — |
| | 5,827 |
| | — |
| | — |
| | 12,067 |
| | 17,894 |
| — |
| | — |
| | 5,827 |
| | — |
| | — |
| | 12,067 |
| | 17,894 |
|
| Costs associated with equity issuance | — |
| | — |
| | — |
| | (986 | ) | | — |
| | — |
| | — |
| | (986 | ) | — |
| | — |
| | (986 | ) | | — |
| | — |
| | — |
| | (986 | ) |
| TEP LTIP units tendered by employees to satisfy tax withholding obligations | — |
| | — |
| | — |
| | (51 | ) | | — |
| | — |
| | (447 | ) | | (498 | ) | — |
| | — |
| | (51 | ) | | — |
| | — |
| | (447 | ) | | (498 | ) |
| Distribution of excess TEGP IPO proceeds to Exchange Right Holders | — |
| | — |
| | — |
| | (1,603 | ) | | — |
| | — |
| | — |
| | (1,603 | ) | |
| Distribution of excess TGE IPO proceeds to Exchange Right Holders | | — |
| | — |
| | (1,603 | ) | | — |
| | — |
| | — |
| | (1,603 | ) |
| Contributions from Predecessor Entities, net | — |
| | 3,736 |
| | | | | | | | | | | | 3,736 |
| 3,736 |
| | — |
| | | | — |
| | — |
| | — |
| | 3,736 |
|
| Conversion of Class B shares to Class A shares | | — |
| | 10,350 |
| | — |
| | (10,350 | ) | | — |
| | — |
| | — |
|
| Balance at December 31, 2016 | | $ | 82,295 |
| | 58,075 |
| | $ | 250,967 |
| | 99,154 |
| | $ | — |
| | $ | 1,596,152 |
| | $ | 1,929,414 |
|
| Acquisition of Terminals and NatGas | | (82,295 | ) | | — |
| | (21,314 | ) | | — |
| | — |
| | (36,391 | ) | | (140,000 | ) |
| Net income | | — |
| | — |
| | (128,729 | ) | | — |
| | — |
| | 352,714 |
| | 223,985 |
|
| Issuance of TEP units to public, net of offering costs | | — |
| | — |
| | 11,353 |
| | — |
| | — |
| | 101,067 |
| | 112,420 |
|
| Dividends paid to Class A Shareholders | | — |
| | — |
| | (73,321 | ) | | — |
| | — |
| | — |
| | (73,321 | ) |
| Noncash compensation expense | | — |
| | — |
| | 1,603 |
| | — |
| | — |
| | 10,390 |
| | 11,993 |
|
| Issuance of TGE Class A shares under TGE LTIP plan | | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| TEP LTIP units tendered by employees to satisfy tax withholding obligations | | — |
| | — |
| | (1,317 | ) | | — |
| | — |
| | (11,616 | ) | | (12,933 | ) |
| Partial exercise of call option | | — |
| | — |
| | (12,052 | ) | | — |
| | — |
| | (72,890 | ) | | (84,942 | ) |
| Repurchase of TEP common units from TD | | — |
| | — |
| | (3,618 | ) | | — |
| | — |
| | (31,717 | ) | | (35,335 | ) |
| Acquisition of additional 24.99% membership interest in Rockies Express | | — |
| | — |
| | 23,522 |
| | — |
| | — |
| | 40,159 |
| | 63,681 |
|
| Acquisition of additional 40% membership interest in Deeprock Development | | — |
| | — |
| | — |
| | — |
| | — |
| | 45,869 |
| | 45,869 |
|
| Acquisition of noncontrolling interests | | — |
| | — |
| | 669 |
| | — |
| | — |
| | (7,109 | ) | | (6,440 | ) |
| Contributions from TD | | — |
| | — |
| | 850 |
| | — |
| | — |
| | 1,451 |
| | 2,301 |
|
| Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | 1,589 |
| | 1,589 |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | (317,102 | ) | | (317,102 | ) |
| Balance at December 31, 2017 | | $ | — |
| | 58,085 |
| | $ | 48,613 |
| | 99,154 |
| | $ | — |
| | $ | 1,672,566 |
| | $ | 1,721,179 |
|
| Cumulative effect of ASC 606 implementation | | — |
| | — |
| | 4,588 |
| | — |
| | — |
| | 39,543 |
| | 44,131 |
|
| Net income | | — |
| | — |
| | 137,127 |
| | — |
| | — |
| | 330,544 |
| | 467,671 |
|
| Dividends paid to Class A Shareholders | | — |
| | — |
| | (206,431 | ) | | — |
| | — |
| | — |
| | (206,431 | ) |
| Noncash compensation expense | | — |
| | — |
| | 6,296 |
| | — |
| | — |
| | 3,197 |
| | 9,493 |
|
| Acquisition of additional TEP common units from TD | | — |
| | — |
| | (62,223 | ) | | 10,758 |
| | — |
| | (189,520 | ) | | (251,743 | ) |
| Issuance of Tallgrass Equity units | | — |
| | — |
| | — |
| | — |
| | — |
| | 644,782 |
| | 644,782 |
|
TALLGRASS ENERGY, GP, LP
CONSOLIDATED STATEMENTS OF EQUITY
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | TEGP Predecessor Equity | | Predecessor Equity | | Partners' Capital | | Noncontrolling Interests | | Total Equity |
| | | | Class A Shares | | Class B Shares | | |
| | | | Shares | | Amount | | Shares | | Amount | | |
| | (in thousands) |
| Conversion of Class B shares to Class A shares | — |
| | — |
| | 10,350 |
| | — |
| | (10,350 | ) | | — |
| | — |
| | — |
|
| Balance at December 31, 2016 | $ | — |
| | $ | 82,295 |
| | 58,075 |
| | $ | 250,967 |
| | 99,154 |
| | $ | — |
| | $ | 1,596,152 |
| | $ | 1,929,414 |
|
| Acquisition of Terminals and NatGas | — |
| | (82,295 | ) | | — |
| | (21,314 | ) | | — |
| | — |
| | (36,391 | ) | | (140,000 | ) |
| Net income | — |
| | — |
| | — |
| | (128,729 | ) | | — |
| | — |
| | 352,714 |
| | 223,985 |
|
| Issuance of TEP units to the public, net of offering costs | — |
| | — |
| | — |
| | 11,353 |
| | — |
| | — |
| | 101,067 |
| | 112,420 |
|
| TEGP distributions to Class A shareholders | — |
| | — |
| | — |
| | (73,321 | ) | | — |
| | — |
| | — |
| | (73,321 | ) |
| Noncash compensation expense | — |
| | — |
| | — |
| | 1,603 |
| | — |
| | — |
| | 10,390 |
| | 11,993 |
|
| Issuance of TEGP Class A shares under TEGP LTIP plan | — |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| TEP LTIP units tendered by employees to satisfy tax withholding obligations | — |
| | — |
| | — |
| | (1,317 | ) | | — |
| | — |
| | (11,616 | ) | | (12,933 | ) |
| Partial exercise of call option | — |
| | — |
| | — |
| | (12,052 | ) | | — |
| | — |
| | (72,890 | ) | | (84,942 | ) |
| Repurchase of TEP common units from TD | — |
| | — |
| | — |
| | (3,618 | ) | | — |
| | — |
| | (31,717 | ) | | (35,335 | ) |
| Acquisition of additional 24.99% membership interest in Rockies Express | — |
| | — |
| | — |
| | 23,522 |
| | — |
| | — |
| | 40,159 |
| | 63,681 |
|
| Acquisition of additional 40% membership interest in Deeprock Development | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 45,869 |
| | 45,869 |
|
| Acquisition of noncontrolling interests | — |
| | — |
| | — |
| | 669 |
| | — |
| | — |
| | (7,109 | ) | | (6,440 | ) |
| Contributions from TD | — |
| | — |
| | — |
| | 850 |
| | — |
| | — |
| | 1,451 |
| | 2,301 |
|
| Contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,589 |
| | 1,589 |
|
| Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (317,102 | ) | | (317,102 | ) |
| Balance at December 31, 2017 | $ | — |
| | $ | — |
| | 58,085 |
| | $ | 48,613 |
| | 99,154 |
| | $ | — |
| | $ | 1,672,566 |
| | $ | 1,721,179 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Predecessor Equity | | Partners' Capital | | Noncontrolling Interests | | Total Equity |
| | | Class A Shares | | Class B Shares | | |
| | | Shares | | Amount | | Shares | | Amount | | |
| | (in thousands) |
| Acquisition of additional 25.01% membership interest in Rockies Express | — |
| | — |
| | 34,116 |
| | 16,797 |
| | — |
| | 74,421 |
| | 108,537 |
|
| Acquisition of additional 2% membership interest in Pony Express | — |
| | — |
| | (5,268 | ) | | — |
| | — |
| | (44,732 | ) | | (50,000 | ) |
| Consolidation of Deeprock North | — |
| | — |
| | — |
| | — |
| | — |
| | 31,843 |
| | 31,843 |
|
| Consolidation of BNN Colorado | — |
| | — |
| | — |
| | — |
| | — |
| | 10,138 |
| | 10,138 |
|
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | 1,787 |
| | 1,787 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (327,578 | ) | | (327,578 | ) |
| Issuance of TEP units to the public, net of offering costs | — |
| | — |
| | (98 | ) | | — |
| | — |
| | (279 | ) | | (377 | ) |
| TEP LTIP units tendered by employees to satisfy tax withholding obligations | — |
| | — |
| | (190 | ) | | — |
| | — |
| | (1,531 | ) | | (1,721 | ) |
| Issuance of Class A shares under LTIP plan, net of units tendered by employees to satisfy tax withholding obligations | — |
| | 19 |
| | (30 | ) | | — |
| | — |
| | — |
| | (30 | ) |
| Conversion of Class B shares to Class A shares | — |
| | 2,822 |
| | (8,717 | ) | | (2,822 | ) | | — |
| | 8,717 |
| | — |
|
| Deferred tax asset | — |
| | — |
| | 15,427 |
| | — |
| | — |
| | — |
| | 15,427 |
|
| Acquisition of additional TEP common units | — |
| | — |
| | (351,431 | ) | | — |
| | — |
| | (1,762,327 | ) | | (2,113,758 | ) |
| Issuance of Class A shares | — |
| | 95,386 |
| | 2,113,758 |
| | — |
| | — |
| | — |
| | 2,113,758 |
|
| Balance at December 31, 2018 | $ | — |
| | 156,312 |
| | $ | 1,725,537 |
| | 123,887 |
| | $ | — |
| | $ | 491,571 |
| | $ | 2,217,108 |
|
TALLGRASS ENERGY, GP, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
| Cash Flows from Operating Activities: | | | | | | | | | | |
| Net income | $ | 223,985 |
| | $ | 250,039 |
| | $ | 200,348 |
| $ | 467,671 |
| | $ | 223,985 |
| | $ | 250,039 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | | | | | |
| Depreciation and amortization | 98,537 |
| | 94,038 |
| | 89,168 |
| 117,430 |
| | 98,537 |
| | 94,038 |
|
| Equity in earnings of unconsolidated investments | (237,110 | ) | | (54,531 | ) | | (2,759 | ) | (306,819 | ) | | (237,110 | ) | | (54,531 | ) |
| Distributions from unconsolidated investments | 237,192 |
| | 54,449 |
| | 3,096 |
| 306,934 |
| | 237,192 |
| | 54,449 |
|
| Deferred tax expense (benefit) | 208,458 |
| | 17,741 |
| | (7,277 | ) | |
| Deferred income tax expense | | 55,709 |
| | 208,458 |
| | 17,741 |
|
| Gain on remeasurement of unconsolidated investment | (9,728 | ) | | — |
| | — |
| — |
| | (9,728 | ) | | — |
|
| Other noncash items, net | 9,226 |
| | 9,711 |
| | 10,446 |
| (2,382 | ) | | 9,226 |
| | 9,711 |
|
| Changes in components of working capital: | | | | | | | | | | |
| Accounts receivable and other | (57,927 | ) | | 2,835 |
| | (15,900 | ) | (102,105 | ) | | (57,927 | ) | | 2,835 |
|
| Accounts payable and accrued liabilities | 84,731 |
| | 10,684 |
| | 10,297 |
| 112,474 |
| | 84,731 |
| | 10,684 |
|
| Deferred revenue | 27,283 |
| | 33,815 |
| | 20,612 |
| 17,547 |
| | 27,283 |
| | 33,815 |
|
| Other current assets and liabilities | (10,542 | ) | | (5,578 | ) | | (6,143 | ) | (3,079 | ) | | (10,542 | ) | | (5,578 | ) |
| Other operating, net | (2,709 | ) | | 95 |
| | (1,672 | ) | 9,145 |
| | (2,709 | ) | | 95 |
|
| Net Cash Provided by Operating Activities | 571,396 |
| | 413,298 |
| | 300,216 |
| 672,525 |
| | 571,396 |
| | 413,298 |
|
| Cash Flows from Investing Activities: | | | | | | | | | | |
| Contributions to unconsolidated investments | | (473,946 | ) | | (45,948 | ) | | (50,076 | ) |
| Capital expenditures | | (368,873 | ) | | (145,144 | ) | | (84,491 | ) |
| Acquisition of BNN North Dakota, net of cash acquired | | (95,000 | ) | | — |
| | — |
|
| Acquisition of NGL Water Solutions Bakken | | (91,000 | ) | | — |
| | — |
|
| Distributions from unconsolidated investments in excess of cumulative earnings | | 80,213 |
| | 69,434 |
| | 24,120 |
|
| Sale of Tallgrass Crude Gathering | | 50,046 |
| | — |
| | — |
|
| Acquisition of membership interest in PLT | | (30,704 | ) | | — |
| | — |
|
| Acquisition of membership interest in Pawnee Terminal | | (30,600 | ) | | — |
| | — |
|
| Acquisition of 38% membership interest in Deeprock North | | (19,500 | ) | | — |
| | — |
|
| Acquisition of Rockies Express membership interest | (400,000 | ) | | (436,022 | ) | | — |
| — |
| | (400,000 | ) | | (436,022 | ) |
| Capital expenditures | (145,144 | ) | | (84,491 | ) | | (120,718 | ) | |
| Acquisition of Terminals and NatGas | (140,000 | ) | | — |
| | — |
| — |
| | (140,000 | ) | | — |
|
| Acquisition of Douglas Gathering System | (128,526 | ) | | — |
| | — |
| — |
| | (128,526 | ) | | — |
|
| Distributions from unconsolidated investment in excess of cumulative earnings | 69,434 |
| | 24,120 |
| | 1,552 |
| |
| Acquisition of Deeprock Development | (57,202 | ) | | — |
| | — |
| |
| Contributions to unconsolidated investments | (45,948 | ) | | (50,076 | ) | | (383 | ) | |
| Acquisition of Deeprock Development, net of cash acquired | | — |
| | (57,202 | ) | | — |
|
| Acquisition of PRB Crude System | (36,030 | ) | | — |
| | — |
| — |
| | (36,030 | ) | | — |
|
| Acquisition of Pony Express membership interest | — |
| | (49,118 | ) | | (700,000 | ) | — |
| | — |
| | (49,118 | ) |
| Acquisition of Western | — |
| | — |
| | (75,000 | ) | |
| Other investing, net | (15,125 | ) | | 48 |
| | (4,883 | ) | (7,848 | ) | | (15,125 | ) | | 48 |
|
| Net Cash Used in Investing Activities | (898,541 | ) | | (595,539 | ) | | (899,432 | ) | (987,212 | ) | | (898,541 | ) | | (595,539 | ) |
| Cash Flows from Financing Activities: | | | | | | | | | | |
| Proceeds from issuance of long-term debt | 1,103,750 |
| | 400,000 |
| | — |
| 500,000 |
| | 1,103,750 |
| | 400,000 |
|
| (Repayments) borrowings under revolving credit facilities, net | (356,000 | ) | | 262,000 |
| | 342,000 |
| |
| Borrowings (repayments) under revolving credit facilities, net | | 417,000 |
| | (356,000 | ) | | 262,000 |
|
| Distributions to noncontrolling interests | (317,102 | ) | | (249,142 | ) | | (153,064 | ) | (327,578 | ) | | (317,102 | ) | | (249,142 | ) |
| Dividends paid to Class A shareholders | | (206,431 | ) | | (73,321 | ) | | (42,499 | ) |
| Acquisition of Pony Express membership interest | | (50,000 | ) | | — |
| | (425,882 | ) |
| Proceeds from public offering of TEP common units, net of offering costs | 112,420 |
| | 337,671 |
| | 554,084 |
| — |
| | 112,420 |
| | 337,671 |
|
| TEGP distributions to Class A shareholders | (73,321 | ) | | (42,499 | ) | | (10,356 | ) | |
| Partial exercise of call option | (72,381 | ) | | (204,634 | ) | | — |
| |
| Repurchase of TEP common units from TD | (35,335 | ) | | — |
| | — |
| |
| Payments for deferred financing costs | (22,375 | ) | | (10,380 | ) | | (3,271 | ) | |
| Contribution from TD | — |
| | 17,894 |
| | — |
| |
| Distribution to TEGP Predecessor Member, net | — |
| | — |
| | (13,533 | ) | |
| Distribution to TEP GP Member, net | — |
| | — |
| | (7,465 | ) | |
TALLGRASS ENERGY, GP, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | Acquisition of Pony Express membership interest | — |
| | (425,882 | ) | | — |
| |
| Partial exercise of call option | | — |
| | (72,381 | ) | | (204,634 | ) |
| Repurchase of TEP common units from TD | | — |
| | (35,335 | ) | | — |
|
| Payments for deferred financing costs | | — |
| | (22,375 | ) | | (10,380 | ) |
| Proceeds from private placement of TEP common units, net of offering costs | — |
| | 90,009 |
| | — |
| — |
| | — |
| | 90,009 |
|
| Distribution of Excess Proceeds to Exchange Right Holders | — |
| | (1,603 | ) | | (334,068 | ) | |
| Proceeds from initial public offering of Class A shares, net | — |
| | — |
| | 1,314,738 |
| |
| Acquisition of Acquired TEP Units | — |
| | — |
| | (953,600 | ) | |
| Acquisition of additional Tallgrass Equity units | — |
| | — |
| | (171,948 | ) | |
| Contribution from TD | | — |
| | — |
| | 17,894 |
|
| Other financing, net | (12,377 | ) | | 9,032 |
| | 37,066 |
| (11,301 | ) | | (12,377 | ) | | 7,429 |
|
| Net Cash Provided by Financing Activities | 327,279 |
| | 182,466 |
| | 600,583 |
| 321,690 |
| | 327,279 |
| | 182,466 |
|
| Net Change in Cash and Cash Equivalents | 134 |
| | 225 |
| | 1,367 |
| 7,003 |
| | 134 |
| | 225 |
|
| Cash and Cash Equivalents, beginning of period | 2,459 |
| | 2,234 |
| | 867 |
| 2,593 |
| | 2,459 |
| | 2,234 |
|
| Cash and Cash Equivalents, end of period | $ | 2,593 |
| | $ | 2,459 |
| | $ | 2,234 |
| $ | 9,596 |
| | $ | 2,593 |
| | $ | 2,459 |
|
| | | | | | | | | | | |
| Supplemental Disclosures: | | | | | | | | | | |
| Cash payments for interest, net | $ | (72,698 | ) | | $ | (34,367 | ) | | $ | (16,432 | ) | $ | (114,026 | ) | | $ | (72,698 | ) | | $ | (34,367 | ) |
| Schedule of Noncash Investing and Financing Activities: | | | | | | | | | | |
Acquisition of additional TEP common units (a)(b) | | $ | (2,365,501 | ) | | $ | — |
| | $ | — |
|
Issuance of Class A shares (a) | | $ | 2,113,758 |
| | $ | — |
| | $ | — |
|
Issuance of Tallgrass Equity units (b) | | $ | 644,782 |
| | $ | — |
| | $ | — |
|
Acquisition of Rockies Express membership interest (b) | | $ | (393,039 | ) | | $ | — |
| | $ | — |
|
| Contribution of 38% membership interest in Deeprock North to Deeprock Development | | $ | (19,500 | ) | | $ | — |
| | $ | — |
|
| Issuance of noncontrolling interests in Deeprock Development in exchange for 62% membership interest in Deeprock North | | $ | (31,843 | ) | | $ | — |
| | $ | — |
|
| TEP common units issued as partial consideration to acquire additional 9% membership interest in Deeprock Development | | $ | — |
| | $ | 6,617 |
| | $ | — |
|
| Increase in accrual for payment of property, plant and equipment | $ | 8,975 |
| | $ | — |
| | $ | — |
| $ | 5,755 |
| | $ | 8,975 |
| | $ | — |
|
| TEP common units issued as partial consideration to acquire additional 9% membership interest in Deeprock Development | $ | 6,617 |
| | $ | — |
| | $ | — |
| |
| Property, plant and equipment acquired via the cash management agreement with TD | $ | — |
| | $ | — |
| | $ | 138,936 |
| |
| Contributions from noncontrolling interests settled via the cash management agreement with TD | $ | — |
| | $ | — |
| | $ | 68,277 |
| |
| Distributions to noncontrolling interests settled via the cash management agreement with TD | $ | — |
| | $ | — |
| | $ | (69,017 | ) | |
| |
(a) | Represents the acquisition of additional TEP common units in exchange for Class A shares associated with the Merger Agreement as discussed in Note 1 – Description of Business. |
| |
(b) | Represents the issuance of Tallgrass Equity units associated with our acquisition of a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units as discussed in Note 3 – Acquisitions and Dispositions. |
TALLGRASS ENERGY, GP, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Business
Tallgrass Energy, LP ("TGE") formerly known as Tallgrass Energy GP, LP, ("TEGP" or the "Partnership") is a limited partnership that owns, operates, acquires and develops midstream energy assets in North America and has elected to be treated as a corporation for U.S. federal income tax purposes. TEGP was formed as part of the reorganization of entities controlled by Tallgrass Equity, LLC ("Tallgrass Equity") to effect the initial public offering of Class A shares of TEGP (the "TEGP IPO"), which was completed on May 12, 2015. Prior to closing the TEGP IPO, Tallgrass Equity held a 100% membership interest in Tallgrass Energy Holdings, LLC ("Tallgrass Energy Holdings"). Tallgrass Energy Holdings, in turn, held a 100% limited partner interest in TEGP and a 100% membership interest in TEGP Management, LLC ("TEGP Management"), the general partner of TEGP. For more information see "Basis of Presentation" in Note 2 – Summary of Significant Accounting Policies.
TEGP's sole cash-generating asset as of December 31, 2017 was an approximate 36.94% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets as of December 31, 2017 consisted of its direct and indirect partnership interests in TEP, as described below, that were historically owned by entities controlled by Tallgrass Equity, including TD:
100% of the outstanding membership interests in Tallgrass MLP GP, LLC ("TEP GP"), which owns the general partner interest in TEP as well as all the TEP incentive distribution rights ("IDRs"). The general partner interest in TEP is represented by 834,391 general partner units, representing an approximate 1.13% general partner interest in TEP at December 31, 2017.
The Acquired TEP Units, representing an approximate 27.01% limited partner interest in TEP at December 31, 2017.
As discussed in Note 22 – Subsequent Events, on February 7, 2018, Tallgrass Development merged into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity ("Tallgrass Development Holdings"), and as a result of the merger, Tallgrass Equity acquired a 25.01% membership in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TEGP and Tallgrass Equity issued 27,554,785 unregistered TEGP Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of Tallgrass Development.
The term "TEGP Predecessor" refers to TEGP, as recast to show the effects of the Reorganization Transactions, for the periods prior to completion of the TEGP IPO on May 12, 2015. "We," "us," "our" and similar terms refer to TEGPTGE together with its consolidated subsidiaries.
Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, or to TEGP Predecessor together with its consolidated subsidiaries, as the context requires, including in both cases, Tallgrass Equity, and TEP (and their respective subsidiaries).
TEP is a publicly traded, growth-oriented limited partnership formed toLLC ("Tallgrass Equity"), in which we directly own operate, acquire and develop midstream energy assets in North America. TEP's operationsan approximate 55.79% membership interest as of December 31, 2018. We are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations. TEP's
Our reportable business segments are:
Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and an integrated natural gas storage facilities;facility;
Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system; and
Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering and processing facilities; crude oil gathering, storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs.
Natural Gas Transportation.TEP provides We provide natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) its 49.99%our 75% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), which owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio (the "Rockies Express Pipeline"), inclusive of the additional 24.99% membership interest acquired from Tallgrass Development, LP ("TD") effective March 31, 2017 as discussed in Note 4 – Acquisitions, and our 100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas") acquired effective January 1, 2017,, which operates the Rockies Express Pipeline, (2) the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and (3) the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline"). As discussed in Note 22 – Subsequent Events, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express from Tallgrass Development on February 7, 2018.
Crude Oil Transportation. TEP providesWe provide crude oil transportation to customers in Wyoming, Colorado, Kansas, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a FERC-regulated crude oil pipeline commencing in both Guernsey, Wyoming and Weld County, Colorado and terminating in Cushing, Oklahoma and includes a lateral in Northeast Colorado commencing(the "Pony Express System"). In the second quarter of 2018, Pony Express placed into service an extension of the system from an additional origin point in Weld County, Colorado that interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System").located near Platteville, Colorado.
Gathering, Processing & Terminalling.TEP provides We provide natural gas gathering and processing services for customers in Wyoming through: (1) a natural gas gathering system in the Powder River Basin (the "Douglas Gathering System") that was acquired on June 5, 2017, as discussed in Note 4 – Acquisitions, (2) the Casper and Douglas natural gas processing facilities in Casper and Douglas, and (3) the West Frenchie Drawa natural gas treating facility. TEPfacility at West Frenchie Draw. We also provides crude oil gathering services for customers in Wyoming through a crude oil gathering system in the Powder River Basin (the "PRB Crude System") that was acquired on August 3, 2017, as discussed in Note 4 – Acquisitions; andprovide NGL transportation services in Northeast Colorado and Wyoming. TEP performsWe perform water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, Wyoming, and WyomingNorth Dakota through BNN Water Solutions, LLC ("Water Solutions"), and crude oil storage and terminalling services through TEP'sour 100% membership interest in Tallgrass Terminals, LLC ("Terminals") acquired effective January 1, 2017,, which owns and operates crude oil terminals near Sterling,in Colorado, (the "Sterling Terminal")Oklahoma, and in Weld County, Colorado (the "Buckingham Terminal"). Terminals also owns a 69% membership interest in Deeprock Development, LLC ("Deeprock Development"), which owns a crude oil terminal in Cushing, Oklahoma (the "Cushing Terminal"), inclusive of an additional 49% membership interest in Deeprock Development acquired in July 2017 as discussed in Note 4 – Acquisitions.Kansas. The Gathering, Processing & Terminalling segment also includes newly formed Stanchion Energy, LLC ("Stanchion"), which transacts in crude oil. As discussed in Note 22 – Subsequent Events, on January 2, 2018, Terminals acquired an approximately 38% interest in Deeprock North, LLC ("Deeprock North"), which was merged into Deeprock Development immediately following the acquisition, and on January 12, 2018, Water Solutions acquired a 100% membership interest in Buckhorn Energy Services, LLC and Buckhorn SWD Solutions, LLC (collectively, "BNN North Dakota").
The term "Terminals Predecessor" refers to Terminals and the term "NatGas Predecessor" refers to NatGas prior to their acquisition by TEPTallgrass Energy Partners, LP ("TEP") on January 1, 2017. Terminals Predecessor and NatGas Predecessor are collectively referred to as the Predecessor Entities, as further discussed in Note 2 – Summary of Significant Accounting Policies. Financial results for all prior periods have been recast to reflect the operations of the Predecessor Entities. Predecessor Equity as presented in the consolidated financial statements represents the capital account activity of Terminals Predecessor and NatGas Predecessor prior to January 1, 2017. For additional information regarding these acquisitions, see Note 43 – Acquisitions and Dispositions.
Merger Agreement with Tallgrass Energy Partners, LP
TGE previously entered into a definitive Agreement and Plan of Merger, dated as of March 26, 2018 (the "Merger Agreement"), with TEP, a Delaware limited partnership, Tallgrass MLP GP, LLC, a Delaware limited liability company and the general partner of TEP ("TEP GP"), and Razor Merger Sub, LLC, a Delaware limited liability company. The merger transaction
contemplated by the Merger Agreement (the "TEP Merger") was completed effective June 30, 2018, and as a result, 47,693,097 TEP common units held by the public were converted into the right to receive Class A shares of TGE at an exchange ratio of 2.0 Class A shares for each outstanding TEP common unit, TEP's incentive distribution rights were cancelled, TEP's common units are no longer publicly traded, and 100% of TEP's equity interests are now owned by Tallgrass Equity and its subsidiaries. The TEP Merger was accounted for as an acquisition of noncontrolling interest. Following consummation of the TEP Merger, TGE changed its name from "Tallgrass Energy GP, LP" to "Tallgrass Energy, LP" and began trading on the New York Stock Exchange under the ticker symbol "TGE" on July 2, 2018.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements and related notes were prepared in conformity with accounting principles generally accepted in the United States of America ("GAAP"). In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.
The accompanying consolidated financial statements of TEGP for periods prior to May 12, 2015 include historical cost basis accounts of the assets of TEGP and were prepared in contemplation of TEGP's initial public offering of Class A shares completed on May 12, 2015 and the acquisition of an approximately 30.35% interest in Tallgrass Equity as described below, which was accounted for as a transaction between entities under common control in accordance with ASC 805. Significant intra-entity items have been eliminated in the presentation. Both TEGP and TEGP Predecessor are considered entities under common control and, as such, the transfer between the entities of the assets and liabilities has been recorded by TEGP at historical cost. TEGP, as used herein, refers to the consolidated financial results and operations for TEGP Predecessor prior to the completion of the TEGP IPO and to TEGP thereafter.
In connection with the closing of the TEGP IPO on May 12, 2015, the following transactions (the "Reorganization Transactions") occurred:
Tallgrass Equity distributed its membership interest in Tallgrass Energy Holdings to its members, pro rata, and Tallgrass Energy Holdings distributed its 100% limited partner interest in TEGP, respectively, to its members, pro rata, which are referred to as the "Initial Exchange Right Holders";
TEGP issued 47,725,000 Class A shares to the public for net proceeds of approximately $1.3 billion, including 6,225,000 Class A shares issued in connection with the underwriters' exercise of the overallotment option;
The existing limited partner interests in TEGP held by the Initial Exchange Right Holders were converted into 115,729,440 Class B shares, 6,225,000 of which were automatically canceled in connection with the underwriters' exercise of the overallotment option, resulting in the Initial Exchange Right Holders owning 109,504,440 Class B shares;
Tallgrass Equity issued 41,500,000 Tallgrass Equity units to TEGP in exchange for approximately $1.1 billion in net proceeds from the issuance of TEGP's Class A shares to the public and amended the limited liability company agreement of Tallgrass Equity to, among other things, provide that TEGP is the managing member of Tallgrass Equity;
TEGP used the net proceeds from the purchase of the 6,225,000 overallotment option shares to purchase Tallgrass Equity units from the Initial Exchange Right Holders; and
Tallgrass Equity entered into a $150 million revolving credit facility and borrowed $150 million thereunder, using the aggregate proceeds from such borrowings together with the net proceeds from the TEGP IPO that Tallgrass Equity received from TEGP, to purchase 20,000,000 common units, representing limited partner interests in Tallgrass Energy Partners, LP ("TEP"), from Tallgrass Development, LP ("TD") at $47.68 per TEP common unit (the "Acquired TEP Units") and pay offering expenses and other transaction costs. Tallgrass Equity distributed substantially all the remaining proceeds (the "Excess Proceeds") to the Initial Exchange Right Holders.
As further discussed in Note 43 – Acquisitions and Dispositions, TEPwe closed the acquisition of Terminals and NatGas effective January 1, 2017. As the acquisitions of Terminals and NatGas are considered transactions between entities under common control, and a change in reporting entity, the financial information presented has been recast to include Terminals and NatGas for all periods presented. Net equity contributions of the Predecessor Entities included in the consolidated financial statements represent transfers of cash as a result of TD'sTallgrass Development's ("TD") centralized cash management system prior to January 1, 2017 for Terminals and NatGas, under which cash balances were swept daily and recorded as loans from the subsidiaries of TD. These loans were then periodically recorded as equity distributions.
The accompanying consolidated financial statements of TEGPTGE include historical cost-basis accounts of the assets of Terminals and NatGas for the periods prior to January 1, 2017, the date TEPwe acquired Terminals and NatGas from TD, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis. TEGP,TGE, TEP, and the Predecessor Entities are all considered "entities under common control" as defined under GAAP and, as such, the transfers between the entities of the assets and liabilities have been recorded by TEGPTGE at historical cost.
The consolidated financial statements include the accounts of TEGPTGE and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Prior to January 1, 2016, Pony Express participated in a cash management agreement with TD, which currently holds a 2.0% common membership interest in Pony Express, under which cash balances were swept periodically and recorded as loans from Pony Express to TD. Effective January 1, 2016, Pony Express entered into a cash management agreement with TEP.
Net income or loss from consolidated subsidiaries that are not wholly-owned by TEGPTGE is attributed to TEGPTGE and noncontrolling interests. This is done in accordance with substantive profit sharing arrangements, which generally follow the allocation of cash distributions and may not follow the respective ownership percentages held by TEGP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in Pony Express effective September 1, 2014, TEP, TD, and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65 million through the quarter ended September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5 million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ended December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 are attributed to TEP and its noncontrolling interests in accordance with the respective ownership interests.
A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity's economic performance. We have presented separately in our consolidated balance sheets, to the extent material, the liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Our consolidated VIEs dodid not have material assets that cancould only be used to settle specific obligations of the consolidated VIEs. Prior to June 29, 2018, both Tallgrass Equity isand TEP were considered to be a VIE under the applicable authoritative guidance. Based on a qualitative analysis in accordance with the applicable authoritative guidance, we have determined that we are the primary beneficiary as we have the right to receive benefits of Tallgrass Equity that could potentially
be significant to Tallgrass Equity. TEP is also considered to be a VIE under the applicable authoritative guidance. Based on a qualitative analysis, we have determined that TEP GP is the primary beneficiary of TEP and we continue to consolidate TEP accordingly. Pony Express was considered to be a VIEVIEs under the applicable authoritative guidance prior toand included in our acquisitionconsolidated results. As a result of an additional 31.3% membership interest effective January 1, 2016. Effective January 1, 2016, Pony Express isthe TEP Merger, and changes in ownership and their respective partnership arrangements, Tallgrass Equity and TEP are no longer considered to be a VIE.VIEs. We continue to consolidate our membership interests in Tallgrass Equity and TEP through the voting interest in Pony Express.model.
Use of Estimates
Certain amounts included in or affecting these consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts reported for assets, liabilities, revenues, and expenses during the reporting period, and the disclosure of contingent assets and liabilities at the date of the financial statements. Management evaluates these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from these estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
Cash and Cash Equivalents
We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Net equity contributions of the Predecessor Entities included in the consolidated statements of cash flows represent transfers of cash as a result of TD's centralized cash management systems prior to January 1, 2017 for Terminals and NatGas, under which cash balances were swept daily and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable are carried at their estimated collectible amounts. We make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and adjustments are recorded as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. Our allowance for doubtful accounts totaled $0.5$7.7 million and $0.6$0.5 million at December 31, 20172018 and 2016,2017, respectively.
Inventories
Inventories primarily consist of crude oil, materials and supplies, gas in underground storage, materials and supplies, natural gas liquids and crude oil. Gas in underground storage, sometimes referred to as working gas, and natural gas liquids are recorded at the lower of historical cost and net realizable value using the average cost method.liquids. As discussed further under "Revenue Recognition" below, a loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline loss allowance oil, or PLA, which we can then sell. As pipeline allowancePLA oil is accumulated, it is recorded as inventory at the lower of historical cost and net realizable value using the average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for physical deterioration and obsolescence. Natural gas liquids and gas in underground storage, sometimes referred to as working gas, are recorded at the lower of historical cost and net realizable value using the average cost method. For additional information, see "Gas in Underground Storage" below.
Accounting for Regulatory Activities
Regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the Codification. This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We recorded regulatory assets of approximately $2.6$3.2 million and $2.9$2.6 million included in "Prepayments and other current assets" and "Deferred charges and other assets" in the consolidated balance sheets at December 31, 20172018 and 2016,2017, respectively. Regulatory assets at December 31, 20172018 and December 31, 20162017 were primarily attributable to costs associated with both TIGT's 2015 Rate Case Filing and Trailblazer's 2013 Rate Case Filing as well as fuel tracker assets at our regulated natural gas pipelines as well as both Trailblazer's 2013 and 2018 Rate Case Filings and TIGT's 2015 Rate Case Filing. We recorded regulatory liabilities of approximately $2.3$1.9 million and $1.7$2.3 million included in "Other current liabilities" in the consolidated balance sheets at December 31, 20172018 and 2016,2017, respectively, related to fuel tracker liabilities at our regulated natural gas pipelines. For further information regarding our rate case filings and fuel tracker balances, see Note 18 – Regulatory Matters.
Property, Plant and Equipment
Property, plant and equipment is stated at historical cost, which for constructed plants includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction for regulated assets and other costs directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs related to the construction of assets, including internal labor costs, interest and engineering costs.
Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in accumulated depreciation and/or the negative salvage liability discussed under "Depreciation and Amortization" below, as appropriate, with no effect on current period earnings. Gains or losses are recognized upon retirement of non-regulated or regulated property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred.
Intangible Assets
We establish identifiable intangible assets when they meet either the separability criterion or the contractual-legal criterion. Contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section of TIGT's natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years, the period of expected future benefit. During 2018, we recognized additional intangible assets at Plaquemines Liquids Terminal, LLC ("PLT"), a newly formed subsidiary as discussed in Note 3 – Acquisitions and Dispositions, from the acquisition of permits,
designs, and other work-product related to the development and construction of a crude oil terminal facility in Louisiana. These intangible assets will be amortized on a straight-line basis over a period of 35 years, the period of expected future benefit. Also, during 2018, we recognized an intangible asset associated with customer relationships as part of our acquisition of NGL Water Solutions Bakken, LLC as discussed in Note 3 – Acquisitions and Dispositions. The customer relationships are amortized on a straight-line basis over a period of 8 years. Other intangible assets include customer contracts amortized on a straight-line basis over a period of 2 to 8- 14 years, based on the remaining term of the contracts at the time of acquisition.
Impairment of Long-Lived Assets
We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset or asset group's use and its eventual disposition are less than its carrying amount. We assess our long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived asset or asset group is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value.
Examples of long-lived asset impairment indicators include:
a significant decrease in the market value of a long-lived asset or asset group;
a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;
a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group;
a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and
a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
When an impairment indicator is present, we first assess the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset or asset group to its carrying amount. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the asset or asset group is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be recognized.
Gas in Underground Storage
Gas in underground storage represents the cost of base gas, which refers to the volumes necessary to maintain pressure and deliverability requirements in our storage facilities. We record base gas as a component of property, plant and equipment.
We maintain working gas in our underground storage facilities on behalf of certain third parties. We receive a fee for our storage services but do not reflect the value of third-party gas in the accompanying consolidated financial statements. We occasionally acquire volumes of working gas for our own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost and net realizable value.
Depreciation and Amortization
For non-regulated assets, we have elected to use the straight-line method of depreciation. For our regulated assets, we have elected to compute depreciation using a composite method employed by applying a single depreciation rate to a group of assets with similar economic characteristics. This composite method of depreciation approximates a straight-line method of depreciation. The depreciation rates for our regulated natural gas pipeline assets include two components, one based on economic service life (capital recovery) and one based on net costs of removal (negative salvage). The accumulated liability related to negative salvage is classified as "Other long-term liabilities and deferred credits" in our consolidated balance sheets.
The rates of depreciation for the various classes of depreciable assets are as follows:
|
| |
| | Range of Depreciation Rates |
| Crude oil pipelines | 2.8% |
| Natural gas pipelines | 0.70.7% - 5.0% |
| Gathering & processing assets | 2.22.2% - 5.0% |
| Water business assets | 2.32.3% - 20.0% |
| Terminal assets | 1.81.8% - 2.8% |
Replacement Gas Facilities (1) | 10.0% |
| General & other | 2.52.9% - 25.0% |
| |
(1) | Represents costs incurred by TIGT, and reimbursed by Pony Express, for the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System after having sold approximately 433 miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013. |
Gas Imbalances
Gas imbalances receivable and payable represent the difference between customer nominations and actual gas receipts from and gas deliveries to interconnecting pipelines under various operational balancing and imbalance agreements. Gas imbalances are either made up in-kind or settled in cash, subject to the terms and valuations of the various agreements. Imbalances are valued at applicable average market index prices. Gas imbalances receivable and payable are included in "Prepayments and other current assets" and "Other current liabilities" in the consolidated balance sheets.
Deferred Financing Costs
Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method. Deferred financing costs associated with long-term debt are presented as a reduction to the corresponding debt in our consolidated balance sheets. Deferred financing costs associated with our revolving credit facility are presented as noncurrent assets in our consolidated balance sheets. During the year ended December 31, 2018, we recognized a $2.2 million loss on debt retirement, recorded as "Other income, net" in the accompanying consolidated statements of income, associated with the write off of deferred financing costs associated with the Amendment to the TEP revolving credit facility and the termination of the Tallgrass Equity revolving credit facility as discussed further in Note 10 – Long-term Debt.
Goodwill
We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of fair value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31. We evaluate goodwill for impairment at the reporting unit level, which is the same as, or one level below, an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or proceeding directly to the quantitative impairment test depending on facts and circumstances of the reporting unit. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. If we, after performing the qualitative assessment, determine it is "more likely than not" that the fair value of a reporting unit is greater than its carrying amount, then goodwill is not considered impaired. When goodwill is evaluated for impairment using the quantitative impairment test, the carrying amount of the reporting unit is compared to its fair value. If the fair value exceeds the carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the reporting unit's fair value, then the reporting unit should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. See Note 8 – Goodwill and Other Intangible Assets for additional information regarding impairment testing performed during 2017.2018.
Investment in Unconsolidated Affiliates
We use the equity method to account for investments in 20% or greater owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and for investments in less than 20% owned affiliates where we have the ability to exercise significant influence.
We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in
value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary. See Note 97 – Investments in Unconsolidated Affiliates for additional information regarding our investment in unconsolidated affiliates.
Revenue Recognition
WeIn May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five-step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract.
Management completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2018. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to members' equity. Consolidated revenues presented in the comparative consolidated financial statements for periods prior to January 1, 2018 have not been revised.
On January 1, 2018, we recorded a cumulative effect adjustment to equity of $44.1 million, increased the carrying amount of our investment in Rockies Express by $42.8 million, and recognized a receivable from Rockies Express of $1.3 million. These adjustments relate to the cumulative effect adjustment recorded by Rockies Express of $125.2 million upon adoption of ASC 606. The cumulative effect adjustment at Rockies Express arose as services are rendered or goods are solda result of the allocation of the transaction price to a purchaserseries of individual performance obligations in certain long-term transportation contracts with rates that vary throughout the term of the contract. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas during the periods prior to implementation.
Through our review process, we also identified the following changes to our revenue recognition policies that did not result in a cumulative effect adjustment on January 1, 2018:
Gathering & Processing. We have determined that a number of our gathering & processing contracts at TMID do not represent customer arrangements under ASC 606. Instead, arrangements deemed to represent wellhead purchases of raw gas are accounted for as supply arrangements pursuant to ASC 705. As a fixed and determinable price, delivery has occurred, title has transferred and collectability is reasonably assured.result, gathering & processing fees previously recognized in revenue are reported as a reduction to cost of sales under ASC 606.
Pipeline Loss Allowance. We provide various types of natural gas transportation and storage services andhave determined that PLA collected under certain crude oil transportation services to our customers in which the commodity remains the property of these customers at all times.
Natural gas transportation and storage services occur in the Natural Gas Transportation segment. In many cases (generally described as "firm service"), the customer paysarrangements is a two-part rate that includes (i) a fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fee-based component of the overall rate is recognized astransaction price where the PLA both significantly exceeds actual losses and was negotiated with the intent of providing a revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumesstream to Pony Express. Under ASC 606, PLA barrels retained from customers are deliveredsubject to the customers' agreed upon delivery point, orguidance for noncash consideration and recognized in revenue at their contract inception fair value.
See Note 12 – Revenue from Contracts with Customers for revenue disclosures related to both the implementation and the additional requirements prescribed by the standard. These new disclosures include information regarding the significant judgments used in evaluating when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as "interruptible service"), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service,and how revenue is (or will be) recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In additionand data related to "firm"contract assets and "interruptible" transportation services, we also provide natural gas park and loan services to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized as services are provided, based on the terms negotiated under these contracts.
Crude oil transportation services occur in the Crude Oil Transportation segment. We provide various types of crude oil transportation services to our customers and, other than pipeline allowance oil, do not take title to the crude oil and do not incur the risks and rewards of ownership. In many cases the customer has committed to ship a fixed quantity of oil barrels per month. For barrels physically received by us and delivered to the customers' agreed upon destination point, revenue is recognized in the period the service is provided. Shipper deficiencies, or barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers' agreed upon destination point, are charged at the committed tariff rate per barrel and recorded as a liability until the barrels are physically transported and delivered. In the case of non-committed shippers, revenue is recognized in the same manner utilized for the barrels physically transported and delivered. A loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil. Any pipeline allowance oil that remains after replacing losses in transit can be sold. We take title and record revenue at market prices when the volumes included in the pipeline loss allowance are delivered from the customer. When pipeline loss allowance oil is eventually sold, we record revenue at the contractual sales price and cost of sales at average cost as discussed in liabilities."Inventories" above.
Natural gas liquids sales occur in the Gathering, Processing & Terminalling segment and consist of the sale of outputs from our processing plants and the marketing of natural gas liquids that are delivered by our suppliers under either fee-based arrangements or percent-of-proceeds arrangements. Under these arrangements, we treat and process the natural gas delivered by our suppliers, and then sell the resulting NGLs and condensate based on published index market prices. We remit to the producers an agreed-upon percentage of the actual proceeds that we receive from our sales of the NGLs and condensate. We keep the difference between the proceeds received and the amount remitted back to the producer. We generally report gross revenues in the consolidated statements of income, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. Processing and other revenues primarily represent fees for processing, treating and fractionation of natural gas and NGLs earned under fee-based arrangements and revenue from water services earned in the Gathering, Processing & Terminalling segment.
Natural gas sales occur in both the Natural Gas Transportation segment and in the Gathering, Processing & Terminalling segment. In the Natural Gas Transportation segment, transportation services revenue is recognized when a portion of the natural gas transported by customers is collected as a contractual fee to compensate us for fuel consumed by pipeline and storage operations. We take title and record revenue at market prices when the volumes included in the contractual fee are delivered from the customer and injected into our storage facility. When the excess volumes are eventually sold, we record natural gas sales revenue at the contractual sales price and cost of sales at average cost. As of the date of the TIGT rate case settlement in 2016, all of our regulated gas pipelines operate under fuel tracker mechanisms, as discussed under "Accounting for Regulatory Activities" above, and as a result our regulated gas pipelines no longer recognize revenue associated with volumes retained from the customer. When operational conditions allow, we occasionally sell "base gas," which refers to the minimum volume of natural gas required in order to operate the storage facility. In the Gathering, Processing & Terminalling segment, we purchase natural gas primarily for use in our operations and for meeting contractual requirements to deliver natural gas to certain customers. In addition, some of our contractual arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate revenue by selling the volumes of natural gas received or purchased that exceed our business needs.
Commitments and Contingencies
We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss.
Environmental Costs
We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. We
do not discount environmental liabilities to a net present value, and record environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action. Estimates of environmental liabilities are based on currently available facts and presently enacted laws and regulations taking into consideration the likely effects of other factors including our prior experience in remediating contaminated sites, other companies' clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information.
Fair Value
Fair value, as defined in the Codification, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. We apply the fair value measurement guidance to financial assets and liabilities in determining the fair value of derivative assets and liabilities, and to nonfinancial assets and liabilities upon the acquisition of a business or in conjunction with the measurement of an impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill.
The fair value measurement accounting guidance requires that we make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments' fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity.
Fair value, where available, is based on observable market prices. Where observable market prices or inputs are not available, different valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments' complexity.
To increase consistency and enhance disclosure of fair value, the Codification creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability's level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows:
Level 1 Inputs-quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;
Level 2 Inputs-inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
Level 3 Inputs-unobservable inputs for the asset or liability. These unobservable inputs reflect the entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity's own data).
Any transfers between levels within the fair value hierarchy are recognized at the end of the reporting period.
For information regarding financial instruments measured at fair value on a recurring basis, see Note 109 – Risk Management. For information regarding the fair value of financial instruments not measured at fair value in the consolidated balance sheets, see Note 1110 – Long-term Debt.
Risk Management Activities
Our operations expose us to a variety of risks including, but not limited to, changes in the prices of commodities that we buy or sell. We utilize energy derivativesmanage these exposures with either physical or financial transactions. We have established a comprehensive risk management policy and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the purposeoverall management of mitigating ourcredit risk resulting from fluctuations in the marketand commodity price of crude oilrisk, including establishing and natural gas. monitoring exposure limits.
We record derivative contracts at their estimated fair values as of each reporting date.date and present profit and loss activity on a net basis in "Processing and other revenues" in our consolidated statements of operations. For more information on our risk management activities, see Note 109 – Risk Management.
Equity-Based Compensation
Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. As discussed in Note 16 – Equity-Based Compensation, prior to February 2018 a portion of the expense recognized relating to equity-based compensation grants iswas charged to TD.
Income Taxes
Although TEGPTGE is organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes and are therefore subject to both U.S. federal and state income taxes for periods beginning May 12, 2015. Prior to the completion of the TEGP IPO on May 12, 2015, TEGP Predecessor was comprised primarily of limited liability companies that were flow-through entities (that is, partnerships or disregarded entities) for income tax purposes, with the exception of a single C corporation which did not generate any income. Accordingly, no provision for federal or state income taxes was recorded in the consolidated financial statements of TEGP Predecessor and the tax effects of our activities accrued to their respective partners and members for periods prior May 12, 2015. Subsequent to May 12, 2015, TEGP'staxes. TGE's consolidated subsidiaries consist primarily of entities that are flow-through entities for income tax purposes. On September 14, 2015, TEP, through its membership interest in Pony Express, formed a newWe also own certain C corporation Tallgrass Colorado Pipeline, Inc. ("Tallgrass Colorado"),subsidiaries which is 99.8% owned by Pony Express. The remaining 0.2% interest in Tallgrass Colorado is held by direct and indirect wholly owned subsidiaries of TEP. Tallgrass Colorado washave been formed for the purpose of the potential pipeline construction of a lateral pipeline that would interconnect with the Pony Express System's existing lateral in Northeast Colorado and has not yet commenced operations or generated any income.other investment purposes. In addition, during the year ended December 31, 2015, TEP formed Tallgrass Energy Finance Corp., is a wholly owned subsidiary of TEP that has no material assets and was formed for the sole purpose of being a co-issuer of TEP's senior notes as discussed in Note 1110 – Long-term Debt. On September 29, 2017, TEP, through its membership interest in TIGT, formed a newThese C corporation Cheyenne Connector Pipeline, Inc. ("Cheyenne Connector"), for the purpose of the construction of a pipeline lateral in Northeast Colorado that would interconnect with Rockies Express Pipeline's Cheyenne Hub. Cheyenne Connector hassubsidiaries have not yet commenced operations or generated any income. Accordingly,material income, and as a result no provision for federal or state income taxes has been recorded in our consolidated financial statements.
Deferred income taxes are provided for temporary differences arising from differences between the consolidated financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates expected to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than not that a deferred tax asset will not be realized. In determining the appropriate valuation allowance, we consider projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies, and our overall deferred tax position.
Pursuant to the applicable guidance related to accounting for uncertainty in income taxes, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2017,2018, we had not recognized any material amounts in connection with uncertainty in income taxes.
Business Combinations
We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill or gain from a bargain purchase. For material or complex acquisitions, management typically engages an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed, noncontrolling interest, if any, and goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, we will record any material adjustments to the initial estimate based on new information obtained about facts and circumstances that existed as of the acquisition date. An income, market or cost valuation methodapproach may be utilized to estimate the fair value of the assets acquired, liabilities assumed, and noncontrolling interest, if any, in a business combination. We typically use an income approach, such as the multi-period excess earnings method, to value intangible assets. The income valuation method represents the present value ofapproach requires management to estimate future cash flows over the life of the asset using:flows: (i) discrete financial forecasts, which rely on management’smanagement's estimates of volumes, commodity prices, revenuegross margin and operating expenses; (ii) long-termterminal growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid forWe typically use a reasonably similar asset by other purchasers in the market, with adjustments relatingcost approach to any differences between the assets.value property, plant and equipment. The cost valuation methodapproach is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. See Note 43 – Acquisitions and Dispositions for additional information regarding our business combinations.
Accounting Pronouncements Recently Adopted
ASU No. 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business"
In January 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. The ASU also narrows the definition of the term "output" so that the term is consistent with how outputs are described under the revenue recognition guidance in Topic 606.
The amendments in ASU 2017-01 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2017. Early adoption is permitted in certain circumstances. We elected to adopt the guidance in ASU 2017-01 effective April 1, 2017. As a result of the early adoption of ASU 2017-01, TEP's acquisition of the Douglas Gathering System, as discussed in Note 4 – Acquisitions, was accounted for as an asset acquisition.
ASU No. 2017-04, "Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment"
In January 2017, the FASB issued ASU No. 2017-04, which simplifies the subsequent measurement of goodwill by eliminating "Step 2" from the goodwill impairment test, which involved calculating the implied fair value of goodwill by determining the fair value at the impairment testing date of a reporting unit's assets and liabilities. Instead, under the simplified test approach, an entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.
The amendments in ASU 2017-04 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We elected to adopt the guidance in ASU 2017-04 effective April 1, 2017, and as a result applied the new guidance to our annual goodwill impairment tests performed as of August 31, 2017.
ASU No. 2016-09, "Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting"
In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Among other changes, ASU 2016-09 allows an entity to make an entity-wide accounting policy election to either estimate the number of awards expected to vest (consistent with current GAAP) or account for forfeitures when they occur.
The amendments in ASU 2016-09 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2016. Early adoption is permitted. We adopted the guidance in ASU 2016-09 effective January 1, 2017 and made a policy election to account for forfeitures when they occur. The adoption of ASU 2016-09 did not have a material impact on our consolidated financial statements.
Accounting Pronouncements Not Yet Adopted
Revenue Recognition
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five-step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract.
Subsequent to issuing ASU 2014-09, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, and ASU No. 2017-13, Revenue Recognition (Topic 605), Revenue from Contracts with Customers (Topic 606), Leases (Topic 840), and Leases (Topic 842): Amendments to SEC Paragraphs Pursuant to the Staff Announcement at the July 20, 2017 EITF Meeting and Rescission of Prior SEC Staff Announcements and Observer Comments. The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, ASU 2016-20, and ASU 2017-13 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period.
Management has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2018. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to members' equity. Consolidated revenues presented in the comparative consolidated financial statements for periods prior to January 1, 2018 will not be revised.
On January 1, 2018, we recorded a cumulative effect adjustment to equity of $44.1 million, increased the carrying amount of our investment in Rockies Express by $42.8 million, and recognized a receivable from Rockies Express of $1.3 million. These adjustments relate to the cumulative effect adjustment recorded by Rockies Express of $125.2 million upon adoption of ASC 606. The cumulative effect adjustment at Rockies Express arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with tiered-pricing arrangements. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas during the periods prior to implementation.
Through our review process, we also identified the following changes to our revenue recognition policies that did not result in a cumulative effect adjustment on January 1, 2018:
Gathering & Processing. We have determined that a number of our gathering & processing contracts at TMID do not represent customer arrangements under ASC 606. Instead, arrangements deemed to represent wellhead purchases of raw gas will be accounted for as supply arrangements pursuant to ASC 705. As a result, gathering & processing fees previously recognized in revenue will be reported as a reduction to cost of sales under ASC 606.
Pipeline Loss Allowance. We have determined that pipeline loss allowance, or PLA, collected under certain crude oil transportation arrangements is a component of the transaction price where the PLA both significantly exceeds actual losses and was negotiated with the intent of providing a revenue stream to TEP. Under ASC 606, PLA barrels retained from customers will be subject to the guidance for noncash consideration and recognized in revenue at their contract inception fair value.
We anticipate significant changes to our disclosures based on the additional requirements prescribed by the standard. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities. Additionally, we are continuing to provide internal training and awareness related to the revised guidance to key stakeholders throughout our organization and evaluate our business processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new revenue guidance.
ASU No. 2016-02, "Leases (Topic 842)"
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing leaseright-of-use ("ROU") assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.
Management is currently evaluatingSubsequent to issuing ASU 2016-02, the impactFASB has issued a series of our pending adoption of ASC 842. The status of our implementation is as follows:
Management has formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain contract types, and project status.
Management is in the process of gathering data and reviewing contracts in order to identify all impacted contracts.
Management is evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from its contract review process.
Management plans to provide internal training and awareness relatedsubsequent updates to the revisedlease guidance in Topic 842, including ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to the key stakeholders throughout its organization.
Topic 842, ASU No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, and ASU 2018-20, Leases (Topic 842): Narrow-Scope Improvements for Lessors. The amendments in ASU 2016-02, ASU
2018-01, ASU 2018-10, ASU 2018-11, and ASU 2018-20 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted.
Management has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2019. The approach allows us to (i) initially apply ASC 842 at the adoption date, January 1, 2019 and (ii) continue reporting comparative periods presented in the financial statements in the period of adoption under ASC 840. We will not recast comparative periods in the consolidated financial statements. We have elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements as property, plant and equipment.
Adoption of the new standard resulted in the recognition of ROU assets and lease liabilities for operating leases as of January 1, 2019. Excluding ROU assets and lease liabilities relating to agreements between consolidated subsidiaries, the ROU assets and liabilities recognized as of January 1, 2019 are currently evaluating the impact of ASU 2016-02.not expected to be material. Our accounting for finance leases remained substantially unchanged.
