UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________________________________
FORM 10-K
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934. |
For the fiscal year ended December 31, 2017
OR
| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 001-36635
__________________________________________________
CNX MIDSTREAM PARTNERS LP
(Exact name of registrant as specified in its charter)
| Delaware | 47-1054194 | |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
CNX Center, 1000 CONSOL Energy Drive
Canonsburg, PA 15317-6506
(724) 485-4000
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
__________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Name of exchange on which registered | |
Common Units 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 o No x
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 o 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 o
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 o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) 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, 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.
Large accelerated filer o Accelerated filer x Non-accelerated filer o Smaller Reporting Company o Emerging Growth Company x
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. x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
The aggregate market value of common units held by non-affiliates of the registrant as of June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter, was $382.8 million. This is based on the closing price of common units on the New York Stock Exchange on such date.
As of February 7, 2018, CNX Midstream Partners LP had 63,591,740 common units outstanding.
| Page | ||
| PART I | ||
| PART II | ||
| PART III | ||
| PART IV | ||
GLOSSARY OF CERTAIN OIL AND GAS MEASUREMENT TERMS
/d: Any abbreviation with this suffix signifies that the metric is per day.
Bbl or barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs or other liquid hydrocarbons.
BBtu: One billion British thermal units.
Bcfe: One billion cubic feet of natural gas equivalent, determined using a ratio of six thousand cubic feet of natural gas to one barrel of oil.
Btu: British thermal units.
condensate: A natural gas liquid with a low vapor pressure compared with natural gasoline and liquefied petroleum gas. Condensate is mainly composed of butane, propane, pentane and heavier hydrocarbon fractions. The condensate is not only generated into the reservoir, it is also formed when liquid drops out, or condenses, from a natural gas stream in pipelines or surface facilities.
DOT: The U.S. Department of Transportation.
dry gas: Natural gas that occurs in the absence of condensate or liquid hydrocarbons, or natural gas that has had condensable hydrocarbons removed.
EPA: The U.S. Environmental Protection Agency.
FERC: The U.S. Federal Energy Regulatory Commission.
field: The general area encompassed by one or more oil or gas reservoirs or pools that are located on a single geologic feature, that are otherwise closely related to the same geologic feature (either structural or stratigraphic).
high-pressure pipelines: Pipelines gathering or transporting natural gas that has been dehydrated and compressed to the pressure of the downstream pipelines or processing plants.
hydrocarbon: An organic compound containing only carbon and hydrogen.
low-pressure pipelines: Pipelines gathering natural gas at or near wellhead pressure that has yet to be compressed (other than by well pad gas lift compression or dedicated well pad compressors) and dehydrated.
MBbl: One thousand Bbls.
Mcf: One thousand cubic feet of natural gas.
MMBtu: One million British thermal units.
MMcf: One million cubic feet of natural gas.
MMcfe: One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
natural gas: Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.
NGLs: Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane and natural gasoline.
oil: Crude oil and condensate.
SEC: The U.S. Securities and Exchange Commission.
Tcfe: One trillion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
throughput: The volume of product transported or passing through a pipeline, plant, terminal or other facility.
wet gas: Natural gas that contains less methane (typically less than 85% methane) and more ethane and other more complex hydrocarbons.
3
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words “believe,” “expect,” “anticipate,” “intend,” “estimate” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters identify forward-looking statements. Our forward-looking statements include statements about our business strategy, our industry, our future profitability, our expected capital expenditures and the impact of such expenditures on our performance, the costs of being a publicly traded partnership and our capital programs.
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. You are cautioned not to place undue reliance on any forward-looking statement, as these statements involve risks, uncertainties and other factors that could cause our actual future outcomes to differ materially from those set forth in such 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 reliance on our customers, including our Sponsor; |
| • | the effects of changes in market prices of natural gas, NGLs and crude oil on our customers’ drilling and development plans on our dedicated acreage and the volumes of natural gas and condensate that are produced on our dedicated acreage; |
| • | changes in our customers’ drilling and development plans in the Marcellus Shale and Utica Shale; |
| • | our customers’ ability to meet their drilling and development plans in the Marcellus Shale and Utica Shale; |
| • | the demand for natural gas and condensate gathering services; |
| • | changes in general economic conditions; |
| • | competitive conditions in our industry; |
| • | actions taken by third-party operators, gatherers, processors and transporters; |
| • | our ability to successfully implement our business plan; |
| • | our ability to complete internal growth projects on time and on budget; |
| • | the price and availability of debt and equity financing; |
| • | the availability and price of oil and natural gas 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 our midstream services; |
| • | natural disasters, weather-related delays, casualty losses and other matters beyond our control; |
| • | interest rates; |
| • | labor relations; |
| • | defaults by our customers under our gathering agreements; |
| • | changes in availability and cost of capital; |
| • | changes in our tax status; |
| • | the effect of existing and future laws and government regulations; |
| • | the effects of future litigation; and |
| • | certain factors discussed elsewhere in this report. |
You should not place undue reliance on our forward-looking statements. Although forward-looking statements reflect our good faith beliefs at the time they are made, forward-looking statements involve known and unknown risks, uncertainties and other factors, including the factors described under “Risk Factors” of Item 1A of Part I in this report, which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.
4
PART I
| ITEM 1. | BUSINESS |
Unless otherwise indicated, references in this Annual Report on Form 10-K to the “Predecessor,” “we,” “our,” or “us” or like terms, when referring to period prior to September 30, 2014, refer to CNX Gathering LLC (formerly known as CONE Gathering LLC) (“CNX Gathering”) our predecessor for accounting purposes. References to the “Partnership,” “we,” “our,” “us” or similar expressions, when referring to periods since September 30, 2014, refer to CNX Midstream Partners LP (formerly known as CONE Midstream Partners LP), including its consolidated subsidiaries.
Overview
We are a growth-oriented master limited partnership focused on the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets to service our customers’ production in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. Our assets include natural gas gathering pipelines and compression and dehydration facilities, as well as condensate gathering, collection, separation and stabilization facilities. We are managed by our general partner, CNX Midstream GP LLC, formerly known as CONE Midstream GP LLC (our “general partner”), a wholly owned subsidiary of CNX Gathering. CNX Gathering is a wholly owned subsidiary of CNX Resources Corporation, formerly known as CONSOL Energy Inc. (NYSE: CNX)(“CNX”).
We were formed in May 2014 as a joint venture between CNX and Noble Energy, Inc. (NYSE: NBL) (“Noble Energy”). On January 3, 2018, CNX Gas Company LLC (“CNX Gas”), an indirect wholly owned subsidiary of CNX, acquired from NBL Midstream, LLC (“NBL Midstream”), a wholly owned subsidiary of Noble Energy, NBL Midstream’s 50% interest in CNX Gathering. CNX became our sole sponsor as a result of this transaction, and we refer to CNX as our “Sponsor” throughout this Annual Report on Form 10-K. Please read “Developments and Highlights—CNX Gas and NBL Midstream Transaction” beginning on page 6 for more information related to CNX Gas’ acquisition of NBL Midstream’s indirect interest in our general partner.
We generate substantially all of our revenues under long-term, fixed-fee gathering agreements with CNX and HG Energy II Appalachia, LLC (“HG Energy”), to whom Noble Energy assigned its gathering agreement with us, that are intended to mitigate our direct commodity price exposure and enhance the stability of our cash flows. Please read “Developments and Highlights—Noble Energy Sale of Upstream Assets” beginning on page 6 for more information related to the assignment of the Noble Energy gathering agreement. The gathering agreements with CNX and HG Energy currently include acreage dedications of approximately 513,000 aggregate net acres, subject to the release provisions set forth therein. Although CNX and HG Energy currently account for substantially all our revenues, we intend to supplement our profitability and future growth by pursuing opportunities to perform gathering services for other unrelated third parties in the future. In addition, we also consider accretive acquisitions, which may include drop downs of additional interests in our existing consolidated assets.
Over the last five years, the Partnership has turned in line over 400 wells in our Marcellus Shale dedication area, which contributed to average combined daily gross wellhead production of approximately 1,266 BBtu/d in 2017. Please read “Our Acreage Dedication and Right of First Offer Assets” beginning on page 10 for more information.
The following charts illustrate our production trends and well turn in line activity on our dedicated acreage for the periods indicated:
(1) Represents gross wellhead production attributable to wells drilled on our dedicated acreage.
(2) Represents total gross wells turned in line on our dedicated acreage.
5
Developments and Highlights
Noble Energy Sale of Upstream Assets
On June 28, 2017, Noble Energy sold its upstream assets in northern West Virginia and southern Pennsylvania to HG Energy, a portfolio company of Quantum Energy Partners, LP, effectively making HG Energy the new shipper on the dedicated acreage that was previously owned by Noble Energy (the “Noble Energy Asset Sale”). The Partnership currently gathers the natural gas and condensate volumes produced by HG Energy on our dedicated acreage under the terms of our gathering agreement with Noble Energy, which was assigned to HG Energy by Noble Energy upon consummation of the Noble Energy Asset Sale.
In connection with the Noble Energy Asset Sale, Noble Energy provided notice to the Partnership of its release of approximately 37,000 undeveloped acres, which were primarily within the Growth and Additional Systems, from amounts dedicated to us as per the terms of our gathering agreement. The Partnership is in the process of confirming the dedication status of the acres that were released.
Conversion of Subordinated Units
On October 19, 2017, the board of directors of our general partner declared a quarterly cash distribution of $0.3025 per unit for the quarter ended September 30, 2017. The distribution was paid on November 14, 2017 to unitholders of record as of the close of business on November 3, 2017. Upon payment of this distribution, the requirements for the conversion of all subordinated units were satisfied under our partnership agreement. As a result, on November 15, 2017, all 29,163,121 subordinated units, which were owned entirely by CNX and Noble Energy in the aggregate, converted into common units on a one-for-one basis and thereafter will participate on terms equal with all other common units in distributions from available cash.
CNX Gas and NBL Midstream Transaction
On January 3, 2018, CNX Gas acquired NBL Midstream’s 50% membership interest in CNX Gathering for cash consideration of $305.0 million and the mutual release of all outstanding claims between the parties (the “Transaction”). In connection with the Transaction, CNX Gas entered into new 20-year fixed-fee gathering agreement with the Partnership. Please read “Our Gathering Agreements with CNX Gas and HG Energy” beginning on page 11 for more information. As a result of the Transaction, CNX, as the sole member of CNX Gas, owns 100% of the membership interest in CNX Gathering. CNX also became our sole Sponsor.
Noble Energy continues to own 21,692,198 common units representing limited partner interests in the Partnership (the “Retained Units”); however, Noble Energy has announced its intention to divest of the Retained Units over the next few years. In connection with the closing of the Transaction, we entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Noble Energy relating to the registered resale of common units that Noble acquired in connection with our initial public offering in September 2014 (our “IPO”) and upon conversion of subordinated units representing limited partner interests in the Partnership (collectively, the “Registrable Securities”). Pursuant to the Registration Rights Agreement, the Partnership is required to prepare and file a registration statement, or amend an existing registration statement, for the registered resale of the Registrable Securities and to use commercially reasonable efforts to cause such registration statement to become effective as soon as practicable after the Partnership’s release of earnings for the year ended December 31, 2017.
In certain circumstances, and subject to customary qualifications and limitations, Noble Energy will have piggyback registration rights on offerings of common units initiated by the Partnership and other holders of common units. Noble will also have the right to request that the Partnership initiate up to four Demand Underwritten Offerings (as defined in the Registration Rights Agreement) of Registrable Securities, subject to certain limitations described in the Registration Rights Agreement. The Registration Rights Agreement will terminate no later than the third anniversary of the date on which the registration statement becomes effective.
In connection with the closing of the Transaction, we changed our name to CNX Midstream Partners LP and, effective January 4, 2018, our common units are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “CNXM.”
6
Organizational Structure (*)
(*) As of January 4, 2018, immediately following the Transaction.
7
Our Midstream Assets
In order to effectively manage our business we have divided our current midstream assets among three separate operating segments that we refer to as our “Anchor Systems,” “Growth Systems” and “Additional Systems” based on their relative current cash flows, growth profiles, capital expenditure requirements and stages of their development.
| • | Our Anchor Systems include our most developed midstream systems that generate the largest portion of our current cash flows, which includes our three primary midstream systems (the McQuay System, the Majorsville System and the Mamont System) and related assets. |
| • | Our Growth Systems are primarily located in the dry gas regions of our dedicated acreage that are generally in earlier phases of development and require substantial future expansion capital expenditures to materially increase production, which would primarily be funded by CNX in proportion to CNX Gathering’s 95% retained ownership interest. |
| • | Our Additional Systems include several gathering systems primarily located in the wet gas regions of our dedicated acreage that we expect will require lower levels of expansion capital investment relative to our Growth Systems. The substantial majority of capital investment on these systems would primarily be funded by CNX in proportion to CNX Gathering’s 95% retained ownership interest. |
In order to maintain operational flexibility, our operations are conducted through, and our operating assets are owned by, our operating subsidiaries. However, neither we nor our operating subsidiaries have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by CNX or others. All of the personnel that conduct our business are employed or contracted by our general partner and its affiliates, including CNX, but we sometimes refer to these individuals as our employees because they provide services directly to us.
8
The following map details our existing assets:
9
Gathering Assets and Compression and Dehydration Facilities
We operated 18 facilities to provide our compression and/or dehydration services as of December 31, 2017. The following table provides information regarding our gathering assets and compression and dehydration facilities as of December 31, 2017:
| System | Pipelines (in miles) | Average Daily Throughput (BBtu/d) | Maximum Interconnect Capacity(1)(2) (BBtu/d) | Compression (horsepower) | Compression Capacity (BBtu/d) | |||||
| Anchor Systems | 177 | 972 | 1,429 | 77,830 | 1,262 | |||||
| Growth Systems | 31 | 51 | 860 | 6,700 | 80 | |||||
| Additional Systems | 52 | 243 | 445 | 9,480 | 160 | |||||
| 260 | 1,266 | 2,734 | 94,010 | 1,502 | ||||||
(1) Maximum interconnect capacity is the maximum throughput that can be delivered from the system through physical interconnections to third-party facilities or pipelines.
(2) Our midstream systems currently have interconnects with the following interstate pipelines: Columbia Gas Transmission, Texas Eastern Transmission and Dominion Transmission, Inc.
Condensate Handling Facilities
Our assets include condensate handling facilities in Majorsville, Pennsylvania (Anchor Systems) and Moundsville, West Virginia (Additional Systems) that provide condensate gathering, collection, separation and stabilization services. Each facility has nominal handling capacities of 2,500 Bbl/d.
Our Relationship with CNX and CNX Gathering
CNX, our sole Sponsor following the Transaction, is a Pittsburgh-based natural gas exploration and production company, focusing on the major shale formations of the Appalachian Basin, including the Marcellus Shale and Utica Shale. CNX deploys an organic growth strategy focused on developing its resource base.
Following the Transaction, CNX owns a 100% interest in CNX Gathering, which owns our general partner as well as noncontrolling limited partner interests in two of our operating subsidiaries, which we refer to as our Growth and Additional Systems. Through our ownership of all of the outstanding general partner interests in our operating subsidiaries, the Partnership has voting control over, and the exclusive right to manage, the day-to-day operations, business and affairs of our midstream systems. CNX Gathering retained noncontrolling interests in our operating subsidiaries that are subject to our right of first offer. Following our purchase in November 2016 of the remaining 25% noncontrolling interest in the Anchor Systems, which include our most developed systems, we own a 100% controlling interest in the Anchor Systems.
CNX Gathering continues to own 95% noncontrolling interests in each of the Growth Systems and the Additional Systems. CNX Gathering’s retention of ownership interests in the Growth Systems and the Additional Systems, combined with our right of first offer on those interests, may provide opportunities for us to grow our distributable cash flow through a series of acquisitions of these retained interests over time. However, CNX Gathering is under no obligation to offer to sell us any assets (including our right of first offer assets, unless and until it otherwise intends to dispose of such assets), and we are under no obligation to buy any assets from CNX Gathering. In addition, we do not know when or if CNX Gathering will make any offers to sell assets to us.
Our Acreage Dedication and Right of First Offer Assets
As of January 3, 2018, the date of the Transaction, our existing dedicated acreage covered approximately 513,000 aggregate net acres, subject to the release provisions set forth in our gas gathering agreements. Our gathering agreement with CNX Gas, which was amended and restated on January 3, 2018, and our gathering agreement with Noble Energy, which became effective on December 1, 2016 and was assigned to HG Energy on June 28, 2017, provide that, in addition to our existing dedicated acreage, any future acreage covering the Marcellus Shale formation that is acquired by CNX Gas or HG Energy (or was acquired by Noble Energy prior to the effective date of the assignment to HG Energy,) in an area that covers over 7,700 square miles in West Virginia and Pennsylvania, which we refer to as the “dedication area,” and that is not subject to a pre-existing third-party commitment automatically will be dedicated to us for natural gas midstream services, subject to the release provisions set forth in each agreement.
In addition to the initial assets contributed to us in connection with our IPO, CNX Gathering has granted us a right of first offer (“ROFO”) to acquire (i) CNX Gathering’s retained interests in our Growth Systems and Additional Systems, (ii) CNX Gathering’s other ancillary midstream assets and (iii) any additional midstream assets that CNX Gathering develops, before
10
CNX Gathering sells any of those interests to any third party during the ten-year period following the completion of our IPO (the “right of first offer period”). CNX Gathering is under no obligation to offer to sell us any assets (including our right of first offer assets, unless and until it otherwise intends to dispose of such assets), and we are under no obligation to buy any assets from CNX Gathering. In addition, we do not know when or if CNX Gathering will make any offers to sell assets to us. While we believe our rights of first offer are significant positive attributes, they may also be sources of conflicts of interest. CNX Gathering owns our general partner, and there is substantial overlap between the officers and directors of our general partner and the officers and directors of CNX. Please read “Risk Factors — Risks Inherent in an Investment in Us—We do not have any officers or employees and rely on officers of our general partner and employees of CNX.”
We have also been granted rights of first offer by each of CNX and HG Energy (as successor to Noble Energy’s obligations under the assigned gas gathering agreement) to provide midstream services on their respective ROFO acreage, which currently includes approximately 198,000 aggregate net acres of CNX Gas’ and HG Energy’s combined existing Marcellus Shale acreage that is not currently dedicated to us, along with any future acreage covering the Marcellus Shale formation that is acquired by CNX Gas or HG Energy, as applicable, in an area that covers over 18,300 square miles in West Virginia and Pennsylvania, which we refer to as the “ROFO area,” and that is not subject to a pre-existing third-party commitment. There are no restrictions under our gathering agreements (discussed below) on the ability of CNX Gas or HG Energy to transfer acreage in the ROFO area, and any such transfer of acreage in the ROFO area will not be subject to our right of first offer.
Our Gathering Agreements with CNX Gas and HG Energy
On January 3, 2018, we entered into a new 20-year, fixed-fee gathering agreement with CNX Gas that amended and restated the previous gathering agreement with CNX Gas in its entirety. Although the fees for services we provide in the Marcellus Shale for existing wells that were covered under the prior agreement remain unchanged in the new agreement, and are identical to the fees we charge to HG Energy (discussed below), the new gas gathering agreement with CNX Gas also dedicates an additional 63,000 of acreage in the Utica Shale in and around the McQuay area and Wadestown area and introduces the following gas gathering and compression rates:
•Gas Gathering:
| ◦ | McQuay area Utica - a fee of $0.225 per MMBtu; and |
| ◦ | Wadestown Marcellus and Utica - a fee of $0.35 per MMBtu. |
| • | Compression: |
| ◦ | For areas not benefitting from system expansion pursuant to the Second Amended and Restated gas gathering agreement, compression services are included in the base fees; and |
| ◦ | In the McQuay and Wadestown areas, for wells turned in line beginning January 1, 2018 and beyond, we will receive additional fees of $0.065 per MMBtu for Tier 1 pressure services (maximum receipt point of pressure of 600 psi) and $0.130 per MMBtu for Tier 2 pressure services (maximum receipt point of pressure of 300 psi). |
Our new gathering agreement with CNX Gas also commits CNX Gas to drill the following numbers of wells in the McQuay area, provided that if 125 wells have been drilled and completed in the Marcellus Shale, then the remainder of such planned wells must be drilled in the Utica Shale. To the extent the requisite amount of wells are not drilled by CNX Gas in a given period, we will be entitled to a deficiency payment per shortfall well as set out in the parenthetical below:
| • | January 1, 2018 to December 31, 2018 - 30 wells (deficiency payment of $3.5 million per well) |
| • | January 1, 2019 to April 30, 2020 - 40 wells (deficiency payment of $3.5 million per well) |
| • | May 1, 2020 to April 30, 2021 - 40 wells (deficiency payment of $2.0 million per well) |
| • | May 1, 2021 to April 30, 2022 - 30 wells (deficiency payment of $2.0 million per well) |
In the event that CNX Gas drills wells and completes a number of wells in excess of the number of wells required to be drilled and completed in such period, (i) the number of excess wells drilled and completed during such period will be applied to the minimum well requirement in the succeeding period or (ii) to the extent CNX Gas was required to make deficiency payments for shortfalls in the preceding period, CNX Gas may elect to cause the Partnership to pay a refund in an amount equal to (x) the number of excess wells drilled and completed during the period, multiplied by (y) the deficiency payment paid per well during the period in which the shortfall occurred.
On December 1, 2016, we entered into new fixed-fee gathering agreements with Noble Energy and CNX Gas that replaced the gathering agreements that had been in place since our IPO. Our gathering agreement with Noble Energy was assigned to HG Energy upon consummation of the Noble Energy Asset Sale effective June 28, 2017. The terms of the agreement remain unchanged following the assignment, except as it relates to HG Energy’s inability to, without the Partnership’s consent, release dedicated acreage in connection with a transfer of such acreage free of the dedication to us, and
11
exercise other initial shipper rights provided under the gathering agreement. Under the gathering agreements with HG Energy and CNX Gas, we receive a fee based on the type and scope of the midstream services we provide, summarized as follows effective January 1, 2018:
| • | For the services we provide with respect to natural gas from the Marcellus Shale formation that does not require downstream processing, or dry gas, we receive a fee of $0.431 per MMBtu. |
| • | For the services we provide with respect to the natural gas that requires downstream processing, or wet gas, we receive: |
| ◦ | a fee of $0.296 per MMBtu in the Moundsville area (Marshall County, West Virginia); |
| ◦ | a fee of $0.296 per MMBtu in the Pittsburgh International Airport area; and |
| ◦ | a fee of $0.593 per MMBtu for all other areas in the dedication area. |
| • | Our fees for condensate services were $5.38 per Bbl in the Majorsville area and $2.693 per Bbl in the Moundsville area. |
Each of the foregoing fees paid by CNX Gas or HG Energy, as applicable, escalates by 2.5% on January 1 on an annual basis, through and including the final calendar year of the initial term. Commencing on January 1, 2035, and as of January 1 thereafter, each of the applicable fees will be adjusted pursuant to the percentage change in CPI-U, but such fees will never escalate or decrease by more than 3%. Notwithstanding the foregoing, from time to time, CNX Gas and HG Energy may request rate reductions under certain circumstances, which are reviewed by the board of directors of our general partner, with oversight, as our board of directors deems necessary, by our conflicts committee. No rate reduction arrangements are currently active.
We provide gas gathering services to CNX Gas and HG Energy for their dedicated natural gas in the Marcellus Shale on a first-priority basis and gather and/or stabilize and store all of CNX Gas’ and HG Energy’s dedicated condensate on a first-priority basis in the Moundsville, Majorsville and Pittsburgh International Airport areas, subject to certain exceptions described in our respective gathering agreements.
We receive ongoing updates from our customers regarding their drilling and development operations, which include detailed descriptions of the drilling plans, production details and well locations for periods that range from up to 24-48 months, as well as more general development plans that may extend as far as ten years. In addition, we regularly meet with CNX Gas and HG Energy to discuss our current plans to timely construct the necessary facilities to be able to provide midstream services to each of them on our dedicated acreage. In the event that we do not perform our obligations under a gathering agreement, CNX Gas or HG Energy, as applicable, will be entitled to certain rights and procedural remedies thereunder, including rate reductions, the temporary and/or permanent release from dedication discussed below and indemnification from us.
In addition to the natural gas and condensate that is produced from the dedicated acreage, CNX Gas or HG Energy may each elect to dedicate non-Marcellus Shale properties located in the dedication area to us in which the shipper has an interest. If a shipper elects to dedicate any such property, then that shipper will propose a fee for the associated midstream services we would provide. So long as the proposed fee generates a rate of return consistent with the shipper’s existing gathering agreement on both incremental capital and operating expense associated with any expenditures necessary to gather gas from such property, any midstream services that we agree to provide will be on a second priority basis; second only to the first priority basis afforded to each of CNX Gas and HG Energy on their respective dedicated production.
Our gathering agreements with HG Energy and, in the event that CNX ceases to control our general partner, CNX Gas provide that if we fail to timely complete the construction of the facilities necessary to provide midstream services as defined in our respective gathering agreements to a shipper’s dedicated acreage or have an uncured default of any of our material obligations that causes a delay or interruption in our services, we are subject to monetary penalties and/or the affected acreage may be permanently released from our dedication. Any permanent releases of CNX Gas’ or HG Energy’s acreage from our dedication could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
Our gathering agreements also provide that in certain situations, such as an uncured default of any of our material obligations under the gathering agreement for more than 45 days but less than 90 days, our dedicated acreage can be temporarily released from our dedication. In addition, if we interrupt or curtail the receipt of CNX Gas’ or HG Energy’s gas under certain conditions for a period of five consecutive days or more than seven days within any consecutive two week period, then the applicable shipper can temporarily release from the dedication under its gathering agreement the affected volumes for a period lasting until the first day of the month following 30 days after our notice to the shipper that the interruption or curtailment has ended. Although there have not been any such instances to date, any temporary releases of acreage from our dedication could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
12
Upon completion of their initial 20-year terms, each of our gathering agreements with CNX Gas and HG Energy will continue in effect from year to year until such time as the agreement is terminated by either us or the other party to such agreement on or before 180 days prior written notice.
Third-Party Services and Commitments
CNX Gas and HG Energy (as successor to Noble Energy’s obligations under the assigned gas gathering agreement) have entered into agreements that impact the scope of certain services we provide and the fees we charge under our gathering agreements. Although we provide all field gathering in the following areas, we do not provide compression, dehydration and condensate stabilization services with respect to (i) approximately 3,500 net acres in the Moundsville area (Marshall County, West Virginia) and (ii) approximately 9,000 net acres in the Pittsburgh International Airport area (Allegheny County, Pennsylvania). With respect to these areas, CNX Gas and HG Energy have contracted with third parties for the provision of such services. Accordingly, we charge our shippers a reduced fee for the services we provide with respect to all natural gas and condensate produced from these areas.
Title to Our Properties
Our real property interests are acquired pursuant to easements, rights-of-way, permits, surface use agreements, deeds or licenses from landowners, lessors, easement holders, governmental authorities, or other parties controlling surface estate (collectively, “surface agreements”). These surface agreements allow us to use such land for our operations. Thus, the real estate interests on which our pipelines and facilities are located are held by us as grantee, and the party who owns or controls the surface lands, as grantor. We have acquired these surface agreements without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory rights and interests to conduct our operations on such lands. We have no knowledge of any challenge to the underlying title of any material surface agreements held by us or to our title to any material surface agreements, and we believe that we have satisfactory title to all of our material surface agreements.
Some of the surface agreements that were transferred to us from CNX Gathering required the consent of the grantor or other holder of such rights. CNX Gathering obtained sufficient third-party consents and authorizations and provided notices required for the transfer of the assets necessary to enable us to operate our business in all material respects. With respect to any remaining consents, authorizations or notices that have not been obtained or provided, we have determined these will not have a material adverse effect on the operation of our business should the Partnership or CNX Gathering fail to obtain or provide such consents, authorizations or notices in a reasonable time frame.
Seasonality
Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand fluctuations. These seasonal anomalies can increase demand for natural gas during the summer and winter months and decrease demand for natural gas during the spring and fall months. With respect to our completed midstream systems, we do not expect seasonal conditions to have a material impact on our throughput volumes. Severe or prolonged winters may, however, impact our ability to complete additional well connections or complete construction projects, which may impact the rate of our growth. In addition, severe winter weather may also impact or delay the execution of our customers’ drilling and development plans.
Competition
As a result of our acreage dedications from CNX Gas and HG Energy, we do not compete for the portion of the existing operations of CNX Gas’ and HG Energy’s upstream operations for which we currently provide midstream services, and other than with respect to acreage that may be released, subject to the terms of our gas gathering agreements, we will not compete for future portions of their upstream operations that are dedicated to us pursuant to our gathering agreements. Please read “Our Gathering Agreements and Rights of First Offer Assets.” Nonetheless, CNX Gas and HG Energy have entered into agreements with third parties for the provision of certain midstream services. Please read “Third-Party Services and Commitments.” In addition, we face competition in attracting third-party volumes to our midstream systems, and these third parties may develop their own midstream systems in lieu of employing our assets.
Regulation of Operations
Regulation of pipeline gathering services may affect certain aspects of our business and the market for our services.
Natural Gas Gathering Pipeline Regulation
Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”) under the NGA. Although FERC has not made any formal determinations with
13
respect to any of our facilities we consider to be gathering facilities, we believe that the natural gas gathering pipelines meet the traditional tests FERC has used to establish that a natural gas pipeline is a gathering pipeline not subject to FERC NGA jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gas gathering facilities on a case-by-case basis, so the classification and regulation of some our gas gathering facilities may be subject to change based on future determinations by FERC, the courts, or Congress. If FERC were to consider the status of an individual facility and determine that the facility is not a gas gathering pipeline and the pipeline provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA and/or the Natural Gas Policy Act (“NGPA”). Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such service in excess of the rate established by FERC.
State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. States in which we operate may adopt ratable take and common purchaser statutes, which would require our gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one source of supply over another similarly situated source of supply. The regulations under these statutes may have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. States in which we operate may also adopt a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such regulation will be adopted and whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, our midstream systems have not been adversely affected by recent state regulations.
Our gathering operations could be adversely affected should they be subject in the future to more stringent application of state regulation of rates and services. Our gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Pipeline Safety Regulation
Some of our natural gas pipelines are subject to regulation by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968, (“NGPSA”), as amended by the Pipeline Safety Act of 1992 (“PSA”), the Accountable Pipeline Safety and Partnership Act of 1996 (“APSA”), the Pipeline Safety Improvement Act of 2002 (“PSIA”), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (“PIPES Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas (“HCAs”).
PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including us, to:
| • | perform ongoing assessments of pipeline integrity; |
| • | identify and characterize applicable threats to pipeline segments that could impact a HCA; |
| • | improve data collection, integration and analysis; |
| • | repair and remediate pipelines as necessary; and |
| • | implement preventive and mitigating actions. |
The 2011 Pipeline Safety Act reauthorized funding for federal pipeline safety programs, increased penalties for safety violations, established additional safety requirements for newly constructed pipelines, and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. In 2017, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $209,002
14
per violation per day, with a maximum of $2,909,022 for a related series of violations. In January 2017, in the final weeks of the Obama Administration, PHMSA released a pre-publication copy of its final hazardous liquid pipeline safety regulations that would significantly extend the integrity management requirements to previously exempt pipelines and would impose additional obligations on hazardous liquid pipeline operators that are already subject to the integrity management requirements, including periodic integrity assessments and leak detecting for pipelines outside of HCAs, inspecting of pipelines after extreme weather events, expanded reporting, and more stringent integrity management repair and data collection requirements. PHMSA issued a separate regulatory proposal in July 2015 that would impose pipeline incident prevention and response measures on natural gas and hazardous liquid pipeline operators. PHMSA also issued an advisory bulletin providing guidance on the verification of records related to pipeline maximum allowable operating pressure.
The National Transportation Safety Board (“NTSB”) has recommended that PHMSA make a number of changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines installed before 1970. In April 2016, PHMSA published in the Federal Register a Notice of Proposed Rule Making (“NPRM”) that would significantly modify existing regulations related to reporting, impact, design, construction, maintenance, operations and integrity management of gas transmission and gathering pipelines. The proposed rule addresses four congressional mandates and six recommendations by the NTSB to broaden the scope of safety coverage by adding new assessment and repair criteria for gas transmission pipelines, and by expanding these protocols to include pipelines not formerly regulated by the federal standards. This includes extending regulatory requirements to transmission and gathering pipelines of eight inches and greater in rural Class I areas. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. Also, compliance with the rule, as proposed, may prove challenging and costly for operators of older pipelines due to the difficulty of locating historic records. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, the ultimate impact of the rule on the Partnership remains uncertain until the rulemaking is finalized. PHMSA is expected to finalize its natural gas pipeline safety rule this year.
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the Department of Transportation (“DOT”), to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include more stringent requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.
We have incorporated all existing requirements into our programs by the required regulatory deadlines and are continually incorporating the new requirements into procedures and budgets. We expect to incur increasing regulatory compliance costs based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above. In addition to regulatory changes, costs may be incurred when there is an accidental release of a commodity transported by our midstream systems, or a regulatory inspection identifies a deficiency in our required programs.
Regulation of Environmental and Occupational Safety and Health Matters
General
Our natural gas gathering and compression activities are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment and worker health and safety. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
| • | requiring the installation of pollution-control equipment, imposing emission or discharge limits or otherwise restricting the way we operate; |
| • | limiting or prohibiting construction activities in areas, such as air quality non-attainment areas, wetlands, endangered species habitat and other protected areas; |
| • | delaying system modification or upgrades during review of permit applications and revisions; |
| • | requiring investigatory and remedial actions to mitigate discharges, releases or pollution conditions associated with our operations or attributable to former operations; and |
| • | enjoining operations deemed to be in non-compliance with permits issued pursuant to or regulatory requirements imposed by such environmental laws and regulations. |
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and/or criminal enforcement measures, including the assessment of monetary penalties and natural resource damages. Certain environmental
15
statutes impose strict or joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or solid wastes have been disposed or otherwise released. Moreover, neighboring landowners and other third parties may file common law claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other pollutants into the environment.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and thus, 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 different from the amounts we currently anticipate. As with the midstream industry in general, complying with current and anticipated environmental laws and regulations can increase our capital costs to construct, maintain and operate equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we do not believe they will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various activities in which we are presently engaged that are subject to environmental laws and regulations are not expected to materially interrupt or diminish our operational ability to gather natural gas. We cannot assure, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business.
