UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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Form 10-K
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| [X] | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20152017
or
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| [ ] | 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: 001-35081
Kinder Morgan, Inc.
(Exact name of registrant as specified in its charter)
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| Delaware | | 80-0682103 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
1001 Louisiana Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices) (zip code)
Registrant’s telephone number, including area code: 713-369-9000
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Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | Name of each exchange on which registered |
| Class P Common Stock | New York Stock Exchange |
Warrants to Purchase Class P Common Stock | New York Stock Exchange |
Depositary Shares, each representing a 1/20th interest in a share of 9.75% Series A Mandatory Convertible Preferred Stock | New York Stock Exchange |
| 1.500% Senior Notes due 2022 | New York Stock Exchange |
| 2.250% Senior Notes due 2027 | 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 of 1933. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes o No þ
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 þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K(§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o
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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes o No þ
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 30, 20152017 was approximately $69,734,282,635.$36,830,209,065. As of February 11, 2016,8, 2018, the registrant had2,231,555,9762,206,066,684 Class P shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2018, are incorporated into PART III, as specifically set forth in PART III.
KINDER MORGAN, INC. AND SUBSIDIARIES TABLE OF CONTENTS
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KINDER MORGAN, INC. AND SUBSIDIARIES TABLE OF CONTENTS (continued)
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KINDER MORGAN, INC. AND SUBSIDIARIES GLOSSARY
Company Abbreviations
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| Calnev | = | Calnev Pipe Line LLC | KMGP | = | Kinder Morgan G.P., Inc. |
| CIG | = | Colorado Interstate Gas Company, L.L.C. | KMI | = | Kinder Morgan, Inc. and its majority-owned and/or |
| Copano | = | Copano Energy, L.L.C. | | | controlled subsidiaries |
| CPGPL | = | Cheyenne Plains Gas Pipeline Company, L.L.C. | KML | = | Kinder Morgan Canada Limited and its majority- |
| EagleHawk | = | EagleHawk Field Services LLC | | | owned and/or controlled subsidiaries |
| Elba Express | = | Elba Express Company, L.L.C. | KMLP | = | Kinder Morgan Louisiana Pipeline LLC |
| ELC | = | Elba Liquefaction Company, L.L.C. | KMP | = | Kinder Morgan Energy Partners, L.P. and its |
| EP | = | El Paso Corporation and its majority-owned and | | | majority-owned and controlled subsidiaries |
| | controlled subsidiaries | KMR | = | Kinder Morgan Management, LLC |
| EPB | = | El Paso Pipeline Partners, L.P. and its majority- | MEP | = | Midcontinent Express Pipeline LLC |
| | owned and controlled subsidiaries | NGPL | = | Natural Gas Pipeline Company of America LLC |
| EPNG | = | El Paso Natural Gas Company, L.L.C. | Ruby | = | Ruby Pipeline Holding Company, L.L.C. |
| EPPOC | = | El Paso Pipeline Partners Operating Company, | SFPP | = | SFPP, L.P. |
| | L.L.C. | SLNG | = | Southern LNG Company, L.L.C. |
| FEP | = | Fayetteville Express Pipeline LLC | SNG | = | Southern Natural Gas Company, L.L.C. |
| Hiland | = | Hiland Partners, LP | TGP | = | Tennessee Gas Pipeline Company, L.L.C. |
| KinderHawk | = | KinderHawk Field Services LLC | TMEP | = | Trans Mountain Expansion Project |
KMCO2 | = | Kinder Morgan CO2 Company, L.P. |
CIG | = | Colorado Interstate Gas Company, L.L.C. | KMEP | = | Kinder Morgan Energy Partners, L.P. |
Copano | = | Copano Energy, L.L.C. | KMGP | = | Kinder Morgan G.P., Inc. |
CPG | = | Cheyenne Plains Gas Pipeline Company, L.L.C. | KMI | = | Kinder Morgan Inc. and its majority-owned and/or |
EagleHawk | = | EagleHawk Field Services LLC | | | controlled subsidiaries |
Eagle Ford | = | Eagle Ford Gathering LLC | KMLP | = | Kinder Morgan Louisiana Pipeline LLC |
Elba Express | = | Elba Express Company, L.L.C. | KMP | = | Kinder Morgan Energy Partners, L.P. and its |
ELC | = | Elba Liquefaction Company, L.L.C. | | | majority-owned and controlled subsidiaries |
EP | = | El Paso Corporation and its its majority-owned and | KMR | = | Kinder Morgan Management, LLC |
| | controlled subsidiaries | MEP | = | Midcontinent Express Pipeline LLC |
EPB | = | El Paso Pipeline Partners, L.P. and its majority- | NGPL | = | Natural Gas Pipeline Company of America LLC |
| | owned and controlled subsidiaries | SFPP | = | SFPP, L.P. |
EPNG | = | El Paso Natural Gas Company, L.L.C. | SLNG | = | Southern LNG Company, L.L.C. |
EPPOC | = | El Paso Pipeline Partners Operating Company, | SNG | = | Southern Natural Gas Company, L.L.C. |
| | L.L.C. | TGP | = | Tennessee Gas Pipeline Company, L.L.C. |
FEP | = | Fayetteville Express Pipeline LLC | WIC | = | Wyoming Interstate Company, L.L.C. |
HilandKMEP | = | HilandKinder Morgan Energy Partners, LPL.P. | WYCO | = | WYCO Development L.L.C. |
KinderHawk | = | KinderHawk Field Services LLC | | | |
| Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries. |
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| Common Industry and Other Terms |
/d2017 Tax | | | IPO | = | per dayInitial Public Offering |
| Reform | = | The Tax Cuts & Jobs Act of 2017 | LIBOR | = | London Interbank Offered Rate |
| /d | = | per day | LLC | = | limited liability company |
| AFUDC | = | allowance for funds used during construction | LLCLNG | = | limited liability companyliquefied natural gas |
| BBtu | = | billion British Thermal Units | LNGMBbl | = | liquefied natural gasthousand barrels |
| Bcf | = | billion cubic feet | MBblMDth | = | thousand barrelsdekatherms |
| CERCLA | = | Comprehensive Environmental Response, | MDthMLP | = | thousand dekathermsmaster limited partnership |
| | | Compensation and Liability Act | MLPMMBbl | = | master limited partnershipmillion barrels |
| C$ | = | Canadian dollars | MMcf | = | million cubic feet |
CO2 | = | carbon dioxide or our CO2 business segment | MMBblNEB | = | million barrelsNational Energy Board |
| CPUC | = | California Public Utilities Commission | MMcfNGL | = | million cubic feetnatural gas liquids |
| DCF | = | distributable cash flow | NEBNYMEX | = | National Energy BoardNew York Mercantile Exchange |
| DD&A | = | depreciation, depletion and amortization | NGLNYSE | = | natural gas liquidsNew York Stock Exchange |
| DGCL | = | General Corporation Law of the state of Delaware | NYMEXOTC | = | New York Mercantile Exchangeover-the-counter |
| Dth | = | dekatherms | NYSEPHMSA | = | New York Stock ExchangeUnited States Department of Transportation |
| EBDA | = | earnings before depreciation, depletion and | OTC | = | over-the-counterPipeline and Hazardous Materials Safety |
| | | amortization expenses, including amortization of | PHMSA | = | United States Department of TransportationAdministration |
| | | excess cost of equity investments | U.S. | = | Pipeline and Hazardous Materials SafetyUnited States of America |
| EPA | = | United States Environmental Protection Agency | SEC | = | AdministrationUnited States Securities and Exchange |
| FASB | = | Financial Accounting Standards Board | SEC | = | United States Securities and ExchangeCommission |
| FERC | = | Federal Energy Regulatory Commission | | | Commission |
FTC | = | Federal Trade Commission | TBtu | = | trillion British Thermal Units |
| FTC | = | Federal Trade Commission | WTI | = | West Texas Intermediate |
| GAAP | = | United States Generally Accepted Accounting | WTI | = | West Texas Intermediate |
| | | Principles | | | |
| When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch. |
Information Regarding Forward-Looking Statements
This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,“outlook,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or pay dividends, are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in our forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or accurately predict. Specific factors that could cause actual results to differ from those in our forward-looking statements include:
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| • | the extent of volatility in prices for and resulting changes in supply of and demand for NGL, refined petroleum products, oil, CO2, natural gas, electricity, coal, steel and other bulk materials and chemicals and certain agricultural products in North America; |
economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;
changes in our tariff rates required by the FERC, the CPUC, Canada’s NEB or another regulatory agency;
our ability to acquire new businesses and assets and integrate those operations into our existing operations, and make cost-saving changes in operations, particularly if we undertake multiple acquisitions in a relatively short period of time, as well as our ability to expand our facilities;
our ability to safely operate and maintain our existing assets and to access or construct new pipeline, gas processing, gas storage and NGL fractionation capacity;
our ability to attract and retain key management and operations personnel;
difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines;
shut-downs or cutbacks at major refineries, petrochemical or chemical plants, natural gas processing plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us;
changes in crude oil and natural gas production (and the NGL content of natural gas production) from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the shale plays in North Dakota, Oklahoma, Ohio, Pennsylvania and Texas, and the U.S. Rocky Mountains and the Alberta, Canada oil sands;
changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may increase our compliance costs, restrict our ability to provide or reduce demand for our services, or otherwise adversely affect our business;
interruptions of operations at our facilities due to natural disasters, damage by third-parties, power shortages, strikes, riots, terrorism (including cyber attacks), war or other causes;
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| • | the uncertainty inherent in estimating future oil, natural gas, and CO2 production or reserves that we may experience; |
issues, delays or stoppage associated with major expansion projects, including TMEP;
regulatory, environmental, political, legal, operational and geological uncertainties that could affect our ability to complete our expansion projects on time and on budget;budget or at all;
the timing and success of our business development efforts, including our ability to renew long-term customer contracts;contracts at economically attractive rates;
the ability of our customers and other counterparties to perform under their contracts with us;
competition from other pipelines or other forms of transportation;
changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities;
changes in tax law;laws;
our ability to access external sources of financing in sufficient amounts and on acceptable terms to the extent needed to fund acquisitions of operating businesses and assets and expansions of our facilities;
our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at a competitive disadvantage compared to our competitors that have less debt, or have other adverse consequences;
our ability to obtain insurance coverage without significant levels of self-retention of risk;
acts of nature,natural disasters, sabotage, terrorism (including cyber attacks) or other similar acts or accidents causing damage to our properties greater than our insurance coverage limits;
possible changes in our and our subsidiariessubsidiaries’ credit ratings;
conditions in the capital and credit markets, inflation and fluctuations in interest rates;
political and economic instability of the oil producing nations of the world;
national, international, regional and local economic, competitive and regulatory conditions and developments;developments, including the effects of any enactment of import or export duties, tariffs or similar measures;
our ability to achieve cost savings and revenue growth;
foreign exchange fluctuations;
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| • | the extent of our success in developing and producing CO2 and oil and gas reserves, including the risks inherent in development drilling, well completion and other development activities; |
engineering and mechanical or technological difficulties that we may experience with operational equipment, in well completions and workovers,work-overs, and in drilling new wells; and
unfavorable results of litigation and the outcome of contingencies referred to in Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that any of the actions, events or results of theexpressed in forward-looking statements will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements.
See Item 1A “Risk Factors” for a more detailed descriptionAdditional discussion of these and other factors that may affect our forward-looking statements.statements appears elsewhere in this report, including in Item 1A “Risk Factors,” Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk-Energy Commodity Market Risk.” In addition, there is a general level of uncertainty regarding the extent to which potential positive or negative changes to fiscal, tax and trade policies may impact us and those with whom we do business. It is not possible at this time to predict the extent of any such impact. When considering forward-looking statements, oneyou should keep in mind the risk factors described in Item 1A “Risk Factors.” The riskthis section and the other sections referenced above. These factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation, other than as required by applicable law, and described below under Items 1 and 2 “Business and Properties—(a) General Development of Business—Recent Developments—2016 Outlook”,2018 Outlook,” to update the above list or to announce publicly the result of any revisions to any of theour forward-looking statements to reflect future events or developments.
PART I
Items 1 and 2. Business and Properties.
We are one of the largest energy infrastructure companycompanies in North America. We own an interest in or operate approximately 84,00085,000 miles of pipelines and approximately 180 terminals (includes 15 terminals acquired in our February 2016 BP Products North America Inc. (BP) transaction). For more information about the acquisition, see Note 3 “Acquisitions and Divestitures” to our consolidated financial statements.152 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate,
CO2 and other products, and our terminals transload and store liquid commodities including petroleum products, ethanol and chemicals, and handle suchbulk products, as coal,including petroleum coke, steel and steel.coal. We are also thea leading producer and transporter of CO2, which is utilizedwe and others utilize for enhanced oil recovery projects primarily in North America.the Permian basin. Our common stock trades on the NYSE under the symbol “KMI.”
(a) General Development of Business
Organizational Structure
On November 26, 2014, we completedWe are a Delaware corporation and our acquisition, pursuant to three separate merger agreements, of all of the outstanding common units of Kinder Morgan Energy Partners, L.P. and El Paso Pipeline Partners, L.P. and all of the outstanding shares of Kinder Morgan Management, LLC that we did not already own. The transactions, valued at approximately $77 billion, are referred to collectively as the “Merger Transactions.”stock has been publicly traded since February 2011.
As we controlled eachSale of KMP, KMR and EPB before and continued to control each of them after the Merger Transactions, the changesApproximate 30% Interest in our ownershipCanadian Business
On May 30, 2017, our indirectly owned subsidiary, KML, completed an IPO of 102,942,000 restricted voting shares listed on the Toronto Stock Exchange (TSX) at a price to the public of C$17.00 per restricted voting share for total gross proceeds of approximately C$1,750 million. The net proceeds of C$1,677 million (U.S.$1,245 million) from the IPO were used by KML to indirectly acquire from us an approximate 30% interest in eacha limited partnership that holds our Canadian business, while we retained the remaining 70% interest. We used the proceeds from KML to pay down debt.
Subsequent to the IPO, we retained control of KMP, KMRKML and EPB were accounted forthe limited partnership, and as an equity transaction and no gain or loss was recognizeda result, they remain consolidated in our consolidated statements of income related to the Merger Transactions. After closing the KMR Merger Transaction, KMR was merged with and into KMI.
Additionally, on January 1, 2015, EPB and its subsidiary, EPPOC merged with and into KMP. As a result of such merger, allfinancial statements. The public ownership of the subsidiaries of EPB and EPPOC became wholly owned subsidiaries of KMP. References to EPB refer to EPB for periods prior to its merger into KMP.
Prior to the Merger Transactions, we owned an approximate 10% limited partner interest (including our interest in KMR) and the 2% general partner interest including incentive distribution rights in KMP, and an approximate 39% limited partner interest and the 2% general partner interest and incentive distribution rights in EPB. Effective with the Merger Transactions, the incentive distribution rights held by the general partner of KMP were eliminated.
Historically, most of our operating assets were owned and most of our investments were conducted by KMP and EPB.
The equity interests in KMP, EPB and KMR (which are all consolidated in our financial statements) owned by the public prior to the Merger Transactions areKML restricted voting shares is reflected within “Noncontrolling interests” in our accompanying consolidated statements of stockholders’ equity. The earnings recorded by KMP, EPBequity and KMR that were attributedconsolidated balance sheets. Earnings attributable to the units and shares, respectively, held by the public prior to the Merger Transactionsownership of KML are reported aspresented in “Net income attributable to noncontrolling interests” in our accompanying consolidated statements of income.income for the periods presented after May 30, 2017.
The portion of the Canadian business operations that we sold to the public on May 30, 2017 represented Canadian assets that are included in our Kinder Morgan Canada, Terminals and Products Pipelines business segments and included the Trans Mountain pipeline system (including related terminaling assets), TMEP, the Puget Sound and Jet Fuel pipeline systems, the Canadian portion of the Cochin pipeline system, the Vancouver Wharves Terminal and the North 40 Terminal; as well as three jointly controlled investments: the Edmonton Rail Terminal, the Alberta Crude Terminal and the Base Line Terminal.
Subsequent to its IPO, KML has obtained a credit facility and completed two preferred share offerings. KMI expects KML to be a self-funding entity and does not anticipate making contributions to fund its growth or specifically to fund the TMEP.
You should read the following in conjunction with our audited consolidated financial statements and the notes thereto. We have prepared our accompanying consolidated financial statements under GAAP and the rules and regulations of the SEC. Our accounting records are maintained in U.S. dollars and all references to dollars in this report are to U.S. dollars, except where stated otherwise. Our consolidated financial statements include our accounts and those of our majority-owned and/or controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation. The address of our principal executive offices is 1001 Louisiana Street, Suite 1000, Houston, Texas 77002, and our telephone number at this address is (713) 369-9000.
Recent Developments
The following is a brief listing of significant developments and updates related to our major projects.projects and other transactions. Additional information regarding most of these items may be found elsewhere in this report. “Capital Scope” is estimated for our share of the described project which may include portions not yet completed.