3. VariableAcquisitions and Dispositions
Consolidation of BNN Colorado
Effective December 1, 2018, we obtained control of BNN Colorado Water, LLC ("BNN Colorado") through an amendment to the voting rights in BNN Colorado's limited liability company agreement. Prior to the amendment, we accounted for our interest in BNN Colorado under the equity method of accounting. The consolidation was accounted for as a business combination under ASC 805. No gain or loss was recognized on the remeasurement of our 63% membership interest as of December 1, 2018, as the carrying value was determined to approximate the fair value. The 37% equity interest in BNN Colorado held by noncontrolling interests was recorded at its acquisition date fair value of $10.1 million. These fair value measurements are based on significant inputs, such as forecasted cash flows and discount rates, that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820.
The following represents the fair value of assets acquired and liabilities assumed (in thousands):
|
| | | | |
| Accounts receivable | $ | 4,053 |
| |
| Property, plant and equipment | 18,535 |
| |
| Intangible asset | 7,922 |
| (1) |
| Accounts payable and accrued liabilities | (53 | ) | |
| Deferred revenue | (4,053 | ) | |
| Net identifiable assets acquired (excluding cash) | $ | 26,404 |
| |
| |
(1) | The $7.9 million intangible asset acquired represents a customer contract. This intangible asset is amortized on a straight-line basis over a period of approximately 3 years, the remaining term of the underlying contract at the time of acquisition. |
At December 31, 2018, the assets acquired and liabilities assumed were recorded at provisional amounts based on the preliminary purchase price allocation. We are in the process of identifying and measuring all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. Actual revenue and net loss attributable to TGE from BNN Colorado of less than $1.0 million was recognized in the accompanying consolidated statements of income for the period from December 1, 2018 to December 31, 2018.
Acquisitions of BNN North Dakota
In January 2018, we acquired 100% of the membership interests in Buckhorn Energy Services, LLC and Buckhorn SWD Solutions, LLC, which were subsequently merged and renamed BNN North Dakota, LLC ("BNN North Dakota"), for approximately $95.0 million, net of cash acquired. BNN North Dakota owns a produced water gathering and disposal system in the Bakken basin with approximately 133,000 acres under dedication. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.
The following represents the fair value of assets acquired and liabilities assumed (in thousands):
|
| | | | |
| Accounts receivable | $ | 2,457 |
| |
| Inventory | 67 |
| |
| Property, plant and equipment | 48,900 |
| |
| Intangible asset | 46,800 |
| (1) |
| Accounts payable and accrued liabilities | (3,224 | ) | |
| Net identifiable assets acquired (excluding cash) | $ | 95,000 |
| |
| |
(1) | The $46.8 million intangible asset acquired represents three major customer contracts. This intangible asset is amortized on a straight-line basis over a period of 8 - 14 years, the remaining terms of the underlying contracts at the time of acquisition. |
At March 31, 2018, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of June 30, 2018. Actual revenue and net income attributable to TGE from BNN North Dakota of $18.8 million and $4.7 million, respectively, was recognized in the accompanying consolidated statements of income for the period from January 12, 2018 to December 31, 2018.
In November 2018, we acquired 100% of the membership interests in NGL Water Solutions Bakken, LLC ("NGL Water Solutions Bakken"), a produced water disposal system in the Bakken basin, for cash consideration of approximately $91.0 million, subject to working capital adjustments. NGL Water Solutions Bakken was subsequently merged into BNN North Dakota. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.
The following represents the fair value of assets acquired and liabilities assumed (in thousands): |
| | | | |
| Accounts receivable | $ | 3,599 |
| |
| Prepayments and other current assets | 5 |
| |
| Property, plant and equipment | 17,200 |
| |
| Intangible asset | 54,000 |
| (1) |
| Accounts payable and accrued liabilities | (949 | ) | |
| Net identifiable assets acquired | 73,855 |
| |
| Goodwill | 17,145 |
| |
| Net assets acquired | $ | 91,000 |
| |
| |
(1) | The $54.0 million intangible asset acquired represents customer relationships and a customer contract. This intangible asset is amortized on a straight-line basis over a period of 3 - 8 years. |
At December 31, 2018, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. We are in the process of identifying and measuring all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. The goodwill recognized of $17.1 million is primarily attributed to synergies expected from combining the operations of TGE and NGL Water Solutions Bakken. All the goodwill was assigned to our Gathering, Processing & Terminalling segment. Actual revenue and net income attributable to TGE from NGL Water Solutions Bakken of $1.4 million and $0.5 million, respectively, was recognized in the accompanying consolidated statements of income for the period from November 30, 2018 to December 31, 2018.
Acquisition of Plaquemines Liquids Terminal, LLC
In November 2018, we entered into a joint venture agreement with Drexel Hamilton Infrastructure Fund I, L.P. ("DHIF") to jointly-own Plaquemines Liquids Terminal, LLC ("PLT"). PLT was formed with the intention of entering into agreements to develop a storage and terminalling facility. The facility is expected to offer up to 20 million barrels of storage for both crude oil and refined products and export facilities capable of loading Suezmax and Very Large Crude Carriers ("VLCC") vessels for international delivery. We made an initial cash contribution to PLT of $30.7 million in exchange for a 100% preferred membership interest and a 80% common membership interest in PLT. DHIF contributed any and all assets and rights related to PLT in exchange for a 20% common membership interest and the right to receive certain special distributions. Our preferred and common membership interests are considered to be a controlling financial interest and PLT was consolidated accordingly. The transaction has been accounted for as an asset acquisition, with substantially all the fair value allocated to the assets and
liabilities acquired based on their relative fair values. The intangible assets acquired, valued at approximately $35 million, relate to permits, designs, and other work-product related to the development and construction of a crude oil terminal facility in Louisiana. The liabilities recognized relate to DHIF's right to receive special distributions totaling $35 million. The special distributions are contingent upon PLT reaching certain milestones in the development and construction of the project facilities. Also in November 2018, PLT entered into an agreement with the Plaquemines Port & Harbor Terminal District to lease the land site on which PLT will construct the facilities.
Acquisition of Pawnee Terminal
In January 2018, we entered into an agreement to acquire a 51% membership interest in the Pawnee, Colorado crude oil terminal ("Pawnee Terminal") from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately $30.6 million. The transaction closed on April 1, 2018. As the 51% membership interest does not represent a controlling interest in Pawnee, our investment in Pawnee Terminal is recorded under the equity method of accounting and reported as "Unconsolidated investments" on the consolidated balance sheets.
Acquisitions of 75% Membership Interest Entitiesin Rockies Express and Additional TEP Common Units
In May 2016, TD assigned us its right to purchase a 25% membership interest in Rockies Express from a unit of Sempra U.S. Gas and Power ("Sempra") pursuant to the purchase agreement originally entered into between TD's wholly-owned subsidiary and Sempra in March 2016. Subsequently on May 6, 2016, we closed the purchase of a 25% membership interest in Rockies Express from Sempra pursuant to the purchase agreement for cash consideration of approximately $436.0 million, after making the adjustments to the purchase price required by the purchase agreement.
In March 2017, TEP, TD, and Rockies Express Holdings, LLC, entered into a definitive Purchase and Sale Agreement, pursuant to which TEP acquired an additional 24.99% membership interest in Rockies Express from TD in exchange for cash consideration of $400 million.
The 2017 transfer of the Rockies Express membership interest between TD and TEP is considered a VIEtransaction between entities under common control, but does not represent a change in reporting entity. As a result of which TEP GP, our consolidated subsidiary, is the primary beneficiary. We continue to consolidate TEP accordingly. We have not provided any additional financial support other than TEP GP's initial capitalcommon control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed contribution to acquirerepresenting the general partnerexcess carrying value of the 24.99% membership interest in TEP and have no contractual commitments or obligations to provide additional financial support to TEP.Rockies Express acquired over the fair value of the consideration paid. For further discussion, see Note 11 - Partnership Equity.
TEGP, as the managing memberIn February 2018, TD merged into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity has voting rights disproportionate("Tallgrass Development Holdings"), and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TGE and Tallgrass Equity issued 27,554,785 unregistered TGE Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to its ownership interest.the limited partners of TD. Subsequent to the closing of the transaction, our aggregate membership interest in Rockies Express is 75%.
The 2018 transfer of the Rockies Express membership interest between TD and Tallgrass Equity is considered a transaction between entities under common control, but does not represent a change in reporting entity. As a result we have determined that Tallgrassof the common control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed contribution representing the excess carrying value of the 25.01% membership interest in Rockies Express acquired over the fair value of the consideration paid. For further discussion, see Note 11 - Partnership Equity is. As the aggregate 75% membership interest does not represent a VIE of which we are the primary beneficiary and we consolidate Tallgrass Equity accordingly. We have not provided any additional financial support to Tallgrass Equity other than our initial capital contribution to acquire a portion of our controlling interest in Tallgrass EquityRockies Express, TGE's investment in Rockies Express is recorded under the equity method of accounting and have no contractual commitments or obligations to provide additional financial support to Tallgrass Equity.
Other than TEGP's deferred tax asset of approximately $313.0 million and $521.5 million at December 31, 2017 and December 31, 2016, respectively, the assets and liabilities included inis reported as "Unconsolidated investments" on our consolidated balance sheets at December 31, 2017sheets. For additional information, see Note 7 - Investments in Unconsolidated Affiliates.
The acquisition of an additional 5,619,218 TEP common units is considered an acquisition of noncontrolling interest and December 31, 2016 representresulted in the consolidated assetsrecognition of a noncash deemed distribution representing the excess purchase price over the $53.8 million carrying value of the 5,619,218 TEP common units acquired as of February 7, 2018. For further discussion, see Note 11 - Partnership Equity.
Acquisition and liabilities of Tallgrass Equity, including the assets and liabilities of TEP.
4. Acquisitions
TEP AcquisitionSale of Outrigger Powder River Operating, LLC
OnIn August 3, 2017, TEPwe acquired 100% of the membership interests of Outrigger Powder River Operating, LLC (subsequently renamed as Tallgrass Crude Gathering, LLC, "TCG"), which owns the PRB Crude System, a crude oil gathering system in the Powder River Basin with approximately 34 miles of gathering lines as of the acquisition date and approximately 150,000 acres dedicated on a long-term fee-based contract, for approximately $36 million. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.
The following represents the fair value of assets acquired and liabilities assumed at August 3, 2017 (in thousands):
|
| | | | |
| Accounts receivable | $ | 117 |
| |
| Property, plant and equipment | 29,306 |
| |
| Intangible asset | 6,694 |
| (1) |
| Accounts payable and accrued liabilities | (87 | ) | |
| Net identifiable assets acquired | $ | 36,030 |
| |
| |
(1) | The $6.7 million intangible asset acquired represents a major customer contract. This intangible asset is amortized on a straight-line basis over a period of 8 years, the remaining term of the contract at the time of acquisition. |
At September 30, 2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of December 31, 2017. Actual revenue and net loss attributable to TEPTGE from TCG of less than $1 million was recognized in the accompanying consolidated statements of income for the period from August 3, 2017 to December 31, 2017.
TEP In February 2018, we entered into an agreement with an affiliate of Silver Creek Midstream, LLC ("Silver Creek") to sell our 100% membership interest in TCG, for approximately $50.0 million. The sale of TCG closed on February 23, 2018. During the year ended December 31, 2018, we recognized a gain of $9.4 million on the sale which is presented in the line item "Gain on disposal of assets" in the consolidated statements of income.
Joint Venture with Silver Creek
In February 2018, we entered into an agreement with Silver Creek to form Iron Horse Pipeline, LLC ("Iron Horse"), which owns a new 80-mile crude oil pipeline currently under construction that will transport crude oil from the Powder River Basin to Guernsey, Wyoming ("Iron Horse Pipeline"). During the year ended December 31, 2018, we contributed an initial $3.5 million and committed to funding our proportionate share of the remaining costs of construction in exchange for a 75% membership interest in Iron Horse. As the 75% membership interest does not represent a controlling interest in Iron Horse, our investment in Iron Horse is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the consolidated balance sheets.
In August 2018, we entered into an agreement with Silver Creek to expand the Iron Horse joint venture through the contribution by us and Silver Creek of cash and additional Powder River Basin assets. These additional contributions closed in January 2019. We contributed our 75% membership interest in Iron Horse, $37 million in cash, and various other assets, including terminal facilities currently under construction in Guernsey, Wyoming. Silver Creek contributed the Powder River Express Pipeline ("PRE Pipeline") and their 25% membership interest in Iron Horse. The expanded joint venture operates under the name Powder River Gateway, LLC ("Powder River Gateway"), and owns the Iron Horse Pipeline, the PRE Pipeline, a 70-mile crude oil pipeline that transports crude oil from the Powder River Basin to Guernsey, Wyoming, and crude oil terminal facilities in Guernsey, Wyoming. Effective January 1, 2019, we own a 51% membership interest in Powder River Gateway and continue to operate the joint venture, while Silver Creek owns a 49% membership interest.
Acquisitions of Additional Interests in Deeprock Development, LLC
OnIn July 20, 2017, TEPwe acquired an additional 40% membership interest in Deeprock Development from Kinder Morgan Cushing, LLC for cash consideration of approximately $57.2 million, net of cash acquired. TEPWe subsequently acquired an additional 9% membership interest in Deeprock Development from Deeprock Energy Resources LLC ("DER") on July 21, 2017, as discussed further below.
Upon closing of the acquisition of the 40% membership interest on July 20, 2017, TEPwe obtained a controlling financial interest in Deeprock Development and accordingly have accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, TEPwe remeasured itsour previously held 20% equity interest in Deeprock Development to its fair value of $22.9 million, recognized a gain of $9.7 million in "Gain on remeasurement of unconsolidated investment" in the consolidated statements of income, and consolidated Deeprock Development in itsour consolidated financial statements. The 40% equity interest in Deeprock Development held by noncontrolling interests was recorded at its acquisition date fair value of $45.9 million. The fair values of the previously held equity interest and the noncontrolling interest were determined using a discounted cash flow analysis and adjusted for lack of control. These fair value measurements are based on significant inputs, such as forecasted cash flows and discount rates, that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820.
The following represents the fair value of assets acquired and liabilities assumed at July 20, 2017 (in thousands):
|
| | | |
| Accounts receivable | $ | 968 |
|
| Other current assets | 598 |
|
| Property, plant and equipment | 70,148 |
|
| Accounts payable | (712 | ) |
| Deferred revenue | (6,546 | ) |
| Net identifiable assets acquired | 64,456 |
|
| Goodwill | 61,550 |
|
| Net assets acquired (excluding cash) | $ | 126,006 |
|
At September 30, 2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of December 31, 2017. The goodwill recognized of $61.6 million is primarily attributed to synergies expected from combining our operations with the operations of TEP and Deeprock Development. All the goodwill was assigned to our Gathering, Processing & Terminalling segment. Actual revenue and net income attributable to TEPTGE from Deeprock Development of $10.5 million and $8.5$0.9 million, respectively, was recognized in the accompanying consolidated statements of income for the period from July 20, 2017 to December 31, 2017.
OnIn July 21, 2017, subsequent to the acquisition of an additional 40% membership interest discussed above, TEPwe acquired an additional 9% membership interest in Deeprock Development from DER for total consideration valued at approximately $13.1 million, consisting of approximately $6.4 million in cash and the issuance of 128,790 TEP common units (valued at approximately $6.7 million based on the July 20, 2017 closing price of TEP's common units), which was accounted for as an acquisition of noncontrolling interest. Subsequent to the closing of the transaction, our aggregate membership interest in Deeprock Development is 69%.
TEP Acquisition of Deeprock North and Merger with Deeprock Development
In January 2018, we acquired an approximate 38% membership interest in Deeprock North, LLC ("Deeprock North") from Kinder Morgan Deeprock North Holdco LLC for cash consideration of $19.5 million. Immediately following the acquisition, Deeprock North was merged into Deeprock Development, and the members of Deeprock North and Deeprock Development received adjusted membership interests in the combined entity. As a result, we recognized additional noncontrolling interests in Deeprock Development of $31.8 million. The acquisition of Deeprock North by Deeprock Development has been accounted for as an asset acquisition, with substantially all of the fair value allocated to the long-lived assets acquired based on their relative fair values. After the acquisition and merger, we own an approximate 60% membership interest in the combined entity.
Acquisition of DCP Douglas, LLC
OnIn June 5, 2017, TEPwe acquired 100% of the membership interests in DCP Douglas, LLC (subsequently renamed as Tallgrass Midstream Gathering, LLC), which owns the Douglas Gathering System, a natural gas gathering system in the Powder River Basin with approximately 1,500 miles of gathering pipeline connected to the Douglas processing plant, for approximately $128.5 million, subject to working capital adjustments.million. The acquisition has been accounted for as an asset acquisition, with substantially all the fair value allocated to the long-lived assets acquired based on their relative fair values.
TEP Acquisitions of 49.99% in Rockies Express Pipeline LLC
On May 6, 2016, TD assigned us its right to purchase a 25% membership interest in Rockies Express from a unit of Sempra U.S. Gas and Power ("Sempra") pursuant to the purchase agreement originally entered into between TD's wholly-owned subsidiary and Sempra in March 2016. Subsequently on May 6, 2016, we closed the purchase of a 25% membership interest in Rockies Express from Sempra pursuant to the purchase agreement for cash consideration of approximately $436.0 million, after making the adjustments to the purchase price required by the purchase agreement.
On March 31, 2017, TEP, TD, and Rockies Express Holdings, LLC, entered into a definitive Purchase and Sale Agreement, pursuant to which TEP acquired an additional 24.99% membership interest in Rockies Express from TD in exchange for cash consideration of $400 million. Together with the 25% membership interest in Rockies Express that TEP acquired from a unit of Sempra U.S. Gas and Power on May 6, 2016, this transaction increases TEP’s aggregate membership interest in Rockies Express to 49.99%. For additional information, see Note 9 – Investments in Unconsolidated Affiliates.
TEP's Acquisition of Tallgrass Terminals, LLC and Tallgrass NatGas Operator, LLC
EffectiveIn January 1, 2017, TEPwe acquired 100% of the issued and outstanding membership interests in Terminals and 100% of the issued and outstanding membership interests in NatGas from TD for total cash consideration of $140 million. These acquisitions are considered transactions between entities under common control, and a change in reporting entity.
Terminals owns several fully operational assets providing storage capacity and additional injection points for As a result of the Pony Express System, includingcommon control nature of the Sterling Terminal near Sterling, Colorado,transaction, the Buckingham Terminal in northeast Colorado, and a 69% interestacquisitions resulted in the Deeprock Development Terminal in Cushing, Oklahoma followingrecognition of a noncash deemed distribution representing the acquisition of an aggregate additional 49% membership interest in Deeprock Development in July 2017 discussed above. Terminals also owns acreage in Cushing, Oklahoma and Guernsey, Wyoming, which is under development to provide additional storage capacity and other potential opportunities.
NatGas is the operatorexcess fair value of the Rockies Express Pipelineconsideration paid over the carrying value of Terminals and receives a fee from Rockies Express as compensation for its services.NatGas net assets acquired. For further discussion, see Note 11 - Partnership Equity.
TEP Acquisitions of 100% of Pony Express
Effective September 1, 2014, TEP acquired a controlling 33.3% membership interest in Pony Express for total consideration of approximately $600 million. At closing, Pony Express, TD, and TEP entered into the Second Amended Pony Express LLC Agreement, which set forth the relative rights of TD and TEP as the owners of Pony Express. The terms of TEP's acquisition of a 33.3% membership interest in Pony Express provided TEP a minimum quarterly preference payment of $16.65 million through the quarter ended September 30, 2015 with distributions thereafter shared in accordance with the terms of the Second Amended Pony Express LLC Agreement.
Effective March 1, 2015, TEP acquired an additional 33.3% membership interest in Pony Express for cash consideration of $700 million. At closing, Pony Express, TD, and TEP entered into the Pony Express LLC Agreement, which sets forth the relative rights of TD and TEP as the owners of Pony Express. The terms of the transaction increased the minimum quarterly preference payment provided to TEP to $36.65 million through the quarter ending December 31, 2015 (prorated to approximately $23.5 million for the quarter ended March 31, 2015) with distributions thereafter shared in accordance with the terms of the Pony Express LLC Agreement.
Upon the effective date of the second acquisition, TEP reevaluated its VIE assessment and determined that Pony Express continued to be considered a VIE of which TEP is the primary beneficiary. The acquisition of the additional 33.3% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction have not been recast to reflect the additional 33.3% membership interest. The transaction resulted in a deemed distribution to our general partner as discussed further in Note 12 – Partnership Equity and Distributions.
EffectiveIn January 1, 2016, TEPwe acquired an additional 31.3% membership interest in Pony Express in exchange for cash consideration of $475 million and 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015 closing price of our common units) issued to TD, for total consideration of approximately $743.6 million. The transaction increased our aggregate membership interest in Pony Express to 98%. effective January 1, 2016. As part of the transaction, TD granted us an 18-month call option covering the newly issued 6,518,000 common units at a price of $42.50. On the effective date of the acquisition, the call option was valued at $46.0 million. As discussed in Note 109 – Risk Management, in July 2016
and October 2016, we partially exercised the option covering 3,563,146 and 1,251,760 of the common units, respectively. OnIn February 1, 2017, we exercised the remainder of the call option covering an additional 1,703,094 common units, leaving no remaining common units subject to the call option as of such date. As a result of the partial exercises in 2016 and 2017, TEPwe derecognized a portion of the derivative asset balance, recognizing approximately $34.0 million and $12.6 million through equity for the years ended December 31, 2016 and 2017, respectively, as discussed further in Note 129 – Partnership Equity and DistributionsRisk Management.
The acquisition of the additional 31.3% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction has not been recast to reflect the additional 31.3% membership interest. TheAs a result of the common control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed distribution to our general partner as discussedrepresenting the excess fair value of the consideration paid over the carrying value of the 31.3% membership interest in Pony Express acquired. For further indiscussion, see Note 12 –11 - Partnership Equity and Distributions.
Cash outflows to acquire an additional noncontrolling interest in Pony Express are classified as an investing activity in the accompanying consolidated statements of cash flows to the extent the consideration paid was used to directly fund the construction of the underlying assets by the noncontrolling member. Cash outflows to acquire an additional noncontrolling interest in excess of the cost to construct the underlying assets are classified as financing activities. For the year ended December 31, 2016, $49.1 million of the $475 million paid to acquire the additional 31.3% membership interest in Pony Express was classified as an investing activity and $425.9 million was classified as a financing activity.
As discussed in Note 22 – Subsequent Events, TEPIn February 2018, we acquired the remaining 2% ofmembership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from TD effective February 1, 2018.
TEP Acquisition of BNN Western, LLC
On December 16, 2015, Whiting Oil and Gas Corporation ("Whiting"), BNN Redtail, LLC ("Redtail"), and BNN Western, LLC ("Western"), a newly formed Delaware limited liability company, entered into a definitive Transfer, Purchase and Sale Agreement, pursuant to which Redtail acquired 100% of the outstanding membership interests of Western from Whiting in exchange for total cash consideration of $75 million. Western's assets consistapproximately $60 million, bringing our aggregate membership interest in Pony Express to 100%. The acquisition of the remaining 2% membership interest in Pony Express represents a fresh water deliverytransaction between entities under common control and storage system and produced water gathering and produced water disposal system, which together comprise 62 milesan acquisition of pipeline along with associated fresh water ponds and disposal wells.noncontrolling interests. As parta result, financial information for periods prior to the transaction has not been recast to reflect the additional 2% membership interest. As a result of the common control nature of the transaction, with Whiting, Whiting also executed a five-year fresh water service contract and a nine-year gathering and disposal contract, each of which commenced in December 2015.
At December 31, 2015, the assets acquired and liabilities assumedacquisition resulted in the acquisition were recorded at provisional amounts based onrecognition of a noncash deemed distribution representing the preliminary purchase price allocation. The $75 million purchase priceexcess fair value of the assets was allocated entirely to property, plant and equipment. No adjustments were made to these provisional amounts andconsideration paid over the allocationcarrying value of assets acquired and liabilities assumedthe 2% membership interest in the acquisition was considered final as of September 30, 2016.Pony Express acquired. For further discussion, see Note 11 – Partnership Equity.
Pro Forma Financial Information
Unaudited pro forma revenue and net income (loss) attributable to TEGPTGE for the years ended December 31, 2018 and 2017 is presented below as if the acquisitions of BNN North Dakota, NGL Water Solutions Bakken, and BNN Colorado had been completed on January 1, 2017. Unaudited pro forma revenue and net (loss) income attributable to TGE for the years ended December 31, 2017 and 2016 is presented below as if the acquisitions of TCG and Deeprock Development had been completed on January 1, 2016. Unaudited pro forma revenue and net income attributable to TEGP for the year ended December 31, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015.
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
| Revenue | $ | 667,391 |
| | $ | 632,528 |
| | $ | 544,497 |
| $ | 813,286 |
| | $ | 686,803 |
| | $ | 632,528 |
|
| Net (loss) income attributable to TEGP | $ | (129,401 | ) | | $ | 34,311 |
| | $ | 44,379 |
| |
| Net income (loss) attributable to TGE | | $ | 140,005 |
| | $ | (129,155 | ) | | $ | 34,311 |
|
The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TEGPTGE would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they purport to project the results of operations or financial position of TEGPTGE for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements. The pro forma revenue and net income (loss) includes adjustments to give effect to the estimated results of operations of BNN North Dakota, NGL Water Solutions Bakken, BNN Colorado, TCG, and Deeprock Development and Western for the periods presented, as well aspresented. The pro forma net income (loss) also includes adjustments to eliminate the equity in earnings and gain on remeasurement of unconsolidated investment associated with our previously held 20% membership interest in Deeprock Development.Development and to eliminate the equity in earnings associated with our 63% membership interest in BNN Colorado which was previously accounted for as an equity method investment.
Historical Financial Information
The results of our acquisitions of Terminals and NatGas are included in the consolidated balance sheets as of December 31, 20172018 and December 31, 2016. The following table presents our previously reported December 31, 2016 consolidated balance sheet, adjusted for the acquisitions of Terminals2017 and NatGas:
|
| | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | TEGP (As previously reported) | | Consolidate Terminals | | Consolidate NatGas | | TEGP (As currently reported) |
| | (in thousands) |
| ASSETS | | | | | |
| Current Assets: | | | | | | | |
| Cash and cash equivalents | $ | 2,459 |
| | $ | — |
| | $ | — |
| | $ | 2,459 |
|
| Accounts receivable, net | 59,469 |
| | 38 |
| | 29 |
| | 59,536 |
|
| Gas imbalances | 1,597 |
| | — |
| | — |
| | 1,597 |
|
| Inventories | 12,805 |
| | 288 |
| | — |
| | 13,093 |
|
| Derivative assets | 10,967 |
| | — |
| | — |
| | 10,967 |
|
| Prepayments and other current assets | 6,820 |
| | 808 |
| | — |
| | 7,628 |
|
| Total Current Assets | 94,117 |
| | 1,134 |
| | 29 |
| | 95,280 |
|
| Property, plant and equipment, net | 2,012,263 |
| | 66,969 |
| | — |
| | 2,079,232 |
|
| Goodwill | 343,288 |
| | — |
| | — |
| | 343,288 |
|
| Intangible assets, net | 93,522 |
| | — |
| | — |
| | 93,522 |
|
| Unconsolidated investments | 461,915 |
| | 13,710 |
| | — |
| | 475,625 |
|
| Deferred tax asset | 521,454 |
| | — |
| | — |
| | 521,454 |
|
| Deferred financing costs, net | 6,042 |
| | — |
| | — |
| | 6,042 |
|
| Deferred charges and other assets | 9,637 |
| | 1,400 |
| | — |
| | 11,037 |
|
| Total Assets | $ | 3,542,238 |
| | $ | 83,213 |
| | $ | 29 |
| | $ | 3,625,480 |
|
| LIABILITIES AND EQUITY | | | | | | | |
| Current Liabilities: | | | | | | | |
| Accounts payable | $ | 24,403 |
| | $ | 46 |
| | $ | — |
| | $ | 24,449 |
|
| Accounts payable to related parties | 5,768 |
| | 56 |
| | — |
| | 5,824 |
|
| Gas imbalances | 1,239 |
| | — |
| | — |
| | 1,239 |
|
| Derivative liabilities | 556 |
| | — |
| | — |
| | 556 |
|
| Accrued taxes | 16,328 |
| | 668 |
| | — |
| | 16,996 |
|
| Accrued liabilities | 16,578 |
| | 177 |
| | — |
| | 16,755 |
|
| Deferred revenue | 60,757 |
| | — |
| | — |
| | 60,757 |
|
| Other current liabilities | 6,446 |
| | — |
| | — |
| | 6,446 |
|
| Total Current Liabilities | 132,075 |
| | 947 |
| | — |
| | 133,022 |
|
| Long-term debt, net | 1,555,981 |
| | — |
| | — |
| | 1,555,981 |
|
| Other long-term liabilities and deferred credits | 7,063 |
| | — |
| | — |
| | 7,063 |
|
| Total Long-term Liabilities | 1,563,044 |
| | — |
| | — |
| | 1,563,044 |
|
| Equity: | | | | | | | |
| Net Equity | 1,847,119 |
| | 82,266 |
| | 29 |
| | 1,929,414 |
|
| Total Equity | 1,847,119 |
| | 82,266 |
| | 29 |
| | 1,929,414 |
|
| Total Liabilities and Equity | $ | 3,542,238 |
| | $ | 83,213 |
| | $ | 29 |
| | $ | 3,625,480 |
|
The results of our acquisitions of Terminals and NatGas are included in the consolidated statements of income for the years ended December 31, 2018, 2017, 2016, and 2015.2016. The following tables presenttable presents the previously reported consolidated statements of income for the yearsyear ended December 31, 2016 and 2015, adjusted for the acquisitions of Terminals and NatGas:
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | TEGP (As previously reported) | | Consolidate Terminals | | Consolidate NatGas | | Elimination | | TEGP (As currently reported) |
| | (in thousands) |
| Revenues: | | | | | | | | | |
| Crude oil transportation services | $ | 374,949 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 374,949 |
|
| Natural gas transportation services | 119,962 |
| | — |
| | — |
| | — |
| | 119,962 |
|
| Sales of natural gas, NGLs, and crude oil | 77,394 |
| | 99 |
| | — |
| | (370 | ) | (1) | 77,123 |
|
| Processing and other revenues | 32,817 |
| | 12,043 |
| | 6,228 |
| | (11,460 | ) | (2) | 39,628 |
|
| Total Revenues | 605,122 |
| | 12,142 |
| | 6,228 |
| | (11,830 | ) | | 611,662 |
|
| Operating Costs and Expenses: | | | | | | | | | |
| Cost of sales | 71,920 |
| | 100 |
| | — |
| | (370 | ) | (1) | 71,650 |
|
| Cost of transportation services | 58,341 |
| | 788 |
| | — |
| | (11,460 | ) | (2) | 47,669 |
|
| Operations and maintenance | 53,386 |
| | 1,684 |
| | — |
| | — |
| | 55,070 |
|
| Depreciation and amortization | 84,896 |
| | 1,351 |
| | — |
| | — |
| | 86,247 |
|
| General and administrative | 55,829 |
| | 1,469 |
| | — |
| | — |
| | 57,298 |
|
| Taxes, other than income taxes | 24,727 |
| | 673 |
| | — |
| | — |
| | 25,400 |
|
| Contract termination | — |
| | 8,061 |
| (3) | — |
| | — |
| | 8,061 |
|
| Loss on disposal of assets | 1,849 |
| | — |
| | — |
| | — |
| | 1,849 |
|
| Total Operating Costs and Expenses | 350,948 |
| | 14,126 |
| | — |
| | (11,830 | ) | | 353,244 |
|
| Operating Income (Expense) | 254,174 |
| | (1,984 | ) | | 6,228 |
| | — |
| | 258,418 |
|
| Other Income (Expense): | | | | | | | | | |
| Interest expense, net | (45,601 | ) | | — |
| | — |
| | — |
| | (45,601 | ) |
| Unrealized loss on derivative instrument | (1,291 | ) | | — |
| | — |
| | — |
| | (1,291 | ) |
| Equity in earnings of unconsolidated investments | 51,780 |
| | 2,751 |
| | — |
| | — |
| | 54,531 |
|
| Other income, net | 1,723 |
| | — |
| | — |
| | — |
| | 1,723 |
|
| Total Other Income | 6,611 |
| | 2,751 |
| | — |
| | — |
| | 9,362 |
|
| Net income before tax | 260,785 |
| | 767 |
| | 6,228 |
| | — |
| | 267,780 |
|
| Deferred income tax expense | (17,741 | ) | | — |
| | — |
| | — |
| | (17,741 | ) |
| Net income | 243,044 |
| | 767 |
| | 6,228 |
| | — |
| | 250,039 |
|
| Net income attributable to noncontrolling interests | (216,250 | ) | | — |
| | — |
| | — |
| | (216,250 | ) |
| Net income attributable to TEGP | $ | 26,794 |
| | $ | 767 |
| | $ | 6,228 |
| | $ | — |
| | $ | 33,789 |
|
| | | | Year Ended December 31, 2015 | Year Ended December 31, 2016 |
| | TEGP (As previously reported) | | Consolidate Terminals | | Consolidate NatGas | | Elimination | | TEGP (As currently reported) | TGE (As previously reported) | | Consolidate Terminals | | Consolidate NatGas | | Elimination | | TGE (As currently reported) |
| | (in thousands) | (in thousands) |
| Revenues: | | | | | | | | | | | | | | | | | | |
| Crude oil transportation services | $ | 300,436 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 300,436 |
| $ | 374,949 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 374,949 |
|
| Natural gas transportation services | 119,895 |
| | — |
| | — |
| | — |
| | 119,895 |
| 119,962 |
| | — |
| | — |
| | — |
| | 119,962 |
|
| Sales of natural gas, NGLs, and crude oil | 82,133 |
| | — |
| | — |
| | — |
| | 82,133 |
| 77,394 |
| | 99 |
| | — |
| | (370 | ) | (1) | 77,123 |
|
| Processing and other revenues | 33,733 |
| | 7,689 |
| | 6,332 |
| | (7,557 | ) | (2) | 40,197 |
| 32,817 |
| | 12,043 |
| | 6,228 |
| | (11,460 | ) | (2) | 39,628 |
|
| Total Revenues | 536,197 |
| | 7,689 |
| | 6,332 |
| | (7,557 | ) | | 542,661 |
| 605,122 |
| | 12,142 |
| | 6,228 |
| | (11,830 | ) | | 611,662 |
|
| Operating Costs and Expenses: | | | | | | | | | | | | | | | | | | |
| Cost of sales | 75,285 |
| | — |
| | — |
| | — |
| | 75,285 |
| 71,920 |
| | 100 |
| | — |
| | (370 | ) | (1) | 71,650 |
|
| Cost of transportation services | 53,597 |
| | 800 |
| | — |
| | (7,557 | ) | (2) | 46,840 |
| 58,341 |
| | 788 |
| | — |
| | (11,460 | ) | (2) | 47,669 |
|
| Operations and maintenance | 49,138 |
| | 1,685 |
| | — |
| | — |
| | 50,823 |
| 53,386 |
| | 1,684 |
| | — |
| | — |
| | 55,070 |
|
| Depreciation and amortization | 83,476 |
| | 782 |
| | — |
| | — |
| | 84,258 |
| 84,896 |
| | 1,351 |
| | — |
| | — |
| | 86,247 |
|
| General and administrative | 51,479 |
| | 1,156 |
| | — |
| | — |
| | 52,635 |
| 55,829 |
| | 1,469 |
| | — |
| | — |
| | 57,298 |
|
| Taxes, other than income taxes | 21,796 |
| | — |
| | — |
| | — |
| | 21,796 |
| 24,727 |
| | 673 |
| | — |
| | — |
| | 25,400 |
|
| Contract termination | | — |
| | 8,061 |
| (3) | — |
| | — |
| | 8,061 |
|
| Loss on disposal of assets | 4,795 |
| | — |
| | — |
| | — |
| | 4,795 |
| 1,849 |
| | — |
| | — |
| | — |
| | 1,849 |
|
| Total Operating Costs and Expenses | 339,566 |
| | 4,423 |
| | — |
| | (7,557 | ) | | 336,432 |
| 350,948 |
| | 14,126 |
| | — |
| | (11,830 | ) | | 353,244 |
|
| Operating Income | 196,631 |
| | 3,266 |
| | 6,332 |
| | — |
| | 206,229 |
| |
| Operating Income (Expense) | | 254,174 |
| | (1,984 | ) | | 6,228 |
| | — |
| | 258,418 |
|
| Other Income (Expense): | | | | | | | | | | | | | | | | | | |
| Equity in earnings of unconsolidated investments | | 51,780 |
| | 2,751 |
| | — |
| | — |
| | 54,531 |
|
| Interest expense, net | (18,330 | ) | | — |
| | — |
| | — |
| | (18,330 | ) | (45,601 | ) | | — |
| | — |
| | — |
| | (45,601 | ) |
| Equity in earnings of unconsolidated investments | — |
| | 2,759 |
| | — |
| | — |
| | 2,759 |
| |
| Other income, net | 2,413 |
| | — |
| | — |
| | — |
| | 2,413 |
| 432 |
| | — |
| | — |
| | — |
| | 432 |
|
| Total Other (Expense) Income | (15,917 | ) | | 2,759 |
| | — |
| | — |
| | (13,158 | ) | |
| Total Other Income | | 6,611 |
| | 2,751 |
| | — |
| | — |
| | 9,362 |
|
| Net income before tax | 180,714 |
| | 6,025 |
| | 6,332 |
| | — |
| | 193,071 |
| 260,785 |
| | 767 |
| | 6,228 |
| | — |
| | 267,780 |
|
| Deferred income tax benefit | 7,277 |
| | — |
| | — |
| | — |
| | 7,277 |
| |
| Deferred income tax expense | | (17,741 | ) | | — |
| | — |
| | — |
| | (17,741 | ) |
| Net income | 187,991 |
| | 6,025 |
| | 6,332 |
| | — |
| | 200,348 |
| 243,044 |
| | 767 |
| | 6,228 |
| | — |
| | 250,039 |
|
| Net income attributable to noncontrolling interests | (156,035 | ) | | — |
| | — |
| | — |
| | (156,035 | ) | (216,250 | ) | | — |
| | — |
| | — |
| | (216,250 | ) |
| Net income attributable to TEGP | $ | 31,956 |
| | $ | 6,025 |
| | $ | 6,332 |
| | $ | — |
| | $ | 44,313 |
| |
| Net income attributable to TGE | | $ | 26,794 |
| | $ | 767 |
| | $ | 6,228 |
| | $ | — |
| | $ | 33,789 |
|
| |
(1) | Represents the elimination of revenue and cost of sales associated with the purchase of crude oil from Pony Express by Terminals. |
| |
(2) | Represents the elimination of revenue and cost of transportation services associated with the lease of the Sterling Terminal facilities by Pony Express. |
| |
(3) | Represents a one-time charge related to the termination of an operating agreement at the Sterling Terminal. |
5.4. Related Party Transactions
As a result of our relationship with Tallgrass Energy Holdings, LLC ("Tallgrass Energy Holdings") and its affiliates, we have entered into a number of related party transactions. The following disclosure includes those related party transactions which are not otherwise disclosed in these notes to our consolidated financial statements.
We have no employees.All of our employees are employed by Tallgrass Management, LLC ("Tallgrass Management"). Prior to July 1, 2018, Tallgrass Management was a wholly-owned subsidiary of Tallgrass Energy Holdings. In connection with the closing of the TEP initial public offering on May 17, 2013, TEP and its general partnerTEP GP entered into an Omnibus Agreement with Tallgrass Energy Holdings and certain of its affiliates (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse Tallgrass Energy Holdings and its affiliates for all expenses they incur and payments they make on TEP's behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain centralized corporate functions performed by Tallgrass Energy Holdings and its affiliates, including legal, accounting, cash management, insurance administration and
claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP. In addition, in connection with the closing of ourthe TGE initial public offering on May 12, 2015 (the "TEGP"TGE IPO"), TEGPTGE entered into an Omnibus Agreement (the "TEGP"TGE Omnibus Agreement") with Tallgrass Energy GP, LLC (formerly known as TEGP Management, LLC,LLC), Tallgrass Equity and Tallgrass Energy Holdings.
PursuantEffective July 1, 2018, Tallgrass Management was contributed to the TEGP Omnibus Agreement, Tallgrass Equity paysin connection with the TEP Merger. As a reimbursement toresult, the costs of employer and director compensation and benefits are now incurred directly by Tallgrass Energy Holdings for costs associated with TEGP being a public company beginning in the second quarter of 2015, which was $2.0 million for the year ended December 31, 2017. This amount is periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEGP.
Due to the cash management agreement discussed in Note 2 – Summary of Significant Accounting Policies, intercompany balances at the Predecessor Entities were periodically settled and treated as equity distributions prior to January 1, 2017 for Terminals and NatGas. Balances lent to TD under the Pony Express cash management agreement effective September 1, 2014 were classified as related party receivables in the consolidated balance sheets. There was no interest income from TD recognized for the years ended December 31, 2017 and 2016. During the year ended December 31, 2015 we recognized interest income from TD of $0.4 million on the receivable balance under the Pony Express cash management agreement in effect through December 31, 2015.Equity.
Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
Processing and other revenues (1) | $ | 8,516 |
| | $ | 6,228 |
| | $ | 6,331 |
| $ | 7,483 |
| | $ | 8,516 |
| | $ | 6,228 |
|
Cost of transportation services (2) | $ | 10,476 |
| | $ | 18,585 |
| | $ | 18,288 |
| $ | — |
| | $ | 10,476 |
| | $ | 18,585 |
|
Charges to TEGP: (3) | | | | | | |
Charges to TGE: (3) | | | | | | |
| Property, plant and equipment, net | $ | 2,679 |
| | $ | 3,084 |
| | $ | 4,342 |
| $ | — |
| | $ | 2,679 |
| | $ | 3,084 |
|
| Other deferred charges | $ | 25 |
| | $ | 44 |
| | $ | 7 |
| $ | — |
| | $ | 25 |
| | $ | 44 |
|
| Operations and maintenance | $ | 29,881 |
| | $ | 25,431 |
| | $ | 23,658 |
| $ | — |
| | $ | 29,881 |
| | $ | 25,431 |
|
| General and administrative | $ | 41,676 |
| | $ | 40,321 |
| | $ | 34,779 |
| $ | — |
| | $ | 41,676 |
| | $ | 40,321 |
|
| |
(1) | Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline. |
| |
(2) | Reflects rent expense for the crude oil storage at the Deeprock Terminal prior to our consolidation of Deeprock Development during the third quarter of 2017, as discussed in Note 43 – Acquisitions and Dispositions. |
| |
(3) | Charges to TEGP,TGE, inclusive of Tallgrass Equity and TEP, include directlyindirectly charged wages and salaries, other compensation and benefits, and shared services.services for periods prior to January 1, 2018. Effective January 1, 2018, these costs are incurred by TEP directly and, in the case of certain employee compensation and benefits, paid on TEP's behalf by its affiliate, Tallgrass Management, LLC, pursuant to the TEP Omnibus Agreement. |
Details of balances with affiliates included in "Accounts receivable, net" and "Accounts payable to related parties"payable" in the consolidated balance sheets are as follows:
| | | | December 31, 2017 | | December 31, 2016 | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
| Receivable from related parties: | | | | | | |
| Rockies Express Pipeline LLC | $ | 1,340 |
| | $ | 590 |
| $ | 3,447 |
| | $ | 1,340 |
|
| Iron Horse Pipeline, LLC | | 186 |
| | — |
|
| Pawnee Terminal, LLC | | 115 |
| | — |
|
| Total receivable from related parties | $ | 1,340 |
| | $ | 590 |
| $ | 3,748 |
| | $ | 1,340 |
|
| Accounts payable to related parties: | | | | | | |
| Tallgrass Operations, LLC | $ | 5,342 |
| | $ | 5,811 |
| |
| Deeprock Development, LLC | — |
| | 13 |
| |
Tallgrass Operations, LLC (1) | | $ | — |
| | $ | 5,342 |
|
| Total accounts payable to related parties | $ | 5,342 |
|
| $ | 5,824 |
| $ | — |
|
| $ | 5,342 |
|
| |
(1) | Reflects accounts payable for charges to TGE, inclusive of Tallgrass Equity and TEP, including indirectly charged wages and salaries, other compensation and benefits, and shared services prior to January 1, 2018 as discussed above. |
Gas imbalances with affiliated shippers are as follows:
| | | | December 31, 2017 | | December 31, 2016 | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
| Affiliate gas imbalance receivables | $ | 18 |
| | $ | 177 |
| $ | 19 |
| | $ | 18 |
|
| Affiliate gas imbalance payables | $ | 442 |
| | $ | — |
| $ | 742 |
| | $ | 442 |
|
6.5. Inventory
The components of inventory at December 31, 20172018 and 20162017 consisted of the following:
| | | | December 31, 2017 | | December 31, 2016 | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
| Crude oil | $ | 12,792 |
| | $ | 5,462 |
| $ | 23,205 |
| | $ | 12,792 |
|
| Materials and supplies | 5,891 |
| | 6,383 |
| 8,206 |
| | 5,891 |
|
| Gas in underground storage | | 2,740 |
| | 1,984 |
|
| Natural gas liquids | 942 |
| | 265 |
| 165 |
| | 942 |
|
| Gas in underground storage | 1,984 |
| | 983 |
| |
| Total inventory | $ | 21,609 |
| | $ | 13,093 |
| $ | 34,316 |
| | $ | 21,609 |
|
7.6. Property, Plant and Equipment
A summary of net property, plant and equipment by classification is as follows:
| | | | December 31, 2017 | | December 31, 2016 | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
| Crude oil pipelines | $ | 1,220,379 |
| | $ | 1,202,125 |
| $ | 1,313,976 |
| | $ | 1,220,379 |
|
Gathering, processing and terminalling assets (1) | 675,092 |
| | 397,701 |
| 889,168 |
| | 675,092 |
|
| Natural gas pipelines | 581,400 |
| | 572,150 |
| 607,343 |
| | 581,400 |
|
General and other | 98,680 |
| | 82,510 |
| 180,299 |
| | 98,680 |
|
| Construction work in progress | 97,978 |
| | 20,606 |
| 191,994 |
| | 97,978 |
|
| Accumulated depreciation and amortization | (279,192 | ) | | (195,860 | ) | (380,351 | ) | | (279,192 | ) |
Total property, plant and equipment, net (2)(3) | $ | 2,394,337 |
| | $ | 2,079,232 |
| $ | 2,802,429 |
| | $ | 2,394,337 |
|
| |
(1) | Includes approximately $138.2$53.6 million and $46.2 million of assets associated with the Douglas Gathering System acquiredacquisitions of BNN North Dakota in June 2017,January and November 2018 and Deeprock North in January 2018, respectively. |
| |
(2) | Includes approximately $68.4$30.7 million of assetsland associated with the acquisition of the aggregate additional 49% membership interestPLT capital lease as discussed in Deeprock Development in July 2017,Note 3 – Acquisitions and approximately $29.3 million of assets associated with the PRB Crude System acquired in August 2017.Dispositions. |
| |
(2)(3)
| Property, plant and equipment, net includes approximately $431.6$455.8 million of assets at our regulated natural gas pipelines at December 31, 2017.2018. |
Depreciation expense was approximately $102.7 million, $86.9 million, $83.2 million, and $76.3$83.2 million for the years ended December 31, 2018, 2017, 2016, and 2015,2016, respectively. Capitalized interest was approximately $5.2 million, $1.1 million, $0.6 million, and $0.9$0.6 million for the years ended December 31, 2018, 2017, 2016, and 2015,2016, respectively.
Under various lease agreements, effective October 3, 2015 and January 1, 2017, TMID, as lessor, leases capacity on NGL pipelines that were constructed for third parties.parties, and Deeprock Development, as lessor, leases capacity on certain of its storage facilities under lease agreements acquired as part of the Deeprock North acquisition on January 2, 2018. Rental income for these arrangements was approximately $10.9 million, $3.8 million, $3.2 million, and $0.8$3.2 million for the years ended December 31, 2018, 2017, 2016, and 2015,2016, respectively, and was recorded as "Processing and other revenues" in the accompanying consolidated statements of income. Under a lease agreement initially effective November 13, 2012, TIGT, as lessor, leases a portion of its office space to a third party. Rental income was approximately $0.8 million for the years ended December 31, 2018, 2017, 2016, and 20152016 and was recorded as "Other income, net" in the accompanying consolidated statements of income.
As of December 31, 2017,2018, future minimum rental income under non-cancelable operating leases as the lessor were as follows (in thousands):
| | | Year | | Total | | Total |
| 2018 | | $ | 4,575 |
| |
| 2019 | | 4,590 |
| | $ | 7,742 |
|
| 2020 | | 3,978 |
| | 3,952 |
|
| 2021 | | 3,773 |
| | 3,773 |
|
| 2022 | | 3,773 |
| | 3,773 |
|
| 2023 | | | 3,773 |
|
| Thereafter | | 11,127 |
| | 7,353 |
|
| Total | | $ | 31,816 |
| | $ | 30,366 |
|
8. Goodwill and Other Intangible Assets
Reconciliation of Goodwill
The following table presents a reconciliation of the carrying amount of goodwill by reportable segment for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 | | Year Ended December 31, 2016 |
| | Natural Gas Transportation | | Gathering, Processing & Terminalling | | Total | | Natural Gas Transportation | | Gathering, Processing & Terminalling | | Total |
| | (in thousands) |
| Balance at beginning of period | $ | 255,558 |
| | $ | 87,730 |
| | $ | 343,288 |
| | $ | 255,558 |
| | $ | 87,730 |
| | $ | 343,288 |
|
| Goodwill acquired | — |
| | 61,550 |
| (1) | 61,550 |
| | — |
| | — |
| | — |
|
| Balance at end of period | $ | 255,558 |
| | $ | 149,280 |
| | $ | 404,838 |
| | $ | 255,558 |
| | $ | 87,730 |
| | $ | 343,288 |
|
| |
(1)
| The $61.6 million of goodwill was recorded in connection with the acquisition of a controlling interest in Deeprock Development on July 20, 2017 as discussed further in Note 4 – Acquisitions.
|
Annual Goodwill Impairment Analysis
We did not elect to apply the qualitative assessment option during our 2017 annual goodwill impairment testing; instead we proceeded directly to the quantitative impairment test. We compared the fair value of each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting unit, the results of the quantitative impairment test indicated no impairment as the fair value of the reporting units was greater than their respective book values. As a result, in accordance with the Codification guidance, we did not record a goodwill impairment during the year ended December 31, 2017. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary.
Other Intangible Assets
A summary of amortized intangible assets is as follows:
|
| | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | (in thousands) |
| Pony Express oil conversion use rights | $ | 105,973 |
| | $ | 105,973 |
|
| Customer contracts | 8,064 |
| | — |
|
| Accumulated amortization | (16,306 | ) | | (12,451 | ) |
| Intangible assets, net | $ | 97,731 |
| | $ | 93,522 |
|
Amortization of intangible assets was approximately $3.8 million, $3.0 million, and $8.0 million for the years ended December 31, 2017, 2016, and 2015, respectively.
Estimated future amortization for the intangible assets is as follows (in thousands):
|
| | | | |
| Year | | Total |
| 2018 | | $ | 4,581 |
|
| 2019 | | 4,048 |
|
| 2020 | | 3,868 |
|
| 2021 | | 3,868 |
|
| 2022 | | 3,868 |
|
| Thereafter | | 77,498 |
|
| Total | | $ | 97,731 |
|
9.7. Investments in Unconsolidated Affiliates
Rockies Express
Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our consolidated balance sheets. As of May 6, 2016, the difference between the fair value of our 25% membership interest in Rockies Express of $436.0 million and the book value of the underlying net assets resulted in a negative basis difference of approximately $404.7 million. As discussed in Note 43 – Acquisitions and Dispositions, we acquired an additional 24.99% and 25.01% membership interest in Rockies Express from TD on March 31, 2017.2017 and February 7, 2018, respectively. As of March 31, 2017, the negative basis difference carried over from TD from the transfer of the 24.99% Rockies Express membership interest was approximately $386.8 million. As of February 7, 2018, the negative basis difference carried over from TD from the transfer of the 25.01% Rockies Express membership interest was approximately $376.5 million. The transfer of the 24.99% Rockies Express membership interest between TD and TEP and the Partnership is25.01% Rockies Express membership interest between TD and Tallgrass Equity are considered a transactiontransactions between entities under common control, but does not represent a change in reporting entity. As a result of the common control nature of the transaction,transactions, the 24.99% and 25.01% membership interestinterests in Rockies Express waswere transferred to the PartnershipTEP and Tallgrass Equity, respectively, at TD's historical carrying amount, including the remaining unamortized basis difference driven by the difference between the fair value of the investmentinvestments and the book value of the underlying assets and liabilities on November 13, 2012, the date of acquisition by TD.
The basis difference was allocated to property, plant and equipment and long-term debt based on their respective fair values at the date of acquisition.
The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years, which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. At December 31, 2017,2018, the basis difference for theour membership interests acquired in May 2016 and March 2017 wereRockies Express was allocated as follows:
| | | | Basis Difference | | Amortization Period | Basis Difference | | Amortization Period |
| | (in thousands) | | (in thousands) | |
| Long-term debt | $ | 29,458 |
| | 2 - 25 years | $ | 47,182 |
| | 2 - 25 years |
| Property, plant and equipment | (788,631 | ) | | 35 years | (1,146,984 | ) | | 35 years |
| Total basis difference | $ | (759,173 | ) | | $ | (1,099,802 | ) | |
During the year ended December 31, 2017,2018, we recognized equity in earnings associated with our 49.99%aggregate 75% membership interest in Rockies Express of $235.6$303.4 million, inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $304.7$380.7 million and $39.3$432.0 million, respectively.
In July 2018, we made a special contribution of approximately $412.5 million to fund our portion of the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018.
BNN Colorado Water, LLC
As discussed in Note 223 – Subsequent EventsAcquisitions and Dispositions, Tallgrass Equity acquired a 25.01% membership interestwe consolidated BNN Colorado effective December 1, 2018 and no longer account for our investment in Rockies Express from Tallgrass Development on February 7, 2018.BNN Colorado under the equity method of accounting.
Deeprock Development
As discussed in Note 43 – Acquisitions and Dispositions, on July 20, 2017, we acquired an additional 40% membership interest in Deeprock Development. As a result of the acquisition, TEPwe consolidated Deeprock Development and effective July 20, 2017 we no longer accountsaccount for itsour investment in Deeprock Development under the equity method of accounting.
Summarized Financial Information of Unconsolidated Affiliates
Combined summarized financial information for all our unconsolidated affiliates is shown in the tables below. Summarized financial information for Deeprock Development is presented from January 1, 20152016 to July 20, 2017, the date TEPwe acquired a controlling interest in Deeprock Development. Summarized financial information for Rockies Express is presented from the date of the initial acquisition of May 6, 2016 to December 31, 2017.2018. Summarized financial information for BNN Colorado is presented from the date of the acquisition, June 23, 2017 to December 1, 2018, the date we acquired a controlling interest in BNN Colorado. Summarized financial information for Iron Horse is presented from the date of the acquisition, February 23, 2018 to December 31, 2017.2018. Summarized financial information for Pawnee Terminal is presented from the date of the acquisition, April 1, 2018 to December 31, 2018.
| | | | December 31, 2017 | | December 31, 2016 | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
| Current assets | $ | 122,362 |
| | $ | 199,958 |
| $ | 132,213 |
| | $ | 122,362 |
|
| Noncurrent assets | $ | 5,974,926 |
| | $ | 6,148,203 |
| $ | 6,031,066 |
| | $ | 5,974,926 |
|
| Current liabilities | $ | 714,037 |
| | $ | 197,305 |
| $ | 694,951 |
| | $ | 714,037 |
|
| Noncurrent liabilities | $ | 2,049,189 |
| | $ | 2,656,836 |
| $ | 1,502,906 |
| | $ | 2,049,189 |
|
| Members' equity | $ | 3,334,062 |
| | $ | 3,494,020 |
| $ | 3,965,422 |
| | $ | 3,334,062 |
|
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
| Revenue | $ | 860,115 |
| | $ | 440,838 |
| | $ | 18,646 |
| $ | 930,771 |
| | $ | 860,115 |
| | $ | 440,838 |
|
| Operating income | $ | 480,337 |
| | $ | 203,801 |
| | $ | 13,794 |
| $ | 524,607 |
| | $ | 480,337 |
| | $ | 203,801 |
|
| Net income to Members | $ | 465,592 |
| | $ | 184,314 |
| | $ | 13,794 |
| $ | 376,934 |
| | $ | 465,592 |
| | $ | 184,314 |
|
8. Goodwill and Other Intangible Assets
Reconciliation of Goodwill
The following table presents a reconciliation of the carrying amount of goodwill by reportable segment for the reporting period:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2018 | | Year Ended December 31, 2017 |
| | Natural Gas Transportation | | Gathering, Processing & Terminalling | | Total | | Natural Gas Transportation | | Gathering, Processing & Terminalling | | Total |
| | (in thousands) |
| Balance at beginning of period | $ | 255,558 |
| | $ | 149,280 |
| | $ | 404,838 |
| | $ | 255,558 |
| | $ | 87,730 |
| | $ | 343,288 |
|
| Goodwill acquired | — |
| | 17,145 |
| (1) | 17,145 |
| | — |
| | 61,550 |
| (2) | 61,550 |
|
| Balance at end of period | $ | 255,558 |
| | $ | 166,425 |
| | $ | 421,983 |
| | $ | 255,558 |
| | $ | 149,280 |
| | $ | 404,838 |
|
| |
(1) | The $17.1 million of goodwill was recorded in connection with the acquisition of NGL Water Solutions Bakken on November 30, 2018 as discussed further in Note 3 – Acquisitions and Dispositions. |
| |
(2) | The $61.6 million of goodwill was recorded in connection with the acquisition of a controlling interest in Deeprock Development on July 20, 2017 as discussed further in Note 3 – Acquisitions and Dispositions. |
Annual Goodwill Impairment Analysis
In 2018, we elected to apply the qualitative assessment option for four of our five reporting units. In conducting the qualitative assessment we considered relevant factors and circumstances that affect the fair value or carrying amount of the reporting entity. Such factors included changes in discount rates, projected cash flows, macroeconomic considerations, industry and market considerations, overall financial performance, prior quantitative results, and entity and reporting unit specific events. For each of these reporting units, the results of the qualitative assessment indicated that it was more likely than not that the fair value of the reporting units exceeded their respective book values. As such, we did not perform a quantitative impairment analysis, and we concluded that no impairment was indicated as of August 31, 2018.