Hydraulic Fracturing Activities
Although we do not conduct hydraulic fracturing operations, substantially all CNX Gas and HG Energy natural gas production on our dedicated acreage is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the well completion process. Hydraulic fracturing is an essential and common practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process is typically regulated by state oil and natural gas commissions, but the U.S. Environmental Protection Agency (“EPA”) has asserted certain regulatory authority over hydraulic fracturing and has moved forward with various regulatory actions, including the issuance of new regulations requiring green completions for hydraulically fractured wells, emission requirements for certain midstream equipment, and an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances and Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing.
Scrutiny of hydraulic fracturing activities continues in other ways. In June 2015, the EPA issued its draft report on the potential impacts of hydraulic fracturing on drinking water and groundwater. The draft report found no systemic negative impacts from hydraulic fracturing. In December 2016, the EPA released its final report on the impacts of hydraulic fracturing on drinking water. While the language was changed and included the possibility of negative impacts from hydraulic fracturing, it also included the guidance to industry and regulators on how the process can be performed safely. The Bureau of Land Management (“BLM”) also published a final rule in March 2015 that regulates hydraulic fracturing on federal and Indian lands. The BLM rule was challenged in U.S. federal court, struck down, and subsequently appealed. A U.S. federal appeals court ruling in September 2017 dismissed the appeal and vacated the trial court’s decisions. The rule is currently subject to a July 2017 proposal by BLM to rescind it.
Some states, including states in which we operate have adopted, and other states are considering adopting, laws and/or regulations that could impose more stringent permitting, disclosure and well construction requirements on natural gas drilling activities. 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, or otherwise seek to ban some or all of these activities.
We cannot predict whether any other legislation or regulations will be enacted and if so, what its provisions will be. Additional levels of regulation and/or permits required through the adoption of new laws and regulations at the federal, state or local level could lead to delays, increased operating costs and prohibitions for producers who drill near our pipelines, reduce the volumes of natural gas available to move through our midstream systems and materially adversely affect our revenue and results of operations.
Hazardous Waste
Our operations generate solid wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state laws, which impose requirements for the handling, storage, treatment and disposal of non-hazardous and hazardous waste. RCRA currently exempts certain wastes associated with the exploration, development or production of natural gas, which we handle in the course of our operation, including produced water. However, these exploration and production wastes may still be regulated by the EPA or state agencies under RCRA’s less stringent non-hazardous solid waste provisions, state laws or other federal laws, and it is possible that certain exploration and production wastes now classified as non-hazardous could be classified as hazardous in the future.
16
Site Remediation
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Under CERCLA, such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Although natural gas (and petroleum) is excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations, we generate wastes that may be designated as hazardous substances. CERCLA authorizes the EPA, states, and, in some cases, third parties to take actions in response to releases or threatened releases of hazardous substances into the environment and to seek to recover from the classes of responsible persons the costs they incur to address the release. Under CERCLA, we could be subject to strict joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In some states, including those in which we operate, site remediation of oil and natural gas facilities is regulated by state agencies with jurisdiction over oil and natural gas operations. The regulated releases and remediation activities, including the classes of persons that may be held responsible for releases of hazardous substances, may be broader than those regulated under CERCLA or RCRA.
We currently own, lease or operate, and may have in the past owned, leased or operated, properties that have been used for the gathering and compression of natural gas. Although we have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. Such hydrocarbons or other wastes may have migrated to property adjacent to our owned and leased sites or the disposal sites. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial operations to prevent future contamination. We are not currently a potentially responsible party in any federal or state Superfund site remediation and there are no current, pending or anticipated Superfund response or remedial activities at our facilities.
Air Emissions
The Clean Air Act and comparable state laws, including those states in which we operate, impose various pre-construction and operational permit requirements, noise and emission limits, operational limits, and monitoring, reporting and record-keeping requirements on air emission sources, including on our compressor stations. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and/or criminal enforcement actions. Such laws and regulations, for example, require permit limits to address the impacts of noise from our compression operations, and pre-construction permits for the construction or modification of certain projects or facilities with the potential to emit air emissions above certain thresholds. Pre-construction permits generally require use of best available control technology, or BACT, to limit air pollutants.
On August 16, 2012, the EPA published final revisions to the New Source Performance Standards (“NSPS”) to regulate emissions of volatile organic compounds (“VOCs”) and sulfur dioxide from various oil and gas exploration, production, processing and transportation facilities. Additionally, revisions were made to the National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) to further regulate emissions from the oil and natural gas production sector and the transmission and storage of natural gas. Section 111 of the CAA authorized the EPA to develop technology-based standards which apply to specific categories of stationary sources. On September 18, 2015, the EPA proposed two new regulations. The first was to provide an update to the NSPS to create new standards for the regulation of methane and VOCs emission sources. This proposed rule includes requirements for new fugitive emission and leak detection and reporting requirements. The second was to propose the Source Determination Rule which would clarify the use of the term “adjacent” in determining Title V air permitting requirements as they apply to the oil and natural gas industry for major sources of air emissions. On June 3, 2016, the EPA finalized updates to the final NSPS, known as Subpart 0000a, that created new standards for the regulation of methane and VOC emission sources and published the final Source Determination Rule. On August 1, 2016 the updates to the NSPS were challenged in the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) by industry and state associations, and a request for administrative reconsideration was also filed. Additionally, 15 states have filed suit and asked the Court of Appeals to review the need for the changes. In April 2017, the EPA announced that it would review its June 2016 standards and initiate reconsideration proceedings to potentially revise or rescind portions of the methane rule. Subsequently, effective June 2, 2017, the EPA issued a 90-day stay of certain requirements under the rule, but such stay was vacated by a three-judge panel of the D.C. Circuit on July 3, 2017. On August 10, 2017, the D.C. Circuit rejected petitions for an en banc review of its July 3, 2017
17
ruling. In the interim, on July 16, 2017, the EPA issued a proposed rule that would stay Subpart OOOOa for two years, but such rule is not yet final, is subject to public notice and comment, and may be subject to legal challenges. Legal uncertainty therefore exists at this time with respect to the future implementation of EPA’s methane rule.
In October 2015, the EPA lowered the primary and secondary National Ambient Air Quality Standards (“NAAQS”) for ozone. This rule has resulted in additional areas being in non-attainment with federal standards, which could result in us being required to install additional control equipment and restrict operations. Several federal NSPS and NESHAP, and analogous state law requirements, also apply to our facilities and operations. These applicable federal and state standards impose emission limits and operations limits as well as detailed testing, record keeping and reporting requirements on the facilities subject to these regulations.
We may incur capital expenditures in the future for air pollution control equipment in connection with complying with existing and recently proposed rules, or with obtaining or maintaining operating or preconstruction permits and complying with federal, state and local regulations related to air emissions (including air emission reporting requirements). However, we do not believe that such requirements will have a material adverse effect on our operations.
Climate Change
The EPA has adopted regulations under existing provisions of the Clean Air Act that establish Prevention of Significant Deterioration (“PSD”), pre-construction permits, and Title V operating permits for greenhouse gas (“GHG”) emissions from certain large stationary sources. Under these regulations, facilities required to obtain PSD permits must meet BACT standards for their GHG emissions established by the states or, in some cases, by the EPA on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities, which was recently amended to include gathering and boosting systems and blowdowns of natural gas transmission pipelines.
Additionally, while Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that exploration and production operators produce, some of whom are our customers, which could thereby reduce demand for our midstream services. In December 2015, the United National Climate Change Conference was held and an agreement was reached between the countries participating in the conference, including the United States, to limit global warming to less than two degrees Celsius compared to pre-industrial levels. This agreement, known as the Paris Agreement, calls for zero net anthropogenic greenhouse gas emissions to be reached during the second half of the 21st century. On September 3, 2016, the United States formally joined the Paris Agreement by submitting a plan of compliance to the United Nations, which could have an adverse effect on our business. However, on June 1, 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or to establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020.
Water Discharges
The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including sediment, and spills and releases of oil, brine and other substances into waters of the United States. The discharge of pollutants into jurisdictional waters is prohibited, except in accordance with the terms of a permit issued by the EPA, U.S. Army Corps of Engineers, or a delegated state agency. Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
In May 2015, the EPA released a final rule outlining its position on the federal jurisdictional reach over “waters of the United States” (the “WotUS Rule”). Nationwide implementation of the WotUS Rule was stayed nationwide by the U.S. Circuit Court of Appeals for the Sixth Circuit in October 2015, as that appellate court and several other courts pondered lawsuits opposing the rule. In January 2017, the U.S. Supreme Court accepted review of the rule to determine whether jurisdiction to hear challenges to the rule rests with the federal district or federal appellate courts. In February 2017, President Trump issued an executive order directing the EPA and the U.S. Army Corps of Engineers to review and, consistent with applicable law initiate a rulemaking to rescind or revise the rule. The EPA and the U.S. Army Corps of Engineers published a notice of intent to review and rescind or revise the WotUS Rule in May 2017. In June 2017, the EPA and the U.S. Army Corps of Engineers proposed a rule that would initiate the first step in a two-step process intended to review and revise the definition of “waters of the United States” consistent with President Trump’s executive order. Under the proposal, the first step would be to rescind the WotUS Rule and put back into effect the narrower language defining “waters of the United States” under the Clean Water Act
18
that existed prior to the rule. The second step would be a notice-and-comment rulemaking in which the agencies will conduct a substantive reevaluation of the definition of “waters of the United States” in accordance with the executive order. At this time, it is unclear what impact these actions will have on the implementation of the WotUS Rule.
The primary federal law related specifically to oil spill liability is the Oil Pollution Act (“OPA”), which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills, or threatened spills, in waters of the United States or adjoining shorelines. The OPA applies 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, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.
Endangered Species
The Endangered Species Act (“ESA”) and analogous state laws protect species threatened with extinction restricting activities that may affect endangered or threatened species or their habitats. Some of our pipelines are located in areas that are or may be designated as protected habitats for endangered or threatened species, including the Northern Long-Eared and Indiana bats, which has a seasonal impact on our construction activities and operations. However, based on species that have been identified and the current application of endangered species laws and regulations, we do not believe that there are any additional species protected under the ESA or state laws that would materially and adversely affect our ability to operate. The future listing of previously unprotected species in areas where we conduct or may conduct operations, or the designation of critical habitat in these areas, could cause us to incur increased costs arising from species protection measures or could result in limitations on our operating activities, which could have an adverse impact on our results of operations.
Occupational Safety and Health Act
We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right-to-Know Act and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Certain of our operations are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive material.
Employees
The officers of our general partner manage our operations and activities. All of the employees required to conduct and support our operations, including our Chief Executive Officer and our Chief Financial Officer, are employed by CNX and are subject to the operational services agreement and omnibus agreement between us, our general partner and CNX. As of December 31, 2017, CNX employed approximately 100 people that provide direct support to our operations pursuant to the operational services agreement and omnibus agreement.
Offices
Our principal offices are located at CNX Center, 1000 CONSOL Energy Drive, Canonsburg, Pennsylvania 15317.
Insurance
We maintain insurance policies with insurers in amounts and with coverage and deductibles that we believe are reasonable and prudent. We cannot, however, assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
Financial Information about Segments
Please read Part II. Item 8. Note 13–Segment Information, for financial information by business segment including, but not limited to, gathering revenue–related party, net income (loss), and total assets, which information is incorporated herein by reference.
Legal Proceedings
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently subject to any material litigation.
19
Available Information
Our website is www.cnxmidstream.com. We make our periodic reports and other information filed with or furnished to the U.S. Securities and Exchange Commission, or SEC, available, free of charge, on our website under “Investors/SEC Filings,” as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Alternatively, you may access these reports at the SEC’s website at www.sec.gov. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
Also posted on our website under “About/Our Governance”, and available in print upon request made by any unitholder to the Investor Relations department, are our audit committee charter and copies of our Code of Ethics, Corporate Governance Guidelines and Whistle Blower policy. Within the time period required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.
20
| ITEM 1A. | RISK FACTORS |
Limited partner interests are inherently different from the 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 a similar business. You should carefully consider the following risk factors together with all of the other information set forth in this Annual Report on Form 10-K, including the matters addressed under “Forward-Looking Statements,” in evaluating an investment in our common units.
If any of the following risks were to occur, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially adversely affected. In that case, we may not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment. In addition, the current economic and political environment intensifies many of these risks.
Risks Related to Our Business
Our two largest customers, CNX and HG Energy, currently account for substantially all of our revenue. If either or both of them change their business strategies, alter their current drilling and development plans on our dedicated acreage, release portions of their dedicated acreage, as permitted by the terms of the gas gathering agreement, or otherwise significantly reduce the volumes of natural gas and condensate transported through our gathering systems, our revenue would decline and our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders would be materially and adversely affected.
As we currently derive substantially all of our revenue from our gathering agreements with CNX and HG Energy, any event, whether in our dedicated acreage or elsewhere, that materially and adversely affects either or both of CNX’s or HG Energy’s business strategies with respect to drilling on and development of our dedicated acreage or their financial condition, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the operational and business risks of CNX and HG Energy, the most significant of which include the following:
| • | a reduction in or slowing of CNX’s or HG Energy’s drilling and development plans on our dedicated acreage; |
| • | a reduction in, or curtailment of, production from existing wells on our dedicated acreage; |
| • | the extreme volatility of natural gas, NGL and crude oil prices, which could have a negative effect on CNX’s or HG Energy’s drilling and development plans on, or levels of existing production from, our dedicated acreage or their ability to finance its operations and drilling and exploration costs on our dedicated acreage; |
| • | the availability of capital on an economic basis to fund exploration and development activities of CNX and HG Energy; |
| • | drilling and operating risks, including potential environmental liabilities, associated with CNX’s and HG Energy’s operations on our dedicated acreage; |
| • | downstream processing and transportation capacity constraints and interruptions, including the failure of CNX or HG Energy to have sufficient contracted processing or transportation capacity; and |
| • | adverse effects of increased or changed governmental and environmental regulation. |
In addition, we are indirectly subject to the business risks of CNX and HG Energy generally and other factors, including, among others:
| • | their financial condition, credit ratings, leverage, market reputation, liquidity and cash flows; |
| • | their ability to maintain or replace reserves; |
| • | adverse effects of governmental and environmental regulation on their upstream operations; and |
| • | losses from pending or future litigation. |
Further, we have no control over CNX’s or HG Energy’s business decisions and operations, and they are under no obligation to adopt business strategies that are favorable to us. We are subject to the risk of non-payment or non-performance by our customers, including with respect to our gathering agreements, which do not contain minimum volume commitments. In addition, our gas gathering agreements permit HG Energy and, in the event that CNX ceases to control our general partner, CNX to release portions of acreage from dedication under the respective agreements, subject to the terms of the respective gathering agreements. We cannot predict the extent to which our customers’ businesses will be impacted if conditions in the energy industry deteriorate nor can we estimate the impact such conditions will have on their ability to execute their drilling and development plans on our dedicated acreage or to perform under our gathering agreements.
Global energy commodity prices may fluctuate widely in response to market uncertainty and relatively minor changes in the supply of and demand for oil, natural gas and NGLs. Historically, oil, natural gas and NGL prices have been volatile. Lower commodity prices reduce CNX’s cash flows and may affect their borrowing ability. Our customers may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in their reserves as existing reserves are
21
depleted. Lower commodity prices may also reduce the amount of natural gas, NGLs and oil that our customers can produce economically. If commodity prices further decrease, a significant portion of their exploitation, development and exploration projects on our dedicated acreage could become uneconomic. This may result in our customers having to make significant downward adjustments to their estimated proved reserves on our dedicated acreage. As a result, a substantial or extended decline in commodity prices may materially and adversely affect both CNX’s and HG Energy’s future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
Any material non-payment or non-performance by either CNX or HG Energy under our gathering agreements, which have initial terms ending in 2037 and 2034, respectively, would have a significant adverse impact on our business, financial condition, results of operations and cash flows and could therefore materially adversely affect our ability to make cash distributions to our unitholders at the expected rate or at all. There is no guarantee that we will be able to renew or replace those gathering agreements on equal or better terms upon their expiration. Our ability to renew or replace our gathering agreements with CNX or HG Energy following their expiration at rates sufficient to maintain our current revenues and cash flows could be adversely affected by activities beyond our control, including the activities of our customers and our competitors.
Additionally, following the closing of a transaction (the “Spin-Off”) in December 2017 in which CNX’s coal business was contributed to CONSOL Energy Inc. (“CONSOL”), certain of CNX’s key personnel became employees of CONSOL. As a result, CNX is a smaller and less diversified company with more limited financial resources and operational capabilities, and CNX may be unable or unwilling to provide us with certain financial and operational support that it was able or willing to provide to us prior to the Spin-Off. CNX’s status as a smaller company and loss of these capabilities and key personnel could have a material adverse effect upon our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Under our gathering agreements, our customers may transfer their leasehold, working and mineral fee interests in their dedicated acreage.
Our customers may transfer their leasehold, working and mineral fee interests in, or grant an overriding royalty interest, production payment, net profits interest or other similar interest in their dedicated acreage. Each of our customers continually evaluates how to enhance its upstream portfolio, including its holdings in the Marcellus Shale and could sell, exchange, farm-out or otherwise dispose of all of, or an undivided interest in, its Marcellus Shale holdings as part of these enhancement efforts. If either of our customers transfers all or an undivided portion of its interests in the future, its economic interest in developing the dedicated acreage could decrease, which could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
We cannot currently determine what impact, if any, Noble Energy’s divestiture of its upstream assets in the Marcellus Shale will have on the Partnership.
In connection with the Noble Energy Asset Sale, HG Energy succeeded to the terms of our gathering agreement with Noble Energy. To the extent they produce on acreage that is dedicated to the Partnership, we will continue to gather such production at the fees that are outlined in our gathering agreement with HG Energy. HG Energy is under no obligation to pursue business strategies that are favorable to us, and it may alter its drilling and development plan at any time. We are subject to fluctuations in HG Energy’s creditworthiness and overall financial condition, which following consummation of the transaction, may subject us to the risk of non-payment or non-performance by HG Energy under our gathering agreement, which could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions. In addition, while HG Energy is subject to many similar business and operational risks as those faced by Noble Energy, HG Energy may be more adversely impacted by those risks than Noble Energy, which may in turn have a greater adverse impact on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
We may not generate sufficient distributable cash flow to make the payment of the minimum quarterly distribution to our unitholders.
In order to make the payment of the minimum quarterly distribution of $0.2125 per unit per quarter, or $0.85 per unit on an annualized basis, we must generate distributable cash flow of approximately $13.8 million per quarter, or approximately $55.2 million per year, based on the number of common units and the general partner interest outstanding as of December 31, 2017. We may not generate sufficient distributable cash flow to make the payment of the minimum quarterly distribution to our unitholders.
The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
| • | the volume of natural gas we gather, compress and dehydrate, the volume of condensate we gather and treat and the fees we are paid for performing such services; |
22
| • | the effects of changes in market prices of natural gas, NGLs and crude oil on our customers’ drilling and development plans on our dedicated acreage and the volumes of natural gas and condensate that are produced on our dedicated acreage; |
| • | our customers’ ability to fund their drilling and development plans on our dedicated acreage; |
| • | capital expenditures necessary for us to maintain and build out our midstream systems to gather natural gas and condensate from our customers’ new well completions on our dedicated acreage; |
| • | the levels of our operating expenses, maintenance expenses and general and administrative expenses; |
| • | regulatory action affecting: (i) the supply of, or demand for, natural gas and condensate, (ii) the rates we can charge for our midstream services, (iii) the terms upon which we are able to contract to provide our midstream services, (iv) our existing gathering and other commercial agreements or (v) our operating costs or our operating flexibility; |
| • | the rates we charge third parties, if any, for our midstream services; |
| • | prevailing economic conditions; and |
| • | favorable or adverse weather conditions. |
In addition, the actual amount of distributable cash flow that we generate will also depend on other factors, some of which are beyond our control, including:
| • | the level and timing of our capital expenditures; |
| • | our debt service requirements and other liabilities; |
| • | our ability to borrow under our debt agreements to fund our capital expenditures and operating expenditures and to pay distributions; |
| • | fluctuations in our working capital needs; |
| • | restrictions on distributions contained in any of our debt agreements; |
| • | the cost of acquisitions, if any; |
| • | the fees and expenses of our general partner and its affiliates (including CNX) that we are required to reimburse; |
| • | the amount of cash reserves established by our general partner; and |
| • | other business risks affecting our cash levels. |
Because of the natural decline in production from existing wells, our success, in part, depends on our ability to maintain or increase natural gas and condensate throughput volumes on our midstream systems, which depends on the level of development and completion activity on acreage dedicated to us.
The level of natural gas and condensate volumes handled by our midstream systems depends on the level of production from natural gas wells dedicated to our midstream systems, which may be less than expected and which will naturally decline over time. In order to maintain or increase throughput levels on our midstream systems, we must obtain production from new wells completed by CNX and any third party customers on acreage dedicated to our midstream systems or execute agreements with other third parties in our areas of operation.
We have no control over CNX’s or other producers’ levels of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over CNX’s or other producers or their exploration and development decisions, which may be affected by, among other things:
| • | prevailing and projected natural gas, NGL and crude oil prices, which are extremely volatile; |
| • | demand for natural gas, NGLs and crude oil; |
| • | changes in the strategic importance our customers assign to development in the Marcellus and Utica Shale areas as opposed to other plays they may consider core to their businesses, which could adversely affect the financial and operational resources our customers are willing to devote to development in our areas of operations; |
| • | the availability and cost of capital; |
| • | levels of reserves; |
| • | geologic considerations; |
| • | increased levels of taxation related to the exploration and production of natural gas in our areas of operation; |
| • | environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and |
| • | the costs of producing natural gas and the availability and costs of drilling rigs and other equipment and services. |
Due to these and other factors, even if reserves are known to exist in areas served by our midstream systems, CNX or other producers may choose not to develop those reserves. If CNX or other producers choose not to develop their reserves, or they choose to slow their development rate, in our areas of operation, they will have no need to dedicate such additional acreage and associated reserves to our midstream systems and the pace of such additional dedications will be below anticipated levels. In addition, certain of our gas gathering agreements permit our customers to release portions of their acreage from
23
dedication, subject to the terms of the agreements. Our inability to obtain additional dedications of acreage resulting from reductions in development activity, coupled with the natural decline in production from, or releases of, our current dedicated acreage, would result in our inability to maintain the then current levels of throughput on our midstream systems, which could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
Our gathering agreements do not include minimum volume commitments.
Although we have obtained acreage dedications from CNX Gas and HG Energy and minimum well commitments from CNX Gas in certain development areas, our gathering agreements do not specifically include minimum volume commitments that would protect us against volumetric risks associated with lower-than-forecast volumes flowing through our gathering systems. Our customers are not contractually obligated to us to develop their properties in the areas covered by our acreage dedications, and they may determine that it is more attractive to direct their capital spending and resources to other areas. A decrease in capital spending and development of reserves by our customers in the areas covered by our acreage dedications could result in reduced volumes serviced by us and a material decline in our revenues and cash flows. Any decrease in the current levels of throughput on our gathering systems could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
Certain of our dedicated acreage is either not held by production by our customers or has not yet been earned by them.
Certain of our dedicated acreage is either not held by production or has yet to be earned by our customers under farmout agreements to which they are parties. As of December 31, 2017, approximately one-fifth of our dedicated acreage was not held by production or was yet to be earned by our customers. With respect to dedicated acreage that is not held by production, if the applicable shipper does not timely meet the drilling obligations specified in the underlying leases, then the leases will terminate and will no longer be subject to our dedication. With respect to the dedicated acreage that is yet to be earned under certain farmout agreements, if the applicable customer does not meet its drilling obligations to earn the acreage subject to the farmout agreement prior to the termination of the farmout agreement, then it will have no further rights to earn any acreage that it has not previously earned under the farmout agreement. Also, if the counterparty to a farmout agreement becomes insolvent or bankrupt, then the farmout agreement may be deemed an executory contract that may be discharged in a bankruptcy proceeding. If our customers do not timely meet the drilling obligations specified in the leases not held by production or do not earn all of the acreage subject to the farmout agreements prior to the termination of the farmout agreements or if such customer’s farmout agreements are discharged, the affected acreage will no longer be dedicated to us, which could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
We may not be able to attract dedications of third-party volumes, in part because our industry is highly competitive, which could limit our ability to grow and continue our dependence on our existing customers.
Part of our long-term growth strategy includes diversifying our customer base by identifying opportunities to offer services to third parties in our areas of operation. Over the near term, substantially all of our revenues will be earned from CNX and HG Energy relating to production they own or control on our dedicated acreage. Our ability to increase throughput on our midstream systems and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when requested by third parties. Any lack of available capacity on our systems for third-party volumes will detrimentally affect our ability to compete effectively with third-party systems for natural gas and condensate produced from reserves associated with acreage other than our then current dedicated acreage in our area of operation. In addition, some of our competitors for third-party volumes have greater financial resources and access to larger supplies of natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do.
Our efforts to attract new third parties as customers may be adversely affected by (i) our relationship with our existing customers and the fact that a substantial majority of the capacity of our midstream systems will be necessary to service their production on our dedicated acreage and that, under our gathering agreements with our existing customers, such customers will receive priority of service for the provision of our midstream services over third parties and (ii) our desire to provide services pursuant to fee-based agreements. As a result, we may not have the capacity to provide services to third parties and/or potential third-party customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure. In addition, potential third-party customers who are significant producers of natural gas and condensate may develop their own midstream systems in lieu of using our systems. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition, cash flows and ability to make cash distributions to our unitholders.
24
We may not be able to make attractive offers to CNX or HG Energy on our ROFO acreage.
Each of CNX and HG Energy is required to allow us to make a first offer to provide midstream services on existing upstream acreage that is not currently dedicated to us or a third party, which, as of December 31, 2017, covered, in the aggregate, approximately 198,000 net acres, and any future acreage that is acquired by CNX or HG Energy, as applicable, in the ROFO area, which includes acreage outside our acreage dedication that may be serviced by our midstream systems. Neither customer is under any obligation to accept an offer we make on this acreage, even if we submit the most attractive bid it receives. In addition, another midstream service provider may be able to make a more attractive offer, whether because they have existing infrastructure on or around this acreage or otherwise. Any rejection by CNX or HG Energy, as applicable, of any offer on this acreage could adversely affect our organic growth strategy or our ability to maintain or increase our cash distribution level.
Our only assets are controlling ownership interests in our operating subsidiaries. Because our interests in our operating subsidiaries represent our only cash-generating assets, our cash flow will depend entirely on the performance of our operating subsidiaries and their ability to distribute cash to us.
We have a holding company structure, meaning the sole source of our earnings and cash flow consists exclusively of the earnings of and cash distributions from our operating subsidiaries. Therefore, our ability to make quarterly distributions to our unitholders will be completely dependent upon the performance of our operating subsidiaries and their ability to distribute funds to us. We are the sole member of the general partner of each of our operating subsidiaries, and we control and manage our operating subsidiaries through our ownership of our operating subsidiaries’ respective general partners.
The limited partnership agreement governing each operating company requires that the general partner of such operating company cause such operating company to distribute all of its available cash each quarter, less the amounts of cash reserves that such general partner determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of such operating company’s business.
The amount of cash each operating company generates from its operations will fluctuate from quarter to quarter based on events and circumstances and the actual amount of cash each operating company will have available for distribution to its partners, including us, also will depend on certain factors. For a description of the events, circumstances and factors that may affect the cash distributions from our operating subsidiaries please read “Risk Factors—We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution to our unitholders.”
Our gathering agreements with our customers provide for the release of dedicated acreage in certain situations.
Our gathering agreements with our customers provide that if we fail to timely complete the construction of the facilities necessary to provide midstream services to their dedicated acreage or have an uncured default of any of our material obligations that has caused an interruption in our services to either party for more than 90 days, the affected acreage will be permanently released from our dedication. Also, under the terms of its gathering agreement with us, if CNX Gas drills a well or anticipates drilling a well that is located more than a certain distance from an area served by our current gathering system and a third-party gatherer offers a lower cost of service, and it elects to utilize the third-party gatherer, then the acreage associated with such well will be permanently released from our dedication. Any permanent releases of our customers’ acreage from our dedication could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
Our gathering agreements with CNX Gas and HG Energy also provide that in certain situations, such as an uncured default of any of our material obligations that has caused an interruption in our services for more than 45 days but less than 90 days, our dedicated acreage can be temporarily released from our dedication. Any temporary releases of acreage from our dedication could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
We may be responsible for mine subsidence costs in the future.
Portions of our gathering systems pass over coal mines. Activities related to the use and expansion of our gathering systems have historically, and may continue to, be affected by mine subsidence. Under the terms of the omnibus agreement between us, our general partner, CNX Gathering, CNX and Noble Energy, CNX Gathering has agreed to indemnify us for a period of four years following our IPO against costs or losses arising out of mine subsidence. However, after the four-year period, we may be liable for any costs or losses arising out of or attributable to mine subsidence. For the year ended December 31, 2017, we incurred mine subsidence costs related to the expansion of our systems of approximately $0.8 million that were reimbursed to us by CNX Gathering. We cannot predict the amount of any costs or losses associated with mine subsidence that may impact our assets after the term of the indemnification provided in the omnibus agreement. Mine subsidence costs and losses that we incur and for which we cannot seek indemnification could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
25
Our midstream systems are exclusively located in the Appalachian Basin, making us vulnerable to risks associated with operating in a single geographic area.
We currently rely exclusively on revenues generated from our midstream systems that are located in the Appalachian Basin. As a result of this concentration, we will be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, market limitations, water shortages or other drought related conditions or interruption of the processing or transportation of natural gas, NGLs or condensate. If any of these factors were to impact the Appalachian Basin more than other producing regions, our business, financial condition, results of operations and ability to make cash distributions will be adversely affected relative to other midstream companies that have a more geographically diversified asset portfolio.
We may be unable to grow by acquiring the noncontrolling interests in, or assets of, our operating subsidiaries owned by CNX Gathering, which could limit our ability to increase our distributable cash flow.
Part of our strategy for growing our business and increasing distributions to our unitholders is dependent upon our ability to make acquisitions that increase our distributable cash flow. Part of the acquisition component of our growth strategy is based upon our expectation of future divestitures by CNX Gathering to us of portions of its remaining, noncontrolling interests in our operating subsidiaries or divestitures by CNX Gathering to our wholly owned operating subsidiaries of assets owned by our non-wholly owned operating subsidiaries. We have only a right of first offer pursuant to our omnibus agreement to purchase the noncontrolling interests in our operating subsidiaries retained by CNX Gathering. CNX Gathering is under no obligation to offer to sell us additional assets (including our right of first offer assets), unless and until it otherwise intends to dispose of such assets, and we are under no obligation to buy any additional assets from CNX Gathering. We may never purchase all or a portion of the noncontrolling interests in our operating subsidiaries or the assets owned by our non-wholly owned operating subsidiaries for several reasons, including the following:
| • | CNX Gathering may choose not to sell these noncontrolling interests or assets; |
| • | we may not make offers for these noncontrolling interests or assets; |
| • | we and CNX Gathering may be unable to agree to terms acceptable to both parties; |
| • | we may be unable to obtain financing to purchase these noncontrolling interests or assets on acceptable terms or at all; or |
| • | we may be prohibited by the terms of our debt agreements (including our credit facility) or other contracts from purchasing some or all of these noncontrolling interests or assets, and CNX Gathering may be prohibited by the terms of its debt agreements or other contracts from selling some or all of such noncontrolling interests or assets. If we or CNX Gathering must seek waivers of such provisions or refinance debt governed by such provisions in order to consummate a sale of these noncontrolling interests or assets, we or CNX Gathering may be unable to do so in a timely manner or at all. |
We do not know when or if all or any portion of such noncontrolling interests will be offered to us for purchase or whether we will have an opportunity to acquire assets from our non-wholly owned operating subsidiaries on behalf of our wholly owned operating subsidiaries, and we can provide no assurance that we will be able to successfully consummate any future acquisition of all or any portion of such noncontrolling interests or assets. Furthermore, if CNX Gathering reduces its ownership interest in us, it may be less willing to sell to us such remaining noncontrolling interests or assets. In addition, except for our rights of first offer, there are no restrictions on CNX Gathering’s ability to transfer its noncontrolling interests in our operating subsidiaries or assets of such entities to a third party. If we do not acquire all or a significant portion of the noncontrolling interests in our operating subsidiaries held by CNX Gathering or if we fail to acquire on behalf of our wholly owned subsidiaries the assets of our non-wholly owned subsidiaries that are offered to us on favorable terms, our ability to grow our business and increase our cash distributions to our unitholders may be significantly limited.
If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our operating margin, cash flow and ability to make cash distributions to our unitholders could be adversely affected.
Our assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of third-party pipelines, processing and fractionation plants, compressor stations and other midstream facilities is not within our control. These third-party pipelines, processing and fractionation plants, compressor stations and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, changes to operating conditions, delivery or receipt parameters, unavailability of firm transportation, lack of operating capacity, force majeure events, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. If any such increase in costs occurs or if any of these pipelines or other midstream facilities becomes unable to receive or transport natural gas, our operating margin, cash flow and ability to make cash distributions to our unitholders could be adversely affected.
26
To maintain and grow our business, we will be required to make substantial capital expenditures. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished or our financial leverage could increase.