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| Asset or project | | Description | | Activity | | Approx. Capital Scope |
Placed in service, acquisitions or acquisitionsdivestitures |
Hiland PartnersELC | | Assets consistSold 49% interest in ELC to investment funds of crude oil gatheringEIG Global Energy Partners and transportation pipelines and gas gathering and processing systems, primarily serving production from the Bakken Formationformed a joint venture, which includes our remaining 51% interest in North Dakota and Montana, including the Double H crude oil pipeline.ELC. | | AcquiredCompleted in February 2017. | | n/a |
| Jones Act Tankers | | Purchase of nine new-build, medium-range Jones Act tankers constructed by General Dynamics NASSCO Shipyard (five) and Philly Shipyard, Inc. (four). Each of the 50,000-deadweight-ton, LNG conversion-ready product tankers has a capacity of approximately 330,000 barrels and is contracted under a term charter agreement. | | First tanker delivery took place in December 2015. Four additional tankers were delivered during 2016. The final four tankers were delivered during 2017. | | $3.01.4 billion |
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Asset or projectElba Express and SNG Expansion | | DescriptionExpansion project that provides 854,000 Dth/d of incremental natural gas transportation service supporting the needs of customers in Georgia, South Carolina and northern Florida, and also serving ELC. Supported by long-term firm contracts. | | ActivityInitial service began in December 2016. As of December 31, 2017, more than 70% of capacity has been placed in service. The remaining work is expected to be completed by November 2018. | | Approx. Capital Scope$284 million |
| KM Export Terminal | | Brownfield expansion along Houston Ship Channel that adds 12 storage tanks with 1.5 MMBbl of liquids storage capacity, one ship dock, one barge dock and cross-channel pipelines to connect with the KM Galena Park terminal. Supported by a long-term contract with a major ship channel refiner. | | Storage tanks placed in service in January 2017 followed by the terminal’s full marine capabilities, which were commissioned in March 2017. | | $246 million |
| Pit 11 Expansion | | Project adds 2 MMBbl of refined products storage at Pasadena terminal along the Houston Ship Channel. Supported by long-term commitments from existing customers. | | Placed in service throughout fourth quarter 2017. | | $186 million |
TGP Broad Run Flexibility and Broad Run ExpansionSusquehanna West | | Modification to existing pipelines under two separate projects to create 790,000Expansion project that provides 145,000 Dth/d of north-to-southincremental natural gas transportation capacity from a receipt point in West Virginiathe northeast Marcellus supply basin to delivery points in Mississippi and Louisiana.of liquidity. Subscribed under long-term firm transportation contracts. | | TGP Broad Run Flexibility facilities were placedPlaced in service November 2015 to allow for deliveries of 590,000 Dth/d; In-service of the remaining 200,000 Dth/d as of June 1, 2018.September 2017. | | $800 million |
ELC Acquisition | | Acquired Shell’s 49 percent equity interest in the ELC joint venture to develop liquefaction facilities at Elba Island, Georgia. | | Acquired July 2015. | | $510126 million |
TGP South System FlexibilityOrion | | Expansion project that provides more than 900 miles135,000 Dth/d of north-to-southincremental firm transportation capacity of 500,000 Dth/d on our TGP system from Tennesseethe Marcellus supply basin to South Texas and expands our transportation service to Mexico.TGP’s interconnection with Columbia Gas Transmission in Pike County, Pennsylvania. Subscribed under long-term firm transportation contracts. | | Initial volume placed into service January 2015. The next capacity increment was placedPlaced in service December 2015, with the remainder expected in December 2016.November 2017. | | $216104 million |
NGPL Acquisition | | Acquired equity interest from Myria Holdings, Inc. increasing ownership in NGPL from 20 percent to 50 percent. | | Acquired December 2015. | | $136 million |
Cow Canyon development | | An expansion project that will increase CO2 production in the Cow Canyon area of the McElmo Dome source field by 200 MMcf/d.
| | Majority placed in service in 2015. | | $309 million |
Edmonton Rail TerminalTGP Connecticut Expansion | | Expansion increasesproject that provides 72,100 Dth/d of incremental firm transportation capacity from Wright, New York to over 210,000 bpd at the joint venture crude rail terminalthree local distribution companies in Edmonton. The facility, supported byConnecticut. Subscribed under long-term customer contracts, will be connected via pipeline to the Trans Mountain pipeline and be capable of sourcing all crude streams handled by us for delivery by rail to North American markets and refineries. | | Placed in service second quarter 2015. | | CAD$270 million |
Royal Vopak U.S. Terminal acquisition | | Purchase of three U.S. terminals and one undeveloped site. | | Acquisition closed in February 2015. | | $158 million |
Galena Park Tank Project and Pasadena Barge Dock | | Construction of nine storage tanks with total shell capacity of 1.2 million barrels and a new barge dock at Pasadena, supported by long-term customer contracts. | | Final three tanks were placed in service first quarter 2015; barge dock placed in service December 2015. | | $138 million |
KM Condensate Processing Facility | | Project includes building two separate units to split condensate into various components and construct storage tanks totaling almost 2 million barrels to support the processing operation, supported by long-term customerfirm transportation contracts. | | Placed in service March 2015 (phase 1) and July 2015 (phase 2)November 2017. | | $104 million |
| TGP Triad Expansion | | Expansion project that provides 180,000 Dth/d of incremental firm transportation capacity from the Marcellus supply basin to Invenergy’s Lackawanna Energy Center in Lackawanna County, Pennsylvania. Subscribed under long-term firm transportation contracts. | | Project facilities placed in service November 2017 (customer contracts to begin June 2018). | | $445 57 million |
| Other Announcements | | | | | | |
| Natural Gas Pipelines |
TGP Northeast Energy Direct-Market Path | | Development of a 188-mile market path that will extend from Wright, New York to Dracut, Massachusetts. | | Expected in service November 2018. | | $3.1
billion
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ELC and SLNG expansionExpansion | | Building of new natural gas liquefaction and export facilities at our SLNG natural gas terminal on Elba Island, near Savannah, Ga., with a total capacity of 2.5 million tonnes per year of LNG, equivalent to 350 MMcf/357,000 Dth/d of natural gas. Supported by a 20-yearlong-term firm contract with Shell. | | First of 10 liquefaction units expected to be placed in service first quarter 2018in mid-2018 with the remainder expected by the end of 2018.mid-2019. | | $1.2 billion |
| KMTP Gulf Coast Express Pipeline Project (GCX Project)(a) | | $2.0New infrastructure joint venture project (KMTP 50%, DCP Midstream, LP 25% and Targa Resources Corp. 25% ownership interest) to provide up to 1.98 Bcf/d of transportation capacity from the Permian Basin to the Agua Dulce, Texas area with 1.76 Bcf/d under long-term contracts. A binding open season for the remaining 220,000 Dth/d of project capacity ends on March 1, 2018.
billion
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EPNG upstream Sierrita Gas Pipeline LLC | | Expansion projectsPending regulatory approvals, the project is expected to provide 550,000 Dth/d contracted, firm natural gas transport capacity with a first phase of system improvements to deliver volumes to the Sierrita pipeline and the second phase for incremental deliveries of natural gas to Arizona and California. | | Phase onebe placed in service October 2014 ($2 million), phase two expected fully in service July 2020 ($389 million).2019. | | $391 million |
Elba Express and SNG expansion | | Expansion project that provides 854,000 Dth/d incremental contracted, firm natural gas transportation service supporting the needs of customers in Georgia, South Carolina and northern Florida, and also serving ELC. | | Expected in service late third quarter or early fourth quarter of 2016 (first phase) and 2017. | | $306 million |
TGP Southwest Louisiana Supply (formerly Cameron LNG) | | Project provides 900,000 Dth/d of long-term capacity to the future Cameron LNG export complex at Hackberry, Louisiana. Subscribed under long-term firm transportation contracts. | | Expected in service February 2018. | | $178638 million |
|
| | | | | | |
| Asset or project | | Description | | Activity | | Approx. Capital Scope |
| TGP Broad Run Expansion | | Second of two projects to create a total of 790,000 Dth/d of incremental firm transportation capacity from the southwest Marcellus and Utica supply basins to delivery points in Mississippi and Louisiana. Subscribed under long-term firm transportation contracts. | | Broad Run Expansion (200,000 Dth/d) expected to be placed in service June 2018. Broad Run Flexibility facilities (590,000 Dth/d) were placed in service November 2015. | | $453 million |
| Texas Intrastate Crossover Expansion | | Expansion project creatingthat provides over 1,000,000 Dth/d of transportation capacity from the Katy Hub, the company’s Houston Central processing plant, and other third party receipt points to serve thecustomers in Texas Intrastate’sand Mexico. Phase I is supported by long-term firm transportation commitmentscontracts of 250,000nearly 700,000 Dth/dayd, including a contract with Comisión Federal de Electricidad. Phase 2, which is supported by long-term firm transportation contracts with Cheniere Energy, Inc. at its Corpus Christi LNG facility and SK E&S LNG, LLC, that will provide service to the Cheniere Corpus ChristiFreeport LNG export facility and 527,000 Dth/day to the CFE at delivery points in South Texas.other domestic markets. | | Expected in-servicePhase 1 was placed in service in September 2016 for the CFE commitment and January 2019 for the Cheniere commitment.2016. Phase 2 is expected to be placed in service by third quarter 2019. | | $164 million |
Texas Intrastate SK Freeport LNG | | Entered into a 20-year firm transportation services agreement with SK E&S LNG, LLC in December 2014 to provide more than 320,000 Dth/d of firm natural gas transportation services. | | Expected in-service January 2019 | | $161307 million |
TGP Susquehanna WestSouthwest Louisiana Supply | | Expansion project that provides 145,000to provide 900,000 Dth/d of incremental natural gasfirm transportation capacity servingfrom multiple supply basins to the northeast Marcellus to points of liquidity. Subscribed under long-term firm transportation contracts. | | ExpectedCameron LNG export facility in service November 2017. | | $156 million |
KMLP Magnolia LNG Liquefaction Transport | | Upgrades to existing pipeline system to provide 700,000 Dth/d capacity to serve Magnolia LNG in the Lake Charles, La., area.Cameron Parish, Louisiana. Subscribed under long-term firm transportation contracts. | | Expected in-service fourth quarter 2018date March 2018. | | $156178 million |
KMLP Cheniere Sabine Pass LNGTGP Lone Star | | ReconfigurationExpansion project to flow northeastprovide 300,000 Dth/d of incremental firm transportation capacity from Louisiana receipt points to southeast to deliver 600 MDth/d to the Cheniere Sabine Pass Liquefaction TerminalCheniere’s Corpus Christi LNG export facility in Cameron Parish, LA.Jackson County, Texas. Subscribed under long-term firm transportation contracts. | | Expected in-service fourth quarter 2019date July 2019. | | $146150 million |
TGP OrionEPNG South Mainline Expansion (formerly Marcellus to Milford)upstream Sierrita) | | An expansionExpansion project that provides 471,000 Dth/d of firm transportation capacity with a first phase of system improvements to provide additional firm capacity fromdeliver volumes to the Marcellus supply basinSierrita pipeline and the second phase for incremental deliveries of natural gas to TGP’s interconnection with Columbia Gas Transmission in Pike County, Pennsylvania. The capacity of this expansion will be at least 135,000 Dth/d.Arizona and California. Subscribed under long-term firm transportation contracts. | | ExpectedPhase one placed in service June 2018.October 2014, phase two expected to be in service July 2020. | | $142134 million |
TGP Lone StarKMLP Magnolia LNG Liquefaction Transport | | Two Greenfield compressor stationsExpansion project to provide supply700,000 Dth/d of incremental firm transportation capacity from various receipt points to the Corpus Christiproposed Magnolia LNG liquefactionexport facility in Lake Charles, Louisiana. Subscribed under long-term firm agreements, subject to shipper’s final investment decision. | | In-service date subject to timing of shipper’s final investment decision. | | $127 million |
| KMLP Sabine Pass Expansion | | Expansion project for ato provide 600,000 Dth/d of incremental firm transportation capacity of 300,000 Dth/d.from various receipt points to Cheniere’s Sabine Pass Liquefaction Terminal in Cameron Parish, Louisiana. Subscribed under long-term firm transportation contracts. | | Expected in-service Julydate as early as the first quarter 2019. | | $134122 million |
TGP TriadSNG Fairburn Expansion | | Expansion project that provides 180,000in Georgia to provide 347,000 Dth/d of incremental long-term firm transportation capacity for Invernergy’s Lakawanna Energy Centerinto the Southeast market, and includes the construction of a new compressor station, 6.5 miles of new pipeline and new meter stations. | | Expected in-service date October 2018. | | $119 million |
| NGPL Gulf Coast Southbound Expansion | | Expansion project to provide 460,000 Dth/d of incremental firm transportation capacity from various interstate pipeline interconnects in Illinois, Arkansas and Texas, to points south on NGPL’s pipeline system to serve a planned new area power plant.growing demand in the Gulf Coast area. Subscribed under long-term firm transportation contracts. | | ExpectedPartially in service November 2017. | | $87
million
|
CO2
|
Cortez Pipeline expansion | | Project will increase capacity from 1.35 Bcf/dApril 2017 (75,000 Dth/d). Remaining (385,000 Dth/d) expected to 1.5 Bcf/d on this existing pipeline. This pipeline will transport CO2 from southwestern Colorado to eastern New Mexico and west Texas for use in enhanced oil recovery projects.
| | Expected fullbe in service secondfourth quarter 2016.of 2018. | | $214106 million |
| Terminals |
KM General Dynamics’ NASSCO TankersBase Line Terminal development(b) | | PurchaseA 4.8 MMBbl new-build merchant crude oil storage facility in Edmonton, Alberta. Developed as part of five medium-range Jones Act tankers constructeda 50-50 joint venture with Keyera Corp. Capital figure includes costs associated with the construction of a pipeline segment funded solely by General Dynamics’ NASSCO Shipyard in San Diego. All of the tankers will be 50,000-deadweight-ton, LNG conversion-ready product carriers,Kinder Morgan. Subscribed under long-term contracts with a capacity of 330,000 barrels and contracted for an average initial term of 57.5 years. | | Commissioning began in the first quarter of 2018. First tanker delivery took placefour tanks placed in-service in December 2015. DeliveryJanuary 2018 with balance expected to be phased into service throughout 2018. | | C$398 million |
| Products Pipelines |
| Utopia Pipeline | | Building of remaining four tankers expected between early 2016new 267 mile pipeline, supported by a long-term customer contract, to transport ethane and mid-2017.ethane-propane mixtures from the prolific Utica Shale, with an initial design capacity of 50 MBbl/d, expandable to more than 75 MBbl/d. | | Placed in-service January 2018. | | $782 million |
KM Philly Tankers | | Further expansion of growing fleet of Jones Act product tankers with the purchase of four, new 50,000-deadweight-ton. The Tier II tankers will be constructed by Philly Shipyard. (two under contract and two remaining to be contracted). Each LNG conversion-ready tanker will have a capacity of 337,000 barrels. | | Definitive agreement executed. Delivery of tankers expected between November 2016 and November 2017. | | $633 million |
KM and BP Joint Venture | | Acquire 15 refined products terminals and associated infrastructure. KM and BP have formed a joint venture to own 14 of the acquired assets. One terminal will be owned solely by KM. | | Closed on February 1, 2016 | | $350 million |
KM Export Terminal | | Brownfield expansion along Houston Ship Channel will add 12 storage tanks with 1.5 million barrels of liquids storage capacity, one ship dock, one barge dock and cross-channel pipelines to connect with the KM Galena Park terminal. Supported by a long-term contract with a major ship channel refiner. | | Expected in service first quarter 2017. | | $220275 million |
|
| | | | | | |
| Asset or project | | Description | | Activity | | Approx. Capital Scope |
KM Base Line Terminal development | | Announced a 50-50 joint venture with Keyera Corp. to build a new 4.8 million barrels of crude oil storage facility in Edmonton, Alberta. Subscribed under long-term contracts. | | Planning-permitting activities continue. | | CAD$372 million |
Products Pipelines |
Palmetto Pipeline | | Construction of a new 360-mile pipeline, underpinned by long-term customer contracts, to move gasoline, diesel and ethanol from Louisiana, Mississippi and South Carolina to points in South Carolina, Georgia and Florida. | | Expected in service December 2017. | | $1 billion
|
Utopia East Pipeline | | Building of new 240 mile pipeline, supported by a long-term customer contract, to transport ethane and ethane-propane mixtures from the prolific Utica Shale, with an initial design capacity of 50,000 bpd, expandable to more than 75,000 bpd. | | Expected in service January 2018. | | $517 million |
| Kinder Morgan Canada |
Trans Mountain Expansion ProjectTMEP(b) | | An increase of capacity on our Trans Mountain pipeline system from approximately 300,000300 to 890,000 barrels per day,890 MBbl/d, underpinned by long-term take-or-pay contracts. | | Currently engaged in final approval process with the NEB andReceived federal government expectedapproval in service third quarter 2019.December 2016. In the process of getting permits and other regulatory approval. | | $5.4C$7.4
billion |
_______
n/a - not applicable
| |
| (a) | Our share of capital scope is adjusted to reflect the potential exercise of Apache Corp.’s option to purchase 15% equity in the project. |
| |
| (b) | As of May 31, 2017, these assets are now included in KML and are partially owned by KML’s Restricted Voting Stockholders. |
KMI Financings
On August 10, 2017, we issued $1 billion of unsecured senior notes with a fixed rate of 3.15% and $250 million of unsecured senior notes with a floating rate, both due January 26, 2016, we closed on a three-year, unsecured2023. The net proceeds from the notes were primarily used to repay all of the $225 million principal amount outstanding of Hiland’s 5.50% senior notes due 2022, plus accrued interest, and to repay the $1 billion term loan facility due 2019.