We did not elect to apply the qualitative assessment option for one reporting unit during our 2018 annual goodwill impairment testing; instead we proceeded directly to the quantitative impairment test. We compared the fair value of the reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. The fair value of the reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are revenue, operating expenses, general and administrative expenses, terminal growth rates, maintenance capital expenditures, and the weighted average cost of capital. The fair value of the reporting unit was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For this reporting unit, the results of the quantitative impairment test indicated no impairment as the fair value of the reporting unit was greater than its respective book value. As a result, in accordance with the Codification guidance, we did not record a goodwill impairment during the year ended December 31, 2018. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow model and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary.
Other Intangible Assets
A summary of amortized intangible assets is as follows:
|
| | | | | | | |
| | December 31, 2018 | | December 31, 2017 |
| | (in thousands) |
| Pony Express oil conversion use rights | $ | 105,973 |
| | $ | 105,973 |
|
| Customer contracts | 60,348 |
| | 8,064 |
|
| Customer relationships | 52,100 |
| | — |
|
| Plaquemines Liquids Terminal use rights and permits | 35,000 |
| | — |
|
| Accumulated amortization | (26,318 | ) | | (16,306 | ) |
| Intangible assets, net | $ | 227,103 |
| | $ | 97,731 |
|
Amortization of intangible assets was approximately $8.1 million, $3.8 million, and $3.0 million for the years ended December 31, 2018, 2017, and 2016, respectively.
Estimated future amortization for the intangible assets is as follows (in thousands):
|
| | | | |
| Year | | Total |
| 2019 | | $ | 16,528 |
|
| 2020 | | 16,347 |
|
| 2021 | | 16,294 |
|
| 2022 | | 13,144 |
|
| 2023 | | 13,144 |
|
| Thereafter | | 116,646 |
|
Total (1) | | $ | 192,103 |
|
| |
(1) | Excludes the $35 million intangible asset at PLT, as discussed in Note 3 – Acquisitions and Dispositions, that will be amortized over 35 years beginning on the in-service date of the project facilities. |
10.9. Risk Management
We enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments.
Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs.
Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included in the consolidated balance sheets:
|
| | | | | | | | | |
| | Balance Sheet
Location | | December 31, 2017 | | December 31, 2016 |
| | | | (in thousands) |
Call option derivative (1) | Current assets | | $ | — |
| | $ | 10,676 |
|
Natural gas derivative contracts (2) | Current assets | | $ | — |
| | $ | 291 |
|
Crude oil derivative contracts (3) | Current liabilities | | $ | 2,368 |
| | $ | 440 |
|
Natural gas derivative contracts (2) | Current liabilities | | $ | — |
| | $ | 116 |
|
|
| | | | | | | | | |
| | Balance Sheet
Location | | December 31, 2018 | | December 31, 2017 |
| | | | (in thousands) |
Crude oil derivative contracts (1) | Prepayments and other current assets | | $ | 3,526 |
| | $ | — |
|
Crude oil derivative contracts (2) | Other current liabilities | | $ | 1,642 |
| | $ | 2,368 |
|
| |
(1) | As discussed below, in conjunction with our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted us an 18 month call option coveringDecember 31, 2018, the 6,518,000 common units issued to TD. Asfair value shown for crude oil derivative contracts represents the forward purchase of February 1, 2017, no common units remained subject to the call option.2,105,146 barrels of crude oil, consisting of fixed price and floating price contracts, which will settle throughout 2019. |
| |
(2) | As of December 31, 2017, there were no natural gas derivative contracts outstanding. As of December 31, 2016,2018, the fair value shown for natural gascrude oil derivative contracts was comprisedrepresents the forward sale of derivative volumes for short1,274,500 barrels of crude oil, consisting of fixed price and long natural gas fixed-price swaps totaling 0.3 Bcf and 0.4 Bcf, respectively. |
| |
(3)
| floating price contracts, which will settle throughout the first quarter of 2019. As of December 31, 2017, the fair value shown for crude oil derivative contracts represents the forward sale of 356,000 barrels of crude oil, consisting of fixed price and floating price contracts, which will settle throughoutsettled in the first quarter of 2018. As of December 31, 2016, the fair value shown for crude oil derivative contracts represents the sale of 125,000 barrels of crude oil which settled throughout 2017. |
Effect of Derivative Contracts in the Statements of Income
The following table summarizes the impact of derivative contracts not designated as hedging contracts for the years ended December 31, 2018, 2017 2016 and 2015:2016:
| | | | Location of
gain (loss) recognized
in income on derivatives | | Amount of gain (loss) recognized in income on derivatives | | Location of
gain (loss) recognized
in income on derivatives | | Amount of gain (loss) recognized in income on derivatives |
| | | Year Ended December 31, | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| | | | (in thousands) | | | | (in thousands) |
| Derivatives not designated as hedging contracts: | | | | | | | |
| Crude oil derivative contracts | Sales of natural gas, NGLs, and crude oil | | $ | 39 |
| | $ | (40 | ) | | $ | — |
| | Sales of natural gas, NGLs, and crude oil | | $ | 29,510 |
| | $ | 39 |
| | $ | (40 | ) |
| Natural gas derivative contracts | Sales of natural gas, NGLs, and crude oil | | $ | 75 |
| | $ | 74 |
| | $ | 427 |
| | Sales of natural gas, NGLs, and crude oil | | $ | — |
| | $ | 75 |
| | $ | 74 |
|
| Call option derivative | Unrealized gain (loss) on derivative instrument | | $ | 1,885 |
| | $ | (1,291 | ) | | $ | — |
| | Other income, net | | $ | — |
| | $ | 1,885 |
| | $ | (1,291 | ) |
Call Option Derivative
As part of TEP'sour acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted TEP an 18 month call option at an exercise price of $42.50 per TEP common unit covering the 6,518,000 TEP common units issued to TD as a portion of the consideration. In July 2016 and October 2016, TEP partially exercised the call option covering 3,563,146 and 1,251,760 common units, respectively, for cash payments of $151.4 million and $53.2 million, respectively. On February 1, 2017, TEP exercised the remainder of the call option covering an additional 1,703,094 common units for a cash payment of $72.4 million. These common units were deemed canceled upon the exercise of the call option and as of the applicable exercise date were no longer issued and outstanding.
Credit Risk
We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our commodity derivatives consist of market participants and major financial institutions. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. The counterparty to our call option derivative was TD.
Our derivative contracts are entered into with counterparties through central trading organizations such as futures, options or stock exchanges or counterparties outside of central trading organizations. While we typically enter into derivative transactions with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. As of December 31, 2017, the fair value ofThe maximum potential exposure to credit losses on our crude oil derivative contracts wereat December 31, 2018 was:
|
| | | |
| | Asset Position |
| | (in thousands) |
| Gross | $ | 3,526 |
|
| Netting agreement impact | — |
|
| Cash collateral held | — |
|
| Net exposure | $ | 3,526 |
|
As of December 31, 2018, we did not have any cash in a liability position, resultingmargin accounts or outstanding letters of credit in no credit exposure from TEP's counterparties assupport of that date.
our commodity derivatives. As of December 31, 2017, we had $3.0 million of cash in margin accounts and outstanding letters of credit in support of our commodity derivative contracts. As of December 31, 2016, we did not have any outstanding letters of credit or cash in margin accounts in support of our hedging of commodity price risks associated with our commodity derivative contracts.
Fair Value
Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter ("OTC"). OTC commodity derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy. The call option granted by TD was valued using a Black-Scholes option pricing model. Key inputs to the valuation model included the term of the option, risk free rate, the exercise price and current market price, expected volatility and expected distribution yield of the underlying units. The call option valuation was classified within Level 2 of the fair value hierarchy as the value was based on significant observable inputs.
Certain OTC derivative contracts trade in less liquid markets with limited pricing information; as such, the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our consolidated financial statements. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management's best estimate is used.
The following table summarizes the fair value measurements of our derivative contracts as of December 31, 20172018 and 2016,2017, based on the fair value hierarchy:
|
| | | | | | | | | | | | | | | |
| | | | Asset Fair Value Measurements Using |
| | Total | | Quoted prices in
active markets
for identical
assets
(Level 1) | | Significant
other observable
inputs
(Level 2) | | Significant
unobservable
inputs
(Level 3) |
| | (in thousands) |
| As of December 31, 2016: | | | | | | | |
| Call option derivative | $ | 10,676 |
| | $ | — |
| | $ | 10,676 |
| | $ | — |
|
| Natural gas derivative contracts | $ | 291 |
| | $ | — |
| | $ | 291 |
| | $ | — |
|
| | | | Liability Fair Value Measurements Using |
| | Total | | Quoted prices in
active markets
for identical
assets
(Level 1) | | Significant
other observable
inputs
(Level 2) | | Significant
unobservable
inputs
(Level 3) |
| | (in thousands) |
| As of December 31, 2017: | | | | | | | |
| Crude oil derivative contracts | $ | 2,368 |
| | $ | — |
| | $ | 2,368 |
| | $ | — |
|
| As of December 31, 2016: | | | | | | | |
| Crude oil derivative contracts | $ | 440 |
| | $ | — |
| | $ | 440 |
| | $ | — |
|
| Natural gas derivative contracts | $ | 116 |
| | $ | — |
| | $ | 116 |
| | $ | — |
|
|
| | | | | | | | | | | | | | | |
| | | | Asset Fair Value Measurements Using |
| | Total | | Quoted prices in
active markets
for identical
assets
(Level 1) | | Significant
other observable
inputs
(Level 2) | | Significant
unobservable
inputs
(Level 3) |
| | (in thousands) |
| As of December 31, 2018: | | | | | | | |
| Crude oil derivative contracts | $ | 3,526 |
| | $ | — |
| | $ | 3,526 |
| | $ | — |
|
| | | | Liability Fair Value Measurements Using |
| | Total | | Quoted prices in
active markets
for identical
assets
(Level 1) | | Significant
other observable
inputs
(Level 2) | | Significant
unobservable
inputs
(Level 3) |
| | (in thousands) |
| As of December 31, 2018: | | | | | | | |
| Crude oil derivative contracts | $ | 1,642 |
| | $ | — |
| | $ | 1,642 |
| | $ | — |
|
| As of December 31, 2017: | | | | | | | |
| Crude oil derivative contracts | $ | 2,368 |
| | $ | — |
| | $ | 2,368 |
| | $ | — |
|
11.10. Long-term Debt
Long-term debt consisted of the following at December 31, 20172018 and 2016:2017:
| | | | December 31, 2017 | | December 31, 2016 | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
Tallgrass Equity revolving credit facility | $ | 146,000 |
| | $ | 148,000 |
| $ | — |
| | $ | 146,000 |
|
| TEP revolving credit facility | 661,000 |
| | 1,015,000 |
| 1,224,000 |
| | 661,000 |
|
| TEP 4.75% senior notes due October 1, 2023 | | 500,000 |
| | — |
|
| TEP 5.50% senior notes due September 15, 2024 | 750,000 |
| | 400,000 |
| 750,000 |
| | 750,000 |
|
| TEP 5.50% senior notes due January 15, 2028 | 750,000 |
| | — |
| 750,000 |
| | 750,000 |
|
Less: Deferred financing costs, net (1) | (17,737 | ) | | (7,019 | ) | |
Less: Deferred financing costs, net (2) | | (21,421 | ) | | (17,737 | ) |
| Plus: Unamortized premium on 2028 Notes | 3,730 |
| | — |
| 3,379 |
| | 3,730 |
|
| Total long-term debt, net | $ | 2,292,993 |
| | $ | 1,555,981 |
| $ | 3,205,958 |
| | $ | 2,292,993 |
|
| |
(1) | On July 26, 2018, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility. |
| |
(2) | Deferred financing costs, net as presented above relate solely to the 2024 and 2028 Notes.Senior Notes (as defined below). Deferred financing costs associated with our revolving credit facilities are presented in noncurrent assets on our consolidated balance sheets. |
TEP Senior Unsecured Notes due 2028
On September 15, 2017,26, 2018, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 15, 201726, 2018 (the "2028"2023 Indenture") pursuant to which the Issuers issued $500 million in aggregate principal amount of 5.50%4.75% senior notes due 20282023 (the "2028"2023 Notes"). On December 11, 2017, the Issuers issued an additional $250 million in aggregate principal amount of the 2028 Notes, which are also governed by the 2028 Indenture. The notes issued on September 15, 2017 and December 11, 2017 are treated as a single class of debt securities and have identical terms, other than the issue date, offering price and first interest payment date.
The 20282023 Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all TEP’sTEP's properties to, another person. As
The Issuers have also previously issued $500 million in aggregate principal amount of December 31,5.50% senior notes due 2028 (the "2028 Notes") on September 15, 2017 we areand an additional $250 million in compliance with the covenants required underaggregate principal amount of the 2028 Notes.
TEP Senior Unsecured Notes due 2024
Onon December 11, 2017. The 2028 Notes issued on September 1, 2016,15, 2017 and December 11, 2017 are treated as a single class of debt securities and have identical terms, other than the Issuers, the Guarantors named thereinissue date and U.S. Bank, National Association, as trustee, entered intooffering price. The 2028 Notes are governed by an Indenture dated September 1, 201615, 2017 (the "2024"2028 Indenture"), pursuant which contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to whichsecure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all TEP's properties to, another person.
In addition, the Issuers have previously issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes"). On May 16, 2017, the Issuers issued on September 1, 2016 and an additional $350 million in aggregate principal amount of the 2024 Notes which are also governed by theon May 16, 2017. The 2024 Indenture. The notesNotes issued on September 1, 2016 and May 16, 2017 are treated as a single class of debt securities and have identical terms, other than the issue date, offering price and first interest payment date.
The 2024 Notes are governed by an Indenture dated September 1, 2016 (the "2024 Indenture") which contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests in the event of default or noncompliance with the covenants required, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates.
The 2023 Notes, 2024 Notes, and 2028 Notes are together referred to as the "Senior Notes." As of December 31, 2017,2018, TEP is in compliance with the covenants required under the 2024 Notes.
Tallgrass Equity Revolving Credit Facility
The following table sets forth the available borrowing capacity under the Tallgrass Equity revolving credit facility as of December 31, 2017 and 2016:
|
| | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | (in thousands) |
| Total capacity under the Tallgrass Equity revolving credit facility | $ | 150,000 |
| | $ | 150,000 |
|
| Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility | (146,000 | ) | | (148,000 | ) |
| Available capacity under the Tallgrass Equity revolving credit facility | $ | 4,000 |
| | $ | 2,000 |
|
In connection with the TEGP IPO, Tallgrass Equity entered into a $150 million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders, which will mature on May 12, 2020. The Tallgrass Equity credit facility includes a $10 million sublimit for letters of credit and a $10 million sublimit for swing line loans. The Tallgrass Equity revolving credit facility also contains an accordion feature whereby Tallgrass Equity can increase the size of the credit facility to an aggregate of $200 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. Among various other covenants and restrictive provisions, Tallgrass Equity is required to maintain a total leverage ratio of not more than 3.00 to 1.00. As of December 31, 2017, Tallgrass Equity was in compliance with the covenants required under the revolving credit facility.
Tallgrass Equity's obligations under2023 Indenture, the revolving credit facility are secured by a first priority lien on all2024 Indenture, and the present and after acquired equity interests held by Tallgrass Equity in TEP GP and TEP. Borrowings under the credit facility bear interest, at Tallgrass Equity's option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin is 1.50%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin is 2.50%.
The unused portion of the revolving credit facility is subject to a commitment fee of 0.50%. As of December 31, 2017, the weighted average interest rate on outstanding borrowings under the Tallgrass Equity revolving credit facility was 4.07%. During the year ended December 31, 2017, Tallgrass Equity's weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 3.96%.2028 Indenture.
TEP Revolving Credit Facility
On June 2, 2017, TEP entered into a $1.75 billion Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent and collateral agent, and a syndicate of lenders (the "Amended Credit Agreement"). The Amended Credit Agreement amends and restates TEP's existing revolving credit facility. The Amended Credit Agreement, among other things, extends the maturity date of TEP's existing revolving credit facility from May 13, 2018 to June 2, 2022, and provides for an uncommitted accordion in an amount up to an additional $250 million, subject to the satisfaction of certain other conditions. In addition, the revolving credit facility includes a $60 million sublimit for swing line loans and a $75 million sublimit for letters of credit
The following table sets forth the available borrowing capacity under the TEP revolving credit facility as of December 31, 20172018 and 2016:2017:
| | | | December 31, 2017 | | December 31, 2016 | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
| Total capacity under the TEP revolving credit facility | $ | 1,750,000 |
| | $ | 1,750,000 |
| $ | 2,250,000 |
| | $ | 1,750,000 |
|
| Less: Outstanding borrowings under the TEP revolving credit facility | (661,000 | ) | | (1,015,000 | ) | (1,224,000 | ) | | (661,000 | ) |
| Less: Letters of credit issued under the TEP revolving credit facility | (94 | ) | | — |
| (94 | ) | | (94 | ) |
| Available capacity under the TEP revolving credit facility | $ | 1,088,906 |
| | $ | 735,000 |
| $ | 1,025,906 |
| | $ | 1,088,906 |
|
On July 26, 2018, TEP and certain of its subsidiaries entered into Amendment No. 1 (the "Amendment") to its existing revolving credit facility with Wells Fargo Bank, National Association, as administrative agent and collateral agent, and a syndicate of lenders (the "Credit Agreement"). The Amendment modified certain provisions of the Credit Agreement to, among other things, (i) increase the available amount of the TEP revolving credit facility to $2.25 billion, (ii) reduce certain applicable margins in the pricing grids used to determine the interest rate and revolving credit commitment fees, (iii) modify the use of proceeds to allow TEP to pay off the Tallgrass Equity revolving credit facility, and (iv) increase the maximum total leverage ratio to 5.50 to 1.00.
TEP's revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP's ability (as well as the ability of its restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions, including distributions from available cash, if a default or event of default under the credit agreement then exists or would result therefrom, change the nature of its business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not more than 5.00 to 1.00 (which will be increased to 5.50 to 1.00 for certain measurement periods following(5.00 to 1.00 prior to the consummation of certain acquisitions)Amendment), a consolidated senior secured leverage ratio of not more than
3.75 to 1.00 and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of December 31, 2017,2018, TEP iswas in compliance with the covenants required under its revolving credit facility. The consummation of the Blackstone Acquisition would constitute an event of default under TEP's revolving credit agreement. The closing conditions of the Blackstone Acquisition include TEP obtaining the consent or waiver of the required lenders under TEP's revolving credit facility in connection with the transactions contemplated by the Blackstone Acquisition.
The unused portion of TEP's revolving credit facility is subject to a commitment fee, which ranges from 0.250% to 0.375% (0.250% to 0.500% prior to the Amendment), based on TEP's total leverage ratio. As of December 31, 2017,2018, the weighted average interest rate on outstanding borrowings under the TEP revolving credit facility was 3.24%3.96%. During the year ended December 31, 2017,2018, the weighted average effective interest rate under the TEP revolving credit facility, including the interest on outstanding borrowings under TEP's revolving credit facility, commitment fees, and amortization of deferred financing costs, was 3.31%4.11%.
Fair Value
The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the consolidated balance sheets as of December 31, 20172018 and 2016,2017, but for which fair value is disclosed:
| | | | Fair Value | | | Fair Value | | |
| | Quoted prices
in active markets
for identical assets
(Level 1) | | Significant
other observable
inputs
(Level 2) | | Significant
unobservable
inputs
(Level 3) | | Total | | Carrying
Amount | Quoted prices
in active markets
for identical assets
(Level 1) | | Significant
other observable
inputs
(Level 2) | | Significant
unobservable
inputs
(Level 3) | | Total | | Carrying
Amount |
| | (in thousands) | (in thousands) |
| As of December 31, 2018: | | | | | | | | | | |
| Revolving credit facility | | $ | — |
| | $ | 1,224,000 |
| | $ | — |
| | $ | 1,224,000 |
| | $ | 1,224,000 |
|
| 2023 Notes | | $ | — |
| | $ | 485,285 |
| | $ | — |
| | $ | 485,285 |
| | $ | 494,603 |
|
| 2024 Notes | | $ | — |
| | $ | 737,745 |
| | $ | — |
| | $ | 737,745 |
| | $ | 741,196 |
|
| 2028 Notes | | $ | — |
| | $ | 726,503 |
| | $ | — |
| | $ | 726,503 |
| | $ | 746,159 |
|
| As of December 31, 2017: | | | | | | | | | | | | | | | | | | |
| Revolving credit facilities | $ | — |
| | $ | 807,000 |
| | $ | — |
| | $ | 807,000 |
| | $ | 807,000 |
| $ | — |
| | $ | 807,000 |
| | $ | — |
| | $ | 807,000 |
| | $ | 807,000 |
|
| 2024 Notes | $ | — |
| | $ | 771,645 |
| | $ | — |
| | $ | 771,645 |
| | $ | 739,824 |
| $ | — |
| | $ | 771,645 |
| | $ | — |
| | $ | 771,645 |
| | $ | 739,824 |
|
| 2028 Notes | $ | — |
| | $ | 758,168 |
| | $ | — |
| | $ | 758,168 |
| | $ | 746,169 |
| $ | — |
| | $ | 758,168 |
| | $ | — |
| | $ | 758,168 |
| | $ | 746,169 |
|
| As of December 31, 2016: | | | | | | | | | | |
| Revolving credit facilities | $ | — |
| | $ | 1,163,000 |
| | $ | — |
| | $ | 1,163,000 |
| | $ | 1,163,000 |
| |
| 2024 Notes | $ | — |
| | $ | 398,000 |
| | $ | — |
| | $ | 398,000 |
| | $ | 392,981 |
| |
The long-term debt borrowed under the revolving credit facilities is carried at amortized cost. As of December 31, 20172018 and 2016,2017, the fair value of borrowings under the revolving credit facilities approximates the carrying amount of the borrowings using a discounted cash flow analysis. The 2024 and 2028Senior Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the 2024 and 2028Senior Notes is based upon quoted market prices adjusted for illiquid markets. We are not aware of any factors that would significantly affect the estimated fair value subsequent to December 31, 2017.2018.
12.11. Partnership Equity and Distributions
TEGP Partnership Agreement and DistributionsTGE Dividends to Holders of Class A Shares
On May 12, 2015, TEGP closed the TEGP IPO and completed the Reorganization Transactions as outlined in Note 1 – Description of Business. In connection with the TEGP IPO, TEGP entered into an amended and restated partnership agreement. The partnership agreement requires TEGP to distribute its available cash to Class A shareholders on a quarterly basis, subject to certain terms and conditions, beginning with the quarter ended June 30, 2015. The following table details the distributionsdividends for the periods indicated:
| | | Three Months Ended | | Date Paid | | Distributions to Class A Shareholders | | Distributions per Class A Share | | | Date Paid | | Dividends to Class A Shareholders | | Dividends per Class A Share | |
| | | (in thousands) | | | | |
| December 31, 2018 | | | February 14, 2019 (1) | | $ | 81,304 |
| | $ | 0.5200 |
| |
| September 30, 2018 | | | November 14, 2018 | | 79,717 |
| | 0.5100 |
| |
| June 30, 2018 | | | August 14, 2018 | | 77,052 |
| | 0.4975 |
| |
| March 31, 2018 | | | May 15, 2018 | | 28,316 |
| | 0.4875 |
| |
| December 31, 2017 | | February 14, 2018 (1) | | $ | 21,346 |
| | $ | 0.3675 |
| | | February 14, 2018 | | 21,346 |
| | 0.3675 |
| |
| September 30, 2017 | | November 15, 2017 | | 20,617 |
| | 0.3550 |
| | | November 14, 2017 | | 20,617 |
| | 0.3550 |
| |
| June 30, 2017 | | August 14, 2017 | | 19,891 |
| | 0.3425 |
| | | August 14, 2017 | | 19,891 |
| | 0.3425 |
| |
| March 31, 2017 | | May 15, 2017 | | 16,697 |
| | 0.2875 |
| | | May 15, 2017 | | 16,697 |
| | 0.2875 |
| |
| December 31, 2016 | | February 14, 2017 | | 16,116 |
| | 0.2775 |
| | | February 14, 2017 | | 16,116 |
| | 0.2775 |
| |
| September 30, 2016 | | November 14, 2016 | | 12,528 |
| | 0.2625 |
| | | November 14, 2016 | | 12,528 |
| | 0.2625 |
| |
| June 30, 2016 | | August 12, 2016 | | 11,693 |
| | 0.2450 |
| | | August 12, 2016 | | 11,693 |
| | 0.2450 |
| |
| March 31, 2016 | | May 13, 2016 | | 10,022 |
| | 0.2100 |
| | | May 13, 2016 | | 10,022 |
| | 0.2100 |
| |
| December 31, 2015 | | February 12, 2016 | | 8,256 |
| | 0.1730 |
| | |
| September 30, 2015 | | November 13, 2015 | | 6,872 |
| | 0.1440 |
| | |
| June 30, 2015 | | August 17, 2015 | | 3,484 |
| | 0.0730 |
| (2) | |
| |
(1) | The distributiondividend announced on January 8, 201815, 2019 for the fourth quarter of 20172018 will be paid on February 14, 20182019 to Class A shareholders of record at the close of business on January 31, 2018.2019. |
| |
(2)Subsidiary Distributions TEP Distributions. The following table shows the distributions for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Distributions | | Distribution per Limited Partner Common Unit | | | | | | Limited Partner
Common Units | | General Partner | | | | | Three Months Ended | | Date Paid | | Incentive Distribution Rights | | General Partner Units | | Total | | | | | | | (in thousands, except per unit amounts) | | March 31, 2018 | | May 15, 2018 | | $ | 71,370 |
| | $ | 39,816 |
| | $ | 1,267 |
| | $ | 112,453 |
| | $ | 0.9750 |
| | December 31, 2017 | | February 14, 2018 | | 70,638 |
| | 39,125 |
| | 1,251 |
| | 111,014 |
| | 0.9650 |
| | September 30, 2017 | | November 14, 2017 | | 69,174 |
| | 37,744 |
| | 1,219 |
| | 108,137 |
| | 0.9450 |
| | June 30, 2017 | | August 14, 2017 | | 67,671 |
| | 36,342 |
| | 1,186 |
| | 105,199 |
| | 0.9250 |
| | March 31, 2017 | | May 15, 2017 | | 60,486 |
| | 29,840 |
| | 1,040 |
| | 91,366 |
| | 0.8350 |
| | December 31, 2016 | | February 14, 2017 | | 58,793 |
| | 28,358 |
| | 1,008 |
| | 88,159 |
| | 0.8150 |
| | September 30, 2016 | | November 14, 2016 | | 57,332 |
| | 26,987 |
| | 976 |
| | 85,295 |
| | 0.7950 |
| | June 30, 2016 | | August 12, 2016 | | 54,442 |
| | 24,262 |
| | 911 |
| | 79,615 |
| | 0.7550 |
| | March 31, 2016 | | May 13, 2016 | | 48,238 |
| | 19,816 |
| | 830 |
| | 68,884 |
| | 0.7050 |
|
As a result of the TEP Merger, Tallgrass Equity and its wholly-owned subsidiary, Tallgrass Equity Investments, LLC, will receive all distributions paid by TEP for the second quarter of 2018 and subsequent periods.
| The first quarterly distribution declared on July 15, 2015 was prorated for the number of days between the closing of TEGP's initial public offering on May 12, 2015 and the end of the second quarter. |
Exchange Rights
Our current Class B shareholders (collectively, the "Exchange Right Holders") own an equal number of Tallgrass Equity units. The Initial Exchange Right Holders, the shareholders who received 27,554,785 units of Tallgrass Equity and Class B shares in connection with the acquisition of the 25.01% membership interest in Rockies Express and the 5,619,218 additional TEP common units acquired by Tallgrass Equity on February 7, 2018 and any permitted transferees of their Tallgrass Equity units, (collectively, the "Exchange Right Holders") each have the right to exchange all or a portion of their Tallgrass Equity units for Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares are transferred by the exercising party to us. Upon such exchange, we will cancel the Class B shares received from the exercising party.
During the year ended December 31, 2018, 2,821,332 Class A shares were issued and an equal number of Class B shares were cancelled as a result of the exercise of the Exchange Right. As of February 8, 2019, the Exchange Right Holders primarily consist of Kelso & Company and its affiliated investment funds ("Kelso"), The Energy & Minerals Group and its affiliated investment funds ("EMG"), and Tallgrass KC, LLC ("Tallgrass KC"), which is an entity owned primarily by certain members of TGE's management.
Subsidiary Distributions
TEP DistributionsAs discussed in Note 22 – Subsequent Events, on January 31, 2018, we announced that affiliates of Blackstone Infrastructure Partners (collectively, "BIP") had entered into a definitive purchase agreement with Kelso, EMG, and Tallgrass KC (collectively, the "Sellers"), pursuant to which BIP will acquire from the Sellers 100% of the membership interests in our general partner and an approximately 44% economic interest in us (the "Blackstone Acquisition"). The following table showsOne or more affiliates of GIC Special Investment Pte. Ltd., the distributions forinfrastructure and private equity arm of GIC Pte. Ltd., Singapore's sovereign wealth fund, will be a minority investor in the periods indicated:Blackstone Acquisition. Following consummation of the Blackstone Acquisition, the Exchange Rights Holders are expected to consist of BIP and certain members of TGE's management.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | Distributions | | Distribution per Limited Partner Common Unit |
| | | | | Limited Partner
Common Units | | General Partner | | | |
| Three Months Ended | | Date Paid | | Incentive Distribution Rights | | General Partner Units | | Total | |
| | | | | (in thousands, except per unit amounts) |
| December 31, 2017 | | February 14, 2018 (1) | | $ | 70,638 |
| | $ | 39,125 |
| | $ | 1,251 |
| | $ | 111,014 |
| | $ | 0.9650 |
|
| September 30, 2017 | | November 14, 2017 | | 69,174 |
| | 37,744 |
| | 1,219 |
| | 108,137 |
| | 0.9450 |
|
| June 30, 2017 | | August 14, 2017 | | 67,671 |
| | 36,342 |
| | 1,186 |
| | 105,199 |
| | 0.9250 |
|
| March 31, 2017 | | May 15, 2017 | | 60,486 |
| | 29,840 |
| | 1,040 |
| | 91,366 |
| | 0.8350 |
|
| December 31, 2016 | | February 14, 2017 | | 58,793 |
| | 28,358 |
| | 1,008 |
| | 88,159 |
| | 0.8150 |
|
| September 30, 2016 | | November 14, 2016 | | 57,332 |
| | 26,987 |
| | 976 |
| | 85,295 |
| | 0.7950 |
|
| June 30, 2016 | | August 12, 2016 | | 54,442 |
| | 24,262 |
| | 911 |
| | 79,615 |
| | 0.7550 |
|
| March 31, 2016 | | May 13, 2016 | | 48,238 |
| | 19,816 |
| | 830 |
| | 68,884 |
| | 0.7050 |
|
| December 31, 2015 | | February 12, 2016 | | 42,984 |
| | 15,332 |
| | 724 |
| | 59,040 |
| | 0.6400 |
|
| September 30, 2015 | | November 13, 2015 | | 36,347 |
| | 11,567 |
| | 660 |
| | 48,574 |
| | 0.6000 |
|
| June 30, 2015 | | August 14, 2015 | | 35,135 |
| | 10,418 |
| | 627 |
| | 46,180 |
| | 0.5800 |
|
| March 31, 2015 | | May 14, 2015 | | 31,322 |
| | 6,934 |
| | 530 |
| | 38,786 |
| | 0.5200 |
|
| |
(1)
| The distribution announced on January 8, 2018 for the fourth quarter of 2017 will be paid on February 14, 2018 to unitholders of record at the close of business on January 31, 2018. |
TEP Equity Distribution Agreements
WeNeither TGE or TEP currently have activeequity distribution agreements in place. TEP was previously a party to equity distribution agreements pursuant to which it may sellsold from time to time through a group of managers, as its sales agents, TEP common units representing limited partner interests having an aggregate offering price of up to $100.2 million and $657.5 million. Net cash proceeds from any sale ofinterests. Following the TEP Merger, these agreements were terminated effective July 2, 2018. During the year ended December 31, 2018, TEP did not issue any common units may be used for general partnership purposes, which includes, among other things, TEP's exercise of the call option with respect to the 6,518,000 common units issued to TD in connection with TEP's acquisition of an additional 31.3% of Pony Express in January 2016, repayment or refinancing of debt, funding for acquisitions, capital expenditures and additions to working capital.under its equity distribution agreements.
During the year ended December 31, 2017, TEP issued and sold 2,341,061 common units with a weighted average sales price of $48.82 per unit under its equity distribution agreementsagreement for net cash proceeds of approximately $112.4 million (net of approximately $1.9 million in commissions and professional service expenses). TEP used the net cash proceeds for general partnership purposes as described above.
During the year ended December 31, 2016, TEP issued and sold 7,696,708 common units with a weighted average sales price of $44.46 per unit under its equity distribution agreementagreements for net cash proceeds of approximately $337.7 million (net of approximately $4.5 million in commissions and professional service expenses). TEP used the net cash proceeds for general partnership purposes as described above.
During the year ended December 31, 2015, TEP issued and sold 65,744 common units with a weighted average sales price of $45.58 per unit under its equity distribution agreements for net cash proceeds of approximately $3.0 million (net of approximately $30,000 in commissions and professional service expenses). TEP used the net cash proceeds for general partnership purposes as described above.
Repurchase of TEP Common Units Owned by TD
Following an offer received from TD with respect to TEP common units owned by TD not subject to the call option, TEP repurchased 736,262 TEP common units from TD at an aggregate price of approximately $35.3 million, or $47.99 per common unit, on February 1, 2017, which was approved by the conflicts committee of the board of directors of TEP's general partner. These common units were deemed canceled upon ourTEP's purchase and as of such transaction date were no longer issued and outstanding.
Secondary Offering
On November 17, 2016, TEGPTGE entered into an Underwriting Agreement (the "Underwriting Agreement"), by and among the PartnershipTGE and certain selling shareholders named in the Underwriting Agreement (the "Selling Shareholders"), on one hand, and Goldman, Sachs & Co., as the sole underwriter (the "Underwriter"), on the other hand, providing for the offer and sale by the Selling Shareholders (the "Secondary Offering"), and purchase by the Underwriter, of 9,000,000 Class A shares ("Class A Shares") representing limited partner interests, at a price to the public of $22.00 per share. Pursuant to the Underwriting Agreement, the Selling Shareholders also granted the Underwriter an option for a period of 30 days to purchase up to an additional 1,350,000 Class A shares, on the same terms, which the Underwriter exercised in full.
In connection with the Secondary Offering, Class A Sharesshares were issued to the Selling Shareholders upon the exercise by each Selling Shareholder of its right to exchange all or a portion of its units ("Tallgrass Equity Units") of Tallgrass Equityunits into Class A Sharesshares at an exchange ratio of one Class A Shareshare for each Tallgrass Equity Unitunit exchanged (the "Exchange Right"). Pursuant to the terms of the Exchange Right, simultaneously therewith, the exercising Selling Shareholder transferred to the PartnershipTGE Class B shares ("Class B Shares") representing limited partner interests in the Partnership in an amount equal to the number of Tallgrass Equity Unitsunits exchanged by such exercising Selling Shareholder. Upon each such exchange, the PartnershipTGE cancelled the Class B Sharesshares received from the exercising Selling Shareholder. Immediately prior to the Secondary Offering, we and the Exchange Right Holders owned approximately 30.35% and 69.65% of the Tallgrass Equity Units,units, respectively. At the completion of the Secondary Offering, we and the Exchange Right Holders owned 36.94% and 63.06% of the Tallgrass Equity Units,units, respectively.
Private Placement
On April 28, 2016, TEP issued an aggregate of 2,416,987 common units for net cash proceeds of $90 million in a private placement transaction to certain funds managed by Tortoise Capital Advisors, L.L.C. The units were subsequently registered pursuant to our Form S-3/A (File No. 333-210976) filed with the SEC on May 6, 2016, which became effective May 17, 2016.
Tallgrass Development Purchase Program
On February 17, 2016, we announced that the Board of Directors of Tallgrass Energy Holdings, LLC, the sole member of TEGP's general partner and the general partner of TD, at the time of the announcement, had authorized an equity purchase program under which TD could purchase up to an aggregate of $100 million of the outstanding Class A shares of TEGP or the outstanding common units of TEP on the open market or in negotiated purchases. No purchases were made under this program during the years ended December 31, 2017 and 2016 nor during the period commencing January 1, 2018 and prior to the merger of TD into Tallgrass Development Holdings on February 7, 2018. As a result of such merger, no future purchases are expected to be made under the program.
TEP Public Offerings
On February 27, 2015, TEP sold 10,000,000 common units representing limited partner interests in an underwritten public offering at a price of $50.82 per unit, or $49.29 per unit net of the underwriter's discount, for net proceeds of approximately $492.4 million after deducting the underwriter's discount and offering expenses. TEP used the net proceeds from the offering to fund a portion of the consideration for the acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions. Pursuant to the underwriters' option to purchase additional units, TEP sold an additional 1,200,000 common units representing limited partner interests to the underwriters at a price of $50.82 per unit, or $49.29 per unit net of the underwriter's discount, for net proceeds of approximately $59.3 million after deducting the underwriter's discount and offering expenses. TEP used the net proceeds from this additional purchase of common units to reduce borrowings under its revolving credit facility, a portion of which were used to fund the March 2015 acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions.
Noncontrolling Interests
As of December 31, 2017,2018, noncontrolling interests in our subsidiaries consisted of a 63.06%44.21% interest in Tallgrass Equity held by the Exchange Right Holders, as defined in Note 14 – Net Income per Class A Share the 72.68% limited partner interest in TEP held by TD and the public TEP unitholders, and a 31%an approximate 40% membership interest in Deeprock Development, and the 2.0%a 37% membership interest in BNN Colorado. During the year ended December 31, 2018, we recognized contributions from and distributions to noncontrolling interests of $1.8 million and $327.6 million, respectively. Contributions from noncontrolling interests consisted primarily of contributions from DER to Deeprock Development. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of $223.7 million, distributions to TEP unitholders of $97.7 million, and distributions to Deeprock Development and Pony Express held by TD. noncontrolling interests of $6.2 million.
During the year ended December 31, 2017, we recognized contributions from and made distributions to noncontrolling interests of $1.6 million and $317.1 million, respectively. Contributions from noncontrolling interests consisted primarily of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of $185.7 million, Tallgrass Equity distributions to the Exchange Right Holders of $125.2 million, and distributions to Pony Express and Deeprock Development noncontrolling interests of $6.2 million.
During the year ended December 31, 2016, we recognized contributions from and made distributions to noncontrolling interests of $9.3 million and $249.1 million, respectively. Contributions from noncontrolling interests consisted primarily of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders
of $145.1 million, Tallgrass Equity distributions to the Exchange Right Holders of $97.5 million, and distributions to Pony Express and Water Solutions noncontrolling interests of $6.5 million.
Other Contributions and Distributions
During the year ended December 31, 2015, we2018, TGE recognized the following other contributions from and distributions:
TGE was deemed to have made distributionsa noncash capital distribution of $198.0 million, which represents the excess purchase price over the $53.8 million carrying value of the 5,619,218 TEP common units acquired as of February 7, 2018;
TGE was deemed to noncontrolling interestshave received a noncash capital contribution of $110.1$108.5 million, which represents the excess carrying value of the 25.01% membership interest in Rockies Express acquired as of February 7, 2018 over the fair value of the consideration paid; and $197.4
TEP was deemed to have made a noncash capital distribution of $16.2 million, respectively. Contributions from noncontrolling interests consisted primarilywhich represents the excess purchase price over the $33.8 million carrying value of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of $99.1 million, Tallgrass Equity distributions to the Exchange Right Holders of $28.7 million, and distributions toadditional 2% membership interest in Pony Express and Water Solutions noncontrolling interestsacquired as of $69.6 million.February 1, 2018.
Other Contributions and Distributions
During the year ended December 31, 2017, TGE recognized the following other contributions and distributions:
TEP was deemed to have made a noncash capital distribution of $57.7 million, which represents the excess purchase price over the $82.3 million carrying value of the Terminals and NatGas net assets acquired January 1, 2017;
TEP was deemed to have received a noncash capital contribution of $63.7 million, which represents the excess carrying value of the additional 24.99% membership interest in Rockies Express acquired March 31, 2017 over the fair value of the consideration paid; and
TEP received contributions from TD of $2.3 million primarily to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in Note 19 – Legal and Environmental Matters.
During the year ended December 31, 2016, TGE recognized the following other contributions and distributions:
TEP was deemed to have made noncash capital distributions of $280.0 million, which represent the excess purchase price over the $417.7 million carrying value of the additional 31.3% membership interest in Pony Express acquired effective January 1, 2016, partially offset by the 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015 closing price of our common units) issued to TD;
TEP received contributions from TD of $17.9 million primarily to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed above. In addition, we
TGE distributed the remaining $1.6 million in remaining proceeds from the TEGPTGE IPO to the Exchange Right Holders that had been retained from the distribution of Excess Proceeds for short-term working capital needs.
12. Revenue from Contracts with Customers
As discussed in Note 2 – Summary of Significant Accounting Policies, we adopted the guidance in ASC Topic 606 effective January 1, 2018 using the modified retrospective method of adoption. As a result, revenue reported for the years ended December 31, 2017 and 2016 have not been revised. The following tables provide the impact of ASC Topic 606 on our consolidated balance sheet as of December 31, 2018 and the consolidated statements of income for the year ended December 31, 2015, we distributed $334.1 million proceeds from the TEGP IPO2018:
|
| | | | | | | | | | | | |
| | December 31, 2018 | |
| | As currently reported | | Under previous guidance | | Impact of ASC Topic 606 | |
| | (in thousands) | |
| Unconsolidated investments | $ | 1,861,686 |
| | $ | 1,773,849 |
| | $ | 87,837 |
| (1) |
|
| | | | | | | | | | | | |
| | Year Ended December 31, 2018 | |
| | As currently reported | | Under previous guidance | | Impact of ASC Topic 606 | |
| | (in thousands) | |
| Crude oil transportation services | $ | 398,334 |
| | $ | 398,329 |
| | $ | 5 |
| (2) |
| Sales of natural gas, NGLs, and crude oil | $ | 168,586 |
| | $ | 173,055 |
| | $ | (4,469 | ) | (3) |
| Processing and other revenues | $ | 99,445 |
| | $ | 104,117 |
| | $ | (4,672 | ) | (1)(3) |
| Cost of sales | $ | 114,815 |
| | $ | 123,458 |
| | $ | (8,643 | ) | (2)(3) |
| Equity in earnings of unconsolidated investments | $ | 306,819 |
| | $ | 261,848 |
| | $ | 44,971 |
| (1) |
| Net income attributable to TGE | $ | 137,127 |
| | $ | 121,402 |
| | $ | 15,725 |
| |
| Basic net income per Class A share | $ | 1.27 |
| | $ | 1.13 |
| | $ | 0.14 |
| |
| Diluted net income per Class A share | $ | 1.27 |
| | $ | 1.13 |
| | $ | 0.14 |
| |
| |
(1) | Reflects the impact on our investment in Rockies Express and the management fee collected by NatGas of the cumulative effect adjustment at Rockies Express, which arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with rates that vary throughout the term of the contract. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas. |
| |
(2) | Reflects the impact to revenue and cost of sales to value PLA barrels collected under certain crude oil transportation arrangements at their contract inception fair value in revenue and record an associated lower of cost or net realizable value adjustment in cost of sales. |
| |
(3) | Reflects the reclassification of certain gathering and processing fees collected under arrangements determined to be supply arrangements, rather than customer arrangements under ASC 606, to cost of sales and the reclassification of certain commodities retained as consideration for processing services to processing fee revenue. |
Disaggregated Revenue
A summary of our revenue by line of business is as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2018 |
| | Natural Gas Transportation segment | | Crude Oil Transportation segment | | Gathering, Processing, & Terminalling segment | | Corporate and Other | | Total Revenue |
| | (in thousands) |
| Crude oil transportation - committed shipper revenue | $ | — |
| | $ | 392,276 |
| | $ | — |
| | $ | — |
| | $ | 392,276 |
|
| Natural gas transportation - firm service | 128,041 |
| | — |
| | — |
| | (4,585 | ) | | 123,456 |
|
| Water business services | — |
| | — |
| | 52,333 |
| | — |
| | 52,333 |
|
| Natural gas gathering & processing fees | — |
| | — |
| | 24,109 |
| | — |
| | 24,109 |
|
All other (1) | 11,223 |
| | 45,888 |
| | 18,444 |
| | (53,950 | ) | | 21,605 |
|
| Total service revenue | 139,264 |
| | 438,164 |
| | 94,886 |
| | (58,535 | ) | | 613,779 |
|
| Natural gas liquids sales | — |
| | — |
| | 101,382 |
| | — |
| | 101,382 |
|
| Natural gas sales | 1,195 |
| | — |
| | 29,558 |
| | — |
| | 30,753 |
|
| Crude oil sales | — |
| | 6,290 |
| | 652 |
| | — |
| | 6,942 |
|
| Total commodity sales revenue | 1,195 |
| | 6,290 |
| | 131,592 |
| | — |
| | 139,077 |
|
| Total revenue from contracts with customers | 140,459 |
| | 444,454 |
| | 226,478 |
| | (58,535 | ) | | 752,856 |
|
Other revenue (2) | — |
| | — |
| | 53,187 |
| | (12,784 | ) | | 40,403 |
|
Total revenue (3) | $ | 140,459 |
| | $ | 444,454 |
| | $ | 279,665 |
| | $ | (71,319 | ) | | $ | 793,259 |
|
| |
(1) | Includes revenue from crude oil transportation walk up shippers, crude oil terminal services, interruptible natural gas transportation and storage, and natural gas park and loan service. |
| |
(2) | Includes lease and derivative revenue not subject to ASC 606. |
| |
(3) | Excludes $930.8 million of revenue recognized at Rockies Express, BNN Colorado, and Pawnee Terminal for the year ended December 31, 2018. See Note 7 – Investments in Unconsolidated Affiliates for additional information. |
Performance Obligations
A performance obligation is a promise in a contract to transfer a distinct good or service to the Exchange Right Holderscustomer, and is the unit of account in ASC Topic 606. A contract's transaction price is allocated to each distinct performance obligation and recognized as partrevenue when, or as, the performance obligation is satisfied. The majority of our contracts have a single performance obligation and are billed and collected monthly.
All of our segments engage in commodity sales, in which our performance obligations include an obligation to deliver the specified volume of a commodity to the designated receipt point. Revenue from commodity sales is recognized at a point in time when the customer obtains control of the reorganizationcommodity, typically upon delivery to the designated delivery point when the customer accepts and takes possession of entities effective concurrentthe commodity.
In the Natural Gas Transportation segment, our performance obligations typically include an obligation to stand ready to provide natural gas transportation, storage, or an integrated transportation and storage service over the life of the contract, which is a series. These performance obligations are satisfied over time using each day of service to measure progress toward satisfaction of the performance obligation.
In the Crude Oil Transportation segment, our performance obligations typically include an obligation to provide crude oil transportation services over the life of the contract, which is a series. These performance obligations are satisfied over time using barrels delivered to measure progress toward satisfaction of the performance obligation.
In the Gathering, Processing & Terminalling segment, the performance obligations vary based on the operating asset and type of contract. In our natural gas gathering and processing arrangements, performance obligations typically include an obligation to provide an integrated processing service over the life of the contract, which is a series. These performance obligations are satisfied over time using each unit of gas processed to measure progress toward satisfaction of the performance
obligation. In our freshwater supply arrangements, performance obligations typically include an obligation to deliver a specified volume of water to the designated receipt point. These performance obligations are satisfied at a point in time when the customer obtains control of the water. In our produced water gathering and disposal arrangements, performance obligations typically include an obligation to provide an integrated produced water gathering and disposal service over the life of the contract, which is a series. These performance obligations are satisfied over time using barrels disposed to measure progress toward satisfaction of the performance obligation.
On December 31, 2018, we had $1.6 billion of remaining performance obligations at our consolidated subsidiaries, which we refer to as total backlog. Total backlog includes performance obligations under long-term crude oil transportation contracts with committed shippers, natural gas firm transportation and firm storage contracts, and certain water business service contracts with minimum volume commitments, and excludes variable consideration that is not estimated at contract inception, as discussed further below. We expect to recognize the TEGP IPO. In addition, we received $7.5 milliontotal backlog during future periods as follows (in thousands):
|
| | | | |
| Year | | Estimated Revenue |
|
| 2019 | | $ | 532,549 |
|
| 2020 | | 357,226 |
|
| 2021 | | 170,713 |
|
| 2022 | | 163,852 |
|
| 2023 | | 140,101 |
|
| Thereafter | | 210,625 |
|
| Total | | $ | 1,575,066 |
|
Contract Estimates
Accounting for long-term contracts involves the use of TEP general partnervarious techniques to estimate total contract revenue. Contract estimates are based on various assumptions to project the outcome of future events that often span several years. These assumptions include the anticipated volumes of crude oil expected to be delivered by our customers for transport in future periods.
The nature of our contracts gives rise to several types of variable consideration, including PLA, volumetric charges for actual volumes delivered, overrun charges, and IDR distributionsother fees that are contingent on the actual volumes delivered by our customers. As the amount of variable consideration is allocable to each distinct performance obligation within the series of performance obligations that comprise the single performance obligation and the uncertainty related to periods priorthe consideration is resolved each month as the distinct service is provided, we do not estimate the total variable consideration for the single overall performance obligation. Consequently, we are able to include in the transaction price each month the actual amount of variable consideration because no uncertainty exists surrounding the services provided that month.
Certain of our contracts include provisions in which a portion of the consideration is noncash. In our Crude Oil Transportation segment, we collect PLA from our customers. As crude oil is transported, we earn, and take title to, a portion of the oil transported for our services. Any PLA that remains after replacing losses in transit can be sold. Where PLA is determined to be a component of compensation for the transportation services provided, crude oil retained is recognized in revenue at its contract inception fair value. In our Gathering, Processing & Terminalling segment, we retain commodity products as consideration under certain of our gathering and processing arrangements. Processing fee revenue is recorded when the performance obligation is completed based on the value of the product received at the time services are performed. At this time, the variability of the non-cash consideration related to both form (price) and other-than-form (volume and product mix), which are interrelated, is resolved.
As a significant change in one or more of these estimates could affect the amount and timing of revenue recognized under our customer contracts, we review and update our contract-related estimates regularly.
Contract Balances
The timing of revenue recognition, billings, and cash collections may result in billed accounts receivable, unbilled receivables (contract assets), and deferred revenue (contract liabilities) on our consolidated balance sheets. Revenue is generally billed and collected monthly based on services provided or commodity volumes sold. In our Crude Oil Transportation segment, we recognize shipper deficiencies, or deferred revenue, for barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the TEGP IPO whichcustomers' agreed upon destination point. These shipper deficiencies are charged at the committed tariff rate per barrel and recorded as a contract liability until the barrels are physically transported and delivered, or when the likelihood that the customer will utilize the deficiency balance becomes
remote. We also recognize contract liabilities, in the form of deferred revenue, under certain water business services contracts in the Gathering, Processing & Terminalling segment. Contract balances as of December 31, 2018 were distributed to the previous TEP GP Members and $13.5 million of TEP distributions received which were distributed by Tallgrass Equity to the Exchange Right Holders.as follows:
|
| | | | | | | |
| | December 31, 2018 | | January 1, 2018 |
| | (in thousands) |
| Accounts receivable from contracts with customers | $ | 80,935 |
| | $ | 61,888 |
|
| Other accounts receivable | 151,414 |
| | 56,727 |
|
| Receivable from related parties | 3,748 |
| | 1,340 |
|
| Accounts receivable, net | $ | 236,097 |
| | $ | 119,955 |
|
| | | | |
Deferred revenue from contracts with customers (1) | $ | 111,095 |
| | $ | 88,471 |
|
| |
(1) | Revenue recognized during the year ended December 31, 2018 that was included in the deferred revenue balance at the beginning of the period was $12.0 million. This revenue primarily represented the utilization of shipper deficiencies at Pony Express. |
13. Commitments & Contingent Liabilities
Leases and Right of Way Agreements
Rent expense under operating leases and right of way agreements totaled approximately $1.4 million, $9.5 million, $16.5 million, and $16.1$16.5 million for the years ended December 31, 2018, 2017, 2016, and 2015,2016, respectively.
At December 31, 2017,2018, future minimum rental commitments under major, non-cancelable operating leases and right of way ("ROW") agreements were as follows (in thousands):
| | | Year | | Total | | Operating Lease and ROW Obligations | | Capital Lease Obligations |
| 2018 | | $ | 1,226 |
| |
| 2019 | | 1,351 |
| | $ | 1,818 |
| | $ | 449 |
|
| 2020 | | 1,414 |
| | 1,757 |
| | 449 |
|
| 2021 | | 1,093 |
| | 1,056 |
| | 449 |
|
| 2022 | | 828 |
| | 796 |
| | 449 |
|
| 2023 | | | 679 |
| | 449 |
|
| Thereafter | | 4,394 |
| | 3,153 |
| | 17,770 |
|
| Total | | $ | 10,306 |
| | $ | 9,259 |
| | $ | 20,015 |
|
Operating leases consist of leases for office space and equipment. Prior to the acquisition of a controlling interest in Deeprock Development in July 2017, as discussed in as discussed in Note 43 - Acquisitions and Dispositions, rent expense included payments made by Pony Express to Deeprock Development for the use by Pony Express of storage capacity at the Deeprock tank storage facility near Cushing, Oklahoma. Capital lease obligations consist of the PLT land site lease, as discussed in Note 3 - Acquisitions and Dispositions. The PLT land site lease includes a bargain purchase option exercisable after the initial lease term. PLT satisfied the capital lease obligation of $30.7 million at lease inception, and as a result has no imputed interest on the future minimum rental commitments in the table above. These future commitments represent certain administrative fees and estimated payments to the Plaquemines Port & Harbor Terminal District which approximate the ad valorem taxes that would be assessed if PLT acquired the land directly.
Capital Expenditures
We had committed approximately $17.3$39.6 million for the future purchase of property, plant and equipment at December 31, 2017.2018.
Other Purchase Obligations
Other purchase obligations primarily represent costs associated with Western's freshwater delivery and produced water gathering and disposal systems acquired in December 2015. Actual costs associated with these contracts totaled approximately $2.5 million, $1.4 million, and $4,000 for the years ended December 31, 2017, 2016, and 2015 respectively.
At December 31, 2017,2018, future minimum commitments under long-term, non-cancelable contracts for other purchase obligations were as follows (in thousands):
| | | Year | | Total | | Total |
| 2018 | | $ | 2,084 |
| |
| 2019 | | 2,091 |
| | $ | 13,467 |
|
| 2020 | | 2,070 |
| | 11,198 |
|
| 2021 | | 20 |
| | 6,677 |
|
| 2022 | | 20 |
| | 5,604 |
|
| 2023 | | | 5,614 |
|
| Thereafter | | 48 |
| | 13,231 |
|
| Total | | $ | 6,333 |
| | $ | 55,791 |
|
14. Net Income per Class A Share
Basic net income per Class A share is determined by dividing net income attributable to TEGPTGE by the weighted average number of outstanding Class A shares during the period. Class B shares do not share in the earnings of the Partnership.TGE. Accordingly, basic and diluted net income per Class B share has not been presented.
Diluted net income per Class A share is determined by dividing net income attributable to TEGPTGE by the weighted average number of outstanding diluted Class A shares during the period. For purposes of calculating diluted net income per Class A share, we considered the impact of possible future exercises of the Exchange Right by the Exchange Right Holders on both net income attributable to TEGPTGE and the diluted weighted average number of Class A shares outstanding. The Exchange Right Holders refers to the group of persons who collectively own all TEGP'sTGE's outstanding Class B shares and an equivalent number of Tallgrass Equity units. The Exchange Right Holders are entitled to exercise the right to exchange their Tallgrass Equity units (together with an equivalent number of TEGPTGE Class B shares) for TEGPTGE Class A shares at an exchange ratio of one TEGPTGE Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. TheAs of February 8, 2019, the Exchange Right Holders primarily consist of Kelso, & Company and its affiliated investment funds, The Energy & Minerals Group and its affiliated investment funds,EMG and Tallgrass KC, LLC, which is an entity owned byKC. Following consummation of the Blackstone Acquisition, the Exchange Right Holders will primarily consist of BIP and certain members of TEGP's and TEP'sTGE's management.
Pursuant to the TEGPTGE partnership agreement and the Tallgrass Equity limited liability company agreement, our capital structure and the capital structure of Tallgrass Equity will generally replicate one another in order to maintain the one-for-one exchange ratio between the Tallgrass Equity units and Class B shares, on the one hand, and our Class A shares, on the other hand. As a result, the exchange of any Class B shares for Class A shares does not have a dilutive effect on basic net income per Class A share. However, for the years ended December 31, 20162018 and 2015,2016, the potential issuance of TEGPTGE Equity Participation Shares would have had a dilutive effect on basic net income per Class A share. The potential issuance of TEGPTGE Equity Participation Shares would not have had a dilutive effect on the basic net loss per Class A share for the year ended December 31, 2017.
The TEGP IPO became effective during the second quarter of 2015. As a result, no income from the period from January 1, 2015 through May 11, 2015 is allocated to the Class A shares that were issued on May 12, 2015.
All net income or loss from Terminals and NatGas prior to TEP's acquisition on January 1, 2017 is allocated to predecessor operations in the consolidated statements of income. Accordingly, no net income or loss from Terminals and NatGas is allocated to our Class A shareholders. We present the financial results of any transferred business prior to the transaction date in the line item "Predecessor operations interest in net income" in the consolidated statements of income.