In order to maintain and grow our business, we will need to make substantial capital expenditures to fund growth capital expenditures associated with our Anchor Systems, as well as to fund our share of such expenditures associated with our 5% controlling interests in each of the Growth Systems and Additional Systems, or to purchase or construct new midstream systems. If we do not make sufficient or effective capital expenditures, we will be unable to maintain and grow our business and, as a result, we may be unable to maintain or raise the level of our future cash distributions over the long term. In addition, under the terms of our gas gathering agreements, we may be required to expand our midstream systems or construct additional midstream assets to services the production delivered by our customers. If we are unable to expand these systems or develop these assets, we may be in breach of our gas gathering agreements, which would negatively impact our business and financial condition. To fund our capital expenditures, we will be required to use cash from our operations, incur debt or sell additional common units or other equity securities. Using cash from our operations will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or our ability 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 and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. Also, due to our relationship with CNX, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to the financial condition of CNX or adverse changes in CNX’s credit ratings. Any material limitation on our ability to access capital as a result of such adverse changes to CNX could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes affecting CNX could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our business activities, or could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
Even if we are successful in obtaining the necessary funds to support our growth plan, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then current distribution rate, which could materially decrease our ability to pay distributions at the then prevailing distribution rate. While we have historically received funding from CNX, none of CNX, CNX Gathering, our general partner or any of their respective affiliates is committed to providing any direct or indirect financial support to fund our growth.
The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow and not solely on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record a net loss for financial accounting purposes, and conversely, we might fail to make cash distributions during periods when we record net income for financial accounting purposes.
Increased competition from other companies that provide midstream services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could adversely affect our financial results.
Our ability to renew or replace contracts with our existing customers or negotiate and enter into contracts with new customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our systems compete for third-party customers primarily with other crude oil and natural gas gathering systems and fresh and saltwater service providers. Some of our competitors have greater financial resources and may now, or in the future, have access to greater supplies of crude oil and natural gas than we do. Some of these competitors may expand or construct gathering systems that would create additional competition for the services we would provide to third-party customers. In addition, potential third-party customers may develop their own gathering systems instead of using ours. Moreover, CNX and its affiliates are not limited in their ability to compete with us outside of our dedicated area.
Further, hydrocarbon fuels compete with other forms of energy available to end-users, including electricity and coal. Increased demand for such other forms of energy at the expense of hydrocarbons could lead to a reduction in demand for our services.
All of these competitive pressures could make it more difficult for us to retain our existing customers or 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 ability to make quarterly cash distributions to our unitholders. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
27
Our construction of new gathering, compression, dehydration, treating or other midstream assets may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our cash flows, results of operations and financial condition and, as a result, our ability to distribute cash to our unitholders.
The construction of additions or modifications to our existing systems, including pursuant to the terms of our existing gas gathering agreements, involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all.
Our revenues may not increase immediately (or at all) upon the expenditure of funds on a particular project. For instance, if we build a new compression facility, the construction may occur over an extended period of time, and we may not receive any material increases in revenues until the project is completed. Additionally, we may construct facilities to capture anticipated future production growth in an area in which such growth does not materialize. As a result, new gathering, compression, dehydration, treating or other midstream assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
The construction of additions to our existing assets may require us to obtain new rights-of-way prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new natural gas supplies to our existing gathering pipelines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
Certain plant or animal species are or could be designated as endangered or threatened, which could have a material impact on our and our customers’ operations.
The Federal Endangered Species Act (“ESA”) and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify gas well pad siting or pipeline right of ways, or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA, including the Northern Long-Earned and Indiana bats. Additional species are expected to be considered for listing within our operating region, and we consider this uncertainty, as well as the cost to comply with stringent mitigation requirements, a risk to cost and operational timing.
Our exposure to commodity price risk may change over time and we cannot guarantee the terms of any existing or future agreements for our midstream services with third parties or with CNX.
We currently generate substantially all of our revenues pursuant to fee-based gathering agreements under which we are paid based on the volumes that we gather and compress, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows do not have significant direct exposure to commodity price risk. However, the producers that are customers of our midstream services are exposed to commodity price risk, and extended reduction in commodity prices could adversely reduce the production volumes available for our midstream services in the future below expected levels. Although we intend to enter into fee-based gathering agreements with existing or new customers in the future, our efforts to negotiate such terms may not be successful.
Restrictions in our revolving credit facility, and other debt agreements that we may enter into in the future, could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.
Our $250.0 million revolving credit facility limits, and other debt agreements that we may enter into in the future may limit, our ability (subject to certain exceptions) to, among other things:
| • | incur or guarantee additional debt; |
| • | 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. |
Our revolving credit facility also contains, and other debt agreements we may enter into in the future may contain, covenants requiring us to maintain certain financial ratios. For example, under our revolving credit facility, we may not permit the ratio of (i) consolidated total funded debt (as defined in the agreement governing our revolving credit facility) as of the last
28
day of each fiscal quarter to (ii) consolidated EBITDA (as defined in the agreement governing our revolving credit facility) for the four consecutive fiscal quarters ending on the last day of such fiscal quarter to exceed (A) at any time other than during a qualified acquisition period (as defined in the agreement governing our revolving credit facility), 5.00 to 1.00 and (B) during a qualified acquisition period (as defined in the agreement governing our revolving credit facility), 5.50 to 1.00. In addition, under our revolving credit facility, we may not permit the ratio of (i) consolidated EBITDA for the four consecutive fiscal quarters ending on the last day of each fiscal quarter to (ii) consolidated interest expense (as defined in the agreement governing our revolving credit facility) for such four consecutive fiscal quarters to be less than 3.00 to 1.00. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet any such ratios and tests.
The provisions of our revolving credit facility and other debt agreements we may enter into in the future 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 our revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” under Item 7 of Part I of this Annual Report on Form 10-K.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of such assets, which may cause our revenues to decline and our operating expenses to increase.
Our gathering and transportation operations are exempt from regulation by FERC under the NGA. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. Although FERC has not made any formal determinations with respect to any of our facilities we consider to be gathering facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish that a natural gas pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation. FERC determines whether facilities are gas gathering facilities on a case-by-case basis, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by FERC, the courts, or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA and/or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows.
Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, gas quality, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. Should we fail to comply with any applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines, which could have a material adverse effect on our results of operations and cash flows. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1,213,503 per day for each violation. Violations of the NGA or the NGPA could also result in administrative and criminal remedies and the disgorgement of any profits associated with the violation.
State regulation of natural gas gathering facilities pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, as well as complaint-based rate regulation. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, compression and sale.
For more information regarding federal and state regulation of our operations, please read “Business — Regulation of Operations” under Item 1 of Part I of this Annual Report on Form 10-K.
We may incur significant costs and liabilities as a result of pipeline and related facility integrity management program testing and any related pipeline repair or preventative or remedial measures.
PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines and related facilities located where a leak or rupture could do the most harm, i.e., in “high consequence areas.” The regulations require operators to:
| • | perform ongoing assessments of pipeline and related facility integrity; |
| • | identify and characterize applicable threats to pipeline segments that could impact a high consequence area; |
29
| • | improve data collection, integration and analysis; |
| • | repair and remediate the pipeline as necessary; and |
| • | implement preventive and mitigating actions. |
The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. In 2017, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $209,002 per violation per day, with a maximum of $2,909,022 for a related series of violations. Should our operations fail to comply with PHMSA or comparable state regulations, we could be subject to substantial penalties and fines. PHMSA has also published notices and advanced notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to extend the integrity management program requirements to additional types of facilities, such as gathering pipelines and related facilities. In January 2017, in the final week of the Obama Administration, PHMSA released a pre-publication copy of its final hazardous liquid pipeline safety regulations that would significantly extend the integrity management requirements to previously exempt pipelines and would impose additional obligations on hazardous liquid pipeline operators that are already subject to the integrity management requirements, including periodic integrity assessments and leak detection for pipelines outside of high consequence areas, inspections of pipelines after extreme weather events, expanded reporting, and more stringent integrity management repair and data collection requirements. Due to the change in Presidential administrations, PHMSA’s final hazardous liquid pipeline safety rule was never published in the Federal Register and has not yet taken effect. PHMSA is expected to finalize its hazardous liquid pipeline safety rule this year. PHMSA’s proposed rule would also require annual reporting of safety-related conditions and incident reports for all hazardous liquid gathering lines and gravity lines, including pipelines that are currently exempt from PHMSA regulations. PHMSA issued a separate regulatory proposal in July 2015 that would impose pipeline incident prevention and response measures on natural gas and hazardous liquid pipeline operators. Additionally, in April 2016, PHMSA published in the Federal Register a Notice of Proposed Rule Making (“NPRM”) that would significantly modify existing regulations related to reporting, impact, design, construction, maintenance, operations and integrity management of gas transmission and gathering pipelines. The proposed rule addresses four congressional mandates and six recommendations by the National Transportation Safety Board to broaden the scope of safety coverage by adding new assessment and repair criteria for gas transmission pipelines, and by expanding these protocols to include pipelines not formerly regulated by the federal standards. This includes extending regulatory requirements to transmission and gathering pipelines of eight inches and greater in rural Class I areas. Compliance with the rule, as proposed, may prove challenging and costly for operators of older pipelines due to the difficulty of locating historic records. As proposed, compliance with the rule could have a material adverse effect on the Partnership’s operations. However, the ultimate impact of the rule on the Partnership remains uncertain until the rulemaking is finalized. PHMSA is expected to finalize its natural gas pipeline safety rule this year. The adoption of regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flow. Please read “Business — Regulation of Operations — Pipeline Safety Regulation” under Item 1 of Part I of this Annual Report on Form 10-K.
Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas, NGL and crude oil production by our customers, which could reduce the throughput on our gathering and other midstream systems, which could adversely impact our revenues.
We do not conduct hydraulic fracturing operations, but substantially all of our customers’ natural gas production on our dedicated acreage is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand combined with fracturing chemical additives that are pumped at high pressure to crack open previously impenetrable rock to release hydrocarbons. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. 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, or otherwise seek to ban some or all of these activities. However, the EPA, has asserted certain regulatory authority over hydraulic fracturing and has moved forward with various regulatory actions, including, the issuance of new regulations requiring green completions for hydraulically fractured wells, emission requirements for certain midstream equipment, proposed pretreatment standards that would prohibit the indirect discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned treatment works, and an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances and Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Certain environmental groups have also suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of
30
Congress to provide for such regulation. We cannot predict whether any such legislation will be enacted and if so, what its provisions would be. Additional levels of regulation and permits required through the adoption of new laws and regulations at the federal, state or local level could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas and liquids that move through our gathering systems, which in turn could materially adversely affect operations.
We and our customers may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.
As an owner and operator of gathering and compressing systems, we are subject to various stringent federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment and worker health and safety. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly response actions. These laws and regulations may impose numerous obligations that are applicable to our and our customers’ operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customers’ operations. Failure to comply with these laws, regulations and permits may result in joint and several or strict liability or the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and/or the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. There is no assurance that changes in or additions to public policy regarding the protection of the environment and worker health and safety will not have a significant impact on our operations and profitability.
In 2013, the EPA issued a draft report entitled Connectivity of Streams and Wetlands to Downstream Waters, which affects a proposed rulemaking that would expand the scope of the Clean Water Act (“CWA”) to include previously non-jurisdictional streams, wetlands, and waters, making these areas jurisdictional inter-coastal Waters of the U.S (“WotUS”). In June 2015, EPA published the final WotUS rule but a federal appeals court stayed implementation of the rule in October 2015 as legal challenges to the rule are considered. In January 2017, the U.S. Supreme Court accepted review of the WotUS rule to determine whether jurisdiction to hear challenges to the rule rests with the federal district or appellate courts. In June 2017, EPA and the Army Corps of Engineers proposed a rule that would initiate the first step in a two-step process intended to review and revise the definition of “waters of the United States.” Under the proposal, the first step would be to rescind the May 2015 WotUS rule and put back into effect the narrower language defining “waters of the United States” under the CWA that existed prior to the rule. The second step would be a notice-and-comment rulemaking in which the agencies will conduct a substantive reevaluation of such definition. While we cannot at this time predict the final form of the WotUS rule, such rulemaking could lead to additional mitigation costs and severely limit CNX’s operations.
Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, potentially resulting in increased costs of doing business and consequently affecting profitability. Please read “Business — Regulation of Environmental and Occupational Safety and Health Matters” under Item 1 of Part I of this Annual Report on Form 10-K.
Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the natural gas that we gather while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
While climate change legislation in the U.S. is generally considered to be unlikely in the next several years, the issue of global climate change continues to attract considerable public and scientific attention with underlying concern about the impacts of human activity, especially the emissions of greenhouse gases (“GHGs”) such as carbon dioxide (“CO2”) and methane, on the environment.
The EPA, under the Climate Action Plan, has elected to regulate GHGs under the Clean Air Act (“CAA”) to limit emissions of CO2 from natural gas-fired power plants. On September 20, 2013, the EPA re-proposed New Source Performance Standards (“NSPS”) for CO2 emissions from new power plants and on June 2, 2014, the EPA re-proposed NSPS for CO2 emissions from existing and modified/reconstructed power plants, which rescinded the rules that were originally proposed in 2012. On August 3, 2015, the EPA finalized the Carbon Pollution Standards to cut carbon emissions from new, modified and reconstructed power plants, which became effective on October 23, 2015. In another proposed rulemaking related to CO2
31
emissions, on June 2, 2014, the EPA proposed the Clean Power Plan Rule to cut carbon emissions from existing power plants. Under this proposed rule, the EPA would create emission guidelines for states to follow in developing plans to address GHG emissions from existing fossil fuel-fired electric generating units. Specifically, the EPA is proposing state-specific rate-based goals for CO2 emissions from the power sector, as well as guidelines for states to follow in developing plans to achieve the state-specific goals. On August 3, 2015, the EPA finalized the Clean Power Plan Rule to cut carbon pollution from existing power plants, which became effective on December 22, 2015. Numerous petitions challenging the Clean Power Plan Rule have been consolidated into one case, West Virginia v. EPA. While the litigation is still ongoing at the circuit court level, a mid-litigation application to the Supreme Court resulted in a stay of the Clean Power Plan Rule. On September 27, 2016, an en banc panel of the U.S. Court of Appeals for the D.C. Circuit heard oral arguments in the case. In April 2017, the D.C. Circuit granted the EPA’s motion to hold the case in abeyance while the EPA undertakes its review of the regulations. Also in April 2017, the EPA announced that it was initiating a review of the Clean Power Plan consistent with President Trump’s Executive Order 13783, and in October 2017 published a proposed rule to formally repeal the Clean Power Plan.
The EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for certain large stationary sources that emit GHGs. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore oil and gas production sources in the U.S. on an annual basis, which was expanded in October 2015 to include, amongst other equipment, certain gathering and boosting activities and transmission pipelines. We monitor and file annual required reports for the GHG emissions from our operations in accordance with the GHG emissions reporting rule.
Further, in December 2015, more than 190 countries, including the United States, reached an agreement to reduce greenhouse gas emissions (the “Paris Agreement”). However, in June 2017, the Trump Administration announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. To the extent that the United States adopts regulations in accordance with this agreement, these regulations could adversely affect our business and the businesses of CNX and our customers. As part of the Obama administration’s initiative to reduce methane emissions from the oil and gas industry, EPA adopted rules to control volatile organic compound emissions from certain oil and gas equipment and operations. In June 2017, the EPA issued a 90-day stay of certain requirements under the methane rule. The stay was vacated in July 2017 by the U.S. Court of Appeals for the D.C. Circuit. In the interim, in July 2017, the EPA issued a proposed rule that would stay the methane rule for two years, but this rule is not yet final and is subject to public notice, comment, and legal challenges.
Additionally, some states in which we operate are contemplating measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and potential cap-and-trade programs. Most of these types of programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available being reduced each year until a target goal is achieved. The cost of these allowances could increase over time.
While new laws and regulations are prompting power producers to shift from coal to natural gas, which is increasing demand for natural gas, new regulations that impose GHG limits thereby increasing the costs for permitting, equipping, monitoring and reporting GHGs.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our ability to distribute cash and, accordingly, the market price for our common units.
Our operations are subject to all of the hazards inherent in the gathering and compression of natural gas, including:
| • | damage to pipelines, compressor stations, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism and acts of third parties; |
| • | leaks of natural gas or condensate or losses of natural gas or condensate as a result of the malfunction of, or other disruptions associated with, equipment or facilities; |
| • | fires, ruptures, landslides, mine subsidence and explosions; and |
| • | other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. |
32
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
| • | injury or loss of life; |
| • | damage to and destruction of property, natural resources and equipment; |
| • | pollution and other environmental damage; |
| • | regulatory investigations and penalties; |
| • | suspension of our operations; and |
| • | repair and remediation costs. |
Although we maintain insurance for a number of risks and hazards, we may not be insured or fully insured against the losses or liabilities that could arise from a significant accident in our operations, as we may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
We may not own in fee the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
Most of the land on which our midstream systems have been constructed is not owned in fee by us. Most of our pipelines and facilities are located on properties that are held by surface use agreements, rights-of-way or other easement rights. We are, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way or otherwise, could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
A shortage of equipment and skilled labor in the Appalachian Basin could reduce equipment availability and labor productivity and increase labor and equipment costs, which could have a material adverse effect on our business and results of operations.
Our gathering and other midstream services require special equipment and laborers who are skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. If we experience shortages of necessary equipment or skilled labor in the future, our labor and equipment costs and overall productivity could be materially and adversely affected. If our equipment or labor prices increase or if we experience materially increased health and benefit costs for employees, our business and results of operations could be materially and adversely affected.
We do not have any officers or employees and rely on officers of our general partner and employees of CNX.
We are managed and operated by the board of directors and executive officers of our general partner. Our general partner has no employees and relies on the employees of CNX to conduct our business and activities.
CNX conducts businesses and activities of its own in which we have no economic interest. As a result, there could be material competition for the time and effort of the officers and employees who provide services to both our general partner and CNX. If our general partner and the officers and employees of CNX do not devote sufficient attention to the management and operation of our business and activities, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially adversely affected.
Our success depends on key members of our general partner’s senior management team and our ability to attract and retain experienced technical and other professional personnel.
Our future success depends to a large extent on the services of our general partner’s key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.
Debt we incur 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 (including building additional gathering pipelines needed for required connections and building additional compression and treating facilities pursuant to our gathering agreements) or other purposes may be impaired or such financing may not be available on favorable terms; |
33
| • | our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt; |
| • | 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 debt will depend 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 indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. 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 business, common unit price, our ability to issue equity or incur debt for acquisitions, capital expenditures or other purposes and our ability to make cash distributions at our intended levels.
Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Rising interest rates could reduce the amount of cash we generate and materially adversely affect our liquidity and our ability to pay cash distributions. Moreover, the trading price of our units is sensitive to changes in interest rates and could be materially adversely affected by any increase in interest rates. As with other yield-oriented securities, our common unit price will be impacted by the level of our 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 our common units, and a rising interest rate environment could have an adverse impact on our common unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make cash distributions at our intended levels.
Assuming an outstanding balance on the revolving credit facility of $149.5 million, an increase of one percentage point in the interest rates would have resulted in an increase in interest expense during 2017 of $1.5 million. Accordingly, our results of operations, cash flows and financial condition, all of which affect our ability to make cash distributions to our unitholders, could be materially adversely affected by significant increases in interest rates.
Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations.
Terrorist attacks or cyber-attacks may significantly affect the energy industry, and economic conditions, including our operations and our customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States.
Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Our insurance may not protect us against such occurrences.
The oil and gas industry has become increasingly dependent on digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our employees and business partners, and to conduct day-to-day operations including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines. Our business partners, including vendors, service providers, and financial institutions, are also dependent on digital technology.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also has increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA (supervisory control and data acquisition) based systems are potentially vulnerable to targeted cyber-attacks due to their critical role in operations.
Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
Deliberate attacks on our assets, or security breaches in our systems or infrastructure, the systems or infrastructure of third-parties, or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third -party liability, including the following:
34
| • | a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;3 |
| • | a cyber-attack on our facilities may result in equipment damage or failure; |
| • | a cyber-attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues; |
| • | a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues; |
| • | a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and |
| • | business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our units. |
Our implementation of various controls and processes, including globally incorporating a risk-based cyber security framework, to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
Risks Inherent in an Investment in Us
Our general partner and its affiliates, including CNX, have conflicts of interest with us and limited fiduciary duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of CNX, and CNX is under no obligation to adopt a business strategy that favors us.
As of January 3, 2018, CNX owns an aggregate 33.43% limited partner interest in us. CNX, through its ownership of CNX Gathering, also owns a 2.0% general partner interest and owns and controls our general partner. In addition, CNX Gathering owns 95% noncontrolling equity interests in each of our Growth Systems and Additional Systems. Although our general partner has a duty to manage us in a manner that is in the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of its owner, CNX Gathering, which is owned by CNX. Conflicts of interest may arise between CNX and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including CNX, over the interests of our common unitholders. These conflicts include, among others, the following situations:
| • | neither our partnership agreement nor any other agreement requires CNX to pursue business strategies that favor us or utilize our assets, which could involve decisions by CNX to increase or decrease natural gas production on our dedicated acreage, release portions of their dedicated acreage, as permitted by the terms the gas gathering agreements, pursue and grow particular markets or undertake acquisition opportunities for itself. CNX’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of CNX; |
| • | CNX may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests; |
| • | our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law; |
| • | except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; |
| • | our general partner determines the amount and timing of, among other things, cash expenditures, borrowings and repayments of indebtedness, the issuance of additional partnership interests, the creation, increase or reduction in cash reserves in any quarter and asset purchases and sales, each of which can affect the amount of cash that is available for distribution to unitholders; |
| • | our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus generated in any given period; |
| • | our general partner determines which costs incurred by it are reimbursable by us; |
| • | our general partner may cause us to borrow funds in order to permit the payment of cash distributions or to make incentive distributions; |
| • | our partnership agreement permits us to classify up to $50.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash |
35
may be used to fund distributions to our general partner in respect of the general partner interest or the incentive distribution rights;
| • | our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; |
| • | our general partner intends to limit its liability regarding our contractual and other obligations; |
| • | our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80% of the common units; |
| • | our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including our gathering agreements with CNX; |
| • | our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and |
| • | our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units and general partner interests to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our common unitholders. This election could result in lower distributions to our common unitholders in certain situations. |
Neither our partnership agreement nor our omnibus agreement prohibits CNX or any other affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including CNX and executive officers and directors of our general partner. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us does not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Consequently, CNX and other affiliates of our general partner, including CNX Gathering, may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from CNX and other affiliates of our general partner could materially and adversely impact our results of operations and distributable cash flow. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to 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. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of 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 partnership interests in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional partnership interests may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional partnership interests, including partnership interests ranking senior to our common units as to distributions or in liquidation or that have special voting rights and other rights, and our common unitholders have no preemptive or other rights (solely as a result of their status as common unitholders) to purchase any such additional partnership interests. The incurrence of additional commercial bank borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash that we have available to distribute to our unitholders.
Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.
Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership, provided that the partnership agreement may not eliminate the implied contractual covenant of good faith and fair dealing. This implied covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts, and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action.
As permitted by Delaware law, 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
36
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 unitholders. 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 limited partners. By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above.
Our partnership agreement restricts the remedies available to holders of our common units 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 unitholders 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 makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner 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 determination or the decision to take or decline to take such action was in the best interests of our partnership, and 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; |
| • | provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith; |
| • | provides that 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 |
| • | provides that our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement. |
In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Cost reimbursements, which will be determined in our general partner’s sole discretion, and fees due our general partner and its affiliates for services provided will be substantial and will reduce the amount of cash we have available for distribution to unitholders.
Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our omnibus agreement and operational services agreement, our general partner determines the amount of these expenses. Under the terms of the omnibus agreement we are required to reimburse CNX for the provision of certain administrative support services to us. Under our operational services agreement, we are required to reimburse CNX for the provision of certain maintenance, operating, administrative and construction services in support of our operations. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner. The costs and expenses for which we will reimburse our general partner and its affiliates may include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The costs and expenses for which we are required to reimburse our general partner and its affiliates are not subject to any caps or other limits. Payments to our general partner and its affiliates will be substantial and will reduce the amount of cash we have available to distribute to unitholders.
Unitholders have very limited voting rights and, even if they are dissatisfied, they will have limited ability to remove our general partner.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. For example, unlike holders of stock in a public corporation, unitholders have no “say-on-pay” advisory voting rights. Unitholders have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by its sole member, CNX Gathering, which is owned by CNX. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner.
37
As a result of these limitations, the price at which our common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Our general partner may not be removed unless such removal is both (i) for cause and (ii) approved by a vote of the holders of at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. “Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable to us or any limited partner for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business. As of January 3, 2018, CNX owns approximately 34.1% of our total outstanding common units. As a result, our public unitholders have limited ability to remove our general partner.
Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.
Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of CNX Gathering to transfer its membership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices.
The incentive distribution rights held by our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.
We may issue an unlimited number of additional partnership interests without unitholder approval, which would dilute unitholder interests.
At any time, we may issue an unlimited number of general partner interests or limited partner interests of any type without the approval of our unitholders, and our unitholders have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such general partner interests or limited partner interests. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
| • | our unitholders’ proportionate ownership interest in us will decrease; |
| • | the amount of cash we have available to distribute on each unit may decrease; |
| • | the ratio of taxable income to distributions may increase; |
| • | the relative voting strength of each previously outstanding unit may be diminished; and |
| • | the market price of our common units may decline. |
The issuance by us of additional general partner interests may have the following effects, among others, if such general partner interests are issued to a person who is not an affiliate of CNX:
| • | management of our business may no longer reside solely with our current general partner; and |
| • | affiliates of the newly admitted general partner may compete with us, and neither that general partner nor such affiliates will have any obligation to present business opportunities to us except with respect to rights of first offer contained in our omnibus agreement. |
38
CNX or Noble Energy may sell common units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
CNX currently holds 21,692,198 common units. Our partnership agreement provides CNX with certain registration rights under applicable securities laws. In connection with CNX’s acquisition of Noble Energy’s interest in CNX Gathering, we entered into a registration rights agreement (the “RRA”) with an affiliate of Noble Energy. The RRA provides Noble Energy with certain registration rights with respect to the resale of up to 21,692,198 common units, which equals all the common units that Noble Energy holds following conversion of the subordinated units. The sale of the common units held by CNX or Noble Energy in the public or private markets could have an adverse impact on the market for and price of our common units.
Our general partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to unitholders.
Affiliates of our general partner, including CNX and CNX Gathering, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us except with respect to rights of first offer contained in our omnibus agreement.
Neither our partnership agreement nor our omnibus agreement prohibit CNX or any other affiliates of our general partner, including CNX Gathering, from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including CNX and executive officers and directors of our general partner. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Consequently, CNX and other affiliates of our general partner, including CNX Gathering, may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from CNX and other affiliates of our general partner could materially and adversely impact our results of operations and distributable cash flow.
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of our then-outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on your investment. Our unitholders may also incur a tax liability upon a sale of their units. As of January 3, 2018, CNX owns approximately 34.1% of our common units.
Our general partner intends to limit its liability regarding our contractual and other obligations.
Our general partner intends to limit its liability under contractual arrangements and other obligations between us and third parties so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets (or against any affiliate of our general partner or its assets). Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
39
Unitholders may have to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units and general partner interests to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of our conflicts committee or our common unitholders. This election could result in lower distributions to our common unitholders in certain situations.
Our general partner has the right, at any time when it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48%, in addition to distributions paid on its 2% general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and a general partner interest. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in such two quarters. Our general partner will also be issued an additional general partner interest necessary to maintain our general partner’s interest in us at the level that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units and general partner interests in connection with resetting the target distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee shall have the same rights as the general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled.
Units held by persons who our general partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption.
As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our common units to certify that they are both U.S. citizens and subject to U.S. federal income taxation on our income. Units held by persons who our general partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption. “Eligible holders” are limited partners whose (or whose owners’) (i) U.S. federal income tax status or lack of proof of U.S. federal income tax status does not have and is not reasonably likely to have, as determined by our general partner, a material adverse effect on the rates that can be charged to customers by us or our subsidiaries with respect to assets that are subject to regulation by the Federal Energy Regulatory Commission or similar regulatory body and (ii) nationality, citizenship or other related status does not create and is not reasonably likely to create, as determined by our general partner, a substantial risk of cancellation or forfeiture of any property in which we have an interest. The aggregate redemption price for redeemable interests will be an amount equal to the current market price (the date of determination of which will be the date fixed for redemption) of limited partner interests of the class to be so redeemed multiplied by the number of limited partner interests of each such class included among the redeemable interests. For these purposes, the “current market price” means, as of any date for any class of limited partner interests, the average of the daily closing prices per limited partner interest of such class for the 20 consecutive trading days immediately prior to such date. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. The units held by any person the general partner determines is not an eligible holder will not be entitled to voting rights.
40
Our partnership agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which limits our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.
Our partnership agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) shall be the exclusive forum for any claims, suits, actions or proceedings (i) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (ii) brought in a derivative manner on our behalf, (iii) asserting a claim of breach of a duty owed by any of our, or our general partner’s, directors, officers, or other employees, or owed by our general partner, to us or our partners, (iv) asserting a claim against us arising pursuant to any provision of the Delaware Act or (v) asserting a claim against us governed by the internal affairs doctrine.
If any person brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. In addition, our partnership agreement provides that each limited partner irrevocably waives the right to trial by jury in any such claim, suit, action or proceeding. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on the NYSE under the symbol “CNXM.” Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
Our partnership is organized under Delaware law. Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right of, by the limited partners as a group to:
| • | remove or replace our general partner for cause; |
| • | approve some amendments to our partnership agreement; or |
| • | take other action under our partnership agreement; |
constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.
Our operating subsidiaries conduct business in Pennsylvania and West Virginia. We may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a partner or member of our subsidiaries may require compliance with legal requirements in the jurisdictions in which such subsidiaries conduct business, including qualifying such entities to do business there. Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership, respectively, have not been clearly established in many jurisdictions. If, by virtue of our ownership interests in our operating subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the
41
right or exercise of the right by the limited partners as a group to remove or replace our general partner for cause, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances.
If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.
Our initial assets consist of direct and indirect ownership interests in our operating subsidiaries. If a sufficient amount of our assets, such as our ownership interests in these subsidiaries or other assets acquired in the future, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940 (the “Investment Company Act”), we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. In that event, it is possible that our ownership of these interests, combined with our assets acquired in the future, could result in our being required to register under the Investment Company Act if we were not successful in obtaining exemptive relief or otherwise modifying our organizational structure or applicable contract rights. Treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to our unitholders would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
Moreover, registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase of additional interests in our midstream systems from CNX, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.
Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 21%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Several 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 any such taxes may substantially reduce the cash available for distribution to you. Therefore, if we were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.
42
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress and the President have periodically considered substantive changes to the existing U.S. federal income tax laws that would affect the tax treatment of certain publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships. Further, final Treasury regulations under Section 7704(d)(1)(E) of the Code published in the Federal Register interpret the scope of qualifying income requirements for publicly traded partnerships by providing industry-specific guidance. We do not believe these final regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.
Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to satisfy the requirements of the exception pursuant to which we are treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.
Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our distributable cash flow.
For partnership tax years beginning after 2017, the rules for auditing large partnerships and for assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level federal income tax audit were altered. Under these rules, unless we are eligible to, and do, elect to issue revised Schedules K-1 to our partnership with respect to an audited and adjusted partnership tax return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed. If we are required to pay taxes, penalties and interest as a result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited tax year.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.
43
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income.
We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of Treasury and the IRS issued Treasury Regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of the common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, in certain circumstances, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
44
As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders are likely subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently conduct business in Pennsylvania and West Virginia. Both Pennsylvania and West Virginia currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns.
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
| ITEM 2. | PROPERTIES |
For a description of the Partnership’s properties, see Item 1. “Business”, which is incorporated herein by reference.
| ITEM 3. | LEGAL PROCEEDINGS |
For a description of the Partnership’s legal proceedings, see Item 8, Note 11–Commitments and Contingencies, which is incorporated herein by reference.
| ITEM 4. | MINE SAFETY AND DISCLOSURES |
Not applicable.
45
PART II
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Effective January 4, 2018, the Partnership’s common units are listed on the NYSE under the symbol “CNXM.” Prior to January 4, 2018, the Partnership’s common units were listed on the NYSE under the symbol “CNNX.” The following table sets forth the range of high and low sales prices of the Partnership’s common units as reported on the NYSE and the cash distributions per unit declared on the common units during each quarter for the years ended December 31, 2017 and 2016:
| High | Low | Distributions | |||||||||||
| Year ended December 31, 2017: | |||||||||||||
| Quarter ended December 31, 2017 | $ | 17.76 | $ | 15.25 | $ | 0.3025 | |||||||
| Quarter ended September 30, 2017 | $ | 21.00 | $ | 15.82 | $ | 0.2922 | |||||||
| Quarter ended June 30, 2017 | $ | 23.78 | $ | 17.13 | $ | 0.2821 | |||||||
| Quarter ended March 31, 2017 | $ | 25.56 | $ | 20.30 | $ | 0.2724 | |||||||
| Year ended December 31, 2016: | |||||||||||||
| Quarter ended December 31, 2016 | $ | 24.24 | $ | 17.89 | $ | 0.2630 | |||||||
| Quarter ended September 30, 2016 | $ | 19.86 | $ | 16.03 | $ | 0.2540 | |||||||
| Quarter ended June 30, 2016 | $ | 18.43 | $ | 12.19 | $ | 0.2450 | |||||||
| Quarter ended March 31, 2016 | $ | 12.99 | $ | 7.55 | $ | 0.2362 | |||||||
Transfer Agent and Registrar
The transfer agent and registrar for our common units is EQ Shareowner Services, 1110 Centre Pointe Curve, Suite 101, Mendota Heights, MN 55120.