KML Financings
In addition to proceeds received from KML’s IPO discussed above, on June 16, 2017, KML entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the TMEP; (ii) a $1C$1.0 billion expansion of our unsecured revolving contingent credit facility increasingfor the capacitypurpose of thatfunding, if necessary, additional TMEP costs (and, subject to the need to fund such additional costs and regulatory approval, meeting the Canadian NEB-mandated liquidity requirements); and (iii) a C$500 million revolving working capital facility, from $4 billion to $5 billion. Proceeds from the term loan werebe used to repay existing borrowingsfor working capital and forother general corporate purposes. Pricingpurposes (collectively, the “KML Credit Facility”). The KML Credit Facility has a five year term and is with a syndicate of financial institutions with Royal Bank of Canada as the covenant packageadministrative agent. On January 23, 2018, KML entered into an agreement amending certain terms of both facilities are consistentthe KML Credit Facility to, among other things, provide additional funding certainty with our existing revolving credit facility.respect to the construction, contingent and working capital facilities. As of December 31, 2017, KML had no amounts outstanding under the KML Credit Facility and C$53 million (U.S.$42 million) in letters of credit.
Current Commodity Price EnvironmentOn August 15, 2017, KML completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares) on the TSX at a price to the public of $25.00 per Series 1 Preferred Share for total net proceeds of C$293 million (U.S.$230 million) and on December 8, 2017, KML completed an offering of 10,000,000 cumulative redeemable minimum rate reset preferred shares, Series 3 (Series 3 Preferred Shares) on the TSX at a price to the public of $25.00 per Series 3 Preferred Share for total net proceeds of C$243 million (U.S.$189 million).
Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” as well as Note 4 “Impairments and Disposals” and Note 8 “Goodwill” to our consolidated financial statements, discuss the impacts of the current commodity price environment on the energy industry, including our customers and us. Refer to the developments addressed in these sections, including the resulting non-cash impairment charges related to goodwill, certain long-lived assets and equity method investments. For a more general discussion of these related risk factors, refer to Item 1A. “Risk Factors.”
Dividend Announcement
Refer to Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources” for a discussion regarding the reduction in our dividend announced in December 2015 to an expected $0.50 per share on an annualized basis.
20162018 Outlook
We expect to declare dividends of $0.80 per share for 2018, a 60% increase from the 2017 declared dividends of $0.50 per share, for 2016, generate approximately $4.9 billion of distributable cash flow available to equity and approximately $4.7 billion of distributable cash flow available to common shareholders (i.e. after payment of preferred dividends) and generate approximately $3.6$4.57 billion of DCF. We also expect to invest $2.2 billion on expansion projects and other discretionary spending in 2018, excluding growth capital and discretionary spending by KML, which we expect to continue to be a self-funding entity. As in recent years, our discretionary spending will be funded with excess, internally generated cash flow, with no need to access equity markets during 2018. In addition, our board of directors authorized a $2 billion share buy-back program, and in excessDecember 2017 and January 2018 we bought back 27 million Class P shares for $500 million.
We are unable to provide budgeted net income attributable to common stockholders (the GAAP financial measure most directly comparable to DCF) due to the inherent difficulty and impracticality of our dividend. predicting certain amounts required by GAAP, such as ineffectiveness on commodity, interest rate and foreign currency hedges, unrealized gains and losses on derivatives marked to market, and potential changes in estimates for certain contingent liabilities.
These expectations assume an average 2016annual prices for WTI crude oil price of $38 per barrel, an average 2016and Henry Hub natural gas price of $2.50$56.50 per barrel and $3.00 per MMBtu, and interest ratesrespectively, consistent with the current forward curve at the time thatpricing during our 20162018 budget was prepared.
process. The overwhelmingvast majority of cash we generate is supported by multi-year fee-based customer arrangements and therefore is not directly exposed to commodity
prices. The primary area where we have direct commodity price sensitivity is in our CO2 segment, wherein which we hedge the majority of the next 12 months of oil and NGL production to minimize this sensitivity. For 2016,2018, we estimate that every $1 change in the average WTI crude oil price from our budget of $56.50 per barrel would impact our distributable cash flowDCF by approximately $6.5$7 million and each $0.10 per MMBtu change in the average price of natural gas impacts distributable cash flowfrom our budget of $3.00 per MMBtu would impact DCF by approximately $0.6 million, and every 1% change in the ratio of the weighted-average NGL price per barrel to the WTI crude oil price per barrel impacts distributable cash flow by approximately $2.0$1 million. These sensitivities compare to total anticipated segment earnings before DD&A in 2016 of approximately $8 billion (adding back our share of joint venture DD&A).
We expect that a full-year of contributions from our 2015 acquisitions and expansions along with partial-year contributions from our anticipated 2016 expansion investments, as described above under “—Recent Developments”, will generate incremental earnings and cash flow from our assets in 2016 and beyond. Generally, our base cash flows (that is, cash flows not attributable to acquisitions or expansions) are relatively stable from year to year and are largely supported by multi-year, fee-based customer arrangements.
In addition, our expectations for 20162018 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable to not put undue reliance on any forward-looking statement. Please read our Item 1A “Risk Factors” below for more information. Furthermore, we plan to provide updates to our 20162018 expectations when we believe previously disclosed expectations no longer have a reasonable basis.
2017 Tax Reform
While the recently enacted 2017 Tax Reform will ultimately be moderately positive for us, the reduced corporate income tax rate caused certain of our deferred-tax assets to be revalued at 21 percent versus 35 percent at the end of 2017. Although there is no impact to the underlying related deductions, which can continue to be used to offset future taxable income, we took an estimated approximately $1.4 billion non-cash accounting charge in the fourth quarter of 2017. This charge is our initial estimate and may be refined in the future as permitted by recent guidance from the SEC and FASB. The positive impacts of the law include the reduced corporate income tax rate and the fact that several of our U.S. business units (essentially all but our interstate natural gas pipelines) will be able to deduct 100 percent of their capital expenditures through 2022. The net impact results in postponing the date when we become a significant federal cash taxpayer by approximately one year, to beyond 2024.
(b) Financial Information about Segments
For financial information on our sixfive reportable business segments, see Note 16 “Reportable Segments” to our consolidated financial statements.
(c) Narrative Description of Business
Business Strategy
Our business strategy is to:
focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure of growing markets within North America;
increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound operating practices;
leverage economies of scale from incremental acquisitions and expansions of assets that fit within our strategy and are accretive to cash flow; and
maintain a strong balance sheet and return value to our stockholders.
It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances. However, as discussed under Item 1A. “Risk“Risk Factors” below, there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.
We regularly consider and enter into discussions regarding potential acquisitions, and full and partial divestitures, and we are currently contemplating potential acquisitions.transactions. Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, receipt of fairness opinions, and approval of our board of directors, if applicable. While there are currently no unannounced purchase or sale agreements for the acquisition or sale of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.
Business Segments
We operate the following reportable business segments. These segments and their principal sources of revenues are as follows:
Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG facilities;
| |
| • | CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas; |
Terminals—(i) the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, condensate,chemicals, and ethanol and bulk products, including coal, petroleum coke, cement, alumina, saltsteel and other bulk chemicalscoal; and (ii) the ownership and operation of our Jones Act tankers;
Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate pipelines that primarily deliver, refined petroleumamong other products, (gasoline,gasoline, diesel fuel and jet fuel), NGL,fuel, propane, ethane, crude oil condensate and bio-fuelscondensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; and
Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport; and
Other—primarily other miscellaneous assets and liabilities including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with legacy trading activities; and (iii) other miscellaneous legacy assets and liabilities.Airport.
Natural Gas Pipelines
Our Natural Gas Pipelines segment includes interstate and intrastate pipelines and our LNG terminals, and includes both FERC regulated and non-FERC regulated assets.
Our primary businesses in this segment consist of transportation, storage, natural gas sales, transportation, storage, gathering, processing and treating, and the terminaling of LNG. Within this segment, are: (i) approximately 52,00046,000 miles of wholly owned natural gas pipelines and (ii) our equity interests in entities that have approximately 19,00026,000 miles of natural gas pipelines, along with associated storage and supply lines for these transportation networks, which are strategically located throughout the North American natural gas pipeline grid. Our transportation network provides access to the major natural gas supply areas and consumers in the western U.S., Louisiana, Texas, the Midwest, Northeast, Rocky Mountain, Midwest and Southeastern regions. Our LNG storage and regasification terminals also serve natural gas supply areas in the southeast. The following tables summarize our significant Natural Gas Pipelines segment assets, as of December 31, 2015.2017. The Design Capacity represents either transmission, gathering or liquefaction capacity depending on the nature of the asset.
|
| | | | | | | | |
| | Ownership Interest % | | Miles of Pipeline | | Design (Bcf/d) [Storage (Bcf)] Capacity | | Supply and Market Region |
| Natural Gas Pipelines |
| TGP | 100 | | 11,800 |
| | 9.74 [99] | | South Texas and Gulf of Mexico to northeast and southeast U.S.; Haynesville, Marcellus, Utica, and Eagle Ford shale formations |
| EPNG/Mojave pipeline system | 100 | | 10,700 |
| | 5.65 [44] | | Northern New Mexico, Texas, Oklahoma, to California, connects to San Juan, Permian, and Anadarko basins |
| NGPL | 50 | | 9,100 |
| | 6.20 [288] | | Chicago and other Midwest markets and all central U.S. supply basins |
| SNG | 100 | | 6,900 |
| | 3.90 [68] | | Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee; basins in Texas, Louisiana, Mississippi and Alabama |
| Florida Gas Transmission (Citrus) | 50 | | 5,300 |
| | 3.60 | | Texas to Florida; basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico |
| CIG | 100 | | 4,300 |
| | 5.15 [43] | | Colorado and Wyoming; Rocky Mountains and the Anadarko Basin |
| WIC | 100 | | 850 |
| | 3.88 | | Wyoming, Colorado, and Utah; Overthrust, Piceance, Uinta, Powder River and Green River Basins |
| Ruby pipeline | 50 | | 680 |
| | 1.53 | | Wyoming to Oregon; Rocky Mountain basins |
| MEP | 50 | | 510 |
| | 1.80 | | Oklahoma and north Texas supply basins to interconnects with deliveries to interconnects with Transco, Columbia Gulf and various other pipelines |
| CPG | 100 | | 410 |
| | 1.20 | | Colorado and Kansas, natural gas basins in the Central Rocky Mountain area |
TransColorado Gas | 100 | | 310 |
| | 0.98 | | Colorado and New Mexico; connects to San Juan, Paradox and Piceance basins |
| WYCO | 50 | | 224 |
| | 1.20 [7] | | Northeast Colorado; interconnects with CIG, WIC, Rockies Express Pipeline, Young Gas Storage and PSCo’s pipeline system |
|
| | | | | | | | |
| | Ownership Interest % | | Miles of Pipeline | | Design (Bcf/d) [Storage (Bcf)] Capacity | | Supply and Market Region |
| Elba Express | 100 | | 200 |
| | 0.95 | | Georgia; connects to SNG (Georgia), Transco (Georgia/South Carolina), SLNG (Georgia) and CGT (Georgia). |
| FEP | 50 | | 185 |
| | 2.00 | | Arkansas to Mississippi; connects to NGPL, Trunkline Gas Company, Texas Gas Transmission, and ANR Pipeline Company |
| KMLP | 100 | | 135 |
| | 2.20 | | sources gas from Cheniere Sabine Pass LNG terminal to interconnects with Columbia Gulf, ANR and various other pipelines |
| Sierrita Gas Pipeline LLC | 35 | | 61 |
| | 0.20 | | near Tucson, Arizona, to the U.S.-Mexico border near Sasabe, Arizona; connects to EPNG and via a new international border crossing with a new natural gas pipeline in Mexico |
| Young Gas Storage | 48 | | 16 |
| | [6] | | Morgan County, Colorado, capacity is committed to CIG and Colorado Springs Utilities. |
| Keystone Gas Storage | 100 | | 12 |
| | [6] | | located in the Permian Basin and near the WAHA natural gas trading hub in West Texas. |
| Gulf LNG Holdings | 50 | | 5 |
| | [6.6] | | near Pascagoula, Mississippi; connects to four interstate pipelines and natural gas processing plant. |
| Bear Creek Storage | 100 | | — |
| | [59] | | located in Louisiana; provides storage capacity to SNG and TGP. |
| SLNG | 100 | | — |
| | [11.5] | | Georgia; connects to Elba Express, SNG and CGT |
| ELC | 100 | | — |
| | 0.35 | | Georgia; not in service until 2018 |
| | | | | | | | |
| Midstream assets | | | | | | |
KM Texas and Tejas pipelines | 100 | | 5,600 |
| | 6.20 [124] | | Texas Gulf Coast. |
Mier-Monterrey pipeline | 100 | | 87 |
| | 0.65 | | Starr County, Texas to Monterrey, Mexico; connects to Pemex NG Transportation system and a 1,000-megawatt power plant |
KM North Texas pipeline | 100 | | 82 |
| | 0.33 | | interconnect from NGPL; connects to 1,750-megawatt Forney, Texas, power plant and a 1,000-megawatt Paris, Texas, power plant |
| Oklahoma | | | | | | |
| Southern Dome | 73 | | — |
| | 0.03 | | propane refrigeration plant in the southern portion of Oklahoma county |
| Oklahoma System | 100 | | 3,600 |
| | 0.38 | | Hunton Dewatering, Woodford Shale, and Mississippi Lime |
| South Texas | | | | | | |
| Webb/Duval gas gathering system | 63 | | 145 |
| | 0.15 | | South Texas |
| South Texas System | 100 | | 1,300 |
| | 1.88 | | Eagle Ford shale formation, Woodbine and Eaglebine (Texas) |
| EagleHawk | 25 | | 860 |
| | 1.20 | | South Texas, Eagle Ford shale formation |
| KM Altamont | 100 | | 1,200 |
| | 0.08 | | Utah, Uinta Basin |
| Red Cedar | 49 | | 740 |
| | 0.70 | | La Plata County, Colorado, Ignacio Blanco Field |
| Rocky Mountain | | | | | | |
| Fort Union | 37 | | 310 |
| | 1.25 | | Powder River Basin (Wyoming) |
| Bighorn | 51 | | 290 |
| | 0.60 | | Powder River Basin (Wyoming) |
| KinderHawk | 100 | | 500 |
| | 2.00 | | Northwest Louisiana, Haynesville and Bossier shale formations |
| North Texas | 100 | | 400 |
| | 0.14 | | North Barnett Shale Combo |
| Endeavor | 40 | | 100 |
| | 0.12 | | East Texas, Cotton Valley Sands and Haynesville/ Bossier Shale horizontal well developments |
| Camino Real - Gas | 100 | | 70 |
| | 0.15 | | South Texas, Eagle Ford shale formation |
| KM Treating | 100 | | — |
| | — | | Odessa, Texas, other locations in Tyler and Victoria, Texas |
|
| | | | | | | | | |