The following table illustrates the calculation of net income per Class A share for the years ended December 31, 2018, 2017, 2016, and 2015:2016:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in thousands, except per unit amounts) |
| Basic Net Income per Class A Share: | | | | | |
| Net (loss) income attributable to TEGP, excluding predecessor operations interest | $ | (128,729 | ) | | $ | 26,794 |
| | $ | 31,956 |
|
| Net income attributable to TEGP prior to May 12, 2015 | — |
| | — |
| | (7,393 | ) |
| Net (loss) income attributable to TEGP subsequent to May 12, 2015 | $ | (128,729 | ) | | $ | 26,794 |
| | $ | 24,563 |
|
| Basic weighted average Class A Shares outstanding | 58,076 |
| | 48,856 |
| | 47,725 |
|
| Basic net (loss) income per Class A share | $ | (2.22 | ) | | $ | 0.55 |
| | $ | 0.51 |
|
| Diluted Net Income per Class A Share: | | | | | |
| Net (loss) income attributable to TEGP subsequent to May 12, 2015 | $ | (128,729 | ) | | $ | 26,794 |
| | $ | 24,563 |
|
| Incremental net income attributable to TEGP including the effect of the assumed issuance of Equity Participation Shares | — |
| | 9 |
| | 6 |
|
| Net (loss) income attributable to TEGP including incremental net income from assumed issuance of Equity Participation Shares | $ | (128,729 | ) | | $ | 26,803 |
| | $ | 24,569 |
|
| Basic weighted average Class A Shares outstanding | 58,076 |
| | 48,856 |
| | 47,725 |
|
| Equity Participation Shares equivalent shares | — |
| | 33 |
| | 83 |
|
| Diluted weighted average Class A Shares outstanding | 58,076 |
| | 48,889 |
| | 47,808 |
|
| Diluted net (loss) income per Class A Share | $ | (2.22 | ) | | $ | 0.55 |
| | $ | 0.51 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in thousands, except per unit amounts) |
| Basic Net Income per Class A Share: | | | | | |
| Net income (loss) attributable to TGE, excluding predecessor operations interest | $ | 137,127 |
| | $ | (128,729 | ) | | $ | 26,794 |
|
| Basic weighted average Class A Shares outstanding | 107,586 |
| | 58,076 |
| | 48,856 |
|
| Basic net income (loss) per Class A share | $ | 1.27 |
| | $ | (2.22 | ) | | $ | 0.55 |
|
| Diluted Net Income per Class A Share: | | | | | |
| Net income (loss) attributable to TGE, excluding predecessor operations interest | $ | 137,127 |
| | $ | (128,729 | ) | | $ | 26,794 |
|
| Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares | 2,108 |
| | — |
| | 9 |
|
| Net income (loss) attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares | $ | 139,235 |
| | $ | (128,729 | ) | | $ | 26,803 |
|
| Basic weighted average Class A Shares outstanding | 107,586 |
| | 58,076 |
| | 48,856 |
|
| Equity Participation Shares equivalent shares | 2,231 |
| | — |
| | 33 |
|
| Diluted weighted average Class A Shares outstanding | 109,817 |
| | 58,076 |
| | 48,889 |
|
| Diluted net income (loss) per Class A Share | $ | 1.27 |
| | $ | (2.22 | ) | | $ | 0.55 |
|
15. Major Customers and Concentration of Credit Risk
During the yearyears ended December 31, 2018 and 2017, one non-affiliated customer, Continental Resources, Inc. ("Continental Resources"), accounted for $81.9 million (10%) and $100.2 million (15%), of our total operating revenue.revenues, respectively. During the year ended December 31, 2016, two non-affiliated customers, Continental Resources and Shell Trading (US) Company ("Shell"), accounted for $97.8 million (16%) and $76.2 million (12%) of our total operating revenues, respectively. DuringRevenues from Continental Resources for the year ended December 31, 2015 two non-affiliated customers, Continental Resources2018 were earned in our Crude Oil Transportation and Shell, accounted for $84.5 million (16%) and $78.6 million (14%) of our total operating revenues, respectively.Gathering, Processing & Terminalling segments. Revenues from Continental Resources for the years ended December 31, 2017 2016, and 20152016 were earned in our Crude Oil Transportation segment. Revenues from Shell for the yearsyear ended December 31, 2016 and 2015 were earned in our Natural Gas Transportation, Crude Oil Transportation, and Gathering, Processing & Terminalling segments.
For the year ended December 31, 2017,2018, the percentage of segment revenues from the top ten non-affiliated customers for each segment was as follows:
|
| | |
| | | Percentage of Segment Revenue |
| Natural Gas Transportation | | 56%58% |
| Crude Oil Transportation | | 91%84% |
| Gathering, Processing & Terminalling | | 75%60% |
We attempt to mitigate credit risk by seeking credit support, such as letters of credit, prepayments or other financial guarantees from customers with specific credit concerns. In support of credit extended to certain customers, we had received prepayments of $4.9 million at December 31, 2017 and 2016, included in the caption "Other current liabilities" in the accompanying consolidated balance sheets.
16. Equity-Based Compensation
Long-term Incentive Plan
Effective May 12, 2015, our general partner adoptedWe have two long-term incentive plans. The Tallgrass Energy GP, LLC Long-Term Incentive Plan (f/k/a the TEGP Management, LLC Long-Term Incentive Plan), was originally adopted by our general partner effective as of May 1, 2015, and was amended and restated effective August 2, 2018 (as amended, the "TGE LTIP"). In addition, the Tallgrass MLP GP, LLC Long-Term Incentive Plan ("was originally adopted by TEP GP effective as of May 13, 2013, and was amended and restated effective August 2, 2018 (as amended, the "Legacy LTIP" and together with the TGE LTIP, the "Plans") on. In connection with the completion of the TEP Merger effective June 30, 2018, the Legacy LTIP was assumed by our behalfgeneral partner.
Awards under the Plans may consist of, among others, unrestricted shares, restricted shares, equity participation shares, options and share appreciation rights which may be granted to (i) the employees of our general partner and its affiliates who perform services for us, (ii) the non-employee directors of our general partner and (iii) the consultants who perform services for us. Awards under the LTIP may consist of, among others, unrestricted shares, restricted shares, equity participation shares, options and share appreciation rights. The TGE LTIP limits the number of shares that may be delivered pursuant to awards to 3,144,589 Class A shares, (subjectand the Legacy LTIP limits the number of shares that may be delivered pursuant to awards under such plan to 20,000,000 Class A shares, subject in each case to any adjustment due to recapitalization, reorganization or a similar event permitted under the LTIP).applicable Plan. Shares that are forfeited or withheld to satisfy exercise price or tax withholding obligations are available for delivery pursuant to other awards.awards under the applicable Plan. The Plans are administered by the board of directors of our general partner or a committee thereof, which is referred to as the plan administrator.
Equity Participation Shares
Vesting of the Equity Participation Shares granted to date is contingent on certain service and performance conditions. The Equity Participation Shares are non-participating; as such participants are not entitled to receive any distributionsdividends with respect to the Equity Participation Shares unless the participant receives a separate grant of Distribution Equivalent Rights. At this time, no grants of Distribution Equivalent Rights have been made.
The Equity Participation Share grants under the LTIPPlans are measured at their grant date fair value. The Equity Participation Shares are non-participating; therefore, the grant date fair value is discounted from the grant date fair value of TEGP'sTGE's Class A shares for the present value of the expected future distributionsdividends during the vesting period. Effective June 30, 2018 with the completion of the TEP Merger, as discussed in Note 1 – Description of Business, TEP's outstanding Equity Participation Units were converted to Equity Participation Shares at a ratio of 2.0 Equity Participation Shares for each outstanding TEP Equity Participation Unit. Total equity-based compensation cost related to the Equity Participation Share grants was approximately $7.6 million, $1.6 million, $1.4 million, and $0.5$1.4 million for the years ended December 31, 2018, 2017, and 2016 and 2015 respectively.respectively, excluding costs associated with TEP's Equity Participation Units prior to the TEP Merger. Of the total compensation cost, $0.2$7.6 million, $0.2 million, and $32,000$0.2 million for the years ended December 31, 2018, 2017, 2016, and 20152016 respectively, were recognized as compensation expense at TEGPTGE and the remainder was allocated to TEP and TD. As of December 31, 2017, $2.42018, $34.3 million of total compensation cost related to non-vested Equity Participation Shares is expected to be recognized over a weighted-average period of 1.63.2 years.
The following table summarizes the changes in the Equity Participation Shares outstanding for the years ended December 31, 2018, 2017 2016 and 2015:2016:
| | | | Equity Participation Shares | | Weighted Average
Grant Date Fair Value | Equity Participation Shares | | Weighted Average
Grant Date Fair Value |
| | | | | | | |
| Outstanding at January 1, 2015 | — |
| | $ | — |
| |
| Granted | 160,000 |
| | 27.97 |
| |
| Outstanding at December 31, 2015 | 160,000 |
| | 27.97 |
| |
| Outstanding at January 1, 2016 | | 160,000 |
| | $ | 27.97 |
|
| Granted | 45,000 |
| | 18.22 |
| 45,000 |
| | 18.22 |
|
| Outstanding at December 31, 2016 | 205,000 |
| | 25.83 |
| 205,000 |
| | 25.83 |
|
| Granted | 30,000 |
| | 23.66 |
| 30,000 |
| | 23.66 |
|
| Vested | (10,002 | ) | | (14.26 | ) | (10,002 | ) | | (14.26 | ) |
| Outstanding at December 31, 2017 | 224,998 |
| | $ | 25.91 |
| 224,998 |
| | 25.91 |
|
| Granted | | 1,138,200 |
| | 17.01 |
|
Converted (1) | | 1,786,310 |
| | 18.20 |
|
| Vested | | (20,664 | ) | | (19.19 | ) |
| Forfeited | | (79,200 | ) | | (20.62 | ) |
| Outstanding at December 31, 2018 | | 3,049,644 |
| | $ | 18.25 |
|
| |
(1) | Reflects TEP's outstanding Equity Participation Units that were converted to Equity Participation Shares at a ratio of 2.0 Equity Participation Shares for each outstanding TEP Equity Participation Unit upon completion of the TEP Merger as discussed above. |
17. Income Taxes
Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be recovered, a valuation allowance is established. We record a valuation allowance to reduce our deferred tax assets to the amount we believe is more likely than not to be realized. In making these determinations we consider historical and projected taxable income, and ongoing prudent and feasible tax planning strategies, in assessing the appropriateness of a valuation allowance. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective.
The Reorganization Transactions became effective on May 12, 2015. As a result, no income prior to May 12, 2015 is subject to income tax.
U.S. Federal and State Taxes
Although we are organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes and are therefore subject to both U.S. federal and state income taxes. We are projecting a loss for both U.S. federal and state income taxes for the tax year ended December 31, 2017.2018. As a result, there is no current provision for income taxes for the year ended December 31, 2017.2018.
Tax Components
Components of the deferred income tax expense (benefit) are as follows: | | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
| Deferred tax expense (benefit): | | | | | | |
| Deferred income tax expense: | | | | | | |
| Federal income tax | $ | 200,787 |
| | $ | 15,587 |
| | $ | 5,675 |
| $ | 41,585 |
| | $ | 200,787 |
| | $ | 15,587 |
|
| State income tax | 7,671 |
| | 2,154 |
| | (12,952 | ) | 14,124 |
| | 7,671 |
| | 2,154 |
|
| Total deferred tax expense (benefit) | $ | 208,458 |
| | $ | 17,741 |
| | $ | (7,277 | ) | |
| Total deferred income tax expense | | $ | 55,709 |
| | $ | 208,458 |
| | $ | 17,741 |
|
The difference between tax expense based on the statuary federal income tax rate and our effective tax expense is summarized as follows:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
| Income before tax | $ | 432,443 |
| | $ | 267,780 |
| | $ | 193,071 |
| |
| Net income before tax | | $ | 523,380 |
| | $ | 432,443 |
| | $ | 267,780 |
|
| Less: Predecessor operations interest in net income | — |
| | (6,995 | ) | | (12,357 | ) | — |
| | — |
| | (6,995 | ) |
| Income before tax, excluding predecessor operations interest | 432,443 |
| | 260,785 |
| | 180,714 |
| |
| Net income before tax, excluding predecessor operations interest | | 523,380 |
| | 432,443 |
| | 260,785 |
|
| Less: Net income attributable to noncontrolling interests | (352,714 | ) | | (216,250 | ) | | (156,035 | ) | (330,544 | ) | | (352,714 | ) | | (216,250 | ) |
| Less: Net income attributable to TEGP prior to May 12, 2015 | — |
| | — |
| | (7,393 | ) | |
| Income subject to tax | $ | 79,729 |
| | $ | 44,535 |
| | $ | 17,286 |
| |
| Net income subject to tax | | $ | 192,836 |
| | $ | 79,729 |
| | $ | 44,535 |
|
| Federal statutory income tax rate | 35 | % | | 35 | % | | 35 | % | 21 | % | | 35 | % | | 35 | % |
| Income tax at statutory rate | $ | 27,905 |
| | $ | 15,587 |
| | $ | 6,050 |
| $ | 40,496 |
| | $ | 27,905 |
| | $ | 15,587 |
|
| State income taxes, net of federal benefit | 2,392 |
| | 1,592 |
| | 449 |
| 5,419 |
| | 2,392 |
| | 1,592 |
|
| Change in state tax rate | 1,353 |
| | 562 |
| | (13,776 | ) | 8,705 |
| | 1,353 |
| | 562 |
|
| Other | | 1,089 |
| | — |
| | — |
|
| Valuation allowance | 3,926 |
| | — |
| | — |
| — |
| | 3,926 |
| | — |
|
| Total income tax expense before change in tax legislation | $ | 35,576 |
| | $ | 17,741 |
| | $ | (7,277 | ) | $ | 55,709 |
| | $ | 35,576 |
| | $ | 17,741 |
|
| Impact of federal tax legislation on deferred tax asset | 172,037 |
| | — |
| | — |
| — |
| | 172,037 |
| | — |
|
| Impact of federal tax legislation on valuation allowance | 845 |
| | — |
| | — |
| — |
| | 845 |
| | — |
|
| Total income tax expense (benefit) | $ | 208,458 |
| | $ | 17,741 |
| | $ | (7,277 | ) | |
| Total income tax expense | | $ | 55,709 |
| | $ | 208,458 |
| | $ | 17,741 |
|
| Effective tax rate | 48.2 | % | | 6.8 | % | | (4.0 | )% | 10.6 | % | | 48.2 | % | | 6.8 | % |
Deferred tax assets result from the following:
| | | | December 31, 2017 | | December 31, 2016 | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
| Deferred tax assets: | | | | | | |
| Investment in partnerships | $ | 269,136 |
| | $ | 473,888 |
| $ | 198,290 |
| | $ | 269,136 |
|
| Net operating losses | 48,632 |
| | 47,566 |
| 80,012 |
| | 48,632 |
|
| Deferred tax assets before valuation allowance | $ | 317,768 |
| | $ | 521,454 |
| $ | 278,302 |
| | $ | 317,768 |
|
| Valuation allowance | (4,771 | ) | | — |
| (4,771 | ) | | (4,771 | ) |
| Total deferred tax assets | $ | 312,997 |
| | $ | 521,454 |
| $ | 273,531 |
| | $ | 312,997 |
|
| | | | | |
| Deferred tax liability: | | | | |
| Equity earnings adjustment pursuant to ASC 606 | | $ | 817 |
| | $ | — |
|
On May 12, 2015, as a result of the transfer of the ownership interest in Tallgrass Equity as part of the Reorganization Transactions in connection with the TEGPTGE IPO, we recognized a deferred tax asset of $445.2 million. In November 2016, we completed the Secondary Offering as discussed in Note 1211 – Partnership Equity and Distributions. In connection with the resulting transfer of Tallgrass Equity Units, we recognized an additional deferred tax asset of $86.8 million. During 2018, a portion of the Exchange Right Holders exercised their Exchange Right as discussed in Note 11 – Partnership Equity. In connection with the resulting transfer of Tallgrass Equity Units, we recognized an additional deferred tax asset of $15.4 million. These transfers of ownership were accounted for at the historical carrying basis for GAAP accounting purposes, but recorded at the value of the consideration paid for U.S. federal income tax purposes. The tax rates that apply when the deferred tax balances ultimately reverse are inherent in the realization of the deferred tax balances. State tax rates can change from year to year based upon changes in both state apportionment percentages and state tax laws.
As of December 31, 2017,2018, we had a federal net operating loss carry forward of $196.0$328.2 million and various state net operating loss carry forwards. The determination of the state net operating loss carry forwards is dependent upon apportionment percentages and state laws that can change from year to year and impact the amount of such carry forwards. If not utilized, the federal net operating loss carry forward will expire between 2035 and 2037 and the state operating loss carry forwards will expire between 2025 and 2037. We believe that it is more likely than not that the benefit from certain state operating loss carryforwards will not be realized. In recognition of this risk, we have provided a valuation allowance on the deferred tax assets relating to these carryforwards.
On December 22, 2017, legislation referred to as the “Tax"Tax Cuts and Jobs Act”Act" ("TCJA") was signed into law. Substantially all provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes amendments to the Internal Revenue Code of 1986 that significantly change the taxation of individuals and business entities. Pursuant to ASC Topic 740, Income Taxes (ASC 740), we recognized the tax effect of the TCJA changes during the year ended December 31, 2017, the period in which the law was enacted. ASC 740 requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Accordingly, we remeasured our deferred tax asset based on the new tax rates, resulting in an increase to our tax provision of $172.9 million for the year endingended December 31, 2017.
The 2015 2016 and 2017through 2018 tax years are open to examination for federal and state tax.
18. Regulatory Matters
There are no regulatory proceedings challenging the rates of Pony Express, Rockies Express, Tallgrass Interstate Gas Transmission, LLC ("TIGT") or TIGT. On June 29, 2018, Trailblazer Pipeline Company LLC ("Trailblazer"). filed a general rate case with the FERC pursuant to Section 4 of the Natural Gas Act ("NGA"), as further described below. We have also made certain regulatory filings with the FERC, including the following:
Pony Express
On May 25, 2016, Pony Express made a tariff filing with the FERC in Docket No. IS16-326-000 to update its non-contract rates under its Local Pipeline Tariff for local non-contract rates from all origins, by an amount reflecting the most recent FERC annual index adjustment of approximately 0.9799 effective July 1, 2016, which resulted in a reduction of the Pony Express non-contract rates of 2.01%.
On May 22, 2017 and May 31, 2017, Pony Express made tariff filings with the FERC in Docket Nos. IS17-263-000, IS17-464-00, and IS17-465-000 to increase the contract and non-contract rates by an amount reflecting the most recent FERC annual index adjustment of approximately 0.2%, which became effective July 1, 2017.
On November 30, 2017, Pony Express filed with the FERC in Docket No. IS18-60-000 certain changes to its tariffs to reflect the addition of two new destination points proposed to be effective January 1, 2018.
On December 29, 2017, Pony Express filed with the FERC in Docket No. IS18-113-000 certain changes to its tariffs to reflect a new origin point in Rooks County, Kansas. The changes were proposed to become effective on February 1, 2018.
Rockies Express
Petition for Declaratory Order – FERC Docket No. RP13-969-000
In June 2013, in Docket No. RP13-969-000, Rockies Express filed with the FERC a Petition for Declaratory Order which sought a ruling that the "most favored nations" or "MFN" provisions contained in Rockies Express' negotiated rate agreements ("NRAs") with its Foundation and Anchor Shippers would not prevent Rockies Express from providing firm transportation service at rates lower than Foundation and Anchor Shippers' rates that (1) have an east-to-west primary path; (2) are for a term of one year or longer; and (3) are limited to service in one rate zone and therefore do not utilize all of the same facilities or rate
zones as the service provided pursuant to the Foundation and Anchor Shipper NRAs. In November 2013, the FERC issued a declaratory order finding that the potential transactions would not trigger the MFN rights of Rockies Express’Express' Foundation and Anchor Shippers. Various parties filed requests for rehearing of the FERC’sFERC's declaratory order.
In September 2014 and December 2015, the FERC accepted amended contracts with the shippers holding MFN rights on Rockies Express, which reflect the terms of settlements between these shippers and Rockies Express. The settlements provide additional clarity with respect to the applicability of the settling shippers' MFN rights, sharing by Rockies Express of certain transportation revenues, and the withdrawal of the settling shippers from the Petition for Declaratory Order proceeding. On September 27, 2017, FERC issued an order denying the requests for rehearing of the declaratory order issued in November 2013, and no party sought judicial appeal of the FERC order denying rehearing within the statutory deadline.
2015 Annual FERC Fuel Tracking Filings - FERC Docket No. RP15-584-000
On February 27, 2015, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2015 in Docket No. RP15-584-000. This filing incorporated the revised fuel and lost and unaccounted-for and power cost tracker mechanisms filed in Docket No. RP14-1003. The FERC issued an order accepting the filing on March 26, 2015 and on April 9, 2015, accepted an errata to the February 27, 2015 filing reflecting a corrected rate for the Cheyenne Booster rate (PCT Reimbursement Charge).
Seneca Lateral Facilities Conversion – FERC Docket No. CP15-102-000
On March 2, 2015 in Docket No. CP15-102-000, Rockies Express filed with the FERC an application for (1) authorization to convert certain existing and operating pipeline and compression facilities located in Noble and Monroe Counties, Ohio (Seneca Lateral Facilities described in Docket Nos. CP13-539-000 and CP14-194-000) from Natural Gas Policy Act of 1978 Section 311 authority to NGA Section 7 jurisdiction, and (2) issuance of a certificate of public convenience and necessity authorizing Rockies Express to operate and maintain the Seneca Lateral Facilities. On April 7, 2016, the FERC issued a Certificate to Rockies Express granting its requested authorizations and on June 1, 2016 Rockies Express commenced NGA service on the Seneca Lateral.
Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000
On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. The facilities increased the Rockies Express Zone 3 east-to-west mainline capacity by 0.8 Bcf/d. Pursuant to the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the project facilities. The project was placed in-service for the full 0.8 Bcf/d on January 6, 2017.
2016 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP16-702RP16-702-000 and RP17-240RP17-240-000
On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in Docket No. RP16-702.RP16-702-000. The FERC issued an order accepting the filing on March 25, 2016. On December 1, 2016, Rockies Express made an interim fuel tracker filing with a proposed effective date of January 1, 2017 in Docket No. RP17-240.RP17-240-000. The FERC issued an order accepting the filing on December 29, 2016.
Electric Power Charge Clarification - FERC Docket No. RP17-285RP17-285-000
On December 21, 2016, in Docket No. RP17-285,RP17-285-000, Rockies Express proposed certain revisions to the General Terms and Conditions of its tariff to clarify that the electric power costs associated with the operation of gas coolers installed in association with the Zone 3 Capacity Enhancement Project at both electric and gas powered stations, will be included in the Power Cost Tracker. Several shippers submitted comments on the proposal. The FERC issued an order on January 19, 2017 accepting the proposed revisions permitting the recovery of electric power costs from the operation of both gas and electric powered compressor stations, subject to certain clarifications.
2017 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP17-401RP17-401-000 and RP17-1064RP17-1064-000
On February 13, 2017, in Docket No. RP17-401,RP17-401-000, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2017. The FERC issued an order accepting the filing, including certain requested waivers, on March 21, 2017. On September 20, 2017, Rockies Express made its interim fuel tracker filing in Docket No. RP17-1064RP17-1064-000 with a proposed effective date of November 1, 2017. The FERC issued an order accepting the filing on October 18, 2017.
Increased Frequency of FL&U and PCT Adjustments - FERC Docket No. RP18-228RP18-228-000
On December 1, 2017, in Docket No. RP18-228,RP18-228-000, Rockies Express made a filing with the FERC to increase the frequency in which it may adjust fixed fuel and lost and unaccounted for retainages and power cost tracker charges during the year so that its recovery of fixed fuel and lost and unaccounted for charges and power costs more closely track usage. Rockies Express proposed an effective date of April 1, 2018. The comment period ended on December 13, 2017, and no parties opposed Rockies Express’Express' filing. On April 4, 2018, the FERC issued a letter order accepting Rockies Express' proposal, subject to certain modifications. Rockies Express submitted a compliance filing reflecting the approved tariff provisions and requested
modifications on April 10, 2018. No comments on the compliance filing were submitted by the comment deadline of April 16, 2018. On April 18, 2018, the FERC issued an order accepting Rockies Express' compliance filing effective April 19, 2018.
2018 Annual FERC Fuel Tracking Filing - FERC Docket No. RP18-453-000
On February 20, 2018, in Docket No. RP18-453-000, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2018. The matter isFERC issued an order accepting the filing on March 19, 2018.
Cheyenne Hub Enhancement Project - FERC Docket No. CP18-103-000
On March 2, 2018, Rockies Express submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity authorizing the construction and operation of certain booster compressor units and ancillary facilities located at the Cheyenne Hub in Weld County, Colorado that will enable Rockies Express to provide a new hub service allowing for firm receipts and deliveries between Rockies Express and certain other interconnected pipelines at the Cheyenne Hub. Rockies Express filed this certificate application in conjunction with a concurrently filed certificate application by Cheyenne Connector, LLC ("Cheyenne Connector") for the Cheyenne Connector Pipeline Project further described below. The comment period for the Cheyenne Hub Enhancement Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Rockies Express has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment.
Rockies Express Form No. 501-G Filing - FERC Docket No. RP19-412-000
On December 6, 2018, Rockies Express submitted its one-time informational filing in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and the FERC's changes to its Income Tax Policy Statement following the decision of the U.S. Court of Appeals for the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. The filing remains pending before the FERC.
Cheyenne Connector
Cheyenne Connector Pipeline Project - FERC Docket No. CP18-102-000
On March 2, 2018, Cheyenne Connector, an indirect subsidiary of TGE, submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity to construct and operate a 70-mile, 36-inch pipeline to transport natural gas from multiple gas processing plants in Weld County, Colorado to Rockies Express' Cheyenne Hub. The comment period for the Cheyenne Connector Pipeline Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Cheyenne Connector has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment.
TIGT
General Rate Case Filing - FERC Docket No. RP16-137-000, et seq.
On October 30, 2015, in Docket No. RP16-137-000, et seq., TIGT filed a general rate case with the FERC pursuant to Section 4 of the National Gas Act ("NGA").NGA. The general rate case was ultimately resolved via settlement, which the FERC approved on November 2, 2016, and a compliance filing that modernized TIGT’sTIGT's FERC Gas Tariff, consistent with prior FERC orders, which the FERC accepted on March 16, 2017. Per the terms of the settlement, TIGT is required to file a new general rate case on May 1, 2019 (provided that such rate case is not pre-empted by a pre-filing settlement).
2017 Annual Fuel Tracker Filing - FERC Docket No. RP17-428-000
On February 27, 2017, in Docket No. RP17-428-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2017. The filing incorporated the FL&U tracker and power cost tracker mechanisms agreed to in the TIGT Rate Case Settlement. The FERC accepted the filing on March 21, 2017.
Electric Power Charge Clarification - FERC Docket No. RP17-1051-000
On September 15, 2017, in Docket No. RP17-1051-000, TIGT proposed certain revisions to its tariff to clarify, amongst other things, that the electric power costs associated with the operation of gas coolers at both electric and gas powered stations are properly included in the Power Cost Tracker. The FERC issued an order on October 3, 2017 accepting the proposed revisions.
Trailblazer
General Rate Case
2018 Annual Fuel Tracker Filing - FERC Docket No. RP13-1031-000, et. seq.RP18-533-000
On JulyMarch 1, 2013,2018, in Docket No. RP13-1031-000, et. seq., Trailblazer filedRP18-533-000, TIGT made its annual fuel tracker filing with a generalproposed effective date of April 1, 2018. The FERC accepted the filing on March 22, 2018.
TIGT Form No. 501-G Filing - FERC Docket No. RP19-423-000
On December 6, 2018, TIGT submitted its one-time informational filing in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate case with the FERC pursuant to Section 4effect of the NGA. The general rate case was ultimately resolved via settlement, whichchanges in tax laws and policy following the FERC approved on May 29, 2014. PerTax Cuts and Jobs Act and the termsFERC's changes to its Income Tax Policy Statement following the decision of the settlement, Trailblazer is required to file a new general rate case with rates to be effective no later than January 1, 2019 (presuming a maximum suspension periodU.S. Court of Appeals for any rate increase).the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. On December 18, 2018, one protest and one set of comments were filed by intervenors in the docket. The filing remains pending before the FERC.
Trailblazer
2016 Annual Fuel Tracker Filing – FERC Docket Nos. RP16-814-000 and RP16-814-001
On April 1, 2016, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2016 in Docket No. RP16-814-000. The FERC accepted this filing on April 18, 2016. On May 19, 2016, Trailblazer filed its refund report associated with the April 1, 2016 annual fuel tracker filing, which the FERC accepted on July 11, 2016. On September 7, 2016, Trailblazer filed an adjustment to its April 1, 2016 filing in Docket No. RP16-814-001, which the FERC accepted on October 3, 2016. Trailblazer filed a corresponding refund report on October 14, 2016, which the FERC accepted on November 16, 2016.
2017 Annual and Interim Fuel Tracker Filings - FERC Docket Nos. RP17-549-000 and RP17-1052-000
On March 22, 2017, in Docket No. RP17-549-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2017. The FERC accepted the filing on April 19, 2017. On September 15, 2017, Trailblazer made its interim fuel tracker filing in Docket No. RP17-1052-000 with a proposed effective date of November 1, 2017. The FERC accepted the filing on October 13, 2017.
2018 Annual Fuel Tracker Filing - FERC Docket No. RP18-580-000
On March 22, 2018, in Docket No. RP18-580-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2018. The FERC accepted the filing on April 20, 2018.
General Rate Case Filing - FERC Docket No. RP18-922-000, et seq.
On June 29, 2018, Trailblazer filed a general rate case with the FERC, which satisfies the requirement set forth in the settlement resolving Trailblazer's previous general rate case that Trailblazer file a new general rate case with rates to be effective no later than January 1, 2019. The June 29, 2018 filing reflects an overall increase to Trailblazer's cost of service. In the filing, Trailblazer is proposing to maintain its existing bifurcated firm transportation service rate design as well as its current tracking methodologies for the treatment of Fuel and Lost and Unaccounted For ("FL&U") gas and electric power costs. The proposed rates include an increase in rates on Trailblazer's Existing System Firm Transportation Service. The overall rate increase would be partially offset by a proposed decrease in rates for Expansion System Firm Transportation Service and interruptible services. Trailblazer is also proposing to include a cost recovery mechanism in its tariff to recover future eligible costs related to system safety, integrity, reliability, environmental and cybersecurity issues. Under the NGA and the FERC's regulations, Trailblazer's shippers and other interested parties, including the FERC's Trial Staff, have the right to challenge any aspect of Trailblazer's rate case filing. On July 11, 2018, four protests were filed that challenge various aspects of Trailblazer's rate case filing. FERC action remains pending.
On July 31, 2018, the FERC issued an Order accepting and suspending the rate case filing, and establishing hearing and settlement procedures. In the Order, the FERC approved the as-filed rate decreases for Expansion System Firm Transportation Service, as well as Trailblazer's interruptible services, effective August 1, 2018. The Commission also established a paper hearing to examine the extent to which Trailblazer is entitled to an income tax allowance. All remaining issues, including the proposed rate increases to Existing System Firm Transportation Service have been set for hearing and are accepted effective January 1, 2019, subject to refund. On August 30, 2018, Trailblazer and certain of Trailblazer's shippers filed a request for rehearing of the July 31, 2018 Order, which remains pending before the FERC. Consistent with the July 31, 2018 Order, on August 30, 2018, certain of Trailblazer's shippers and other interested parties filed initial briefs regarding the Income Tax Allowance issue. Trailblazer filed its reply brief regarding the same on September 14, 2018. On November 1, 2018, Trailblazer filed a supplement to its reply brief addressing a recent FERC order regarding the appropriate methodology used to calculate return on equity and discussing the impact of such order on Trailblazer's proposed Income Tax Allowance. The briefs remain pending before the FERC. On August 28, 2018, the participants attended an initial settlement conference. On September 12, 2018, the Chief Administrative Law Judge issued an order continuing settlement judge procedures. On November 15, 2018, the participants attended a second settlement conference. On December 31, 2018, Trailblazer filed a motion with the FERC to
move the suspended tariff records into effect as of January 1, 2019. In January 2019, the participants attended a third settlement conference. A fourth settlement conference is scheduled in late February 2019.
Pony Express
On May 25, 2016, Pony Express made a tariff filing with the FERC in Docket No. IS16-326-000 to update its non-contract rates under its Local Pipeline Tariff for local non-contract rates from all origins, by an amount reflecting the most recent FERC annual index adjustment of approximately 0.9799 effective July 1, 2016, which resulted in a reduction of the Pony Express non-contract rates of 2.01%.
On May 22, 2017 and May 31, 2017, Pony Express made tariff filings with the FERC in Docket Nos. IS17-263-000, IS17-464-000, and IS17-465-000 to increase the contract and non-contract rates by an amount reflecting the FERC annual index adjustment of approximately 0.2%, which became effective July 1, 2017.
On November 30, 2017, Pony Express filed with the FERC in Docket No. IS18-60-000 certain changes to its tariffs to reflect the addition of two new destination points, which became effective January 1, 2018.
On December 29, 2017, Pony Express filed with the FERC in Docket No. IS18-113-000 certain changes to its tariffs to reflect a new origin point in Rooks County, Kansas, which became effective on February 1, 2018.
On February 28, 2018, Pony Express filed with the FERC in Docket No. IS18-199-000 certain changes to its tariffs to reflect a new origin point in Platteville, Colorado, which became effective on April 1, 2018.
On March 1, 2018, Pony Express submitted proposed revisions to its Rules and Regulations Tariff in Docket No. IS18-204-000 to establish the right to accept "Specialty Batches" of oil that do not conform to the Quality Specifications reflected in the tariff, provided that the acceptance is operationally feasible. These tariff changes became effective on April 1, 2018.
On April 11, 2018, Pony Express filed with the FERC in Docket No. IS18–267–000 certain changes to its tariffs to reflect additional contract rates from a new origin point in Platteville, Colorado, which became effective May 1, 2018.
On May 2, 2018, Pony Express filed with the FERC in Docket No. IS18-297-000 certain changes to its rules and regulations applicable to new intermediate off-system storage points, which became effective May 15, 2018.
On May 31, 2018, Pony Express made tariff filings with the FERC in Docket No. IS18-570-000 to increase the contract and non-contract rates by an amount reflecting the FERC annual index adjustment of approximately 4.4% which became effective July 1, 2018.
On January 11, 2019, Pony Express filed with the FERC in Docket No. IS19-145-000 certain changes to its tariffs to incorporate the Sterling origin point in Logan County, Colorado in the published rate schedules, to establish a line fill return rate from the Natoma origin point, and to make minor clarifying edits.
Iron Horse
Petition for Declaratory Order - FERC Docket No. OR19-9-000
On November 9, 2018, Iron Horse filed a Petition for Declaratory Order with the FERC, requesting approval of Iron Horse's proposed rate structures, Committed Shipper rights, and prorationing provisions for shippers and various other aspects of the Transportation Service Agreement for service on the pipeline. The Petition is pending before the FERC.
19. Legal and Environmental Matters
Legal
In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such routine itemsmatters will not have a material adverse impact on our business, financial position, results of operations, or cash flows.
We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, have recorded no reserve for legal claims as of December 31, 20172018 and 2016.2017.
Rockies Express
Ohio Public Utility Excise Tax
The Ohio Tax Commissioner has assessed Rockies Express a public utility excise tax on transactions concerning product that entered and exited Rockies Express within the state of Ohio. This tax applies to gross receipts from all business conducted within the state, but exempts all receipts derived wholly from interstate business. Rockies Express has disputed any obligation
to pay Ohio's public utility excise tax, but has paid the taxes as assessed in order to preserve its right to appeal. The dispute is currently pending before the Ohio Supreme Court, with a final decision possible by the end of 2019. It is Rockies Express' position that the relevant statute exempts receipts derived wholly from interstate business from the public utility excise tax. The Ohio Supreme Court and the United States Supreme Court have both held that, once it enters an interstate pipeline, natural gas is moving in "interstate commerce" for the duration of its journey until it is delivered to a local distribution system. While it is difficult to accurately predict how the Ohio Supreme Court will decide the case, Rockies Express is optimistic about the ultimate outcome.
As of December 31, 2018, Rockies Express has paid public utility excise taxes to the state of Ohio totaling $7.1 million, accrued an additional $3.3 million for amounts expected to be assessed through the year ended December 31, 2018, and has recognized a $10.4 million deposit representing the anticipated refund of the public utility excise taxes paid.
Mineral Management Service Lawsuit
On June 30, 2009, Rockies Express filed claims against Mineral Management Service, a former unit of the U.S. Department of Interior (collectively "Interior") for breach of its contractual obligation to sign transportation service agreements for pipeline capacity that it had agreed to take on Rockies Express. The Civilian Board of Contract Appeals ("CBCA") conducted a trial and ruled that Interior was liable for breach of contract, but limited the damages Interior was required to pay. On September 13, 2013, the United States Court of Appeals for the Federal Circuit issued a decision affirming that Interior was
liable for its breach of contract, but reversing the CBCA's decision to limit damages. The case was remanded to the CBCA for the purpose of calculating damages at a hearing. On May 20, 2016, Rockies Express and Interior agreed to resolve the claims in this matter in exchange for a $65 million cash payment to Rockies Express. Interior paid the amount due Rockies Express on June 23, 2016.
Ultra Resources
In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2 Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14, 2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, seeking approximately $303 million in damages and other relief. On April 29, 2016, Ultra and certain of its debtor affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District of Texas, which operated as a stay of the Harris County state court proceeding.
On January 12, 2017, Rockies Express and Ultra entered into an agreement to settle Rockies Express' approximately $303 million claim against Ultra. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of $150 million on July 12, 2017, and entered into a new, seven-year firm transportation agreement with Rockies Express commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate of approximately $0.37 per dth/d, or approximately $26.8 million annually. TEPWe received itsour proportionate distribution from the cash settlement payment in July 2017.
Michels Corporation
On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express in the Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due.
On February 2, 2017, Rockies Express and Michels agreed to resolve Michels' claims for a $10 million cash payment by Rockies Express. The cash payment was inclusive of approximately $5.9 million that Rockies Express had been withholding from Michels. Subsequently, Rockies Express and Michels entered into a definitive agreement with respect to the settlement and Rockies Express made the $10 million cash payment to Michels on February 16, 2017.
Environmental, Health and Safety
We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. We currently believe that compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. We had environmental reserves of $7.7$7.4 million and $4.0$7.7 million at December 31, 2018 and 2017, respectively.
Rockies Express
Seneca Lateral
On January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and 2016, respectively.natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations. The release required Rockies Express to shut off the flow through the segment until February 27, 2018, when temporary repairs were completed allowing the segment to be placed back into service. Total cost of remediation was approximately $6.1 million prior to any insurance recoveries. Permanent repairs were completed in September 2018. As of February 8, 2019, Rockies Express has recovered a significant majority of these costs from insurance.
TMID
Casper Plant, EPA Notice of Violation
In August 2011, the EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, Tallgrass Midstream, LLC ("TMID") received a letter from the EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including the expected inclusion of TIGT as a party to any possible settlement as a result of TIGT owning a compressor that is located adjacent to the Casper Gas Plant site.
Casper Mystery Bridge Superfund Site
The Casper Gas Plant is part of the Mystery Bridge Road/U.S. Highway 20 Superfund Site also known as Casper Mystery Bridge Superfund Site. Remediation work at the Casper Gas Plant has been completed and we have requested that the portion of the site attributable to us be delisted from the National Priorities List. On July 3, 2017, our partial delisting request was published by the EPA in the Federal Register. On August 3, 2017, there were no adverse public comments, therefore on August 29, 2017, the Casper Gas Plant portion of the Casper Mystery Bridge Superfund Site was delisted from the National Priorities List.
Casper Gas Plant
On November 25, 2014, WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing.
TMG
Archibald Booster Station
Tallgrass Midstream Gathering, LLC ("TMG") is currently a party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Archibald Booster Station located in Campbell County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling, and quarterly recovery activities at monitoring wells. The facility is currently in compliance with the WDEQ under the remedy agreement.
Irwin Booster Station
TMG is also party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Irwin Booster Station located in Converse County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling. The facility is currently in compliance with the WDEQ under the remedy agreement.
Trailblazer
Pipeline Integrity Management Program
Starting in 2014 Trailblazer’sTrailblazer's operating capacity was decreased as a result of smart tool surveys that identified approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing
subscription levels or had a material adverse financial impact on us. However, Trailblazer intends to continuecontinued performing remediation to increase and maximize its operating capacity over the long-term and expects to spend in excess of $20spent approximately $21 million during 2018 for this pipe replacement and remediation work. As of October 2018, the pipeline was returned to its maximum allowable operating capacity. Trailblazer is exploring all possible cost recovery options to recover expenditures, including recovery through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.
In connection with TEP's acquisition of Trailblazer in April 2014, TD agreed to indemnify TEP for certain out of pocket costs related to repairing or remediating the Trailblazer Pipeline. The contractual indemnity was capped at $20 million and subject to a $1.5 million deductible. TEP has received the entirety of the $20 million from TD pursuant to the contractual indemnity as of December 31, 2017.
Pony Express
Pipeline Integrity
In connection with certain crack tool runs on the Pony Express System completed in 2015, 2016, and 2016,2017, Pony Express completed approximately $10$18 million of remediation for anomalies identified on the Pony Express System associated with the initial conversion and commissioning of portions of the pipeline converted from natural gas to crude oil service, and has completed additional remediation on the Pony Express Systemservice. Remediation work was substantially complete as of approximately $8.2 million during the year ended DecemberMarch 31, 2017.2018.
Terminals
System Failures
In January 2017, approximately 10,000 bbls of crude oil were released at the Sterling Terminal as the result of a defective roof drain system on a storage tank. The release was restricted to the containment area designed for such purpose and approximately 9,000 bbls were recovered. Remediation was complete as of June 30, 2017. The total cost to remediate the release was approximately $600,000.
20. Reportable Segments
Our operations are located in the United States. During the third quarter of 2017, management revised the operational reporting used by the chief operating decision maker in light of recent acquisitions and commercial management reorganization. As a result of this internal change, our reportable segments were updated to ensure that segment classification remains aligned with operational reporting. We are organized into three reportable segments: (1) Natural Gas Transportation, (2) Crude Oil Transportation, and (3) Gathering, Processing & Terminalling. Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable segments, such as interest and fees associated with our revolving credit facility and the Senior Notes, public company costs, and equity-based compensation expense.
Natural Gas Transportation
The Natural Gas Transportation segment is engaged in the ownership and operation of FERC-regulated interstate natural gas pipelines and an integrated natural gas storage facility that providesprovide services to on-system customers (such as third-party LDCs), industrial users and other shippers. The Natural Gas Transportation segment includes our 100% membership interest in NatGas acquired effective January 1, 2017 and our 49.99%aggregate 75% membership interest in Rockies Express, includinginclusive of the additional 24.99%25.01% membership interest acquired effective March 31, 2017.February 7, 2018.
Crude Oil Transportation
The Crude Oil Transportation segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale, Denver-Julesburg and Powder River Basins, and other nearby oil producing basins. The mainline portion of the Pony Express System was placed in service in October 2014. The Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System just east of Sterling, Colorado and was placed in service in the second quarter of 2015.
Gathering, Processing & Terminalling
The Gathering, Processing & Terminalling segment is engaged in the ownership and operation of natural gas gathering and processing facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets, including the Douglas Gathering System acquired on June 5, 2017, as well asmarkets; our crude oil terminal services; water business services provided primarily to the oil and gas exploration and production industry andindustry; the transportation of NGLs. The Gathering, Processing & Terminalling segment also includes Stanchion as well as our 100% membership interest in Terminals acquired effective January 1, 2017NGLs; and the PRB Crude System acquired on August 3, 2017.
Corporate and Other
Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable segments, such as interest and fees associated with our revolving credit facilities and the 2024 and 2028 Notes, public company costs, and equity-based compensation expense.Stanchion.
These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for their respective operations. During the second quarter of 2018, upon completion of the TEP Merger, management updated TGE's internal reporting. Beginning in the second quarter of 2018, we consider Adjusted EBITDA, as described below, to be our primary segment performance measure.
We consider Adjusted EBITDA to be our primary segment performance measure as we believe it is the most meaningful measure to assess our financial condition and results of operations as a public entity. We define Adjusted EBITDA as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments and deficiency payments received from or utilized by our customers. Adjusted EBITDA is calculated and presented at the Tallgrass Equity level, before consideration of noncontrolling interest associated with the Exchange Right Holders, which we believe provides investors the most complete picture of our overall financial and operational results.
The following tables set forth our segment information for the periods indicated:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| Revenue: | Total
Revenue | | Inter-
Segment | | External
Revenue | | Total
Revenue | | Inter-
Segment | | External
Revenue | | Total
Revenue | | Inter-
Segment | | External
Revenue | Total
Revenue | | Inter-
Segment | | External
Revenue | | Total
Revenue | | Inter-
Segment | | External
Revenue | | Total
Revenue | | Inter-
Segment | | External
Revenue |
| | (in thousands) | (in thousands) |
| Natural Gas Transportation | $ | 141,021 |
| | $ | (6,694 | ) | | $ | 134,327 |
| | $ | 135,097 |
| | $ | (5,641 | ) | | $ | 129,456 |
| | $ | 137,988 |
| | $ | (5,384 | ) | | $ | 132,604 |
| $ | 140,459 |
| | $ | (4,661 | ) | | $ | 135,798 |
| | $ | 141,021 |
| | $ | (6,694 | ) | | $ | 134,327 |
| | $ | 135,097 |
| | $ | (5,641 | ) | | $ | 129,456 |
|
| Crude Oil Transportation | 364,574 |
| | (10,676 | ) | | 353,898 |
| | 380,503 |
| | (370 | ) | | 380,133 |
| | 304,227 |
| | — |
| | 304,227 |
| 444,454 |
| | (39,319 | ) | | 405,135 |
| | 364,574 |
| | (10,676 | ) | | 353,898 |
| | 380,503 |
| | (370 | ) | | 380,133 |
|
| Gathering, Processing & Terminalling | 186,211 |
| | (18,538 | ) | | 167,673 |
| | 113,533 |
| | (11,460 | ) | | 102,073 |
| | 113,387 |
| | (7,557 | ) | | 105,830 |
| 279,665 |
| | (27,339 | ) | | 252,326 |
| | 186,211 |
| | (18,538 | ) | | 167,673 |
| | 113,533 |
| | (11,460 | ) | | 102,073 |
|
| Corporate and Other | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| Total revenue | $ | 691,806 |
| | $ | (35,908 | ) | | $ | 655,898 |
| | $ | 629,133 |
| | $ | (17,471 | ) | | $ | 611,662 |
| | $ | 555,602 |
| | $ | (12,941 | ) | | $ | 542,661 |
| $ | 864,578 |
| | $ | (71,319 | ) | | $ | 793,259 |
| | $ | 691,806 |
| | $ | (35,908 | ) | | $ | 655,898 |
| | $ | 629,133 |
| | $ | (17,471 | ) | | $ | 611,662 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| Operating Income: | Total
Operating Income | | Inter-
Segment | | External
Operating Income |
| | (in thousands) |
| Natural Gas Transportation | $ | 67,434 |
| | $ | (7,709 | ) | | $ | 59,725 |
|
| Crude Oil Transportation | 190,170 |
| | 17,263 |
| | 207,433 |
|
| Gathering, Processing & Terminalling | 33,453 |
| | (9,554 | ) | | 23,899 |
|
| Corporate and Other | (19,210 | ) | | — |
| | (19,210 | ) |
| Total Operating Income | $ | 271,847 |
| | $ | — |
| | $ | 271,847 |
|
| Reconciliation to Net Income: | | | | | |
| Interest expense, net | | | | | (89,348 | ) |
| Equity in earnings of unconsolidated investments | | | | | 237,110 |
|
| Unrealized gain on derivative instrument | | | | | 1,885 |
|
| Gain on remeasurement of unconsolidated investment | | | | | 9,728 |
|
| Other income, net | | | | | 1,221 |
|
| Net income before tax | | | | | $ | 432,443 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Tallgrass Equity Adjusted EBITDA: | Total
Adjusted EBITDA | | Inter-
Segment | | External
Adjusted EBITDA | | Total
Adjusted EBITDA | | Inter-
Segment | | External
Adjusted EBITDA | | Total
Adjusted EBITDA | | Inter-
Segment | | External
Adjusted EBITDA |
| | (in thousands) |
| Natural Gas Transportation | $ | 377,224 |
| | $ | (4,251 | ) | | $ | 372,973 |
| | $ | 180,978 |
| | $ | (2,176 | ) | | $ | 178,802 |
| | $ | 75,029 |
| | $ | (1,633 | ) | | $ | 73,396 |
|
| Crude Oil Transportation | 239,330 |
| | (8,147 | ) | | 231,183 |
| | 140,785 |
| | 4,878 |
| | 145,663 |
| | 132,154 |
| | 4,881 |
| | 137,035 |
|
| Gathering, Processing & Terminalling | 59,203 |
| | 12,398 |
| | 71,601 |
| | 16,083 |
| | (2,702 | ) | | 13,381 |
| | 4,078 |
| | (3,248 | ) | | 830 |
|
| Corporate and Other | (21,321 | ) | | — |
| | (21,321 | ) | | (37,591 | ) | | — |
| | (37,591 | ) | | (2,142 | ) | | — |
| | (2,142 | ) |
| Reconciliation to Net Income: | | | | | | | | | | | | | | | | | |
| Add: | | | | | | | | | | | | | | | | | |
Equity in earnings of unconsolidated investments (1) | | | | | 237,197 |
| | | | | | 66,922 |
| | | | | | 15,287 |
|
Gain (loss) on disposal of assets(1) | | | | | 4,630 |
| | | | | | 189 |
| | | | | | (526 | ) |
Non-cash gain (loss) related to derivative instruments (1) | | | | | 3,340 |
| | | | | | (64 | ) | | | | | | (650 | ) |
Gain on remeasurement of unconsolidated investment (1) | | | | | — |
| | | | | | 2,744 |
| | | | | | — |
|
| Less: | | | | | | | | | | | | | | | | | |
Interest expense, net(1) | | | | | (95,465 | ) | | | | | | (29,403 | ) | | | | | | (16,632 | ) |
Depreciation and amortization expense (1) | | | | | (74,998 | ) | | | | | | (26,131 | ) | | | | | | (25,567 | ) |
Distributions from unconsolidated investments (1) | | | | | (302,364 | ) | | | | | | (86,551 | ) | | | | | | (22,085 | ) |
Non-cash compensation expense (1) | | | | | (8,634 | ) | | | | | | (2,682 | ) | | | | | | (1,862 | ) |
Deficiency payments, net (1) | | | | | (14,443 | ) | | | | | | (7,701 | ) | | | | | | (9,672 | ) |
| Loss on debt retirement | | | | | (2,245 | ) | | | | | | — |
| | | | | | — |
|
| Deferred income tax expense | | | | | (55,709 | ) | | | | | | (208,458 | ) | | | | | | (17,741 | ) |
| Net income attributable to Exchange Right Holders | | | | | (208,618 | ) | | | | | | (137,849 | ) | | | | | | (95,882 | ) |
| Net income (loss) attributable to TGE | | | | | $ | 137,127 |
| | | | | | $ | (128,729 | ) | | | | | | $ | 33,789 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| Operating Income: | Total
Operating Income | | Inter-
Segment | | External
Operating Income |
| | (in thousands) |
| Natural Gas Transportation | $ | 56,135 |
| | $ | (5,641 | ) | | $ | 50,494 |
|
| Crude Oil Transportation | 215,784 |
| | 16,843 |
| | 232,627 |
|
| Gathering, Processing & Terminalling | (903 | ) | | (11,202 | ) | | (12,105 | ) |
| Corporate and Other | (12,598 | ) | | — |
| | (12,598 | ) |
| Total Operating Income | $ | 258,418 |
| | $ | — |
| | $ | 258,418 |
|
| Reconciliation to Net Income: | | | | | |
| Interest expense, net | | | | | (45,601 | ) |
| Unrealized loss on derivative instrument | | | | | (1,291 | ) |
| Equity in earnings of unconsolidated investments | | | | | 54,531 |
|
| Other income, net | | | | | 1,723 |
|
| Net income before tax | | | | | $ | 267,780 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| Operating Income: | Total
Operating Income | | Inter-
Segment | | External
Operating Income |
| | (in thousands) |
| Natural Gas Transportation | $ | 48,133 |
| | $ | (5,384 | ) | | $ | 42,749 |
|
| Crude Oil Transportation | 159,467 |
| | 12,941 |
| | 172,408 |
|
| Gathering, Processing & Terminalling | 7,995 |
| | (7,557 | ) | | 438 |
|
| Corporate and Other | (9,366 | ) | | — |
| | (9,366 | ) |
| Total Operating Income | $ | 206,229 |
| | $ | — |
| | $ | 206,229 |
|
| Reconciliation to Net Income: | | | | | |
| Interest expense, net | | | | | (18,330 | ) |
| Equity in earnings of unconsolidated investments | | | | | 2,759 |
|
| Other income, net | | | | | 2,413 |
|
| Net income before tax | | | | | $ | 193,071 |
|
| |
(1) | Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity. |
| | | | Year Ended December 31, | Year Ended December 31, |
| Depreciation and Amortization Expense: | 2017 | | 2016 | | 2015 | |
| Capital Expenditures: | | 2018 | | 2017 | | 2016 |
| | (in thousands) | (in thousands) |
| Natural Gas Transportation | $ | 19,180 |
| | $ | 20,976 |
| | $ | 22,927 |
| $ | 112,529 |
| | $ | 16,705 |
| | $ | 28,475 |
|
| Crude Oil Transportation | 52,364 |
| | 51,362 |
| | 47,168 |
| 65,745 |
| | 57,022 |
| | 29,893 |
|
| Gathering, Processing & Terminalling | 19,256 |
| | 13,909 |
| | 14,163 |
| 185,732 |
| | 71,417 |
| | 26,123 |
|
| Corporate and Other | — |
| | — |
| | — |
| 4,867 |
| | — |
| | — |
|
| Total depreciation and amortization expense | $ | 90,800 |
| | $ | 86,247 |
| | $ | 84,258 |
| |
| Total capital expenditures | | $ | 368,873 |
| | $ | 145,144 |
| | $ | 84,491 |
|
| | | | Year Ended December 31, | |
| Capital Expenditures: | 2017 | | 2016 | | 2015 | |
| Unconsolidated Investments: | | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
| Natural Gas Transportation | $ | 16,705 |
| | $ | 28,475 |
| | $ | 10,478 |
| $ | 1,794,987 |
| | $ | 895,873 |
|
| Crude Oil Transportation | 57,022 |
| | 29,893 |
| | 38,802 |
| 35,467 |
| | — |
|
| Gathering, Processing & Terminalling | 71,417 |
| | 26,123 |
| | 71,438 |
| 31,232 |
| | 13,658 |
|
| Corporate and Other | — |
| | — |
| | — |
| |
| Total capital expenditures | $ | 145,144 |
| | $ | 84,491 |
| | $ | 120,718 |
| |
| Total unconsolidated investments | | $ | 1,861,686 |
| | $ | 909,531 |
|
|
| | | | | | | |
| Unconsolidated Investments: | December 31, 2017 | | December 31, 2016 |
| | (in thousands) |
| Natural Gas Transportation | $ | 895,873 |
| | $ | 461,915 |
|
| Crude Oil Transportation | — |
| | — |
|
| Gathering, Processing & Terminalling | 13,658 |
| | 13,710 |
|
| Corporate and Other | — |
| | — |
|
| Total unconsolidated investments | $ | 909,531 |
| | $ | 475,625 |
|
| | | Assets: | December 31, 2017 | | December 31, 2016 | December 31, 2018 | | December 31, 2017 |
| | (in thousands) | (in thousands) |
| Natural Gas Transportation | $ | 1,606,666 |
| | $ | 1,176,147 |
| $ | 2,606,696 |
| | $ | 1,606,666 |
|
| Crude Oil Transportation | 1,407,758 |
| | 1,410,695 |
| 1,423,740 |
| | 1,407,758 |
|
| Gathering, Processing & Terminalling | 943,340 |
| | 495,170 |
| 1,522,559 |
| | 943,340 |
|
| Corporate and Other | 334,249 |
| | 543,468 |
| 340,514 |
| | 334,249 |
|
| Total assets | $ | 4,292,013 |
| | $ | 3,625,480 |
| $ | 5,893,509 |
| | $ | 4,292,013 |
|
21. Selected Quarterly Financial Data (Unaudited)
The following tables summarize our unaudited quarterly financial data for 20172018 and 2016:2017:
| | | | Quarter Ended 2017 | Quarter Ended 2018 |
| | First | | Second | | Third | | Fourth | First | | Second | | Third | | Fourth |
| | (in thousands, except per unit amounts) | (in thousands, except per unit amounts) |
| Total revenues | $ | 144,400 |
| | $ | 160,863 |
| | $ | 175,869 |
| | $ | 174,766 |
| $ | 179,094 |
| | $ | 193,589 |
| | $ | 200,320 |
| | $ | 220,256 |
|
| Operating income | $ | 63,226 |
| | $ | 66,944 |
| | $ | 74,003 |
| | $ | 67,674 |
| $ | 81,913 |
| | $ | 79,275 |
| | $ | 90,084 |
| | $ | 99,359 |
|
| Net income | $ | 67,238 |
| | $ | 79,167 |
| | $ | 170,777 |
| | $ | (93,197 | ) | $ | 114,313 |
| | $ | 109,701 |
| | $ | 118,712 |
| | $ | 124,945 |
|
| Net income (loss) attributable to TEGP | $ | 12,029 |
| | $ | 8,753 |
| | $ | 15,866 |
| | $ | (165,377 | ) | |
| Net income allocable to noncontrolling interests | $ | (55,209 | ) | | $ | (70,414 | ) | | $ | (154,911 | ) | | $ | (72,180 | ) | $ | (97,578 | ) | | $ | (108,638 | ) | | $ | (59,162 | ) | | $ | (65,166 | ) |
| Basic net income (loss) per Class A Share | $ | 0.21 |
| | $ | 0.15 |
| | $ | 0.27 |
| | $ | (2.85 | ) | |
| Diluted net income (loss) per Class A Share | $ | 0.21 |
| | $ | 0.15 |
| | $ | 0.27 |
| | $ | (2.85 | ) | |
| Net income attributable to TGE | | $ | 16,735 |
| | $ | 1,063 |
| | $ | 59,550 |
| | $ | 59,779 |
|
| Basic net income per Class A Share | | $ | 0.29 |
| | $ | 0.02 |
| | $ | 0.38 |
| | $ | 0.38 |
|
| Diluted net income per Class A Share | | $ | 0.29 |
| | $ | 0.02 |
| | $ | 0.38 |
| | $ | 0.38 |
|
During the second quarter of 2018, we recognized increased deferred income tax expense as a result of our increased ownership in TEP due to the TEP Merger and the resulting increase in income allocated to TGE.
|
| | | | | | | | | | | | | | | |
| | Quarter Ended 2017 |
| | First | | Second | | Third | | Fourth |
| | (in thousands, except per unit amounts) |
| Total revenues | $ | 144,400 |
| | $ | 160,863 |
| | $ | 175,869 |
| | $ | 174,766 |
|
| Operating income | $ | 63,226 |
| | $ | 66,944 |
| | $ | 74,003 |
| | $ | 67,674 |
|
| Net income | $ | 67,238 |
| | $ | 79,167 |
| | $ | 170,777 |
| | $ | (93,197 | ) |
| Net income allocable to noncontrolling interests | $ | (55,209 | ) | | $ | (70,414 | ) | | $ | (154,911 | ) | | $ | (72,180 | ) |
| Net income (loss) attributable to TGE | $ | 12,029 |
| | $ | 8,753 |
| | $ | 15,866 |
| | $ | (165,377 | ) |
| Basic net income (loss) per Class A Share | $ | 0.21 |
| | $ | 0.15 |
| | $ | 0.27 |
| | $ | (2.85 | ) |
| Diluted net income (loss) per Class A Share | $ | 0.21 |
| | $ | 0.15 |
| | $ | 0.27 |
| | $ | (2.85 | ) |
During the third quarter of 2017, we recognized equity in earnings relating to our proportionate share of the Ultra settlement discussed in Note 19 – Legal and Environmental Matters. During the fourth quarter of 2017, we remeasured our deferred tax asset based on the new tax rates as a result of the federal rate change under the TCJA signed into law on December 22, 2017, resulting in an increase to our tax provision. For additional information, see Note 17 – Income Taxes.
|
| | | | | | | | | | | | | | | |
| | Quarter Ended 2016 |
| | First | | Second | | Third | | Fourth |
| | (in thousands, except per unit amounts) |
| Total revenues | $ | 147,168 |
| | $ | 149,015 |
| | $ | 153,268 |
| | $ | 162,211 |
|
| Operating income | $ | 63,445 |
| | $ | 54,758 |
| | $ | 66,943 |
| | $ | 73,272 |
|
| Net income | $ | 44,306 |
| | $ | 80,721 |
| | $ | 60,402 |
| | $ | 64,610 |
|
| Net income attributable to TEGP | $ | 11,274 |
| | $ | (440 | ) | | $ | 10,652 |
| | $ | 12,303 |
|
| Net income allocable to noncontrolling interests | $ | (33,032 | ) | | $ | (81,161 | ) | | $ | (49,750 | ) | | $ | (52,307 | ) |
| Basic net income per Class A Share | $ | 0.16 |
| | $ | 0.07 |
| | $ | 0.15 |
| | $ | 0.17 |
|
| Diluted net income per Class A Share | $ | 0.16 |
| | $ | 0.07 |
| | $ | 0.15 |
| | $ | 0.17 |
|
22. Subsequent Events
Deeprock North Acquisition and Merger with Deeprock DevelopmentPowder River Gateway
On January 2, 2018, Terminals acquired an approximate 38% membership interest in Deeprock North, LLC ("Deeprock North") from Kinder Morgan Deeprock North Holdco LLC for cash consideration of $19.5 million. Immediately following the acquisition, Deeprock North was merged into Deeprock Development. After the acquisition and merger, Terminals owns an approximately 60% membership interest in the combined entity.