Unitholders Profile
We declared a cash distribution of $0.3133 per common unit on January 22, 2018, which will be paid on February 14, 2018 to unitholders of record as of the close of business on February 5, 2018. As of February 1, 2018, there were approximately 11,500 holders of record of our common units.
Equity Compensation Plan Information
Please read “Item 12–Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters - Securities Authorized for Issuance Under Equity Compensation Plans.”
Market Repurchases
The Partnership did not repurchase any of its common units during 2016 or 2017.
Distributions of Available Cash
General
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.
Definition of Available Cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
| • | less, the amount of cash reserves established by our general partner to: |
| ◦ | provide for the proper conduct of our business (including reserves for our future capital expenditures, future acquisitions and anticipated future debt service requirements); |
46
| ◦ | comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which we or any of our subsidiaries is a party or by which we or such subsidiary is bound or we or such subsidiary’s assets are subject; or |
| ◦ | provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions pursuant to this bullet point if the effect of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter); |
| • | plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter. |
The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our Partnership Agreement, working capital borrowings are generally borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to our partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.
Intent to Distribute the Minimum Quarterly Distribution
Under the Partnership’s current cash distribution policy, the Partnership intends to make a minimum quarterly distribution to the holders of common units of $0.2125 per unit, or $0.85 per unit on an annualized basis, to the extent the Partnership has sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that the Partnership will pay the minimum quarterly distribution on those units in any quarter. The amount of distributions paid under the Partnership’s cash distribution policy and the decision to make any distribution will be determined by our general partner, taking into consideration the terms of the partnership agreement. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
General Partner Interest and Incentive Distribution Rights
Initially, our general partner is entitled to 2% of all quarterly distributions that we make prior to our liquidation and has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions will be reduced if we issue additional limited partner interests in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest.
Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48%, of the available cash we distribute from operating surplus in excess of $0.24438 per unit per quarter. The maximum distribution of 48% does not include any distributions that our general partner or its affiliates may receive on common units or the general partner interest that they own.
47
| ITEM 6. | SELECTED FINANCIAL DATA |
The following table presents selected financial data of CNX Gathering LLC (“CNX Gathering”), which is our Predecessor for accounting purposes, as of and for the year ended December 31, 2013 and of CNX Midstream Partners LP as of and for the years ended December 31, 2017, 2016, 2015 and 2014. The selected consolidated balance sheet data as of December 31, 2017 and 2016 and the selected consolidated statement of operations data and of cash flows data for the years ended December 31, 2017, 2016 and 2015 have been derived from our audited consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The selected consolidated balance sheet data as of December 31, 2015, 2014 and 2013 and the selected consolidated statement of operations data and of cash flows data for the years ended December 31, 2014 and 2013 have been derived from our audited consolidated financial statements and related notes not included in this Annual Report on Form 10-K. The selected historical financial data of our Predecessor as of and for the year ended December 31, 2013 are derived from the audited financial statements of our Predecessor.
Predecessor financial data consists of the assets and operations of CNX Gathering on a 100% basis until the closing of our IPO. In connection with the closing of our IPO on September 30, 2014, CNX Gathering contributed to us a 75% controlling interest in our Anchor Systems, a 5% controlling interest in our Growth Systems and a 5% controlling interest in our Additional Systems. Effective November, 16, 2016, the Partnership completed the acquisition of the remaining 25% noncontrolling interest in our Anchor Systems, which brought the Partnership’s controlling ownership in that system to 100%. As required by accounting principles generally accepted in the United States (“GAAP”), we consolidate 100% of the assets and operations of all of our operating subsidiaries in our financial statements for all periods following the IPO. Net income attributable to general and limited partner ownership interest in CNX Midstream Partners LP includes only the unitholders’ controlling interests in the Partnership following the IPO.
The following table should be read together with, and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes included in this Annual Report on Form 10-K. The table should also be read together with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
| For the Years Ended December 31, | ||||||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||
| CONSOLIDATED STATEMENTS OF OPERATIONS: | (in thousands, except per share amounts) | |||||||||||||||||||
| Total gathering revenue | $ | 233,848 | $ | 239,211 | $ | 203,423 | $ | 130,087 | $ | 65,626 | ||||||||||
| Net income | $ | 134,062 | $ | 130,122 | $ | 115,531 | $ | 64,827 | $ | 28,124 | ||||||||||
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP (1) | $ | 114,993 | $ | 96,486 | $ | 71,247 | $ | 15,378 | N/A | |||||||||||
| Net income per limited partner unit - Basic: | ||||||||||||||||||||
| Common units | $ | 1.70 | $ | 1.60 | $ | 1.20 | $ | 0.26 | N/A | |||||||||||
Subordinated units (2) | $ | 1.76 | $ | 1.58 | $ | 1.20 | $ | 0.26 | N/A | |||||||||||
| Net income per limited partner unit - Diluted: | ||||||||||||||||||||
| Common units | $ | 1.70 | $ | 1.59 | $ | 1.20 | $ | 0.26 | N/A | |||||||||||
Subordinated units (2) | $ | 1.76 | $ | 1.58 | $ | 1.20 | $ | 0.26 | N/A | |||||||||||
| As of December 31, | ||||||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||
| CONSOLIDATED BALANCE SHEETS: | (in thousands) | |||||||||||||||||||
| Property and equipment, net | $ | 899,278 | $ | 878,560 | $ | 866,309 | $ | 622,746 | $ | 388,116 | ||||||||||
| Total assets | $ | 926,589 | $ | 918,557 | $ | 924,425 | $ | 686,804 | $ | 409,264 | ||||||||||
| Revolving credit facility | $ | 149,500 | $ | 167,000 | $ | 73,500 | $ | 31,300 | $ | — | ||||||||||
| Total partners’ capital and noncontrolling interest | $ | 751,111 | $ | 725,261 | $ | 803,142 | $ | 582,763 | $ | 368,074 | ||||||||||
48
| For the Years Ended December 31, | ||||||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||
| CASH FLOW STATEMENT DATA: | (in thousands) | |||||||||||||||||||
| Net cash provided by operating activities | $ | 155,550 | $ | 160,089 | $ | 116,017 | $ | 84,694 | $ | 34,514 | ||||||||||
| Net cash used in investing activities | $ | (26,835 | ) | $ | (45,328 | ) | $ | (291,211 | ) | $ | (269,601 | ) | $ | (130,924 | ) | |||||
| Net cash (used in) provided by financing activities | $ | (131,942 | ) | $ | (108,557 | ) | $ | 172,159 | $ | 182,183 | $ | 95,000 | ||||||||
| OTHER DATA: | ||||||||||||||||||||
| Capital expenditures | $ | 48,366 | $ | 50,660 | $ | 291,211 | $ | 269,686 | $ | 130,924 | ||||||||||
EBITDA(3) | $ | 161,314 | $ | 153,122 | $ | 131,419 | $ | 72,181 | $ | 33,949 | ||||||||||
Adjusted EBITDA(3)(5) | $ | 166,404 | $ | 163,980 | $ | 131,821 | $ | 72,181 | $ | 33,949 | ||||||||||
Adjusted EBITDA attributable to general and limited partner ownership interest in CNX Midstream Partners LP(3) | $ | 136,076 | $ | 110,547 | $ | 80,310 | $ | 63,460 | $ | 33,949 | ||||||||||
Distributable Cash Flow(4)(5) | $ | 117,031 | $ | 96,166 | $ | 70,919 | $ | 57,452 | $ | 30,509 | ||||||||||
(1) In 2014, the amount reflects only the general and limited partner interest in net income since the closing of the IPO on September 30, 2014. See Item 8, Note 1 - Description of Business.
(2) | Upon payment of the cash distribution with respect to the quarter ended September 30, 2017, the financial requirements for the conversion of all subordinated units were satisfied. As a result, on November 15, 2017, all 29,163,121 subordinated units converted into common units on a one-for-one basis. For purposes of calculating a) net income allocable to subordinated units and b) weighted average subordinated units outstanding within the net income per common and subordinated unit calculations, the conversion of the subordinated units is deemed to have occurred on October 1, 2017. |
(3) We define EBITDA as net income (loss) before net interest expense, depreciation and amortization, and Adjusted EBITDA as EBITDA adjusted for non-cash items which should not be included in the calculation of distributable cash flow. EBITDA and Adjusted EBITDA are used as supplemental financial measures by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:
| • | our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure; |
| • | the ability of our assets to generate sufficient cash flow to make distributions to our partners; |
| • | 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 investment opportunities. |
We believe that the presentation of EBITDA and Adjusted EBITDA provides information that is useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to EBITDA and Adjusted EBITDA are net income and net cash provided by operating activities. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and Adjusted EBITDA exclude some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, EBITDA and Adjusted EBITDA as presented herein may not be comparable to similarly titled measures of other companies.
(4) We define distributable cash flow as Adjusted EBITDA less net income attributable to noncontrolling interest, cash interest paid and maintenance capital expenditures, each net to the Partnership. Distributable cash flow does not reflect changes in working capital balances.
Distributable cash flow is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:
| • | the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and |
| • | the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities. |
We believe that the presentation of distributable cash flow in this report provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities. Distributable cash flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable cash flow excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, our distributable cash flow may not be comparable to similarly titled measures that other companies may use.
(5) The following table presents a reconciliation of the non-GAAP measures of EBITDA, Adjusted EBITDA, Adjusted EBITDA attributable to CNX Midstream Partners LP and distributable cash flow to the most directly comparable GAAP financial measure of net income.
49
| For the Year Ended December 31, | ||||||||||||||||||||
| (in thousands) | 2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
| Net Income | $ | 134,062 | $ | 130,122 | $ | 115,531 | $ | 64,827 | $ | 28,124 | ||||||||||
| Depreciation expense | 22,692 | 21,201 | 15,053 | 7,330 | 5,825 | |||||||||||||||
| Interest expense | 4,560 | 1,799 | 835 | 24 | — | |||||||||||||||
| EBITDA | $ | 161,314 | $ | 153,122 | $ | 131,419 | $ | 72,181 | $ | 33,949 | ||||||||||
| Non-cash unit-based compensation expense | 1,176 | 775 | 402 | — | — | |||||||||||||||
| Loss on asset sales | 3,914 | 10,083 | — | — | — | |||||||||||||||
| Adjusted EBITDA | $ | 166,404 | $ | 163,980 | $ | 131,821 | $ | 72,181 | $ | 33,949 | ||||||||||
| Less: | ||||||||||||||||||||
| Net income attributable to noncontrolling interest | 19,069 | 33,636 | 44,284 | 7,858 | — | |||||||||||||||
| Depreciation expense attributable to noncontrolling interest | 7,147 | 9,597 | 6,799 | 863 | — | |||||||||||||||
| Other expenses attributable to noncontrolling interest | 394 | 621 | 428 | — | — | |||||||||||||||
| Loss on asset sales attributable to noncontrolling interest | 3,718 | 9,579 | — | — | — | |||||||||||||||
| Adjusted EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP | $ | 136,076 | $ | 110,547 | $ | 80,310 | $ | 63,460 | $ | 33,949 | ||||||||||
| Less: cash interest paid, net | 4,387 | 1,310 | 407 | — | — | |||||||||||||||
| Less: maintenance capital expenditures, net of reimbursements | 14,658 | 13,071 | 8,984 | 6,008 | 3,440 | |||||||||||||||
| Distributable Cash Flow | $ | 117,031 | $ | 96,166 | $ | 70,919 | $ | 57,452 | $ | 30,509 | ||||||||||
50
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this report. The information provided below supplements, but does not form part of, our financial statements. This discussion contains forward‑looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward‑looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact our future operating performance or financial condition, please read see “Item 1A. Risk Factors.” and the section entitled “Cautionary Statement Regarding Forward‑Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Unless otherwise indicated, references in this Annual Report on Form 10-K to the “Predecessor,” “we,” “our,” or “us” or like terms, when referring to period prior to September 30, 2014, refer to CNX Gathering LLC (formerly known as CONE Gathering LLC) our predecessor for accounting purposes. References to the “Partnership,” “we,” “our,” “us” or similar expressions, when referring to periods since September 30, 2014, refer to CNX Midstream Partners LP (formerly known as CONE Midstream Partners LP), including its consolidated subsidiaries.
Overview
We are a growth-oriented master limited partnership focused on the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets to service our customers’ production in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. Our assets include natural gas gathering pipelines and compression and dehydration facilities, as well as condensate gathering, collection, separation and stabilization facilities. We are managed by our general partner, CNX Midstream GP LLC, formerly known as CONE Midstream GP LLC (our “general partner”), which is a wholly owned subsidiary of CNX Gathering LLC, formerly known as CONE Gathering LLC (“CNX Gathering”). CNX Gathering is a wholly owned subsidiary of CNX Resources Corporation, formerly known as CONSOL Energy Inc. (NYSE: CNX) (“CNX”).
We were formed in May 2014 as a joint venture between CNX and Noble Energy, Inc. (NYSE: NBL) (“Noble Energy”). On January 3, 2018, CNX Gas Company LLC (“CNX Gas”), an indirect wholly owned subsidiary of CNX, acquired from NBL Midstream, LLC (“NBL Midstream”), a wholly owned subsidiary of Noble Energy, NBL Midstream’s 50% interest in CNX Gathering for cash consideration of $305.0 million and the mutual release of all outstanding claims between the parties (the “Transaction”).
As a result of the Transaction, CNX became our sole Sponsor.
Joint Development Agreement with Noble Energy
On September 30, 2011, CNX and Noble Energy entered into a Joint Development Agreement (“JDA”) and related ancillary agreements governing their joint exploration and development of their combined acreage in the Marcellus Shale, which comprised an area of mutual interest (“AMI”) that covered portions of 28 counties in West Virginia and 19 counties in Pennsylvania and included over 26,000 square miles (the “Co-Owned Properties”). Pursuant to the JDA, each of CNX and Noble Energy owned an undivided 50% working interest in the jointly owned Marcellus Shale acreage, and under the JDA, any other oil and natural gas interests covering the Marcellus Shale within the AMI that became jointly owned by CNX and Noble Energy would have automatically become part of the upstream acreage.
On December 1, 2016, CNX and Noble Energy consummated an Exchange Agreement (the “Exchange Agreement”), pursuant to which, effective as of October 1, 2016, the JDA was terminated and CNX and Noble Energy separated their Marcellus Shale AMI into two separate operating areas. Under the Exchange Agreement, CNX Gas and Noble Energy exchanged certain jointly owned oil and gas properties and related assets that were previously subject to the JDA. Among other things, under the Exchange Agreement, CNX Gas transferred its interests in certain of the Co-Owned Properties to Noble Energy, and Noble Energy transferred its interests in the remaining Co-Owned Properties to CNX Gas. Following consummation of the Exchange Agreement, each of CNX Gas and Noble Energy owned 100% of their respective upstream interests in the Marcellus Shale.
Noble Energy Sale of Upstream Assets
On June 28, 2017, Noble Energy sold its upstream assets in northern West Virginia and southern Pennsylvania to HG Energy II Appalachia, LLC (“HG Energy”), a portfolio company of Quantum Energy Partners, LP (“Quantum”), effectively making HG Energy the new shipper on the dedicated acreage that was previously owned by Noble Energy (the “Noble Energy Asset Sale”). In connection with the Noble Energy Asset Sale, Noble Energy provided notice to the Partnership of its release of approximately 37,000 undeveloped acres, which were primarily within the Growth and Additional Systems, from amounts
51
dedicated to us as per the terms of our gathering agreement. The Partnership is in the process of confirming the dedication status of the acres that were released.
The Partnership currently gathers the natural gas and condensate volumes produced by HG Energy on our dedicated acreage under the terms of our gathering agreement with Noble Energy, dated December 1, 2016, which was assigned to HG Energy upon consummation of the Noble Energy Asset Sale.
Our Gathering Agreements with CNX Gas and HG Energy
On January 3, 2018, we entered into a new 20-year fixed-fee gathering agreement with CNX Gas that amended and restated the previous gathering agreement with CNX Gas in its entirety. Although the fees for services we provide in the Marcellus Shale for existing wells that were covered under the prior agreement remain unchanged in the new agreement, and are identical to the fees we charge HG Energy (discussed below), the new gas gathering agreement with CNX Gas also dedicates an additional 63,000 of acreage in the Utica Shale in and around the McQuay area and Wadestown area and introduces the following gas gathering and compression rates:
| • | Gas Gathering: |
| ◦ | McQuay area Utica - a fee of $0.225 per MMBtu; and |
| ◦ | Wadestown Marcellus and Utica - a fee of $0.35 per MMBtu. |
| • | Compression: |
| ◦ | For areas not benefitting from system expansion pursuant to the Second Amended and Restated gas gathering agreement, compression services are included in the base fees; and |
| ◦ | In the McQuay and Wadestown areas, for wells turned in line beginning January 1, 2018 and beyond, we will receive additional fees of $0.065 per MMBtu for Tier 1 pressure services (maximum receipt point of pressure of 600 psi) and $0.130 per MMBtu for Tier 2 pressure services (maximum receipt point of pressure of 300 psi). |
Our new gathering agreement with CNX Gas also commits CNX Gas to drill the following numbers of wells in the McQuay area, provided that if 125 wells have been drilled and completed in the Marcellus Shale, then the remainder of such planned wells will be drilled in the Utica Shale. To the extent the requisite amount of wells are not drilled by CNX Gas in a given period, we will be entitled to a deficiency payment per shortfall well as set out in the parenthetical below:
| • | January 1, 2018 to December 31, 2018 - 30 wells (deficiency payment of $3.5 million per well) |
| • | January 1, 2019 to April 30, 2020 - 40 wells (deficiency payment of $3.5 million per well) |
| • | May 1, 2020 to April 30, 2021 - 40 wells (deficiency payment of $2.0 million per well) |
| • | May 1, 2021 to April 30, 2022 - 30 wells (deficiency payment of $2.0 million per well) |
In the event that CNX Gas drills wells and completes a number of wells in excess of the number of wells required to be drilled and completed in such period, (i) the number of excess wells drilled and completed during such period will be applied to the minimum well requirement in the succeeding period or (ii) to the extent CNX Gas was required to make deficiency payments for shortfalls in the preceding period, CNX Gas may elect to cause the Partnership to pay a refund in an amount equal to (x) the number of excess wells drilled and completed during the period, multiplied by (y) the deficiency payment paid per well during the period in which the shortfall occurred.
On December 1, 2016, we entered into new fixed-fee gathering agreements with Noble Energy and CNX Gas that replaced the gathering agreements that had been in place since our IPO. Our gathering agreement with Noble Energy was assigned to HG Energy upon consummation of the Noble Energy Asset Sale effective June 28, 2017. The terms of the agreement remain unchanged following the assignment, except as it relates to HG Energy’s inability to, without the Partnership’s consent, release dedicated acreage in connection with a transfer of such acreage free of the dedication to us, and exercise other initial shipper rights provided under the gathering agreement. Under the gathering agreements with HG Energy and CX Gas, we receive a fee based on the type and scope of the midstream services we provide, summarized as follows effective January 1, 2018:
| • | For the services we provide with respect to natural gas from the Marcellus Shale formation that does not require downstream processing, or dry gas, we receive a fee of $0.431 per MMBtu. |
| • | For the services we provide with respect to the natural gas that requires downstream processing, or wet gas, we receive: |
| ◦ | a fee of $0.296 per MMBtu in the Moundsville area (Marshall County, West Virginia); |
| ◦ | a fee of $0.296 per MMBtu in the Pittsburgh International Airport area; and |
| ◦ | a fee of $0.593 per MMBtu for all other areas in the dedication area. |
| • | Our fees for condensate services were $5.38 per Bbl in the Majorsville area and $2.693 per Bbl in the Moundsville area. |
52
Each of the foregoing fees paid by CNX Gas or HG Energy, as applicable, escalates by 2.5% on January 1 on an annual basis, through and including the final calendar year of the initial term. Commencing on January 1, 2035, and as of January 1 thereafter, each of the applicable fees will be adjusted pursuant to the percentage change in CPI-U, but such fees will never escalate of decrease by more than 3%. Notwithstanding the foregoing, from time to time, CNX Gas and HG Energy may request rate reductions under certain circumstances, which are reviewed by the board of directors of our general partner, with oversight, as our board of directors deems necessary, by our conflicts committee. No rate reduction arrangements are currently active.
We provide gas gathering services to CNX Gas and HG Energy for their dedicated natural gas in the Marcellus Shale on a first-priority basis and gather and/or stabilize and store all of CNX Gas’ and HG Energy’s dedicated condensate on a first-priority basis in the Moundsville, Majorsville and Pittsburgh International Airport areas, subject to certain exceptions described in our respective gathering agreements.
We receive ongoing updates from our customers regarding their drilling and development operations, which include detailed descriptions of the drilling plans, production details and well locations for periods that range from up to 24-48 months, as well as more general development plans that may extend as far as ten years. In addition, we regularly meet with CNX Gas and HG Energy to discuss our current plans to timely construct the necessary facilities to be able to provide midstream services to each of them on our dedicated acreage. In the event that we do not perform our obligations under a gathering agreement, CNX Gas or HG Energy, as applicable, will be entitled to certain rights and procedural remedies thereunder, including rate reductions, the temporary and/or permanent release from dedication discussed below and indemnification from us.
Following the Transaction and subsequent new gas gathering agreement between the Partnership and CNX Gas, our gas gathering agreements include dedications of approximately 513,000 aggregate net acres, subject to our confirmation of the dedication status of the acres that were released in connection with the Noble Energy Asset Sale.
Factors Affecting the Comparability of Our Financial Results
On September 30, 2014, in connection with the closing of our IPO, CNX and Noble Energy, through their ownership interest in CNX Gathering, contributed to us a 75% controlling interest in our Anchor Systems, a 5% controlling interest in our Growth Systems and a 5% controlling interest in our Additional Systems, collectively referred to as the “Limited Partnerships.” Accordingly, most income statement line items, including net income, reflect the results of the Limited Partnerships on a 100% basis, with the exception of net income attributable to general and limited partner ownership interests in CNX Midstream Partners LP, which only includes our controlling interests in the Limited Partnerships.
On November 16, 2016 the Partnership acquired the remaining 25% limited partner noncontrolling interest in the Anchor Systems from CNX Gathering in exchange for (i) cash consideration of $140.0 million, (ii) the Partnership’s issuance of 5,183,154 common units representing limited partner interests in the Partnership at an issue price of $20.42 per common unit, and (iii) the Partnership’s issuance to the general partner of an additional general partner interest in the Partnership in an amount necessary for the general partner to maintain its 2% general partner interest in the Partnership (the “Anchor Systems Acquisition”). Our results, net to the Partnership, include 100% of the Anchor Systems beginning on November 16, 2016. Accordingly, our results of operations for the year ended December 31, 2017, net to the Partnership, are not comparable to prior periods.
2017 Highlights
The Partnership continued its solid financial performance during the year ended December 31, 2017. Compared to the year ended December 31, 2016, results attributable to the general and limited partner ownership interests in the Partnership increased primarily as a result of the Anchor Systems Acquisition. Results net to the Partnership, with the exception of operating cash flows, which is reported on a gross consolidated basis, were as follows for the years ended December 31, 2017 and 2016, respectively:
| • | Net income of $115.0 million as compared to $96.5 million; |
| • | Average daily throughput volumes of 1,266 Btu per day (BBtu/d) (or 986 BBtu/d net to the Partnership) as compared to 1,354 BBtu/d (or 869 BBtu/d net to the Partnership); |
| • | Adjusted EBITDA of $136.1 million as compared to $110.5 million; |
| • | Net cash flows provided by operating activities of $155.6 million as compared to $160.1 million; and |
| • | Distributable cash flow of $117.0 million as compared to $96.2 million |
Consistent with the year ended December 31, 2016, current year operating cash flows exceeded the sum of capital expenditures ($48.4 million), distributions to unitholders ($77.1 million) and interest paid not including amortization of revolver fees ($4.3 million) during the year ended December 31, 2017.
53
A discussion of why the above metrics are important to management, and how the non-GAAP financial measures reconcile to their nearest comparable financial measures prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) follows below.
How We Evaluate Our Operations
Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) throughput volumes; (ii) EBITDA and Adjusted EBITDA; (iii) distributable cash flow and (iv) operating expenses.
Throughput Volumes
The amount of revenue we generate primarily depends on the volumes of natural gas and condensate that we gather for our largest customers, our Sponsor and HG Energy, which are primarily affected by upstream development drilling and production volumes from the natural gas wells connected to our gathering pipelines. Their willingness to engage in new drilling is determined by a number of factors, which include the prevailing and projected prices of natural gas and natural gas liquids (“NGLs”), the cost to drill and operate a well, the relative economics of alternative drilling opportunities available to our customers, the availability and cost of capital, and environmental and government regulations.
In order to meet our contractual obligations under our gathering agreements with our Sponsor and HG Energy with respect to new wells drilled on our dedicated acreage, we will likely incur capital expenditures to extend our gathering systems and facilities to the new wells that our Sponsor and HG Energy drill. Our Sponsor, through its ownership interests in CNX Gathering, is responsible for its proportionate share (95%) of the total capital expenditures associated with the ongoing build-out of our midstream systems in each of the Growth and Additional Systems.
Because the production rate of a natural gas well declines over time, we must continually obtain new supplies of natural gas and condensate to maintain or increase the throughput volumes on our midstream systems. Our ability to maintain or increase existing throughput volumes and obtain new supplies of natural gas and condensate are impacted by:
| • | successful drilling activity by our Sponsor and HG Energy on our dedicated acreage and our ability to fund the capital costs required to connect our gathering systems to new wells; |
| • | our ability to utilize the remaining uncommitted capacity on, or add additional capacity to, our gathering systems; |
| • | the level of work-overs and re-completions of wells on existing pad sites to which our gathering systems are connected; |
| • | our ability to increase throughput volumes on our gathering systems by making outlet connections to existing or new third-party pipelines or other facilities, primarily driven by the anticipated supply of and demand for natural gas; |
| • | the number of new pad sites on our dedicated acreage awaiting lateral connections; |
| • | our ability to identify and execute, at returns that are acceptable to us, organic expansion projects to capture incremental volumes from our customers; |
| • | our ability to compete for volumes from successful new wells in the areas in which we operate outside of our dedicated acreage; |
| • | our ability to gather natural gas and condensate that has been released from commitments with our competitors; and |
| • | release of our dedicated acreage, subject to the terms of our gas gathering agreements with CNX Gas and HG Energy. |
We actively monitor producer activity in the areas served by our gathering systems to pursue new supply opportunities.
Adjusted EBITDA & Distributable Cash Flow
Adjusted EBITDA and distributable cash flow are non-GAAP measures that we believe provide information useful to investors in assessing our financial condition and results of operations. For a discussion on how we define Adjusted EBITDA and distributable cash flow and the supporting reconciliations to their most directly comparable GAAP financial measures, please read “Non-GAAP Financial Measures” beginning on page 60.
Operating Expense
Operating expense is comprised of costs directly associated with gathering natural gas at the wellhead and transporting it to interstate and intrastate pipelines, natural gas processing facilities or other delivery points. These costs include electrically-powered compression, direct labor, repairs and maintenance, supplies, ad valorem and property taxes, utilities and contract services. With the exception of electrically-powered compression, these expenses generally remain stable across broad ranges of throughput volumes but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses.
54
Industry Outlook
Although the Partnership does not have significant direct exposure to commodity price risk, our customers are significantly exposed to commodity price risk. Global energy commodity prices have declined in general over the last few years, and natural gas, NGL and crude oil prices have declined as a result of several factors, including increased worldwide natural gas and crude oil supply and strong competition among natural gas and oil producing countries for market share.
On average, Henry Hub natural gas traded at approximately $3.00 per MMBtu throughout 2017, which is an increase from the 2016 average of $2.50 per MMBtu. According to the U.S. Energy Information Administration (“EIA”), prices generally increased throughout 2017 because of lower levels of inventory and the increased exportation of liquid natural gas to other countries. The EIA is forecasting the average to be $2.88 MMBtu in 2018 and $2.92 MMBtu in 2019 due to strong expected production growth in order to meet growing domestic consumption and exports.
Company Outlook
Although our financial performance has been solid over the past few years, our throughput has varied, as we have no control over the drilling activities of our customers. In addition, periods of depressed commodity prices have resulted from time to time in well shut-ins and a lack of drilling on our dedicated acreage. However, we believe the signing of the new gas gathering agreement with CNX Gas and related minimum well commitment, coupled with the closing of the Transaction and CNX becoming our single Sponsor, has the potential to provide a more positive outlook heading into the year ending December 31, 2018 compared to prior years.
We continue to remain committed to delivering cash distribution growth to our investors over the long term. The board of directors of our general partner approves all cash distributions on a quarterly basis, subject to the terms of our partnership agreement, which requires that we distribute all of our available cash each quarter. Available cash is a metric that the board of directors of our general partner has considerable discretion in determining, and it weighs many factors in making this determination, including the consideration of maximizing the long term value and total returns for the holders of our common units.
In order to adapt to the uncertain current environment, we will continue to manage our costs and intend to continue to focus on generating distributable cash flows through depressed commodity cycles. The co-ownership structure of our Growth and Additional Systems is designed to reduce up-front capital expenditure burdens on the Partnership while also facilitating drop downs of additional interests from CNX Gathering. Although we expect that CNX, through its 100% membership interest in CNX Gathering, will continue to present us with drop down opportunities in the future, we do not know when or if such opportunities may be presented. Please read Item 1A. “Risk Factors - We may be unable to grow by acquiring noncontrolling interests in our operating subsidiaries owned by CNX Gathering, which could limit our ability to increase our distributable cash flow” for more information.
For the year ending December 31, 2018, we anticipate capital expenditures attributable to the Partnership will be between $70 million and $80 million, of which approximately $12 million to $14 million is expected to be for maintenance capital. The board of directors of our general partner may approve additional growth capital during the year at their discretion.
55
Results of Operations
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
| For the Years Ended December 31, | ||||||||||||||
| (in thousands) | 2017 | 2016 | Change ($) | Change (%) | ||||||||||
| Revenue | ||||||||||||||
| Gathering revenue — related party | $ | 184,693 | $ | 239,211 | $ | (54,518 | ) | (22.8 | )% | |||||
| Gathering revenue — third party | 49,155 | — | 49,155 | 100.0 | % | |||||||||
| Total Revenue | 233,848 | 239,211 | (5,363 | ) | (2.2 | )% | ||||||||
| Expenses | ||||||||||||||
| Operating expense — third party | 26,640 | 30,405 | (3,765 | ) | (12.4 | )% | ||||||||
| Operating expense — related party | 25,513 | 29,771 | (4,258 | ) | (14.3 | )% | ||||||||
| General and administrative expense — third party | 5,506 | 5,174 | 332 | 6.4 | % | |||||||||
| General and administrative expense — related party | 10,961 | 10,656 | 305 | 2.9 | % | |||||||||
| Loss on asset sales | 3,914 | 10,083 | (6,169 | ) | (61.2 | )% | ||||||||
| Depreciation expense | 22,692 | 21,201 | 1,491 | 7.0 | % | |||||||||
| Interest expense | 4,560 | 1,799 | 2,761 | 153.5 | % | |||||||||
| Total Expense | 99,786 | 109,089 | (9,303 | ) | (8.5 | )% | ||||||||
| Net Income | $ | 134,062 | $ | 130,122 | $ | 3,940 | 3.0 | % | ||||||
| Less: Net income attributable to noncontrolling interest | 19,069 | 33,636 | (14,567 | ) | (43.3 | )% | ||||||||
| Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP | $ | 114,993 | $ | 96,486 | $ | 18,507 | 19.2 | % | ||||||
Operating Statistics - Gathered Volumes for the Year Ended December 31, 2017
| Anchor | Growth | Additional | TOTAL | NET TOTAL (*) | ||||||||||
| Dry gas (BBtu/d) | 595 | 47 | 15 | 657 | 598 | |||||||||
| Wet gas (BBtu/d) | 372 | 4 | 220 | 596 | 383 | |||||||||
| Condensate (MMcfe/d) | 5 | — | 8 | 13 | 5 | |||||||||
| Total gathered volumes | 972 | 51 | 243 | 1,266 | 986 | |||||||||
Operating Statistics - Gathered Volumes for the Year Ended December 31, 2016
| Anchor | Growth | Additional | TOTAL | NET TOTAL (*) | ||||||||||
| Dry gas (BBtu/d) | 714 | 63 | 20 | 797 | 560 | |||||||||
| Wet gas (BBtu/d) | 381 | 6 | 160 | 547 | 305 | |||||||||
| Condensate (MMcfe/d) | 5 | — | 5 | 10 | 4 | |||||||||
| Total gathered volumes | 1,100 | 69 | 185 | 1,354 | 869 | |||||||||
(*) In each table, represents throughput volumes net of the noncontrolling interests owned by CNX Gathering. As a result of our acquisition on November 16, 2016 of the remaining 25% noncontrolling interest in the Anchor Systems, net income attributable to general and limited partner ownership interests in the Partnership includes 100% of the results of the Anchor Systems for the periods subsequent to the closing date of that transaction.
Revenue
Our revenue typically increases or decreases as our customers’ production on our dedicated acreage increases or decreases. Since we charge a higher fee for natural gas that is shipped through our wet system than through our dry system, our revenue can also be impacted by the relative mix of gathered volumes by area, which may vary dependent upon our customers’ elections as to where to deliver their produced volumes, which may change dynamically depending on the most current commodity prices at the time of shipment.
Total revenue decreased approximately 2.2% to $233.8 million for the year ended December 31, 2017 compared to approximately $239.2 million for the year ended December 31, 2016, while gathered volumes decreased approximately 6.5% in
56
the current year compared to the prior year. The volume decrease was primarily within our Anchor Systems. The revenue decrease compared to the prior year was less than the volume decrease primarily because of the positive mix of wet gas gathered versus dry gas gathered in the current year compared to the prior year, coupled with the annual 2.5% increase in gathering fees that we charge pursuant to our gas gathering agreements.