| Asset (KMI ownership shown if not 100%) | | Miles of Pipeline | | Design (Bcf/d) Capacity | | Storage (Bcf) [Processing (Bcf/d)] Capacity | | Supply and Market Region |
| Natural Gas Pipelines |
| TGP | | 11,750 |
| | 12.00 | | 106 | | North to south to Gulf Coast and U.S.-Mexico border, southeast U.S.; Haynesville, Marcellus, Utica, and Eagle Ford shale formations |
| EPNG/Mojave pipeline system | | 10,600 |
| | 5.65
| | 44 | | Northern New Mexico, Texas, Oklahoma, to California, connects to San Juan, Permian and Anadarko basins |
| NGPL (50%) | | 9,100 |
| | 7.60 | | 288 | | Chicago and other Midwest markets and all central U.S. supply basins; north to south for LNG and to U.S.-Mexico border |
| SNG (50%) | | 6,900 |
| | 4.16 | | 68 | | Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee; basins in Texas, Louisiana, Mississippi and Alabama |
| Florida Gas Transmission (Citrus) (50%) | | 5,300 |
| | 3.60 | | — | | Texas to Florida; basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico |
| CIG | | 4,350 |
| | 5.15 | | 37 | | Colorado and Wyoming; Rocky Mountains and the Anadarko Basin |
|
| | | | | | | | |
| | Ownership Interest % | | Miles of Pipeline | | Design (Bcf/d) [Storage (Bcf)] Capacity | | Supply and Market Region |
| Hiland | | | | | | | |
| Williston - Gas | 100 | | 2,000 |
| | 0.31 | | Bakken shale formation (North Dakota) |
| Midcontinent | 100 | | 690 |
| | 0.23 | | Woodford Shale, Anadarko Basin and Arkoma Basin |
| | | | | | | | |
| | | | | | | | |
| | | | | | (MBbl/d) | | |
| Liquids | | | | | | | |
| Liberty Pipeline | 50 | | 87 |
| | 170 | | Houston Central complex to the Texas Gulf Coast |
| Liquids Assets | 100 | | 345 |
| | 115 | | Houston Central complex to the Texas Gulf Coast |
| Camino Real - Oil | 100 | | 68 |
| | 110 | | South Texas, Eagle Ford shale formation |
| Williston - Oil | 100 | | 1,400 |
| | 266 | | Bakken shale formation (North Dakota) |
|
| | | | | | | | | |
| Asset (KMI ownership shown if not 100%) | | Miles of Pipeline | | Design (Bcf/d) Capacity | | Storage (Bcf) [Processing (Bcf/d)] Capacity | | Supply and Market Region |
| WIC | | 850 |
| | 3.88 | | — | | Wyoming, Colorado and Utah; Overthrust, Piceance, Uinta, Powder River and Green River Basins |
| Ruby (50%)(a) | | 680 |
| | 1.53 | | — | | Wyoming to Oregon with interconnects supplying California and the Pacific Northwest; Rocky Mountain basins |
| MEP (50%) | | 510 |
| | 1.80 | | — | | Oklahoma and north Texas supply basins to interconnects with deliveries to interconnects with Transco, Columbia Gulf and various other pipelines |
| CPGPL | | 410 |
| | 1.20 | | — | | Colorado and Kansas, natural gas basins in the Central Rocky Mountain area |
| TransColorado Gas | | 310 |
| | 0.98 | | — | | Colorado and New Mexico; connects to San Juan, Paradox and Piceance basins |
| WYCO (50%) | | 224 |
| | 1.20
| | 7 | | Northeast Colorado; interconnects with CIG, WIC, Rockies Express Pipeline, Young Gas Storage and PSCo’s pipeline system |
| Elba Express | | 200 |
| | 0.95 | | — | | Georgia; connects to SNG (Georgia), Transco (Georgia/South Carolina), SLNG (Georgia) and Dominion Energy Carolina Gas Transmission (Georgia) |
| FEP (50%) | | 185 |
| | 2.00 | | — | | Arkansas to Mississippi; connects to NGPL, Trunkline Gas Company, Texas Gas Transmission and ANR Pipeline Company |
| KMLP | | 135 |
| | 2.20 | | — | | sources gas from Cheniere Sabine Pass LNG terminal to interconnects with Columbia Gulf, ANR and various other pipelines |
| Sierrita Gas Pipeline LLC (35%) | | 61 |
| | 0.20 | | — | | near Tucson, Arizona, to the U.S.-Mexico border near Sasabe, Arizona; connects to EPNG and via an international border crossing with a third-party natural gas pipeline in Mexico |
| Young Gas Storage (48%) | | 16 |
| | — | | 5.8 | | Morgan County, Colorado, capacity is committed to CIG and Colorado Springs Utilities |
| Keystone Gas Storage | | 15 |
| | — | | 6.4 | | located in the Permian Basin and near the WAHA natural gas trading hub in West Texas |
| Gulf LNG Holdings (50%) | | 5 |
| | — | | 6.6 | | near Pascagoula, Mississippi; connects to four interstate pipelines and a natural gas processing plant |
| Bear Creek Storage (75%) | | — |
| | — | | 59 | | located in Louisiana; provides storage capacity to SNG and TGP |
| SLNG | | — |
| | — | | 11.5 | | Georgia; connects to Elba Express, SNG and Dominion Energy Carolina Gas Transmission |
| ELC (51%) | | — |
| | 0.35 | | — | | Georgia; expect phased in-service from mid-2018 to mid-2019 |
| | | | | | | | | |
| Midstream Natural Gas Assets |
| KM Texas and Tejas pipelines | | 5,660 |
| | 7.00 | | 132 [0.54] | | Texas Gulf Coast |
| Mier-Monterrey pipeline | | 90 |
| | 0.65 | | — | | Starr County, Texas to Monterrey, Mexico; connect to CENEGAS national system and multiple power plants in Monterrey |
| KM North Texas pipeline | | 80 |
| | 0.33 | | — | | interconnect from NGPL; connects to 1,750-megawatt Forney, Texas, power plant and a 1,000-megawatt Paris, Texas, power plant |
| Oklahoma | | | | | | |
| Oklahoma System | | 3,500 |
| | .50 | | [0.14] | | Hunton Dewatering, Woodford Shale and Mississippi Lime |
| Hiland - Midcontinent | | 620 |
| | .22 | | — | | Woodford Shale, Anadarko Basin and Arkoma Basin |
| Cedar Cove (70%) | | 85 |
| | 0.03 | | — | | Oklahoma STACK, capacity excludes third-party offloads |
| South Texas | | | | | | |
| South Texas System | | 1,300 |
| | 1.74 | | [1.02] | | Eagle Ford shale, Woodbine and Eaglebine formations |
| Webb/Duval gas gathering system (63%) | | 145 |
| | 0.15 | | — | | South Texas |
|
| | | | | | | | | |
| Asset (KMI ownership shown if not 100%) | | Miles of Pipeline | | Design (Bcf/d) Capacity | | Storage (Bcf) [Processing (Bcf/d)] Capacity | | Supply and Market Region |
| EagleHawk (25%) | | 530 |
| | 1.20 | | — | | South Texas, Eagle Ford shale formation |
| KM Altamont | | 1,380 |
| | 0.08 | | [0.08] | | Utah, Uinta Basin |
| Red Cedar (49%) | | 900 |
| | 0.70 | | — | | La Plata County, Colorado, Ignacio Blanco Field |
| Rocky Mountain | | | | | | | | |
| Fort Union (37%) | | 310 |
| | 1.25 | | — | | Powder River Basin (Wyoming) |
| Bighorn (51%) | | 290 |
| | 0.60 | | — | | Powder River Basin (Wyoming) |
| KinderHawk | | 510 |
| | 2.00 | | — | | Northwest Louisiana, Haynesville and Bossier shale formations |
| North Texas | | 550 |
| | 0.14 | | [0.10] | | North Barnett Shale Combo |
| Endeavor (40%) | | 101 |
| | 0.15 | | — | | East Texas, Cotton Valley Sands and Haynesville/ Bossier Shale |
| Camino Real | | 70 |
| | 0.15 | | — | | South Texas, Eagle Ford shale formation |
| KM Treating | | — |
| | — | | — | | Odessa, Texas, other locations in Tyler and Victoria, Texas |
| Hiland - Williston | | 2,030 |
| | .32 | | [0.20] | | Bakken/Three Forks shale formations (North Dakota/Montana) |
| | | | | | | | | |
| Midstream Liquids/Oil/Condensate Pipelines |
| | | | | (MBbl/d) | | (MBbl) | | |
| Liberty Pipeline (50%) | | 87 |
| | 140 | | — | | Y-grade pipeline from Houston Central complex to the Texas Gulf Coast |
| South Texas NGL Pipelines | | 340 |
| | 115 | | — | | Ethane and propane pipelines from Houston Central complex to the Texas Gulf Coast |
| Camino Real - Condensate | | 69 |
| | 110 | | 60 | | South Texas, Eagle Ford shale formation |
| Hiland - Williston - Oil | | 1,500 |
| | 282 | | — | | Bakken/Three Forks shale formations (North Dakota/Montana) |
| EagleHawk - Condensate (25%) | | 400 |
| | 220 | | 60 | | South Texas, Eagle Ford shale formation |
_______
| |
| (a) | We operate Ruby and own the common interest in Ruby. Pembina Pipeline Corporation (Pembina) owns the remaining interest in Ruby in the form of a convertible preferred interest. If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby. |
Competition
The market for supply of natural gas is highly competitive, and new pipelines, storage facilities, treating facilities, and facilities for related services are currently being built to serve the growing demand for natural gas in each of the markets served by the pipelines in our Natural Gas Pipelines business segment. Our operations compete with interstate and intrastate pipelines, and their shippers, for connections to new markets and supplies and for transportation, processing and treating services. We believe the principal elements of competition in our various markets are location, rates, terms of service and flexibility and reliability of service. From time to time, other projects are proposed that would compete with us. We do not know whether or when any such projects would be built, or the extent of their impact on our operations or profitability.
Shippers on our natural gas pipelines compete with other forms of energy available to their natural gas customers and end users, including electricity, coal, propane, fuel oils and fuel oils.renewables such as wind and solar. Several factors influence the demand for natural gas, including price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the ability to convert to alternative fuels and weather.
CO2
Our CO2 business segment produces, transports, and markets CO2 for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. Our CO2 pipelines and related assets allow us to market a complete
package of CO2 supply, transportation and technical expertise to our customers. We also hold ownership interests in several oil-producing fields and own a crude oil pipeline, all located in the Permian Basin region of West Texas.
Sales and Transportation Activities
Our principal market for CO2 is for injection into mature oil fields in the Permian Basin. Our ownership of CO2 resources as of December 31, 2017 includes:
|
| | | | | | | | | |
| | Ownership Interest % | | Recoverable CO2 (Bcf) | | Compression Capacity (Bcf/d) | | Location |
Recoverable CO2 | | | | | | | |
| McElmo Dome unit | 45 | | 4,159 |
| | 1.5 |
| | Colorado |
| Doe Canyon Deep unit | 87 | | 382 |
| | 0.2 |
| | Colorado |
| Bravo Dome unit(a) | 11 | | 285 |
| | 0.3 |
| | New Mexico |
_______
| |
| (a) | We do not operate this unit. |
CO2 Segment Pipelines
The principal market for transportation on our CO2 pipelines is to customers, including ourselves, using CO2 for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to remain stable for the next several years. The tariffs charged on the Wink crude oil pipeline system are regulated by both the FERC and the Texas Railroad Commission and the Pecos Carbon Dioxide Pipeline’s tariffs are regulated by the Texas Railroad Commission. The tariff charged on the Cortez pipeline is based on a consent decree and the tariffs charged by our other CO2 pipelines are not regulated.
Our ownership of CO2 and crude oil pipelines as of December 31, 2017 includes:
|
| | | | | | | | |
| Asset (KMI ownership shown if not 100%) | | Miles of Pipeline | | Transport Capacity (Bcf/d) | | Supply and Market Region |
CO2 pipelines | | | | | | |
| Cortez pipeline (53%) | | 569 |
| | 1.5 |
| | McElmo Dome and Doe Canyon source fields to the Denver City, Texas hub |
| Central Basin pipeline | | 334 |
| | 0.7 |
| | Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers, and Pecos pipelines |
| Bravo pipeline (13%)(a) | | 218 |
| | 0.4 |
| | Bravo Dome to the Denver City, Texas hub |
| Canyon Reef Carriers pipeline (98%) | | 163 |
| | 0.3 |
| | McCamey, Texas, to the SACROC, Sharon Ridge, Cogdell and Reinecke units |
Centerline CO2 pipeline | | 113 |
| | 0.3 |
| | between Denver City, Texas and Snyder, Texas |
Eastern Shelf CO2 pipeline | | 98 |
| | 0.1 |
| | between Snyder, Texas and Knox City, Texas |
| Pecos pipeline (95%) | | 25 |
| | 0.1 |
| | McCamey, Texas, to Iraan, Texas, delivers to the Yates unit |
| Goldsmith Landreth (99%) | | 3 |
| | 0.2 |
| | Goldsmith Landreth San Andres field in the Permian Basin of West Texas |
| | | | | (Bbls/d) | | |
| Crude oil pipeline | | | | | | |
| Wink pipeline | | 457 |
| | 145,000 |
| | West Texas to Western Refining’s refinery in El Paso, Texas |
_______
| |
| (a) | We do not operate Bravo pipeline. |
Oil and Gas Producing Activities
Oil Producing Interests
Our ownership interests in oil-producing fields located in the Permian Basin of West Texas include the following:
| | | | | | KM Gross | | | KMI Gross |
| | Working | | Developed | Working | | Developed |
| | Interest % | | Acres | Interest % | | Acres |
| SACROC | 97 |
| | 49,156 |
| 97 |
| | 49,156 |
|
| Yates | 50 |
| | 9,576 |
| 50 |
| | 9,576 |
|
Goldsmith Landreth San Andres(a) | 99 |
| | 6,166 |
| 99 |
| | 6,166 |
|
| Katz Strawn | 99 |
| | 7,194 |
| 99 |
| | 7,194 |
|
| Sharon Ridge | 14 |
| | 2,619 |
| 14 |
| | 2,619 |
|
| Tall Cotton (ROZ) | 100 |
| | 461 |
| 100 |
| | 641 |
|
| H.T. Boyd(b) | 21 |
| | n/a |
| |
| MidCross | 13 |
| | 320 |
| 13 |
| | 320 |
|
| Reinecke(c) | — |
| | 80 |
| |
| Reinecke(a) | | — |
| | 80 |
|
_______
| |
(c) | Working interest less than 1 percent. |
The following table sets forth productive wells, service wells and drilling wells in the oil and gas fields in which we owned interests as of December 31, 2015.2017. The oil and gas producing fields in which we own interests are located in the Permian Basin area of West Texas. When used with respect to acres or wells, “gross” refers to the total acres or wells in which we have a working interest, and “net” refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by us:
| | | | Productive Wells(a) | | Service Wells(b) | | Drilling Wells(c) | Productive Wells(a) | | Service Wells(b) | | Drilling Wells(c) |
| | Gross | | Net | | Gross | | Net | | Gross | | Net | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Crude Oil | 2,199 |
| | 1,415 |
| | 1,157 |
| | 910 |
| | 2 |
| | 2 |
| 2,327 |
| | 1,518 |
| | 1,412 |
| | 1,088 |
| | 27 |
| | 26 |
|
| Natural Gas | 5 |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| 5 |
| | 2 |
| | — |
| | — |
| | — |
| | — |
|
| Total Wells | 2,204 |
| | 1,417 |
| | 1,157 |
| | 910 |
| | 2 |
| | 2 |
| 2,332 |
| | 1,520 |
| | 1,412 |
| | 1,088 |
| | 27 |
| | 26 |
|
_______
| |
| (a) | Includes active wells and wells temporarily shut-in. As of December 31, 2015,2017, we did not operate any productive wells with multiple completions. |
| |
| (b) | Consists of injection, water supply, disposal wells and service wells temporarily shut-in. A disposal well is used for disposal of salt water into an underground formation; and an injection well is a well drilled in a known oil field in order to inject liquids and/or gases that enhance recovery. |
| |
| (c) | Consists of development wells in the process of being drilled as of December 31, 2015.2017. A development well is a well drilled in an already discovered oil field. |
The following table reflects our net productive wells that were completed in each of the years ended December 31, 2015, 20142017, 2016 and 2013:2015:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Productive | | | | | | | | | | |
| Development | 130 |
| | 83 |
| | 51 |
| 108 |
| | 40 |
| | 87 |
|
| Exploratory | 31 |
| | 26 |
| | 4 |
| | | 3 |
| | 20 |
|
| Total Productive | 161 |
| | 109 |
| | 55 |
| 108 |
| | 43 |
| | 107 |
|
| Dry Exploratory | — |
| | 1 |
| | — |
| — |
| | — |
| | — |
|
| Total Wells | 161 |
| | 110 |
| | 55 |
| 108 |
| | 43 |
| | 107 |
|
_______
Note: The above table includes wells that were completed during each year regardless of the year in which drilling was initiated, and does not include any wells where drilling and completion operations were not completedfinalized as of the end of the applicable year. A completed well refers to the installation of permanent equipment for the production of oil and gas. A development well is a well drilled in an already discovered oil field. A dry hole is reflected once the well has been abandoned and reported to the appropriate governmental agency.
The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2015:2017:
|
| | | | | |
| | Gross | | Net |
| Developed Acres | 75,572 |
| | 72,382 |
|
| Undeveloped Acres | 17,142 |
| | 14,952 |
|
| Total | 92,714 |
| | 87,334 |
|
_______
Note: As of December 31, 2015, we have no material amount of acreage expiring in the next three years. |
| | | | | |
| | Gross | | Net |
| Developed Acres | 75,752 |
| | 72,562 |
|
| Undeveloped Acres | 17,282 |
| | 15,351 |
|
| Total | 93,034 |
| | 87,913 |
|
See “Supplemental Information on Oil and Gas Activities (Unaudited)” for additional information with respect to operating statistics and supplemental information on ourOur oil and gas producing activities.activities are not significant and therefore, we do not include the supplemental information on oil and gas producing activities under Accounting Standards Codification Topic 932, Extractive Activities - Oil and Gas.