BNN North Dakota Acquisition
In January 2018, Water Solutions2019, we closed the acquisitionon an expansion of a 100% membership interest in Buckhorn Energy Services, LLC and Buckhorn SWD Solutions, LLC (collectively, "BNN North Dakota") for cash consideration of approximately $95.0 million, subject to working capital adjustments. BNN North Dakota owns a produced water gathering and disposal system in the Bakken basinour joint venture with approximately 133,000 acres under dedication.
Potential Acquisition of Pawnee Terminal
OnSilver Creek. Effective January 2, 2018, Terminals entered into an agreement to acquire1, 2019, we own a 51% membership interest in Powder River Gateway, which owns the Pawnee, ColoradoIron Horse Pipeline, the PRE Pipeline, and crude oil terminal (“Pawnee Terminal”) from Zenith Energy Terminals Holdings, LLC for cash considerationfacilities in Guernsey, Wyoming. For additional information, see Note 3 – Acquisitions and Dispositions.
Blackstone Acquisition
On January 31, 2019, we announced that BIP had entered into a definitive purchase agreement with Kelso, EMG, and Tallgrass KC pursuant to which BIP will acquire 100% of approximately $31 million, subjectthe membership interests in our general partner and an approximate 44% economic interest in us. Subject to working capital adjustments. Terminals expectscustomary closing conditions, the transactionBlackstone Acquisition is expected to close inwithin the first quarter of 2018, subject to certain closing conditions.
Acquisition of Additional Interest in Pony Express
Effective February 1, 2018, TEP acquired the remaining 2% membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from Tallgrass Development for cash consideration of approximately $60 million, bringing its aggregate membership interest in Pony Express to 100%.
Potential Joint Venture and Sale of TCG
On February 6, 2018, TEP entered into an agreement with an affiliate of Silver Creek Midstream, LLC ("Silver Creek") to form Iron Horse Pipeline, a new joint venture pipeline to transport crude oil from the Powder River Basin. In addition to forming the joint venture, TEP has also agreed to sell to Silver Creek its 100% membership interest in TCG, which owns a 50-mile crude oil gathering system in the Powder River Basin. TEP expects to close the sale of TCG and the formation of the joint venture in February 2018.
Tallgrass Equity Acquisitions
On February 7, 2018, Tallgrass Development merged into Tallgrass Development Holdings, a wholly-owned subsidiary of Tallgrass Equity, and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TEGP and Tallgrass Equity issued 27,554,785 unregistered TEGP Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of Tallgrass Development. The equity issued by TEGP and Tallgrass Equity was based on a discounted 30-day volume weighted average price of TEGP Class A shares. The 25.01% membership interest
was valued at approximately $400 million and the 5,619,218 TEP common units were valued at approximately $256.2 million based on a 30-day volume weighted average price.
Seneca Lateral
On January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations, however, the release required Rockies Express to shut off the flow through the segment. Repairs are underway to return the segment to service as soon as possible and a root cause investigation is ongoing. 2019.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based upon their evaluation of those controls and procedures performed as of December 31, 2017,2018, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective.
Management's Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles.
As of December 31, 2017,2018, the Partnership's management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control - Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of acquisitions made in 2017 of Terminals, the Douglas Gathering System and the 49% membership interest in Deeprock Development whose total assets and total revenue excluded from management's assessment collectively represent approximately 10% and 5%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2017. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. Management is in the process of integrating these acquisitions and the Partnership’s internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Based on this assessment and those criteria, management determined that we maintained effective internal control over financial reporting as of December 31, 2017.2018.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our independent registered public accounting firm, PricewaterhouseCoopers LLP, audited the effectiveness of our internal control over financial reporting as of December 31, 2017,2018, as stated in their report included in Item 8.—Financial Statements and Supplementary Data of this Annual Report.
Changes in Internal Control over Financial Reporting
There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 20172018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
We are a limited partnership and have no officers or directors. Unless otherwise indicated, references to our officers and directors in Items 10 through 14 of this Annual Report refer to the officers and directors of our general partner.
Management of Tallgrass Energy, GP, LP
Our general partner's board of directors and executive officers manage our operations and activities. Our general partner is not elected by our Class A shareholders and will not be subject to re-election in the future. Directors of our general partner oversee our operations. Class A shareholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations.
Unlike shareholders in a publicly traded corporation, our shareholders are not entitled to select our general partner or elect the members of the board of directors of our general partner. Tallgrass Energy Holdings is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including our independent directors. As of February 8, 2019, EMG, Kelso and Tallgrass KC own, in the aggregate, approximately 100% of the outstanding membership interests in Tallgrass Energy Holdings. AllFollowing consummation of the Blackstone Acquisition, the membership interests in our general partner will be owned by BIP. As of February 8, 2019, all the executive officers and certain of the directors of our general partner are also officers and/or directors of TEP GP and Tallgrass Energy Holdings.
Neither we nor our general partner have any employees. Although all the employees that conduct our business are employed by Tallgrass Management, we sometimes refer to these individuals in this Annual Report as our employees.
As of December 31, 2017,2018, the board of directors of our general partner had eightnine directors, threefour of whom the board has determined meet the independence standards established by the NYSE. The threefour independent directors are Jeffrey A. Ball, Thomas A. Gerke, Roy N. Cook and W. Curtis Koutelas.Terrance D. Towner. The NYSE does not require a publicly-traded limited partnership like ours to have a majority of independent directors on the board of directors of its general partner or to establish a compensation or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act. As of December 31, 2017,2018, the audit committee of the board of directors of our general partner had threefour members, each of whom meet the independence and experience standards established by the NYSE and the Exchange Act.
In evaluating director candidates, Tallgrass Energy Holdings assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board's ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.
All the executive officers of our general partner are also officers of TEP GP, Tallgrass Equity, and Tallgrass Energy Holdings. Our officers will devote such portion of their business time to our business and affairs as they deem reasonably required to manage and conduct our operations. Neither our general partner nor TEP'sOur general partner and its affiliates do not currently receive any management fee in connection with the management of our business, but Tallgrass Equity reimburses our general partner for all expenses it incurs and payments it makes on our behalf pursuant to our partnership agreement. In addition, Tallgrass Equity reimburses Tallgrass Energy Holdings and its affiliates for all expenses it incurs and payments it makes on our behalf pursuant to the TEGPTGE Omnibus Agreement, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain corporate, general and administrative services in each case to the extent properly allocable to us. Any direct expenses associated with being a separate publicly traded entity are borne by Tallgrass Equity. Neither our partnership agreement nor the TEGPTGE Omnibus Agreement limits the amount of expenses for which our general partner, Tallgrass Energy Holdings and their respective affiliates may be reimbursed. For more information, see "Certain Relationships and Related Party Transactions, and Director Independence-Omnibus Agreement."
Directors and Executive Officers of Our General Partner and TEP GP
The following table sets forth certain information with respect to the executive officers and directors of our general partner as of February 13, 2018. The table also shows certain individuals who serve as directors of TEP GP who are not currently directors of our general partner.8, 2019.
|
| | | | | | |
| Name | | Age | | Position with Our General Partner | | Position with TEP GP |
| David G. Dehaemers, Jr. | | 57 | | President, Chief Executive Officer and Director58 | | President, Chief Executive Officer and Director |
| William R. Moler | | 52 | | Executive Vice President, Chief Operating Officer and Director53 | | Executive Vice President, Chief Operating Officer and Director |
| Gary J. Brauchle | | 44 | | Executive Vice President and Chief Financial Officer45 | | Executive Vice President and Chief Financial Officer |
| Christopher R. Jones | | 4142 | | Vice President, General Counsel and Secretary | | Executive Vice President, General Counsel and Secretary |
| Gary D. Watkins | | 45 | | Vice President and Chief Accounting Officer46 | | Vice President and Chief Accounting Officer |
| Frank J. Loverro | | 48 | | Director49 | | Director |
| Stanley de J. Osborne | | 47 | | Director48 | | Director |
| Jeffrey A. Ball | | 43 | | Director44 | | Director |
| John T. Raymond | | 47 | | Director48 | | Director |
| Thomas A. Gerke | | 61 | | Director | | n/a |
W. Curtis Koutelas | | 56 | | Director | | n/a |
Terrance D. Towner | | 59 | | n/a62 | | Director |
| Roy N. Cook | | 60 | | n/a61 | | Director |
Jeffrey R. ArmstrongTerrance D. Towner | | 48 | | n/a60 | | Director |
Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors are duly elected or qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of the directors or executive officers of our general partner.
David G. Dehaemers, Jr. has been a director and the President and Chief Executive Officer of TEP GP since February 2013 and of our general partner since February 2015. Mr. Dehaemers has served as the President and Chief Executive Officer of TEP GP and Tallgrass Equity since February 2013 and as a director and the President and Chief Executive Officer of Tallgrass Energy Holdings since August 2012. Previously, Mr. Dehaemers served as a director of TEP GP from February 2013 to June 2018. Prior to joining our general partner, Mr. Dehaemers served as Co-Founder, Chief Executive Officer and Chief Investment Officer of Tallgrass MLP Fund I, L.P., a private MLP Investment Fund from 2008 to 2012. Mr. Dehaemers also served as Executive Vice President of corporate development at Inergy, LP, or NRGY, from 2003 to 2007. Mr. Dehaemers played a role in NRGY's corporate development group, where he focused on developing its long-term expansion strategies in the midstream area, which included acquisitions and expansion projects in excess of $500 million. Mr. Dehaemers also was an owner of Inergy Holdings, L.P., or NRGP, when that entity went public in 2005. Before Inergy, Mr. Dehaemers was part of the executive management team of Kinder Morgan, Inc. and Kinder Morgan Energy Partners, LP from 1997 to 2003, where he served as the Chief Financial Officer from 1997 to 2000. In 2000, Mr. Dehaemers assumed responsibility for Kinder Morgan's corporate development efforts, in which role he and his team developed and executed Kinder Morgan's growth strategies. Mr. Dehaemers holds an undergraduate degree in Accounting from Creighton University in Omaha, Nebraska and is a Certified Public Accountant. He also holds a Juris Doctorate in Law from University of Missouri-Kansas City. We believe that Mr. Dehaemers' education and experience, coupled with the leadership qualities demonstrated by his executive background, bring important experience and skill to the boards of directors of our general partner and of TEP GP.partner.
William R. Moler has been a director, Executive Vice President and Chief Operating Officer of TEP GP since February 2013 and of our general partner since February 2015. Mr. Moler has also served as Executive Vice President and Chief Operating Officer of TEP GP and Tallgrass Equity since February 2013 and as a director, Executive Vice President and Chief Operating Officer of Tallgrass Energy Holdings since October 2012. Previously, Mr. Moler served as a director of TEP GP from February 2013 to June 2018. From 2004 until his departure in October 2012, Mr. Moler served in various capacities with Inergy, L.P. and its affiliates, most recently as Senior Vice President and Chief Operating Officer of Inergy Midstream, L.P. and President and Chief Operating Officer—Natural Gas Midstream Operations of Inergy, L.P. Prior to joining Inergy, L.P., Mr. Moler was with Westport Resources Corporation from 2002 to 2004, where he served as both General Manager of Marketing and Transportation Services and General Manager of Westport Field Services, LLC. Prior to Westport, Mr. Moler served in various leadership positions at Kinder Morgan, Inc. and its predecessors from 1988 to 2002. Mr. Moler has
also served on the Board of the National Parkinson's Foundation Heartland Region and served as its President from 2015 to 2017. Mr. Moler earned a Bachelor of Science degree in Mechanical Engineering from Texas Tech University in 1988. We believe that as a result of his background and knowledge, as well as the attributes of leadership demonstrated by his executive experience, Mr. Moler brings substantial experience and skill to the boards of directors of our general partner and of TEP GP.partner.
Gary J. Brauchle has been Executive Vice President and Chief Financial Officer of TEP GP since February 2013 and of our general partner since February 2015. Mr. Brauchle has also served as Executive Vice President and Chief Financial Officer of TEP GP and Tallgrass Equity since February 2013 and of Tallgrass Energy Holdings since November 2012. Prior to joining Tallgrass, Mr. Brauchle was Vice President and Chief Accounting Officer at McDermott International, Inc., a global engineering and construction company serving the oil and gas industry during 2012 and as Corporate Controller from 2010 to 2012. He joined McDermott in 2003 and served in various positions of increasing responsibility, including as Director of Internal Audit from 2005 to 2007 and as Director of Operational Accounting and Assistant Controller for an operating subsidiary from 2007 to 2008 and 2008 to 2010, respectively. Mr. Brauchle also served in the Houston office of PricewaterhouseCoopers' energy and utilities practice from 1997 to 2003, including as a Manager from 2001 to 2003, and with a focus on midstream master limited partnerships, or MLPs. Mr. Brauchle was a postgraduate technical assistant at the Financial Accounting Standards Board (FASB) from 1996 to 1997. Mr. Brauchle is a Certified Public Accountant and a graduate of Texas A&M University, where he received a Master of Science in Accounting in 1996 and a Bachelor of Business Administration in Accounting in 1995.
Christopher R. Jones has been Executive Vice President, General Counsel and Secretary of our general partner since February 2018. Mr. Jones has also served as Executive Vice President, General Counsel and Secretary of TEP GP and Tallgrass Energy Holdings since February 2018. Previously, Mr. Jones served as Vice President, General Counsel and Secretary of our general partner, TEP GP and Tallgrass Energy Holdings sincefrom May 2016. Previously, Mr. Jones served as Tallgrass's2016 to February 2018 and was an Assistant General Counsel beginning inat Tallgrass from October 2012.2012 to May 2016. Prior to joining Tallgrass, Mr. Jones was an attorney with the law firm that is now known as Stinson Leonard Street LLP from 2003 to 2012, becoming a partner in 2008. Mr. Jones holds an undergraduate degree and a Juris Doctorate in Law from the University of Kansas.
Gary D. Watkins has been Vice President and Chief Accounting Officer and the principal accounting officer of TEP GP since April 2014 and of our general partner since February 2015. Mr. Watkins has also served as Vice President and Chief Accounting Officer of TEP GP since April 2014 and of Tallgrass Equity and of Tallgrass Energy Holdings since February 2015. Previously, Mr. Watkins served as Vice President, Controller and principal accounting officer of DCP Midstream Partners, LP and DCP Midstream, LLC from May 2011 until April 2014. Prior to that, Mr. Watkins had held the positions of Senior Director—Marketing Accounting and Director of Corporate Accounting with DCP Midstream, LLC. Prior to joining DCP Midstream, LLC in November 2004, Mr. Watkins held various positions of increasing responsibility at Advanced Energy Industries, Inc. Mr. Watkins also served in the Denver offices of Arthur Andersen LLP and KPMG LLP from 1996 through 2002.
Frank J. Loverro has served as a director of TEP GP since February 2013 and of our general partner since February 2015. Mr. Loverro has also served2015 and as a director of Tallgrass Energy Holdings since August 2012. Previously, Mr. Loverro served as a director of TEP GP from February 2013 to June 2018. Mr. Loverro joined Kelso in 1993, has been Managing Director since 2004 and a Member of Kelso's Management Committee since 2013, and in 2016 became Co-CEO. He spent the preceding three years in the private equity investment and high yield groups at The First Boston Corporation. Mr. Loverro is also a director of Ajax Resources, LLC, Delphin Shipping LLC, Hunt Marcellus, LLC, Physicians Endoscopy, LLC, Poseidon Containers Holdings LLC and Zenith Energy U.S., L.P. Mr. Loverro was also a director of Buckeye GP LLC. Mr. Loverro received a B.A. in Economics with Distinction from the University of Virginia in 1991. Mr. Loverro has extensive experience in corporate financing and in evaluating the financial performance and operations of companies across a variety of business sectors, including the energy sector. We believe that this background, in addition to Mr. Loverro's valuable experience serving on the boards of various public and private companies, provides an important source of insight and perspective to the boardsboard of directors of our general partner and of TEGP Management.partner.
Stanley de J. Osborne has served as a director of TEP GP since February 2013 and of our general partner since February 2015. Mr. Osborne has also served2015 and as a director of Tallgrass Energy Holdings since August 2012. Previously, Mr. Osborne served as a director of TEP GP from February 2013 to June 2018. Mr. Osborne joined Kelso in 1998 and has been Managing Director since 2007. He spent the preceding two years as an Associate at Summit Partners. He spent the previous three years at J.P. Morgan & Co. as an Associate in the Private Equity Group and an Analyst in the Financial Institutions Group. Mr. Osborne is also a director of Ajax Resources, LLC, 4Refuel Canada LP, Hunt Marcellus, LLC, Logan's Roadhouse, Inc., Traxys S.a.r.l, Power Team Services, LLC and LBM Acquisition, LLC.LLC, Southern Carlson and Traxys S.a.r.l. Mr. Osborne was also previously a director of CVR Energy, Inc. and Global Geophysical Services, Inc. Mr. Osborne received a B.A. in Government from Dartmouth College in 1993. Mr. Osborne has extensive experience in corporate financing and in evaluating the financial performance and operations of companies across a variety of business sectors, including the energy sector. We believe that this background, in addition to Mr. Osborne's valuable experience serving on the boards of various public and private companies, provides an important source of insight and perspective to the boardsboard of directors of our general partner and of TEGP Management.partner.
Jeffrey A. Ball has served as a director of TEP GP since May 2013 and of our general partner since February 2015. Mr. Ball has also served as the Chairman of the audit committee of TEP GP since May 20132015 and as the Chairman of the audit committee of our general partner since April 2015. Further, Mr. Ball has served as a director of Tallgrass Energy Holdings since August 2012. Previously, Mr. Ball served as a director of TEP GP from May 2013 to June 2018 and as the Chairman of the audit committee of TEP GP from May 2013 to June 2018. Mr. Ball is a Managing Director at EMG, a diversified natural resource private equity fund manager, and is
responsible for transaction origination, structuring and execution, portfolio company management and investment realization. Prior to joining EMG in October 2007, Mr. Ball was a Director in the investment banking group at Credit Suisse Securities (USA), LLC, covering the energy industry with a particular focus on
MLPs and the midstream sector. Mr. Ball has completed over $55 billion of mergers and acquisitions and capital markets financing transactions during his career in the energy and minerals sector. Mr. Ball currently serves on the Boards of Ferus Inc., Ferus GP LLC, Ferus Natural Gas Fuels Inc., Ferus Natural Gas Fuels GP, LLC, Ferus Natural Gas Fuels (CNG), LLC, Ascent Resources, LLC, Sable PRES Holdings,Permian Resources, LLC and is a board observer of MarkWest Utica EMG, LLC. Mr. Ball received a B.S. in Economics with honors from the Wharton School at the University of Pennsylvania. We believe that Mr. Ball's experience with mergers & acquisitions and financings of a variety of MLPs and other midstream assets provides a valuable resource to the boardsboard of directors of our general partner and of TEP GP.partner.
John T. Raymond has served as a director of TEP GP since February 2013 and of our general partner since February 2015. Mr. Raymond has also served2015 and as a director of Tallgrass Energy Holdings since August 2012. Previously, Mr. Raymond served as a director of TEP GP from February 2013 to June 2018. Mr. Raymond is an owner and founder of The Energy & Minerals Group. EMG is a diversified natural resource private equity fund manager with approximately $15.8$16.0 billion of regulatory assets under management (RAUM) as of September 30, 2017.2018. EMG has allocated approximately $10.5$11.0 billion in commitments across the energy sector since inception. Mr. Raymond has been Managing Partner and CEO since EMG's inception in 2006. Prior to that time, Mr. Raymond held leadership positions with various energy companies, including President and CEO of Plains Resources Inc., President and Chief Operating Officer of Plains Exploration and Production Company and Director of Development for Kinder Morgan, Inc. Mr. Raymond currently serves on numerous other boards, including the board of directors of each of NGL Energy Holdings, LLC, the general partner of NGL Energy Partners, LP, Plains All American GP LLC, the general partner of Plains All American Pipeline, LP, and PAA GP Holdings LLC, the general partner of Plains GP Holdings, LP. Mr. Raymond received a BSM degree from the A.B. Freeman School of Business at Tulane University with dual concentrations in finance and accounting. We believe that Mr. Raymond's experience with investment in and management of a variety of upstream and midstream assets and operations provides a valuable resource to the boardsboard of directors of our general partner and of TEP GP.partner.
Thomas A. Gerke has served as a director of our general partner since August 2015. He is alsoand as a member of the audit committee of our general partner.partner since August 2015. Mr. Gerke has served as the General Counsel and Chief Administrative Officer at H&R Block, a global consumer tax services provider since May 2016 and prior to that starting in January 2012, he served as Chief Legal Officer. In addition, during a two-month-plus period in 2017 while H&R Block went through a CEO transition, Mr. Gerke served as interim President and Chief Executive Officer from August 1, 2017 to October 8, 2017. Prior to joining H&R Block, from January 2011 to April 2011, Mr. Gerke served as Executive Vice President, General Counsel and Secretary of YRC Worldwide, a leading transportation service provider. From July 2009 to December 2010, Mr. Gerke served as Executive Vice Chairman of CenturyLink, a Fortune 500 integrated communications business. From December 2007 to June 2009, he served as President and Chief Executive Officer at Embarq, then a Fortune 500 integrated communications business. He also held the position of Executive Vice President and General Counsel, Law and External Affairs at Embarq from May 2006 to December 2007. From October 1994 through May 2006, Mr. Gerke held several executive and legal positions with Sprint, serving as Executive Vice President and General Counsel for over two years. Mr. Gerke currently serves as a member of the board of directors at Consolidated Communications Holdings, Inc. (NASDAQ: CNSL). He is also a former member of the boards of CenturyLink, Embarq and United States Telecom Association. In addition, he is a former member of the board of trustees for Rockhurst University and the Kansas City Local Investment Commission (LINC). Mr. Gerke earned his Bachelor of Science degree in Business Administration from the University of Missouri in Columbia, his Masters of Business Administration degree from Rockhurst University, and his Juris Doctorate from the University of Missouri School of Law in Kansas City. We believe that Mr. Gerke's leadership roles and board experience at a number of Fortune 500 and other large public companies, as well as his legal acumen and background outside of the energy industry, provides a valuable resource to the board of directors of our general partner.
W. Curtis KoutelasRoy N. Cook has served as a director of our general partner since May 2016. He is alsoand as a member of the audit committee of our general partner.partner since September 2018. Previously, Mr. Koutelas founded Arrowhead Contracting Inc. in 1990 and hasCook served as its President fora director of TEP GP from September 2013 to June 2018 and as a member of the past 27 years. Arrowhead provides general construction, remedial construction, environmental engineering, facilityaudit committee of TEP GP from December 2017 to June 2018. From 2001 to 2013, Mr. Cook was employed by, and held a variety of roles within, the terminals division of Kinder Morgan, focusing on acquisitions, management, design and operations and maintenancespecializing in the dry bulk side of the terminals business. Prior to 2001, Mr. Cook owned and homeland security servicesmanaged several businesses in the service industry, including Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminals, Inc., each of which were sold to a broad base of federal agencies and large-business prime contractors. In addition to his work with Arrowhead,Kinder Morgan in 2001. Mr. Koutelas is dedicated to serving the Kansas City area by participating in volunteer and outreach programs benefitingCook currently owns several small businesses across diverse industries, including a self-storage business, an electrical service company and providing financial assistance to disadvantaged young mena commercial real estate management and women attending Rockhurst High School and Rockhurst College. Mr. Koutelas holdsdevelopment company. He graduated from Kansas State University in 1979 with a Bachelor of ScienceB.S. degree in Construction Management from Pittsburg State University.Agriculture Economics. We believe that Mr. Koutelas's extensive businessCook's MLP experience, and leadershiphis intricate knowledge of the terminals business provides a valuable resourcestrategic and practical insight, and perspective to the board of directors of our general partner.
Terrance D. Towner has served as a director of our general partner and as a member of the audit committee of our general partner since September 2018. Previously, Mr. Towner served as a director of TEP GP and as a member of the audit committee of TEP GP sincefrom August 2013.2013 to June 2018. Mr. Towner currently serves as the Executive Chairman of Jaguar Management Inc. and its affiliates, which makes direct investments in and provides advisory services to various private equity clientscompanies and private companies.clients. Mr. Towner is also a director of Base, Inc., Cando Rail Services Holdings, Inc., West Memphis Transload, West Memphis Base
Railroad and SilverCreek RCM. Prior to joining Jaguar Management, Inc. in November 2018, Mr. Towner provided business advisory services. Between 2000 and December 2014, Mr. Towner was employed by Watco Companies, a Kansas based transportation company, in various
capacities, including Vice Chairman, President, COO and CFO. As President and COO, Mr. Towner was responsible for all operations, safety, quality, human resources, information services and the financial performance of Watco's transportation, mechanical, and terminal and port divisions. Prior to joining Watco, Mr. Towner spent thirteen years in banking including three years as President and CEO of First State Bank & Trust Company of Pittsburg, Kansas. He also served for five years as President of Pitsco, a company that develops and markets computer based education products, and approximately two years as a financial and strategic consultant with Grant Thornton. Following his departure from Grant Thornton, Mr. Towner acquired Joplin.com, an internet service provider located in Joplin, Missouri and subsequently sold the company to Empire District Electric Company, a public utility. Mr. Towner earned his bachelor's degree in Economics from Pittsburg State University in 1981 and his MBA from Pittsburg State University in 1993. We believe that Mr. Towner's business acumen, and a unique perspective on the midstream services industry, helps provide valuable strategic and practical guidance, insight, and perspective to the board of directors of TEP GP.
Roy N. Cook has served as a director of TEP GP since September 2013 and as a member of the audit committee of TEP GP since December 2017. From 2001 to 2013, Mr. Cook was employed by, and held a variety of roles within, the terminals division of Kinder Morgan, focusing on acquisitions, management, design and operations and specializing in the dry bulk side of the terminals business. Prior to 2001, Mr. Cook owned and managed several businesses in the service industry, including Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminals, Inc., each of which were sold to Kinder Morgan in 2001. Mr. Cook currently owns several small businesses across diverse industries, including a self-storage business, an electrical service company and a commercial real estate management and development company. He graduated from Kansas State University in 1979 with a B.S. degree in Agriculture Economics. We believe that Mr. Cook's MLP experience, and his intricate knowledge of the terminals business provides valuable strategic and practical insight, and perspective to the board of directors of TEP GP.
Jeffrey R. Armstrong has served as a director of TEP GP since April 2014 and was a member of the audit committee of TEP GP from April 2014 to December 2017. In August 2014, Mr. Armstrong became the Chief Executive Officer of Zenith Energy, LP, a privately held midstream energy company. In October 2014, Mr. Armstrong became the chairman of MID-SHIP Group, a privately held logistics and transportation company. Mr. Armstrong is the Manager and controlling shareholder of MID-SHIP Capital LLC, which owns 100% of MID-SHIP Securities LLC, a member of the Financial Industry Regulatory Authority, or FINRA. From March 2001 until December 2013, Mr. Armstrong was employed by Kinder Morgan and held various positions within the company including Vice President of Corporate Strategy and President of the Terminals division. Prior to 2001, Mr. Armstrong was employed by GATX Corporation where he held various commercial and operational roles including General Manager of the company's east coast operations. He received his bachelor's degree from the U.S. Merchant Marine Academy and an MBA from the University of Notre Dame. We believe that Mr. Armstrong's extensive experience as it relates both toour general corporate strategy and specifically to the terminals business, provides valuable insight and perspective to the board of directors of TEP GP.partner.
Audit Committee
The board of directors of our general partner has a standing audit committee which is currently comprised of threefour directors, Jeffrey A. Ball, Thomas A. Gerke, Roy N. Cook, and W. Curtis Koutelas.Terrance D. Towner. Each audit committee member has past experience in accounting or related financial management experience. The board has determined that all our audit committee members are independent under Section 303A.02 of the NYSE listing standards and Rule 10A-3 of the Securities Exchange Act of 1934, as amended. In making the independence determination, the board considered the requirements of the NYSE, the SEC and our Code of Business Conduct and Ethics. Among other factors, the board considered current or previous employment with us, our auditors or their affiliates by the director or his immediate family members, ownership of our voting securities and other material relationships with us. The audit committee has adopted a charter, which has been ratified and approved by the board of directors.
Jeffrey A. Ball has been designated by the board as the audit committee's financial expert meeting the requirements promulgated by the SEC and set forth in Item 407(d) of Regulation S-K of the Securities Exchange Act of 1934, as amended, based upon his education and employment experience as more fully detailed in Mr. Ball's biography set forth above. Mr. Ball also acts as the Chairman of our audit committee.
A copy of the Audit Committee Charter is available to any person, free of charge, at our website at www.tallgrassenergy.com.
Conflicts Committee
Our general partner may, from time to time, have a conflicts committee to which the board of directors will appoint at least two independent directors and which may be asked to review specific matters that the board believes may involve conflicts of interest between us and our general partner or the owners of our general partner or between us and TEP or its affiliates.partner. The conflicts committee will determine if the resolution of any conflict of interest referred to it by our general partner is in the best interests of our partnership. There is no requirement that our general partner seek the approval of the conflicts committee for the resolution of any conflict. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, or TEP GP, may not hold an ownership interest in the general partner or its affiliates other than shares or awards under any long-term incentive plan, equity compensation plan or similar plan implemented by the general partner or us, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. The conflicts committee currently consists of two independent directors, Mr. Gerke and Mr. Koutelas, with Mr. Gerke currently acting as the Chairman.
Any matters approved by the conflicts committee will be conclusively deemed to have been approved by all of our partners, and shall not constitute a breach by our general partner of any duties it may owe us or our shareholders. Any shareholder challenging any matter approved by the conflicts committee will have the burden of proving that the members of the conflicts committee did not subjectively believe that the matter was in the best interests of our partnership. Moreover, any acts taken or omitted to be taken in reliance upon the advice or opinions of experts such as legal counsel, accountants, appraisers, management consultants and investment bankers, where our general partner (or any members of the board of directors of our general partner including any member of the conflicts committee) reasonably believes the advice or opinion to be within such person's professional or expert competence, shall be conclusively presumed to have been done or omitted in good faith.
Corporate Governance Guidelines and Code of Business Conduct and Ethics
Our general partner has adopted Corporate Governance Guidelines and a Code of Business Conduct and Ethics applicable to all of our employees, officers and directors with regard to Partnership-related activities. The Corporate Governance Guidelines and the Code of Business Ethics incorporate guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations. They also incorporate expectations of our employees that
enable us to provide accurate and timely disclosure in our filings with the SEC and other public communications. A copy of the Corporate Governance Guidelines and the Code of Business Conduct and Ethics are available to any person, free of charge, at our website at www.tallgrassenergy.com.
The Chairman of the audit committee of our general partner, currently Jeffrey A. Ball, presides over any executive session of the board of directors of our general partner in which the members of our management are not present. Interested parties may communicate directly with the independent members of the board of directors of our general partner by submitting in an envelope marked "Confidential" addressed to the "Independent Members of the Board" in care of the Secretary of the General Partner at: Tallgrass Energy, GP, LP, 4200 W. 115th Street, Suite 350, Leawood, Kansas 66211.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires members of our general partner's board of directors, executive officers of our general partner, and persons who own more than 10% of a registered class of our equity securities, to file with the SEC, and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our Class A shares, Class B shares and other equity securities. Officers, directors and greater than 10% shareholders are required by the SEC's regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they file with the SEC.
Based solely upon a review of Forms 3, 4 and 5, and amendments thereto, we know of no director, officer, or beneficial owner of more than 10% of any class of our equity securities registered pursuant to Section 12 of the Exchange Act that failed to file timely any reports required to be furnished during 2017 pursuant to Section 16(a) of the Exchange Act.
Item 11. Executive Compensation
Compensation Discussion and Analysis
Executive Summary and Background
We and our general partner were formed in Delaware in February 2015. Our general partner did not accrue any obligations with respect to management incentive or retirement benefits for its directors and executive officers until after our initial public offering in May 2015. We do not directly employ any of the persons responsible for managing our business. Our business is managed and operated by the directors and executive officers of our general partner. All employees, including our Named Executive Officers (as defined in "Summary Compensation Table" below), are employed by an affiliate of our general partner, Tallgrass Management, LLC ("Tallgrass Management"). Prior to July 1, 2018, Tallgrass Management was a wholly-owned subsidiary of Tallgrass Energy Holdings. Effective July 1, 2018, Tallgrass Management was contributed to Tallgrass Equity in connection with the TEP Merger. As a result, the costs of employer and director compensation and benefits are now incurred directly by Tallgrass Equity.
Compensation of our Named Executive Officers is set and approved by the board of directors of our general partner and by the board of managers of Tallgrass Energy Holdings, which controls our general partner. Tallgrass Energy Holdings owns 100% of Tallgrass Management and 100% of our general partner. We reimbursePrior to July 1, 2018, we reimbursed Tallgrass Energy Holdings and its affiliates including Tallgrass Management, for all salaries, benefits and other compensation expenses for employees of Tallgrass Management (including the Named Executive Officers) to the extent such employees provideprovided services to us pursuant to an allocation agreed upon between our general partner and Tallgrass Energy Holdings under the terms of the TEGPTGE Omnibus Agreement. Other than the employment agreement with our Chief Executive Officer, David G. Dehaemers, Jr., none of our Named Executive Officers has entered into any employment agreements with Tallgrass Management, our general partner or any other affiliate of TEGP.TGE.
Philosophy and Objectives
Since our initial public offering in May 2015, we have employed a compensation philosophy that emphasizes pay for performance and places the majority of each Named Executive Officer's compensation at risk. We believe our pay-for-performance approach aligns the interests of our Named Executive Officers with that of our Class A shareholders, and at the same time enables us to maintain a lower level of recurring compensation costs in the event our operating or financial performance is below expectations. We design our executive compensation to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our Class A shareholders, and to reward success in reaching such goals.
We use three primary elements of compensation to fulfill that design: salary, cash bonusbonuses and long-term equity incentive awards. Cash bonusesBonuses and long-term equity incentives (as opposed to salary) generally represent the performance driven elements. They are also flexible in application and can be tailored to meet our objectives. The determination of specific individuals' cash bonuses is based on their relative contribution to achieving or exceeding relative near-term company goals and the determination of specific individuals' long-term incentive equity awards is based on their actual and anticipated contribution to
longer term performance objectives. The primary long-term measure of our performance is our ability to increase quarterly distributionsdividends to our Class A shareholders while maintaining safe operations and long-term stable cash flow and financial health.
We do not maintain a defined benefit or pension plan for our Named Executive Officers as we believe such plans primarily reward longevity and not performance. We provide a basic benefits package generally to all employees, which includes a 401(k) plan and health, disability and life insurance.
Elements of Compensation
Salary. We benchmark our salary amounts to comparable companies in our industry. We believe our salaries are generally competitive with the universe of similarly situated master limited partnerships,midstream energy companies, but are moderate relative to energy industry competitors for people with similar roles and responsibilities.
Cash Bonuses. Our cash bonuses are annual discretionary bonuses in which all of our current Named Executive Officers potentially participate.
Long-Term Incentive Awards. Our bonuses to Named Executive Officers receive grantsgenerally consist of a cash bonus. In 2018, Mr. Brauchle, Mr. Moler and Mr. Jones were granted awards under both the TEGP and TEPLegacy LTIP (as defined below). TEGP as an additional component of their 2018 bonus. These awards were granted on January 31, 2019 and TEP sharevested immediately. The recipients of these awards will receive the same primary long-term performance measure of increasing quarterly distributions while maintaining safe operations and long-term stable cash flow and financial health. AsClass A shares as a result of TEGP’s controlling membership interest inthe vesting on January 31, 2020.
Awards under Long-Term Incentive Plans. We have two long-term incentive plans. The Tallgrass Equity and indirect ownership of Energy GP, LLC Long-Term Incentive Plan (f/k/a 35% limited partnership interest in TEP, all of TEP’sthe TEGP Management, LLC Long-Term Incentive Plan), was originally adopted by our general partner interesteffective as of May 1, 2015, and allwas amended and restated effective August 2, 2018 (as amended, the "TGE LTIP"). In addition, the Tallgrass MLP GP, LLC Long-Term Incentive Plan was originally adopted by TEP GP effective as of TEP’s incentive distribution rights, failing to achieve that performance standard atMay 13, 2013, and was amended and restated effective August 2, 2018 (as amended, the "Legacy LTIP" and together with the TGE LTIP, the "Plans"). In connection with the completion of the TEP would be detrimental to TEGP,Merger effective June 30, 2018, discussed in Note 1 – Description of Business, the Legacy LTIP was assumed by our general partner and vice versa. We therefore believe granting our Named Executive OfficersTEP's outstanding equity participation units under the TEP LTIP andwere converted to equity participation shares under the TEGP LTIP appropriately incentivizes our Named Executive Officers to seek stable distribution growth at both entities. We expect equity participation unit awards under the TEP LTIP will be the primary long-term equity incentive provided to our Named Executive Officers, and that grantsa ratio of 2.0 equity participation shares will be made pursuant tofor each outstanding TEP equity participation unit.
Awards under the TEGP LTIP on a more limited basis.
Long-Term Incentive AwardsPlans may consist of, TEGP. Effective May 1, 2015, our general partner adopted a Long-Term Incentive Plan ("TEGP LTIP") pursuant to which awards based on Class Aamong others, unrestricted shares, of TEGP in the form of restricted shares, equity participation shares, options and share appreciation rights distribution equivalent rights and share awardswhich may be granted to (i) the employees consultants, and directors of Tallgrass Managementour general partner and its affiliates who perform services for or on behalfus, (ii) the non-employee directors of TEGP or its affiliates, including TEPour general partner and Tallgrass Development. As noted above,(iii) the consultants who perform services for us (such awards, the "LTIP Awards"). Historically, we have used equity participation shares may be issuedshare awards under the TEGP LTIPPlans to in part,encourage and reward timely achievement of certain events or dividend levels and align the long-term interests of our Named Executive Officers with those of our Class A shareholders. An equity participation share is the right to receive, upon the satisfaction of vesting criteria specified in the grant, a TEGP Class A share.
In 2015, grants of Equity participation share awards under the Plans have been, and we expect will continue to be, the primary long-term equity participation shares were made under TEGP LTIP, including a grant madeincentive provided to Mr. Jonesour Named Executive Officers and to Mr. Watkins, who are thus far the onlyappropriately incentivizes our Named Executive Officers to receive a grant under the TEGP LTIP. The terms of the awards to Mr. Jones and Mr. Watkins each stipulate that the equity participation shares will generally vest upon the later of the first date on which TEGP pays a regular quarterly distribution of at least $0.35 on each outstanding Class A share (the "TEGP Distribution Date") or May 12, 2019. The TEGP Distribution Achievement Date was met upon payment of the $0.3550 distribution declared for the third quarter of 2017, thus these awards will vest on May 12, 2019 as long as the employee satisfies the continuing service requirement set forth in the applicable award agreement.seek stable dividend growth.
Long-Term Incentive Awards of TEP. Vesting Conditions.Our Named Executive Officers also participate in the Long-Term Incentive Plan established by TEP's general partner effective May 13, 2013 ("TEP LTIP"). Pursuant to the TEP LTIP, awards based on common units of TEP in the form of restricted units, equity participation units, unit options, unit appreciation rights, distribution equivalent rights and unit awards may be granted to employees, consultants, and directors of TEP GP and its affiliates who perform services for or on behalf of TEP or its affiliates, including Tallgrass Development (such awards, collectively with the awards under the TEGP LTIP, the "LTIP Awards"). Historically, we have used equity participation unit grants issued under the TEP LTIP to encourage and reward timely achievement of certain events or TEP distribution levels and, as noted above, align the long-term interests of our Named Executive Officers with those of our Class A shareholders. An equity participation unit is the right to receive, upon the satisfaction of vesting criteria specified in the grant, a TEP common unit.
The vesting conditions applicable to TEP'sthe equity participation unit awardsshares held by Named Executive Officers that are outstanding under the Plans can generally be divided into four categories. the following categories:
The first category of awards was originally granted by TEP between June 2013 and September 2014 (prior to our formation) with vesting of such awards contingent upon the Pony Express System going into commercial service, which occurred in October 2014. Generally, one-third of the awards in this category vested on May 13, 2015 and the remaining two-thirds vested on May 13, 2017. All of our Named Executive Officers other than Mr. Dehaemers were granted equity participation unit awards in this category.
The second category of TEP's equity participation unit awards were granted between August 2015 and September 2015 with vesting occurring in two parts. One-half vests on the later to occur of the first date on which we haveTEP paid a regular quarterly distribution of at least $0.6875 on each outstanding common unit (the "TEP Distribution Achievement Date") or May 13, 2018, and the other half vestingvests on the later to occur of the TEP Distribution Achievement Date or May 13, 2019. The TEP Distribution Achievement Date occurred on May 13, 2016, thusand the first half of the awards in this category will vest as long as the employee satisfies the continuing service requirement set forth in the applicable award agreement. Mr. Jones and Mr. Watkins are the only Named Executive Officers that were granted equity participation units in this second category.
vested on May 13, 2018. The third category of TEP's equity participation unit awards were granted in November 2016 andremaining half will vest on November 1,May 13, 2019 as long as the employee satisfies the continuing service requirement set forth in the applicable award agreement. Mr. Jones and Mr. Watkins are the only Named Executive Officers that were granted equity participation unitsshares in this category. The Blackstone Acquisition constitutes a change of control with respect to the awards in this category and as a result, any outstanding awards in this category will vest upon consummation of the Blackstone Acquisition.
The second category of awards was granted by TGE in 2015 to Mr. Jones and to Mr. Watkins. The terms of the awards to Mr. Jones and Mr. Watkins each stipulate that the equity participation shares will generally vest upon the later of the first date on which TGE pays a regular quarterly dividend of at least $0.35 on each outstanding Class A share (the "TGE Dividend Achievement Date") or May 12, 2019. The TGE Dividend Achievement Date was met upon payment of the $0.3550 dividend declared for the third category.quarter of 2017, thus these awards will vest on May 12, 2019 as long as the employee satisfies the continuing service requirement set forth in the applicable award agreement. The Blackstone Acquisition constitutes a change of control with respect to the awards in this category and as a result, any outstanding awards in this category will vest upon consummation of the Blackstone Acquisition.
The third category of awards was originally granted by TEP in November 2016 and will vest on November 1, 2019 as long as the employee satisfies the continuing service requirement set forth in the applicable award agreement. Mr.
Jones and Mr. Watkins are the only Named Executive Officers that were granted equity participation shares in this category. The Blackstone Acquisition constitutes a change of control with respect to the awards in this category and as a result, any outstanding awards in this category will vest upon consummation of the Blackstone Acquisition.
The fourth category of TEP's equity participation unit awards werewas originally granted by TEP in August 2017 (the "2017 Grants") and will vest on the earliest date on or after April 1, 2021, on which the average compounded annual distribution growth rate for TEP'sTGE's regular quarterly distributions, based upon the regular quarterly distribution paid by TEPTGE on, or immediately prior to, such date is at least 5% over an annualized distribution rate of $3.34$1.67 per TEP common unit,TGE Class A share, as determined by the board of directors of TEP'sour general partner. If such date has not occurred by August 2, 2024, such equity participation unitsshares will expire and terminate and no vesting will occur. Mr. Jones and Mr. Watkins are the only Named Executive Officers that were granted equity participation unitsshares in this fourth category. The 2017 Grants do not vest solely as a result of the consummation of the Blackstone Acquisition. See "Potential Payments upon Termination or Change-in-Control" for a description of the conditions that would accelerate vesting of the 2017 Grants.
The fifth category of awards was originally granted by TEP in February 2018 and will vest on January 1, 2020 as long as the employee satisfies the continuing service requirement set for in the applicable award agreement. Mr. Brauchle, Mr. Moler, and Mr. Jones are the only Named Executive Officers that were granted equity participation shares in this category. The Blackstone Acquisition constitutes a change of control with respect to the awards in this category and as a result, any outstanding awards in this category will vest upon consummation of the Blackstone Acquisition.
The sixth category of awards was granted by TGE in October 2018 (the "2018 Grants") and will vest on the earliest date on or after November 1, 2022, on which the average compounded annual distribution growth rate, based upon the regular quarterly distribution paid by TGE on, or immediately prior to, such date is at least 5% over an annualized distribution rate of $1.99 per TGE Class A share, as determined by the board of directors of our general partner. If such date has not occurred by October 19, 2025, such equity participation shares will expire and terminate and no vesting will occur. Mr. Jones and Mr. Watkins are the only Named Executive Officers that were granted equity participation shares in this category. The 2018 Grants do not vest solely as a result of the consummation of the Blackstone Acquisition. See "Potential Payments upon Termination or Change-in-Control" for a description of the conditions that would accelerate vesting of the 2018 Grants.
Relation of Compensation Elements to Compensation Objectives
Our compensation program is designed to motivate, reward and retain our Named Executive Officers. Cash bonusesBonuses serve as a near-term motivation and reward for achieving positive short-term results, such as meeting specified distributiondividend growth and other financial guidance targets. Longer-term retention is facilitated by the requirement for continued employment or service for specified time periods in order for LTIP Awards to fully vest. The level of cash bonuses and LTIP Awards reflect the moderate salary profile of our Named Executive Officers and the weighting towards performance based, at-risk compensation.
We strive to focus on performance-based compensation elements in an attempt to create a performance-driven environment in which our Named Executive Officers are (i) motivated to perform over both the short-term and the long-term, (ii) appropriately rewarded for their services and (iii) encouraged to remain with us even after meeting long-term performance goals. We believe our compensation philosophy as implemented by application of the three primary compensation elements (i) aligns the interests of our Named Executive Officers with our Class A shareholders, (ii) positions us to achieve our business goals, and (iii) effectively encourages the exercise of sound judgment and risk-taking that is conducive to creating and sustaining long-term value. We believe the processes we employ to apply the elements of compensation (as discussed in more detail below) provide an adequate level of oversight with respect to the degree of risk being taken by management to achieve short-term and long-term performance goals. See "Relation of Compensation Policies and Practices to Risk Management."
We believe our compensation program has been instrumental in our achievement of stated objectives. One of the primary measures of our performance is our ability to enhance the ability of our assets to generate distributable cash flowavailable for dividends that we can use to increase quarterly distributionsdividends to TEP's unitholders and our Class A shareholders. In the period since TEP'sour initial public offering through December 31, 2016, TEP's2018, our compounded annual distribution per common unit has grown at a compound annual rate of 31%, and since our initial public offering, our distributiondividend growth rate is 50%48%. This distributiondividend growth has, in part, supported our decision to pay cash bonuses to our Named Executive Officers overrelated to that period.
Application of Compensation Elements
Salary. We do not make systematic annual adjustments to the salaries of our Named Executive Officers. We do, however, make salary adjustments as necessary to ensure that our salaries remain competitive in the industry marketplace.
Annual Discretionary Cash Bonuses. Annual discretionary bonuses are determined based on our performance relative to our annual budget, our distributiondividend growth targets, and other quantitative and qualitative goals established each year. Such annual objectives are discussed and reviewed with the board of directors periodically during the year and then again in conjunction with the review and authorization of the annual budget and this annual report.
At the end of each year, the CEO, with assistance from other members of executive management, performs a quantitative and qualitative assessment of our performance relative to our goals. Key quantitative measures include Adjusted EBITDA, distributable cash flow, distributionavailable for dividend, dividend coverage, and growth in the annualized quarterly distributiondividend level per common unitClass A share relative to annual growth targets. We also compare our market performance relative to our MLP peers and major indices. Our primary performance metric is our ability to generate increasing and sustainable cash distributionsdividends to our Class A shareholders. Accordingly, although net income and net income per unit are monitored to highlight inconsistencies with our primary performance metrics, we do not consider net income and net income per unit to be key performance measures. Executive management's analysis of our performance examines our accomplishments, shortfalls and overall performance against opportunity, taking into account controllable and non-controllable factors encountered during the year.
After the annual company-level performance analysis is completed by our CEO and other members of executive management, that same group, along with personnel from our human resources department, considers cash bonuses and salary adjustments for our employees, including our Named Executive Officers. There are no set formulas for determining salary adjustments or annual discretionary bonuses for our Named Executive Officers. Factors considered by executive management in determining the level of salary adjustment and bonus in general include (i) whether or not we achieved any goals established for the year and any notable shortfalls relative to expectations; (ii) the level of difficulty associated with achieving any such objectives based on the opportunities and challenges encountered during the year; (iii) current year operating and financial performance relative to both public guidance and prior year's performance; (iv) significant transactions or accomplishments for the period not included in the goals for the year; (v) our prospects at the end of the year with respect to future growth and performance; and (vi) our positioning at the end of the year with respect to our targeted credit profile. The CEO and other members of executive management take these factors into consideration, as well as the relative contributions of each of our Named Executive Officers to the year's performance, in developing recommendations for Named Executive Officer bonus amounts and salary adjustments.
These recommendations for discretionary bonus amounts and salary adjustments for our Named Executive Officers are presented to the board of directors of our general partner and the board of managers of Tallgrass Energy Holdings, adjusted as appropriate, and then formally approved by those boards. In several historical instances, the CEO has requested that his bonus amount be reduced or eliminated.
Long-Term Incentive Awards. We do not make systematic annual grants of LTIP Awards to our Named Executive Officers. We have historically attempted to time the granting of LTIP Awards such that the creation of new long-term incentives coincides with the satisfaction of vesting criteria under existing awards. We have not formally decided on a recurring grant cycle for future grants, but we intend for future grants to provide a balance between a meaningful retention period for us and a visible, reasonable, growth-oriented reward for the Named Executive Officer. Under existing LTIP Awards, achievement of performance targets does not shorten the minimum service period requirement.
Application in 20172018
AtIn connection with the beginningannouncement of 2017, our stated financial guidance was to grow distributions to Class A shareholders by more than 30% and potentiallythe TEP Merger in excess of 40%. In addition, TEPMarch 2018, we established the following financial performance objectives at TEP for 2017:2018:
Adjusted EBITDA of $620$755 - $680$835 million for the year ended December 31, 2017;2018;
Distributable Cash FlowMaintenance capital of $570$20 - $63030 million for the year ended December 31, 2017;2018;
DistributionDividend coverage of 1.30x - 1.50xgreater than 1.20x for the year ended December 31, 2017;2018; and
Growth of approximately 20%38 - 42% in our annualized distributiondividend rate for the calendar year 2017.2018.
We and TEP achievedmet or exceeded all these goals:
Our distributionsAdjusted EBITDA for the year ended December 31, 2018 was approximately $860.4 million;
Our maintenance capital for the year ended December 31, 2018 was approximately $21 million;
Our dividend coverage for the year ended December 31, 2018 was approximately 1.26x; and
Our dividends on Class A shares in the fourth quarter of 20172018 represented a 32.4%41.5% increase from ourthe fourth quarter 2016 distribution on Class A shares, higher than the distribution growth rate of TEP's cash distributions;
TEP's Adjusted EBITDA for the year ended December 31, 2017 was approximately $678.0 million;
TEP's Distributable Cash Flow for the year ended December 31, 2017 was approximately $611.3 million;
TEP's distribution coverage for the year ended December 31, 2017 was 1.47x; and
TEP grew its annualized distribution rate during calendar year 2017 by 18.4%.2017.
Additionally, our internal qualitative goals included (a) advancing multi-year programs and initiatives and preparing the organization for future growth, and (b) continuing to promote a culture of safety and environmental responsibility throughout the organization. We achieved several accomplishments with respect to these qualitative goals, including:
The execution of the Merger Agreement and successful completion of the TEP Merger with the expected benefits of streamlining our corporate structure, lowering our cost of capital, and broadening our investor appeal;
The acquisitions from Tallgrass Development of a 24.99%an additional 25.01% membership interest in Rockies Express and the remaining 2% membership interest in March 2017 and 100% of the membership interestsPony Express in Terminals and NatGas in January 2017;February 2018;
Third-party acquisitions in 2018, including the acquisition of the Douglas Gathering Systema 38% membership interest in June 2017, the additional 40%Deeprock North in January 2018, a 100% membership interests Deeprock Developmentinterest in July 2017,Buckhorn Energy Services, LLC and the PRB Crude SystemBuckhorn SWD Solutions, LLC in August 2017;January 2018, a 51% membership interest in Pawnee Terminal in April 2018, and a 100% membership interest in NGL Water Solutions Bakken, LLC in November 2018;
The contract extension with Continental Resources, Inc. through October 31, 2024 for transportation on the Ponyassignment by Fitch Ratings of investment grade ratings to TEP and Rockies Express System;
The commencement of new expansion projects, including the Platteville Extension Project on the Pony Express System and the Cheyenne Connector Pipeline; andin September 2018;
The amendment and restatement of our 1.75 billionthe TEP revolving credit facility in July 2018, increasing the available amount from $1.75 billion to $2.25 billion and permitting the repayment of the Tallgrass Equity revolving credit facility; and
The senior note offerings of 2024 Notes and 2028the 2023 Notes in an aggregate principal amount of $1.1 billion.$500 million in September 2018.
For 2017,2018, the elements of compensation were applied as described below.
Salary. In 2017,2018, we did not implement material salary increases for our Named Executive Officers.Mr. Dehaemers, Mr. Brauchle, or Mr. Moler. Mr. Jones and Mr. Watkins received salary increases of approximately 10% over 2017.
Cash Bonuses. Based on the CEO's annual performance review and the individual performance of each of our Named Executive Officers, the board of directors of our general partner approved the annual bonuses for our Named Executive Officers reflected in the Summary Compensation Table and notes thereto. Such amounts take into account performance relative to our 20172018 goals; the level of difficulty associated with achieving such objectives; our relative positioning at the end of the year with respect to future growth and performance; the significant transactions or accomplishments for the period not included in the goals for the year; and our positioning at the end of the year with respect to our targeted credit profile. The board of directors of our general partner also considered, on a subjective basis, how well the executive officer performed his or her duties during the year.
Long-Term Incentive Awards. Pursuant toEach of our Named Executive Officers, with the TEP LTIP,exception of Mr. Jones and Mr. WatkinsDehaemers, received grants of 90,000 and 35,000 equity participation units, respectively, in 2017. No equity participation shares were granted to a Named Executive Officer under the TEGP LTIPPlans in 2017.2018. As noted below, we believe the substantial direct and indirect equity interests held by our management team, including our Named Executive Officers, in TEP, TEGP,TGE, Tallgrass EquityEnergy Holdings and Tallgrass Energy HoldingsEquity aligns their interests with those of our unitholders,Class A shareholders, and is taken into account when considering the level of equity incentives in TEP and TEGP granted to our Named Executive Officers under our compensation programs.
Other Compensation Related Matters
Equity Ownership. Although we encourage our Named Executive Officers to acquire and retain ownership in TEP common units and TEGP Class A shares, we do not require our Named Executive Officers to maintain a specified equity ownership level. Our policies, including our Insider Trading Policy, strongly discourage our Named Executive Officers from using puts, calls or options to hedge the economic risk of their ownership in TEP or TEGP.TGE. Based on the closing price of TEP’s common units and TEGP’s Class A shares on February 8, 2018,6, 2019, the value of the combined equity ownership of our Named Executive Officers discussed below was significantly greater than their combined aggregate salaries and bonuses for 2017.2018. We believe that the substantial direct and indirect equity interests held by our management team in TEGP,TGE and Tallgrass Energy Holdings and TEP further aligns their interests with those of our Class A shareholders, and is taken into account when considering the level of equity incentives in TEP and TEGP granted to our Named Executive Officers under our compensation programs.