The fees we charged CNX and Noble Energy, prior to consummation of the Noble Energy Asset Sale on June 28, 2017, were recorded in gathering revenue - related party in our consolidated statements of operations. Following consummation of the Noble Energy Asset Sale, fees from gathering services we performed for HG Energy, as well as gathering services we performed on behalf of another third party shipper, were recorded in gathering revenue - third party in our results of operations.
Operating Expense
Total operating expense was approximately $52.2 million for the year ended December 31, 2017 compared to approximately $60.2 million for the year ended December 31, 2016. Included in total operating expense is electrically-powered compression expense of $16.4 million for the year ended December 31, 2017 compared to $16.9 million for the year ended December 31, 2016, which was reimbursed by our customers pursuant to our gas gathering agreements. After adjusting for the electrically-powered compression expense reimbursement, operating expenses decreased by approximately 17.3% in the current year when compared to the prior year, primarily as a result of continued adherence to operating cost control measures implemented by our operations team throughout the year.
General and Administrative Expense
General and administrative expense is comprised of direct charges for the management and operation of our assets. Total general and administrative expense was approximately $16.5 million for the year ended December 31, 2017 compared to approximately $15.8 million for the year ended December 31, 2016. The increase year over year is related primarily to legal and other professional costs incurred related to the Transaction, compared to those costs incurred in the prior year as a result of the Anchor Systems Acquisition and the dissolution of the upstream joint venture originally formed by CNX and Noble Energy.
Loss on Asset Sales
During the year ended December 31, 2017, we sold property and equipment with a carrying value of $17.4 million to CNX Gas for $14.0 million in cash proceeds. Our sale of midstream assets resulted in a loss of $3.4 million, which was recorded in loss on asset sales in the accompanying consolidated statement of operations. The assets that were sold were previously within the Additional Systems; accordingly the net impact to earnings attributable to general and limited partners’ ownership interests in the Partnership was $0.2 million. In addition, we sold a significant portion of our pipe stock in the Growth Systems segment to an unrelated third party for approximately $0.5 million below its carrying value during the year ended December 31, 2017.
During the year ended December 31, 2016, we sold a portion of excess pipe stock from the Growth Systems segment to an unrelated third party for an amount that was below its carrying value. We recorded a loss of $10.1 million related to the sale during the 2016 period; however, the net impact to earnings attributable to general and limited partners’ ownership interests in the Partnership was $0.5 million.
Depreciation
Depreciation expense is recognized on gathering and other equipment on a straight-line basis, with useful lives ranging from 25-40 years. Total depreciation expense was approximately $22.7 million for the year ended December 31, 2017 compared to approximately $21.2 million for the year ended December 31, 2016. The increase is the result of additional assets placed into service over time.
Interest Expense
Interest expense is primarily comprised of interest on the outstanding balance under our revolving credit facility. Interest expense was approximately $4.6 million in the year ended December 31, 2017 compared to approximately $1.8 million for the year ended December 31, 2016. The increase is primarily due to the increase in our average outstanding balance under our revolving credit facility for the year ended December 31, 2017 compared to the year ended December 31, 2016, which is primarily attributable to borrowings incurred under our revolving credit facility in November 2016 to fund the consideration paid in connection with the Anchor Systems Acquisition.
57
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
| For the Years Ended December 31, | ||||||||||||||
| (in thousands) | 2016 | 2015 | Change ($) | Change (%) | ||||||||||
| Revenue | ||||||||||||||
| Gathering revenue — related party | $ | 239,211 | $ | 203,423 | $ | 35,788 | 17.6 | % | ||||||
| Total Revenue | 239,211 | 203,423 | 35,788 | 17.6 | % | |||||||||
| Expenses | ||||||||||||||
| Operating expense — third party | 30,405 | 28,987 | 1,418 | 4.9 | % | |||||||||
| Operating expense — related party | 29,771 | 29,937 | (166 | ) | (0.6 | )% | ||||||||
| General and administrative expense — third party | 5,174 | 4,444 | 730 | 16.4 | % | |||||||||
| General and administrative expense — related party | 10,656 | 8,636 | 2,020 | 23.4 | % | |||||||||
| Loss on asset sales | 10,083 | — | 10,083 | 100.0 | % | |||||||||
| Depreciation expense | 21,201 | 15,053 | 6,148 | 40.8 | % | |||||||||
| Interest expense | 1,799 | 835 | 964 | 115.4 | % | |||||||||
| Total Expense | 109,089 | 87,892 | 21,197 | 24.1 | % | |||||||||
| Net Income | $ | 130,122 | $ | 115,531 | $ | 14,591 | 12.6 | % | ||||||
| Less: Net income attributable to noncontrolling interest | 33,636 | 44,284 | (10,648 | ) | (24.0 | )% | ||||||||
| Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP | $ | 96,486 | $ | 71,247 | $ | 25,239 | 35.4 | % | ||||||
Operating Statistics - Gathered Volumes for the Year Ended December 31, 2016
| Anchor | Growth | Additional | TOTAL | NET TOTAL (*) | ||||||||||
| Dry gas (BBtu/d) | 714 | 63 | 20 | 797 | 560 | |||||||||
| Wet gas (BBtu/d) | 381 | 6 | 160 | 547 | 305 | |||||||||
| Condensate (MMcfe/d) | 5 | — | 5 | 10 | 4 | |||||||||
| Total gathered volumes | 1,100 | 69 | 185 | 1,354 | 869 | |||||||||
Operating Statistics - Gathered Volumes for the Year Ended December 31, 2015
| Anchor | Growth | Additional | TOTAL | NET TOTAL (*) | ||||||||||
| Dry gas (BBtu/d) | 468 | 81 | 9 | 558 | 355 | |||||||||
| Wet gas (BBtu/d) | 345 | 8 | 169 | 522 | 267 | |||||||||
| Condensate (MMcfe/d) | 8 | — | 11 | 19 | 7 | |||||||||
| Total gathered volumes | 821 | 89 | 189 | 1,099 | 629 | |||||||||
(*) In each table, represents throughput volumes net of the noncontrolling interests owned by CNX Gathering. As a result of our acquisition on November 16, 2016 of the remaining 25% noncontrolling interest in the Anchor Systems, net income attributable to general and limited partner ownership interests in the Partnership includes 100% of the results of the Anchor Systems for the period subsequent to the closing date of that transaction.
Revenue
Our revenue typically increases or decreases as our customers’ production on our dedicated acreage increases or decreases. Since we charge a higher fee for natural gas that is shipped through our wet system than through our dry system, our revenue can also be impacted by the relative mix of gathered volumes by area, which may vary dependent upon our customers’ elections as to where to deliver their produced volumes, which may change dynamically depending on the most current commodity prices at the time of shipment.
Gathering revenue — related party was approximately $239.2 million for the year ended December 31, 2016 compared to approximately $203.4 million for the year ended December 31, 2015. The $35.8 million increase was primarily due to a 239 BBtu/d increase in natural gas gathered in our customers’ dry gas production area and a 16 BBtu/d increase in natural gas volumes in our customers’ wet gas and condensate production areas.
58
From a segment perspective, the dry gas increase during the year ended December 31, 2016 was primarily related to a 246 BBtu/d increase at our Anchor System, which was partially offset by a net seven BBtu/d decrease related to the Growth and Additional Systems. The wet gas and condensate increase was primarily the result of increased production of 33 BBtu/d within our Anchor System, which was partially offset by a 17 BBtu/d decrease in production in our Growth and Additional Systems.
Operating Expense
Total operating expense was approximately $60.2 million for the year ended December 31, 2016 compared to approximately $58.9 million for the year ended December 31, 2015, an increase of $1.3 million. Included in total operating expense is electrically-powered compression expense of $16.9 million and $15.9 million for the years ended December 31, 2016 and 2015, respectively, which was reimbursed by our customers pursuant to our gas gathering agreements. After adjusting for the compression expense reimbursement, operating expenses were generally flat year over year despite substantial throughput growth. This was primarily the result of cost control measures implemented by our operations team as they continue to refine their processes and improve facility efficiencies.
General and Administrative Expense
General and administrative expense is comprised of direct charges for the management and operation of our assets. Total general and administrative expense was approximately $15.8 million for the year ended December 31, 2016 compared to approximately $13.1 million for the year ended December 31, 2015. The $2.7 million increase was due to a variety of factors, including increased salary and benefits expenses to support increased throughput and earnings growth and approximately $0.9 million in legal and other professional fees that were incurred in connection with the Anchor Systems Acquisition and the dissolution of the upstream joint venture originally formed by CNX and Noble Energy.
Loss on Asset Sales
During the year ended December 31, 2016, management sold a portion of existing excess pipe stock that was not dedicated to specific capital projects to an unrelated third party for an amount that was below its carrying cost. Accordingly, we reduced the carrying value of the remaining excess pipe stock to the value that was commensurate with the price agreed to with the third party. The result was a negative impact to consolidated net income of $10.1 million during the year ended December 31, 2016; however, since the value loss was entirely within the Growth System, the net impact to earnings attributable to general and limited partners’ ownership interests in the Partnership was $0.5 million.
Depreciation
Depreciation expense is recognized on gathering and other equipment on a straight-line basis, with useful lives ranging from 25-40 years. Total depreciation expense was approximately $21.2 million for the year ended December 31, 2016 compared to approximately $15.1 million for the year ended December 31, 2015. The increase of $6.1 million was primarily related to our significant capital spending in 2015 and the resulting assets that were placed into service.
59
Non-GAAP Financial Measures
EBITDA and Adjusted EBITDA
We define EBITDA as net income (loss) before net interest expense, depreciation and amortization, and Adjusted EBITDA as EBITDA adjusted for non-cash items which should not be included in the calculation of distributable cash flow. EBITDA and Adjusted EBITDA are used as supplemental financial measures by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:
| • | our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure; |
| • | the ability of our assets to generate sufficient cash flow to make distributions to our partners; |
| • | 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 investment opportunities. |
We believe that the presentation of EBITDA and Adjusted EBITDA provides information that is useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to EBITDA and Adjusted EBITDA are net income and net cash provided by operating activities. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and Adjusted EBITDA exclude some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, EBITDA and Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.
Distributable Cash Flow
We define distributable cash flow as Adjusted EBITDA less net income attributable to noncontrolling interest, cash interest paid and maintenance capital expenditures, each net to the Partnership. Distributable cash flow does not reflect changes in working capital balances.
Distributable cash flow is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:
| • | the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and |
| • | the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities. |
We believe that the presentation of distributable cash flow in this report provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities. Distributable cash flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable cash flow excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, our distributable cash flow may not be comparable to similarly titled measures that other companies may use.
60
The following table presents a reconciliation of the non-GAAP measures of EBITDA, Adjusted EBITDA and distributable cash flow to the most directly comparable GAAP financial measures of net income and net cash provided by operating activities.
| Year Ended December 31, | ||||||||||||
| (in thousands) | 2017 | 2016 | 2015 | |||||||||
| Net Income | $ | 134,062 | $ | 130,122 | $ | 115,531 | ||||||
| Depreciation expense | 22,692 | 21,201 | 15,053 | |||||||||
| Interest expense | 4,560 | 1,799 | 835 | |||||||||
| EBITDA | 161,314 | 153,122 | 131,419 | |||||||||
| Non-cash unit-based compensation expense | 1,176 | 775 | 402 | |||||||||
| Loss on asset sales | 3,914 | 10,083 | — | |||||||||
| Adjusted EBITDA | 166,404 | 163,980 | 131,821 | |||||||||
| Less: | ||||||||||||
| Net income attributable to noncontrolling interest | 19,069 | 33,636 | 44,284 | |||||||||
| Depreciation expense attributable to noncontrolling interest | 7,147 | 9,597 | 6,799 | |||||||||
| Other expenses attributable to noncontrolling interest | 394 | 621 | 428 | |||||||||
| Loss on asset sales attributable to noncontrolling interest | 3,718 | 9,579 | — | |||||||||
| Adjusted EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP | $ | 136,076 | $ | 110,547 | $ | 80,310 | ||||||
| Less: cash interest paid, net | 4,387 | 1,310 | 407 | |||||||||
| Less: maintenance capital expenditures, net of reimbursements | 14,658 | 13,071 | 8,984 | |||||||||
| Distributable Cash Flow | $ | 117,031 | $ | 96,166 | $ | 70,919 | ||||||
| Net Cash Provided by Operating Activities | $ | 155,550 | $ | 160,089 | $ | 116,017 | ||||||
| Interest expense | 4,560 | 1,799 | 835 | |||||||||
| Loss on asset sales | 3,914 | 10,083 | — | |||||||||
| Other, including changes in working capital | 2,380 | (7,991 | ) | 14,969 | ||||||||
| Adjusted EBITDA | 166,404 | 163,980 | 131,821 | |||||||||
| Less: | ||||||||||||
| Net income attributable to noncontrolling interest | 19,069 | 33,636 | 44,284 | |||||||||
| Depreciation expense attributable to noncontrolling interest | 7,147 | 9,597 | 6,799 | |||||||||
| Other expenses attributable to noncontrolling interest | 394 | 621 | 428 | |||||||||
| Loss on asset sales attributable to noncontrolling interest | 3,718 | 9,579 | — | |||||||||
| Adjusted EBITDA attributable to General and Limited Partner ownership interest in CNX Midstream Partners LP | $ | 136,076 | $ | 110,547 | $ | 80,310 | ||||||
| Less: cash interest paid, net | 4,387 | 1,310 | 407 | |||||||||
| Less: maintenance capital expenditures, net of reimbursements | 14,658 | 13,071 | 8,984 | |||||||||
| Distributable Cash Flow | $ | 117,031 | $ | 96,166 | $ | 70,919 | ||||||
Distributable cash flow is a non-GAAP measure that is net to the Partnership. The $20.9 million increase in the current year compared to the prior year was primarily attributable to the Anchor Systems Acquisition consummated in the fourth quarter of 2016. Changes in net cash provided by operating activities are discussed in the “Liquidity and Capital Resources” section below.
61
Liquidity and Capital Resources
Liquidity and Financing Arrangements
We satisfy our working capital requirements, fund capital expenditures and acquisitions, and make cash distributions with cash generated from operations and borrowings under our revolving credit facility. If necessary, we may issue additional equity or debt securities to satisfy the expenditure requirements necessary to support future growth. We believe that cash generated from these sources will continue to be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.
Revolving Credit Facility
We maintain a $250.0 million revolving credit facility, which is available for working capital, capital expenditures, certain acquisitions, distributions, unit repurchases and other lawful partnership purposes. As of December 31, 2017, we had an outstanding balance on our credit facility of $149.5 million, and we incurred $4.3 million of cash interest expense on the revolving credit facility (not including amortization of revolver fees) during the year ended December 31, 2017.
Borrowings under our revolving credit facility bear interest at our option at either:
| • | the base rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) JP Morgan’s prime rate; or (iii) the daily LIBOR rate for a one month interest period plus 1.00%; in each case, plus a margin varying from 0.125% to 1.00% depending on our most recent consolidated total leverage ratio (as defined in the agreement governing our revolving credit facility) or our credit rating; or |
| • | the LIBOR rate plus a margin varying from 1.125% to 2.00%, in each case, depending on our most recent consolidated leverage ratio (as defined in the agreement governing our revolving credit facility) or our credit rating, as the case may be. |
Interest on base rate loans is payable quarterly. Interest on LIBOR loans is payable on the last day of each interest period or, in the case of interest periods longer than three months, every three months. The unused portion of our revolving credit facility is subject to a commitment fee ranging from 0.15% to 0.35% per annum depending on our most recent consolidated leverage ratio or our credit rating, as the case may be.
Our revolving credit facility contains covenants and conditions that, among other things, limit (subject to certain exceptions) our ability to incur or guarantee additional debt, make cash distributions (though there will be an exception for distributions permitted under the partnership agreement, subject to certain customary conditions), incur certain liens or permit them to exist, make certain investments and acquisitions, enter into certain types of transactions with affiliates, merge or consolidate with another company, and transfer, sell or otherwise dispose of assets. In connection with the Transaction, the lenders under our revolving credit facility waived certain change of control provisions contained in our revolving credit facility.
We are subject to covenants that require us to maintain certain financial ratios, as follows:
| • | The ratio of (i) consolidated total funded debt (as defined in the agreement governing our revolving credit facility) as of the last day of each fiscal quarter to (ii) consolidated EBITDA (as defined in the agreement governing our revolving credit facility) for the four consecutive fiscal quarters ending on the last day of such fiscal quarter may not exceed (A) at any time other than during a qualified acquisition period (as defined in the agreement governing our revolving credit facility), 5.0 to 1.0 and (B) during a qualified acquisition period, 5.5 to 1.0. This consolidated leverage ratio is calculated as the total amount outstanding on our credit facility divided by EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP. The consolidated leverage ratio was 1.1 to 1.0 at December 31, 2017. |
| • | The ratio of (i) consolidated EBITDA for the four consecutive fiscal quarters ending on the last day of each fiscal quarter to (ii) consolidated interest expense (as defined in the agreement governing our revolving credit facility) for such four consecutive fiscal quarters may not be less than 3.0 to 1.0. This consolidated interest coverage ratio is calculated as EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP divided by total interest charges. The consolidated interest coverage ratio was 31.3 to 1.0 at December 31, 2017. |
Based on these ratios, we had the maximum amount of revolving credit available for borrowing at December 31, 2017, or $100.5 million.
62
Cash Flows
Net cash provided by or used in operating activities, investing activities and financing activities for the years ended December 31, 2017 and 2016 were as follows:
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | Change ($) | ||||||||||
| Net cash provided by operating activities: | $ | 155,550 | $ | 160,089 | $ | (4,539 | ) | |||||
| Net cash used in investing activities: | $ | (26,835 | ) | $ | (45,328 | ) | $ | 18,493 | ||||
| Net cash used in financing activities: | $ | (131,942 | ) | $ | (108,557 | ) | $ | (23,385 | ) | |||
Net cash provided by operating activities decreased approximately $4.5 million during the year ended December 31, 2017 compared to the year ended December 31, 2016. The decrease was primarily the result of working capital adjustments, none of which were individually significant.
Net cash used in investing activities decreased $18.5 million in the current year compared to the prior year. The primary reason for the decrease was our receipt of approximately $21.5 million in the current year from the sale of long term assets.
Net cash used in financing activities increased approximately $23.4 million during the current year compared to the prior year. The increase in cash used in financing activities during the year ended December 31, 2017 compared to the prior year is primarily due to an increase of $17.4 million in quarterly distribution payments made in the year ended December 31, 2017 compared to the year ended December 31, 2016.
Capital Expenditures
The midstream energy business is capital intensive and requires maintenance of existing gathering systems and other midstream assets and facilities, as well as the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement requires that we categorize our capital expenditures as either:
| • | Maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity, operating income or revenue. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to comply with environmental laws and regulations. In addition, we designate a portion of our capital expenditures to connect new wells to maintain gathering throughput as maintenance capital to the extent such capital expenditures are necessary to maintain, over the long term, our operating capacity, operating income or revenue; or |
| • | Expansion capital expenditures, which are cash expenditures to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines and compressor stations, in each case to the extent such capital expenditures are expected to expand our operating capacity, operating income or revenue. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures may also be considered expansion capital expenditures. |
Capital Expenditures for the Year Ended December 31, 2017
| Anchor | Growth | Additional | TOTAL | ||||||||||||
| Capital Investment | |||||||||||||||
| Maintenance capital | $ | 14,471 | $ | 819 | $ | 2,917 | $ | 18,207 | |||||||
| Expansion capital | 26,387 | (117 | ) | 3,889 | 30,159 | ||||||||||
| Total Capital Investment | $ | 40,858 | $ | 702 | $ | 6,806 | $ | 48,366 | |||||||
| Capital Investment Net to the Partnership | |||||||||||||||
| Maintenance capital | $ | 14,471 | $ | 41 | $ | 146 | $ | 14,658 | |||||||
| Expansion capital | 26,387 | (6 | ) | 194 | 26,575 | ||||||||||
| Total Capital Investment Net to the Partnership | $ | 40,858 | $ | 35 | $ | 340 | $ | 41,233 | |||||||
63
We anticipate that we will continue to make expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that any significant future expansion capital expenditures will be funded by borrowings under our revolving credit facility and/or the issuance of debt and equity securities.
Insurance Program
We maintain insurance policies with insurers in amounts and with coverage and deductibles that we believe are reasonable and prudent. We cannot, however, assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
Cash Distributions
Under our current cash distribution policy, we intend to pay a minimum quarterly distribution of $0.2125 per unit per quarter, which equates to an aggregate distribution of approximately $13.8 million per quarter, or approximately $55.2 million per year, based on the general partner interest and the number of common units outstanding as of December 31, 2017. However, we do not have a legal or contractual obligation to pay distributions quarterly or on any other basis at our minimum quarterly distribution rate or at any other rate. Under our cash distribution policy, the decision to make a distribution as well as the amount of any distribution is determined by our general partner, taking into consideration the terms of the partnership agreement.
From its inception through September 30, 2017, the Partnership paid equal distributions on common, subordinated and general partner units, excluding payments on the incentive distribution rights. Upon payment of the cash distribution with respect to the quarter ended September 30, 2017, the financial requirements for the conversion of all subordinated units were satisfied. As a result, on November 15, 2017, all 29,163,121 subordinated units, which were owned entirely by CNX and Noble Energy in the aggregate, converted into common units on a one-for-one basis. For more information regarding the termination of our subordination period and conversion of our subordinated units on November 15, 2017, see Part II, Item 8. Consolidated Financial Statements, Consolidated Statements of Partners’ Capital and Noncontrolling Interest, which is incorporated herein by reference. For additional information on our cash distribution policy, see Part II, Item 8. Consolidated Financial Statements, Note 3–Distributions, which is incorporated herein by reference.
On January 22, 2018, the board of directors of our general partner declared a cash distribution to our unitholders of $0.3133 per common unit with respect to the fourth quarter of 2017. The cash distribution will be paid on February 14, 2018 to unitholders of record as of the close of business on February 5, 2018.
Off-Balance Sheet Arrangements
We do not maintain any off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the notes to the consolidated financial statements of this Annual Report on Form 10-K.
64
Contractual Obligations
The following table details the future projected payments associated with our contractual obligations as of December 31, 2017 in total and by year:
| Payments Due by Years Ending December 31, | |||||||||||||||||||
| (thousands) | 2018 | 2019-20 | 2021-22 | Thereafter | Total | ||||||||||||||
Operating lease obligations (1) | $ | 3,080 | $ | 2,730 | $ | — | $ | — | $ | 5,810 | |||||||||
Revolving credit facility (2) | 251 | 149,688 | — | — | 149,939 | ||||||||||||||
| Total Contractual Obligations | $ | 3,331 | $ | 152,418 | $ | — | $ | — | $ | 155,749 | |||||||||
(1) We lease various equipment under non-cancelable operating leases (primarily related to compression facilities) for various periods. See Item 8, Note 12.
(2) We have an outstanding balance of $149.5 million on our revolving credit facility at December 31, 2017. Assuming unused capacity on the revolving credit facility of $100.5 million, amounts in the table depict commitment fees we must pay on a quarterly basis under the agreement governing our revolving credit facility. Our revolving credit facility matures on September 30, 2019.
Critical Accounting Policies
For a description of the Partnership’s accounting policies and any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements, see Item 8, Note 2—Significant Accounting Policies—Recent Accounting Pronouncements, which is incorporated herein by reference. The application of the Partnership’s accounting policies may require management to make judgments and estimates about the amounts reflected in the Consolidated Financial Statements. If applicable, management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.
As of December 31, 2017, the Partnership did not have any accounting policies that we deemed to be critical or that would require significant judgment.
65
| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Commodity Price Risk
We currently generate substantially all of our revenues pursuant to fee-based gathering agreements with CNX Gas and HG Energy based on acreage dedications and do not have minimum volume commitments. We are paid based on the volumes of natural gas and condensate that we gather and handle, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows do not have significant direct exposure to commodity price risk. However, we are indirectly exposed to commodity price risks through CNX Gas and HG Energy, who may reduce or shut-in production due to depressed commodity prices. Although we intend to enter into similar fee-based gathering agreements with new customers in the future, our efforts to negotiate terms with third parties may not be successful.
In the future, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Such exposure to the volatility of natural gas, NGL and crude oil prices could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.
Interest Rate Risk
We maintain a $250.0 million revolving credit facility. Assuming the December 31, 2017 balance on our revolving credit facility of $149.5 million was outstanding for the entire year, an increase of one percentage point in the interest rates would have resulted in an increase to interest expense during 2017 of $1.5 million. Accordingly, our results of operations, cash flows and financial condition, all of which affect our ability to make cash distributions to our unitholders, could be materially adversely affected by significant increases in interest rates.
Credit Risk
We are subject to credit risk due to the concentration of receivables from our two most significant customers, our Sponsor and HG Energy, for gas gathering services. We generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results.
66
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
| INDEX TO CONSOLIDATED FINANCIAL STATEMENTS | ||
| Page | ||
67
Report of Independent Registered Public Accounting Firm
To the Unitholders of CNX Midstream Partners LP and the
Board of Directors of CNX Midstream GP LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of CNX Midstream Partners LP (formerly CONE Midstream Partners LP) (the Partnership) as of December 31, 2017 and 2016, and the related consolidated statements of operations, partners’ capital and noncontrolling interest and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2017 and 2016, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Partnership’s auditor since 2014.
Pittsburgh, Pennsylvania
February 7, 2018
68
CNX MIDSTREAM PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit data)
| For the Years Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Revenue | |||||||||||
| Gathering revenue — related party | $ | 184,693 | $ | 239,211 | $ | 203,423 | |||||
| Gathering revenue — third party | 49,155 | — | — | ||||||||
| Total Revenue | 233,848 | 239,211 | 203,423 | ||||||||
| Expenses | |||||||||||
| Operating expense — third party | 26,640 | 30,405 | 28,987 | ||||||||
| Operating expense — related party | 25,513 | 29,771 | 29,937 | ||||||||
| General and administrative expense — third party | 5,506 | 5,174 | 4,444 | ||||||||
| General and administrative expense — related party | 10,961 | 10,656 | 8,636 | ||||||||
| Loss on asset sales | 3,914 | 10,083 | — | ||||||||
| Depreciation expense | 22,692 | 21,201 | 15,053 | ||||||||
| Interest expense | 4,560 | 1,799 | 835 | ||||||||
| Total Expense | 99,786 | 109,089 | 87,892 | ||||||||
| Net Income | 134,062 | 130,122 | 115,531 | ||||||||
| Less: Net income attributable to noncontrolling interest | 19,069 | 33,636 | 44,284 | ||||||||
| Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP | $ | 114,993 | $ | 96,486 | $ | 71,247 | |||||
| Calculation of Limited Partner Interest in Net Income: | |||||||||||
| Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP | $ | 114,993 | $ | 96,486 | $ | 71,247 | |||||
| Less: General partner interest in net income, including incentive distribution rights | 5,614 | 2,526 | 1,425 | ||||||||
| Limited partner interest in net income | $ | 109,379 | $ | 93,960 | $ | 69,822 | |||||
| Net income per limited partner unit - Basic | $ | 1.72 | $ | 1.59 | $ | 1.20 | |||||
| Net income per limited partner unit - Diluted | $ | 1.72 | $ | 1.58 | $ | 1.20 | |||||
| Weighted average limited partner units outstanding - Basic | 63,582 | 59,207 | 58,326 | ||||||||
| Weighted average limited partner unit outstanding - Diluted | 63,634 | 59,289 | 58,340 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
69
CNX MIDSTREAM PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except number of units)
| December 31, | |||||||
| 2017 | 2016 | ||||||
| ASSETS | |||||||
| Current Assets: | |||||||
| Cash | $ | 3,194 | $ | 6,421 | |||
Receivables — related party (Note 6) | 13,104 | 22,434 | |||||
Receivables — third party (Note 6) | 8,251 | — | |||||
| Other current assets | 2,169 | 2,181 | |||||
| Total Current Assets | 26,718 | 31,036 | |||||
Property and Equipment (Note 7): | |||||||
| Property and equipment | 972,841 | 930,732 | |||||
| Less — accumulated depreciation | 73,563 | 52,172 | |||||
| Property and Equipment — Net | 899,278 | 878,560 | |||||
Other assets (Note 8) | 593 | 8,961 | |||||
| TOTAL ASSETS | $ | 926,589 | $ | 918,557 | |||
| LIABILITIES AND EQUITY | |||||||
| Current Liabilities: | |||||||
| Accounts payable | $ | 23,602 | $ | 18,007 | |||
Accounts payable — related party (Note 9) | 2,376 | 8,289 | |||||
| Total Current Liabilities | 25,978 | 26,296 | |||||
| Other Liabilities: | |||||||
Revolving credit facility (Note 10) | 149,500 | 167,000 | |||||
| Total Liabilities | 175,478 | 193,296 | |||||
| Partners’ Capital and Noncontrolling Interest: | |||||||
| Common units (63,588,152 units issued and outstanding at December 31, 2017 and 34,363,371 units issued and outstanding at December 31, 2016) | 389,427 | 418,352 | |||||
| Subordinated units (29,163,121 units issued and outstanding at December 31, 2016) | — | (65,986 | ) | ||||
| General partner interest | 4,328 | (2,311 | ) | ||||
| Partners’ capital attributable to CNX Midstream Partners LP | 393,755 | 350,055 | |||||
| Noncontrolling interest | 357,356 | 375,206 | |||||
| Total Partners’ Capital and Noncontrolling Interest | 751,111 | 725,261 | |||||
| TOTAL LIABILITIES AND PARTNERS’ CAPITAL | $ | 926,589 | $ | 918,557 | |||
The accompanying notes are an integral part of these consolidated financial statements.
70
CNX MIDSTREAM PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
(Dollars in thousands)
| Partners’ Capital | ||||||||||||||||||||||||
| Limited Partners | Capital | |||||||||||||||||||||||
| General | Attributable | Noncontrolling | ||||||||||||||||||||||
| Common | Subordinated | Partner | to Partners | Interest | Total | |||||||||||||||||||
| Balance at December 31, 2014 | $ | 389,612 | $ | (92,285 | ) | $ | (3,772 | ) | $ | 293,555 | $ | 289,208 | $ | 582,763 | ||||||||||
| Net income | 34,911 | 34,911 | 1,425 | 71,247 | 44,284 | 115,531 | ||||||||||||||||||
Investments by partners and noncontrolling interest holders(1) | — | — | — | — | 156,540 | 156,540 | ||||||||||||||||||
| Quarterly distributions to unitholders | (25,526 | ) | (25,526 | ) | (1,042 | ) | (52,094 | ) | — | (52,094 | ) | |||||||||||||
| Unit-based compensation | 402 | — | — | 402 | — | 402 | ||||||||||||||||||
| Balance at December 31, 2015 | $ | 399,399 | $ | (82,900 | ) | $ | (3,389 | ) | $ | 313,110 | $ | 490,032 | $ | 803,142 | ||||||||||
| Net income | 47,935 | 46,025 | 2,526 | 96,486 | 33,636 | 130,122 | ||||||||||||||||||
| General Partner and noncontrolling interest holder activity | — | — | 3 | 3 | (9,068 | ) | (9,065 | ) | ||||||||||||||||
| Quarterly distributions to unitholders | (29,128 | ) | (29,111 | ) | (1,451 | ) | (59,690 | ) | — | (59,690 | ) | |||||||||||||
| Acquisition of remaining 25% interest in Anchor System | (606 | ) | — | — | (606 | ) | (139,394 | ) | (140,000 | ) | ||||||||||||||
| Unit-based compensation | 775 | — | — | 775 | — | 775 | ||||||||||||||||||
| Vested units withheld for unitholder taxes | (23 | ) | — | — | (23 | ) | — | (23 | ) | |||||||||||||||
| Balance at December 31, 2016 | $ | 418,352 | $ | (65,986 | ) | $ | (2,311 | ) | $ | 350,055 | $ | 375,206 | $ | 725,261 | ||||||||||
| Net income | 72,215 | 37,164 | 5,614 | 114,993 | 19,069 | 134,062 | ||||||||||||||||||
Distributions to general partner and noncontrolling interest holders, net | — | — | 30 | 30 | (36,919 | ) | (36,889 | ) | ||||||||||||||||
| Quarterly distributions to unitholders | (39,544 | ) | (33,514 | ) | (4,059 | ) | (77,117 | ) | — | (77,117 | ) | |||||||||||||
Conversion of subordinated units to common units(2) | (62,336 | ) | 62,336 | — | — | — | — | |||||||||||||||||
| Noncash contribution of assets held by general partner | — | — | 5,054 | 5,054 | — | 5,054 | ||||||||||||||||||
| Unit-based compensation | 1,176 | — | — | 1,176 | — | 1,176 | ||||||||||||||||||
| Vested units withheld for unitholder taxes | (436 | ) | — | — | (436 | ) | — | (436 | ) | |||||||||||||||
| Balance at December 31, 2017 | $ | 389,427 | $ | — | $ | 4,328 | $ | 393,755 | $ | 357,356 | $ | 751,111 | ||||||||||||
(1) Includes outstanding cash calls as of December 31, 2015.
(2) All subordinated units were converted to common units on a one-for-one basis on November 15, 2017. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on October 1, 2017. See Note 4.
The accompanying notes are an integral part of these consolidated financial statements.