Gas and Gasoline Plant Interests
Operated gas plants in the Permian Basin of West Texas:
|
| | | | |
| | Ownership | | |
| | Interest % | | Source |
| Snyder gasoline plant(a) | 22 |
| | The SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and Cogdell units |
| Diamond M gas plant | 51 |
| | Snyder gasoline plant |
| North Snyder plant | 100 |
| | Snyder gasoline plant |
_______
| |
| (a) | This is a working interest, in addition, we have a 28% net profits interest. The average net to us does not include the value associated with the net profits interest. |
Sales and Transportation Activities
CO2 Segment Storage and Sales
Our principal market for CO2 is for injection into mature oil fields in the Permian Basin, where industry demand is expected to remain stable for the next several years. Our ownership of CO2 resources as of December 31, 2015 includes:
|
| | | | | | | | | |
| | Ownership Interest % | | Recoverable CO2 (Bcf) | | Compression Capacity (Bcf/d) | | Location |
Recoverable CO2 | | | | | | | |
| McElmo Dome unit(a)(b) | 45 | | 4,758 |
| | 1.5 |
| | Colorado |
| Doe Canyon Deep unit(a) | 87 | | 569 |
| | 0.2 |
| | Colorado |
| Bravo Dome unit | 11 | | 616 |
| | 0.3 |
| | New Mexico |
_______
| |
(b) | Recoverable CO2 estimate from currently approved projects only.
|
CO2 Segment Pipelines
The principal market for transportation on our CO2 pipelines is to customers, including ourselves, using CO2 for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to remain stable for the next several years. The tariffs charged on the Wink pipeline system are regulated by both the FERC and the Texas Railroad Commission and the Pecos Carbon Dioxide Pipeline’s tariffs are regulated by the Texas Railroad Commission. The tariff charged on the Cortez pipeline is based on a consent decree and the tariffs charged by our other CO2 pipelines are not regulated.
Our ownership of CO2 and crude oil pipelines as of December 31, 2015 includes:
|
| | | | | | | | | | |
| | Ownership Interest % | | Miles of Pipeline | | Transport Capacity(Bcf/d) | | Supply and Market Region |
CO2 pipelines | | | | | | | |
| Cortez pipeline | 50 |
| | 565 |
| | 1.3 |
| | McElmo Dome and Doe Canyon source fields to the Denver City, Texas hub |
| Central Basin pipeline | 100 |
| | 324 |
| | 0.7 |
| | Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers, and Pecos pipelines |
| Bravo pipeline(a) | 13 |
| | 218 |
| | 0.4 |
| | Bravo Dome to the Denver City, Texas hub |
| Canyon Reef Carriers pipeline | 98 |
| | 163 |
| | 0.3 |
| | McCamey, Texas, to the SACROC, Sharon Ridge, Cogdell and Reinecke units |
Centerline CO2 pipeline | 100 |
| | 113 |
| | 0.3 |
| | between Denver City, Texas and Snyder, Texas |
Eastern Shelf CO2 pipeline | 100 |
| | 91 |
| | 0.1 |
| | between Snyder, Texas and Knox City, Texas |
| Pecos pipeline(b) | 95 |
| | 25 |
| | 0.1 |
| | McCamey, Texas, to Iraan, Texas, delivers to the Yates unit |
| Goldsmith Landreth | 99 |
| | 3 |
| | 0.2 |
| | Goldsmith Landreth San Andres field in the Permian Basin of West Texas |
| | | | | | (Bbls/d) | | |
| Crude oil pipeline | | | | | | | |
| Wink pipeline | 100 |
| | 454 |
| | 145,000 |
| | West Texas to Western Refining’s refinery in El Paso, Texas |
_______
| |
(a) | We do not operate Bravo pipeline. |
| |
(b) | Acquired Chevron’s 26.01% partnership interest in December 2015. |
Competition
Our primary competitors for the sale of CO2 include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain CO2 resources, and Oxy U.S.A., Inc., which controls waste CO2 extracted from natural gas production in the Val Verde Basin of West Texas. Our ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other CO2 pipelines. We also compete with other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of CO2 to the Denver City, Texas market area.
Terminals
Our Terminals segment includes the operations of our refined petroleum product, crude oil, chemical, ethanol and other liquidsliquid terminal facilities (other than those included in the Products Pipelines segment) and all of our coal, petroleum coke, fertilizer, steel ores and other dry-bulk material services facilities, including all transload, engineering, conveying and other in-plant services.coal facilities. Our terminals are located throughout the U.S. and in portions of Canada. We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide expansion opportunities. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, we haveTerminals’ marine operations include Jones Act qualified product tankers that provide marine transportation of crude oil, condensate and refined petroleum products in thebetween U.S. ports. The following summarizes our Terminals segment assets, as of December 31, 2015:2017:
| | | | Number | | Capacity (MMBbl) | Number | | Capacity (MMBbl) |
Liquids terminals(a) | 52 |
| | 87.6 |
| 51 |
| | 87.4 |
|
| Bulk terminals | 59 |
| | n/a |
| 35 |
| | — |
|
| Jones Act qualified tankers | 8 |
| | 2.6 |
| |
| Jones Act tankers | | 16 |
| | 5.3 |
|
_______
| |
(a) | Includes 10 terminals acquired in February 2016. |
Competition
We are one of the largest independent operators of liquids terminals in the U.S,North America, based on barrels of liquids terminaling capacity. Our liquids terminals compete with other publicly or privately held independent liquids terminals, and terminals
owned by oil, chemical, pipeline, and pipelinerefining companies. Our bulk terminals compete with numerous independent terminal operators, terminals owned by producers and distributors of bulk commodities, stevedoring companies and other industrial companies opting not to outsource terminalterminaling services. In some locations, competitors are smaller, independent
operators with lower cost structures. Our Jones Act qualified product tankers compete with other Jones Act qualified vessel fleets.
Products Pipelines
Our Products Pipelines segment consists of our refined petroleum products, crude oil and condensate, and NGL pipelines and associated terminals, Southeast terminals, our condensate processing facility and our transmix processing facilities. The following summarizes our significant Products Pipelines segment assets we own and operate as of December 31, 2015:2017:
| | | | Ownership Interest % | | Miles of Pipeline | | Number of Terminals (a)(c) or locations | | Terminal Capacity(MMBbl) | | Supply and Market Region | |
| Plantation pipeline | 51 |
| | 3,182 |
| | | | | | Louisiana to Washington D.C. | |
| Asset (KMI ownership shown if not 100%) | | | Miles of Pipeline | | Number of Terminals (a) or locations | | Terminal Capacity(MMBbl) | | Supply and Market Region |
| Plantation pipeline (51%) | | | 3,182 |
| | — | | — | | Louisiana to Washington D.C. |
| West Coast Products Pipelines(b) | West Coast Products Pipelines(b) | | | | | | | | | | | | | | |
| Pacific (SFPP) | 100 |
| | 2,823 |
| | 13 |
| | 15.3 |
| | six western states | | 2,845 |
| | 13 |
| | 15.2 |
| | six western states |
| Calnev | 100 |
| | 570 |
| | 2 |
| | 2.1 |
| | Colton, CA to Las Vegas, NV; Mojave region | | 566 |
| | 2 |
| | 2.0 |
| | Colton, CA to Las Vegas, NV; Mojave region |
| West Coast Terminals | 100 |
| | 43 |
| | 7 |
| | 10.1 |
| | Seattle, Portland, San Francisco and Los Angeles areas | | 38 |
| | 7 |
| | 10.3 |
| | Seattle, Portland, San Francisco and Los Angeles areas |
| Cochin pipeline | 100 |
| | 1,877 |
| | 5 |
| | 1.1 |
| | three provinces in Canada and seven states in the U.S. | | 1,810 |
| | 3 |
| | 1.1 |
| | three provinces in Canada and seven states in the U.S. |
| KM Crude & Condensate pipeline | 100 |
| | 252 |
| | 5 |
| | 2.6 |
| | Eagle Ford shale field in South Texas (Dewitt County) to the Houston ship channel refining complex | | 264 |
| | 5 |
| | 2.6 |
| | Eagle Ford shale field in South Texas (Dewitt, Karnes, and Gonzales Counties) to the Houston ship channel refining complex |
| Double H Pipeline | 100 |
| | 511 |
| | | | | | Bakken shale in Montana and North Dakota to Guernsey, Wyoming | | 511 |
| | — | | — | | Bakken shale in Montana and North Dakota to Guernsey, Wyoming |
| Central Florida pipeline | 100 |
| | 206 |
| | 3 |
| | 3.1 |
| | Tampa to Orlando | | 206 |
| | 2 |
| | 2.4 |
| | Tampa to Orlando |
| Double Eagle pipeline | 50 |
| | 194 |
| | 2 |
| | 0.6 |
| | Live Oak County, Texas; Corpus Christi, Texas; Karnes County, Texas; and LaSalle County | |
| Parkway | 50 |
| | 140 |
| | | | | | interconnect at Collins with Plantation and Plantation markets | |
| Cypress pipeline | 50 |
| | 104 |
| | | | | | Mont Belvieu, Texas to Lake Charles, Louisiana | |
| Double Eagle pipeline (50%) | | | 204 |
| | 2 |
| | 0.6 |
| | Live Oak County, Texas; Corpus Christi, Texas; Karnes County, Texas; and LaSalle County |
| Cypress pipeline (50%) | | | 104 |
| | — | | — | | Mont Belvieu, Texas to Lake Charles, Louisiana |
| Southeast Terminals | 100 |
| | | | 32 |
| | 10.8 |
| | from Mississippi through Virginia, including Tennessee | | — | | 32 |
| | 10.7 |
| | from Mississippi through Virginia, including Tennessee |
| KM Condensate Processing Facility | | | — | | 1 |
| | 1.9 |
| | Houston Ship Channel, Galena Park, Texas |
| Transmix Operations | 100 |
| | | | 6 |
| | 1.5 |
| | Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; St. Louis, Missouri; and Greensboro, North Carolina | | — | | 5 |
| | 0.6 |
| | Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; St. Louis, Missouri; and Greensboro, North Carolina |
_______
| |
| (a) | The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending. |
| |
| (b) | Our West Coast Products Pipelines assets include interstate common carrier pipelines rate-regulated by the FERC, intrastate pipelines in the state of California rate-regulated by the CPUC, and certain non rate-regulated operations and terminal facilities. |
| |
(c) | Includes 5 terminals acquired in February 2016. |
Competition
Our Products Pipelines’ pipeline operations compete against proprietary pipelines owned and operated by major oil companies, other independent products pipelines, trucking and marine transportation firms (for short-haul movements of products) and railcars. Our Products Pipelines’ terminal operations compete with proprietary terminals owned and operated by major oil companies and other independent terminal operators, and our transmix operations compete with refineries owned by major oil companies and independent transmix facilities.
Kinder Morgan Canada
Our Kinder Morgan Canada business segment includes our 100% owned and operatedthe Trans Mountain pipeline system and a 25-mile Jet Fuel pipeline system. Effective with KML’s May 2017 IPO, the operating assets in our Kinder Morgan Canada segment are included in KML. Operating assets in our Terminals and Products Pipelines segments are also included in KML, in which we retain a controlling interest, and KML and these operating assets are included in our consolidated financial statements.
Trans Mountain Pipeline System
The Trans Mountain pipeline system (TMPL) originates at Edmonton, Alberta and transports crude oil and refined petroleum products to destinations in the interior and on the west coast of British Columbia. The Trans Mountain pipelineTMPL is 713 miles in length. We also own and operate a connecting pipeline that delivers crude oil to refineries in the state of Washington. The capacity of the line at Edmonton ranges from 300 MBbl/d when heavy crude oil represents 20% of the total throughput (which is a historically normal heavy crude oil percentage), to 400 MBbl/d with no heavy crude oil. The TMPL mainline is a common carrier pipeline, providing transportation services under a cost of service model that is negotiated with shippers and regulated by the NEB. Although Trans Mountain takes custody of its shippers’ products, it does not own any of the product it ships. The TMPL system has posted tariff rates that are available to all shippers based on a monthly contract which varies according to the type of product being shipped as well as receipt and delivery points. As such, it provides service to producers, marketers, refineries and terminals who sell or resell products to domestic markets, oil marketers and international shippers moving oil to such places as California, Washington State and Asia.
We also own and operate a connecting pipeline that delivers crude oil to refineries in the state of Washington referred to as the Puget Sound Pipeline System which is regulated by the FERC for tariffs and the U.S. Department of Transportation for safety and integrity.
TMEP
KML continues to move forward with its C$7.4 billion TMEP that upon completion would provide western Canadian crude oil producers with an additional 590 MBbl/d of shipping capacity and tidewater access to the western U.S. (most notably states of Washington, California and Hawaii) and global markets (most notably Asia). TMEP has firm transportation services agreements with 13 companies for a total of 707.5 MBbl/d based on a capacity of 890 MBbl/d (the maximum amount that Trans Mountain anticipated the NEB would authorize).
See “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—General—KML—TMEP Construction Progress.”
Jet Fuel Pipeline System
We also own and operate the approximate 25-mile aviation fuel pipeline that serves the Vancouver International Airport, located in Vancouver, British Columbia, Canada. The turbine fuel pipeline is referred to in this report as the Jet Fuel pipeline system. In addition to its receiving and storage facilities located at the Westridge Marine terminal, located in Port Metro Vancouver, the Jet Fuel pipeline system’s operations include a terminal at the Vancouver airport that consists of five jet fuel storage tanks with an overall capacity of 15 MBbl.
Competition
Although Trans Mountain is one of several pipeline alternatives for western Canadian crude oil and refined petroleum production, and it competes against other pipeline providers; however, it is the soleonly pipeline carrying crude oil and refined petroleum products from Alberta to the west coast. Furthermore, as demonstratedcoast, it is subject to competition resulting from the shipment of oil from the Western Canadian Sedimentary Basis (WCSB) to markets other than the Canadian and U.S. West Coast, including shipments to refineries in Ontario, the U.S. Midwest and the U.S. Gulf Coast. In addition, refineries in Washington State and California, which comprise an important point of sale on the U.S. West Coast, have, in the past, been supplied primarily by our previously announced expansion proposal, discussed abovecrude oil from the Alaska North Slope. As such, there has historically been some competitive pressure on supply originating from the WCSB for sale in “—(a) General Developmentthe states of Business—Recent Developments—Kinder Morgan Canada,” we believe thatWashington and California refinery markets. A further source of competition exists from the Trans Mountain pipeline facilities provide us the opportunity to execute on capacity expansionstransportation of oil to the west coast asCanadian West Coast by rail. We expect that such supply and demand conditions in the market for offshore exports continuesoil markets served from the Canadian West Coast will continue to develop.impact the long-term value and economics of the TMPL system.
In December 2013,Historically, the British Columbia MinistryJet Fuel pipeline has transported a significant proportion of Environment granted approval for a new, airport fuel consortium owned,the jet fuel terminal to be located nearused at the Vancouver International Airport. However, the airport also receives jet fuel through other means including trucks and an airport approved, and yet to be constructed, jet fuel barge-receiving terminal near the airport. The impact of this facility on our existing Jet Fuel pipeline system is uncertain at this time.systems’ supplying refinery was sold in 2017. As a result of that sale, we are unable to predict whether, and to what extent, that refinery will continue to supply jet fuel to the Jet Fuel pipeline. These developments have made it unclear how much jet fuel will continue to be available for shipment to the Vancouver International Airport by way of the Jet Fuel pipeline in the future. We continue to assess our options relating to our Jet Fuel pipeline assets.
Other
During 2015, our other segment activity primarily includes other miscellaneous assets and liabilities including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with legacy trading activities; and (iii) other miscellaneous legacy assets and liabilities.
Major Customers
Our revenue is derived from a wide customer base. For each of the years ended December 31, 2015, 20142017, 2016 and 2013,2015, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.
Our Texas Intrastate Natural Gas Pipeline operations (includes the operations of Kinder Morgan Tejas Pipeline LLC, Kinder Morgan Border Pipeline LLC, Kinder Morgan Texas Pipeline LLC, Kinder Morgan North Texas Pipeline LLC and the Mier-Monterrey Mexico pipeline system) buys and sells significant volumes of natural gas within the state of Texas, and, to a far lesser extent, the CO2 business segment also sells natural gas. Combined, total revenues from the sales of natural gas from the Natural Gas Pipelines and CO2 business segments in 2015, 20142017, 2016 and 20132015 accounted for 20%22%, 25%19% and 28%20%, respectively, of our total consolidated revenues. To the extent possible, we attempt to balance the pricing and timing of our natural gas purchases to our natural gas sales, and these contracts are often settled in terms of an index price for both purchases and sales. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.