Equity Ownership in TEGPTGE, Tallgrass Energy Holdings and Tallgrass Energy Holdings.Equity. SomeEach of our Named Executive Officers directlybeneficially own Class A shares in TEGPTGE and some of our Named Executive Officers indirectly own equity interests in Tallgrass Energy Holdings, Tallgrass Equity and TEGPTGE through Tallgrass KC, an entity controlled by Mr. Dehaemers. As of February 9, 2018,6, 2019, our Named Executive Officers beneficially owned, in the aggregate, 578,0803,544,643 of TEGP'sTGE's Class A shares (excluding any unvested LTIP Awards). As of February 9, 2018,6, 2019, Tallgrass KC owned 30,820,45829,416,692 Class B Shares in TEGPTGE and 30,820,45829,416,692 Units in Tallgrass Equity, representing an approximate 16.68%10.50% ownership interest in TEGPTGE and Tallgrass Equity, respectively. On such date, Tallgrass KC also owned approximately 27.61%In addition, as of the outstanding voting equity interestsFebruary 6, 2019, Mr. Dehaemers controlled 281,171 Class B Shares in TGE and 281,171 Units in Tallgrass Energy Holdings.
Equity Ownership in TEP. In addition to their equity ownership in TEGP and Tallgrass Energy Holdings, our Named Executive Officers collectively own substantial equity in TEP. As of February 9, 2018, our Named Executive Officers directly owned, inthrough the aggregate, 721,588 TEP common units (excluding any unvested LTIP Awards).David G. Dehaemers, Jr. Revocable Trust, dated April 26, 2006.
Recovery of Prior Awards. Except as provided by applicable laws and regulations, we do not have a policy with respect to adjustment or recovery of awards or payments if relevant company performance measures upon which previous awards were based are restated or otherwise adjusted in a manner that would have reduced the size of such award or payment if previously known.
Section 162(m). With respect to the deduction limitations under Section 162(m) of the Code, we are a limited partnership and do not fall within the definition of a "corporation" under Section 162(m).
Change-in-Control Triggers and Termination Payments. The equity participation unit and equity participation share grants to our Named Executive Officers other than the 2017 Grants and 2018 Grants include accelerated vesting triggered upon a change of control, as defined
in the respective award agreements. The Blackstone Acquisition constitutes a change of control with respect to these equity participation shares and as a result, any outstanding equity participation shares to our Named Executive Officers other than the 2017 Grants and the 2018 Grants will vest upon consummation of the Blackstone Acquisition. Although the Blackstone Acquisition will constitute a qualifying transaction under the 2017 Grants and the 2018 Grants, vesting under such awards will not accelerate until one of the subsequent conditions described below occurs.
The 2017 Grants include accelerated vesting if either (i) both (A) a qualifying transaction occurs, as defined in the award agreement, and (B) Mr. Dehaemers ceases to be the Chief Executive Officer of TEP'sour general partner andor certain of its affiliates, or (ii) (A) Mr. Dehaemers ceases to be the Chief Executive Officer of TEP'sour general partner andor certain of its affiliates, and (B) the Named Executive Officer is thereafter terminated without cause.
The 2018 Grants to Mr. Jones include accelerated vesting if either (i) both (A) a qualifying transaction occurs, as defined in the award agreement, and (B) in connection with or within 12 months following such qualifying transaction, Mr. Dehaemers ceases to be the Chief Executive Officer of our general partner or certain of its affiliates, or (ii) (A) Mr. Dehaemers ceases to be the Chief Executive Officer of our general partner or certain of its affiliates, and (B) within 2 years after the occurrence of such event, Mr. Jones is terminated without cause. The 2018 Grants to Mr. Watkins include accelerated vesting if either (i) both (A) a qualifying transaction occurs, and (B) in connection with or within 12 months following such qualifying transaction, Mr. Dehaemers, Mr. Moler, Mr. Brauchle or Mr. Jones cease to comprise at least one of the roles of Chief Executive Officer, Chief Operating Officer, Chief Financial Officer or General Counsel of our general partner or certain of its affiliates, or (ii) (A) Mr. Dehaemers, Mr. Moler, Mr. Brauchle or Mr. Jones cease to comprise at least one of the roles of Chief Executive Officer, Chief Operating Officer, Chief Financial Officer or General Counsel of our general partner or certain of its affiliates, and (B) within 2 years after the occurrence of such event, Mr. Watkins is terminated without cause.
The provision of equity acceleration for defined events help to create a retention tool by assuring the executive that the benefit of the compensation arrangement will be at least partially realized despite the occurrence of an event that could materially alter the executive's employment arrangement. In addition, the employment agreement for Mr. Dehaemers provides for severance in the event his employment is terminated without "cause" or in the event he resigns for "good reason." See "Potential Payments upon Termination or Change-in-Control." Except for the accelerated vesting of the 2017 Grants to Mr. Jones and Mr. Watkins and the 2018 Grants to Mr. Jones, if Mr. Dehaemers ceases to be the Chief Executive Officer of TEP'sour general partner andor certain of its affiliates and the Named Executive Officer is thereafter terminated without cause, no other Named Executive Officer has a contractual right to receive severance in the event of a termination of employment.
Relation of Compensation Policies and Practices to Risk Management
Our compensation policies and practices are designed to provide rewards for short-term and long-term performance, both on an individual basis and at the entity level. In general, optimal financial and operational performance, particularly in a competitive business like ours, requires some degree of risk-taking. Accordingly, the use of compensation as an incentive for performance could potentially cause management and others to take unnecessary or excessive risks to reach the performance thresholds. For us, such risks would primarily attach to the execution and financing of capital expansion projects and asset acquisitions and the realization of associated returns from both, as well as to certain commercial activities conducted in our operational segments.segments, in order to achieve the dividend growth performance hurdles.
From a risk management perspective, we monitor and structure our commercial activities in a manner intended to control and minimize the potential for unwarranted risk-taking. See Note 109 – Risk Management. We also monitor and measure our capital projects and acquisitions relative to expectations. In general, we believe our compensation arrangements serve to minimize the incentive for unwarranted risk-taking to achieve short-term, unsustainable results. See "Compensation Discussion and Analysis – Relation of Compensation Elements to Compensation Objectives."
In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.
Summary Compensation Table
The following table reflects the total compensation of the principal executive officer, the principal financial officer and the three other most highly compensated executive officers of our general partner for 20172018 (the "Named Executive Officers") for services rendered to all Tallgrass-related entities, including TEP, TEGP,TGE, Tallgrass Management and Tallgrass Development, for the fiscal years ending December 31, 2018, 2017, 2016, and 2015.2016.
| | | | Year | | Salary (1) | | Bonus (2) | | Equity Awards (3) | | All Other Compensation (4) | | Total | Year | | Salary (1) | | Cash Bonus (2) | | Equity Awards (3) | | All Other Compensation (4) | | Total |
| David G. Dehaemers, Jr. | 2017 | | $ | 300,000 |
| | $ | 1,000,739 |
| | $ | — |
| | $ | 28,152 |
| | $ | 1,328,891 |
| 2018 | | $ | 300,000 |
| | $ | 1,000,000 |
| | $ | — |
| | $ | 28,652 |
| | $ | 1,328,652 |
|
| President, Chief Executive | 2016 | | $ | 300,000 |
| | $ | 651,467 |
| | $ | — |
| | $ | 27,544 |
| | $ | 979,011 |
| 2017 | | $ | 300,000 |
| | $ | 1,000,739 |
| | $ | — |
| | $ | 28,152 |
| | $ | 1,328,891 |
|
| Officer and Director | 2015 | | $ | 300,000 |
| | $ | 601,000 |
| | $ | — |
| | $ | 27,796 |
| | $ | 928,796 |
| 2016 | | $ | 300,000 |
| | $ | 651,467 |
| | $ | — |
| | $ | 27,544 |
| | $ | 979,011 |
|
| | | | | | | | | | | | | | | | | | | | | |
| William R. Moler | 2017 | | $ | 300,000 |
| | $ | 400,943 |
| | $ | — |
| | $ | 28,152 |
| | $ | 729,095 |
| 2018 | | $ | 300,000 |
| | $ | 500,000 |
| | $ | 951,328 |
| | $ | 28,652 |
| | $ | 1,779,980 |
|
| Executive Vice President, Chief | 2016 | | $ | 300,000 |
| | $ | 576,468 |
| | $ | — |
| | $ | 24,544 |
| | $ | 901,012 |
| 2017 | | $ | 300,000 |
| | $ | 400,943 |
| | $ | — |
| | $ | 28,152 |
| | $ | 729,095 |
|
| Operating Officer and Director | 2015 | | $ | 300,000 |
| | $ | 551,000 |
| | $ | — |
| | $ | 27,796 |
| | $ | 878,796 |
| 2016 | | $ | 300,000 |
| | $ | 576,468 |
| | $ | — |
| | $ | 24,544 |
| | $ | 901,012 |
|
| | | | | | | | | | | | | | | | | | | | | |
| Gary J. Brauchle | 2017 | | $ | 299,712 |
| | $ | 750,942 |
| | $ | — |
| | $ | 27,955 |
| | $ | 1,078,609 |
| 2018 | | $ | 300,000 |
| | $ | 500,000 |
| | $ | 710,854 |
| | $ | 28,459 |
| | $ | 1,539,313 |
|
| Executive Vice President and | 2016 | | $ | 294,904 |
| | $ | 576,144 |
| | $ | — |
| | $ | 27,537 |
| | $ | 898,585 |
| 2017 | | $ | 299,712 |
| | $ | 750,942 |
| | $ | — |
| | $ | 27,955 |
| | $ | 1,078,609 |
|
| Chief Financial Officer | 2015 | | $ | 275,000 |
| | $ | 551,000 |
| | $ | — |
| | $ | 27,665 |
| | $ | 853,665 |
| 2016 | | $ | 294,904 |
| | $ | 576,144 |
| | $ | — |
| | $ | 27,537 |
| | $ | 898,585 |
|
| | | | | | | | | | | | | | | | | | | | | |
Christopher R. Jones (5) | 2017 | | $ | 271,569 |
| | $ | 750,942 |
| | $ | 3,545,100 |
| | $ | 27,686 |
| | $ | 4,595,297 |
| 2018 | | $ | 297,116 |
| | $ | 500,000 |
| | $ | 3,821,254 |
| | $ | 28,644 |
| | $ | 4,647,014 |
|
| Vice President, General Counsel | 2016 | | $ | 240,068 |
| | $ | 426,467 |
| | $ | 69,836 |
| | $ | 24,486 |
| | $ | 760,857 |
| |
| and Secretary | | | | | | | | | | | |
| Executive Vice President, | | 2017 | | $ | 271,569 |
| | $ | 750,942 |
| | $ | 3,545,100 |
| | $ | 27,686 |
| | $ | 4,595,297 |
|
| General Counsel and Secretary | | 2016 | | $ | 240,068 |
| | $ | 426,467 |
| | $ | 69,836 |
| | $ | 24,486 |
| | $ | 760,857 |
|
| | | | | | | | | | | | | | | | | | | | | |
| Gary D. Watkins | 2017 | | $ | 224,922 |
| | $ | 248,435 |
| | $ | 1,378,650 |
| | $ | 23,356 |
| | $ | 1,875,363 |
| 2018 | | $ | 247,116 |
| | $ | 250,000 |
| | $ | 1,209,600 |
| | $ | 25,664 |
| | $ | 1,732,380 |
|
| Vice President and | 2016 | | $ | 222,975 |
| | $ | 201,470 |
| | $ | 69,836 |
| | $ | 23,081 |
| | $ | 517,362 |
| 2017 | | $ | 224,922 |
| | $ | 248,435 |
| | $ | 1,378,650 |
| | $ | 23,356 |
| | $ | 1,875,363 |
|
| Chief Accounting Officer | 2015 | | $ | 212,322 |
| | $ | 201,000 |
| | $ | 1,226,264 |
| | $ | 22,152 |
| | $ | 1,661,738 |
| 2016 | | $ | 222,975 |
| | $ | 201,470 |
| | $ | 69,836 |
| | $ | 23,081 |
| | $ | 517,362 |
|
| |
(1) | Reflects actual salary received. Salary adjustments are typically implemented during February, which results in odd amounts actually received by the indicated Named Executive Officer. |
| |
(2) | Represents discretionary cash bonuses paid in 2019, 2018 and 2017 based on performance in 2018, 2017 and 2016, based on performance in 2017, 2016 and 2015, respectively, as well as a bonus of $500 after tax that was paid to all employees in 2017, and a bonus of $1,000 after tax that was paid to all employees in 2016, and a $1,000 pre-tax bonus that was paid to all employees in 2015.2016. |
| |
(3) | The amounts in this column include both equity participation units granted pursuant to the TEP LTIP and equity participation shares granted pursuant to the TEGP LTIP.Plans. Each of our Named Executive Officers, with the exception of Mr. Dehaemers, received grants under the Plans in 2018. In addition, Mr. Moler, Mr. Brauchle, and Mr. Jones each received grants in January 2019 as a component of their 2018 bonuses. Mr. Jones and Mr. Watkins were the only Named Executive Officers to receive grants under the TEP LTIPPlans during 2016 and 2017 and Mr. Watkins was the only Named Executive Officer to receive grants under the TEGP LTIP during 2015. In addition, the2017. These amounts in this column represent the aggregate grant date fair value determined in accordance with ASC Topic 718 for equity participation units, or EPUs, granted under the TEPLegacy LTIP prior to June 30, 2018 and equity participation shares, or EPSs granted under the TEGP LTIP.Plans. Pursuant to SEC rules, the amounts shown in the Summary Compensation Table for awards subject to performance conditions are based on the probable outcome as of the date of grant and exclude the impact of estimated forfeitures. The EPUs and EPSs are non-participating, therefore the grant date fair value is discounted from the grant date fair value of TEP's common units or TEGP'sTGE's Class A shares, as appropriate, for the present value of the expected (but non-participating) future dividends during the vesting period. For additional information, see Note 16 – Equity-Based Compensation. These amounts do not correspond to the actual value that will be recognized by the executive. |
| |
(4) | The amounts in the column include the following: contributions under the 401(k) savings plan (includes $27,500 for Mr. Dehaemers, $27,500 for Mr. Moler, $27,307 for Mr. Brauchle, $27,500 for Mr. Jones, and $24,712 for Mr. Watkins for the year ended December 31, 2018; $27,000 for Mr. Dehaemers, $27,000 for Mr. Moler, $26,804 for Mr. Brauchle, $26,640 for Mr. Jones, and $22,492 for Mr. Watkins for the year ended December 31, 2017,2017; and $26,500 for Mr. Dehaemers, $26,500 for Mr. Moler, $26,500 for Mr. Brauchle, $23,629 for Mr. Jones, and $22,297 for Mr. Watkins for the year ended December 31, 2016, and $26,500 for Mr. Dehaemers, $26,500 for Mr. Moler, $26,477 for Mr. Brauchle, and $21,232 for Mr. Watkins for the year ended December 31, 2015)2016) and the dollar value of premiums paid for group life, accidental death and dismemberment insurance. |
| |
| Mr. Jones was appointed Vice President, General Counsel and Secretary of TEP and TEGP effective July 1, 2016. |
As required by Section 953(b) of the Dodd-Frank Act and Item 402(u) of Regulation S-K, we are providing information regarding the internal pay ratio between the annual total compensation of our Chief Executive Officer and the median of the annual total compensation of all employees. Because we do not have any of our own employees, we are providing this ratio based on the total compensation of all employees of Tallgrass Management as of December 31, 2017. Employees of Tallgrass Management provide certain services to us and our consolidated subsidiaries under the TEP Omnibus Agreement. To determine the median of the annual total compensation of all such employees, excluding our Chief Executive Officer, we identified the “median employee”"median employee" by comparing the amount of salary, wages and tips of such employees, whether full-time, part-time, seasonal or temporary, as reflected in the payroll records of Tallgrass Management for the period from January 1, 20172018 through December 31, 2017.2018. We determined that our Chief Executive Officer had annual total compensation of $1,328,891,$1,328,652, which is reflected in the Summary Compensation Table above, and the median of the annual total compensation of all employees, excluding our Chief Executive Officer, was $107,028.$96,979. Therefore, our Chief Executive Officer’sOfficer's annual total compensation is 12.413.7 times that of the median of the annual total compensation of all employees of Tallgrass Management.
Narrative Disclosure to Summary Compensation Table
A narrative description of all material factors necessary to an understanding of the information included in the above Summary Compensation Table is included in "Compensation Discussion and Analysis" and in the footnotes to such tables.
Grants of Plan-Based Awards Table
The following table provides information concerning each grant of an award made to a Named Executive Officer for 2017, including, but not limited to awards madeduring 2018 under the TEP LTIP and TEGP LTIP.Plans.
| | | | Grant Type | | Grant Date | | Number of Shares or Units | | Grant Date Fair Value of Awards(1) | Grant Type | | Grant Date | | Number of Shares or Units | | Grant Date Fair Value of Awards(1) |
| Gary J. Brauchle | | | | | | | |
| Executive Vice President and | | TEP Equity Participation Units | | 2/14/18 |
| | 6,700 |
| (2) | $ | 30.83 |
|
| Chief Financial Officer | | TGE Equity Participation Shares | | — |
| | — |
| | $ | — |
|
| | | | | | | | |
| William R. Moler | | | | | | | |
| Executive Vice President, Chief | | TEP Equity Participation Units | | 2/14/18 |
| | 14,500 |
| (2) | $ | 30.83 |
|
| Operating Officer and Director | | TGE Equity Participation Shares | | — |
| | — |
| | $ | — |
|
| | | | | | | | |
| Christopher R. Jones | | | | | | | | | | | | | |
| Vice President, General Counsel | TEP Equity Participation Units | | 8/2/17 |
| | 90,000 |
| (2) | $ | 3,545,100 |
| |
| and Secretary | TEGP Equity Participation Shares | | — |
| | — |
| (3) | $ | — |
| |
| Executive Vice President, General | | TEP Equity Participation Units | | 2/14/18 |
| | 6,700 |
| (2) | $ | 30.83 |
|
| Counsel and Secretary | | TGE Equity Participation Shares | | 10/19/18 |
| | 180,000 |
| (3) | $ | 17.28 |
|
| | | | | | | | | | | | | |
| Gary D. Watkins | | | | | | | | | | | | |
| Vice President and | TEP Equity Participation Units | | 8/2/17 |
| | 35,000 |
| (2) | $ | 1,378,650 |
| TEP Equity Participation Units | | — |
| | — |
| | $ | — |
|
| Chief Accounting Officer | TEGP Equity Participation Shares | | — |
| | — |
| (3) | $ | — |
| TGE Equity Participation Shares | | 10/19/18 |
| | 70,000 |
| (3) | $ | 17.28 |
|
| |
(1) | The amounts in this column include EPUs granted pursuant to the TEP LTIP. In addition, the amounts in this column represent the aggregate grant date fair value determined in accordance with ASC Topic 718 for equity participation units, or EPUs, granted under the TEPLegacy LTIP prior to June 30, 2018 and equity participation shares, or EPSs, granted under the TEGP LTIP.Plans. Pursuant to SEC rules, the amounts shown in this table for awards subject to performance conditions, if applicable, are based on the probable outcome as of the date of grant and exclude the impact of estimated forfeitures. The EPU and equity participation share grants are measured at their grant date fair value. The EPUs and equity participation sharesEPSs are non-participating, therefore the grant date fair value is discounted from the grant date fair value of TEP's common units or TEGP'sTGE's Class A shares, as appropriate, for the present value of the expected (but non-participating) future dividends during the vesting period. For additional information, see Note 16 – Equity-Based Compensation. These amounts do not correspond to the actual value that will be recognized by the executive. |
| |
(2) | Vesting of the equity participation unitsEPUs will occur on January 1, 2020 as long as the employee satisfies the continuing service requirement set forth in the applicable award agreement. These awards were converted to EPSs effective June 30, 2018 at a ratio of 2.0 EPSs for each outstanding EPU. The Blackstone Acquisition constitutes a change of control with respect to these EPSs and as a result, any outstanding EPSs under these awards will vest upon consummation of the Blackstone Acquisition. |
| |
(3) | Vesting of the EPSs will occur on the earliest date on or after AprilNovember 1, 2021,2022, on which the average compounded annual distribution growth rate, for TEP's regular quarterly distributions, based upon the regular quarterly distribution paid by TEPTGE on, or immediately prior to, such date is at least 5% over an annualized distribution rate of $3.34$1.99 per TEP common unit,TGE Class A share, as determined by the board of directors of TEP'sour general partner. If such date has not occurred by August 2, 2024,October 19, 2025, such equity participation unitsEPSs will expire and terminate and no vesting will occur. |
| |
These EPSs do not vest solely as a result of the consummation of the Blackstone Acquisition. See (3)"Potential Payments upon Termination or Change-in-Control" for a description of the conditions that would accelerate vesting of these EPSs. | There were no equity participation shares granted under the TEGP LTIP during the year ended December 31, 2017. |
Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Award Table
A narrative description of all material factors necessary to an understanding of the information included in the above Summary Compensation Table and Grants of Plan-Based Awards Table is included in "Compensation Discussion and Analysis" and in the footnotes to such tables.
Outstanding Equity Awards at Fiscal Year-End
The following table reflects theEffective June 30, 2018, all outstanding TEP equity awards of our Named Executive Officers as of December 31, 2017participation units under the Legacy LTIP were converted to equity participation shares at a ratio of 2.0 equity participation shares for each outstanding TEP LTIP.
|
| | | | | | | | | | | | | |
| | Equity Participation Unit Awards (1) |
| | Number of EPU Awards That Have Not Vested | | Market Value of EPU Awards That Have Not Vested (2) | | Number of Unearned EPUs That Have Not Vested | | Market or Payout Value of Unearned EPUs That Have Not Vested |
| David G. Dehaemers, Jr. | — |
| | $ | — |
| | — |
| | $ | — |
|
| William R. Moler | — |
|
| $ | — |
| | — |
| | $ | — |
|
| Gary J. Brauchle | — |
|
| $ | — |
| | — |
| | $ | — |
|
| Christopher R. Jones | 97,800 |
| (3) | $ | 4,484,130 |
| | — |
| | $ | — |
|
| Gary D. Watkins | 43,400 |
| (4) | $ | 1,989,890 |
| | — |
| | $ | — |
|
| |
(1)
| The award agreements pursuant to which the EPUs set forth above were granted provide for the settlement of the EPUs in common units. |
| |
(2)
| Reflects the closing price of $45.85 per TEP common unit at December 29, 2017. |
| |
(3)
| Mr. Jones holds 2,900 EPUs that will vest on May 13, 2018, 2,900 EPUs that will vest on May 13, 2019, and 2,000 EPUs will vest on November 1, 2019 as long as he meets the required continuing service obligations. The remaining 90,000 EPUs that will vest on the earliest date on or after April 1, 2021, on which the average compounded annual distribution growth rate for TEP's regular quarterly distributions, based upon the regular quarterly distribution paid by TEP on, or immediately prior to, such date is at least 5% over an annualized distribution rate of $3.34 per TEP common unit, as determined by the board of directors of TEP's general partner. If such date has not occurred by August 2, 2024, these 90,000 EPUs will expire and terminate and no vesting will occur. |
| |
(4)
| Mr. Watkins holds 3,200 EPUs that will vest on May 13, 2018, 3,200 EPUs that will vest on May 13, 2019, and 2,000 EPUs that will vest on November 1, 2019 as long as he meets the required continuing service obligations. The remaining 35,000 EPUs that will vest on the earliest date on or after April 1, 2021, on which the average compounded annual distribution growth rate for TEP's regular quarterly distributions, based upon the regular quarterly distribution paid by TEP on, or immediately prior to, such date is at least 5% over an annualized distribution rate of $3.34 per TEP common unit, as determined by the board of directors of TEP's general partner. If such date has not occurred by August 2, 2024, these 35,000 EPUs will expire and terminate and no vesting will occur. |
equity participation unit. The following table reflects all outstanding equity awards of our named executive officers as of December 31, 2017 under the TEGP LTIP.2018.
| | | | Equity Participation Share Awards (1) | Equity Participation Share Awards (1) |
| | Number of Equity Participation Share Awards That Have Not Vested | | Market Value of Equity Participation Share Awards That Have Not Vested | | Number of Unearned Equity Participation Shares That Have Not Vested | | Market or Payout Value of Unearned Equity Participation Shares That Have Not Vested (2) | Number of Equity Participation Share Awards That Have Not Vested | | Market Value of Equity Participation Share Awards That Have Not Vested (2) | | Number of Unearned Equity Participation Shares That Have Not Vested | | Market or Payout Value of Unearned Equity Participation Shares That Have Not Vested (2) |
| David G. Dehaemers, Jr. | — |
| | $ | — |
| | — |
| | $ | — |
| — |
| | $ | — |
| | — |
| | $ | — |
|
| William R. Moler | — |
| | $ | — |
| | — |
| | $ | — |
| 29,000 |
| (3) | $ | 705,860 |
| | — |
| | $ | — |
|
| Gary J. Brauchle | — |
| | $ | — |
| | — |
| | $ | — |
| 13,400 |
| (4) | $ | 326,156 |
| | — |
| | $ | — |
|
| Christopher R. Jones | 35,000 |
| (3) | $ | 900,900 |
| | — |
| | $ | — |
| 418,200 |
| (5) | $ | 10,178,988 |
| | — |
| | $ | — |
|
| Gary D. Watkins | 35,000 |
| (3) | $ | 900,900 |
| | — |
| | $ | — |
| 185,400 |
| (6) | $ | 4,512,636 |
| | — |
| | $ | — |
|
| |
(1) | The award agreements pursuant to which the equity participation shares set forth above were granted provide for the settlement of the equity participation shares in TEGP Class A Shares. |
| |
(2) | Reflects the closing price of $25.74$24.34 per TEGP Class A share at December 29, 2017.31, 2018. |
| |
(3) | Mr. Jones and Mr. Watkins each hold 35,000Moler holds 29,000 equity participation shares that will vest on May 12, 2019issued under the fifth category of awards described under "Elements of Compensation" above. |
| |
(4) | Mr. Brauchle holds 13,400 equity participation shares issued under the fifth category of awards described under "Elements of Compensation" above. |
| |
(5) | Mr. Jones holds 5,800, 35,000, 4,000, 180,000, 13,400, and 180,000 equity participation shares issued under the first, second, third, fourth, fifth, and sixth categories, respectively, as longdescribed under "Elements of Compensation" above. |
| |
(6) | Mr. Watkins holds 6,400, 35,000, 4,000, 70,000, and 70,000 equity participation shares issued under the first, second, third, fourth, and sixth categories, respectively, as they meet the required continuing service obligations.described under "Elements of Compensation" above. |
Units Vested LTIP Awards
The following table sets forth certain information regarding the vesting of TEP LTIP Awards duringheld by the fiscal year ended December 31, 2017.Named Executive Officers granted under the Legacy LTIP prior to the June 30, 2018 effective date of the TEP Merger. No TEGP Equity Participation ShareLTIP Awards held by the Named Executive Officers under the TGE LTIP vested during 2017.2018 and no LTIP Awards held by the Named Executive Officers under the Legacy LTIP vested after June 30, 2018.
|
| | | | | | |
| | Number of EPUs Acquired on Vesting (1) | | Value Realized on Vesting (2) |
| David G. Dehaemers, Jr. | — |
| | $ | — |
|
| President, Chief Executive | | | |
| Officer and Director | | | |
| | | | |
| William R. Moler | 33,333 |
| | $ | 1,675,983 |
|
| Executive Vice President, Chief | | | |
| Operating Officer and Director | | | |
| | | | |
| Gary J. Brauchle | 33,333 |
| | $ | 1,675,983 |
|
| Executive Vice President and | | | |
| Chief Financial Officer | | | |
| | | | |
| Christopher R. Jones | 16,000 |
| | $ | 804,480 |
|
| Vice President, General Counsel | | | |
| and Secretary | | | |
| | | | |
| Gary D. Watkins | 16,666 |
| | $ | 837,966 |
|
| Vice President and | | | |
| Chief Accounting Officer | | | |
|
| | | | | | |
| | Number of EPUs Acquired on Vesting (1) | | Value Realized on Vesting (2) |
| David G. Dehaemers, Jr. | — |
| | $ | — |
|
| President, Chief Executive Officer and Director | | | |
| | | | |
| William R. Moler | — |
| | $ | — |
|
| Executive Vice President, Chief Operating Officer and Director | | | |
| | | | |
| Gary J. Brauchle | — |
| | $ | — |
|
| Executive Vice President and Chief Financial Officer | | | |
| | | | |
| Christopher R. Jones | 2,900 |
| | $ | 123,801 |
|
| Executive Vice President, General Counsel and Secretary | | | |
| | | | |
| Gary D. Watkins | 3,200 |
| | $ | 136,608 |
|
| Vice President and Chief Accounting Officer | | | |
| |
(1) | Represents the gross number of EPUs that vested during the year ended December 31, 2017.2018. The actual number of EPUsTEP common units delivered to the Named Executive Officers was, in some cases, less than the number shown in the above table due to the Named Executive Officers' option to net out TEP common units to cover a portion of applicable tax withholding obligations. |
| |
(2) | The stated value realized upon vesting is computed by multiplying the closing market price ($50.28)42.69) of ourTEP's common units on the date they vested (May 13, 2017)2018) by the number of units that vested. |
Pension Benefits
We sponsor a 401(k) plan that is available to all employees, but we do not maintain a pension or defined benefit program.
Nonqualified Deferred Compensation and Other Nonqualified Deferred Compensation Plans
We do not have a nonqualified deferred compensation plan or program for our officers or employees.
Employment Agreement
On November 2, 2016, Mr. Dehaemers entered into a second amended and restated employment agreement with Tallgrass Management, our general partner, Tallgrass Energy Holdings, Tallgrass Equity and TEP's general partner, pursuant to which he agreed to serve as the President and Chief Executive Officer of our general partner. Under the terms of the employment agreement, Mr. Dehaemers is entitled to receive an annual salary of $300,000. In addition, Mr. Dehaemers is entitled to receive (i) benefits that are normally provided to senior executives of Tallgrass Management, (ii) reimbursement for all ordinary and necessary out-of-pocket expenses incurred by Mr. Dehaemers, and (iii) a policy of director and officer liability insurance. Mr. Dehaemers' employment is "at-will" and may be terminated at any time.
For a discussion of certain payments that Mr. Dehaemers may be entitled to upon the termination of his employment, please read "Potential Payments Upon Termination or a Change-in-Control."
Potential Payments upon Termination or Change-in-Control
Termination
The employment agreement for Mr. Dehaemers provides that in the event his employment is terminated without "cause" or in the event he resigns for "good reason" he will receive: (i) a severance payment equal to $900,000, payable in a lump sum within 60 days after the termination of his employment; and (ii) directors and officers liability insurance coverage for so long as he is subject to any claim arising from his employment by TEGPTGE and its Affiliates. In addition, upon any such termination, Mr. Dehaemers would receive payments related to his accrued and unpaid expenses, salary and benefits. Under Mr. Dehaemers' employment agreement:
"Cause" means (i) his conviction of, or plea of nolo contendere to, any crime or offense constituting a felony under applicable law; (ii) his commission of fraud or embezzlement against Tallgrass Management or certain of its affiliates; (iii) gross neglect by Mr. Dehaemers of, or gross or willful misconduct of Mr. Dehaemers in connection with the performance of, his duties that, if curable, is not cured within 30 days of receiving a written notice of such gross neglect or gross or willful misconduct; (iv) Mr. Dehaemers' willful failure or refusal to carry out the reasonable and lawful instructions of the board of managers of the entity with ultimate control over our general partner;Tallgrass Energy Holdings, and, in each case, such failure or refusal has continued for a period of 30 calendar days following written notice; (v) Mr. Dehaemers' failure to perform the duties and responsibilities of his office as his primary business activity; (vi) a judicial determination that Mr. Dehaemers has breached his fiduciary duties with respect to Tallgrass Management or certain of its affiliates; or (vii) Mr. Dehaemers' willful and material breach of his obligations under the operatinglimited liability company agreements of Tallgrass Energy Holdings, our general partner, or certain affiliates of Tallgrass Management, in his capacity as an officer ofEquity and TEP GP, including willfully causing any applicable Tallgrass entity to take any material action prohibited by such entities.organizational documents, that Mr. Dehaemers failed to cure, if curable, within 30 days following written notice thereof, specifically identifying such willful and material breach.
"Good reason" means (i) a material diminution of Mr. Dehaemers' duties and responsibilities to Tallgrass Management or certain of its affiliates to a level inconsistent with those of a chief executive officer; (ii) a material reduction in Mr. Dehaemers' cash compensation or the aggregate welfare benefits provided to him (excluding any reduction that is not limited to him specifically); (iii) a willful or intentional breach of his employment agreement by Tallgrass Management; or (iv) a willful or intentional breach by our general partner or certain affiliates of Tallgrass Management of a material provision of the applicable operating agreements of such entities that has a material and adverse effect on Mr. Dehaemers.
Other than the payments to Mr. Dehaemers pursuant to his employment agreement as described above, we are not obligated to make any cash payment or provide any benefit to our Named Executive Officers if their employment is terminated by us or by the Named Executive Officer, other than the payment of accrued and unpaid expenses, salary and benefits. In addition, except for the acceleration of the 2017 Grants and 2018 Grants under the circumstances further described below, any LTIP Awards that have not vested and/or become exercisable are terminated upon the termination of such Named Executive Officer's employment.
Change in Control
Employment Agreement. Upon a change in control, the employment agreement of Mr. Dehaemers generally does not provide for termination or severance benefits or payments in addition to those described above.
LTIP Award Agreements. In addition to the foregoing payments to Mr. Dehaemers pursuant to his employment agreement, the TEPLegacy LTIP Awards and TEGPTGE LTIP Awards held by our Named Executive Officers other than the 2017 Grants and 2018 Grants typically provide for acceleration of vesting in connection with a change in control. The TEP LTIP Awards held by our Named Executive Officers other than the 2017 Grants and 2018 Grants vest and/or become exercisable in full upon a "change in control" of us or our general partner and the TEGPpartner. The Blackstone Acquisition constitutes a change of control with respect to these LTIP Awards held byand as a result, any outstanding LTIP Awards to our Named Executive Officers other than the 2017 Grants and the 2018 Grants will vest and/or become exercisable in full upon a "change in control"consummation of TEGP or TEGP's general partner.the Blackstone Acquisition.
Under the TEP LTIP, "change of control" means the occurrence of one or more of the following events:
any Person or group, other than Tallgrass Equity or its affiliates, becomes the owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of (A) the combined voting power of the equity interests in TEP's general partner, or (B) the general partner interests in TEP (excluding incentive distribution rights);
the limited partners of TEP approve, in one or a series of transactions, a plan of complete liquidation of TEP; or
the sale or other disposition by TEP of all or substantially all of its assets in one or more transactions to any person other than TEP's general partner or its affiliates.
Under the TEGP LTIP,Plans, "change of control" means the occurrence of one or more of the following events:
any Person or group, other than Tallgrass Energy Holdings or its affiliates, becomes the owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of (A) the combined voting power of the equity interests in TEGP Managementour general partner or (B) the general partner interests in TEGP;
TGE;
the limited partners of TEGPTGE approve, in one or a series of transactions, a plan of complete liquidation of TEGP;TGE; or
the sale or other disposition by TEGPTGE of all or substantially all of its assets in one or more transactions to any person other than TEGP Management orour general partner an affiliate of the TEGP Management.our general partner.
The 2017 Grants include accelerated vesting if either (i) both (A) a qualifying transaction occurs, and (B) Mr. Dehaemers ceases to be the Chief Executive Officer of TEP'sour general partner andor certain of its affiliates, or (ii) (A) Mr. Dehaemers ceases to be the Chief Executive Officer of TEP'sour general partner andor certain of its affiliates, and (B) the Named Executive Officer is thereafter terminated without cause.
Under the award agreements for the 2017 Grants, a qualifying transaction means any transaction in which:
a person other than certain designated persons directly or indirectly acquires direct or indirect ownership or control of 50% or more of the voting interests in TEP's general partner, the ownership of fifty percent 50% or more of the general partner interests in TEP, or the ownership of such other rights or interests that grant to the owner or holder thereof the ability
to direct the management or policies of TEP, whether through the ownership of voting rights, by contract, or otherwise;
TEP's limited partners approve, in one or a series of transactions, a plan of complete liquidation of TEP; or
the sale or other disposition by TEP of all or substantially all of its assets in one or more transactions to any person other than TEP's general partner and its affiliates.
The 2017 Grants do not vest solely as a result of the consummation of the Blackstone Acquisition.
The 2018 Grants to Mr. Jones include accelerated vesting if either (i) both (A) a qualifying transaction occurs, and (B) in connection with or within 12 months following such qualifying transaction, Mr. Dehaemers ceases to be the Chief Executive Officer of our general partner or certain of its affiliates, or (ii) (A) Mr. Dehaemers ceases to be the Chief Executive Officer of our general partner or certain of its affiliates, and (B) within 2 years after the occurrence of such event, Mr. Jones is terminated without cause.
The 2018 Grants to Mr. Watkins include accelerated vesting if either (i) both (A) a qualifying transaction occurs, and (B) in connection with or within 12 months following such qualifying transaction, Mr. Dehaemers, Mr. Moler, Mr. Brauchle or Mr. Jones cease to comprise at least one of the roles of Chief Executive Officer, Chief Operating Officer, Chief Financial Officer or General Counsel of our general partner or certain of its affiliates, or (ii) (A) Mr. Dehaemers, Mr. Moler, Mr. Brauchle or Mr. Jones cease to comprise at least one of the roles of Chief Executive Officer, Chief Operating Officer, Chief Financial Officer or General Counsel of our general partner or certain of its affiliates, and (B) within 2 years after the occurrence of such event, Mr. Watkins is terminated without cause.
Under the award agreements for the 2018 Grants, a qualifying transaction means any transaction in which:
a person other than certain designated persons directly or indirectly acquires direct or indirect ownership or control of more than 50% of the voting interests in our general partner, the ownership of more than 50% of the general partner interests in TGE, or the ownership of such other rights or interests that grant to the owner or holder thereof the ability to direct the management or policies of TGE, whether through the ownership of voting rights, by contract, or otherwise, or if TGE becomes a corporation or limited liability company or if the limited partners of TGE become eligible to elect the members of the board of our general partner, the direct or indirect ability to appoint a majority of the board of directors of the corporation or limited liability company or the board of our general partner, as the case may be.
TGE's limited partners approve, in one or a series of transactions, a plan of complete liquidation of TGE; or
the sale or other disposition by TGE of all or substantially all of its assets in one or more transactions to any person other than our general partner and its affiliates.
The 2018 Grants do not vest solely as a result of the consummation of the Blackstone Acquisition.
The following table sets forth the value of outstanding LTIP Awards that would have vested and/or become exercisable for each of the Named Executive Officers under the TEP LTIP and TEGP LTIPPlans if a triggering change in control event described above occurred on December 31, 2017.2018.
|
| | | |
| | Upon a Change in Control (1) |
| David G. Dehaemers, Jr. | |
| TEP LTIP | $ | — |
|
| TEGP LTIP | $ | — |
|
| | |
| William R. Moler | |
| TEP LTIP | $ | — |
|
| TEGP LTIP | $ | — |
|
| | |
| Gary J. Brauchle | |
| TEP LTIP | $ | — |
|
| TEGP LTIP | $ | — |
|
| | |
| Christopher R. Jones | |
| TEP LTIP | $ | 4,484,130 |
|
| TEGP LTIP | $ | 900,900 |
|
| | |
| Gary D. Watkins | |
| TEP LTIP | $ | 1,989,890 |
|
| TEGP LTIP | $ | 900,900 |
|
|
| | | |
| | Upon a Change in Control (1) |
| David G. Dehaemers, Jr. | $ | — |
|
| William R. Moler | $ | 705,860 |
|
| Gary J. Brauchle | $ | 326,156 |
|
| Christopher R. Jones | $ | 10,178,988 |
|
| Gary D. Watkins | $ | 4,512,636 |
|
| |
(1) | The stated value upon a change in control is computed by assuming that a triggering change of control event occurred on December 29, 201731, 2018 and multiplying the closing market price (TEP: $45.85 and TEGP: $25.74)($24.34) of the relevant units andClass A shares on such date by the number of units andClass A shares that would have vested. |
Confidentiality, Non-Compete and Non-Solicitation Arrangements
Under the terms of Mr. Dehaemers's employment agreement, he has agreed not to compete with Tallgrass Management or certain of its affiliates and not to solicit Tallgrass Management's or any of its affiliates' employees or interfere with certain business relationships during the term of his employment and for one year thereafter. In addition, under the terms of the award
agreements for the 2017 Grants and 2018 Grants, Mr. Jones and Mr. Watkins have agreed not to compete with TEP'sour general partner and its affiliates for the period commencing on the grant date and ending upon the earlier of (i) if a vesting date occurs, 18-months following termination of such person's employment, (ii) the date such EPUsLTIP Awards are forfeited without vesting, and (iii) the date such EPUsLTIP Awards expire. Each of the Named Executive Officers has signed a confidentiality agreement in connection with their employment by Tallgrass Management.
Compensation of TEGPTGE Directors
Officers or employees of Tallgrass Energy Holdings or its affiliates, including certain directors affiliated with EMG or Kelso, who also serve as directors of our general partner do not receive additional compensation for such service. In 2017,2018, those directors of our general partner who were not excluded from receiving compensation were paid quarterlycash compensation as follows:
Quarterly cash payments of $10,000, resulting in an effective annual cash payment of $40,000.
For serving as the conflicts committee chair, a quarterly committee chair cash payment of $5,000.
In addition, Mr. Cook and Mr. Towner received compensation during the year ended December 31, 2018 for their service on the TEP board of directors prior to the TEP Merger. Mr. Cook and Mr. Towner were appointed as directors of our general partner on September 7, 2018.
All directors are also reimbursed for out-of-pocket expenses in connection with their service as directors, including costs incurred to attend meetings. Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our partnership agreement. Directors of our general partner are also eligible to receive grants under the TEGP LTIP.Plans.
The following table sets forth certain information with respect to our non-employee directors receiving cash compensation during the year ended December 31, 2017:2018:
| | | Name and Principal Position | Fees Earned | | Equity Participation Share Awards | | Non-Equity Incentive Plan Compensation | | Total | Fees Earned | | Equity Participation Share Awards (1) | | Non-Equity Incentive Plan Compensation | | Total |
| Thomas A. Gerke | $ | 40,000 |
| | $ | — |
| | $ | — |
| | $ | 40,000 |
| $ | 60,000 |
| | $ | — |
| | $ | — |
| | $ | 60,000 |
|
| W. Curtis Koutelas | $ | 40,000 |
| | $ | — |
| | $ | — |
| | $ | 40,000 |
| |
| Roy N. Cook | | $ | 105,000 |
| | $ | 130,840 |
| | $ | — |
| | $ | 235,840 |
|
| Terrance D. Towner | | $ | 65,000 |
| | $ | 130,840 |
| | $ | — |
| | $ | 195,840 |
|
W. Curtis Koutelas (2) | | $ | 30,000 |
| | $ | — |
| | $ | — |
| | $ | 30,000 |
|
| |
(1) | The amounts in this column include equity participation shares granted pursuant to the Plans. These amounts represent the aggregate grant date fair value determined in accordance with ASC Topic 718 for equity participation shares granted under the Plans. Pursuant to SEC rules, the amounts shown in the table above for awards subject to performance conditions are based on the probable outcome as of the date of grant and exclude the impact of estimated forfeitures. The EPSs are non-participating, therefore the grant date fair value is discounted from the grant date fair value of TGE's Class A shares, as appropriate, for the present value of the expected (but non-participating) future dividends during the vesting period. For additional information, see Note 16 – Equity-Based Compensation. These amounts do not correspond to the actual value that will be recognized by the directors. |
| |
(2) | Mr. Koutelas resigned from the board of directors of our general partner effective September 7, 2018. |
Compensation Committee Interlocks and Insider Participation
The listing rules of the NYSE do not require us to maintain, and we do not maintain, a compensation committee.
Mr. Dehaemers, as President and Chief Executive Officer, and Mr. Moler, as Executive Vice President and Chief Operating Officer, participate in their capacity as a director of our general partner in the deliberations of the Board concerning executive officer compensation. In addition, Mr. Dehaemers makes recommendations to the board of directors regarding named executive officer compensation, but Mr. Dehaemers is not present for any discussions regarding his performance or compensation.
Compensation Report of the Board of Directors
The Board of Directors of our general partner has reviewed and discussed the compensation discussion and analysis contained in this Annual Report on Form 10-K with management and, based on that review and discussion, has recommended that the compensation discussion and analysis be included in this Annual Report for the year ended December 31, 20172018 for filing with the SEC.
David G. Dehaemers, Jr.
William R. Moler
Frank J. Loverro
Stanley de J. Osborne
Jeffrey A. Ball
John T. Raymond
Thomas A. Gerke
W. Curtis KoutelasRoy N. Cook
Terrance D. Towner
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Tallgrass Energy, GP, LP
The following tables set forth certain information regarding the beneficial ownership of our Class A shares and Class B shares as of February 9, 20186, 2019 owned by:
each person who is known to us to beneficially own more than 5% of the Class A shares (calculated in accordance with Rule 13d-3);
the named executive officers of our general partner;
each of the directors of our general partner; and
all the directors and executive officers of our general partner as a group.
All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more shareholders, as the case may be. The amounts and percentage of Class A shares and Class B shares beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all Class A shares and Class B shares shown as beneficially owned by them, subject to community property laws where applicable. Unless otherwise noted, the address of each beneficial owner named in the chart below is 4200 W. 115th Street, Suite 350, Leawood, Kansas 66211, Attn: General Counsel.
| | | Name and Address of Beneficial Owner | | Class A and Class B shares Beneficially Owned (1) | | Percentage of Class A and Class B shares Beneficially Owned (2) | | Combined Voting Power (3) | | Class A and Class B shares Beneficially Owned (1) | | Percentage of Class A and Class B shares Beneficially Owned (2) | | Combined Voting Power (3) |
| 5% shareholders | | | | | | | | | | | | |
Entities affiliated with Kelso (4) | | 46,727,603 |
| | 44.58 | % | | 25.29 | % | | 46,727,603 |
| | 23.01 | % | | 16.67 | % |
Entities affiliated with EMG (5) | | 46,386,232 |
| | 44.4 | % | | 25.1 | % | | 46,386,232 |
| | 22.88 | % | | 16.55 | % |
Tallgrass KC (6) | | 30,820,458 |
| | 34.67 | % | | 16.68 | % | | 29,416,692 |
| | 15.83 | % | | 10.5 | % |
OppenheimerFunds, Inc. (7) | | 12,310,643 |
| | 21.19 | % | | 6.66 | % | | 26,697,437 |
| | 17.08 | % | | 9.53 | % |
Salient Capital Advisors, LLC (8) | | 7,847,848 |
| | 13.51 | % | | 4.25 | % | |
Tortoise Capital Advisors, L.L.C. (8) | | | 24,224,847 |
| | 15.49 | % | | 8.64 | % |
Kayne Anderson Capital Advisors, L.P. (9) | | 4,543,242 |
| | 7.82 | % | | 2.46 | % | | 8,822,918 |
| | 5.64 | % | | 3.15 | % |
Entities affiliated with Harvest Fund Advisors LLC (10) | | 4,254,757 |
| | 7.33 | % | | 2.3 | % | |
Capital World Investors (11) | | 3,549,900 |
| | 6.11 | % | | 1.92 | % | |
Tortoise Capital Advisors, L.L.C. (12) | | 3,029,730 |
| | 5.22 | % | | 1.64 | % | |
Salient Capital Advisors LLC (10) | | | 7,847,848 |
| | 5.02 | % | | 2.8 | % |
| Directors and named Executive officers: | | | | | | | | | | | | |
David G. Dehaemers, Jr. (13) | | 31,652,259 |
| | 35.49 | % | | 17.13 | % | |
William R. Moler (14) | | 2,807,531 |
| | 4.61 | % | | 1.52 | % | |
Gary J. Brauchle (15) | | 2,204,586 |
| | 3.66 | % | | 1.19 | % | |
Christopher R. Jones (16) | | 311,948 |
| | * |
| | * |
| |
David G. Dehaemers, Jr. (11) | | | 31,504,182 |
| | 16.91 | % | | 11.24 | % |
William R. Moler (12) | | | 2,903,053 |
| | 1.82 | % | | 1.04 | % |
Gary J. Brauchle (13) | | | 2,328,812 |
| | 1.47 | % | | * |
|
Christopher R. Jones (14) | | | 358,978 |
| | * |
| | * |
|
| Gary D. Watkins | | 6,500 |
| | * |
| | * |
| | 46,830 |
| | * |
| | * |
|
Frank J. Loverro (4) | | 46,727,603 |
| | 44.58 | % | | 25.29 | % | | 46,727,603 |
| | 23.01 | % | | 16.67 | % |
Stanley de J. Osborne (4) | | 46,727,603 |
| | 44.58 | % | | 25.29 | % | | 46,727,603 |
| | 23.01 | % | | 16.67 | % |
| Jeffrey A. Ball | | 20,000 |
| | * |
| | * |
| | 100,000 |
| | * |
| | * |
|
John T. Raymond (17) | | 46,621,232 |
| | 44.63 | % | | 25.23 | % | |
John T. Raymond (15) | | | 46,833,283 |
| | 23.1 | % | | 16.71 | % |
| Thomas A. Gerke | | 50,968 |
| | * |
| | * |
| | 54,300 |
| | * |
| | * |
|
| W. Curtis Koutelas | | 3,334 |
| | * |
| | * |
| |
| Roy N. Cook | | | 116,165 |
| | * |
| | * |
|
| Terrance D. Towner | | | 53,000 |
| | * |
| | * |
|
| All directors and executive officers of our general partner as a group (11 persons) | | 130,405,961 |
| | 71.64 | % | | 70.57 | % | | 131,026,206 |
| | 46.98 | % | | 46.75 | % |
| |
(1) | Pursuant to Rule 13d-3 under the Exchange Act, a person has beneficial ownership of a security as to which that person, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares voting power and/or investment power of such security and as to which that person has the right to acquire beneficial ownership of such security within 60 days. In addition to Class A shares, this column includes Class B shares beneficially owned by such persons that are, together with a corresponding number of Tallgrass Equity Units, exchangeable at any time and from time to time for Class A shares on a one-for-one basis (subject to the terms of the Tallgrass Equity limited liability company agreement and our partnership agreement). See "Certain Relationships and Related Party Transactions, and Director Independence-Exchange Right." |
| |
(2) | The Class A shares to be issued upon the exchange of Class B shares and Tallgrass Equity Units as described in footnote (1) above are deemed to be outstanding and beneficially owned by the person holding the Class B shares for the purpose of computing the percentage of beneficial ownership of Class A shares for that person and any group of which that person is a member, but are not deemed outstanding for purpose of computing the percentage of beneficial ownership of any other person. As such, the percentage of Class A shares shown as being beneficially owned by each person is based on an assumption that each such person exchanged all of such person's Class B shares, together with a corresponding number of Tallgrass Equity Units, for Class A shares and that no other person made a similar exchange. |
member, but are not deemed outstanding for purpose of computing the percentage of beneficial ownership of any other person. As such, the percentage of Class A shares shown as being beneficially owned by each person is based on an assumption that each such person exchanged all of such person's Class B shares, together with a corresponding number of Tallgrass Equity Units, for Class A shares and that no other person made a similar exchange.
| |
(3) | Represents the percentage of voting power of the Class A shares and Class B shares held by such person voting together as a single class. |
| |
(4) | Consists of Class B shares held of record by: (i) KIA VIII (Rubicon), L.P., a Delaware limited partnership, or KIA VIII, and (ii) KEP VI AIV (Rubicon), LLC, a Delaware limited liability company, or KEP VI AIV. KIA VIII and KEP VI AIV, due to their common control, could be deemed to beneficially own each of the other's shares. Each of KIA VIII and KEP VI AIV disclaim such beneficial ownership. Frank T. Nickell, Thomas R. Wall, IV, George E. Matelich, Michael B. Goldberg, David I. Wahrhaftig, Frank K. Bynum, Jr., Philip E. Berney, Frank J. Loverro, James J. Connors, II, Church M. Moore, Stanley de J. Osborne, Christopher L. Collins, A. Lynn Alexander, Howard A. Matlin, John K. Kim, Henry Mannix, III, Matthew S. Edgerton and Stephen C. Dutton (the "Kelso Individuals") may be deemed to share beneficial ownership of shares held of record or beneficially owned by KIA VIII and KEP VI AIV, by virtue of their status as managing members of KEP VI AIV and of Kelso GP VIII, LLC, a Delaware limited liability company, the principal business of which is serving as the general partner of KIA VIII (Rubicon) GP, L.P., a Delaware limited partnership, the principal business of which is serving as the general partner of KIA VIII. Each of Kelso GP VIII, LLC and KIA VIII (Rubicon) GP, L.P. due to their common control, could be deemed to beneficially own each other's securities and the shares held of record or beneficially owned by KIA VIII and KEP VI AIV. Kelso GP VIII, LLC disclaims beneficial ownership of all the securities owned of record, or deemed beneficially owned, by KIA VIII (Rubicon) GP, L.P., KIA VII and KEP VI AIV, except to the extent, if any, of its pecuniary interest therein, and the inclusion of these securities in the table above shall not be deemed an admission of beneficial ownership of all the reported securities for any purpose. KIA VIII (Rubicon) GP, L.P. disclaims beneficial ownership of all of the securities owned of record, or deemed beneficially owned, by Kelso GP VIII, LLC, KIA VIII and KEP VI AIV, except to the extent, if any, of its pecuniary interest therein, and the inclusion of these securities in the table above shall not be deemed an admission of beneficial ownership of all the reported securities for any purpose. The Kelso Individuals may be deemed to share beneficial ownership of securities owned of record or beneficially owned by Kelso GP VIII, LLC, KIA VIII (Rubicon) GP, L.P., KIA VIII and KEP VI AIV, by virtue of their status as managing members of Kelso GP VIII, LLC and KEP VI AIV, but disclaim beneficial ownership of such securities, and the inclusion of these securities in the table above shall not be deemed an admission that any of the Kelso Individuals is the beneficial owner of these securities for any purposes. Frank J. Loverro, who serves as a Managing Director and Co-Chief Executive Officer of Kelso & Company, which manages the investments in KIA VIII, KEP VI AIV, is one of our directors. Stanley de J. Osborne, who serves as a Managing Director of Kelso & Company, is also one of our directors. The business address for these persons is c/o Kelso & Company, 320 Park Avenue, 24th Floor, New York, NY 10022. |
Mannix, III, Matthew S. Edgerton and Stephen C. Dutton (the "Kelso Individuals") may be deemed to share beneficial ownership of shares held of record or beneficially owned by KIA VIII and KEP VI AIV, by virtue of their status as managing members of KEP VI AIV and of Kelso GP VIII, LLC, a Delaware limited liability company, the principal business of which is serving as the general partner of KIA VIII (Rubicon) GP, L.P., a Delaware limited partnership, the principal business of which is serving as the general partner of KIA VIII. Each of Kelso GP VIII, LLC and KIA VIII (Rubicon) GP, L.P. due to their common control, could be deemed to beneficially own each other's securities and the shares held of record or beneficially owned by KIA VIII and KEP VI AIV. Kelso GP VIII, LLC disclaims beneficial ownership of all the securities owned of record, or deemed beneficially owned, by KIA VIII (Rubicon) GP, L.P., KIA VIII and KEP VI AIV, except to the extent, if any, of its pecuniary interest therein, and the inclusion of these securities in the table above shall not be deemed an admission of beneficial ownership of all the reported securities for any purpose. KIA VIII (Rubicon) GP, L.P. disclaims beneficial ownership of all of the securities owned of record, or deemed beneficially owned, by Kelso GP VIII, LLC, KIA VIII and KEP VI AIV, except to the extent, if any, of its pecuniary interest therein, and the inclusion of these securities in the table above shall not be deemed an admission of beneficial ownership of all the reported securities for any purpose. The Kelso Individuals may be deemed to share beneficial ownership of securities owned of record or beneficially owned by Kelso GP VIII, LLC, KIA VIII (Rubicon) GP, L.P., KIA VIII and KEP VI AIV, by virtue of their status as managing members of Kelso GP VIII, LLC and KEP VI AIV, but disclaim beneficial ownership of such securities, and the inclusion of these securities in the table above shall not be deemed an admission that any of the Kelso Individuals is the beneficial owner of these securities for any purposes. Frank J. Loverro, who serves as a Managing Director and Co-Chief Executive Officer of Kelso & Company, which manages the investments in KIA VIII, KEP VI AIV, is one of our directors. Stanley de J. Osborne, who serves as a Managing Director of Kelso & Company, is also one of our directors. The business address for these persons is c/o Kelso & Company, 320 Park Avenue, 24th Floor, New York, NY 10022.