71
CNX MIDSTREAM PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
| For the Years Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Cash Flows from Operating Activities: | |||||||||||
| Net income | $ | 134,062 | $ | 130,122 | $ | 115,531 | |||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Depreciation expense and amortization of debt issuance costs | 22,860 | 21,364 | 15,217 | ||||||||
| Unit-based compensation | 1,176 | 775 | 402 | ||||||||
| Loss on asset sales | 3,914 | 10,083 | — | ||||||||
| Other | 771 | 695 | — | ||||||||
| Changes in assets and liabilities: | |||||||||||
| Receivables — related party | 9,330 | 7,265 | (3,148 | ) | |||||||
| Receivables — third party | (8,251 | ) | — | — | |||||||
| Other current and non-current assets | 162 | (144 | ) | (673 | ) | ||||||
| Accounts payable | (2,520 | ) | (16,691 | ) | (10,954 | ) | |||||
| Accounts payable — related party | (5,954 | ) | 6,620 | (358 | ) | ||||||
| Net Cash Provided by Operating Activities | 155,550 | 160,089 | 116,017 | ||||||||
| Cash Flows from Investing Activities: | |||||||||||
| Capital expenditures | (48,366 | ) | (50,660 | ) | (291,211 | ) | |||||
| Proceeds from sale of assets | 21,531 | 5,332 | — | ||||||||
| Net Cash Used in Investing Activities | (26,835 | ) | (45,328 | ) | (291,211 | ) | |||||
| Cash Flows from Financing Activities: | |||||||||||
| Distributions to general partner and noncontrolling interest holders, net | (36,889 | ) | (2,344 | ) | 182,053 | ||||||
| Quarterly distributions to unitholders | (77,117 | ) | (59,690 | ) | (52,094 | ) | |||||
| Net (payment) proceeds from revolving credit facility | (17,500 | ) | 93,500 | 42,200 | |||||||
| Vested units withheld for unitholder taxes | (436 | ) | (23 | ) | — | ||||||
| Acquisition of remaining 25.0% noncontrolling interest in the Anchor Systems | — | (140,000 | ) | — | |||||||
| Net Cash (Used In) Provided by Financing Activities | (131,942 | ) | (108,557 | ) | 172,159 | ||||||
| Net (Decrease) Increase in Cash | (3,227 | ) | 6,204 | (3,035 | ) | ||||||
| Cash at Beginning of Period | 6,421 | 217 | 3,252 | ||||||||
| Cash at End of Period | $ | 3,194 | $ | 6,421 | $ | 217 | |||||
| Cash Paid During the Period For: | |||||||||||
| Interest | $ | 4,437 | $ | 1,921 | $ | 301 | |||||
| Noncash Investing Activities: | |||||||||||
| Accrued capital expenditures | $ | 9,942 | $ | 3,471 | $ | 15,452 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
72
CONE MIDSTREAM PARTNERS LP
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 — DESCRIPTION OF BUSINESS
CNX Midstream Partners LP (the “Partnership”), formerly known as CONE Midstream Partners LP, is a growth-oriented master limited partnership focused on the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets to service our customers’ production in the Marcellus Shale in Pennsylvania and West Virginia. The Partnership’s assets include natural gas gathering pipelines and compression and dehydration facilities, as well as condensate gathering, collection, separation and stabilization facilities. The Partnership is managed by its general partner, CNX Midstream GP LLC, formerly known as CONE Midstream GP LLC (the “general partner”). The general partner is a wholly owned subsidiary of CNX Gathering LLC, formerly known as CONE Gathering LLC (“CNX Gathering”), which is a wholly owned subsidiary of CNX Resources Corporation, formerly known as CONSOL Energy Inc. (NYSE: CNX)(“CNX”).
The Partnership was formed in May 2014 as a joint venture between CNX and Noble Energy, Inc (NYSE: NBL)(“Noble Energy”). On January 3, 2018, CNX Gas Company LLC (“CNX Gas”), a Virginia limited liability company, acquired Noble Energy’s 50% membership interest in CNX Gathering for a cash purchase price of $305.0 million and the mutual release of all outstanding claims between the parties (the “Transaction”). As a result of the Transaction, CNX, as the sole member of CNX Gas, owns 100% of the membership interest in CNX Gathering, and is the sole sponsor of the Partnership. Accordingly, we may refer to CNX as the “Sponsor” throughout this Annual Report on Form 10-K.
Noble Energy continues to own 21,692,198 common units representing limited partner interests in the Partnership (the “Retained Units”); however, Noble Energy has announced its intention to divest of the Retained Units over the next few years. See Note 5–Related Party for additional information.
Description of Business
Our midstream assets are divided among three operating segments that we refer to as our “Anchor Systems,” “Growth Systems” and “Additional Systems” based on their relative current cash flows, growth profiles, capital expenditure requirements and the timing of their development.
| • | Our Anchor Systems include our most developed midstream systems that generate the largest portion of our current cash flows, which includes our three primary midstream systems (the McQuay System, the Majorsville System and the Mamont System) and related assets. |
| • | Our Growth Systems are primarily located in the dry gas regions of our dedicated acreage that are generally in earlier phases of development and require substantial future expansion capital expenditures to materially increase production, which would primarily be funded by CNX in proportion to CNX Gathering’s 95% retained ownership interest. |
| • | Our Additional Systems include several gathering systems primarily located in the wet gas regions of our dedicated acreage that we expect will require lower levels of expansion capital investment relative to our Growth Systems. The substantial majority of capital investment on these systems would primarily be funded by CNX in proportion to CNX Gathering’s 95% retained ownership interest. |
In order to maintain operational flexibility, our operations are conducted through, and our operating assets are owned by, our operating subsidiaries. However, neither we nor our operating subsidiaries have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by our Sponsor or others. All of the personnel that conduct our business are employed or contracted by our general partner and its affiliates, including our Sponsor, but we sometimes refer to these individuals as our employees because they provide services directly to us.
Initial Public Offering and Subsequent Drop Down of Additional Interests
On September 30, 2014, the Partnership closed its IPO of 20,125,000 common units at a price to the public of $22.00 per unit, which included all 2,625,000 common units of the underwriters’ over-allotment option. Following the Transaction, the Partnership’s common units are listed on the New York Stock Exchange under the ticker symbol “CNXM.”
Concurrent with the closing of the IPO, CNX Gathering contributed to the Partnership a 75% controlling interest in the Anchor Systems, a 5% controlling interest in the Growth Systems and a 5% controlling interest in the Additional Systems. In exchange for CNX Gathering’s contribution of assets and liabilities to the Partnership, CNX Gathering received:
| • | through its ownership of our general partner, a continuation of a 2% general partner interest in the Partnership; |
| • | 9,038,121 common units and 29,163,121 subordinated units (all of which converted to common units in November 2017), representing an aggregate 64.2% limited partner interest in the Partnership at the time of the IPO (the common and subordinated units were subsequently distributed to CNX and Noble Energy); |
| • | through its ownership of our general partner, all of the Partnerships’ incentive distribution rights (“IDRs”); and |
73
| • | an aggregate cash distribution of $408.0 million. |
On November 16, 2016, the Partnership acquired the remaining 25% noncontrolling interest in the Anchor Systems from CNX Gathering (the “Anchor Systems Acquisition”) in exchange for (i) cash consideration in the amount of $140.0 million, (ii) the Partnership’s issuance of 5,183,154 common units (the “Unit Consideration”) representing limited partner interests in the Partnership (“common units”) at an issue price of $20.42 per common unit, calculated as the volume-weighted average trading price of the common units over the trailing 20-day trading period ending on November 11, 2016, and (iii) the Partnership’s issuance to the general partner of an additional interest in the Partnership in an amount necessary for our general partner to maintain its two percent general partner interest in the Partnership. The cash consideration was distributed and the Unit Consideration issued 50% to CNX Gas and 50% to NBL Midstream LLC, a wholly owned subsidiary of Noble Energy. The Anchor Systems Acquisition was made pursuant to a Contribution Agreement (the “Contribution Agreement”), dated November 15, 2016, by and among the Partnership, our general partner, CNX Gathering, CNX Midstream Operating Company LLC, a Delaware limited liability company (the “Operating Company”), and the other parties thereto.
At December 31, 2017, the Partnership owned a 100% controlling limited partner interest in the Anchor Systems and a 5% controlling limited partner interest in each of the Growth and Additional Systems.
Noble Energy Sale of Upstream Assets
On June 28, 2017, Noble Energy sold its upstream assets in northern West Virginia and southern Pennsylvania to HG Energy II Appalachia, LLC (“HG Energy”), a portfolio company of Quantum Energy Partners, LP (“Quantum”), effectively making HG Energy the new shipper on the dedicated acreage that was previously owned by Noble Energy (the “Noble Energy Asset Sale”). In connection with the Noble Energy Asset Sale, Noble Energy provided notice to the Partnership of its release of approximately 37,000 undeveloped acres, which were primarily within the Growth and Additional Systems, from amounts dedicated to us as per the terms of our gathering agreement. The Partnership is in the process of confirming the dedication status of the acres that were released.
The Partnership currently gathers the natural gas and condensate volumes produced by HG Energy on our dedicated acreage under the terms of our gathering agreement with Noble Energy, which was assigned to HG Energy upon consummation of the Noble Energy Asset Sale.
NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Use of Estimates
The accompanying audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual results could differ from those estimates, which are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable under the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.
Principles of Consolidation
The consolidated financial statements include the accounts of the Partnership and all of its controlled subsidiaries, including 100% of each of the Anchor Systems, Growth Systems and Additional Systems. Although the Partnership has less than a 100% economic interest in the Growth and Additional Systems, each are consolidated fully with the results of the Partnership. However, after adjusting for noncontrolling interests, net income attributable to general and limited partner ownership interests in the Partnership reflect only that portion of net income that is attributable to the Partnership’s unitholders. As a result of the Anchor Systems Acquisition, net income attributable to general and limited partner ownership interests in the Partnership includes 100% of the results of the Anchor Systems for the period subsequent to the closing date of that transaction.
Transactions between the Partnership, CNX and Noble Energy, have been identified in the consolidated financial statements as transactions between related parties and are discussed in Note 5.
Jumpstart Our Business Startups Act (“JOBS Act”)
Under the JOBS Act, for as long as the Partnership remains an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from the Securities and Exchange Commission’s (“SEC”) reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of its system of internal control over financial
74
reporting pursuant to Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and seeking unitholder approval of any golden parachute payments not previously approved. We may take advantage of these reporting exemptions until we are no longer an emerging growth company. We continue to be an emerging growth company at December 31, 2017.
The Partnership will remain an emerging growth company for up to five years from the date of our initial public offering, although we will lose that status sooner if:
| • | we have more than $1.0 billion of revenues in a fiscal year; |
| • | the limited partner interests held by non-affiliates have a market value of more than $700 million as of the last business day of our most recently completed second fiscal quarter, which determination shall be made as of the last day of such fiscal year; or |
| • | we issue more than $1.0 billion of non-convertible debt over a three-year period. |
The JOBS Act also provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. The Partnership has irrevocably elected to “opt out” of this exemption and, therefore, is and will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.
Revenue Recognition
Our revenues primarily consist of fees, which we charge on a per unit basis, for gathering natural gas that was produced by our shippers. We recognize revenue when services have been rendered, the prices are fixed or determinable, and collectability is reasonably assured.
The fees we charge our Sponsor and the fees we charged Noble Energy, prior to consummation of the Noble Energy Asset Sale, are recorded in gathering revenue — related party in our consolidated statements of operations. Following consummation of the Noble Energy Asset Sale, fees from midstream services we perform for HG Energy and any other third party shipper are recorded in gathering revenue — third party in our consolidated statements of operations.
Cash
Cash includes cash on hand and on deposit at banking institutions.
Receivables
Receivables are recorded at the invoiced amount and do not bear interest. When applicable, we reserve for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. We regularly review collectability and establish or adjust the reserve as necessary using the specific identification method. Account balances are charged off against the reserve after all means of collection have been exhausted and the potential for recovery is considered remote.
There were no reserves for uncollectable amounts at December 31, 2017 or 2016.
Fair Value Measurement
The Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long‑lived assets). The fair value is the price that we estimate we would receive upon selling an asset or that we would pay to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly.
The carrying values on our balance sheet of our current assets, current liabilities and revolving credit facility approximate fair values due to their short maturities.
75
Property and Equipment
Property and equipment is recorded at cost upon acquisition and is depreciated on a straight-line basis over the assets’ estimated useful lives or over their lease terms of the assets. Expenditures which extend the useful lives of existing property and equipment are capitalized. When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized as a gain or loss.
The Partnership evaluates whether long-lived assets have been impaired and determines if the carrying amount of its assets may not be recoverable. For such long-lived assets, impairment exists when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying amount of the long-lived asset is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value.
Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as the condition of an asset or management’s intent to utilize the asset generally require management to reassess the cash flows related to long-lived assets. No property and equipment impairments were identified during the periods presented in the accompanying consolidated financial statements.
Environmental Matters
We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At this time, we are unable to assess the timing and/or effect of potential liabilities related to greenhouse gas emissions or other environmental issues. As of December 31, 2017 and 2016, we had no material environmental matters that required the recognition of a separate liability or specific disclosure.
Asset Retirement Obligations
Our gathering pipelines and compressor stations have an indeterminate life. If properly maintained, they will operate for an indeterminate period as long as supply and demand for natural gas exists, which we expect for the foreseeable future. We are under no legal or contractual obligation to restore or dismantle our gathering system upon abandonment. Therefore, we have no recorded liabilities for asset retirement obligations at December 31, 2017 or 2016.
Variable Interest Entities
Each of the Anchor, Growth and Additional Systems (the “Limited Partnerships”) is also a limited partnership and a variable interest entity (“VIE”). These VIEs correspond with the manner in which we report our segment information in Note 13–Segment Information, which also includes information regarding the Partnership’s involvement with each of these VIEs and their relative contributions to our financial position, operating results and cash flows.
The Partnership fully consolidates each of the Limited Partnerships through its ownership of the Operating Company, which, through its general partner ownership interest in each of the Limited Partnerships, is considered to be the primary beneficiary for accounting purposes and has the power to direct all substantive strategic and day-to-day operational decisions of the Limited Partnerships.
Equity Compensation
Equity compensation expense for all unit-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification. We recognize unit-based compensation costs on a straight-line basis over the requisite service period of an award, which is generally the same as the award’s vesting term. See Note 14–Long Term Incentive Plan, for further discussion.
Income Taxes
We are treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of the Partnership’s taxable income. Accordingly, no provision for federal or state income taxes has been recorded in the Partnership’s consolidated financial statements for any period presented in the accompanying consolidated financial statements.
76
Recent Accounting Pronouncements
In May 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-09–Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting. ASU 2017-09 provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The updated guidance is effective for interim and annual periods beginning after December 15, 2017, and early adoption is permitted. We do not believe the updated requirements will materially impact our consolidated financial statements.
In January 2017, the FASB issued ASU 2017-01–Business Combinations (Topic 805): Clarifying the Definition of a Business, which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. The updated guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets is not a business. ASU 2017-01 is effective for annual reporting periods beginning after December 31, 2017 and interim periods therein. The Partnership adopted this guidance on January 1, 2018, which did not result in an adjustment to our consolidated financial statements.
In August 2016, the FASB issued ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments (Topic 230)”. ASU 2016-15 addresses the existing diversity in practice of how several specific cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows. ASU 2016-15 is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2017. The Partnership adopted this guidance on January 1, 2018, which did not result in an adjustment to our consolidated financial statements.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which is intended to improve financial reporting about leasing transactions. The ASU will require organizations (“lessees”) that lease assets with terms of more than 12 months to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. Organizations that own the assets leased by lessees (“lessors”) will remain largely unchanged from current GAAP. In addition, the ASU will require disclosures to help investors and other financial statement users better understand the amount, timing and uncertainty of cash flows arising from leases. The effective date of this ASU is for fiscal years beginning after December 31, 2018 and interim periods within that year. We are currently evaluating the impact this standard will have on our financial statements and financial covenants with lenders; however, we do not believe this standard will materially adversely impact our existing credit agreements.
In May 2014, the FASB issued ASU 2014-09 “Revenue from Contracts with Customers (Topic 606)”, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. The objective of the amendments in this update is to improve financial reporting by creating common revenue recognition guidance under both U.S. GAAP and International Financial Reporting Standards (“IFRS”). The core principle of the 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 and should disclose sufficient information, both qualitative and quantitative, 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 following updates to Topic 606 were made during 2016:
| • | In March 2016, the FASB updated Topic 606 by issuing ASU 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” which clarifies how an entity determines whether it is a principal or an agent for goods or services promised to a customer as well as the nature of the goods or services promised to their customers. |
| • | In April 2016, the FASB issued Update 2016-10 - Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which seeks to address implementation issues in the areas of identifying performance obligations and licensing. |
| • | In May 2016, the FASB issued Update 2016-12 - Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update, which was issued in response to feedback received by the FASB-IASB joint revenue recognition transition resource group, seeks to address implementation issues in the areas of collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. |
After considering the FASB’s issuance of a standard that delayed application of Topic 606 by one year, the new standards are effective for annual reporting periods beginning after December 15, 2017. We have completed our detailed review of the impact of the new standard, and we adopted Topic 606 on January 1, 2018 using the modified retrospective method of adoption, which did not result in an adjustment to equity. We do not expect this standard will have a significant impact on net income in the year ending December 31, 2018. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contract with customers, including disaggregation of revenue and remaining performance obligations.
77
NOTE 3 — DISTRIBUTIONS
Cash Distributions
Our partnership agreement requires that we distribute all of our available cash within 45 days after the end of each quarter to unitholders of record on the applicable record date. The board of directors of our general partner (the “Board of Directors”) declared the following cash distributions to the Partnership’s common, subordinated (when applicable) and general partner unitholders for the periods presented:
| (in thousands, except per unit information) | ||||||||||
| Quarters Ended | Total Quarterly Distribution Per Unit | Total Quarterly Cash Distribution | Date of Distribution | |||||||
| 2016 | ||||||||||
| March 31 | $ | 0.2450 | $ | 14,593 | May 13, 2016 | |||||
| June 30 | 0.2540 | 15,209 | August 12, 2016 | |||||||
| September 30 | 0.2630 | 15,827 | November 14, 2016 | |||||||
| December 31 | 0.2724 | 18,004 | February 14, 2017 | |||||||
| 2017 | ||||||||||
| March 31 | $ | 0.2821 | $ | 18,842 | May 15, 2017 | |||||
| June 30 | 0.2922 | 19,698 | August 14, 2017 | |||||||
| September 30 | 0.3025 | 20,573 | November 14, 2017 | |||||||
See Note 4 for information regarding the conversion of subordinated units to common units on November 14, 2017. See Note 15 for information regarding the distribution that was approved by the Board of Directors with respect to the quarter ended December 31, 2017.
Incentive Distribution Rights
Incentive distribution rights (“IDRs”) represent the right to receive an increasing percentage, up to a maximum of 48% (which does not include the 2% general partner interest), of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels described in the table below have been achieved. All of the IDRs are currently held by our general partner. Our general partner may transfer the IDRs separately from its general partner interest.
See Note 4–Net Income Per Limited Partner and General Partner Interest for additional details regarding achievement of target distribution levels.
NOTE 4 — NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST
We allocate net income between our general partner and limited partners using the two-class method, under which we allocate net income to our limited partners, our general partner and the holders of our IDRs in accordance with the terms of our partnership agreement. We also allocate any earnings in excess of distributions to our limited partners, our general partner and the holders of the IDRs in accordance with the terms of our partnership agreement. We allocate any distributions in excess of earnings for the period to our general partner and our limited partners based on their respective proportionate ownership interests in us, after taking into account distributions to be paid with respect to the IDRs, as set forth in our partnership agreement.
Conversion of Subordinated Units
From its inception through September 30, 2017, the Partnership paid equal distributions on common, subordinated and general partner units, excluding payments on the incentive distribution rights, which are paid in accordance with the table below. Upon payment of the cash distribution with respect to the quarter ended September 30, 2017, the financial requirements for the conversion of all subordinated units were satisfied. As a result, on November 15, 2017, all 29,163,121 subordinated units, which were owned entirely by CNX and Noble Energy in the aggregate, converted into common units on a one-for-one basis. For purposes of calculating a) net income allocable to subordinated units and b) weighted average subordinated units outstanding within the net income per common and subordinated unit calculations, the conversion of the subordinated units is
78
deemed to have occurred on October 1, 2017. The conversion does not impact the amount of the cash distribution paid or the total number of the Partnership’s outstanding units representing limited partner interests.
Percentage Allocations of Available Cash from Operating Surplus
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner, as holder of our IDRs, and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.
Marginal Percentage Interest in Distributions | ||||||||
| Distribution Targets | Total Quarterly Distribution Per Unit Target Amount | Unitholders | General Partner (including IDRs) | |||||
| Minimum Quarterly Distribution | $0.2125 | 98% | 2% | |||||
| First Target Distribution | Above $0.2125 | up to $0.24438 | 98% | 2% | ||||
| Second Target Distribution | Above $0.24438 | up to $0.26563 | 85% | 15% | ||||
| Third Target Distribution | Above $0.26563 | up to $0.31875 | 75% | 25% | ||||
| Thereafter | Above $0.31875 | 50% | 50% | |||||
The Second and Third Target Distributions were reached for the cash flow quarters ended March 31, 2016 and December 31, 2016, respectively, which were paid within 45 days following the ends of these quarters. All quarterly distributions prior to March 31, 2016 were paid in accordance with the First Target Distribution.
Historical earnings per unit
The Partnership calculates historical earnings per unit under the two-class method and allocates the earnings or losses of a transferred business before the date of a dropdown transaction entirely to the general partner. If applicable, the previously reported earnings per unit of the limited partners would not change as a result of a dropdown transaction.
Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the long-term incentive plan, were exercised, settled or converted into common units. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted net income per limited partner unit calculation, the impact is calculated by applying the treasury stock method. There were 45,066 and 11,476 phantom units that were not included in the calculation for the years ended December 31, 2017 and 2016 because the effect would have been antidilutive.
79
Basic and diluted net income per limited partner unit for common and subordinated units are as follows for the periods presented (all amounts in thousands, except per unit information):
| December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP | $ | 114,993 | $ | 96,486 | $ | 71,247 | |||||
| Less: General partner interest in net income, including incentive distribution rights | 5,614 | 2,526 | 1,425 | ||||||||
| Limited partner interest in net income | $ | 109,379 | $ | 93,960 | $ | 69,822 | |||||
| Net income allocable to common units - Basic and Diluted | $ | 70,837 | $ | 47,935 | $ | 34,911 | |||||
| Net income allocable to subordinated units - Basic and Diluted | 38,542 | 46,025 | 34,911 | ||||||||
| Limited partner interest in net income - Basic and Diluted | $ | 109,379 | $ | 93,960 | $ | 69,822 | |||||
| Weighted average limited partner units outstanding — Basic | |||||||||||
| Common units | 41,710 | 30,044 | 29,163 | ||||||||
| Subordinated units | 21,872 | 29,163 | 29,163 | ||||||||
| Total | 63,582 | 59,207 | 58,326 | ||||||||
| Weighted average limited partner units outstanding — Diluted | |||||||||||
| Common units | 41,762 | 30,126 | 29,177 | ||||||||
| Subordinated units | 21,872 | 29,163 | 29,163 | ||||||||
| Total | 63,634 | 59,289 | 58,340 | ||||||||
| Net income per limited partner unit — Basic | |||||||||||
| Common units | $ | 1.70 | $ | 1.60 | $ | 1.20 | |||||
| Subordinated units | 1.76 | 1.58 | 1.20 | ||||||||
| Total | $ | 1.72 | $ | 1.59 | $ | 1.20 | |||||
| Net income per limited partner unit — Diluted | |||||||||||
| Common units | $ | 1.70 | $ | 1.59 | $ | 1.20 | |||||
| Subordinated units | 1.76 | 1.58 | 1.20 | ||||||||
| Total | $ | 1.72 | $ | 1.58 | $ | 1.20 | |||||
NOTE 5 — RELATED PARTY
Throughout 2017, and in the ordinary course of business, we engaged in related party transactions with CNX (and certain of its subsidiaries), CNX Gathering, and Noble Energy (which was a related party until the Transaction was consummated on January 3, 2018), including the billing and receipt of fees we receive under fixed fee gathering agreements (including electrically-powered compression our customers reimburse us) and operating expenses we reimburse to CNX. Related party revenues and related party expenses are presented as separate captions within our consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015.
During the year ended December 31, 2017, the Partnership sold property and equipment to CNX with a carrying value of $17.4 million for $14.0 million in cash proceeds. The resulting loss of $3.4 million was recorded as a loss on asset sales in the accompanying consolidated statement of operations, within the Additional Systems segment. In addition, CNX Gathering contributed assets with a carrying value of $5.0 million to the Partnership’s Anchor Systems during 2017.
During the year ended December 31, 2015, the Partnership sold $2.2 million of supply inventory to CNX. The Partnership purchased supply inventory from a CNX subsidiary, which totaled $3.9 million for the year ended December 31, 2015 and was included in operating expense–related party.
80
Sponsor-related charges within operating expense–related party and general and administrative expense–related party consisted of the following (dollars in thousands):
| For the Years Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Operational services–CNX | $ | 13,166 | $ | 12,875 | $ | 14,047 | |||||
| Electrical compression | 12,347 | 16,896 | 15,890 | ||||||||
| Total Operating Expense — Related Party | $ | 25,513 | $ | 29,771 | $ | 29,937 | |||||
| CNX | $ | 10,378 | $ | 10,006 | $ | 8,083 | |||||
| Noble Energy | 583 | 650 | 553 | ||||||||
| Total General and Administrative Expense — Related Party | $ | 10,961 | $ | 10,656 | $ | 8,636 | |||||
In addition to the aforementioned transactions, throughout the years ended December 31, 2017, 2016 and 2015, CNX Gathering regularly reimbursed the Partnership for capital expenditures, initially funded by the Partnership, in proportion to CNX Gathering’s noncontrolling ownership interests in the Anchor, Growth and Additional Systems. We also distributed to CNX Gathering amounts related to their noncontrolling ownership interest in the earnings of the Anchor, Growth and Additional Systems as well as proceeds from sales of any assets in which CNX Gathering had ownership interests. This activity is recorded in the caption “Distributions to general partner and noncontrolling interest holders, net” in the consolidated statements of partners’ capital and noncontrolling interest and of cash flows.
Omnibus Agreement
In connection with our IPO, we entered into an omnibus agreement with CNX, Noble Energy, CNX Gathering and our general partner that addresses the following matters:
| • | our payment of an annually-determined administrative support fee, which totaled $0.9 million for the year ended December 31, 2017, for the provision of certain services by CNX and its affiliates; |
| • | our payment of an annually-determined administrative support fee, which totaled $0.7 million for the year ended December 31, 2017, for the provision of certain executive services by CNX and its affiliates; |
| • | our payment of an annually-determined administrative support fee, which totaled $0.3 million for the year ended December 31, 2017, for the provision of certain executive services by Noble Energy and its affiliates; |
| • | our obligation to reimburse CNX and Noble Energy for all other direct or allocated costs and expenses incurred by CNX and Noble Energy in providing general and administrative services (which reimbursement is in addition to certain expenses of our general partner and its affiliates that are reimbursed under our partnership agreement); |
| • | our right of first offer to acquire (i) CNX Gathering’s retained interests in each of our Anchor Systems, Growth Systems and Additional Systems, (ii) CNX Gathering’s other ancillary midstream assets and (iii) any additional midstream assets that CNX Gathering develops; and |
| • | an indemnity from CNX Gathering for liabilities associated with the use, ownership or operation of our assets, including environmental liabilities, to the extent relating to the period of time prior to the closing of the IPO; and our obligation to indemnify CNX Gathering for events and conditions associated with the use, ownership or operation of our assets that occur after the closing of the IPO, including environmental liabilities. |
For as long as CNX Gathering controls our general partner, the omnibus agreement will remain in full force and effect. If CNX Gathering ceases to control our general partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms.
Operational Services Agreement
In connection with our IPO, we entered into an operational services agreement with CNX, which was amended and restated upon consummation of the Exchange Agreement on December 1, 2016. The amended and restated operating agreement is generally consistent with the terms of the old agreement, under which CNX provides certain operational services to us in support of our gathering pipelines and dehydration, treating and compressor stations and facilities, including routine and emergency maintenance and repair services, routine operational activities, routine administrative services, construction and related services and such other services as we and CNX may mutually agree upon from time to time. CNX prepares and submits for our approval a maintenance, operating and capital budget on an annual basis. CNX submits actual expenditures for
81
reimbursement on a monthly basis, and we reimburse CNX for any direct third-party costs incurred by CNX in providing these services.
The amended and restated operational services agreement has an initial term ending September 30, 2034 and will continue in full force and effect unless terminated by either party at the end of the initial term or any time thereafter by giving not less than six months’ prior notice to the other party of such termination. CNX may terminate the operational services agreement if (1) we become insolvent, declare bankruptcy or take any action in furtherance of, or indicating our consent to, approval of, or acquiescence in, a similar proceeding or (2) upon not less than 180 days notice. We may immediately terminate the agreement (1) if CNX becomes insolvent, declares bankruptcy or takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, a similar proceeding, (2) upon a finding of CNX’s willful misconduct or gross negligence that has had a material adverse effect on any of our gathering pipelines and dehydration, treating and compressor stations and facilities or our business or (3) CNX is in material breach of the operational services agreement and fails to cure such default within 45 days.
Under the amended and restated operational services agreement, CNX will indemnify us from any claims, losses or liabilities incurred by us, including third-party claims, arising from CNX’s performance of the agreement to the extent caused by CNX’s gross negligence or willful misconduct. We will indemnify CNX from any claims, losses or liabilities incurred by CNX, including any third-party claims, arising from CNX’s performance of the agreement, except to the extent such claims, losses or liabilities are caused by CNX’s gross negligence or willful misconduct.
Our Gathering Agreements with CNX Gas and HG Energy
On January 3, 2018, we entered into a new 20-year, fixed-fee gathering agreement with CNX Gas that amended and restated the previous gathering agreement with CNX Gas in its entirety. Although the fees for services we provide in the Marcellus Shale for existing wells that were covered under the prior agreement (discussed below) remain unchanged in the new agreement, the new gas gathering agreement with CNX Gas also dedicates an additional 63,000 of acreage in the Utica Shale in and around the McQuay area and Wadestown area and introduces the following gas gathering and compression rates:
•Gas Gathering:
| ◦ | McQuay area Utica - a fee of $0.225 per MMBtu; and |
| ◦ | Wadestown Marcellus and Utica - a fee of $0.35 per MMBtu. |
| • | Compression: |
| ◦ | For areas not benefitting from system expansion pursuant to the Second Amended and Restated gas gathering agreement, compression services are included in the base fees; and |
| ◦ | In the McQuay and Wadestown areas, for wells turned in line beginning January 1, 2018 and beyond, we will receive additional fees of $0.065 per MMBtu for Tier 1 pressure services (maximum receipt point of pressure of 600 psi) and $0.130 per MMBtu for Tier 2 pressure services (maximum receipt point of pressure of 300 psi). |
Our new gathering agreement with CNX Gas also commits CNX Gas to drill the following numbers of wells in the McQuay area, provided that if 125 wells have been drilled and completed in the Marcellus Shale, then the remainder of such planned wells must be drilled in the Utica Shale. To the extent the requisite amount of wells are not drilled by CNX Gas in a given period, we will be entitled to a deficiency payment per shortfall well as set out in the parenthetical below:
| • | January 1, 2018 to December 31, 2018 - 30 wells (deficiency payment of $3.5 million per well) |
| • | January 1, 2019 to April 30, 2020 - 40 wells (deficiency payment of $3.5 million per well) |
| • | May 1, 2020 to April 30, 2021 - 40 wells (deficiency payment of $2.0 million per well) |
| • | May 1, 2021 to April 30, 2022 - 30 wells (deficiency payment of $2.0 million per well) |
In the event that CNX Gas drills wells and completes a number of wells in excess of the number of wells required to be drilled and completed in such period, (i) the number of excess wells drilled and completed during such period will be applied to the minimum well requirement in the succeeding period or (ii) to the extent CNX Gas was required to make deficiency payments for shortfalls in the preceding period, CNX Gas may elect to cause the Partnership to pay a refund in an amount equal to (x) the number of excess wells drilled and completed during the period, multiplied by (y) the deficiency payment paid per well during the period in which the shortfall occurred.
On December 1, 2016, we entered into new fixed-fee gathering agreements with Noble Energy and CNX Gas that replaced the gathering agreements that had been in place since our IPO. Our gathering agreement with Noble Energy was assigned to HG Energy upon consummation of the Noble Energy Asset Sale effective June 28, 2017. The terms of the agreement remain unchanged following the assignment, except as it relates to HG Energy’s inability to, without the
82
Partnership’s consent, release dedicated acreage in connection with a transfer of such acreage free of the dedication to us, and exercise other initial shipper rights provided under the gathering agreement.
HG Energy is currently not a related party of the Partnership; accordingly, the focus of the following disclosure is on current and historical related party transactions, which do not include transactions with HG Energy. Our fees for gathering services, throughout 2017, were based on the type and scope of the midstream services we provided, summarized as follows:
| • | For the services we provided with respect to natural gas from the Marcellus Shale formation that did not require downstream processing, or dry gas, we received a fee of $0.42 per MMBtu. |
| • | For the services we provided with respect to the natural gas that required downstream processing, or wet gas, we received: |
| ◦ | a fee of $0.289 per MMBtu in the Moundsville area (Marshall County, West Virginia); |
| ◦ | a fee of $0.289 per MMBtu in the Pittsburgh International Airport area; and |
| ◦ | a fee of $0.578 per MMBtu for all other areas in the dedication area. |
| • | For the services we provided with respect to natural gas from the Utica Shale formation, we received a weighted average rate of $0.26 per MMBtu. |
| • | Our fees for condensate services were $5.25 per Bbl in the Majorsville area and $2.627 per Bbl in the Moundsville area. |
Each of the foregoing fees paid by CNX Gas escalates by 2.5% on January 1 on an annual basis, through and including the final calendar year of the initial term. Commencing on January 1, 2035, and as of January 1 thereafter, each of the applicable fees will be adjusted pursuant to the percentage change in CPI-U, but such fees will never escalate or decrease by more than 3%. Notwithstanding the foregoing, from time to time, CNX Gas and HG Energy may request rate reductions under certain circumstances, which are reviewed by the board of directors of our general partner, with oversight, as our board of directors deems necessary, by our conflicts committee. No rate reduction arrangements were active at December 31, 2017.