Regulation
Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation - U.S. Operations
Some of our U.S. refined petroleum products and crude oil gathering and transmission pipelines are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain our tariffs on file with the FERC. Those tariffs set forth the rates we charge for providing gathering or transportation services on our interstate common carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness
of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.
On October 24, 1992, Congress passed the
The Energy Policy Act of 1992. The Energy Policy Act1992 deemed petroleum products pipeline tariff rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable or “grandfathered” under the ICA. The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. Certain rates on our Pacific operations’ pipeline system were subject to protest during the 365-day period established by the Energy Policy Act. Accordingly, certain of the Pacific pipelines’ rates have been, and continue to be, the subject of complaints with the FERC, as is more fully described in Note 17 “Litigation,“Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
Petroleum products pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. Cost-of-service ratemaking, market-based rates and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates.
Common Carrier Pipeline Rate Regulation - Canadian Operations
The Canadian portion of our crude oil and refined petroleum products pipeline systems is under the regulatory jurisdiction of the NEB. The National Energy Board Act gives the NEB power to authorize pipeline construction and to establish tolls and conditions of service. Our subsidiary Trans Mountain Pipeline, L.P. is the sole owner of our Trans Mountain crude oil and refined petroleum products pipeline system.
The toll charged for the portion of Trans Mountain’s pipeline system located in the U.S. falls under the jurisdiction of the FERC. For further information, see “—“—Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation - U.S. Operations” above.
Interstate Natural Gas Transportation and Storage Regulation
Posted tariff rates set the general range of maximum and minimum rates we charge shippers on our interstate natural gas pipelines. Within that range, each pipeline is permitted to charge discounted rates, so long as such discounts are offered to all similarly situated shippers and granted without undue discrimination. Apart from discounted rates offered within the range of tariff maximums and minimums, the pipeline is permitted to charge negotiated rates where the pipeline and shippers want rate certainty, irrespective of changes that may occur to the range of tariff-based maximum and minimum rate levels. Negotiated rates provide certainty to the pipeline and the shipper of agreed upon rates during the term of the transportation agreement, regardless of changes to the posted tariff rates. There are a variety of rates that different shippers may pay, but while the rates may vary by shipper and circumstance, pipelines must generally use the form of service agreement that is contained within their FERC approved tariff. Any deviation from the pro forma service agreements must be filed with the FERC and only certain types of deviations are acceptable to the FERC.
The FERC regulates the rates, terms and conditions of service, construction and abandonment of facilities by companies performing interstate natural gas transportation services, including storage services, under the Natural Gas Act of 1938. To a lesser extent, the FERC regulates interstate transportation rates, terms and conditions of service under the Natural Gas Policy Act of 1978. Beginning in the mid-1980’s, the FERC initiated a number of regulatory changes intended to ensure that interstate natural gas pipelines operated on a not unduly discriminatory basis and to create a more competitive and transparent environment in the natural gas marketplace. Among the most important of these changes were:
Order No. 436 (1985) which required open-access, nondiscriminatory transportation of natural gas;
Order No. 497 (1988) which set forth new standards and guidelines imposing certain constraints on the interaction between interstate natural gas pipelines and their marketing affiliates and imposing certain disclosure requirements regarding that interaction;
Order Nos. 587, et seq., Order No. 809 (1996-2015) which adopt regulations to standardize the business practices and communication methodologies of interstate natural gas pipelines to create a more integrated and efficient pipeline grid and wherein the CommissionFERC has incorporated by reference in its regulations standards for interstate natural gas
pipeline business practices and electronic communications that were developed and adopted by the North American Energy Standards Board (NAESB). Interstate natural gas pipelines are required to incorporate by reference or verbatim in their respective tariffs the applicable version of the NAESB standards;
Order No. 636 (1992) which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to “unbundle” or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies. Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for thetransportation services and storage services for natural gas commodity, transportation and storage)gas);
Order No. 637 (2000) which revised, among other things, FERC regulations relating to scheduling procedures, capacity segmentation, and pipeline penalties in order to improve the competitiveness and efficiency of the interstate pipeline grid; and
Order No. 717 (2008) amending the Standards of Conduct for Transmission Providers (the Standards of Conduct or the Standards) to make them clearer and to refocus the marketing affiliate rules on the areas where there is the greatest potential for abuse. The FERC standards of conduct address and clarify multiple issues with respect to the actions and operations of interstate natural gas pipelines and public utilities using a functional approach to ensure that natural gas transmission is provided on a nondiscriminatory basis, including (i) the definition of transmission function and transmission function employees; (ii) the definition of marketing function and marketing function employees; (iii) the definition of transmission function information and non-disclosure requirements regarding non-public information; (iv) independent functioning and no conduit requirements; (v) transparency requirements; and (vi) the interaction of FERC standards with the NAESB business practice standards. The Standards of Conduct rules also require that a transmission provider provide annual training on the standards of conduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information.
In addition to regulatory changes initiated by the FERC, the U.S. Congress passed the Energy Policy Act of 2005. Among other things, the Energy Policy Act amended the Natural Gas Act to: (i) prohibit market manipulation by any entity; (ii) direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce; and (iii) significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder.
CPUC Rate Regulation
The intrastate common carrier operations of our Pacific operations’ pipelines in California are subject to regulation by the CPUC under a “depreciated book plant” methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of the Pacific operations’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC. A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates also could arise with respect to its intrastate rates. The intrastate rates for movements in California on our SFPP and Calnev systems have been, and may in the future be, subject to complaints before the CPUC, as is more fully described in Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
Railroad Commission of Texas (RCT) Rate Regulation
The intrastate operations of our crude oil and liquids pipelines and natural gas pipelines and storage facilities in Texas are subject to regulation with respect to such intrastate transportation by the RCT. The RCT has the authority to regulate our rates, though it generally has not investigated the rates or practices of our intrastate pipelines in the absence of shipper complaints.
Mexico - Energy Regulatory Commission
The Mier-Monterrey Pipeline has a natural gas transportation permit granted by the Energy RegulatingRegulatory Commission (the Commission) that defines the conditions for the pipeline to carry out activity and provide natural gas transportation service. This permit expires in 2026.
This permit establishes certain restrictive conditions, including without limitationslimitation (i) compliance with the general conditions for the provision of natural gas transportation service; (ii) compliance with certain safety measures, contingency plans, maintenance plans and the official Mexican standards of Mexico regarding safety; (iii) compliance with the technical and economic specifications of the natural gas transportation system authorized by the Commission; (iv) compliance with certain technical
studies established by the Commission; and (v) compliance with a minimum contributed capital not entitled to withdrawal of at least the equivalent of 10% of the investment proposed in the project.
Mexico - National Agency for Industrial Safety and Environmental Protection (ASEA)
ASEA regulates environmental compliance and industrial and operational safety. The Mier-Monterrey Pipeline must satisfy and maintain ASEA’s requirements, including compliance with certain safety measures, contingency plans, maintenance plans and the official standards of Mexico regarding safety, including a Safety Administration Program.
Safety Regulation
We are also subject to safety regulations imposed by PHMSA, including those requiring us to develop and maintain pipeline Integrity Management programs to comprehensively evaluate areas along our pipelines and take additional measures to protect pipeline segments located in what are referred to as High Consequence Areas, or HCAs, where a leak or rupture could potentially do the most harm.
The ultimate costs of compliance with pipeline Integrity Management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional integrity threats and changes to the amount of pipe determined to be located in HCAs can have a significant impact on costs to perform integrity testing and repairs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by PHMSA regulations. These tests could result in significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.
The Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 or “PIPES Act of 2016” requires PHMSA, among others, to set minimum safety standards for underground natural gas storage facilities and allows states to go above those standards for intrastate pipelines. In compliance with the PIPES Act of 2016, we have implemented procedures for underground natural gas storage facilities.
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which was signed into law in 2012, increased penalties for violations of safety laws and rules and may result in the imposition of more stringent regulations in the next few
years. In 2012, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine maximum pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the Advisory Bulletin requirements, could significantly increase our costs. Additionally, failure to locate such records to verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines. There can be no assurance as to the amount or timing of future expenditures for pipeline Integrity Management regulation, and actual expenditures may be different from the amounts we currently anticipate. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Repair, remediation, and preventative or mitigating actions may require significant capital and operating expenditures.
From time to time, our pipelines may experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
We are also subject to the requirements of the Occupational Safety and Health Administration (OSHA) and other federal and state agencies that address employee health and safety. In general, we believe current expenditures are addressing the OSHA requirements and protecting the health and safety of our employees. Based on new regulatory developments, we may increase expenditures in the future to comply with higher industry and regulatory safety standards. However, such increases in our expenditures, and the extent to which they might be offset, cannot be estimated at this time.
State and Local Regulation
Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, pollution, protection of the environment, and human health and safety.
Marine Operations
The operation of tankers and marine equipment create maritime obligations involving property, personnel and cargo under General Maritime Law. These obligations create a variety of risks including, among other things, the risk of collision, which may precipitate claims for personal injury, cargo, contract, pollution, third party claims and property damages to vessels and facilities.
We are subject to the Jones Act and other federal laws that restrict maritime transportation (between U.S. departure and destination points) to vessels built and registered in the U.S. and owned and manned by U.S. citizens. As a result, we monitor the foreign ownership of our common stock and under certain circumstances, consistent with our certificate of incorporation,
we have the right to redeem shares of our common stock owned by non-U.S. citizens. If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels. Furthermore, from time to time, legislation has been introduced unsuccessfully in Congress to amend the Jones Act to ease or remove the requirement that vessels operating between U.S. ports be built and registered in the U.S. and owned and manned by U.S. citizens. If the Jones Act were amended in such fashion, we could face competition from foreign flagged vessels.
In addition, the U.S. Coast Guard and the American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flag operators than for owners of vessels registered under foreign flags of convenience. The Jones Act and General Maritime Law also provide damage remedies for crew members injured in the service of the vessel arising from employer negligence or vessel unseaworthiness.
The Merchant Marine Act of 1936 is a federal law that provides, upon proclamation by the U.S. President of a national emergency or a threat to the national security, the U.S. Secretary of Transportation the authority to requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our vessels were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire.
However, we would not be entitled to compensation for any consequential damages suffered as a result of such purchase or requisition.
Environmental Matters
Our business operations are subject to federal, state, provincial and local laws and regulations relating to environmental protection, pollution and human health and safety in the U.S. and Canada. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, or at or from our storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damages, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. Furthermore, new projects may require approvals and environmental analysis under federal and state laws, including the National Environmental Policy Act and the Endangered Species Act. The resulting costs and liabilities could materially and negatively affect our business, financial condition, results of operations and cash flows. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities.
Environmental and human health and safety laws and regulations are subject to change. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health. There can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.
In accordance with GAAP, we accrue liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. We have accrued liabilities for estimable and probable environmental remediation obligations at various sites, including multi-party sites where the EPA, or similar state or Canadian agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multi-party sites could increase or mitigate our actual joint and several liability exposures.
We believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or cash flows in any particular reporting period. We have accrued an environmental reserve in the amount of $284$279 million as of December 31, 2015.2017. Our aggregate reserve estimates rangeestimate ranges in value from approximately $284$279 million to approximately $457$443 million, and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability. For additional information related to environmental matters, see Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
Hazardous and Non-Hazardous Waste
We generate both hazardous and non-hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state and Canadian statutes. From time to time, the EPA and state and Canadian regulators consider the adoption of stricter disposal standards for non‑hazardous waste. Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations, may in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.
Superfund
The CERCLA or the Superfund law, and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons for releases of hazardous substances into the environment. These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any. Although petroleum is excluded from CERCLA’s definition of a hazardous substance, in the course of our ordinary operations, we have and will generate
materials that may fall within the definition of hazardous substance. By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any.
Clean Air Act
Our operations are subject to the Clean Air Act, its implementing regulations, and analogous state and Canadian statutes and regulations. The EPA regulations under the Clean Air Act contain requirements for the monitoring, reporting, and control of greenhouse gas emissions from stationary sources. For further information, see “—Climate Change” below.
Clean Water Act
Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the U.S. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal, state or Canadian authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention and response to oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state and Canadian laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release of oil.
EPA Revisions to Ozone National Ambient Air Quality Standard (NAAQS)
As required by the Clean Air Act, EPA establishes National Ambient Air Quality Standards (NAAQS) for how much pollution is permissible and then the states have to adopt rules so their air quality meets the NAAQS. In October 2015, EPA published a rule lowering the ground level ozone NAAQS from 75 ppb to a more stringent 70 ppb standard. This change triggers a process under which EPA will designate the areas of the country that are in or out of attainment with the new NAAQS standard. Then, certain states will have to adopt more stringent air quality regulations to meet the NAAQS standard. These new state rules, which are expected in 2020 or 2021, will likely require the installation of more stringent air pollution controls on newly installed equipment and possibly require retrofitting existing KMKMI facilities with air pollution controls. Given the nationwide implications of the new rule, it is expected that it will have financial impacts for each Kinder Morgan Business Unit.of our business units.
Climate Change
Studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and CO2, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of greenhouse gases. Various laws and regulations exist or are under development that seek to regulate the emission of such greenhouse gases, including the EPA programs to control
greenhouse gas emissions and state actions to develop statewide or regional programs. The U.S. Congress has in the past considered legislation to reduce emissions of greenhouse gases.
Beginning in December 2009, EPA published several findings and rulemakings under the Clean Air Act requiring the permitting and reporting of certain greenhouse gases including CO2 and methane. Our facilities are subject to these requirements. Operational and/or regulatory changes could require additional facilities to comply with greenhouse gas emissions reporting and permitting requirements. Additionally,For example, in September 2015,August 2016, the EPA published a proposed rule regarding the “Oil and Natural Gas Sector: Emission Standards for New and Modified Sources,” otherwise known as the Proposed New Source Performance Standard (NSPS) Part OOOOa Rule. If finalized, thisRule, became effective. This rule would beis the first federal rule under the Clean Air Act to regulate methane as a pollutant and would impose additional pollution control and work practice requirements on applicable Kinder MorganKMI facilities.
On October 23, 2015, the EPA published as a final rule the Clean Power Plan, which sets interim and final CO2CO2 emission performance rates for power generating units that fire coal, oil or natural gas. The final rule is the focus of legislative discussion in the U.S. Congress and litigation in federal court. On February 10, 2016, the U.S. Supreme Court stayed the final rule, effectively suspending the duty to comply with the rule until certain legal challenges are resolved. In October 2017, EPA proposed to repeal the Clean Power Plan. The ultimate resolution of the final rule’s validity remains uncertain. While we do not operate power plants that would be subject to the Clean Power Plan final rule, it remains unclear what effect the final rule, if it comes into force, might have on the anticipated demand for natural gas, including natural gas that we gather, process, store and transport.
At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already
have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. Although many of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that sources such as our gas-fired compressors and processing plants could become subject to related state regulations. Various states are also proposing or have implemented more strict regulations for greenhouse gases that go beyond the requirements of the EPA. Depending on the particular program, we could be required to conduct monitoring, do additional emissions reporting and/or purchase and surrender emission allowances.
Because our operations, including the compressor stations and processing plants, emit various types of greenhouse gases, primarily methane and CO2, such new legislation or regulation could increase the costs related to operating and maintaining the facilities. Depending on the particular law, regulation or program, we or our subsidiaries could be required to incur capital expenditures for installing new monitoring equipment of emission controls on the facilities, acquire and surrender allowances for the greenhouse gas emissions, pay taxes related to the greenhouse gas emissions and administer and manage a greenhouse gas emissions program. We are not able at this time to estimate such increased costs; however, as is the case with similarly situated entities in the industry, they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our or our subsidiaries’ pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond their control, including the outcome of future rate proceedings before the FERC or other regulatory bodies, and the provisions of any final legislation or other regulations. Any of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects.
Some climatic models indicate that global warming is likely to result in rising sea levels, increased intensity of hurricanes and tropical storms, and increased frequency of extreme precipitation and flooding. We may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather. To the extent these phenomena occur, they could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone regions. However, the timing and location of these climate change impacts is not known with any certainty and, in any event, these impacts are expected to manifest themselves over a long time horizon. Thus, we are not in a position to say whether the physical impacts of climate change pose a material risk to our business, financial position, results of operations or cash flows.
Because natural gas emits less greenhouse gas emissions per unit of energy than competing fossil fuels, cap-and-trade legislation or EPA regulatory initiatives such as the proposed Clean Power Plan could stimulate demand for natural gas by increasing the relative cost of fuels such as coal and oil. In addition, we anticipate that greenhouse gas regulations will increase demand for carbon sequestration technologies, such as the techniques we have successfully demonstrated in our enhanced oil recovery operations within our CO2 business segment. However, these positive effects on our markets may be offset if these same regulations also cause the cost of natural gas to increase relative to competing non-fossil fuels. Although we currently cannot predict the magnitude and direction of these impacts, greenhouse gas regulations could have material adverse effects on our business, financial position, results of operations or cash flows.