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(5) | Consists of Class B shares held of record by Tallgrass Holdings, LLC. The manager of Tallgrass Holdings, LLC is EMG Fund II Management, LP. EMG Fund II Management, LP’sLP's general partner is EMG Fund II Management, LLC. John T. Raymond, who serves as one of our directors, is the sole member of EMG Fund II Management, LLC and as such, has sole voting and dispositive power with respect to the shares held by Tallgrass Holdings, LLC; however, he disclaims beneficial ownership of those shares except to the extent of his pecuniary interest therein. The address for Tallgrass Holdings, LLC is The Energy & Minerals Group, 2229 San Felipe, Suite 1300, Houston, Texas 77019. |
| |
(6) | Consists of Class B shares held of record by Tallgrass KC. David G. Dehaemers, Jr. has sole voting and dispositive power with respect to the Class B shares held by Tallgrass KC; however, he disclaims beneficial ownership of those shares except to the extent of his pecuniary interest therein. |
| |
(7) | As reported on Schedule 13G filed with the SEC on February 5, 2018.January 18, 2019. The business address for this person is Two World Financial Center, 225 Liberty Street, New York, New York 10281. |
| |
(8) | As reported on Schedule 13G filed with the SEC on April 10, 2017. The business address for this person is 4265 San Felipe, 8th Floor, Houston, TX 77027. |
| |
(9)
| As reported on Schedule 13G filed with the SEC on February 6,August 9, 2018. Kayne Anderson Capital Advisors, L.P. is the general partner (or general partner of the general partner) of the limited partnerships and investment adviser to the other accounts. Richard A. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. Mr. Kayne is also a limited partner of each of the limited partnerships and a shareholder of the registered investment company. Kayne Anderson Capital Advisors, L.P. disclaims beneficial ownership of the shares reported, except those shares attributable to it by virtue of its general partner interests in the limited partnerships. Mr. Kayne disclaims beneficial ownership of the shares reported, except those shares held by him or attributable to him by virtue of his limited partnership interests in the limited |
partnerships, his indirect interest in the interest of Kayne Anderson Capital Advisors, L.P. in the limited partnerships, and his ownership of common stock of the registered investment company. The business address for these persons is 1800 Avenue of the Stars, Second Floor, Los Angeles California 90067.
| |
(10)
| As reported on Schedule 13D filed with the SEC on January 26, 2018. Harvest Fund Holdco L.P. is the sole member of Harvest Fund Advisors LLC (“HFA”). Blackstone Harvest Holdco L.L.C. is the general partner of Harvest Fund Holdco L.P. Blackstone Intermediary Holdco L.L.C. is the sole member of Blackstone Harvest Holdco L.L.C. Blackstone Advisory Partners L.P. is the sole member of Blackstone Intermediary Holdco L.L.C. Blackstone Advisory Services L.L.C. is the general partner of Blackstone Advisory Partners L.P. Blackstone Holdings I L.P. is the sole member of Blackstone Advisory Services L.L.C. Blackstone Holdings I/II GP Inc. is the general partner of Blackstone Holdings I L.P. The Blackstone Group L.P. is the controlling shareholder of Blackstone Holdings I/II GP Inc. The general partner of The Blackstone Group L.P. is Blackstone Group Management L.L.C. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. HFA, an investment adviser registered under the Investment Advisers Act of 1940, as amended, advises funds and accounts. In such capacity, HFA has voting authority and dispositive discretion over the securities of TEGP described in the Schedule 13D that are owned by the funds and accounts advised by it. Except for the purpose of determining beneficial ownership under Section 13(d) of the Exchange Act HFA and the other reporting persons on the Schedule 13D each disclaims beneficial ownership of all securities reported as beneficially owned by HFA in the Schedule 13D. None of the reporting persons on the Schedule 13D has any pecuniary interest in the securities reported as beneficially owned by HFA in the Schedule 13D, as such term is used for purposes of Section 16 of the Exchange Act. Neither the filing of the Schedule 13D nor any of its contents shall be deemed to constitute an admission that any of the reporting persons is the beneficial owner of the securities referred to in the Schedule 13D for purposes of Section 13(d) or Section 16 of the Exchange Act or for any other purpose. The business address for HFA and Harvest Fund Holdco L.P. is 100 W. Lancaster Avenue, Suite 200, Wayne, Pennsylvania 19087. The business address for the affiliated Blackstone entities is c/o The Blackstone Group L.P., 345 Park Avenue, New York, New York 10154. |
| |
(11)
| As reported on Schedule 13G filed with the SEC on February 13, 2017. Consists of Class A shares for which Capital World Investors is deemed to be the beneficial owner of as a result of Capital World Investors acting as investment adviser to various investment companies registered under Section 8 of the Investment Company Act of 1940. The business address for this person is 333 South Hope Street, Los Angeles, CA 90071. |
| |
(12)
| As reported on Schedule 13G filed with the SEC on February 14, 2017. Tortoise Capital Advisors, L.L.C. (“TCA”("TCA") acts as an investment advisor to certain investment companies registered under the Investment Company Act of 1940. TCA, by virtue of investment advisory agreements with these investment companies, has all investment and voting power over securities owned of record by these investment companies. However, despite their delegation of investment and voting power to TCA, these investment companies may be deemed to be the beneficial owner under Rule 13d-3 of the Act, of the securities they own of record because they have the right to acquire investment and voting power through termination of their investment advisory agreement with TCA. Thus, TCA has reported on the Schedule 13G that it shares voting power and dispositive power over the securities owned of record by these investment companies. TCA also acts as an investment adviser to certain managed accounts. Under contractual agreements with these managed account clients, TCA, with respect to the securities held in these client accounts, has investment and voting power with respect to certain of these client accounts, and has investment power but no voting power with respect to certain other of these client accounts. TCA has reported on the Schedule 13G that it shares voting and/or investment power over the securities held by these client managed accounts despite a delegation of voting and/or investment power to TCA because the clients have the right to acquire investment and voting power through termination of their agreements with TCA. TCA may be deemed the beneficial owner of the securities covered by the Schedule 13G under Rule 13d-3 of the Act that are held by its clients. The business address for this person is 11550 Ash Street, Suite 300, Leawood, Kansas 66211. |
| |
(13)(9)
| As reported on Schedule 13G filed with the SEC on February 1, 2019. Kayne Anderson Capital Advisors, L.P. is the general partner (or general partner of the general partner) of the limited partnerships and investment adviser to the other accounts. Richard A. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. Mr. Kayne is also a limited partner of each of the limited partnerships and a shareholder of the registered investment company. Kayne Anderson Capital Advisors, L.P. disclaims beneficial ownership of the shares reported, except those shares attributable to it by virtue of its general partner interests in the limited partnerships.Mr. Kayne disclaims beneficial ownership of the shares reported, |
except those shares held by him or attributable to him by virtue of his limited partnership interests in the limited partnerships, his indirect interest in the interest of Kayne Anderson Capital Advisors, L.P. in the limited partnerships, and his ownership of common stock of the registered investment company. The business address for these persons is 1800 Avenue of the Stars, Second Floor, Los Angeles California 90067.
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(10) | As reported on Schedule 13G filed with the SEC on April 10, 2017. The business address for this person is 4265 San Felipe, 8th Floor, Houston, TX 77027. |
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(11) | Consists of (i) 30,820,45829,416,692 Class B shares held of record by Tallgrass KC, (ii) 281,171 Class B shares held indirectly through the David G. Dehaemers, Jr. Revocable Trust, dated April 26, 2006 (the “Dehaemers Trust”"Dehaemers Trust"), for which Mr. Dehaemers serves as Trustee and (iii) 550,6301,806,319 Class A shares held indirectly through the Dehaemers Trust. Mr. Dehaemers has sole voting and dispositive power with respect to the shares held by Tallgrass KC; however, he disclaims beneficial ownership of those shares except to the extent of his pecuniary interest therein. |
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(14)(12)
| Consists of 2,807,531(i) 1,403,765 Class B shares held of record by Tallgrass KC.KC and (ii) 1,499,288 Class A shares held indirectly through the William R. Moler Revocable Trust U.T.A. dated August 27, 2013 ("Moler Trust"), for which Mr. Moler serves as Trustee. Mr. Moler indirectly holds a membership interest in Tallgrass KC through the William R. Moler Revocable Trust, U.T.A. dated August 27, 2013, for which Mr. Moler serves as Trustee, that includes 2,807,5311,403,765 TEGP Tracking Units. Pursuant to Tallgrass KC's limited liability company agreement, Mr. Moler is permitted to exchange his TEGP Tracking Units in Tallgrass KC for an equivalent number of Class A shares of TEGP.TGE. |
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(15)(13)
| Consists of (i) 2,183,636 Class B shares held of record by Tallgrass KC and (iii) 20,950(ii) 145,176 Class A shares held indirectly through the Brauchle Revocable Trust, under a trust agreement dated April 10, 2014, for which Mr. Brauchle serves as a Trustee (the "Brauchle Trust"). Mr. Brauchle indirectly holds a membership interest in Tallgrass KC through the Brauchle Trust, that includes 2,183,636 TEGP Tracking Units. Pursuant to Tallgrass KC's limited liability company agreement, Mr. Brauchle is permitted to exchange his TEGP Tracking Units in Tallgrass KC for an equivalent number of Class A shares of TGE. |
Trustee (the “Brauchle Trust”). Mr. Brauchle indirectly holds a membership interest in Tallgrass KC through the Brauchle Trust, that includes 2,183,636 TEGP Tracking Units. Pursuant to Tallgrass KC's limited liability company agreement, Mr. Brauchle is permitted to exchange his TEGP Tracking Units in Tallgrass KC for an equivalent number of Class A shares of TEGP.
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(16)(14)
| Consists of (i) 311,948 Class B shares held of record by Tallgrass KC.KC and (ii) 47,030 Class A shares held directly by Mr. Jones. Mr. Jones holds a membership interest in Tallgrass KC that includes 311,948 TEGP Tracking Units. Pursuant to Tallgrass KC's limited liability company agreement, Mr. Jones is permitted to exchange his TEGP Tracking Units in Tallgrass KC for an equivalent number of Class A shares of TEGP.TGE. |
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(17)(15)
| Consists of (i) 46,386,232 Class B shares held of record by Tallgrass Holdings, LLC and (ii) 235,000447,051 Class A shares held directly by John T. Raymond. The manager of Tallgrass Holdings, LLC is EMG Fund II Management, LP. EMG Fund II Management, LP’sLP's general partner is EMG Fund II Management, LLC. John T. Raymond, who serves as one of our directors, is the sole member of EMG Fund II Management, LLC and as such, has sole voting and dispositive power with respect to the shares held by Tallgrass Holdings, LLC; however, he disclaims beneficial ownership of those shares except to the extent of his indirect pecuniary interest therein. |
Ownership of Tallgrass Energy Partners, LP
The following table sets forth, as of February 9, 2018, the number of common units of TEP owned by each person who is known to us to beneficially own more than 5% of the common units of TEP (calculated in accordance with Rule 13d-3), each of the named executive officers and directors of our general partner and all directors and executive officers of our general partner as a group. Unless otherwise noted, the address of each beneficial owner named in the chart below is 4200 W. 115th Street, Suite 350, Leawood, Kansas 66211, Attn: General Counsel.
|
| | | | | | |
| Name of Beneficial Owner | | Common Units Beneficially Owned (1) | | Percentage of Common Units Beneficially Owned (2) |
Tallgrass Energy Holdings (3) | | 25,619,218 |
| | 35 | % |
Tortoise Capital Advisors, L.L.C. (4) | | 7,206,390 |
| | 9.84 | % |
Funds advised by ALPS Advisors, Inc. (5) | | 3,910,660 |
| | 5.34 | % |
Salient Capital Advisors, LLC (6) | | 3,700,374 |
| | 5.06 | % |
David G. Dehaemers, Jr. (7) | | 573,206 |
| | * |
|
William R. Moler (8) | | 47,761 |
| | * |
|
Gary J. Brauchle (9) | | 62,113 |
| | * |
|
| Christopher R. Jones | | 20,615 |
| | * |
|
| Gary D. Watkins | | 17,893 |
| | * |
|
| Frank J. Loverro | | — |
| | — |
|
| Stanley de J. Osborne | | — |
| | — |
|
| Jeffrey A. Ball | | 20,000 |
| | * |
|
| John T. Raymond | | 100,000 |
| | * |
|
| Roy N. Cook | | 52,000 |
| | * |
|
| Terrance D. Towner | | 25,000 |
| | * |
|
| Jeffrey R. Armstrong | | 3,000 |
| | * |
|
| All directors and executive officers as a group (12 persons) | | 921,588 |
| | 1.26 | % |
| |
(1)
| This column reflects the number of TEP common units held of record or owned through a bank, broker or other nominee. The common units of TEP presented as being beneficially owned by our general partner's directors and executive officers do not include the TEP common units held by Tallgrass Equity that may be attributable to such directors and officers based on their indirect ownership of Tallgrass Equity. |
| |
(2)
| Based on 73,199,753 TEP common units outstanding as of February 9, 2018. |
| |
(3)
| Consists of common units held of record by Tallgrass Equity. Tallgrass Energy Holdings is the sole member of TEGP Management, LLC, TEGP's general partner. TEGP is the managing member of Tallgrass Equity. As such, Tallgrass Energy Holdings has the sole voting and dispositive power with respect to the common units owned by Tallgrass Equity. Tallgrass Energy Holdings is controlled by its board of directors, which currently consists of the following: David G. Dehaemers, Jr., |
William R. Moler, Frank J. Loverro, Stanley de J. Osborne, Jeffrey A. Ball and John T. Raymond. Each of the members of the board of directors of Tallgrass Energy Holdings may be deemed to beneficially own the common units owned by Tallgrass Equity; however, each disclaims beneficial ownership.
| |
(4)
| As reported on Schedule 13G filed with the SEC on July 7, 2017. Tortoise Capital Advisors, L.L.C. (“TCA”) acts as an investment advisor to certain investment companies registered under the Investment Company Act of 1940. TCA, by virtue of investment advisory agreements with these investment companies, has all investment and voting power over securities owned of record by these investment companies. However, despite their delegation of investment and voting power to TCA, these investment companies may be deemed to be the beneficial owner under Rule 13d-3 of the Act, of the securities they own of record because they have the right to acquire investment and voting power through termination of their investment advisory agreement with TCA. Thus, TCA has reported on the Schedule 13G that it shares voting power and dispositive power over the securities owned of record by these investment companies. TCA also acts as an investment adviser to certain managed accounts. Under contractual agreements with these managed account clients, TCA, with respect to the securities held in these client accounts, has investment and voting power with respect to certain of these client accounts, and has investment power but no voting power with respect to certain other of these client accounts. TCA has reported on the Schedule 13G that it shares voting and/or investment power over the securities held by these client managed accounts despite a delegation of voting and/or investment power to TCA because the clients have the right to acquire investment and voting power through termination of their agreements with TCA. TCA may be deemed the beneficial owner of the securities covered by the Schedule 13G under Rule 13d-3 of the Act that are held by its clients. The business address for this person is 11550 Ash Street, Suite 300, Leawood, Kansas 66211. |
| |
(5)
| As reported on Schedule 13G filed with the SEC on February 6, 2018. ALPS Advisors, Inc. (“AAI”), an investment adviser registered under Section 203 of the Investment Advisors Act of 1940, furnishes investment advice to investment companies registered under the Investment Company Act of 1940 (collectively referred to as the “AAI Funds”). In its role as investment advisor, AAI has voting and/or investment power over the securities of TEP that are owned by the AAI Funds, and may be deemed to be the beneficial owner of the shares of TEP held by the AAI Funds. However, all securities reported in this schedule are owned by the AAI Funds. AAI disclaims beneficial ownership of such securities. In addition, the filing of the Schedule 13G shall not be construed as an admission that the reporting person or any of its affiliates is the beneficial owner of any securities covered by the Schedule 13G for any other purposes than Section 13(d) of the Securities Exchange Act of 1934. Alerian MLP ETF, which beneficially owns 3,887,310 common units, is an investment company registered under the Investment Company Act of 1940 and is one of the AAI Funds to which AAI provides investment advice. The business address for AAI and Alerian MLP ETF is 1290 Broadway, Suite 110, Denver, Colorado 80203. |
| |
(6)
| As reported on Schedule 13G filed with the SEC on January 18, 2018. Consists of common units of record by Salient Capital Advisors, LLC. The business address for this person is 4265 San Felipe, 8th Floor, Houston, TX 77027. |
| |
(7)
| David G. Dehaemers, Jr. indirectly owns the common units through the David G. Dehaemers, Jr. Revocable Trust, dated April 26, 2006, for which Mr. Dehaemers serves as Trustee. |
| |
(8)
| William R. Moler indirectly owns the common units through the William R. Moler Revocable Trust, under a trust agreement dated August 29, 2013, for which Mr. Moler serves as Trustee. |
| |
(9)
| Gary J. Brauchle indirectly owns the common units through the Brauchle Revocable Trust, under trust agreement dated April 10, 2014, for which Mr. Brauchle serves as a Trustee. |
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information about our Class A shares that may be issued under equity compensation plans as of December 31, 2017:2018:
| | | Plan Category | (a) Number of securities to be issued upon exercise of outstanding options, warrants and rights | | (b) Weighted average grant date fair value of outstanding options, warrants and rights | | (c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | (a) Number of securities to be issued upon exercise of outstanding options, warrants and rights | | (b) Weighted average grant date fair value of outstanding options, warrants and rights | | (c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) |
Equity compensation plans approved by security holders (1) | 224,998 |
| | $ | 25.91 |
| | 2,909,589 |
| 3,049,644 |
| (1) | $ | 18.25 |
| | 17,735,121 |
|
Equity compensation plans not approved by security holders (2) | — |
| | $ | — |
| | — |
| — |
| | $ | — |
| | — |
|
| Total | 224,998 |
| | $ | 25.91 |
| | 2,909,589 |
| 3,049,644 |
| | $ | 18.25 |
| | 17,735,121 |
|
| |
(1) | Amounts shown represent equity participation share awards outstanding under the TEGP LTIPPlans as of December 31, 2017.2018. The outstanding awards will be settled in Class A shares pursuant to the terms of the award agreements and are not subject to an exercise price. |
| |
(2) | There are no equity compensation plans in place pursuant to which Class A shares may be issued except for the TEGP LTIP.Plans. |
For additional information regarding the LTIP,Plans, see Note 16 – Equity-Based Compensation to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data of this Annual Report.
Item 13. Certain Relationships and Related Transactions, and Director Independence
We are a Delaware limited partnership formed in February 2015. Although we were formed as a limited partnership, we have elected to be taxed as a corporation for U.S. federal income tax purposes.
Our sole asset is Tallgrass Equity units representing 31.43% of the membership interests in Tallgrass Equity, which directly owns (i) 25,619,218 TEP common units, representing an approximate 34.60% limited partner interest in TEP as of February 13, 2018, (ii) all of the membership interests of TEP GP, and (iii) a 25.01% membership interest in Rockies Express. TEP GP owns all the TEP IDRs and 834,391 general partner units, representing an approximate 1.13% general partner interest in TEP as of February 13, 2018.
Before the completion of the TEGP IPO in May 2015, Tallgrass Equity, formerly known as Tallgrass GP Holdings, LLC, was a privately held limited liability company that owned the general partners of Tallgrass Development and TEP. In connection with the completion of the TEGP IPO, the following transactions were effected:
Tallgrass Equity distributed its interests in Tallgrass Energy Holdings and Tallgrass Energy Holdings distributed its existing limited partner interest in TEGP, respectively, to certain of the Exchange Right Holders. Tallgrass Energy Holdings is the owner of our general partner and is the general partner of Tallgrass Development;
We issued 47,725,000 Class A shares to the public for approximately $1.3 billion of net proceeds;
The limited partner interests in TEGP held by certain of the Exchange Right Holders were converted into 109,504,440 Class B shares;
Tallgrass Equity issued a 30.35% membership interest in Tallgrass Equity to us in exchange for the $1.3 billion net proceeds from the issuance of our Class A shares to the public and the limited liability company agreement of Tallgrass Equity was amended to provide that we are the managing member of Tallgrass Equity; and
Tallgrass Equity entered into a $150 million revolving credit facility and borrowed $150 million thereunder, and used the aggregate proceeds from these borrowings together with the net proceeds from the TEGP IPO that Tallgrass Equity received from us, to purchase 20 million TEP common units from Tallgrass Development at $47.68 per TEP common unit and pay offering expenses and other transaction costs. Tallgrass Equity distributed the remaining proceeds to certain of the Exchange Right Holders.
Limited Liability Company Agreement of Tallgrass Equity
As of February 8, 2019, we own Tallgrass Equity units representing 55.79% of the membership interests in Tallgrass Equity. In accordance with the Tallgrass Equity limited liability company agreement, the net profits and net losses of Tallgrass Equity will generally be allocated to the holders of Tallgrass Equity units on a pro rata basis in accordance with their relative number of Tallgrass Equity units held. Accordingly, net profits and losses of Tallgrass Equity are currently allocated 31.43%55.79% to us and 68.57%44.21% to the Exchange Right Holders.Holders with respect to their Tallgrass Equity units. If we cause a distribution to be made, such distribution will be made to the holders of Tallgrass Equity units on a pro rata basis in accordance with their relative number of Tallgrass Equity units held.
For purposes of any transfer or exchange of Tallgrass Equity units initially owned by the Exchange Right Holders and our Class B shares, the Tallgrass Equity limited liability company agreement and our partnership agreement contain provisions linking each such Tallgrass Equity unit with one of our Class B shares. Our Class B shares cannot be transferred without transferring an equal number of Tallgrass Equity units and vice versa.
The Exchange Right Holders and any permitted transferees of their Tallgrass Equity units each have the right to exchange all or a portion of their Tallgrass Equity units into Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged. The above Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares are transferred by the exercising party to us.
The above mechanisms are subject to customary conversion rate adjustments for equity splits, equity dividends and reclassifications.
In addition, pursuant to our partnership agreement and the Tallgrass Equity limited liability company agreement, our capital structure and the capital structure of Tallgrass Equity generally replicate one another and provide for customary antidilution mechanisms in order to maintain the one-for-one exchange ratio between the Tallgrass Equity units and Class B shares, on the one hand, and our Class A shares, on the other hand.
TGE Omnibus Agreement
In connection with the closing of the TEGPTGE IPO, we, our general partner, Tallgrass Equity and Tallgrass Energy Holdings entered into the TEGPTGE Omnibus Agreement, that addresses the following matters:
Tallgrass Equity's obligation to reimburse Tallgrass Energy Holdings and its affiliates for expenses incurred (i) on our behalf, (ii) on behalf of our general partner and (iii) for any other purposes related to our business and activities or those of our general partner, including our public company expenses and general and administrative expenses; and
Our use of the names "TEP" andname "Tallgrass" and any associated or related marks.
Reimbursement of General and Administrative Expenses.
Pursuant to the TEGPTGE Omnibus Agreement, Tallgrass Energy Holdings performs,may perform, or cause its affiliates to perform, centralized general and administrative services for TEGP,TGE, such as accounting, audit, business development, corporate record keeping, treasury services (including cash management), real property/land, legal, operations/engineering, investor relations, risk management, commercial/marketing, information technology, insurance, government relations/compliance, tax, payroll, human resources and environmental, health and safety. In exchange, Tallgrass Equity reimburses Tallgrass Energy Holdings and its affiliates for their expenses to the extent incurred on our behalf in providing these services. All reimbursements to our general partner, Tallgrass Energy Holdings and their respective affiliates by Tallgrass Equity will proportionally reduce cash distributions by Tallgrass Equity to its members, which in turn will reduce the amount of cash we distribute to our Class A shareholders. The TEGP Omnibus Agreement further provides that
Effective January 1, 2018, these costs are incurred by Tallgrass Equity will reimburse Tallgrass Energy Holdings and its affiliates for TEGP's allocable portion of the premiums on any insurance policies covering TEGP's assets.
directly. For the years ended December 31, 2017 2016 and 2015,2016, Tallgrass Equity reimbursed Tallgrass Management and its affiliates $2.0 million $2.0 million, and $1.3 million, respectively, pursuant to the TEGPTGE Omnibus Agreement.
TEP Omnibus Agreement
In May 2013, TEP entered into an Omnibus Agreement with Tallgrass Equity (as successor to Tallgrass Development), Tallgrass Energy Holdings, and TEP GP, which we refer to as the TEP Omnibus Agreement, that governs TEP's relationship with them regarding the following matters:
the provision by Tallgrass Energy Holdings to TEP of certain administrative services and TEP's agreement to reimburse it for such services;
Amendment and Termination.
The TEGP Omnibus Agreement can be amendedthe provision by written agreement of all parties to the TEGP Omnibus Agreement. However, we may not agree to any amendment or modification that would, in the determination of our general partner, be adverse in any material respect to the holders of our Class A shares without the prior approval of the conflicts committee. In the event of (i) a "change in control" (as defined in the TEGP Omnibus Agreement) of us or (ii) the removal of TEGP Management, LLC as our general partner in circumstances where "cause" (as defined in our partnership agreement) does not exist and the Class A shares and Class B shares held by our general partner and its affiliates were not voted in favorTallgrass Energy Holdings of such removal,employees as may be necessary to operate and manage TEP's business, and TEP's agreement to reimburse it for the TEGP Omnibus Agreement will be terminable by Holdings,expenses associated with such employees;
certain indemnification obligations; and we will have a 90-day transition period to cease our
TEP's use of the name "Tallgrass" and related marks.
Pursuant to the TEP Omnibus Agreement, Tallgrass Energy Holdings may perform, or causes its affiliates to perform, centralized corporate, general and administrative services for TEP, such as legal, corporate record keeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. In exchange, TEP reimburses Tallgrass Energy Holdings and its affiliates for their expenses to the extent incurred on TEP's behalf in providing these services.
Exchange Right
The Exchange Right Holders and any permitted transferees of their Tallgrass Equity units each have the right to exchange all or a portion of their Tallgrass Equity units into Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares are transferred by the exercising party to us. Upon such exchange, we will cancel the Class B shares received from the exercising party.
For purposes of any transfer or exchange of Tallgrass Equity units initially owned by the Exchange Right Holders and our Class B shares, the Tallgrass Equity limited liability company agreement and our partnership agreement contain provisions effectively linking one Tallgrass Equity unit with one of our Class B shares. Class B shares cannot be transferred without transferring an equal number of Tallgrass Equity units and vice versa. In connection with the Secondary Offering completed in November 2016, the participating Exchange Right Holders exercised their Exchange Right with respect to a total of 10,350,000 Tallgrass Equity units and an equal number of Class B shares. In addition, during the year ended December 31, 2018, 2,821,332 Class A shares were issued and an equal number of Class B shares were cancelled as a result of the exercise of the Exchange Right.
The above mechanisms are subject to customary conversion rate adjustments for equity splits, equity dividends and reclassifications.
Registration Rights Agreement
In connection with the closing of the TEGPTGE IPO, we entered into a shareholder and registration rights agreement, which we refer to as the registration rights agreement, with certain of the Exchange Right Holders. Pursuant to the registration rights agreement, we agreed to register the resale of 109,504,440 Class A shares issuable upon exercise of the Exchange Right or the Registrable Securities, held by the Exchange Right Holders or any of their permitted transferees to the registration rights agreement under certain circumstances. In addition, we agreed to register the 27,554,785 Class A shares issuable upon the exercise of the Exchange Right with respect to 27,554,785 Tallgrass Equity units and Class B shares, respectively, issued in connection with the acquisition of the 25.01% membership interest in Rockies Express and the 5,619,218 additional TEP common units acquired by Tallgrass Equity in February 2018. We refer to such Class A shares issuable upon exercise of the Exchange Right as the Registrable Securities.
The Registrable Securities were subsequentlyIn accordance with our obligations under the registration rights agreement, we have registered the resale of 125,291,659 Class A shares issuable upon exercise of the Exchange Right pursuant to our Form S-3/AS-3 (File No. 333-210976)333-225382) filed with the SEC on August 8, 2016,June 1, 2018, which became effective August 10, 2016.June 13, 2018. We are required to maintain the effectiveness of such registration statement until the date on which all Registrable Securities covered by the shelf registration statement have been sold thereunder in accordance with the plan and method of distribution disclosed in the annual report included in the shelf registration statement, or otherwise cease to be Registrable Securities under the registration rights agreement.
We have also agreed to register the 27,554,785 Class A shares issuable upon the exercise of the Exchange Right with respect to the 27,554,785 units and Class B Shares, respectively, issued in connection with the acquisition of the 25.01% membership interest in Rockies Express and the 5,619,218 additional TEP common units acquired by Tallgrass Equity on February 7, 2018.
Demand and Piggyback Rights
The Exchange Right Holders have the right to require that we register their Registrable Securities and/or facilitate an underwritten offering of their Registrable Securities. There is no aggregate limit on the number of such demand requests; however, the demand rights of these holders are subject to a number of size, frequency and other limitations. In November 2016, EMG and Kelso exercised this "demand" registration right under the registration rights agreement and together with the other participating Exchange Right Holders, sold 10,350,000 Class A Shares in the Secondary Offering that closed on November 22, 2016. For a period of 120 days following the closing of the Secondary Offering, the participating Exchange Right Holders arewere not permitted to exchange any of their Tallgrass Equity units pursuant to the terms of the underwriting agreement.
In the event we propose to conduct an underwritten offering of Registrable Securities, then the holders of Registrable Securities will generally have customary rights to participate in such offering, subject to customary offering size limitations and related allocation provisions and other limitations. Similarly, in the event that eligible holders demand that we conduct an underwritten offering of their Registrable Securities, then we will generally have customary rights to participate in such offering, subject to customary offering size limitations and related allocation provisions and other limitations.
Delay Rights
We will not be required to comply with any demand request, and may suspend the holders' ability to use any shelf registration statement, following our delivery of written notice to the holders of customary blackout periods and deferral events.
Expenses
The holders of Registrable Securities will pay certain selling expenses, including any underwriters' discounts and commissions. We will generally cause Tallgrass Equity to pay all other registration expenses in connection with our obligations under the registration rights agreement.
Pursuant to the terms of the registration rights agreement discussed above, the Company was obligated to cause Tallgrass Equity to pay all fees and expenses related to the Secondary Offering, excluding certain selling expenses, including any underwriters' discounts and commissions. The Company did not receive any proceeds from the sale of Class A shares in the Secondary Offering. The total expenses paid by Tallgrass Equity in connection with the Secondary Offering, and associated filings, were approximately $1.0 million.
Referral FeeOther Transactions
One of the underwriters of the TEGP IPO, Wells Fargo Securities, LLC ("WFS")In January 2018, we entered into an agreement to acquire a Referral Agreement51% membership interest in the Pawnee, Colorado crude oil terminal ("Pawnee Terminal") from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately $30.6 million. The transaction closed on April 1, 2018. Kelso owns an indirect equity interest in Zenith Energy Terminals Holdings, LLC.
Effective February 1, 2018, TEP acquired the remaining 2% membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from Tallgrass Development for cash consideration of approximately $60 million, bringing its retail brokerage affiliate, Wells Fargo Advisors, LLC ("WFA"), pursuantaggregate membership interest in Pony Express to which WFS agreed to pay a referral fee of up to $600,000 to WFA, up to 50% of which may be directed by WFA to Timothy Dehaemers, a financial adviser employed by WFA who is also the brother of our President and Chief Executive Officer, for his introduction and referral of WFS to TEGP. The referral fee paid from WFS to WFA was paid solely from the underwriting commissions received by WFS and did not in any way increase the total fees paid by TEGP to WFS in connection with the TEGP IPO.
Other Transactions100%.
On February 7, 2018, Tallgrass Development merged into Tallgrass Development Holdings, a wholly-owned subsidiary of Tallgrass Equity, and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TEGPTGE and Tallgrass Equity issued 27,554,785 unregistered TEGPTGE Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of Tallgrass Development.
In August 2018, we entered into an agreement with Silver Creek to expand the Iron Horse joint venture through the contribution by us and Silver Creek of cash and additional Powder River Basin assets. These additional contributions closed in January 2019. The expanded joint venture operates under the name Powder River Gateway, LLC, and owns the Iron Horse Pipeline, the PRE Pipeline, a 70-mile crude oil pipeline that transports crude oil from the Powder River Basin to Guernsey, Wyoming, and crude oil terminal facilities in Guernsey, Wyoming. Effective January 1, 2019, we own a 51% membership interest in Powder River Gateway and continue to operate the joint venture, while Silver Creek owns a 49% membership interest. EMG owns an indirect equity interest in Silver Creek.
Procedures for Review, Approval or Ratification of Transactions with Related Persons
The board of directors of our general partner has adopted a related party transactions policy (the "Policy"), which supplements the conflict of interest provisions in our code of business conduct and ethics. According to the Policy, a "Related Party Transaction" is an actual or proposed transaction, arrangement or relationship (or any series of similar transactions, arrangements or relationships) in which (a) the Partnership, our general partner or Tallgrass Equity (collectively, the "Partnership Group") was, is or will be a participant, (b) the amount involved exceeds $120,000, and (c) in which any Related Party had, has or will have a direct or indirect material interest. The Policy's definition of a "Related Party" is in line with the definition set forth in the instructions to Item 404(a) of Regulation S-K promulgated by the SEC. Transactions resolved under the conflicts provisions of our partnership agreement are not required to be reviewed or approved under the policy.
Under the Policy, the General Counsel and Chief Financial Officer or Chief Accounting Officer are responsible for determining whether a Related Party Transaction requires the approval of the Audit Committee. The Audit Committee is responsible for evaluating and assessing a proposed transaction based on the relevant facts and circumstances, including comparing the terms of the proposed transaction to the terms available to unrelated third parties. The Audit Committee shall approve only those Related Party Transactions that are either (i) on terms no less favorable to the Partnership Group than those
generally being provided to or available from unrelated third parties or (ii) are fair and reasonable to the Partnership Group, taking into account the totality of the relationships between the parties involved.
If the General Counsel determines it is impractical or undesirable to wait until an Audit Committee meeting to consummate a Related Party Transaction, the chairman of the Audit Committee may review and approve the Related Party Transaction in accordance with the procedures set forth in the Policy. However, any such approval (and its rationale) must be reported to the Audit Committee at the next regularly scheduled meeting. A Related Party Transaction entered into without pre-approval of the Audit Committee shall not be deemed to violate the Policy, or be invalid or unenforceable, so long as the transaction is brought to the Audit Committee as promptly as reasonably practical after it is entered into and is subsequently ratified by the Audit Committee. If the Audit Committee determines not to ratify a Related Party Transaction that has been commenced without approval, the Audit Committee may direct the immediate discontinuation or rescission of the transaction, or modify the transaction to make it acceptable for ratification.
Director Independence
The information required by Item 407(a) orof Regulation S-K is included in Item 10.—Directors, Executive Officers and Corporate Governance.
Related Party Transactions of TEP
Distributions and Payments to TEP GP and Its Affiliates
The following information summarizes the distributions and payments made or to be made by TEP to TEP GP and its affiliates in connection with TEP's formation, ongoing operation and any liquidation of TEP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.
Distributions of available cash to TEP GP and its affiliates. TEP will generally make distributions of available cash to common unitholders pro rata (including Tallgrass Equity as the holder of an aggregate of 25,619,218 TEP common units) and to TEP GP as follows: (1) an approximate 1.13% general partner interest with respect to its general partner units and (2) as distributions of available cash exceed the MQD and other higher target levels specified in TEP's partnership agreement, increasing percentages of distributions with respect to its IDRs, up to 48% of the distributions above the highest target level. Assuming TEP has sufficient available cash to pay the full MQD on all of its outstanding units for four quarters, TEP GP and its affiliates would receive an annual distribution of approximately $1.0 million on their general partner units and approximately $30.4 million on their common units based on their ownership as of February 8, 2018. TEP has distributed available cash in excess of the MQD since the quarterly period ending September 30, 2013.
Payments to TEP GP and its affiliates. Neither TEP GP nor Tallgrass Energy Holdings and its affiliates receive a management fee or other compensation for managing TEP. TEP GP and Tallgrass Energy Holdings and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on TEP's behalf pursuant to its partnership agreement and the TEP Omnibus Agreement (defined below). Neither TEP's partnership agreement nor the TEP Omnibus Agreement limit the amount of expenses for which TEP GP or Tallgrass Energy Holdings and its affiliates may be reimbursed. TEP's partnership agreement provides that TEP GP will determine in good faith the expenses that are allocable to TEP.
Withdrawal or removal of TEP GP. If TEP GP withdraws or is removed, its general partner interest and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage. Upon TEP's liquidation, the partners, including TEP GP, will be entitled to receive liquidating distributions according to their particular capital account balances, as further detailed in TEP's limited partnership agreement.
Omnibus Agreement
Upon the closing of the TEP IPO, TEP entered into an Omnibus Agreement with Tallgrass Development Holdings (as successor to Tallgrass Development), Tallgrass Energy Holdings, and TEP GP, which we refer to as the TEP Omnibus Agreement, that governs TEP's relationship with them regarding the following matters:
the provision by Tallgrass Energy Holdings to TEP of certain administrative services and TEP's agreement to reimburse it for such services;
the provision by Tallgrass Energy Holdings of such employees as may be necessary to operate and manage TEP's business, and TEP's agreement to reimburse it for the expenses associated with such employees;
certain indemnification obligations;
TEP's use of the name "Tallgrass" and related marks; and
TEP's right of first offer to acquire certain assets owned by Tallgrass Development Holdings, which currently only includes the 25.01% membership interest in Rockies Express, if Tallgrass Development Holdings decides to sell such assets to a non-affiliate.
Reimbursement of General and Administrative Expenses. Pursuant to the TEP Omnibus Agreement, Tallgrass Energy Holdings performs, or causes its affiliates to perform, centralized corporate, general and administrative services for TEP, such as legal, corporate record keeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. In exchange, TEP reimburse it for expenses incurred in providing these services. The reimbursements to TEP GP and Tallgrass Energy Holdings and its affiliates are made prior to cash distributions to TEP's common unitholders. The TEP Omnibus Agreement further provides that TEP will reimburse Tallgrass Energy Holdings and its affiliates for TEP's allocable portion of the premiums on any insurance policies covering TEP's assets. TEP anticipates reimbursement to Tallgrass Energy Holdings and its affiliates will vary with the size and scale of TEP's operations, among other factors.
For the years ended December 31, 2016, 2015 and 2014, TEP reimbursed Tallgrass Energy Holdings $41.9 million, $40.9 million, and $37.9 million, respectively, pursuant to the TEP Omnibus Agreement.
Indemnification. Under the terms of the TEP Omnibus Agreement, Tallgrass Development Holdings is required to indemnify TEP from liabilities arising out of any federal, state and local income tax liabilities attributable to the ownership and operation of the assets contributed to us in connection with TEP's IPO until 60 days after the applicable statute of limitations. Tallgrass Development Holdings also agreed to use commercially reasonable efforts to obtain indemnification from Kinder Morgan for losses suffered or incurred by TEP with respect to the assets contributed to TEP as part of the TEP IPO, to the extent that Kinder Morgan is obligated to indemnify Tallgrass Development Holdings under the purchase and sale agreement pursuant to which Tallgrass Development Holdings acquired the contributed assets and remit any proceeds received from Kinder Morgan pursuant to such indemnification obligations to TEP. Kinder Morgan's indemnity obligations under the Kinder Morgan purchase agreement generally survived through February 13, 2014, although certain specified indemnities last for longer periods of time. Under the TEP Omnibus Agreement, TEP has agreed to indemnify Tallgrass Development Holdings for events and conditions associated with the operation of the contributed assets that occur on or after the closing of TEP's IPO.
Right of First Offer. Under the terms of the TEP Omnibus Agreement, Tallgrass Development Holdings has granted TEP a right of first offer, for so long as Tallgrass Development Holdings or its affiliates, individually or as part of a group, control TEP GP, on (i) the 25.01% membership interest in Rockies Express owned by Tallgrass Development Holdings and (ii) any assets that are hereafter developed, constructed or acquired by Tallgrass Development Holdings or its subsidiaries (excluding TEP and its subsidiaries) for the purpose of processing natural gas in Natrona, Converse or Campbell counties in Wyoming, which we refer to collectively as the ROFO Assets. If Tallgrass Development Holdings or any of its affiliates decide to attempt to sell (other than to an affiliate of Tallgrass Development Holdings, excluding TEP and its subsidiaries) a ROFO Asset, Tallgrass Development Holdings or its affiliate will notify TEP in advance and, prior to selling such ROFO Asset to a third party, will negotiate with TEP exclusively and in good faith for a period of 45 days in order to give TEP an opportunity to enter into definitive documentation for the purchase and sale of such ROFO Asset on terms that are mutually acceptable to Tallgrass Development Holdings or its affiliate and TEP. If TEP and Tallgrass Development Holdings or its affiliate have not entered into a letter of intent or a definitive purchase and sale agreement with respect to such ROFO Asset within such 45-day period, Tallgrass Development Holdings or its affiliate will have the right to sell such ROFO Asset to a third party following the expiration of such 45-day period on any terms that are acceptable to Tallgrass Development Holdings or its affiliate and such third party. TEP's decision to acquire or not to acquire a ROFO Asset pursuant to this right will require the approval of the conflicts committee of the board of directors of TEP GP.
Amendment and Termination. The TEP Omnibus Agreement can be amended by written agreement of all parties to the agreement. However, TEP may not agree to any amendment or modification that would, in the determination of TEP GP, be adverse in any material respect to the holders of TEP's common units without the prior approval of the conflicts committee. In the event of (i) a "change in control" (as defined in the TEP Omnibus Agreement) of the partnership or (ii) the removal of Tallgrass MLP GP, LLC as TEP's general partner in circumstances where "cause" (as defined in TEP's partnership agreement) does not exist and the common units held by TEP GP and its affiliates were not voted in favor of such removal, the TEP Omnibus Agreement (other than the indemnification and reimbursement provisions therein) will be terminable by Tallgrass Development Holdings, and TEP will have a 90-day transition period to cease TEP's use of the name "Tallgrass" and related marks.
Acquisitions from Tallgrass Development
Effective September 1, 2014, TEP acquired a 33.3% membership interest in Pony Express, from Tallgrass Development for total consideration of approximately $600 million pursuant to that certain Contribution and Transfer Agreement by and between Tallgrass Development, Pony Express, Tallgrass Operations, LLC ("Tallgrass Operations") and TEP. At closing, TEP entered into a Second Amended and Restated Limited Liability Company Agreement of Pony Express effective September 1, 2014 with Tallgrass Development and Pony Express, which provided TEP a minimum quarterly preference payment of $16.65 million through the quarter ending September 30, 2015 with distributions thereafter shared in accordance with the terms of the Second Amended and Restated Limited Liability Company Agreement. In connection with the transaction, Pony Express entered into a Cash Management Agreement effective August 27, 2014, under which cash balances were swept daily and recorded as loans from Pony Express to Tallgrass Development. $270 million of the total consideration was subsequently swept to Tallgrass Development and was recorded as a related party loan which accrued interest at Tallgrass Development's incremental borrowing rate. As of September 1, 2014, balances lent to Tallgrass Development under the cash management agreement were classified as related party receivables on TEP's consolidated balance sheet and were cash settled.
Effective March 1, 2015, TEP acquired an additional 33.3% membership interest in Pony Express from Tallgrass Development for total consideration of approximately $700 million pursuant to that certain Purchase and Sale Agreement by and between Tallgrass Development, Tallgrass Operations and TEP. At closing, TEP, Tallgrass Development and Pony Express entered into a Third Amended and Restated Limited Liability Company Agreement of Pony Express effective March 1, 2015, which provides TEP a minimum quarterly preference payment of $36.65 million through the quarter ending December 31, 2015 with distributions thereafter shared in accordance with the terms of the Third Amended and Restated Limited Liability Company Agreement.
Effective January 1, 2016, TEP acquired an additional 31.3% membership interest in Pony Express from Tallgrass Development for total cash consideration of approximately $475 million and the issuance of 6,518,000 TEP common units, which TEP common units are subject to a call option granted by Tallgrass Operations in favor of TEP, pursuant to that certain Contribution and Transfer Agreement by and between Tallgrass Development, Tallgrass Operations and TEP. In July 2016, October 2016 and on February 1, 2017, TEP exercised the call option granted by Tallgrass Development covering 3,563,146, 1,251,760 and 1,703,094 common units, respectively. These common units were deemed canceled upon the exercise of the call option and as of such exercise date were no longer issued and outstanding. As of February 13, 2018, no common units remained subject to the call option.
On May 6, 2016, Tallgrass Development assigned us its right to purchase a 25% membership interest in Rockies Express from a unit of Sempra U.S. Gas and Power ("Sempra") pursuant to the purchase agreement originally entered into between Tallgrass Development's wholly-owned subsidiary and Sempra in March 2016. Subsequently on May 6, 2016, we closed the purchase of a 25% membership interest in Rockies Express from Sempra pursuant to the purchase agreement for cash consideration of approximately $436.0 million, after making the adjustments to the purchase price required by the purchase agreement.
Effective January 1, 2017, TEP acquired 100% of the issued and outstanding membership interests in Terminals and 100% of the issued and outstanding membership interests in NatGas from TD for total cash consideration of $140 million, pursuant to that certain Purchase and Sale Agreement by and between Tallgrass Development, Tallgrass Operations and TEP.
Following an offer received from Tallgrass Development with respect to common units owned by Tallgrass Development not subject to the call option, we repurchased 736,262 common units from Tallgrass Development at an aggregate price of approximately $35.3 million, or $47.99 per common unit, on February 1, 2017, which was approved by the conflicts committee of the board of directors of our general partner.
Effective March 31, 2017, TEP acquired an additional 24.99% membership interests in Rockies Express from Tallgrass Development for cash consideration of $400 million, pursuant to that certain Purchase and Sale Agreement by and between us and Rockies Express Holdings, LLC, a wholly-owned subsidiary of Tallgrass Development, and for certain limited purposes, Tallgrass Development.
Effective February 1, 2018, TEP acquired the remaining 2% membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from Tallgrass Development for cash consideration of approximately $60 million, bringing its aggregate membership interest in Pony Express to 100%.
Competition
Under TEP's partnership agreement, Tallgrass Energy Holdings and its affiliates are expressly permitted to compete with TEP. Tallgrass Energy Holdings and any of its affiliates, including EMG and Kelso, may acquire, construct or dispose of additional transportation, storage, terminalling and processing or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.
Contracts with Affiliates
Pony Express is party to a terminal lease and operating agreement with Tallgrass Sterling Terminal, LLC ("Sterling Terminal"), which was an indirect wholly-owned subsidiary of Tallgrass Development prior to TEP's acquisition in January 2017. Pursuant to such agreement, Pony Express leases approximately 1.3 million barrels of crude oil storage and Sterling Terminal provides associated crude oil terminalling services. Pony Express pays Sterling Terminal a fixed monthly charge of $942,000 per month, plus a volumetric charge of $0.07 per barrel for each barrel delivered to the terminal in excess of 9,424,000 per month, subject in both cases to an annual 2% escalator. The initial five-year term of the agreement expires in May 2020. Pony Express made lease payments to Sterling Terminal of $11.7 million, $11.5 million and $7.6 million during the years ended December 31, 2017, 2016 and 2015, respectively, pursuant to the agreement.
In May 2016, Pony Express entered into an electric service master meter agreement with Terminals, which was an indirect wholly-owned subsidiary of Tallgrass Development prior to our acquisition in January 2017. Pursuant to such agreement, Terminals receives electric power from Pony Express at the Sterling Terminal. Terminals pays Pony Express for its usage based
on the charges incurred by Pony Express from its third-party electric service provider. Terminals made payments to Pony Express under the agreement of $0.4 million during the years ended December 31, 2017 and 2016.
Other Transactions
On January 2, 2018, Terminals entered into an agreement to acquire a 51% membership interest in the Pawnee Terminal from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately $31 million, subject to working capital adjustments. Terminals expects the transaction to close in the first quarter of 2018, subject to certain closing conditions. Jeff Armstrong, who is on the board of directors of TEP GP, is the Chief Executive Officer of Zenith Energy Terminals Holdings, LLC. Kelso owns an indirect equity interest in Zenith Energy Terminals Holdings, LLC.
Item 14. Principal Accounting Fees and Services
We have engaged PricewaterhouseCoopers LLP as our independent registered public accounting firm. The following table summarizes fees we were billed by PricewaterhouseCoopers LLP (or included in TD's general and administrative expense allocation to us) for independent auditing, tax and related services for each of the last two fiscal years:
| | | | | Year Ended December 31, | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2018 | | 2017 |
| | | (in thousands) | | (in thousands) |
Audit fees (1) | | $ | 1,843 |
| | $ | 2,040 |
| | $ | 1,935 |
| | $ | 1,843 |
|
Audit related fees (2) | | — |
| | — |
| | — |
| | — |
|
Tax fees (3) | | 611 |
| | 454 |
| | 520 |
| | 611 |
|
| Total | | $ | 2,454 |
| | $ | 2,494 |
| | $ | 2,455 |
| | $ | 2,454 |
|
| |
(1) | Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the integrated audit of our annual financial statements and internal control over financial reporting, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this Annual Report. |
| |
(2) | Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews of our financial statements and are not reported under audit fees. |
| |
(3) | Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning. |
All services provided by our independent registered public accountant are subject to pre-approval by the audit committee of our general partner. The audit committee of our general partner is informed of each engagement of the independent registered public accountant to provide services under the policy. The audit committee of our general partner has approved the use of PricewaterhouseCoopers LLP as our independent registered public accounting firm, including all services rendered for the year ended December 31, 2017.2018.
PART IV
Item 15. Exhibits, Financial Statement Schedules
(1) Financial Statements
Consolidated Financial Statements included in this Item 15:
Financial Statements of Rockies Express Pipeline LLC
FINANCIAL STATEMENTS
ROCKIES EXPRESS
PIPELINE LLC
For the years ended December 31, 2018, 2017 2016 and 20152016
Report of Independent Registered Public Accounting Firm
To the Board of Directors of Rockies Express Pipeline LLC
We have audited the accompanying financial statements of Rockies Express Pipeline LLC, which comprise the balance sheets as of December 31, 20172018 and 2016,2017, and the related statements of income, members’members' equity, and cash flows for each of the three years in the period ended December 31, 2017.2018.
Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’Auditors' Responsibility
Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rockies Express Pipeline LLC as of December 31, 20172018 and 2016,2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2018, in accordance with accounting principles generally accepted in the United States of America.
Emphasis of Matter
Matters
As described in Note 6 to the financial statements, the Company has significant transactions with related parties.
As discussed in Notes 2 and 7 to the financial statements, the Company changed the manner in which it accounts for revenue in 2018.
Our opinion is not modified with respect to this matter.
these matters.
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 13, 2018
8, 2019
ROCKIES EXPRESS PIPELINE LLC
BALANCE SHEETS
| | | | December 31, | December 31, |
| | 2017 | | 2016 | 2018 | | 2017 |
| | (in millions) | (in millions) |
| ASSETS | | | | | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | 25.7 |
| | $ | 118.4 |
| $ | 1.1 |
| | $ | 25.7 |
|
| Accounts receivable, net | 75.8 |
| | 59.4 |
| 76.8 |
| | 75.8 |
|
| Regulatory assets | 10.9 |
| | 12.3 |
| |
| Gas imbalances | 6.3 |
| | 2.6 |
| 7.4 |
| | 6.3 |
|
| Current portion of contract asset | | 31.8 |
| | — |
|
| Other current assets | 3.7 |
| | 3.0 |
| 3.6 |
| | 14.6 |
|
| Total Current Assets | 122.4 |
| | 195.7 |
| 120.7 |
| | 122.4 |
|
| Property, plant and equipment, net | 5,939.2 |
| | 6,063.7 |
| 5,759.0 |
| | 5,939.2 |
|
| Contract asset | | 157.0 |
| | — |
|
| Deferred charges and other assets | 11.8 |
| | 15.6 |
| 15.2 |
| | 11.8 |
|
| Total Noncurrent Assets | 5,951.0 |
| | 6,079.3 |
| 5,931.2 |
| | 5,951.0 |
|
| Total Assets | $ | 6,073.4 |
| | $ | 6,275.0 |
| $ | 6,051.9 |
| | $ | 6,073.4 |
|
| | | | | |
| LIABILITIES AND EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Accounts payable | $ | 20.3 |
| | $ | 38.1 |
| $ | 21.0 |
| | $ | 20.3 |
|
| Accrued interest | 56.3 |
| | 56.3 |
| 39.0 |
| | 56.3 |
|
| Accrued taxes | 60.0 |
| | 67.7 |
| 81.8 |
| | 60.0 |
|
| MFN revenue sharing liability | 9.3 |
| | 9.4 |
| |
| Current portion of long-term debt | 550.0 |
| | — |
| 525.0 |
| | 550.0 |
|
| Construction advances | 6.8 |
| | 11.7 |
| |
| Accrued other current liabilities | 11.3 |
| | 4.9 |
| 23.6 |
| | 27.4 |
|
| Total Current Liabilities | 714.0 |
| | 188.1 |
| 690.4 |
| | 714.0 |
|
| Long-term Liabilities and Deferred Credits: | | | | | | |
| Long-term debt | 2,014.8 |
| | 2,561.7 |
| |
| Long-term debt, net | | 1,492.7 |
| | 2,014.8 |
|
| Other long-term liabilities and deferred credits | 34.5 |
| | 95.2 |
| 10.2 |
| | 34.5 |
|
| Total Long-term Liabilities and Deferred Credits | 2,049.3 |
| | 2,656.9 |
| 1,502.9 |
| | 2,049.3 |
|
| | | | | |
| Commitments and Contingencies | | | | | | |
| | | | | |
| Members' Equity: | | | | | | |
| Members' equity | 3,310.1 |
| | 3,430.0 |
| 3,858.6 |
| | 3,310.1 |
|
| Total Liabilities and Members' Equity | $ | 6,073.4 |
| | $ | 6,275.0 |
| $ | 6,051.9 |
| | $ | 6,073.4 |
|
ROCKIES EXPRESS PIPELINE LLC
STATEMENTS OF INCOME
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Revenues: | | | | | | | | | | |
| Transportation services | $ | 839.6 |
| | $ | 715.1 |
| | $ | 779.0 |
| $ | 907.7 |
| | $ | 839.6 |
| | $ | 715.1 |
|
| Natural gas sales | 9.6 |
| | — |
| | 2.1 |
| 6.9 |
| | 9.6 |
| | — |
|
| Total Revenues | 849.2 |
| | 715.1 |
| | 781.1 |
| 914.6 |
| | 849.2 |
| | 715.1 |
|
| Operating Costs and Expenses: | | | | | | | | | | |
| Cost of transportation services | 29.8 |
| | 26.5 |
| | 30.2 |
| 32.3 |
| | 29.8 |
| | 26.5 |
|
| Cost of natural gas sales | 7.3 |
| | — |
| | 2.3 |
| 5.0 |
| | 7.3 |
| | — |
|
| Operations and maintenance | 25.3 |
| | 24.8 |
| | 21.2 |
| 27.0 |
| | 25.3 |
| | 24.8 |
|
| Depreciation and amortization | 218.4 |
| | 204.3 |
| | 199.4 |
| 219.6 |
| | 218.4 |
| | 204.3 |
|
| General and administrative | 30.5 |
| | 39.9 |
| | 26.7 |
| 28.2 |
| | 30.5 |
| | 39.9 |
|
| Taxes, other than income taxes | 65.3 |
| | 71.9 |
| | 73.9 |
| 85.3 |
| | 65.3 |
| | 71.9 |
|
| Total Operating Costs and Expenses | 376.6 |
| | 367.4 |
| | 353.7 |
| 397.4 |
| | 376.6 |
| | 367.4 |
|
| Operating Income | 472.6 |
| | 347.7 |
| | 427.4 |
| 517.2 |
| | 472.6 |
| | 347.7 |
|
| | | | | | | | | | | |
| Other (Expense) Income: | | | | | | | | | | |
| Interest expense, net | (168.0 | ) | | (158.6 | ) | | (170.1 | ) | (150.0 | ) | | (168.0 | ) | | (158.6 | ) |
| Gain on litigation settlement | 150.0 |
| | 61.7 |
| | — |
| — |
| | 150.0 |
| | 61.7 |
|
| Other income, net | 3.4 |
| | 27.7 |
| | 6.6 |
| 2.3 |
| | 3.4 |
| | 27.7 |
|
| Total Other Expense, net | (14.6 | ) | | (69.2 | ) | | (163.5 | ) | (147.7 | ) | | (14.6 | ) | | (69.2 | ) |
| Net Income to Members | $ | 458.0 |
| | $ | 278.5 |
| | $ | 263.9 |
| $ | 369.5 |
| | $ | 458.0 |
| | $ | 278.5 |
|
ROCKIES EXPRESS PIPELINE LLC
STATEMENTS OF MEMBERS' EQUITY
| | | | Total | | Rockies Express Holdings, LLC | | TEP REX Holdings, LLC | | Sempra REX Holdings, LLC | | P66 REX LLC | Total | | Rockies Express Holdings, LLC | | TEP REX Holdings, LLC | | Sempra REX Holdings, LLC | | P66 REX LLC |
| | (in millions) | (in millions) |
| Members' Equity: | | | | | | | | | | | | | | | | | | |
| Balance at January 1, 2015 | $ | 2,820.2 |
| | $ | 1,410.0 |
| | $ | — |
| | $ | 705.1 |
| | $ | 705.1 |
| |
| Net Income to Members | 263.9 |
| | 131.9 |
| | — |
| | 66.0 |
| | 66.0 |
| |
| Contributions from Members | 733.1 |
| | 366.5 |
| | — |
| | 183.3 |
| | 183.3 |
| |
| Distributions to Members | (499.0 | ) | | (249.4 | ) | | — |
| | (124.8 | ) | | (124.8 | ) | |
| Balance at December 31, 2015 | $ | 3,318.2 |
| | $ | 1,659.0 |
| | $ | — |
| | $ | 829.6 |
| | $ | 829.6 |
| |
| Balance at January 1, 2016 | | $ | 3,318.2 |
| | $ | 1,659.0 |
| | $ | — |
| | $ | 829.6 |
| | $ | 829.6 |
|
| Net Income to Members | 278.5 |
| | 139.3 |
| | 42.6 |
| | 27.0 |
| | 69.6 |
| 278.5 |
| | 139.3 |
| | 42.6 |
| | 27.0 |
| | 69.6 |
|
| Contributions from Members | 304.9 |
| | 152.5 |
| | 50.0 |
| | 26.2 |
| | 76.2 |
| 304.9 |
| | 152.5 |
| | 50.0 |
| | 26.2 |
| | 76.2 |
|
| Distributions to Members | (471.6 | ) | | (235.8 | ) | | (75.9 | ) | | (42.0 | ) | | (117.9 | ) | (471.6 | ) | | (235.8 | ) | | (75.9 | ) | | (42.0 | ) | | (117.9 | ) |
| Transfer of equity interest | — |
| | — |
| | 840.8 |
| | (840.8 | ) | | — |
| — |
| | — |
| | 840.8 |
| | (840.8 | ) | | — |
|
| Balance at December 31, 2016 | $ | 3,430.0 |
| | $ | 1,715.0 |
| | $ | 857.5 |
| | $ | — |
| | $ | 857.5 |
| $ | 3,430.0 |
| | $ | 1,715.0 |
| | $ | 857.5 |
| | $ | — |
| | $ | 857.5 |
|
| Net Income to Members | 458.0 |
| | 131.1 |
| | 212.4 |
| | — |
| | 114.5 |
| 458.0 |
| | 131.1 |
| | 212.4 |
| | — |
| | 114.5 |
|
| Contributions from Members | 92.0 |
| | 29.7 |
| | 39.3 |
| | — |
| | 23.0 |
| 92.0 |
| | 29.7 |
| | 39.3 |
| | — |
| | 23.0 |
|
| Distributions to Members | (669.9 | ) | | (197.6 | ) | | (304.8 | ) | | — |
| | (167.5 | ) | (669.9 | ) | | (197.6 | ) | | (304.8 | ) | | — |
| | (167.5 | ) |
| Transfer of equity interest (see Note 1) | — |
| | (850.3 | ) | | 850.3 |
| | — |
| | — |
| — |
| | (850.3 | ) | | 850.3 |
| | — |
| | — |
|
| Balance at December 31, 2017 | $ | 3,310.1 |
| | $ | 827.9 |
| | $ | 1,654.7 |
| | $ | — |
| | $ | 827.5 |
| $ | 3,310.1 |
| | $ | 827.9 |
| | $ | 1,654.7 |
| | $ | — |
| | $ | 827.5 |
|
| Cumulative effect of ASC 606 implementation | | 125.2 |
| | 51.0 |
| | 42.9 |
| | — |
| | 31.3 |
|
| Net Income to Members | | 369.5 |
| | 44.9 |
| | 232.2 |
| | — |
| | 92.4 |
|
| Contributions from Members | | 576.5 |
| | 1.6 |
| | 430.7 |
| | — |
| | 144.2 |
|
| Distributions to Members | | (522.7 | ) | | (63.7 | ) | | (328.4 | ) | | — |
| | (130.6 | ) |
| Transfer of equity interest (see Note 1) | | — |
| | (861.7 | ) | | 861.7 |
| | — |
| | — |
|
| Balance at December 31, 2018 | | $ | 3,858.6 |
| | $ | — |
| | $ | 2,893.8 |
| | $ | — |
| | $ | 964.8 |
|
ROCKIES EXPRESS PIPELINE LLC
STATEMENTS OF CASH FLOWS
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Cash Flows from Operating Activities: | | | | | | | | | | |
| Net income to Members | $ | 458.0 |
| | $ | 278.5 |
| | $ | 263.9 |
| $ | 369.5 |
| | $ | 458.0 |
| | $ | 278.5 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | | | | | |
| Depreciation and amortization | 223.7 |
| | 209.6 |
| | 204.8 |
| 224.7 |
| | 223.7 |
| | 209.6 |
|
| Change in contract asset | | (62.3 | ) | | — |
| | — |
|
| Changes in components of working capital: | | | | | | | | | | |
| Accounts receivable | (25.4 | ) | | 28.2 |
| | (23.8 | ) | (1.7 | ) | | (25.4 | ) | | 28.2 |
|
| Current regulatory assets and liabilities, net | 3.4 |
| | (12.5 | ) | | (10.2 | ) | 10.0 |
| | 3.4 |
| | (12.5 | ) |
| Accounts payable | (7.0 | ) | | 12.2 |
| | 3.7 |
| |
| Accounts payable and accrued other current liabilities | | (19.6 | ) | | (7.0 | ) | | 12.2 |
|
| Accrued taxes | (7.6 | ) | | (0.6 | ) | | 3.7 |
| 11.4 |
| | (7.6 | ) | | (0.6 | ) |
| Other current assets and liabilities | — |
| | (0.7 | ) | | (0.9 | ) | (2.8 | ) | | — |
| | (0.7 | ) |
| Return of customer deposits | (55.7 | ) | | — |
| | — |
| (29.9 | ) | | (55.7 | ) | | — |
|
| Receipt of customer deposits | 5.8 |
| | 52.9 |
| | 32.2 |
| 8.4 |
| | 5.8 |
| | 52.9 |
|
| Other operating, net | 1.1 |
| | (22.5 | ) | | (3.0 | ) | 3.9 |
| | 1.1 |
| | (22.5 | ) |
| Net Cash Provided by Operating Activities | 596.3 |
| | 545.1 |
| | 470.4 |
| 511.6 |
| | 596.3 |
| | 545.1 |
|
| Cash Flows from Investing Activities: | | | | | | | | | | |
| Capital expenditures | (108.9 | ) | | (305.7 | ) | | (281.9 | ) | (36.5 | ) | | (108.9 | ) | | (305.7 | ) |
| Other investing, net | (2.2 | ) | | (2.3 | ) | | (1.9 | ) | (3.3 | ) | | (2.2 | ) | | (2.3 | ) |
| Net Cash Used in Investing Activities | (111.1 | ) | | (308.0 | ) | | (283.8 | ) | (39.8 | ) | | (111.1 | ) | | (308.0 | ) |
| Cash Flows from Financing Activities: | | | | | | | | | | |
| Contributions from Members | | 576.5 |
| | 92.0 |
| | 304.9 |
|
| Distributions to Members | (669.9 | ) | | (471.6 | ) | | (499.0 | ) | (522.7 | ) | | (669.9 | ) | | (471.6 | ) |
| Contributions from Members | 92.0 |
| | 304.9 |
| | 733.1 |
| |
| Repayment of debt | — |
| | — |
| | (450.0 | ) | |
| Payments for deferred financing costs | — |
| | — |
| | (0.7 | ) | |
| Repayment of senior notes | | (550.0 | ) | | — |
| | — |
|
| Other financing, net | | (0.2 | ) | | — |
| | — |
|
| Net Cash Used in Financing Activities | (577.9 | ) | | (166.7 | ) | | (216.6 | ) | (496.4 | ) | | (577.9 | ) | | (166.7 | ) |
| Net Change in Cash and Cash Equivalents | (92.7 | ) | | 70.4 |
| | (30.0 | ) | (24.6 | ) | | (92.7 | ) | | 70.4 |
|
| Cash and Cash Equivalents, beginning of period | 118.4 |
| | 48.0 |
| | 78.0 |
| 25.7 |
| | 118.4 |
| | 48.0 |
|
| Cash and Cash Equivalents, end of period | $ | 25.7 |
| | $ | 118.4 |
| | $ | 48.0 |
| $ | 1.1 |
| | $ | 25.7 |
| | $ | 118.4 |
|
| Supplemental Disclosures: | | | | | | | | | | |
| Cash payments for interest, net | $ | (164.9 | ) | | $ | (155.6 | ) | | $ | (170.7 | ) | $ | (164.9 | ) | | $ | (164.9 | ) | | $ | (155.6 | ) |
| Schedule of Noncash Investing and Financing Activities: | | | | | | | | | | |
| Increase in accrual for payment of property, plant and equipment | $ | — |
| | $ | — |
| | $ | 8.4 |
| $ | 2.8 |
| | $ | — |
| | $ | — |
|
ROCKIES EXPRESS PIPELINE LLC
NOTES TO FINANCIAL STATEMENTS
1. Description of Business
Rockies Express Pipeline LLC ("Rockies Express") is a Federal Energy Regulatory Commission ("FERC") regulated natural gas transportation system with approximately 1,712 miles of natural gas pipeline, including laterals, extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio and consisting of three zones:
Zone 1 - a 328-mile pipeline from the Meeker Hub in Northwest Colorado, across Southern Wyoming to the Cheyenne Hub in Weld County, Colorado capable of transporting 2.0 Bcf/d of natural gas from west to east;
Zone 2 - a 714-mile pipeline from the Cheyenne Hub to an interconnect in Audrain County, Missouri capable of transporting 1.8 Bcf/d of natural gas from west to east; and
Zone 3 - a 643-mile pipeline from Audrain County, Missouri to Clarington, Ohio, which is bi-directional and capable of transporting 1.8 Bcf/d of natural gas from west to east and 2.6 Bcf/d of natural gas from east to west.