We gather, compress, dehydrate and deliver all of CNX Gas’ dedicated natural gas in the Marcellus Shale on a first-priority basis and gather, inject, stabilize and store all of CNX Gas’ dedicated condensate on a first-priority basis, with the exception that until December 1, 2018, CNX Gas will receive first-priority service in our Majorsville system with respect to a certain volume of production (revised bi-annually) and any excess production will receive second-priority service.
CNX Gas provides us with quarterly updates on its drilling and development operations, which include detailed descriptions of the drilling plans, production details and well locations for periods that range from up to 24-48 months, as well as more general development plans that may extend as far as ten years. In addition, we regularly meet with CNX Gas to discuss our current plans to timely construct the necessary facilities to be able to provide midstream services to them on our dedicated acreage. In the event that we do not perform our obligations under a gathering agreement, CNX Gas will be entitled to certain rights and procedural remedies thereunder, including the temporary and/or permanent release from dedication discussed below and indemnification from us.
There are no restrictions under our gathering agreements on the ability of CNX Gas to transfer acreage in the right of first offer (“ROFO”) area, and any such transfer of acreage in the ROFO area will not be subject to our right of first offer. For additional information on the ROFO area, see Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations–How We Evaluate Our Operations–Throughput Volumes.
Upon completion of its 20-year term in 2037, our gathering agreement with CNX Gas will continue in effect from year to year until such time as the agreement is terminated by either us or CNX Gas on or before 180 days prior written notice.
Registration Rights Agreement
On January 3, 2018, in connection with the closing of the Transaction, the Partnership entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Noble Energy relating to the registered resale of common units that Noble acquired in connection with the IPO and upon conversion of subordinated units representing limited partner interests in the Partnership (collectively, the “Registrable Securities”).
Pursuant to the Registration Rights Agreement, the Partnership is required to prepare and file a registration statement, or amend an existing registration statement, for the registered resale of the Registrable Securities and to use commercially reasonable efforts to cause such registration statement to become effective as soon as practicable after the Partnership’s release of earnings for the year ended December 31, 2017.
In certain circumstances, and subject to customary qualifications and limitations, Noble Energy will have piggyback registration rights on offerings of common units initiated by the Partnership and other holders of common units. Noble will also have the right to request that the Partnership initiate up to four Demand Underwritten Offerings (as defined in the Registration Rights Agreement) of Registrable Securities, subject to certain limitations described in the Registration Rights Agreement. The
83
Registration Rights Agreement will terminate no later than the third anniversary of the date on which the registration statement becomes effective.
NOTE 6 — RECEIVABLES AND CONCENTRATION OF CREDIT RISK
Receivables consisted of the following at December 31 (dollars in thousands):
| 2017 | 2016 | ||||||
| Receivables–related party | |||||||
| CNX | $ | 12,801 | $ | 10,956 | |||
| Noble Energy | — | 8,268 | |||||
| CNX Gathering | 303 | 3,210 | |||||
| Receivables–related party | 13,104 | 22,434 | |||||
| Receivables–third party | 8,251 | — | |||||
| Total Receivables | $ | 21,355 | $ | 22,434 | |||
Following the Noble Energy Asset Sale, CNX and HG Energy accounted for substantially all of the Partnership’s gathering revenues. Prior to the consummation of the Noble Energy Asset Sale, CNX and Noble Energy accounted for all of the Partnership’s gathering revenues.
NOTE 7 — PROPERTY AND EQUIPMENT
Property and equipment consisted of the following at December 31 (dollars in thousands):
| 2017 | 2016 | Estimated Useful Lives in Years | |||||||
| Land | $ | 76,130 | $ | 72,878 | N/A | ||||
| Gathering equipment | 662,595 | 643,422 | 25 — 40 | ||||||
| Compression equipment | 180,038 | 169,681 | 30 — 40 | ||||||
| Processing equipment | 30,979 | 30,979 | 40 | ||||||
| Assets under construction | 23,099 | 13,772 | N/A | ||||||
| Total Property and Equipment | $ | 972,841 | $ | 930,732 | |||||
| Less: Accumulated Depreciation | |||||||||
| Gathering equipment | $ | 53,544 | $ | 37,275 | |||||
| Compression equipment | 14,886 | 10,590 | |||||||
| Processing equipment | 5,133 | 4,307 | |||||||
| Total Accumulated Depreciation | $ | 73,563 | $ | 52,172 | |||||
| Property and Equipment, Net | $ | 899,278 | $ | 878,560 | |||||
84
NOTE 8 — OTHER ASSETS
Other assets consisted of the following at December 31 (dollars in thousands):
| 2017 | 2016 | ||||||
| Pipe stock | $ | 392 | $ | 8,596 | |||
| Financing fees | 122 | 286 | |||||
| Deposits | 79 | 79 | |||||
| Total Other Assets | $ | 593 | $ | 8,961 | |||
During the year ended December 31, 2017, the Partnership sold a significant portion of its pipe stock, which was within the Growth Systems, for approximately $0.5 million below is carrying value. The resulting loss was recorded in loss from asset sales in the accompanying consolidated statements of operations.
NOTE 9 — ACCOUNTS PAYABLE - RELATED PARTY
Related party payables consisted of the following at December 31 (dollars in thousands):
| 2017 | 2016 | ||||||
| CNX: | |||||||
| Expense reimbursements | $ | 780 | $ | 999 | |||
| Capital expenditures reimbursements | 83 | 1,148 | |||||
| General and administrative services | 1,458 | 1,964 | |||||
| Operational expenditures reimbursements | — | 395 | |||||
| Other reimbursement | — | 1,060 | |||||
| Due to CNX total | $ | 2,321 | $ | 5,566 | |||
| Noble Energy: | |||||||
| Capital expenditures reimbursements | — | 1,105 | |||||
| General and administrative services | 55 | 53 | |||||
| Operational expenditures reimbursements | — | 401 | |||||
| Other reimbursement | — | 1,060 | |||||
| Due to Noble Energy total | $ | 55 | $ | 2,619 | |||
| CNX Gathering: | |||||||
| Capital expenditures reimbursement to CNX Gathering | — | 104 | |||||
| Due to CNX Gathering total | $ | — | $ | 104 | |||
| Total Accounts Payable — Related Party | $ | 2,376 | $ | 8,289 | |||
NOTE 10 — REVOLVING CREDIT FACILITY
We are party to a credit facility agreement which provides for a $250 million unsecured five year revolving credit facility that matures on September 30, 2019. Our revolving credit facility is available for working capital, capital expenditures, certain acquisitions, distributions, unit repurchases and other lawful partnership purposes. Borrowings under our revolving credit facility bear interest at our option at either:
| • | the base rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) JP Morgan’s prime rate; or (iii) the daily LIBOR rate for a one month interest period plus 1.00%; in each case, plus a margin varying from 0.125% to 1.00% depending on our most recent consolidated total leverage ratio (as defined in the agreement governing our revolving credit facility) or our credit rating; or |
| • | the LIBOR rate plus a margin varying from 1.125% to 2.00%, in each case, depending on our most recent consolidated leverage ratio (as defined in the agreement governing our revolving credit facility) or our credit rating, as the case may be. |
Interest on base rate loans is payable quarterly. Interest on LIBOR loans is payable on the last day of each interest period or, in the case of interest periods longer than three months, every three months. The unused portion of our revolving credit
85
facility is subject to a commitment fee ranging from 0.15% to 0.35% per annum depending on our most recent consolidated leverage ratio or our credit rating, as the case may be.
Our revolving credit facility contains covenants and conditions that, among other things, limit (subject to certain exceptions) our ability to incur or guarantee additional debt, make cash distributions (though there will be an exception for distributions permitted under the partnership agreement, subject to certain customary conditions), incur certain liens or permit them to exist, make certain investments and acquisitions, enter into certain types of transactions with affiliates, merge or consolidate with another company, and transfer, sell or otherwise dispose of assets. In connection with the Transaction, the lenders under our revolving credit facility waived certain change of control provisions contained in our revolving credit facility.
We are subject to covenants that require us to maintain certain financial ratios, the most important of which are as follows:
| • | The ratio of (i) consolidated total funded debt (as defined in the agreement governing our revolving credit facility) as of the last day of each fiscal quarter to (ii) consolidated EBITDA (as defined in the agreement governing our revolving credit facility) for the four consecutive fiscal quarters ending on the last day of such fiscal quarter may not exceed (A) at any time other than during a qualified acquisition period (as defined in the agreement governing our revolving credit facility), 5.0 to 1.0 and (B) during a qualified acquisition period, 5.5 to 1.0 This consolidated leverage ratio is calculated as the total amount outstanding on our credit facility divided by EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP. |
| • | The ratio of (i) consolidated EBITDA for the four consecutive fiscal quarters ending on the last day of each fiscal quarter to (ii) consolidated interest expense (as defined in the agreement governing our revolving credit facility) for such four consecutive fiscal quarters may not be less than 3.0 to 1.0. This consolidated interest coverage ratio is calculated as EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP divided by total interest charges. |
The Partnership is in compliance with each of the above referenced financial covenants at December 31, 2017. Accordingly, the Partnership had the maximum amount of revolving credit available for borrowing at December 31, 2017, or $100.5 million.
The outstanding balances and LIBOR interest rates in effect (plus applicable margin) on our revolving credit facility as of the following dates are presented below.
| 2017 | 2016 | |||||||||||||
| (in thousands, except percentages) | Debt | Interest Rate (1) | Debt | Interest Rate (1) | ||||||||||
| Revolving credit facility, due September 30, 2019 | $ | 149,500 | 3.11 | % | $ | 167,000 | 2.26 | % | ||||||
NOTE 11 — COMMITMENTS AND CONTINGENCIES
We may become involved in claims and other legal matters arising in the ordinary course of business. Although claims are inherently unpredictable, we are not aware of any matters that may have a material adverse effect on our business, financial position, results of operations or cash flows.
NOTE 12 — LEASES
We have entered into various non-cancelable operating leases primarily related to compression facilities. Future minimum lease payments under operating leases as of December 31, 2017 are as follows (dollars in thousands):
| Minimum Lease Payments | |||
| 2018 | $ | 3,080 | |
| 2019 | 1,627 | ||
| 2020 | 1,103 | ||
| $ | 5,810 | ||
Rental expense under operating leases was $7.6 million, $7.7 million and $9.2 million for the years ended December 31, 2017, 2016, and 2015, respectively. These expenses are included within operating expense–third party on our consolidated statement of operations.
86
NOTE 13 — SEGMENT INFORMATION
Operating segments are the revenue-producing components of a company for which separate financial information is produced internally and is subject to evaluation by the chief operating decision maker in deciding how to allocate resources. The Partnership has three operating segments, which are also its reportable segments - the Anchor Systems, Growth Systems and Additional Systems, each of which does business entirely within the United States of America. See Note 1–Description of Business for details.
Segment results for the periods presented are as follows:
| For the Years Ended December 31, | |||||||||||
| (in thousands) | 2017 | 2016 | 2015 | ||||||||
| Gathering Revenue: | |||||||||||
| Anchor Systems | $ | 186,897 | $ | 197,878 | $ | 156,274 | |||||
| Growth Systems | 8,152 | 10,359 | 13,435 | ||||||||
| Additional Systems | 38,799 | 30,974 | 33,714 | ||||||||
| Total Gathering Revenue | $ | 233,848 | $ | 239,211 | $ | 203,423 | |||||
| Net Income (Loss): | |||||||||||
| Anchor Systems | $ | 113,990 | $ | 124,045 | $ | 93,529 | |||||
| Growth Systems | 607 | (6,624 | ) | 4,854 | |||||||
| Additional Systems | 19,465 | 12,701 | 17,148 | ||||||||
| Total Net Income | $ | 134,062 | $ | 130,122 | $ | 115,531 | |||||
| Depreciation Expense: | |||||||||||
| Anchor Systems | $ | 15,170 | $ | 14,333 | $ | 10,717 | |||||
| Growth Systems | 2,193 | 2,157 | 1,948 | ||||||||
| Additional Systems | 5,329 | 4,711 | 2,388 | ||||||||
| Total Depreciation Expense | $ | 22,692 | $ | 21,201 | $ | 15,053 | |||||
| Capital Expenditures for Segment Assets: | |||||||||||
| Anchor Systems | $ | 40,858 | $ | 37,133 | $ | 149,518 | |||||
| Growth Systems | 702 | 1,089 | 22,058 | ||||||||
| Additional Systems | 6,806 | 12,438 | 119,635 | ||||||||
| Total Capital Expenditures | $ | 48,366 | $ | 50,660 | $ | 291,211 | |||||
Segment assets as of the dates presented are as follows:
| December 31, | |||||||
| (in thousands) | 2017 | 2016 | |||||
| Segment Assets: | |||||||
| Anchor Systems | $ | 602,283 | $ | 571,415 | |||
| Growth Systems | 92,659 | 98,447 | |||||
| Additional Systems | 231,647 | 248,695 | |||||
| Total Segment Assets | $ | 926,589 | $ | 918,557 | |||
87
NOTE 14 — LONG-TERM INCENTIVE PLAN
Under the Partnership’s 2014 Long-Term Incentive Plan (our “LTIP”), our general partner may issue long-term equity based awards to directors, officers and employees of the general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services on behalf of the Partnership. The Partnership is responsible for the cost of awards granted under the LTIP, which limits the number of units that may be delivered pursuant to vested awards to 5,800,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, forfeited, withheld to satisfy tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.
The following table presents phantom unit activity during the year ended December 31, 2017:
| Number of Units | Weighted Average Grant Date Fair Value | ||||
| Total awarded and unvested at December 31, 2016 | 158,117 | $ | 10.57 | ||
| Granted | 73,619 | 23.29 | |||
| Vested | (80,004) | 11.05 | |||
| Forfeited | (17,579) | 17.12 | |||
| Total awarded and unvested at December 31, 2017 | 134,153 | $ | 16.40 | ||
The Partnership accounts for phantom units as equity awards and records compensation expense on a straight line basis over the vesting period of the awards based on their fair value on the grant dates. Awards granted to independent directors vest over a period of one year, and awards granted to certain officers and employees of the general partner vest 33% per year over a period of three years.
The Partnership recognized $1.2 million, $0.8 million and $0.4 million of compensation expense for the years ended December 31, 2017, 2016 and 2015, respectively, which was included in general and administrative expense - related party in the consolidated statements of operations.
At December 31, 2017, unrecognized compensation expense related to all outstanding awards was $1.1 million, which is expected to be recognized over the following two years.
NOTE 15 — SUBSEQUENT EVENTS
On January 22, 2018, the board of directors of our general partner declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2017 of $0.3133 per common unit. The cash distribution will be paid on February 14, 2018 to unitholders of record as of the close of business on February 5, 2018.
On February 7, 2018, the Partnership entered into a Purchase and Sale Agreement (the “Purchase Agreement”), with CNX Gathering, CNX Midstream DevCo I LP, a Delaware limited partnership (“DevCo I LP”), CNX Midstream DevCo III LP, a Delaware limited partnership (“DevCo III LP”), and, for certain purposes, CNX Midstream DevCo I GP LLC, a Delaware limited liability company, CNX Midstream DevCo III GP LLC, a Delaware limited liability company, and CNX Midstream Operating Company LLC, a Delaware limited liability company.
CNX Gathering owns a 95% noncontrolling interest in DevCo III LP, which owns the gathering system and related assets commonly referred to as the Shirley-Penns System (the “Shirley-Penns System”), while the Partnership owns the remaining 5% controlling interest in DevCo III LP. Pursuant to the terms of the Purchase Agreement, DevCo III LP will transfer its interest in the Shirley-Penns System on a pro rata basis to CNX Gathering and the Partnership in accordance with each transferee’s respective ownership interest in DevCo III LP, and following such transfer, CNX Gathering will sell its aggregate interest in the Shirley-Penns System to DevCo I LP in exchange for cash consideration in the amount of $265 million (the “Acquisition”). The Partnership expects to fund the Acquisition with cash on hand and by accessing the capital markets, subject to market conditions. The Acquisition is expected to close in the first quarter of 2018, subject to customary closing conditions (the “Closing”). Following the Closing, the Partnership will own (through one or more intermediate entities) a 100% controlling interest in the Shirley-Penns System.
In addition, in connection with the Closing, the Partnership expects to amend its gathering agreement with CNX Gas to require CNX Gas to make a minimum volume commitment for the Shirley-Penns System for the period from January 1, 2018 through December 31, 2031 and to establish certain gathering fees, deficiency payments and excess delivery credits related thereto.
88
SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
| For the Quarters Ended | |||||||||||||||
| March 31 | June 30 | September 30 | December 31 | ||||||||||||
| Year Ended December 31, 2017 | |||||||||||||||
| Revenue | $ | 58,958 | $ | 56,534 | $ | 56,658 | $ | 61,698 | |||||||
| Net income | $ | 33,240 | $ | 29,752 | $ | 33,468 | $ | 37,602 | |||||||
| Net income attributable to general and limited partner ownership interests in CNX Midstream Partners LP | $ | 30,067 | $ | 28,991 | $ | 28,914 | $ | 27,021 | |||||||
| Net income per limited partner unit: | |||||||||||||||
| Basic | $ | 0.46 | $ | 0.44 | $ | 0.43 | $ | 0.40 | |||||||
| Diluted | $ | 0.45 | $ | 0.44 | $ | 0.43 | $ | 0.40 | |||||||
| Year Ended December 31, 2016 | |||||||||||||||
| Revenue | $ | 62,248 | $ | 58,407 | $ | 60,729 | $ | 57,827 | |||||||
| Net income | $ | 37,295 | $ | 24,468 | $ | 36,381 | $ | 31,978 | |||||||
| Net income attributable to general and limited partner ownership interests in CNX Midstream Partners LP | $ | 24,790 | $ | 23,217 | $ | 23,631 | $ | 24,848 | |||||||
| Net income per limited partner unit: | |||||||||||||||
| Basic | $ | 0.42 | $ | 0.39 | $ | 0.40 | $ | 0.38 | |||||||
| Diluted | $ | 0.42 | $ | 0.39 | $ | 0.40 | $ | 0.38 | |||||||
89
| 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
Under the supervision and with the participation of management of our general partner, including the principal executive officer and principal financial officer of our general partner, an evaluation of the Partnership’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”)), was conducted as of the end of the period covered by this Annual Report on Form 10-K. Based upon this evaluation, the chief executive officer and chief financial officer of our general partner have concluded that the Partnership’s disclosure controls and procedures were effective as of the end of the period covered by this report.
Management’s Report on Internal Control over Financial Reporting
The Partnership’s management is responsible for establishing and maintaining adequate internal control over financial reporting, which 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. The Partnership’s internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Partnership; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership’s assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation. 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. Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2017. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (“COSO”) in Internal Control-Integrated Framework. Based on our assessment and those criteria, management has concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2017.
This Annual Report on Form 10-K for the fiscal year ended December 31, 2017 does not include an attestation report of the Partnership’s independent accounting firm, as permitted by the transition period established by rules of the Securities and Exchange Commission for recently public companies.
Changes in Internal Control over Financial Reporting
There were no changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fourth quarter of 2017 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.
| ITEM 9B. | OTHER INFORMATION |
On February 7, 2018, the Partnership entered into a Purchase and Sale Agreement (the “Purchase Agreement”), with CNX Gathering, CNX Midstream DevCo I LP, a Delaware limited partnership (“DevCo I LP”), CNX Midstream DevCo III LP, a Delaware limited partnership (“DevCo III LP”), and, for certain purposes, CNX Midstream DevCo I GP LLC, a Delaware limited liability company, CNX Midstream DevCo III GP LLC, a Delaware limited liability company, and CNX Midstream Operating Company LLC, a Delaware limited liability company.
CNX Gathering owns a 95% interest in DevCo III LP, which owns the gathering system and related assets commonly referred to as the Shirley-Penns System (the “Shirley-Penns System”), while the Partnership owns the remaining 5% interest in DevCo III LP. Pursuant to the terms of the Purchase Agreement, DevCo III LP will transfer its interest in the Shirley-Penns System on a pro rata basis to CNX Gathering and the Partnership in accordance with each transferee’s respective ownership
90
interest in DevCo III LP, and following such transfer, CNX Gathering will sell its aggregate interest in the Shirley-Penns System to DevCo I LP in exchange for cash consideration in the amount of $265 million (the “Acquisition”). The Partnership expects to fund the Acquisition with cash on hand and by accessing the capital markets, subject to market conditions. The Acquisition is expected to close in the first quarter of 2018, subject to customary closing conditions (the “Closing”). Following the Closing, the Partnership will own (through one or more intermediate entities) 100% of the Shirley-Penns System.
In addition, in connection with the Closing, the Partnership expects to amend its gathering agreement with CNX Gas to require CNX Gas to make a minimum volume commitment for the Shirley-Penns System for the period from January 1, 2018 through December 31, 2031 and to establish certain gathering fees, deficiency payments and excess delivery credits related thereto.
The foregoing description of the Purchase Agreement is not complete and is qualified in its entirety by reference to the full text of the Purchase Agreement, which is filed as Exhibit 10.14 to this Annual Report on Form 10-K and incorporated herein by reference.
91
PART III
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Management of CNX Midstream Partners LP
We are managed by the directors and executive officers of our general partner, CNX Midstream GP LLC, formerly known as CONE Midstream GP LLC. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. CNX Gathering LLC (“CNX Gathering”) formerly CONE Gathering LLC, in which CNX owns a 100% membership interest as of January 3, 2018, owns all of the membership interests in our general partner and has the right to appoint the entire board of directors of our general partner, including our independent directors. Our unitholders are not entitled to elect the directors of our general partner’s board of directors or to directly or indirectly participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.
In evaluating director candidates, CNX Gathering will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of our board of directors to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board of directors of our general partner to fulfill their duties.
Neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by our general partner or its affiliates, but we sometimes refer to these individuals in this prospectus as our employees.
Director Independence
As a publicly traded partnership, we qualify for, and are relying on, certain exemptions from the New York Stock Exchange’s (“NYSE”) corporate governance requirements, including:
| • | the requirement that a majority of the board of directors of our general partner consist of independent directors; |
| • | the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and |
| • | the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors. |
As a result of these exemptions, our general partner’s board of directors is not comprised of a majority of independent directors. Our board of directors does not currently intend to establish a nominating/corporate governance committee or a compensation committee. Accordingly, unitholders will not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the NYSE.
We are, however, required to have an audit committee of at least three members, and all of its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act.
Committees of the Board of Directors
The board of directors of our general partner has an audit committee, and may have such other committees (including a conflicts committee) as the board of directors shall determine from time to time.
Audit Committee
The audit committee of the board of directors of our general partner assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary. Ms. Angela A. Minas (Chairperson) and Messrs. Raymond T. Betler and John E. Jackson comprise the members of the audit committee. Each of Ms. Minas and Messrs. Betler and Jackson satisfy the definition of audit committee financial expert for purposes of the SEC’s rules.
92
The audit committee of the board of directors of our general partner oversees the Partnership’s financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process, including the systems of internal controls.
In fulfilling its oversight responsibilities, the audit committee reviewed and discussed with management the audited financial statements contained in this Annual Report on Form 10-K.
The Partnership’s independent registered public accounting firm, Ernst & Young LLP, is responsible for expressing an opinion on the conformity of the audited financial statements with accounting principles generally accepted in the United States of America. The audit committee reviewed with Ernst & Young LLP the firm’s judgment as to the quality, not just the acceptability, of the Partnership’s accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards. The audit committee also discussed with Ernst & Young LLP the matters required to be discussed by Public Company Accounting Oversight Board Auditing Standard No. 16, Communications with Audit Committees.
Based on the reviews and discussions referred to above, the audit committee recommended to the board of directors that the audited financial statements be included in this Annual Report on Form 10-K for the year ended December 31, 2017 for filing with the SEC.
Conflicts Committee
The board of directors of our general partner has the ability to establish a conflicts committee under our partnership agreement. If established, at least two members of the board of directors of our general partner will serve on the conflicts committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. The board of directors of our general partner will determine whether to refer a matter to the conflicts committee on a case-by-case basis. The members of our conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates (including CNX), 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. In addition, the members of our conflicts committee may not own any interest in our general partner or any interest in us or our subsidiaries other than common units or awards under our long-term incentive plan. If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee 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.
Board Leadership Structure and Role in Risk Oversight
Mr. Nicholas J. DeIuliis currently serves as the Chairman of the Board of Directors of our general partner. Directors of the Board of Directors of our general partner are designated or appointed by CNX Gathering. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.
Our corporate governance guidelines provide that the Board of Directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility is largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.
Non-Management Executive Sessions and Unitholder Communications
The non-management members of the board of directors regularly met in executive session in connection with each regularly scheduled meeting of the board of directors, and Ms. Minas, as Chair of the audit committee, presided over such executive sessions.
Unitholders and interested parties can communicate directly with non-management directors by mail in care of the General Counsel and Secretary at CNX Midstream Partners LP, CNX Center, 1000 CONSOL Energy Drive, Canonsburg, Pennsylvania 15317. Such communications should specify the intended recipient or recipients. Commercial solicitations or communications will not be forwarded.
Meetings and Other Information
During the last fiscal year, our board of directors had 11 meetings, of which four were “regularly scheduled meetings” and seven were “special meetings”. Our audit committee had eight meetings, of which four were “regularly scheduled meetings” and four were “special meetings”. All directors have access to members of management, and a substantial amount of information transfer and informal communication occurs between meetings.
93
Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Whistleblower Policy and Audit Committee Charter are available on our website under the Corporate Governance tab. Our Code of Business Conduct and Ethics applies to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. We intend to disclose any amendment to or waiver of our Code of Business Conduct and Ethics either on our website or in a Current Report on Form 8-K filed with the SEC.
Directors and Executive Officers of CNX Midstream GP LLC
Directors are appointed by CNX Gathering, the sole member of our general partner, and hold office until their successors have been appointed or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table presents information for the directors and executive officers of CNX Midstream GP LLC as of February 1, 2018.
| Name | Age | Position with Our General Partner |
| Nicholas J. DeIuliis | 49 | Chairman and Chief Executive Officer |
| Donald W. Rush | 35 | Director and Chief Financial Officer |
| Timothy C. Dugan | 56 | Director and Chief Operating Officer |
| Brian R. Rich | 41 | Chief Accounting Officer |
| Stephen W. Johnson | 59 | Director |
| Angela A. Minas | 53 | Director and Audit Committee Chair |
| Raymond T. Betler | 61 | Director and Audit Committee Member |
| John E. Jackson | 59 | Director and Audit Committee Member |
Nicholas J. DeIuliis has served as Chairman of the Board and Chief Executive Officer of the general partner since January 3, 2018. Mr. DeIuliis is a Director and the President and Chief Executive Officer of CNX Resources Corporation (the “Company”). Prior to the separation of CONSOL Energy Inc. into two separate companies, Mr. DeIuliis had more than 25 years of experience with the Company and in that time has held the positions of Chief Executive Officer since May 7, 2015, President since February 23, 2011, and previously served as the Chief Operating Officer, Senior Vice President–Strategic Planning, and earlier in his career various engineering positions. He was a Director, President and Chief Executive Officer of CNX Gas Corporation from its creation in 2005 through 2009. Mr. DeIuliis was a Director and Chairman of the Board of the general partner of CONSOL Coal Resources LP (formerly known as CNX Coal Resources LP) from March 16, 2015 until November 28, 2017. Mr. DeIuliis is a member of the Board of Directors of the University of Pittsburgh Cancer Institute, the Center for Responsible Shale Development and the Allegheny Conference on Community Development. Mr. DeIuliis is a registered engineer in the Commonwealth of Pennsylvania and a member of the Pennsylvania bar.
Donald W. Rush has served as a Director and Chief Financial Officer of the general partner since January 3, 2018. Mr. Rush has also served as the Executive Vice President and Chief Financial Officer of CNX Resources Corporation since July 11, 2017. Mr. Rush held the same position at the formerly named CONSOL Energy Inc. prior to its separation into two separate companies. He previously served as Vice President of Energy Marketing where he oversaw the Company’s commercial functions, including mergers and acquisitions, gas marketing and transportation, in addition to holding other strategy and planning, business development and engineering positions during his 12 years with the Company. He successfully guided the Company through every significant transaction during its transition into a pure play natural gas exploration and production company, including the sale of the Company’s five West Virginia coal mines in 2013 and the separation of the Company’s Marcellus Shale joint venture with Noble Energy Inc. in 2016. Mr. Rush holds a B.S. in civil engineering from the University of Pittsburgh and an M.B.A. from Carnegie Mellon University’s Tepper School of Business.
Timothy C. Dugan has served as a Director and Chief Operating Officer of our general partner since January 3, 2018 and January 12, 2018, respectively. Mr. Dugan has also served as an Executive Vice President at the Company since September 20, 2016 and Chief Operating Officer of the Company since January 28, 2014. Mr. Dugan held the same position at the formerly named CONSOL Energy Inc. prior to its separation into two separate companies. Before being appointed to his current position, he was President and Chief Operating Officer of CNX Gas Corporation from May 2014 to December 2014 when he became President and Chief Executive Officer. Prior to joining the Company, Mr. Dugan was Vice President–Appalachia South Business Unit at Chesapeake Energy Corporation. During his seven years with Chesapeake Energy Corporation, he held several titles, including Senior Asset Manager and District Manager. Mr. Dugan began his petroleum and natural gas engineering career in 1984 with Cabot Oil & Gas Corporation as a General Foreman and Field Consultant, and he held other industry related
94
positions with progressing responsibility at various oil and gas companies. Mr. Dugan is a member of the Society of Petroleum Engineers.
Brian R. Rich has served as Chief Accounting Officer of our general partner since November 4, 2015. Prior to his appointment as Chief Accounting Officer of our general partner, Mr. Rich was a senior manager within the Company’s accounting department since November 2014, serving in positions of increasing responsibility. Prior to joining the Company, Mr. Rich held various accounting positions at Education Management Corporation from March 2007 through November 2014, including Vice President and Assistant Controller, a position he held upon his departure. Prior to his time at Education Management Corporation, Mr. Rich served in various positions (from associate through manager) with PricewaterhouseCoopers LLP from October 1999 through March 2007, primarily serving the energy sector. Mr. Rich is a Certified Public Accountant licensed in Pennsylvania.
Stephen W. Johnson has served as a Director of our general partner since May 30, 2014. Mr. Johnson has also served as the Executive Vice President and Chief Administrative Officer of CNX Resources Corporation since April 13, 2013. Mr. Johnson held the same position at the formerly named CONSOL Energy Inc. prior to its separation into two separate companies. Before being appointed to his current position, Mr. Johnson served as Executive Vice President–Diversified Business Units and Chief Legal and Corporate Affairs Officer, and as Senior Vice President and General Counsel of both CONSOL Energy Inc. and CNX Gas Corporation. Mr. Johnson was a Director of the general partner of CONSOL Coal Resources LP (formerly known as CNX Coal Resources LP) from March 16, 2015 until November 28, 2017. Mr. Johnson has spent numerous years in the natural resources industry, including 12 years with CNX Resources Corporation, CONSOL Energy Inc. and CNX Gas Corporation and a number of years prior to that representing natural resources companies in private legal practice. Mr. Johnson is the Chairman of the Board of Concordia Lutheran Ministries, a nonprofit continuing care retirement community, and the former Chairman of NEED, a nonprofit minority college access program.
Angela A. Minas was appointed a Director of our general partner and Chairperson of our Audit Committee effective September 25, 2014. Ms. Minas also currently serves on the board of directors of the general partner of Ciner Resources LP, a public master limited partnership, where she also serves as Audit Committee Chair, and on the board of directors of the general partner of Westlake Chemical Partners LP, a public master limited partnership. Ms. Minas previously served as Vice President and Chief Financial Officer of Nemaha Oil and Gas, LLC, a private exploration and production portfolio company backed by Pine Brook Road Partners, a private equity firm. From 2008 to 2012, Ms. Minas served as Vice President and Chief Financial Officer of the general partner of DCP Midstream Partners, LP, a public master limited partnership. From 2006 to 2008, Ms. Minas served as Chief Financial Officer, Chief Accounting Officer and Treasurer of Constellation Energy Partners LLC, a public master limited liability company. Prior to her corporate roles in the MLP industry, Ms. Minas spent 20 years in the management consulting industry and held numerous leadership roles, including Partner responsible for Arthur Andersen's North American oil and gas consulting practice. Ms. Minas serves on the Council of Overseers of the Rice University Graduate Business School. Ms. Minas’ previous experience with public master limited partnerships and the natural resource industry, as well as her knowledge of financial statements, provide her with the necessary skills to be a member of the board of directors of our general partner.
Raymond T. Betler was appointed as a Director of our general partner and member of our Audit Committee effective October 18, 2017. Mr. Betler is a Director and the President and Chief Executive Officer of Westinghouse Air Brake Technologies Corporation (NYSE: WAB)(“Wabtec”), a leading supplier of value-added, technology-based products and services for freight rail, passenger transit and select industrial markets worldwide. Prior to becoming CEO, Mr. Betler served Wabtec as President and Chief Operating Officer from May 2013 until May 2014, and Chief Operating Officer from December 2010 until May 2013. Mr. Betler was Vice President and Group Executive of the Transit Group of Wabtec from August 2008 until December 2010. Prior to his tenure with Wabtec, Mr. Betler served as President, Total Transit Systems for Bombardier Transportation. He held various executive roles within Bombardier during his 30-year career with the transportation company and its numerous predecessors. Mr. Betler is also a Director at Dollar Bank. We believe that Mr. Betler’s public company background and experience in financial matters, along with the leadership attributes indicated by his executive experience, provide an important source of insight and perspective to the board of directors of our general partner.