Department of Homeland Security
The Department of Homeland Security, referred to in this report as the DHS, has regulatory authority over security at certain high-risk chemical facilities. The DHS has promulgated the Chemical Facility Anti-Terrorism Standards and required all high-risk chemical and industrial facilities, including oil and gas facilities, to comply with the regulatory requirements of these standards. This process includes completing security vulnerability assessments, developing site security plans, and implementing protective measures necessary to meet DHS-defined, risk based performance standards. The DHS has not provided final notice to all facilities that it determines to be high risk and subject to the rule; therefore, neither the extent to which our facilities may be subject to coverage by the rules nor the associated costs to comply can currently be determined, but it is possible that such costs could be substantial.
Other
Employees
We employed 11,29010,897 full-time people at December 31, 2015,2017, including approximately 787801 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 20162018 and 2018.2022. We consider relations with our employees to be good.
Most of our employees are employed by us and a limited number of our subsidiaries and provide services to one or more of our business units. The direct costs of compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated to our subsidiaries. Our human resources department provides the administrative support necessary to implement these payroll and benefits services, and the related administrative costs are allocated to our subsidiaries pursuant to our board-approved expense allocation policy. The effect of these arrangements is that each business unit bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs.
Properties
We believe that we generally have satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties or the use of such properties in our businesses. Our terminals, storage facilities, treating and processing plants, regulator and compressor stations, oil and gas wells, offices and related facilities are located on real property owned or leased by us. In some cases, the real property we lease is on federal, state, provincial or local government land.
We generally do not own the land on which our pipelines are constructed. Instead, we obtain the right to construct and operate the pipelines on other people’s land for a period of time. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of a majority of the interests have been obtained. Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense. Permits also have been obtained from railroad companies to run along or cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. Some such permits require annual or other periodic payments. In a few minor cases, property for pipeline purposes was purchased in fee.
(d)(d) Financial Information about Geographic Areas
For geographic information concerning our assets and operations, see Note 16 “Reportable Segments” to our consolidated financial statements.
(e) Available Information
We make available free of charge on or through our internet website, at www.kindermorgan.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on or connected to our internet Websitewebsite is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
Item 1A. Risk Factors.
You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Risks Related to Operating our Business
Our businesses are dependent on the supply of and demand for the commoditiesproducts that we handle.
Our pipelines, terminals and other assets and facilities depend in part on continued production of natural gas, oil and other products in the geographic areas that they serve. Our business also depends in part on the levels of demand for oil, natural gas, NGL, refined petroleum products, CO2, coal, steel, chemicals and other products in the geographic areas to which our pipelines, terminals, shipping vessels and other facilities deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand.
Without additions to oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers may shut down production at lower product prices or higher
production costs, especially where the existing cost of production exceeds other extraction methodologies, such as in the Alberta oil sands. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our pipelines and related facilities may not be able to maintain existing volumes of throughput. Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire.
ChangesTrends in the business environment, such as the sharp decline in crude oil prices that began in 2014, an increase in production costs from higher feedstockdeclining or sustained low commodity prices, supply disruptions, or higher development costs, or high feedstock prices that adversely impact demand, could result in a slowing of supply to our pipelines, terminals and other assets. In addition, changes in the regulatory environment or governmental policies may have an impact on the supply of crude oil, natural gas, coal and other products.the products we handle. Each of these factors impacts our customers shipping through our pipelines or using our terminals, which in turn could impact the prospects of new contracts for transportation, terminaling or other midstream services, or renewals of existing contracts.
Implementation of new regulations or changes to existing regulations affecting the energy industry could reduce production of and/or demand for natural gas, crude oil, refined petroleumthe products coal and other hydrocarbons,we handle, increase our costs and have a material adverse effect on our results of operations and financial condition. We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the production of and/or demand for natural gas, crude oil refined petroleumthe products and other hydrocarbons.we handle.
Financial distress experienced byExpanding our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.
We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as hedging counterparties, joint venture partnersexisting assets and suppliers. Some of these counterparties may be highly leveraged and subject to their own operating, market and regulatory risks, and some are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness.
In 2015, severalconstructing new assets is part of our counterparties defaulted on their obligations to us, and some have filed for bankruptcy protection. We cannot provide any assurance that other financially distressed counterparties will not also default on their obligations to us or file for bankruptcy protection. If a counterparty files for bankruptcy protection, we likely would be unable to collect all, or even a significant portion, of amounts that they owe to us. Additional counterparty defaults and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations or cash flows. Furthermore, in the case of
financially distressed customers, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations, financial condition, and cash flows.
Our operating results may be adversely affected by unfavorable economic and market conditions.
Economic conditions worldwide have from time to time contributed to slowdowns in several industries, including the oil and gas industry, the steel industry, the coal industry and in specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions also may be affected by uncertain or changing economic conditions within that region. Volatility in commodity prices or changes in markets for a given commodity might also have a negative impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us. See “-Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.” In addition, decreases in the prices of crude oil, NGL and natural gas will have a negative impact on our operating results and cash flow. See “-The volatility of oil and natural gas prices could have a material adverse effect on our CO2 business segment and businesses within our Natural Gas Pipeline and Products Pipelines business segments.”
If global economic and market conditions (including volatility in commodity markets), or economic conditions in the U.S. or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition and results of operations.
growth strategy. Our ability to begin and complete construction on expansion and new buildnew-build projects may be inhibited by difficulties in obtaining, or our inability to obtain, permits and rights-of-way, as well as public opposition, cost overruns, inclement weather and other delays.
We regularly undertake major construction projects to expand our existing assets and to construct new assets. A variety of factors outside of our control, such as difficulties in obtaining permits and rights-of-way or other regulatory approvals, that can be exacerbated by public opposition to our projects, have caused, and may continue to cause, delays in our abilityconstruction projects. These factors can be exacerbated by public opposition to begin constructionour projects. Inclement weather, natural disasters and delays in performance by third-party contractors have also resulted in, and may continue to result in, increased costs or delays in construction. Significant cost overruns or delays, or our inability to obtain a required permit or right-of-way, could have a material adverse effect on our return on investment, results of operations and cash flows, and could result in project cancellations or limit our ability to pursue other growth opportunities.
Additionally, For example, our ability to continue and complete construction on the TMEP may be inhibited, delayed or stopped by a variety of factors (some of which may be outside of our control), including without limitation, inabilities to overcome challenges posed by or related to regulatory approvals by federal, provincial or municipal governments, difficulty in obtaining, or inability to obtain, permits (including those that are required prior to construction such as the permits required under the Species at Risk Act), land agreements, public opposition, blockades, legal and regulatory proceedings (including judicial reviews, injunctions, detailed route hearings and land acquisition processes), delays to ancillary projects that are required for the TMEP (including, with respect to power lines and power supply), increased costs and/or cost overruns and inclement weather or significant weather-related events.
We face competition from other pipelines and terminals, as well as other forms of transportation and storage.
Any current or future pipeline system or other form of transportation (such as barge, rail or truck) that delivers the products
we must obtain and maintainhandle into the rights to construct and operate pipelines on other owners’ land. If we were to lose these rights or be required to relocateareas that our pipelines serve could offer transportation services that are more desirable to shippers than
those we provide because of price, location, facilities or other factors. Likewise, competing terminals or other storage options
may become more attractive to our customers. To the extent that competitors offer the markets we serve with new
transportation or storage options, this could result in unused capacity on our pipelines and in our terminals. If pipeline capacity
remains unsubscribed, our ability to re-contract for expiring capacity at favorable rates or otherwise retain existing customers
could be impaired. We also could experience competition for the supply of the products we handle from both existing and
proposed pipeline systems; for example, several pipelines access many of the same areas of supply as our pipeline systems and
transport to destinations not served by us.
Our operating results may be adversely affected by unfavorable economic and market conditions.
Economic conditions worldwide have from time to time contributed to slowdowns in several industries, including the oil
and gas industry, the steel industry, the coal industry and in specific segments and markets in which we operate, resulting in
reduced demand and increased price competition for our products and services. Our operating results in one or more
geographic regions also may be affected by uncertain or changing economic conditions within that region. Volatility in
commodity prices or changes in markets for a given commodity might also have a negative impact on many of our customers,
which in turn could have a negative impact on their ability to meet their obligations to us. See “—Financial distress
experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.” In addition, decreases in the prices of crude oil, NGL and natural gas will have a negative impact on our operating results and cash flow. See “—The volatility of oil and natural gas prices could have a material adverse effect on our CO2 business segment and businesses within our Natural Gas Pipeline and Products Pipelines business segments.”
If global economic and market conditions (including volatility in commodity markets), or economic conditions in the U.S.
or other key markets become more volatile or deteriorate, we may experience material impacts on our business, financial
condition and results of operations.
Financial distress experienced by our customers or other counterparties could be negatively affected. In addition,have an adverse impact on us in the event
they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.
We are subjectexposed to the possibilityrisk of increased costs underloss in the event of nonperformance by our rental agreements with landowners, primarily through rental increasescustomers or other counterparties, such as
hedging counterparties, joint venture partners and renewalssuppliers. Some of expired agreements. Whetherthese counterparties may be highly leveraged and subject
to their own operating, market and regulatory risks, and some are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness.
In 2015 and 2016, several of our counterparties defaulted on their obligations to us, and some have filed for bankruptcy
protection. For more information regarding the impact to our operating results from customer bankruptcies, see Item 7
“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Segment Earnings Results—Terminals.” We cannot provide any assurance that other financially distressed counterparties will not also
default on their obligations to us or file for bankruptcy protection. If a counterparty files for bankruptcy protection, we likely
would be unable to collect all, or even a significant portion, of amounts that they owe to us. Additional counterparty defaults
and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations or cash
flows. Furthermore, in the powercase of eminent domain for our pipelines, other than interstate natural gas pipelines, varies from statefinancially distressed customers, such events might force such customers to state depending upon the type of pipeline-petroleum liquids, natural gas, CO2,reduce or crude oil-and the laws of the particular state. Our interstate natural gas pipelines have federal eminent domain authority. In either case, we must compensate landowners for thecurtail
their future use of their propertyour products and in eminent domain actions, such compensation may be determined byservices, which could have a court. Our inability to exercise the powermaterial adverse effect on our results of eminent domain could negatively affect our business if we were to lose the right to use or occupy any of the properties on which our pipelines are located.operations, financial
condition, and cash flows.
The acquisition of additional businesses and assets is part of our growth strategy. We may experience difficulties integrating
integrating new propertiesbusinesses and businesses,properties, and we may be unable to achieve the benefits we expect from any future
acquisitions.
Part of our business strategy includes acquiring additional businesses and assets. If we do not successfully integrate
acquisitions, we may not realize anticipated operating advantages and cost savings. Integration of acquired companies or assets
involves a number of risks, including (i) demands on management related to the increase in our size; (ii) the diversion of
management’s attention from the management of daily operations; (iii) difficulties in implementing or unanticipated costs of
accounting, estimating,budgeting, reporting, internal controls and other systems; and (iv) difficulties in the retention and assimilation and retention of
necessary employees.
We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve
separately. Successful integration of each acquisition will depend upon our ability to manage those operations and to eliminate
redundant and excess costs. Difficulties in integration may be magnified if we make multiple acquisitions over a relatively short period of time. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.
We face competition from other pipelines and other forms of transportation into the areas we serve as well as with respect to the supply for our pipeline systems.
Any current or future pipeline system or other formWe do not own substantially all of transportation that delivers crude oil, petroleum products or natural gas into the areas thatland on which our pipelines serve could offer transportation services that are more desirablelocated. If we are unable to shippers than those we provide because of price, location, facilities or other factors. To the extent that an excess of supply into these areas is createdprocure and persists,maintain access to land owned by third parties, our revenue and operating costs, and our ability to re-contract for expiring transportation capacity at favorable rates or otherwise to retain existing customerscomplete construction projects, could be impaired. adversely affected.
We also could experience competitionmust obtain and maintain the rights to construct and operate pipelines on other owners’ land, including private landowners, railroads, public utilities and others. While our interstate natural gas pipelines in the U.S. have federal eminent domain authority, the availability of eminent domain authority for our other pipelines varies from state to state depending upon the type of pipeline—petroleum liquids, natural gas, CO2, or crude oil—and the laws of the particular state. We likewise must obtain approval from various governmental entities to construct and operate our pipelines in Canada, particularly for the supplyTMEP. In any case, we must compensate landowners for the use of petroleum productstheir property, and in eminent domain actions, such compensation may be determined by a court. If we are unable to obtain rights-of-way on acceptable terms, our ability to complete
construction projects on time, on budget, or natural gas from both existingat all, could be adversely affected. In addition, we are subject to the possibility of increased costs under our right-of-way or rental agreements with landowners, primarily through renewals of expiring agreements and proposed pipeline systems. Severalrental increases. If we were to lose these rights, our operations could be disrupted or we could be required to relocate the affected pipelines, access many of the same areas of supply aswhich could cause a substantial decrease in our pipeline systemsrevenues and transport to destinations not served by us.cash flows and an increase in our costs.
Commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect our operations.
There are a variety of hazards and operating risks inherent to transportation and storage of crude oil, natural gas, refined petroleumthe products CO2, coal, chemicals and other products -suchwe handle, such as leaks, releases, explosions, mechanical problems and damage caused by third parties. Additional risks to vessels include adverse sea conditions, capsizing, grounding and navigation errors. These risks could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution and impairment of operations, any of which also could result in substantial financial losses.losses, negatively impact our reputation and increase public opposition to our expansion or new build projects. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks may be greater. Incidents that cause an interruption of service, such as when unrelated third party construction damages a pipeline or a newly completed expansion experiences a weld failure, may negatively impact our revenues and cash flows while the affected asset is temporarily out of service. In addition, losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition and results of operations.
The volatility of oil, NGL and natural gas prices could adversely affect our CO2CO2 business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.
The revenues, cash flows, profitability and future growth of some of our businesses depend to a large degree on prevailing oil, NGL and natural gas and NGL prices. Our CO2CO2 business segment (and the carrying value of its oil, NGL and natural gas producing properties) and certain midstream businesses within our Natural Gas Pipelines segment depend to a large degree, and certain businesses within our Product Pipelines segment depend to a lesser degree, on prevailing oil, NGL and natural gas prices. For 2016,2018, we estimate that every $1 change in the average WTI crude oil price per barrel would impact our distributable cash flowDCF by approximately $6.5$7 million and each $0.10 per MMBtu change in the average price of natural gas impacts distributable cash flowwould impact DCF by approximately $0.6 million, and every 1% change in the ratio of the weighted-average NGL price per barrel to the WTI crude oil price per barrel impacts distributable cash flow by approximately $2.0$1 million.
Prices for oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil, NGL and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) the condition of the U.S. economy; (iii) the activities of the Organization of Petroleum Exporting Countries; (iv) governmental regulation; (v) political instability in the Middle East and elsewhere; (vi) the foreign supply of and demand for oil and natural gas; (vii) the price of foreign imports; and (viii) the availability of alternative fuel sources. We use hedging arrangements to partially mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks. Please read “- “—Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.”
A sharp decline in the prices of oil, NGL or natural gas, or a prolonged unfavorable price environment, would result in a commensurate reduction in our revenues, income and cash flows from our businesses that produce, process, or purchase and sell oil, NGL, or natural gas, and could have a material adverse effect on the carrying value of our CO2CO2 business segment’s proved reserves. If prices fall substantially or remain low for a sustained period and we are not sufficiently protected through hedging arrangements, we may be unable to realize a profit from these businesses and would operate at a loss.
In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The excess or short supply of crude oil or natural gas has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively
short periods of seasonal market demand. These fluctuations impact the accuracy of assumptions used in our budgeting process. For more information about our energy and commodity market risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk-Energy Commodity Market Risk.”
The future success of our oil and gas development and production operations depends in part upon our ability to develop additional oil and gas reserves that are economically recoverable.
The rate of production from oil and natural gas properties declines as reserves are depleted. Without successful development activities, the reserves, revenues and cash flows of the oil and gas producing assets within our CO2CO2 business segment will decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. Additionally, if we do not realize production volumes greater than, or equal to, our hedged volumes, we may suffer financial losses not offset by physical transactions.
The development of oil and gas properties involves risks that may result in a total loss of investment.
The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational and market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions, may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.
Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.
We engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil, NGL and natural gas. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and natural gas.
The markets for instruments we use to hedge our commodity price exposure generally reflect then-prevailing conditions in the underlying commodity markets. As our existing hedges expire, we will seek to replace them with new hedging arrangements. To the extent underlying market conditions are unfavorable, new hedging arrangements available to us will reflect such unfavorable conditions.