The member interests and voting rights in Rockies Express as of December 31, 20172018 are as follows:
49.99%75% - TEP REX Holdings, LLC ("TEP REX"), an indirect wholly owned subsidiary of Tallgrass Energy Partners, LP ("TEP");
25.01% - Rockies Express Holdings, LLC ("REX Holdings"), an indirect wholly owned subsidiary of Tallgrass Development, LP ("TD"); and
25% - P66REX LLC, a wholly owned subsidiary of Phillips 66.
On March 31, 2017, TEP, TD,Tallgrass Development LP ("TD"), and Rockies Express Holdings, LLC ("REX Holdings,Holdings"), an indirect wholly owned subsidiary of TD, entered into a definitive Purchase and Sale Agreement, pursuant to which TEP acquired an additional 24.99% membership interest in Rockies Express from TD in exchange for cash consideration of $400 million. This transaction increased TEP’sTEP REX's aggregate membership interest in Rockies Express to 49.99%.
On February 7, 2018, Tallgrass Development Holdings, LLC ("Tallgrass Development Holdings"), a wholly owned subsidiary of Tallgrass Equity, acquired REX Holdings and its 25.01% membership interest in Rockies Express as a result of the merger of TD into Tallgrass Development Holdings. Tallgrass Development Holdings is a wholly-owned subsidiary of Tallgrass Equity LLC, which is the sole member of TEP's general partner. Effective July 1, 2018, REX Holdings was merged into TEP REX, resulting in TEP REX owning a 75% membership interest in Rockies Express.
2. Summary of Significant Accounting Policies
Basis of Presentation
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual results could differ from these estimates. Certain prior year amounts have been reclassified to conform to the current presentation.
Use of Estimates
Certain amounts included in or affecting these financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts reported for assets, liabilities, revenues, and expenses during the reporting period, and the disclosure of contingent assets and liabilities at the date of the financial statements. Management evaluates these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from these estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
Cash and Cash Equivalents
Rockies Express considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable are carried at their estimated collectible amounts. Rockies Express makes periodicperiodically reviews and evaluations ofevaluates the appropriateness of the allowance for doubtful accounts based on a statistical analysis of historical defaults, and adjustments are recorded as necessary for changes in circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. Our allowance for doubtful accounts totaled $1.0 million and $2.0 million at December 31, 2018 and 2017, and 2016.respectively.
Fuel Recovery Mechanism
Rockies Express obtains natural gas quantities from its shippers as reimbursement for fuel consumed at compressor stations and other locations on its system as well as for natural gas quantities lost and otherwise unaccounted for, in accordance with its tariff and applicable contract terms. Rockies Express tracks the volume and value of associated over- or under-collections of fuel and lost and unaccounted for quantities through a tracking mechanism referred to as "fuel tracker." Those amounts are recorded as an addition or reduction to a regulatory asset or liability balance representing the amounts to be recovered from or refunded to customers through the fuel tracker mechanisms. Fuel tracker volumes are valued using a weighted-average monthly index price.
Accounting for Regulatory Activities
Rockies Express' regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("Codification"). This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses to Rockies Express associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. Rockies Express recorded regulatory assets of approximately $10.9$0.7 million and $12.3$10.9 million at December 31, 20172018 and 2016,2017, respectively, and regulatory liabilities of approximately $2.0$1.8 million and $10,000$2.0 million at December 31, 20172018 and 2016,2017, respectively. Regulatory assets and liabilities at December 31, 20172018 and 20162017 were primarily attributable to the fuel tracker discussed in "Fuel Recovery Mechanism" above. For additional details see Note 910 – Regulatory Matters.
Gas Imbalances
Gas imbalances receivable and payable reflect gas volumes owed between Rockies Express and its customers. Gas imbalances represent the difference between customer nominated versus actual gas receipts from and gas deliveries to interconnecting pipelines under various operational balancing agreements. Gas imbalances are settled in cash or made up in-kind subject to the terms of the various agreements and are valued at the average monthly index price.
Property, Plant and Equipment
Property, plant and equipment is stated at historical cost, which for constructed assets includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction and other costs directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized and depreciated over the remaining useful life of the asset or major asset component. Rockies Express also capitalizes certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs.
Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred.
Rockies Express maintains natural gas in its pipeline, known as "line pack," which serves to maintain the necessary pressure to allow efficient transmission of natural gas. Line pack is capitalized within "Property, plant and equipment, net" on the balance sheets and depreciated over the estimated useful life of the pipeline.
Impairment of Long-Lived Assets
Rockies Express reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset's use and its eventual disposition are less than its carrying amount. Rockies Express assesses its long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value.
Examples of long-lived asset impairment indicators include:
a significant decrease in the market value of a long-lived asset or group;
a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;
a significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group;
a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and
a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
When an impairment indicator is present, Rockies Express first assesses the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset to the carrying amount of the asset. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the asset is assessed using a discounted cash flow analysis to determine the amount of impairment, if any, to be recognized.
Depreciation and Amortization
Depreciation is computed based on the straight-lineRockies Express has elected to compute depreciation using a composite method over the estimated useful livesemployed by applying a single depreciation rate to a group of property, plant and equipment.assets with similar economic characteristics. The annual composite rate of depreciation for the years ended December 31, 2018, 2017, 2016, and 20152016 was 2.86%.
Allowance for Funds Used During Construction
Included in the cost of "Property, plant and equipment, net" on the accompanying balance sheets is an allowance for funds used during construction ("AFUDC"). AFUDC represents the estimated cost of debt, from borrowed funds, or the estimated cost of capital, from equity funds, during the construction period. During the years ended December 31, 2018, 2017 and 2016 Rockies Express recognized AFUDC associated with the estimated cost of debt of approximately $0.3 million, $0.2 million, and 2015,$9.3 million, respectively, recorded as "Interest expense, net" on the accompanying statements of income. During the years ended December 31, 2018, 2017, and 2016, Rockies Express recognized AFUDC associated with the estimated cost of capital from equity funds of approximately $0.6 million, $0.5 million, $24.8 million, and $6.5$24.8 million, respectively, recorded as "Other income, net" on the accompanying statements of income.
Revenue Recognition
In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five-step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract.
Management completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2018. This approach allows Rockies Express provides various types of natural gas transportation services to its customers in whichapply the natural gas remains the property of these customers atnew standard to (i) all times. In many cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fixed-fee reserving the right to transport natural gas in Rockies Express' facilitiesnew contracts entered into after January 1, 2018 and (ii) a per-unit rateall existing contracts for volumes actually transported. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers' agreed upon delivery point. In other cases (generally described as "interruptible service"), there is no fixed-fee associated with the services because the customer accepts the possibility that service may be interrupted at the discretion of Rockies Express in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes transported under firm service agreements.
In addition to its "firm" and "interruptible" transportation services, Rockies Express also provides a natural gas park and loan service to assist customers in managing a short-term gas surplus or deficit and a pooling and wheeling service to assist customers in the aggregation of gas supply from physical point(s) within a specified hub to a central pooling point and the re-delivery of gas supply to physical points within the same hub. Revenues are recognized as services are provided, in accordance with the terms negotiated under these contracts.
Rockies Express recognizes revenue from natural gas sales when the natural gas is sold at a fixed or determinable price, delivery has occurred and title has transferred, and collectabilitywhich all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to members' equity. Revenues presented in the comparative financial statements for periods prior to January 1, 2018 have not been revised.
On January 1, 2018, Rockies Express recorded a cumulative effect adjustment to equity of $125.2 million. The cumulative effect adjustment arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with rates that vary throughout the term of the contract. Rockies Express established a contract asset on January 1, 2018 that reflects the amount by which the revenue that would have been recognized pursuant to ASC 606 exceeds the actual cash collected from the customer for periods prior to implementation and will be reversed over the remaining term of the contract.
See Note 7 – Revenue from Contracts with Customers for revenue disclosures related to both the implementation and the additional requirements prescribed by the standard. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is reasonably assured.(or will be) recognized and data related to contract assets and liabilities.
Deferred Financing Costs
Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method. Deferred financing costs associated with long-term debt are presented as a reduction to the corresponding debt on the accompanying balance sheets. Deferred financing costs associated with revolving credit facilities or lines of credit are classified as noncurrent assets on the accompanying balance sheets.
Deferred Charges and Deferred Credits
Rockies Express has $2.5$0.5 million remaining of an initial $20.0 million deferred charge and deferred credit relating to a customer contract. The deferred charge is being amortized using a straight-line-method over the life of the related contract. Amortization of the deferred charge for each of the years ended December 31, 2018, 2017, 2016, and 20152016 was $2.0 million and is included within transportation services revenues in the accompanying statements of income. The deferred credit is payable over a period of 10 years.
Environmental Matters
Rockies Express expenses or capitalizes, as appropriate, environmental expenditures that relate to current operations. Rockies Express expenses amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. Rockies Express does not discount environmental liabilities to a net present value, and records environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Generally, recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action.
Fair Value
Fair value, as defined in the fair value measurement accounting guidance, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. The fair value measurement accounting guidance requires that Rockies Express make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that an obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments' fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity. The fair value of current financial assets and liabilities approximate their reported carrying amounts as of December 31, 20172018 and 2016.2017.
Income Taxes
Rockies Express is a limited liability company that has elected to be treated as a partnership for income tax purposes. Accordingly, no provision for federal or state income taxes has been recorded in the financial statements of Rockies Express and the tax effects of Rockies Express' activities accrue to its Members.
New Accounting Pronouncements
Revenue Recognition
In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five-step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract.
Throughout 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, and ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers.
The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016.
Management has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2018. This approach allows Rockies Express to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to members' equity. Consolidated revenues presented in the comparative financial statements for periods prior to January 1, 2018 will not be revised.
On January 1, 2018, Rockies Express recorded a cumulative effect adjustment to equity of $125.2 million. The cumulative effect adjustment arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with tiered-pricing arrangements. Rockies Express established a contract asset on January 1, 2018 that reflects the amount by which the revenue that would have been recognized pursuant to ASC 606 exceeds the actual cash collected from the customer for periods prior to implementation and will be reversed over the remaining term of the contract.
Rockies Express anticipates significant changes to its disclosures based on the additional requirements prescribed by the standard. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities. Additionally, Rockies Express continues to provide internal training and awareness related to the revised guidance to key stakeholders throughout the organization and evaluate business processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new revenue guidance. Not Yet Adopted
ASU No. 2016-02, "Leases (Topic 842)"
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing leaseright-of-use ("ROU") assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.
Management is currently evaluatingSubsequent to issuing ASU 2016-02, the impactFASB has issued a series of Rockies Express' pending adoption of the revised guidance. The status of its implementation is as follows:
Rockies Express management has formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain contract types, and project status.
Rockies Express management is in the process of gathering data and reviewing contracts in order to identify all impacted contracts.
Rockies Express management is evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from its contract review process.
Rockies Express management plans to provide internal training and awareness relatedsubsequent updates to the revisedlease guidance in Topic 842, including ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to the key stakeholders throughout its organization.
Topic 842, ASU No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, and ASU 2018-20, Leases (Topic 842): Narrow-Scope Improvements for Lessors. The amendments in ASU 2016-02, ASU 2018-01, ASU 2018-10, ASU 2018-11, and ASU 2018-20 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted.
Management has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2019. The approach allows Rockies Express is currently evaluatingto (i) initially apply ASC 842 at the impactadoption date, January 1, 2019 and (ii) continue reporting comparative periods presented in the financial statements in the period of ASU 2016-02. While the SEC has indicated that itadoption under ASC 840. Rockies Express will not object to certain public business entities adoptingrecast comparative periods in the standard usingaccompanying financial statements. Management elected the timeline otherwise afforded to private companies, Rockies Express expects to adoptpackage of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed Rockies Express to carry forward the historical lease classification. Management also elected the practical expedient related to land easements, allowing Rockies Express to carry forward the accounting treatment for land easements on January 1, 2019.existing agreements.
Adoption of the new standard resulted in the recognition of ROU assets and lease liabilities for operating leases of approximately $40.0 million.
3. Property, Plant and Equipment
Rockies Express' property, plant and equipment, net consisted of the following:
| | | | December 31, | December 31, |
| | 2017 | | 2016 | 2018 | | 2017 |
| | (in millions) | (in millions) |
| Natural gas pipelines | $ | 7,661.2 |
| | $ | 7,085.8 |
| $ | 7,677.0 |
| | $ | 7,661.2 |
|
| General and other | 15.4 |
| | 9.9 |
| 15.8 |
| | 15.4 |
|
| Construction work in progress | 11.9 |
| | 503.2 |
| 27.8 |
| | 11.9 |
|
| Accumulated depreciation and amortization | (1,749.3 | ) | | (1,535.2 | ) | (1,961.6 | ) | | (1,749.3 | ) |
| Total property, plant and equipment, net | $ | 5,939.2 |
| | $ | 6,063.7 |
| $ | 5,759.0 |
| | $ | 5,939.2 |
|
Depreciation expense was approximately $219.6 million, $218.4 million $204.3 million and $199.4$204.3 million for the years ended December 31, 2018, 2017 2016 and 2015, respectively. Capitalized interest was $0.2 million, $9.3 million, and $2.8 million for the years ended December 31, 2017, 2016, and 2015, respectively.
4. Financing
Debt
Total outstanding debt as of December 31, 20172018 and 20162017 consisted of the following:
| | | | December 31, | December 31, |
| | 2017 | | 2016 | 2018 | | 2017 |
| | (in millions) | (in millions) |
6.85% senior notes due July 15, 2018 | $ | 550.0 |
| | $ | 550.0 |
| $ | — |
| | $ | 550.0 |
|
6.00% senior notes due January 15, 2019 | 525.0 |
| | 525.0 |
| 525.0 |
| | 525.0 |
|
| 5.625% senior notes due April 15, 2020 | 750.0 |
| | 750.0 |
| 750.0 |
| | 750.0 |
|
| 7.50% senior notes due July 15, 2038 | 250.0 |
| | 250.0 |
| 250.0 |
| | 250.0 |
|
| 6.875% senior notes due April 15, 2040 | 500.0 |
| | 500.0 |
| 500.0 |
| | 500.0 |
|
| Less: Unamortized debt discount and deferred financing costs | (10.2 | ) | | (13.3 | ) | (7.3 | ) | | (10.2 | ) |
| Total debt | 2,564.8 |
| | 2,561.7 |
| |
| Total debt, net | | 2,017.7 |
| | 2,564.8 |
|
| Less: Current portion | (550.0 | ) | | — |
| (525.0 | ) | | (550.0 | ) |
| Total long-term debt | $ | 2,014.8 |
| | $ | 2,561.7 |
| |
| Total long-term debt, net | | $ | 1,492.7 |
| | $ | 2,014.8 |
|
| |
(1) | The 6.85% senior notes were repaid on July 15, 2018. The repayment was funded by contributions from the Rockies Express Members, as discussed further below. |
| |
(2) | The 6.00% senior notes were repaid on January 15, 2019. The repayment was funded by the issuance of a 364-Day Term Loan Agreement effective January 8, 2019, as discussed further below. |
Rockies Express Senior Notes
The senior notes issued by Rockies Express are redeemable in whole or in part, at Rockies Express' option at any time, at redemption prices defined in the associated indenture agreements.
All payments of principal and interest with respect to the fixed rate senior notes are the sole obligation of Rockies Express. Note holders have no recourse against Rockies Express' Members or their respective officers, directors, employees, shareholders, members, managers, unit holders or affiliates for any failure by Rockies Express to perform or comply with its obligations pursuant to the notes or the indenture. As of December 31, 2017,2018, Rockies Express was in compliance with the covenants required under the senior notes.
Maturities of Debt
The scheduled maturities of Rockies Express' outstanding debt balances as of December 31, 20172018 are summarized as follows (in millions):
| | | Year | | Scheduled Maturities | | Scheduled Maturities |
| 2018 | | $ | 550.0 |
| |
| 2019 | | 525.0 |
| | $ | 525.0 |
|
| 2020 | | 750.0 |
| | 750.0 |
|
| 2021 | | — |
| | — |
|
| 2022 | | — |
| | — |
|
| 2023 | | | — |
|
| Thereafter | | 750.0 |
| | 750.0 |
|
| Total scheduled maturities | | 2,575.0 |
| | 2,025.0 |
|
| Unamortized debt discount and deferred financing costs | | (10.2 | ) | | (7.3 | ) |
| Total debt | | $ | 2,564.8 |
| | $ | 2,017.7 |
|
The 6.00% senior notes were repaid on January 15, 2019. The repayment was funded by the issuance of a 364-Day Term Loan Agreement effective January 8, 2019 (the "Term Loan") which matures on January 7, 2020. As a result, Rockies Express has senior notes$525 million of debt scheduled to mature within one year of the issuance of these financial statements totaling $1.075 billion.statements. Management has obtained a letter of support from the Members of Rockies Express confirming the Members’Members' intent and ability to provide Rockies Express with financial support through at least one year and a day beyond February 13, 2018 (the financial statement issuance date)8, 2019 to the extent that other sources of funding are not otherwise available to Rockies Express. This support from the Members effectively alleviates the risk surrounding the ability of Rockies Express to continue as a going concern.
Rockies Express Revolving Credit Facility
On October 1, 2015, Rockies Express entered into a $150 million senior unsecured revolving credit facility ("the revolving credit facility") with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders, which will mature on January 31, 2020. The revolving credit facility includes a $75 million sublimit for letters of credit and a $20 million sublimit for swing line loans and may be used for working capital and general company purposes. The revolving credit facility also contains an accordion feature whereby Rockies Express can increase the size of the credit facility to an aggregate of $200 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. As of December 31, 2017,2018, there were no outstanding borrowings or letters of credit issued under the revolving credit facility.
Borrowings under the credit facility bear interest, at Rockies Express' option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar rate, plus, in each case, an applicable margin. For borrowings bearing interest based on the base rate, the applicable margin was initially 1.00%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin was initially 2.00%. After the first full fiscal quarter, the applicable margin ranges from 0.50% to 1.25% for base rate borrowings and 1.50% to 2.25% for reserve adjusted Eurodollar rate borrowings, based upon Rockies Express' total leverage ratio. The unused portion of the credit facility is subject to a commitment fee, which ranges from 0.20% to 0.45% based upon Rockies Express' total leverage ratio.
Rockies Express has the option to have the applicable margin determined based on Rockies Express' credit ratings should Rockies Express receive an investment grade credit rating from one or more of the ratings agencies in the future.ratings. If Rockies Express were to make an election to exercise this option, the applicable margin would range from 0.125% to 1.00% for base rate borrowings and 1.125% to 2.00% for reserve adjusted Eurodollar borrowings, based on Rockies Express' credit ratings. Under such an election, the commitment fee would range from 0.125% to 0.40%, also based on Rockies Express' credit ratings.
Covenants Under the Term Loan and Revolving Credit Facility
The Term Loan and the revolving credit facility generally requiresrequire Rockies Express to comply with various affirmative and negative covenants, including a limit on the leverage ratio (as defined in theeach credit agreement) of Rockies Express and restrictions on:
incurring secured indebtedness;
entering into mergers, consolidations and sales of assets;
granting liens;
entering into transactions with affiliates; and
making restricted payments.
As of December 31, 2017,2018, Rockies Express was in compliance with the covenants required under the revolving credit facility.
Repayment of 3.90% Senior Notes
The board of directors of Rockies Express approved repayment of the $450 million 3.90% senior notes due April 15, 2015 ("2015 Notes") which was financed through capital contributions by the Members of Rockies Express in proportion to their respective ownership interests. The capital contribution was made by each Member of Rockies Express in accordance with Section 4.3.1 of Rockies Express' Second Amended and Restated Limited Liability Company Agreement, as amended, and was used to repay the 2015 Notes on April 15, 2015.
Fair Value
The following table sets forth the carrying amount and fair value of Rockies Express' debt, which is not measured at fair value in the accompanying balance sheets as of December 31, 20172018 and 2016,2017, but for which fair value is disclosed:
| | | | Fair Value | | | Fair Value | | |
| | Quoted prices in active markets for identical assets
(Level 1) | | Significant other observable inputs
(Level 2) | | Significant unobservable inputs
(Level 3) | | Total | | Carrying
Amount | Quoted prices in active markets for identical assets
(Level 1) | | Significant other observable inputs
(Level 2) | | Significant unobservable inputs
(Level 3) | | Total | | Carrying
Amount |
| | (in millions) | | | (in millions) | | |
| December 31, 2018 | | $ | — |
| | $ | 2,086.9 |
| | $ | — |
| | $ | 2,086.9 |
| | $ | 2,017.7 |
|
| December 31, 2017 | $ | — |
| | $ | 2,752.1 |
| | $ | — |
| | $ | 2,752.1 |
| | $ | 2,564.8 |
| $ | — |
| | $ | 2,752.1 |
| | $ | — |
| | $ | 2,752.1 |
| | $ | 2,564.8 |
|
| December 31, 2016 | $ | — |
| | $ | 2,684.9 |
| | $ | — |
| | $ | 2,684.9 |
| | $ | 2,561.7 |
| |
The debt is carried at amortized cost, net of deferred financing costs. The estimated fair value of Rockies Express' outstanding private placement debt is based upon quoted market prices adjusted for illiquid markets. Rockies Express is not aware of any factors that would significantly affect the estimated fair value subsequent to December 31, 2017.2018.
5. Members' Equity
During the years ended December 31, 2018, 2017, 2016, and 2015,2016, Rockies Express made distributions to Members of $522.7 million, $669.9 million, $471.6 million, and $499.0$471.6 million, respectively. The distributions paid by Rockies Express during the year ended December 31, 2017 included a distribution of the proceeds from the Ultra settlement discussed in Note 1011 – Legal and Environmental Matters.
During the years ended December 31, 2018, 2017, 2016, and 2015,2016, Rockies Express received contributions from Members of $576.5 million, $92.0 million, and $304.9 million, and $733.1respectively. Contributions from Members during the year ended December 31, 2018 included a special contribution of approximately $550 million respectively.to fund the repayment of senior notes as discussed in Note 4 – Financing. Contributions from Members during the years ended December 31, 2017 and 2016 were primarily used to fund the construction and other costs of the Zone 3 Capacity Enhancement project, as discussed in Note 910 – Regulatory Matters. Contributions from Members during the year ended December 31, 2015 were used to repay the 2015 Notes, as discussed in Note 4 – Financing, fund the construction and other costs of the Zone 3 East-to-West Project facilities and the Zone 3 Capacity Enhancement project and remaining costs associated with the Seneca Lateral Project facilities, and to increase cash on hand for working capital needs.
Additional contributions and distributions were made subsequent to December 31, 2017.2018. For details see Note 1112 – Subsequent Events.
6. Related Party Transactions
Rockies Express has an operating agreement with Tallgrass NatGas Operator, LLC ("NatGas"), a subsidiary of TEP, under which NatGas provides and bills Rockies Express for various services at cost including employee labor costs, information technology services, employee health and retirement benefits, and insurance for property and casualty risks. In addition, NatGas receives a management oversight fee in the amount of 1% of Rockies Express' earnings before interest, taxes, depreciation, and amortization. Rockies Express' practice is to settle receivable and payable balances that exist with affiliates in the following month.
Totals of significant transactions with affiliated companies are as follows:
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (in millions) | (in millions) |
Revenues: Transportation services (1) | $ | — |
| | $ | 14.4 |
| | $ | 10.8 |
| $ | — |
| | $ | — |
| | $ | 14.4 |
|
| Charges from TD: | | | | | | |
| Charges to Rockies Express: | | | | | | |
| Compensation, benefits and other charges | $ | 18.6 |
| | $ | 20.6 |
| | $ | 18.5 |
| $ | 18.1 |
| | $ | 18.6 |
| | $ | 20.6 |
|
| General and administrative charges from affiliate | $ | 8.9 |
| | $ | 9.4 |
| | $ | 8.6 |
| $ | 10.3 |
| | $ | 8.9 |
| | $ | 9.4 |
|
| Management Fees: | | | | | | | | | | |
| Tallgrass NatGas Operator, LLC | $ | 8.5 |
| | $ | 6.2 |
| | $ | 6.3 |
| $ | 7.5 |
| | $ | 8.5 |
| | $ | 6.2 |
|
| |
(1) | Transportation services revenue for the yearsyear ended December 31, 2016 and 2015 is primarily from Sempra Energy prior to the May 6, 2016 sale of Sempra Energy's ownership to TEP REX. |
Balances with affiliated companies included in the accompanying balance sheets are as follows:
| | | | December 31, | December 31, |
| | 2017 | | 2016 | 2018 | | 2017 |
| | (in millions) | (in millions) |
| Payables to affiliated companies: | | | | | | |
| TEP | | $ | 3.4 |
| | $ | 1.3 |
|
| TD | $ | 2.3 |
| | 4.5 |
| — |
| | 2.3 |
|
| TEP | 1.3 |
| | 0.6 |
| |
| Total payables to affiliated companies | $ | 3.6 |
| | $ | 5.1 |
| $ | 3.4 |
| | $ | 3.6 |
|
Gas imbalances with affiliated shippers are as follows:
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Affiliate gas imbalance receivables | $ | 0.4 |
| | $ | — |
|
| Affiliate gas imbalance payables | $ | — |
| | $ | 0.2 |
|
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | (in millions) |
| Affiliate gas imbalance receivables | $ | 0.8 |
| | $ | 0.4 |
|
7. Revenue from Contracts with Customers
As discussed in Note 2 – Summary of Significant Accounting Policies, Rockies Express adopted the guidance in ASC Topic 606 effective January 1, 2018 using the modified retrospective method of adoption. As a result, revenue reported for the years ended December 31, 2017 and 2016 have not been revised. The following tables provide the impact of the guidance on the Rockies Express balance sheet as of December 31, 2018 and statement of income for the year ended December 31, 2018:
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| | December 31, 2018 | |
| | As currently reported | | Under previous guidance | | Impact of ASC Topic 606 | |
| | (in millions) | |
| Current portion of contract asset | $ | 31.8 |
| | $ | — |
| | $ | 31.8 |
| (1) |
| Contract asset | $ | 157.0 |
| | $ | — |
| | $ | 157.0 |
| (1) |
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| | | | | | | | | | | | |
| | Year Ended December 31, 2018 | |
| | As currently reported | | Under previous guidance | | Impact of ASC Topic 606 | |
| | (in millions) | |
| Transportation services | $ | 907.7 |
| | $ | 845.4 |
| | $ | 62.3 |
| (1) |
| General and administrative | $ | 28.2 |
| | $ | 27.6 |
| | $ | 0.6 |
| (2) |
| Net Income to Members | $ | 369.5 |
| | $ | 307.8 |
| | $ | 61.7 |
| |
| |
(1) | Reflects the impact of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with rates that vary throughout the term of the contract and related contract asset. |
| |
(2) | Reflects the additional management fee associated with the effect of the change in gas transportation revenue. |
Disaggregated Revenue
A summary of our revenue by line of business is as follows:
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| | | | |
| | | Year Ended December 31, 2018 |
| | | (in millions) |
| Firm Transportation - West to East | | $ | 467.7 |
|
| Firm Transportation - East to West | | 425.0 |
|
| All other | | 15.0 |
|
| Total firm transportation | | 907.7 |
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| Natural gas sales | | 6.9 |
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| Total revenue | | $ | 914.6 |
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Performance Obligations
A performance obligation is a promise in a contract to transfer a distinct good or service to the customer, and is the unit of account in ASC Topic 606. A contract's transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. The majority of Rockies Express' contracts have a single performance obligation and are billed and collected monthly. These performance obligations typically include an obligation to stand ready to provide natural gas transportation service over the life of the contract, which is a series. These performance obligations are satisfied over time using each day of service to measure progress toward satisfaction of the performance obligation.
Rockies Express also engages in commodity sales, in which the performance obligations include an obligation to deliver the specified volume of a commodity to the designated receipt point. Revenue from commodity sales is recognized at a point in time when the customer obtains control of the commodity, typically upon delivery to the designated delivery point when the customer accepts and takes possession of the commodity.
On December 31, 2018, we had $7.5 billion of remaining performance obligations, which we refer to as total backlog. Total backlog includes performance obligations under firm transportation contracts, and excludes variable consideration that is not estimated at contract inception, as discussed further below. We expect to recognize the total backlog during future periods as follows (in millions):
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| | | | |
| Year | | Estimated Revenue |
| 2019 | | $ | 853.9 |
|
| 2020 | | 617.3 |
|
| 2021 | | 606.3 |
|
| 2022 | | 576.2 |
|
| 2023 | | 572.0 |
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| Thereafter | | 4,278.5 |
|
| Total | | $ | 7,504.2 |
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Contract Estimates
Accounting for long-term contracts involves the use of various techniques to estimate total contract revenue. Contract estimates are based on various assumptions to project the outcome of future events that often span several years.
The nature of our contracts gives rise to several types of variable consideration, including volumetric charges for actual volumes delivered, overrun charges, and other fees that are contingent on the actual volumes delivered by our customers. As the amount of variable consideration is allocable to each distinct performance obligation within the series of performance obligations that comprise the performance obligation, we do not estimate the total variable consideration for the overall performance obligation because the uncertainty related to the consideration is resolved each month as the distinct service is provided. Consequently, we are able to include in the transaction price each month the actual amount of variable consideration because no uncertainty exists surrounding the services provided that month.
Contract Balances
The timing of revenue recognition, billings, and cash collections may result in billed accounts receivable, unbilled receivables (contract assets), and deferred revenue (contract liabilities) on our balance sheets. Revenue is generally billed and collected monthly based on services provided or volumes sold. As of December 31, 2018, we had recognized a contract asset of $188.8 million reflecting the amount by which the revenue recognized exceeds the actual cash collected from certain contracts with rates that vary throughout the term of the contract.
8. Commitments and Contingent Liabilities
Leases
Total rental expense under operating leases was $29.2 million for the years ended December 31, 2018, 2017, 2016, and 2015.2016. Future minimum commitments related to these leases as of December 31, 20172018 are as follows (in millions):
| | | Year | | Future Minimum Lease Payments | | Future Minimum Lease Payments |
| 2018 | | $ | 29.2 |
| |
| 2019 | | 29.2 |
| | $ | 29.1 |
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| 2020 | | 29.2 |
| | 29.1 |
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| 2021 | | 29.2 |
| | 29.1 |
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| 2022 | | 29.2 |
| | 29.1 |
|
| 2023 | | | 29.1 |
|
| Thereafter | | 146.0 |
| | 116.4 |
|
| Total | | $ | 292.0 |
| | $ | 261.9 |
|
The future minimum rental commitments are primarily attributable to a 20-year capacity lease agreement with Overthrust Pipeline Company ("Overthrust") which commenced on January 1, 2008. The capacity lease provides the right to transport on a firm basis 625 MMcf/d of natural gas through Overthrust's system from either the Williams Field Services Opal Processing Plant or the TEPPCO Pioneer Processing Plant to the Wamsutter interconnect.
Capital Expenditures
Approximately $7.7$60.8 million of Rockies Express' capital expenditure budget for 20182019 had been committed for purchases of property, plant and equipment at December 31, 2017.2018.
8.9. Major Customers
During 2018, three non-affiliated shippers accounted for $168.5 million (18%), $118.7 million (13%), and $112.2 million (12%), respectively of Rockies Express' total revenues. During 2017, three non-affiliated shippers accounted for $169.4 million (20%), $111.9 million (13%), and $101.3 million (12%), respectively of Rockies Express' total revenues. During 2016, four non-affiliated shippers accounted for $164.8 million (23%), $82.9 million (12%), $71.4 million (10%), and $70.4 million (10%), respectively of Rockies Express' total revenues. During 2015, three non-affiliated shippers accounted for $187.6 million (24%), $163.0 million (21%), and $104.6 million (13%), respectively of Rockies Express' total revenues. Rockies Express attempts to mitigate credit risk by seeking collateral or financial guarantees and letters of credit from customers.
9.10. Regulatory Matters
There are no regulatory proceedings challenging the transportation rates of Rockies Express. Rockies Express has made certain regulatory filings with the FERC, including the following:
Petition for Declaratory Order – FERC Docket No. RP13-969-000
In June 2013, in Docket No. RP13-969-000, Rockies Express filed with the FERC a Petition for Declaratory Order which sought a ruling that the "most favored nations" or "MFN" provisions contained in Rockies Express' negotiated rate agreements ("NRAs") with its Foundation and Anchor Shippers would not prevent Rockies Express from providing firm transportation service at rates lower than Foundation and Anchor Shippers' rates that (1) have an east-to-west primary path; (2) are for a term of one year or longer; and (3) are limited to service in one rate zone and therefore do not utilize all of the same facilities or rate zones as the service provided pursuant to the Foundation and Anchor Shipper NRAs. In November 2013, the FERC issued a declaratory order finding that the potential transactions would not trigger the MFN rights of Rockies Express’Express' Foundation and Anchor Shippers. Various parties filed requests for rehearing of the FERC’sFERC's declaratory order.
In September 2014 and December 2015, the FERC accepted amended contracts with the shippers holding MFN rights on Rockies Express, which reflect the terms of settlements between these shippers and Rockies Express. The settlements provide additional clarity with respect to the applicability of the settling shippers' MFN rights, sharing by Rockies Express of certain transportation revenues, and the withdrawal of the settling shippers from the Petition for Declaratory Order proceeding. On September 27, 2017, FERC issued an order denying the requests for rehearing of the declaratory order issued in November 2013, and no party sought judicial appeal of the FERC order denying rehearing within the statutory deadline.
2015 Annual FERC Fuel Tracking Filings - FERC Docket No. RP15-584-000
On February 27, 2015, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2015 in Docket No. RP15-584-000. This filing incorporated the revised fuel and lost and unaccounted-for and power cost tracker mechanisms filed in Docket No. RP14-1003. The FERC issued an order accepting the filing on March 26, 2015 and on April 9, 2015, accepted an errata to the February 27, 2015 filing reflecting a corrected rate for the Cheyenne Booster rate (PCT Reimbursement Charge).
Seneca Lateral Facilities Conversion – FERC Docket No. CP15-102-000
On March 2, 2015 in Docket No. CP15-102-000, Rockies Express filed with the FERC an application for (1) authorization to convert certain existing and operating pipeline and compression facilities located in Noble and Monroe Counties, Ohio (Seneca Lateral Facilities described in Docket Nos. CP13-539-000 and CP14-194-000) from Natural Gas Policy Act of 1978 Section 311 authority to NGANatural Gas Act ("NGA") Section 7 jurisdiction, and (2) issuance of a certificate of public convenience and necessity authorizing Rockies Express to operate and maintain the Seneca Lateral Facilities. On April 7, 2016, the FERC issued a Certificate to Rockies Express granting its requested authorizations and on June 1, 2016 Rockies Express commenced NGA service on the Seneca Lateral.
Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000
On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. The facilities increased the Rockies Express Zone 3 east-to-west mainline capacity by 0.8 Bcf/d. Pursuant to the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the project facilities. The project was placed in-service for the full 0.8 Bcf/d on January 6, 2017.
2016 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP16-702 and RP17-240
On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in Docket No. RP16-702. The FERC issued an order accepting the filing on March 25, 2016. On December 1, 2016, Rockies Express made an interim fuel tracker filing with a proposed effective date of January 1, 2017 in Docket No. RP17-240. The FERC issued an order accepting the filing on December 29, 2016.
Electric Power Charge Clarification - FERC Docket No. RP17-285
On December 21, 2016, in Docket No. RP17-285, Rockies Express proposed certain revisions to the General Terms and Conditions of its tariff to clarify that the electric power costs associated with the operation of gas coolers installed in association with the Zone 3 Capacity Enhancement Project at both electric and gas powered stations, will be included in the Power Cost Tracker. Several shippers submitted comments on the proposal. The FERC issued an order on January 19, 2017 accepting the proposed revisions permitting the recovery of electric power costs from the operation of both gas and electric powered compressor stations, subject to certain clarifications.
2017 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP17-401 and RP17-1064
On February 13, 2017,in Docket No. RP17-401, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2017. The FERC issued an order accepting the filing, including certain requested waivers, on March 21, 2017. On September 20, 2017, Rockies Express made its interim fuel tracker filing in Docket No. RP17-1064 with a proposed effective date of November 1, 2017. The FERC issued an order accepting the filing on October 18, 2017.
Increased Frequency of FL&U and PCT Adjustments - FERC Docket No. RP18-228
On December 1, 2017, in Docket No. RP18-228, Rockies Express made a filing with the FERC to increase the frequency in which it may adjust fixed fuel and lost and unaccounted for retainages and power cost tracker charges during the year so that its recovery of fixed fuel and lost and unaccounted for charges and power costs more closely track usage. Rockies Express proposed an effective date of April 1, 2018. The comment period ended on December 13, 2017, and no parties opposed Rockies Express’Express' filing. On April 4, 2018, the FERC issued a letter order accepting Rockies Express' proposal, subject to certain modifications. Rockies Express submitted a compliance filing reflecting the approved tariff provisions and requested modifications on April 10, 2018. No comments on the compliance filing were submitted by the comment deadline of April 16, 2018. On April 18, 2018, the FERC issued an order accepting Rockies Express' compliance filing effective April 19, 2018.
2018 Annual FERC Fuel Tracking Filing - FERC Docket No. RP18-453
On February 20, 2018, in Docket No. RP18-453, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2018. The matter isFERC issued an order accepting the filing on March 19, 2018.
Cheyenne Hub Enhancement Project - FERC Docket CP18-103
On March 2, 2018, Rockies Express submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity authorizing the construction and operation of certain booster compressor units and ancillary facilities located at the Cheyenne Hub in Weld County, Colorado that will enable Rockies Express to provide a new hub service allowing for firm receipts and deliveries between Rockies Express and certain other interconnected pipelines at the Cheyenne Hub. The comment period for the Cheyenne Hub Enhancement Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Rockies Express has also responded to data requests from FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment.
Rockies Express Form No. 501-G Filing - FERC Docket No. RP19-412
On December 6, 2018, Rockies Express submitted its one-time informational filing in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and FERC's changes to its Income Tax Policy Statement following the decision of the U.S. Court of Appeals for the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. The filing remains pending before the FERC.
10.11. Legal and Environmental Matters
Legal
In addition to the matters discussed below, Rockies Express is a defendant in various lawsuits arising from the day-to-day operations of its business. Although no assurance can be given, Rockies Express believes, based on its experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on its business, financial position, results of operations or cash flows.
Rockies Express has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and, accordingly, has recorded no reserve for legal claims as of December 31, 20172018 or 2016.2017.
Ohio Public Utility Excise Tax
The Ohio Tax Commissioner has assessed Rockies Express a public utility excise tax on transactions concerning product that entered and exited Rockies Express within the state of Ohio. This tax applies to gross receipts from all business conducted within the state, but exempts all receipts derived wholly from interstate business. Rockies Express has disputed any obligation to pay Ohio's public utility excise tax, but has paid the taxes as assessed in order to preserve its right to appeal. The dispute is currently pending before the Ohio Supreme Court, with a final decision possible by the end of 2019. It is Rockies Express' position that the relevant statute exempts receipts derived wholly from interstate business from the public utility excise tax. The Ohio Supreme Court and the United States Supreme Court have both held that, once it enters an interstate pipeline, natural gas is moving in "interstate commerce" for the duration of its journey until it is delivered to a local distribution system. As of December 31, 2018, Rockies Express has paid public utility excise taxes to the state of Ohio totaling $7.1 million and has accrued an additional $3.3 million for amounts expected to be assessed through the year ended December 31, 2018. While it is difficult to accurately predict how the Ohio Supreme Court will decide the case, Rockies Express is optimistic about the ultimate outcome and has recorded a $10.4 million asset representing the anticipated refund of the public utility excise taxes paid.
Mineral Management Service Lawsuit
On June 30, 2009, Rockies Express filed claims against Mineral Management Service, a former unit of the U.S. Department of Interior (collectively "Interior") for breach of its contractual obligation to sign transportation service agreements for pipeline capacity that it had agreed to take on Rockies Express. The Civilian Board of Contract Appeals ("CBCA") conducted a trial and ruled that Interior was liable for breach of contract, but limited the damages Interior was required to pay. On September 13, 2013, the United States Court of Appeals for the Federal Circuit issued a decision affirming that Interior was liable for its breach of contract, but reversing the CBCA's decision to limit damages. The case was remanded to the CBCA for the purpose of calculating damages at a hearing. On May 20, 2016, Rockies Express and Interior agreed to resolve the claims in this matter in exchange for a $65 million cash payment to Rockies Express. Interior paid the amount due Rockies Express on June 23, 2016.
Ultra Resources
In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2 Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14, 2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, seeking approximately $303 million in damages and other relief. On April 29, 2016, Ultra and certain of its debtor affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District of Texas, which operated as a stay of the Harris County state court proceeding.
On January 12, 2017, Rockies Express and Ultra entered into an agreement to settle Rockies Express' approximately $303 million claim against Ultra. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of $150 million on July 12, 2017, and entered into a new, seven-year firm transportation agreement with Rockies Express commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate of approximately $0.37 per dth/d, or approximately $26.8 million annually.
Michels Corporation
On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express in the Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due.
On February 2, 2017, Rockies Express and Michels agreed to resolve Michels' claims for a $10 million cash payment by Rockies Express. The cash payment was inclusive of approximately $5.9 million that Rockies Express had been withholding from Michels. Subsequently, Rockies Express and Michels entered into a definitive agreement with respect to the settlement and Rockies Express made the $10 million cash payment to Michels on February 16, 2017.
Environmental, Health and Safety
Rockies Express is subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. Rockies Express believes that compliance with these laws will not have a material adverse impact on its business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause Rockies Express to incur significant costs.
11. Subsequent Events
Subsequent events, which are events or transactions that occurred after December 31, 2017 through the issuance of the accompanying financial statements, have been evaluated through February 13, 2018.
Members' Equity
Rockies Express paid distributions of $43.9 million to its Members and received contributions from its Members of $1.3 million in January 2018.
Seneca Lateral
On January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations, however, theevacuations. The release required Rockies Express to shut off the flow through the segment. Repairs are underway to returnsegment until February 27, 2018, when temporary repairs were completed allowing the segment to service as soon as possiblebe placed back into service. Total cost of remediation was approximately $6.1 million prior to any insurance recoveries. Permanent repairs were completed in September 2018. As of February 8, 2019, Rockies Express has recovered a significant majority of these costs from insurance.
12. Subsequent Events
Subsequent events, which are events or transactions that occurred after December 31, 2018 through the issuance of the accompanying financial statements, have been evaluated through February 8, 2019.
Members' Equity
Rockies Express paid distributions of $46.3 million to its Members and a root cause investigation is ongoing. received contributions from its Members of $7.9 million in January 2019.
(2) Financial Statement Schedules
All schedules are omitted because they are either not applicable or the required information is shown in the Consolidated Financial Statements or notes thereto included in Item 8 of this Form 10-K.
(3) Exhibits
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| Exhibit No. | | Description |
| | Agreement and Plan of Merger, dated as of March 26, 2018, by and among Tallgrass Energy GP, LP, Tallgrass Equity, LLC, Razor Merger Sub, LLC, Tallgrass Energy Partners, LP and Tallgrass MLP GP, LLC (incorporated by reference to Exhibit 2.1 to Tallgrass Energy, LP’s Current Report on Form 8-K filed on March 27, 2018). |
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| | Agreement and Plan of Merger, dated as of February 7, 2018, by and among Tallgrass Energy GP, LP, Tallgrass Development, LP, Tallgrass Equity, LLC, Tallgrass Development Holdings, LLC and Tallgrass Energy Holdings, LLC (incorporated by reference to Exhibit 2.2 to Tallgrass Energy, LP’s Quarterly Report on Form 10-Q filed on May 3, 2018). |
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| | Certificate of Amendment to Limited PartnershipLiability Company Certificate of Tallgrass Energy Partners, LP,Formation of TEGP Management, LLC, dated as of February 6, 2013June 29, 2018 (incorporated by reference to Exhibit 3.1 to Tallgrass Energy, Partners, LP's Registration StatementCurrent Report on Form S-1 (File No. 333-187595)8-K filed March 28, 2013)on July 2, 2018). |
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| | Third Amended and Restated Limited Liability Company Agreement of Tallgrass Pony Express Pipeline, LLC, dated as of March 1, 2015, by and among Tallgrass Pony Express Pipeline, LLC, Tallgrass Operations, LLC, and Tallgrass PXP Holdings, LLC (incorporated by reference to Exhibit 10.2 to Tallgrass Energy Partners, LP's Current Report on Form 8-K filed on MarchJuly 2, 2015)2018). |
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| | Omnibus Agreement, dated May 12, 2015, by and among Tallgrass Energy Holdings, LLC, Tallgrass Energy GP, LP, TEGP Management, LLC and Tallgrass Equity, LLC (incorporated by reference to Exhibit 10.1 to Tallgrass Energy GP, LP's Current Report on Form 8-K filed May 12, 2015). |
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| | Second Amended and Restated Employment Agreement, dated November 2, 2016, by and among Tallgrass Management, LLC, Tallgrass Energy Holdings, LLC, Tallgrass Equity, LLC, Tallgrass MLP GP, LLC, TEGP Management, LLC and David G. Dehaemers, Jr. (incorporated by reference to Exhibit 10.4 to Tallgrass Energy Partners, LP's Annual Report on Form 10-K filed February 15, 2017). |
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| | Omnibus Agreement, dated May 17, 2013, by and among Tallgrass Development, LP, Tallgrass Energy Partners, LP, Tallgrass MLP GP, LLC and Tallgrass Development GP, LLC (incorporated by reference to Exhibit 10.2 to Tallgrass Energy Partners, LP's Current Report on Form 8-K filed May 17, 2013). |
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| | Amendment No. 1, dated June 25, 2014, to the Revolving Credit Agreement, dated May 17, 2013, by and among Tallgrass Energy Partners, LP, Barclays Bank PLC, as administrative agent, and a syndicate of lenders named therein (incorporated by reference to Exhibit 10.1 to Tallgrass Energy Partners, LP's Current Report on Form 8-K filed on June 30, 2014). |
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| | Contribution and Transfer Agreement, dated January 1, 2016, by and among Tallgrass Energy Partners, LP, Tallgrass Operations, LLC, and for certain limited purposes, Tallgrass Development, LP (incorporated by reference to Exhibit 10.14 to Tallgrass Energy Partners, LP's Annual Report on Form 10-K filed on February 17, 2016). |
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| | Assignment and Assumption Agreement, dated as of May 6, 2016, by and among Rockies Express Holdings, LLC, TEP REX Holdings, LLC and, for the limited purposes set forth therein, Tallgrass Development, LP (incorporated by reference to Exhibit 10.3 to the Partnership's Quarterly Report on Form 10-Q filed on August 3, 2016). |
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| | Second Amended and Restated Limited Liability Company Agreement of Rockies Express Pipeline LLC, dated effective as of January 1, 2010, among Rockies Express Holdings, LLC (as successor by assignment to Kinder Morgan W2E Pipeline LLC), TEP REX Holdings, LLC (as successor by assignment to Sempra REX Holdings, LLC and P&S Project I, LLC), and P66REX LLC (f/k/a COPREX LLC) (incorporated by reference to Exhibit 10.4 to the Partnership's Quarterly Report on Form 10-Q filed on August 3, 2016). |
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| | Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of Rockies Express Pipeline LLC, dated effective as of November 13, 2012, among Kinder Morgan W2E Pipeline LLC, TEP REX Holdings, LLC (as successor by assignment to Sempra REX Holdings, LLC and P&S Project I, LLC), Rockies Express Holdings, LLC and P66REX LLC (f/k/a COPREX LLC) (incorporated by reference to Exhibit 10.5 to the Partnership's Quarterly Report on Form 10-Q filed on August 3, 2016). |
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| | Omnibus Agreement, dated May 17, 2013, by and among Tallgrass Development, LP, Tallgrass Energy Partners, LP, Tallgrass MLP GP, LLC and Tallgrass Development GP, LLC (incorporated by reference to Exhibit 10.2 to Tallgrass Energy Partners, LP's Current Report on Form 8-K filed May 17, 2013). |
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| | Second Amended and Restated Credit Agreement, dated June 2, 2017, by and among Tallgrass Energy Partners, LP, Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders named therein (incorporated by reference to Exhibit 10.1 to Tallgrass Energy Partners, LP’s Quarterly Report on Form 10-Q filed on August 2, 2017). |
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| 101.INS* | | XBRL Instance Document. |
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| 101.SCH* | | XBRL Taxonomy Extension Schema Document. |
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| 101.CAL* | | XBRL Taxonomy Extension Calculation Linkbase Document. |
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| 101.DEF* | | XBRL Taxonomy Extension Definition Linkbase Document. |
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| 101.LAB* | | XBRL Taxonomy Extension Label Linkbase Document. |
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| 101.PRE* | | XBRL Taxonomy Extension Presentation Linkbase Document. |
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| † - | Management contract of compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to Item 15(b). |
Item 16. Form 10-K Summary
Not applicable.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Tallgrass Energy, GP, LP
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| By: | | TEGP Management,Tallgrass Energy GP, LLC, its general partner |
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| By: | | /s/ David G. Dehaemers, Jr. |
| | | David G. Dehaemers, Jr. |
| | | President and Chief Executive Officer of TEGP Management,Tallgrass Energy GP, LLC (the general partner of Tallgrass Energy, GP, LP) |
Date: February 13, 20188, 2019
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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| Name | | Title | | Date |
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| /s/ David G. Dehaemers, Jr. | | Director, President and Chief Executive Officer | | February 13, 20188, 2019 |
| David G. Dehaemers, Jr. | | (Principal Executive Officer) | | |
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| /s/ Gary J. Brauchle | | Executive Vice President and Chief Financial Officer | | February 13, 20188, 2019 |
| Gary J. Brauchle | | (Principal Financial Officer) | | |
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| /s/ Gary D. Watkins | | Vice President and Chief Accounting Officer | | February 13, 20188, 2019 |
| Gary D. Watkins | | (Principal Accounting Officer) | | |
| | | | | |
| /s/ Frank J. Loverro | | Director | | February 13, 20188, 2019 |
| Frank J. Loverro | | | | |
| | | | | |
| /s/ Stanley de J. Osborne | | Director | | February 13, 20188, 2019 |
| Stanley de J. Osborne | | | | |
| | | | | |
| /s/ Jeffrey A. Ball | | Director | | February 13, 20188, 2019 |
| Jeffrey A. Ball | | | | |
| | | | | |
| /s/ John T. Raymond | | Director | | February 13, 20188, 2019 |
| John T. Raymond | | | | |
| | | | | |
| /s/ William R. Moler | | Director | | February 13, 20188, 2019 |
| William R. Moler | | | | |
| | | | | |
| /s/ Thomas A. Gerke | | Director | | February 13, 20188, 2019 |
| Thomas A. Gerke | | | | |
| | | | | |
/s/ W. Curtis KoutelasRoy N. Cook | | Director | | February 13, 20188, 2019 |
W. Curtis KoutelasRoy N. Cook | | | | |
| | | | |
| /s/ Terrance D. Towner | | Director | | February 8, 2019 |
| Terrance D. Towner | | | | |