John E. Jackson was appointed as a Director of our general partner and member of our Audit Committee effective January 20, 2015. Mr. Jackson is the President and CEO of Spartan Energy Partners, LP (“Spartan”), a privately owned gas gathering, treating & processing company. He has been with Spartan since its formation in March, 2010. Mr. Jackson was Chairman, CEO and President of Price Gregory Services, Inc., a pipeline-related infrastructure service provider from February 2008 until its sale in October of 2009. He served as a director of Hanover Compressor Company (“Hanover”), now known as Exterran Holdings, Inc. (NYSE: EXH), from July 2004 until May 2010. Mr. Jackson served as Hanover’s President and CEO from October 2004 to August 2007 and as Chief Financial Officer from January 2002 to October 2004. Mr. Jackson is a director of Seitel, Inc., a privately owned provider of seismic data to the oil & gas industry in North America, since August 2007, Select Energy Services, LLC, a privately owned total water management company for oil and gas companies, since January 2012 & Main Street Capital Corporation (NYSE: MAIN) a publicly traded BDC, since August 2013. Previously, Mr. Jackson served as
95
a director of Encore Energy Partners (NYSE: ENP) from January 2009 until its sale in December 2011 and RSH Energy, LLC, a privately owned engineering firm, from September 2013 to March 2014. He also serves on the board of several non-profit organizations. We believe that Mr. Jackson’s background in the energy industry and experience in financial matters, along with the leadership attributes indicated by his executive experience, provide an important source of insight and perspective to the board of directors of our general partner.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than ten percent of a registered class of our equity securities (collectively, “Insiders”) to file with the SEC initial reports of ownership and reports of changes in ownership of such equity securities. Insiders are also required to furnish us with copies of all Section 16(a) forms that they file. Such reports are accessible on or through our website at www.cnxmidstream.com.
Based solely upon a review of the copies of Forms 3 and 4 furnished to us, or written representations from certain reporting persons that no Forms 5 were required, we believe that the Insiders complied with all filing requirements with respect to transactions in our equity securities during 2017.
96
| ITEM 11. | EXECUTIVE COMPENSATION |
Neither we nor our general partner employ any of the individuals who serve as executive officers of our general partner and are responsible for managing our business. We are managed by our general partner. For 2017, the executive officers of our general partner were employees of CNX and Noble Energy. For 2017, compensation of our executive officers was set and paid by CNX and Noble Energy, as applicable, under their respective compensation programs. For 2017, we and our general partner were parties to the omnibus agreement with CNX and Noble Energy pursuant to which, among other matters:
| • | CNX and Noble Energy made available to our general partner the services of their employees who acted as the executive officers of our general partner; |
| • | our general partner paid a fixed administrative fee to each of CNX and Noble Energy to cover the services provided to us by the executive officers of our general partner who were employees of CNX and Noble Energy, respectively. |
During 2017, our “Named Executive Officers” (“NEOs”) were:
| • | John T. Lewis, Former Chief Executive Officer; and |
| • | David M. Khani, Former Chief Financial Officer; and |
| • | Joseph M. Fink, Former Chief Operating Officer. |
Throughout 2017, Mr. Lewis, who was also an executive officer of Noble Energy, devoted the majority of his time to his role at Noble Energy and also spent time, as needed, directly managing our business and affairs. During 2017, Mr. Khani transitioned his role as an executive officer of CONSOL Energy Inc. to an executive officer of CONSOL Mining Corporation, the wholly-owned subsidiary that would be spun-off as a separate, publicly traded company on November 28, 2017. Leading up to and after his transition, Mr. Khani devoted the majority of his time to his role at CONSOL Energy Inc. and CONSOL Mining Corporation and spent time as needed managing our business and affairs. Mr. Fink, who is an employee of CNX, also performed responsibilities for CNX unrelated to our business; however, for 2017, Mr. Fink devoted substantially all of his working time to us and our general partner. For 2017, pursuant to the terms of the omnibus agreement, we paid a fixed administrative fee to Noble Energy and CNX, which covered the services provided to us by all of our executive officers. Except with respect to awards under the 2017 STIC Plan and any equity awards that were granted under our equity compensation plans, our executive officers did not receive any separate amounts of compensation for their services to our business or as executive officers of our general partner and, except for the fixed administrative fee we paid to Noble Energy and CNX, we did not otherwise pay or reimburse any compensation amounts to our executive officers.
Effective January 3, 2018, Messrs. Lewis and Khani resigned from their respective positions with us and our general partner and Nicholas DeIuliis and Donald Rush were appointed chief executive officer and chief financial officer of our general partner, respectively, on such date. Effective January 12, 2018, Timothy Dugan was appointed chief operating officer of our general partner. Mr. Fink remains an employee of CNX.
Compensation Committee Report
We do not have a separate compensation committee. In addition, we do not directly employ or compensate our named executive officers. Rather, during 2017 the compensation of our executive officers was set and paid by CNX and Noble Energy, as applicable, under their respective compensation programs, and under the omnibus agreement, our general partner paid a fixed administrative fee to cover the services provided to us by the executive officers of our general partner who were employees of CNX and Noble Energy. In light of the foregoing, the board of directors has reviewed and discussed with management the Compensation Discussion and Analysis set forth herein and, based on such review and discussions, determined that it be included in this annual report on Form 10-K.
Submitted by: Nicholas J. DeIuliis, Chairman of the Board
Donald W. Rush
Timothy C. Dugan
Stephen W. Johnson
Angela A. Minas
Raymond T. Betler
John E. Jackson
97
Summary Compensation Table
The following summarizes the total compensation paid to our named executive officers for their services in relation to our business for 2017, 2016, and 2015:
| Name and Principal Position | Year | Salary | Unit Awards (2) | Non-Equity Incentive Plan Compensation (3) | Change in Pension Value and Nonqualified Deferred Compensation Earnings (4) | All Other Compensation (5) | Total | |||||||||||||||||||
John T Lewis (Former Chief Executive Officer) (1) | 2017 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||
| 2016 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
| 2015 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
David Khani (Former Chief Financial Officer) (1) | 2017 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||
| 2016 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
| 2015 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
| Joseph M. Fink (Former Chief Operating Officer) | 2017 | $ | 232,855 | $ | 175,000 | $ | 119,236 | $ | 16,595 | $ | 27,026 | $ | 570,712 | |||||||||||||
| 2016 | $ | 227,697 | $ | 100,000 | $ | 161,122 | $ | 33,519 | $ | 40,430 | $ | 562,768 | ||||||||||||||
| 2015 | $ | 223,161 | $ | 100,000 | $ | 103,848 | $ | — | $ | 34,567 | $ | 461,576 | ||||||||||||||
(1) For 2017, Messrs. Lewis and Khani devoted approximately 10% of their overall working time to our business, and the compensation Messrs. Lewis and Khani received from Noble Energy and CONSOL Energy Inc., respectively, in relation to their services for us did not comprise a material amount of their total compensation.
(2) Values represent awards of phantom units, which are similar to restricted stock units. All values do not correspond to the actual value that will be recognized by the named executive at the time such units vest.
(3) Includes cash incentives earned in the applicable year under the CNXM Short-Term Incentive Compensation Plan. The relevant performance measures
underlying the cash awards were satisfied in the applicable annual performance period. A portion of the 2017 amount includes an estimate based on Mr. Fink’s individual performance evaluation score, which is to be determined later in February 2018.
(4) Amount reflects the actuarial increase in the present value of the named executive’s benefits under the CONSOL Energy Employee Retirement Plan and the Defined Contribution Restoration Plan. For Mr. Fink, zero is shown for 2015 because the actual change in pension value was a decrease in the amount of $4,909. This was primarily due to the qualified pension plan being frozen as of December 31, 2014 and the change in interest rates. The change in pension value included qualified benefits for 2015 and 2016, whereas 2017 is only the change in the non-qualified pension value.
(5) Mr. Fink’s personal benefits for 2017 include an annual vehicle allowance of $13,000 and $14,026 in matching contributions made by CNX under its 401(k) plan.
Narrative Disclosure to Summary Compensation Table and Additional Narrative Disclosure
CNX provides compensation to its executives in the form of base salaries, annual cash incentive awards, long-term equity incentive awards and participation in various employee benefits plans and arrangements, as further described in the section titled “Retirement, Health, Welfare and Additional Benefits” below.
As explained above, for 2017 Messrs. Lewis and Khani devoted a portion of their overall working time to our business, and the compensation these named executives receive in relation to their services for us did not comprise a material amount of their total compensation. In addition, except for the fixed administrative support fee that our general partner pays to CNX and Noble Energy pursuant to the terms of the omnibus agreement, we did not pay or reimburse any compensation amounts to or for Messrs. Lewis and Khani. During the periods presented, Mr. Fink devoted substantially all of his working time to matters relating to our business, and all of our other executive officers devoted substantially less than a majority of their working time to matters relating to our business.
98
The following sets forth a more detailed explanation of the elements of CNX’s compensation programs as they relate to Mr. Fink.
Base Salary.
Base salary is designed to provide a competitive fixed rate of pay recognizing employees’ different levels of responsibility and performance. In setting an executive’s base salary, CNX considers factors including, but not limited to, external market data, the internal worth and value assigned to the executive’s role and responsibilities at CNX, and the named executive’s skills and performance. As of December 31, 2017, Mr. Fink’s annual base salary was $235,353.
2017 Short Term Incentive Compensation Plan
The 2017 Short Term Incentive Compensation Plan (“STIC”) was designed to deliver cash awards when CNX Midstream and the employees who devote substantially all of their time to us and our general partner are successful in meeting or exceeding the established performance targets, and to pay less, or nothing at all, when we fall short of these targets. The STIC program was designed to provide incentive compensation that is comparable to compensation provided by companies with which we compete for talent.
The Board adopted the 2017 STIC plan to align our employees’ interests with the key goals of generating earnings as measured by the Partnership’s consolidated earnings before interest, taxes, depreciation and amortization (“EBITDA”). The consolidated EBITDA component of the STIC program has a potential payout of 100% to 60%, with 100% awarded if our consolidated EBITDA budget goal was achieved. The 60% payout would be awarded if we achieved 94% of our consolidated EBITDA budget goal. Nothing would be awarded if we achieved less than 94% of our consolidated EBITDA goal. In addition, the awards were subject to deductions for safety exceptions and environmental incidents, which are set forth below:
| Severity Level | Safety Deduction | Environmental Deduction |
| Level 1 | 1% | —% |
| Level 2 | 1% | —% |
| Level 3 | 2% | 1% |
| Level 4 | 3% | 2% |
| Level 5 | 4% | 3% |
The 2017 STIC plan also had a bonus opportunity based on the achievement of EBITDA attributable to general and limited partner ownership interests. If achieved, 50% of the bonus opportunity would be based on employees’ individual STIC opportunity percentage and 50% would be based on individual performance evaluations.
For the year ended December 31, 2017, Mr. Fink had a target bonus of 35% of his annual base salary, with a potential payout up to 200% of target based on the Partnership’s performance metrics outlined above For 2017, CNX paid a cash bonus to Mr. Fink at a level of 150% of his target award level, and he was awarded $98,643 under the STIC plan and an estimated additional $20,593, which is to be finalized later in February 2018 based on based on Mr. Fink’s individual performance evaluation score.
Long-Term Equity-Based Compensation Awards.
Beginning in 2015, Mr. Fink’s long-term incentive awards include phantom units granted under CNX Midstream’s 2014 Long-Term Incentive Plan (the “LTIP”). The following provides additional information about Mr. Fink’s outstanding equity awards in CNX Midstream Partners LP as of December 31, 2017.
| Unit Awards | ||||
| Name | Number of Units That Have Not Vested | Market Value of Units That Have Not Vested | ||
| (#) | ($) | |||
| Joseph M. Fink, Former Chief Operating Officer | 17,663 (1) | 296,209 (2) | ||
(1) Phantom units granted on January 20, 2015, February 17, 2016 and February 16, 2017 (and related distribution equivalent rights, which entitle the recipient to receive additional phantom units on a quarterly basis with a value equal to the per unit cash distribution paid in respect of such quarter), which vest in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(2) The market value for the phantom units was determined by multiplying the closing market price for the Partnership’s common units on the last trading day of 2017 ($16.77) by the number of units underlying the phantom unit.
99
Our executive officers have received and may continue to receive equity or equity-based awards in CNX and Noble Energy, as applicable, under their respective equity compensation programs. The following provides additional information about Mr. Fink’s outstanding equity awards in CNX as of December 31, 2017.
| Outstanding Equity Awards for CNX at December 31, 2017 | |||||||
| Option Awards | |||||||
| Name | Number of Securities Underlying Unexercised Options | Option Exercise Price | Option Expiration Date | ||||
| (Exercisable) | |||||||
| (#) | ($) | ||||||
| Joseph M. Fink, Former Chief Operating Officer | 1,222 (1) | 24.16 | 2/17/2019 | ||||
732 (2) | 43.72 | 2/19/2020 | |||||
1,179 (3) | 42.09 | 2/23/2021 | |||||
1,678 (4) | 31.29 | 1/26/2022 | |||||
(1) Options granted February 17, 2009 that vested and became exercisable in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(2) Options granted February 16, 2010 that vested and became exercisable in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(3) Options granted February 23, 2011 that vested and became exercisable in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
(4) Options granted January 26, 2012 that vested and became exercisable in three equal annual installments (subject to rounding) beginning on the first anniversary of the grant date.
Retirement, Health, Welfare and Additional Benefits.
Our former executive officers were eligible to participate in the employee benefit plans and programs that CNX, CONSOL Energy Inc., and Noble Energy offered to their respective employees, subject to the terms and eligibility requirements of those plans. Our former executive officers, including Mr. Fink, participated in these programs and CNX, CONSOL Energy Inc. and Noble Energy, as applicable, were responsible for all of the benefits provided thereunder for their respective employees.
With respect to the benefits offered by CNX as they relate to Mr. Fink, CNX employees are eligible to participate in a variety of employee benefit plans and programs which include a 401(k) savings plan and a supplemental defined contribution retirement plan that provides benefits to executive officers and key employees, including Mr. Fink, in excess of IRS imposed limits under the 401(k) savings plan.
Severance and Change in Control Programs.
CNX and CNX Gathering have entered into change in control severance agreements with Mr. Fink, pursuant to which Mr. Fink would receive certain severance payments and benefits if his employment is terminated or constructively terminated after, or in connection with, a change in control of either CNX or CNX Gathering and subject to his executing a satisfactory release of claims. Under these circumstances, Mr. Fink would receive a lump sum cash payment equal to 1.5 times his base pay plus incentive pay and would also receive a pro-rated bonus for the year of termination, continuation of employee benefits (including the value attributable to continued participation in pension and similar benefit plans) for a period of 18 months following termination, and outplacement assistance. In addition, all of Mr. Fink’s equity awards would accelerate and vest in connection with a change in control.
Absent a change in control of CNX or CNX Gathering, upon an involuntary termination, (i) under CNX’s severance pay plan for salaried employees, Mr. Fink would be entitled to severance in an amount equal to one week of compensation for each completed full year of continuous service, up to a maximum of 25 weeks of compensation and (ii) under CNX’s supplemental defined contribution retirement plan, Mr. Fink would be entitled to a contribution for the year in which the termination occurred (this benefit is also applicable upon death, disability and other similar circumstances). In addition, Mr. Fink would generally be entitled to accelerated or continued vesting of CNX stock awards in the event of a termination without cause, death, “incapacity retirement” (which requires attaining age 40 and ten years of service and being deemed disabled and entitled to receive a Social Security disability benefit) or disability, provided that such vesting is only on a pro-rated basis through the date of termination in the event of disability if such event is not also an “incapacity retirement.”
100
Severance costs would be allocated to us in accordance with the terms of the omnibus agreement, which, for Mr. Fink, would initially result in us being responsible for up to 100% of the applicable severance costs.
Mr. Fink did not receive any payment or benefits under these arrangements during 2017.
Compensation of Our Directors
The officers or employees of our general partner or of CNX, CONSOL Energy Inc. or Noble Energy who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers or employees of our general partner or of CNX, CONSOL Energy Inc. or Noble Energy (our “non-employee directors”) receive cash and equity-based compensation for their services as directors. During 2017, our general partner’s non-employee director compensation program consists of the following:
| • | an annual retainer of $60,000; |
| • | an additional annual retainer of $20,000 for service as the chair of the audit committee |
| • | additional payments, as necessary, as consideration for service incurred per transaction reviewed by the conflicts committee; and |
| • | an annual equity-based award granted under the LTIP, having a value as of the grant date of approximately $80,000. |
Non-employee directors also receive reimbursement for out-of-pocket expenses they incur in connection with attending meetings of the board of directors or its committees. Each director will be indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law.
The following table provides information regarding the compensation earned by our non-employee directors during the year ended December 31, 2017.
| Name | Fees Earned or Paid in Cash(4) | Equity Awards (1) | Total | ||||||
| Angela A. Minas | $ | 122,500 | $ | 80,000 | $ | 202,500 | |||
Raymond T. Betler (2) | $ | 42,000 | $ | 20,000 | $ | 62,000 | |||
John D. Chandler (3) | $ | 46,500 | $ | — | $ | 46,500 | |||
| John E. Jackson | $ | 87,000 | $ | 80,000 | $ | 167,000 | |||
(1) | The values set forth in this column are based on the aggregate grant date fair value of awards computed in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 718, “Compensation-Stock Compensation” (“FASB ASC Topic 718”). The grant date fair value is computed based upon the closing price of our common units on the date of grant. The values reflect the awards’ fair market value at the date of grant, and do not correspond to the actual value that will be recognized by the directors. As of December 31, 2017, the number of phantom units held by our current non-employee directors in the aggregate was 8,279. |
| (2) | Effective October 18, 2017, Mr. Betler was appointed to the board of directors of our general partner. Accordingly, the fees he earned and equity award that he received were prorated for 2017 to reflect his actual length of service during the year. |
| (3) | Effective August 31, 2017, Mr. Chandler resigned from the board of directors of our general partner. Accordingly, the fees he earned during 2017 were prorated to reflect his actual length of service during the year, and any equity awards granted during the year were forfeited on his date of resignation. |
| (4) | Amounts include additional payments of $42,500 to Ms. Minas and $27,000 to each of Messrs. Betler and Jackson that were earned in 2017, but paid in 2018, for their review of two specific matters that involved conflicts of interest in accordance with the terms of our partnership agreement. |
101
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS |
The following table sets forth, as of February 1, 2018, the beneficial ownership of common units of CNX Midstream Partners LP and held by:
| • | each unitholder known by us to beneficially hold 5% or more of our outstanding units; |
| • | each director or director nominee of our general partner; |
| • | each named executive officer of our general partner; and |
| • | all of the directors, director nominee and named executive officers of our general partner as a group. |
In addition, our general partner owns a 2% general partner interest in us and all of our incentive distribution rights.
Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the following table have sole voting and sole investment power with respect to all units beneficially owned by them, subject to community property laws where applicable.
Name of Beneficial Owner(1) | Common Units Beneficially Owned | Percentage of Common Units Beneficially Owned(2) | ||||
CNX Gas Company LLC(3) | 21,692,198 | 34.1 | % | |||
| NBL Midstream, LLC | 21,692,198 | 34.1 | % | |||
(1) Unless otherwise indicated, the address for all beneficial owners in this table is c/o CNX Midstream GP LLC, CNX Center, 1000 CONSOL Energy Drive, Canonsburg, Pennsylvania 15317.
(2) Based on 63,591,740 common units outstanding as of February 1, 2018.
(3) CNX Gas Company LLC owns a 100% membership interest in CNX Gathering LLC, which owns 100% of the membership interests in our general partner. CNX Gas Company LLC is a wholly owned subsidiary of CNX Resources Corporation.
Directors/Named Executive Officers (1) | Total Common Units Beneficially Owned (2)(3) | Percentage of Common Units Beneficially Owned | ||
| Nicholas J. DeIuliis | 14,000 | * | ||
| Donald W. Rush | 300 | * | ||
| Timothy C. Dugan | 2,500 | * | ||
| Brian R. Rich | 1,718 | * | ||
| Stephen W. Johnson | 7,000 | * | ||
| Angela A. Minas | 36,488 | * | ||
| Raymond T. Betler | 1,285 | * | ||
| John E. Jackson | 20,887 | * | ||
| All Directors and Executive Officers as a group (8 persons) | 84,178 | * | ||
* Less than 1%.
1) Unless otherwise indicated, the address for all beneficial owners in this table is c/o CNX Midstream GP LLC, CNX Center, 1000 CONSOL Energy Drive, Canonsburg, Pennsylvania 15317.
(2) This column reflects the number of common units held of record or owned through a bank, broker or other nominee.
(3) For Messrs. Rich, Betler and Jackson and Ms. Minas, this column includes phantom units, including accrued distributions, to be settled in CNXM common units within 60 days of February 1, 2018, in the following amounts: Mr. Rich, 1,567 units; Mr. Betler, 1,285 units; Mr. Jackson, 3,497 units and Ms. Minas, 3,497 units.
102
The following table sets forth, as of February 1, 2018, the number of shares of CNX common stock beneficially owned by each of the directors and named executive officers of our general partner and all of the directors and named executive officers of our general partner as a group. The percentage of total shares is based on 223,760,085 shares outstanding as of February 1, 2018. Amounts shown below include options that are currently exercisable or that may become exercisable within 60 days of February 1, 2018 and the shares underlying deferred stock units and the shares underlying restricted stock units that will be settled within 60 days of February 1, 2018. Unless otherwise indicated, the named person has the sole voting and dispositive powers with respect to the shares of CNX common stock set forth opposite such person’s name.
| Directors/Named Executive Officers | Total Common Stock Beneficially Owned (1) | Percent of Total Outstanding | ||
| Nicholas J. DeIuliis | 1,353,312 | * | ||
| Donald W. Rush | 65,066 | * | ||
| Timothy C. Dugan | 190,359 | * | ||
| Brian R. Rich | 1,462 | * | ||
| Stephen W. Johnson | 418,814 | * | ||
| Angela A. Minas | — | * | ||
| Raymond T. Betler | — | * | ||
| John E. Jackson | — | * | ||
| All Directors and Executive Officers as a group (8 persons) | 2,029,013 | * | ||
* Less than 1%.
(1) Includes shares issuable pursuant to options that are currently exercisable (or may become exercisable within 60 days of February 1, 2018) as follows: Mr. DeIuliis, 637,988; Mr. Rush, 3,313; Mr. Dugan, 61,876 and Mr. Johnson, 211,549.
Securities Authorized for Issuance under Equity Compensation Plans
The following table summarizes information regarding the number of common units that are available for issuance under our LTIP as of December 31, 2017.
| Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | Weighted-average exercise price of outstanding options, warrants and rights (b) | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)(c) | ||||||
| Equity compensation plans approved by security holders | 33,885 | — | 5,766,115 | ||||||
| Equity compensation plans not approved by security holders | — | — | — | ||||||
| Total | 33,885 | — | 5,766,115 | ||||||
103
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
As of February 1, 2018, CNX owns 21,692,198 common units, representing an approximate 33.4% limited partner interest and a 2% general partner interest in us and all of our incentive distribution rights. As of February 1, 2018, Noble Energy owns 21,692,198 common units, representing an approximate 33.4% limited partner interest.
Distributions and Payments to Our General Partner and Its Affiliates
The following summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and liquidation of us. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Formation Stage
The consideration received by our general partner and its affiliates for our formation:
| • | 2% general partner interest; and |
| • | 98% limited partner interest. |
IPO Stage
The consideration received by our general partner and its affiliates in connection with the IPO for the contribution to us of a 75% controlling interest in our Anchor Systems, a 5% controlling interest in our Growth Systems and a 5% controlling interest in our Additional Systems:
| • | 9,038,121 common units; |
| • | 29,163,121 subordinated units; |
| • | a 2% general partner interest in us; |
| • | the incentive distribution rights; and |
| • | a distribution of approximately $408.0 million from the net proceeds of the IPO. |
Post-IPO Operational Stage
Distributions of available cash to our general partner and its affiliates
| • | We will generally make cash distributions of 98% to the unitholders pro rata, including CNX, and 2% to our general partner, assuming it makes any capital contributions necessary to maintain its 2% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner will entitle our general partner to increasing percentages of the distributions, up to 48% of the distributions above the highest target distribution level. |
Payments to our general partner and its affiliates
| • | Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our omnibus agreement and operational services agreement, our general partner determines the amount of these expenses and such determinations must be made in good faith under the terms of our partnership agreement. Under our omnibus agreement, we will reimburse our Sponsor for expenses incurred by our Sponsor and its affiliates in providing certain general and administrative services to us, including the provision of executive management services by certain officers of our general partner. The expenses of other employees will be allocated to us based on the amount of time actually spent by those employees on our business. These reimbursable expenses also include an allocable portion of the compensation and benefits of employees and executive officers of other affiliates of our general partner who provide services to us. We will also reimburse our Sponsor for any additional out-of-pocket costs and expenses incurred by our Sponsor and its affiliates in providing general and administrative services to us. The costs and expenses for which we are required to reimburse our general partner and its affiliates are not subject to any caps or other limits. |
| • | Under our operational services agreement, we will pay our Sponsor for any direct costs actually incurred by our Sponsor and its affiliates in providing our gathering pipelines and dehydration, treating and compressor stations and facilities with certain maintenance, operational, administrative and construction services. |
104
Withdrawal or removal of our general partner
| • | If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights 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 our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances. |
Agreements with Our Sponsor
We and other parties are parties to various agreements with CNX and certain of its affiliates. These agreements address, among other things, the provision of services, the acquisition of assets and the assumption of liabilities by us and our subsidiaries. While not the result of arm’s-length negotiations, we believe that the terms of each of the agreements with our Sponsor and its affiliates are, and specifically intend the rates to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.
For a description of our related party transactions, see Item 8, Note 5 - Related Party, which is incorporated herein by reference.
Director Independence
Our disclosures in Item 10. “Directors, Executive Officers and Corporate Governance” are incorporated herein by reference.
Procedures for Review, Approval and Ratification of Related Person Transactions
The board of directors of our general partner has adopted a code of business conduct and ethics that provides that the board of directors of our general partner or its authorized committee will review on at least a quarterly basis all transactions with related persons that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a transaction with a related person and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.
The code of business conduct and ethics provides that, in determining whether or not to recommend the initial approval or ratification of a transaction with a related person, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.
105
| ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
Ernst & Young LLP served as the Partnership’s independent registered public accounting firm for the years ended December 31, 2017 and 2016. The following table sets forth the aggregate fees billed by Ernst & Young LLP for the services they provided to us during each of the last two fiscal years.
| Year Ended December 31, | |||||||
| (in thousands) | 2017 | 2016 | |||||
| Audit fees | $ | 389 | $ | 382 | |||
| Audit-related fees | 15 | — | |||||
| Tax fees | — | — | |||||
| All other fees | — | — | |||||
| Total fees | $ | 404 | $ | 382 | |||
Audit fees include fees for the audit of the Partnership’s annual financial statements on Form 10-K, reviews of the Partnership’s financial statements included in the Partnership’s quarterly reports on Form 10-Q, and services that are normally provided in connection with regulatory filings, including consents.
Pre-approval of audit and permissible non-audit services
The audit committee pre-approves all audit and permissible non-audit services provided by the independent registered public accounting firm. These services may include audit services, audit-related services, tax services and other services. The audit committee has adopted a policy for the pre-approval of services provided by the independent registered public accounting firm.
All of the services performed by Ernst & Young LLP in 2017 and 2016 were pre-approved in accordance with the pre-approval policy and procedures adopted by the audit committee. Proposed services may require specific pre-approval by the audit committee (e.g., annual financial statement audit services) or alternatively, may be pre-approved without consideration of specific case-by-case services. In either case, the audit committee must consider whether such services are consistent with SEC rules on auditor independence.
Under the forgoing policy, the Partnership’s independent accounting firm is not allowed to perform any service which may have the effect of jeopardizing the registered public accountant’s independence. Without limiting the foregoing, the independent accounting firm shall not be retained to perform the following:
| • | Bookkeeping or other services related to the accounting records or financial statements |
| • | Financial information systems design and implementation |
| • | Appraisal or valuation services, fairness opinions or contribution-in-kind reports |
| • | Actuarial services |
| • | Internal audit outsourcing services |
| • | Management functions |
| • | Human resources functions |
| • | Broker-dealer, investment adviser or investment banking services |
| • | Legal services |
| • | Expert services unrelated to the audit |
| • | Prohibited tax services |
106
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) and (2) Financial Statements and Schedules.
Our consolidated financial statements are included in Part II, Item 8 of this Annual Report on Form 10-K. Financial statement schedules required under SEC rules but not included in this Annual Report on Form 10-K are omitted because they are not required, not applicable or the required information is contained in the consolidated financial statements or notes thereto.
(a)(3) Exhibits.
In reviewing any agreements incorporated by reference in this Annual Report on Form 10-K or filed with this Form 10-K, please remember that such agreements are included to provide information regarding their terms. They are not intended to be a source of financial, business or operational information about the Partnership. The representations, warranties and covenants contained in these agreements are made solely for purposes of the agreements and are made as of specific dates; are solely for the benefit of the parties; may be subject to qualifications and limitations agreed upon by the parties in connection with negotiating the terms of the agreements, including being made for the purpose of allocating contractual risk between the parties instead of establishing matters as facts; and may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors or security holders. Investors and security holders should not rely on the representations, warranties and covenants or any description thereof as characterizations of the actual state of facts or condition of the Partnership, in connection with acquisition agreements, of the assets to be acquired. Moreover, information concerning the subject matter of the representations, warranties and covenants may change after the date of the agreements. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.
| Incorporated by Reference | |||||||||||
Exhibit Number | Exhibit Description | Form | SEC File Number | Exhibit | Filing Date | ||||||
| 3.1* | S-1 | 333-198352 | 3.1 | 8/25/2014 | |||||||
| 3.2* | 8-K | 001-36635 | 3.1 | 1/3/2018 | |||||||
| 3.3* | 8-K | 001-36635 | 3.2 | 1/3/2018 | |||||||
| 10.1* | 8-K | 001-36635 | 10.1 | 10/3/2014 | |||||||
| 10.2* | 8-K | 001-36635 | 10.2 | 10/3/2014 | |||||||
| 10.3* | 8-K | 001-36635 | 10.1 | 12/7/2016 | |||||||
| 10.4* | 8-K | 001-36635 | 10.3 | 12/7/2016 | |||||||
| 10.5* | 8-K | 001-36635 | 10.2 | 12/7/2016 | |||||||
| 10.6* | 8-K | 001-36635 | 10.2 | 1/3/2018 | |||||||
107
| 10.7* | 8-K | 001-36635 | 10.6 | 10/3/2014 | |||||||
| 10.8*# | 8-K | 001-36635 | 10.7 | 10/3/2014 | |||||||
| 10.9* | 8-K | 001-36635 | 10.8 | 10/3/2014 | |||||||
| 10.10† | |||||||||||
| 10.11*# | 8-K | 001-36635 | 10.1 | 1/22/2015 | |||||||
10.12*#† | |||||||||||
| 10.13* | 8-K | 001-36635 | 2.1 | 11/16/2016 | |||||||
| 10.14* | 8-K | 001-36635 | 10.1 | 1/3/2018 | |||||||
| 10.15† | |||||||||||
| 21.1† | |||||||||||
| 23.1† | |||||||||||
| 31.1† | |||||||||||
| 31.2† | |||||||||||
| 32.1† | |||||||||||
| 32.2† | |||||||||||
| 101.INS† | XBRL Instance Document. | ||||||||||
| 101.SCH† | XBRL Taxonomy Extension Schema Document. | ||||||||||
| 101.CAL† | XBRL Taxonomy Extension Calculation Linkbase Document. | ||||||||||
| 101.DEF† | XBRL Taxonomy Extension Definition Linkbase Document. | ||||||||||
| 101.LAB† | XBRL Taxonomy Extension Labels Linkbase Document. | ||||||||||
| 101.PRE† | XBRL Taxonomy Extension Presentation Linkbase Document. | ||||||||||
* Incorporated by reference into this Annual Report on Form 10-K as indicated.
† Filed herewith.
# Compensatory plan or arrangement.
ITEM 16. FORM 10-K SUMMARY
None.
108
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.
Dated: February 7, 2018
| CNX MIDSTREAM PARTNERS LP | |||
| By: CNX MIDSTREAM GP LLC, its general partner | |||
| By: | /S/ NICHOLAS J. DEIULIIS | ||
| Nicholas J. DeIuliis | |||
Chief Executive Officer and Director (Principal Executive Officer) | |||
Each person whose signature appears below does hereby constitute and appoint Nicholas J. DeIuliis and Donald W. Rush, and each of them, either one of whom may act without joinder of the other, as his or her true and lawful attorney or attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any or all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each, and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, and each of them, or the substitute or substitutes of any or all of them, may lawfully do or cause to be done by virtue hereof.
109
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 indicated on February 7, 2018.
| By: | /S/ NICHOLAS J. DEIULIIS | ||
| Nicholas J. DeIuliis | |||
Chief Executive Officer and Chairman of the Board (Principal Executive Officer) | |||
| By: | /S/ DONALD W. RUSH | ||
| Donald W. Rush | |||
Chief Financial Officer and Director (Principal Financial Officer) | |||
| By: | /S/ TIMOTHY C. DUGAN | ||
| Timothy C. Dugan | |||
| Chief Operating Officer and Director | |||
| By: | /S/ BRIAN R. RICH | ||
| Brian R. Rich | |||
Chief Accounting Officer (Principal Accounting Officer) | |||
| By: | /S/ STEPHEN W. JOHNSON | ||
| Stephen W. Johnson | |||
| Director | |||
| By: | /S/ ANGELA A. MINAS | ||
| Angela A. Minas | |||
| Director | |||
| By: | /S/ RAYMOND T. BETLER | ||
| Raymond T. Betler | |||
| Director | |||
| By: | /S/ JOHN E. JACKSON | ||
| John E. Jackson | |||
| Director | |||
110