The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at the dates of those statements. In addition, it ismay not be possible for us to engage in hedging transactions that completely eliminate our exposure to commodity prices. Ourprices; therefore, our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For more information about our hedging activities, see Item 7 “Management’s“Management’s Discussion and Analysis of Financial Condition and Results of Operations-CriticalOperations—Critical Accounting Policies and Estimates-HedgingEstimates—Hedging Activities” and Note 1314 “Risk Management” to our consolidated financial statements.
A breach of information security or failure of one or more key information technology or operational (IT) systems, or those of third parties, may adversely affect our business, results of operation or harm our business reputation.
Our business is dependent upon our operational systems to process a large amount of data and complex transactions. The
various uses of these IT systems, networks and services include, but are not limited to, controlling our pipelines and terminals
with industrial control systems, collecting and storing information and data, processing transactions, and handling other
processing necessary to manage our business.
If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial
costs to repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to
perform critical functions, which could adversely affect our business and results of operations. A significant failure,
compromise, breach or interruption in our systems could result in a disruption of our operations, customer dissatisfaction,
damage to our reputation and a loss of customers or revenues. Efforts by us and our vendors to develop, implement and
maintain security measures may not be successful in preventing these events from occurring, and any network and information
systems-related events could require us to expend significant resources to remedy such event. Although we believe that we have robust information security procedures and other safeguards in place, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.
Terrorist attacks, or “cyber security” events,including cyber sabotage, or the threat of them,such attacks, may adversely affect our business.business or harm our business reputation.
The U.S. government has issued public warnings that indicate that pipelines and other infrastructure assets might be specific targets of terrorist organizations or “cyber security”sabotage” events. These potential targets might include our pipeline systems, terminals, processing plants or operating systems. A cyber security event could affect our ability to operate or control our facilities or disrupt our operations; also, customer information could be stolen. The occurrence of one of these eventsa terrorist attack could
cause a substantial decrease in revenues and cash flows, increased costs to respond or other financial loss, damage to our reputation, increased regulation or litigation or inaccurate information reported from our operations. There is no assurance that adequate cyber sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.condition or harm our business reputation.
Hurricanes, earthquakes and other natural disasters could have an adverse effect on our business, financial condition and results of operations.
Some of our pipelines, terminals and other assets are located in, and our shipping vessels operate in, areas that are susceptible to hurricanes, earthquakes and other natural disasters. These natural disasters could potentially damage or destroy our assets and disrupt the supply of the products we transport. In the third quarter of 2017, Hurricane Harvey caused
disruptions in our operations and, as of December 31, 2017, we had incurred $27 million in repair costs to our assets near the Texas Gulf Coast. For more information regarding the impact of Hurricane Harvey on our assets and operating results, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Natural disasters can similarly affect the facilities of our customers. In either case, losses could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected, perhaps materially.
Our business requires the retention and recruitment of a skilled workforce, and the loss of suchdifficulties recruiting and retaining our workforce could result in thea failure to implement our business plans.
Our operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible and have significant institutional knowledge that must be transferred to other employees. If we are unable to (i) retain current employees; (ii) successfully complete the knowledge transfer; and/or (iii) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased allocated costs to retain and recruit these professionals.
The increased financial reporting and other obligations of management resulting from KML’s obligations as a public company may divert management’s attention away from other business operations.
KML, in which we own an approximate 70% interest, completed its IPO in Canada in May of 2017. Certain of our officers and directors also serve as officers and directors of KML, and we provide financial reporting support and other services as requested by KML and its controlled affiliates pursuant to a Services Agreement. The increased obligations associated with providing support to KML as a public company may divert our management’s attention from other business concerns and may adversely affect our business, financial condition and results of operations. We are subject to financial reporting and other obligations that place significant demands on our management, administrative, operational, legal, internal audit and accounting resources. The demands on our personnel will be intensified as they comply with the additional obligations applicable to KML.
If we are unable to retain our executive chairman, chief executive officer or other executive officers, our ability to execute our business strategy, including our growth strategy, may be hindered.
Our success depends in part on the performance of and our ability to retain our executive chairman and our executive officers, particularly Richard D. Kinder, our Executive Chairman and one of our founders, and Steve Kean, our President and Chief Executive Officer. Along with the other members of our senior management, Mr. Kinder and Mr. Kean have been responsible for developing and executing our growth strategy. If we are not successful in retaining Mr. Kinder, Mr. Kean or our other executive officers, or replacing them, our business, financial condition or results of operations could be adversely affected. We do not maintain key personnel insurance.
Our Kinder Morgan Canada and Terminals segments are subject to U.S. dollar/Canadian dollar exchange rate fluctuations.
We are a U.S. dollar reporting company. As a result of the operations of our Kinder Morgan Canada and Terminals
business segments, a portion of our consolidated assets, liabilities, revenues, cash flows and expenses are denominated in Canadian dollars. Fluctuations in the exchange rate between U.S. and Canadian dollars could expose us to reductions in the U.S. dollar value of our earnings and cash flows and a reduction in our stockholders’ equity under applicable accounting rules.
Risks Related to Financing Our Business
Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.
As of December 31, 2015,2017, we had approximately $41$36.9 billion of consolidated debt (excluding debt fair value adjustments). Additionally, we and substantially all of our wholly owned U.S. subsidiaries are parties to a cross guarantee agreement under which each party to the agreement unconditionally guarantees the indebtedness of each other party, which means that we are liable for the debt of each of such subsidiaries. This level of consolidated debt and the cross guarantee agreement could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth, or for other purposes; (ii) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.
Our ability to service our consolidated debt, and our ability to meet our consolidated leverage targets, 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, many of which are beyond our control. If our consolidated cash flow is not sufficient to service our consolidated debt, and any future indebtedness that we incur, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may also take such actions to reduce our indebtedness if we determine that our earnings (or consolidated earnings before interest, taxes, depreciation and amortization, or EBITDA, as calculated in accordance with our revolving credit facility) may not be sufficient to meet our consolidated leverage targets, or to comply with consolidated leverage ratios required under certain of our debt agreements. We may not be able to effect any of these actions on satisfactory terms or at all. For more information about our debt, see Note 89 “Debt” to our consolidated financial statements.
Our business, financial condition and operating results may be affected adversely by increased costs of capital or a reduction in the availability of credit.
Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings (which would have a corresponding impact on the credit ratings of our subsidiaries that are party to the cross guarantee) could cause our cost of doing business to increase by limiting our access to capital, limitingincluding our ability to refinance maturities of existing indebtedness on similar terms, which could in turn limit our ability to pursue acquisition or expansion opportunities and reducingreduce our cash flows. Our credit ratings may be impacted by our leverage, liquidity, credit profile and potential transactions. Although the ratings from credit agencies are not recommendations to buy, sell or hold our securities, our credit ratings will generally affect the market value of our and our subsidiaries’ debt securities and the terms available to us for future issuances of debt securities.
Also, disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations on favorable terms. A significant reduction in the availability of credit could materially and adversely affect our business, financial condition and results of operations.
Our acquisition strategyKML and its subsidiaries are not part of the cross guarantee and are rated separately by credit rating agencies. However, because of our approximate 70% ownership interest in KML, we could be indirectly affected if KML experiences material adverse changes in its credit ratings or access to capital.
Acquisitions and growth capital expenditures may require access to external capital. Limitations on our access to external financing sources could impair our ability to grow.
We have limited amounts of internally generated cash flows to fund acquisitions and growth capital expenditures. We may have to rely on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund our acquisitions and growth capital expenditures. Limitations on our access to external financing sources, whether due to tightened capital markets, more expensive capital or otherwise, could impair our ability to execute our growth strategy.
Our large amount of variable rate debt makes us vulnerable to increases in interest rates.
As of December 31, 2015,2017, approximately $11$10.4 billion of our approximately $41$36.9 billion of consolidated debt (excluding debt fair value adjustments) was subject to variable interest rates, either as short-term or long-term variable-rate debt obligations, or as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps. Should interest rates increase, the amount of cash required to service this debt would increase, and our earnings and cash flows could be adversely affected. For more information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk-Interest Rate Risk.”
Our debt instruments may limit our financial flexibility and increase our financing costs.
The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that we deem beneficial and that may be beneficial to us. Some of the agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (i) incurring additional debt; (ii) entering into mergers, consolidations and sales of assets; (iii) granting liens; and (iv) entering into sale-leaseback transactions. The instruments governing any future debt may contain similar or more restrictivelimiting restrictions. Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.
Risks Related to Ownership of Our Capital Stock
The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.
We disclose in this report and elsewhere the expected cash dividends on our common stock and on our preferred stock (or depositary shares). This reflectsThese reflect our current judgment, but as with any estimate, itthey may be affected by inaccurate assumptions and known and unknownother risks and uncertainties, many of which are beyond our control. See “Information Regarding Forward-Looking Statements.”Statements” at the beginning of this report. If the payment ofwe elect to pay dividends at the anticipated levelslevel and that action would leave us with insufficient cash to take timely
advantage of growth opportunities (including through acquisitions), to meet any large unanticipated liquidity requirements, to fund our operations, to maintain our leverage metrics or otherwise to address properly our business prospects, our business wouldcould be harmed.
Conversely, a decision to address such needs might lead to the payment of dividends below the anticipated levels. As events present themselves or become reasonably foreseeable, our board of directors, which determines our business strategy and our dividends, might havemay decide to choose between addressingaddress those matters andby reducing our anticipated dividends. Alternatively, because nothing in our governing documents or credit agreements prohibits us from borrowing to pay dividends, our board of directors maywe could choose to cause us to incur debt to enable us to pay our anticipated dividends. This would add to our substantial debt discussed belowabove under “-Risks“—Risks Related to Financing Our Business-OurBusiness—Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic consequences.conditions.”
Our certificate of incorporation restricts the ownership of our common stock by non-U.S. citizens within the meaning of the Jones Act. These restrictions may affect the liquidity of our common stock and may result in non-U.S. citizens being required to sell their shares at a loss.
The Jones Act requires, among other things, that at least 75% of our common stock be owned at all times by U.S. citizens, as defined under the Jones Act, in order for us to own and operate vessels in the U.S. coastwise trade. As a safeguard to help us maintain our status as a U.S. citizen, our certificate of incorporation provides that, if the number of shares of our common stock owned by non-U.S. citizens exceeds 22%, we have the ability to redeem shares owned by non-U.S. citizens to reduce the percentage of shares owned by non-U.S. citizens to 22%. These redemption provisions may adversely impact the marketability of our common stock, particularly in markets outside of the United States.U.S. Further, stockholders would not have control over the timing of such redemption, and may be subject to redemption at a time when the market price or timing of the redemption is disadvantageous. In addition, the redemption provisions might have the effect of impeding or discouraging a merger, tender offer or proxy contest by a non-U.S. citizen, even if it were favorable to the interests of some or all of our stockholders.
Risks Related to Regulation
New laws, policies, regulations, rulemaking and oversight, as well as changes to those currently in regulations, by regulatory agencies having jurisdiction over our operationseffect, could adversely impact our earnings, cash flows and operations.
Our assets and operations are subject to regulation and oversight by federal, state, provincial and local regulatory authorities. RegulatoryLegislative changes, as well as regulatory actions taken by these agencies, have the potential to adversely affect our profitability. In addition, a certain degree of regulatory uncertainty is created by the current U.S. presidential administration because it remains unclear specifically what the current administration may do with respect to future policies and regulations that may affect us. Regulation affects almost every part of our business and extends to such matters as (i) federal, state, provincial and local taxation; (ii) rates (which include tax, reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (ii)(iii) the types of services we may offer to our customers; (iii)(iv) the contracts for service entered into with our customers; (iv)(v) the certification and construction of new facilities; (v)(vi) the integrity, safety and security of facilities and operations; (vi)(vii) the acquisition of other businesses; (vii)(viii) the acquisition, extension, disposition or abandonment of services or facilities; (viii)(ix) reporting and information posting requirements; (ix)(x) the maintenance of accounts and records; and (x)(xi) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.
Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines and potential loss of government contracts. Furthermore, new laws, regulations or regulationspolicy changes sometimes arise from unexpected sources. New laws or regulations, unexpected policy changes or different interpretations of existing laws or regulations, including unexpected policy changes,the 2017 Tax Reform, applicable to usour income, operations, assets or another aspect of our assetsbusiness, could have a material adverse impact on our business,earnings, cash flow, financial condition and results of operations. For more information, see Items 1 and 2 “Business and Properties-Properties—(c) Narrative Description of Business-Regulation.Business—Regulation.”
The FERC, the CPUC, or the NEB may establish pipeline tariff rates that have a negative impact on us. In addition, the FERC, the CPUC, the NEB, or our customers could initiate proceedings or file complaints challenging the tariff rates charged by our pipelines, and a successful complaintwhich could have an adverse impact on us.
The profitability of our regulated pipelines is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that our costs increase in an amount greater than what we are permitted by the FERC, the CPUC, or the NEB to recover in our rates, or to the extent that there is a lag before we can file for and obtain rate increases, such events can have a negative impact uponon our operating results.
Our existing rates may also be challenged by complaint. Regulators and shippers on our pipelines have rights to challenge, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the regulators that seek substantial refunds for alleged overcharges during the years in
question and prospective reductions in the tariff rates. Further, the FERC may continue to initiate investigations to determine whether interstate natural gas pipelines have over-collected on rates charged to shippers. We may face challenges, similar to those described in Note 1617 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements, to the rates we charge on our pipelines. In addition, following the 2017 Tax Reform, which reduced the corporate tax rate from 35% to 21%, various industry groups have petitioned the FERC to consider action with respect to tax recovery in existing jurisdictional rates. Any successful challenge to our rates could materially adversely affect our future earnings, cash flows and financial condition.
Environmental, health and safety laws and regulations could expose us to significant costs and liabilities.
Our operations are subject to federal, state, provincial and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health and safety. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals. Liability under such laws and regulations may be incurred without regard to fault under CERCLA, the Resource Conservation and Recovery Act, the Federal Clean Water Act, the Oil Pollution Act or analogous state or provincial laws as a result of the presence or release of hydrocarbons and other hazardous substances into or through the environment, and these laws may require response actions and remediation and may impose liability for the remediation of contaminated areas.natural resource and other damages. Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us.
Failure to comply with these laws and regulations also may expose us to civil, criminal and administrative fines, penalties and/or interruptions in our operations that could influence our business, financial position, results of operations and prospects. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, shipping vessels or storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up or otherwise respond to the leak, release or spill, pay for government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our earnings and cash flows. In addition, emission controls required under the Federal Clean Air Act and other similar federal, state and provincial laws could require significant capital expenditures at our facilities.
We own and/or operate numerous properties that have been used for many years in connection with our business activities. While we believe we have utilized operating, handling, and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws in the U.S. such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under the regulatory schemes of the various Canadian provinces, such as British Columbia’s Environmental Management Act, Canada has similar laws with respect to properties owned, operated or used by us or our predecessors. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.
Further, we cannot ensure that such existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. 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. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects. For more information, see Items 1 and 2 “Business“Business and Properties-(c) Narrative Description of Business-EnvironmentalBusiness—Environmental Matters.”
Increased regulatory requirements relating to the integrity of our pipelines may require us to incur significant capital and operating expense outlays to comply.
We are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal guidelines issued by the DOT for pipeline companies in the areas of testing, education, training and communication. The ultimate costs of compliance with the integrity management rules are difficult to predict. The majority of compliance costs relate to pipeline integrity testing and repairs. Technological advances in in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipeline determined to be located in “High Consequence Areas” can have a significant impact on integrity testing and repair costs. We plan to continue our integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the DOT rules. The results of these tests could cause
us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.
Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.
Climate change and related regulation at the federal, state, provincial or regional levels could result in significantly increased operating and capital costs for us and could reduce demand for our products and services.
Various laws and regulations exist or are under development that seek to regulate the emission of greenhouse gases such as methane and CO2,CO2, including the EPA programs to control greenhouse gas emissions and state actions to develop statewide or regional programs. Existing EPA regulations require us to report greenhouse gas emissions in the U.S. from sources such as our larger natural gas compressor stations, fractionated NGL, and production of naturally occurring CO2CO2 (for example, from our McElmo Dome CO2CO2 field), even when such production is not emitted to the atmosphere. Proposed approaches to further regulate greenhouse gas emissions include establishing greenhouse gas “cap and trade” programs, increased efficiency standards, and incentives or mandates for pollution reduction, use of renewable energy sources, or use of alternative fuels with lower carbon content. For more information about climate change regulation, see Items 1 and 2 “Business and Properties-Properties—(c) Narrative Description of Business-Environmental Matters-ClimateBusiness-Environmental Matters—Climate Change.”
Adoption of any such laws or regulations could increase our costs to operate and maintain our facilities and could require us to install new emission controls on our facilities, acquire allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program, and such increased costs could be significant. Recovery of such increased costs from our customers is uncertain in all cases and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC. Such laws or regulations could also lead to reduced demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, which in turn could adversely affect demand for our products and services.
Finally, some climatic models indicate that global warming is likely to result in rising sea levels and increased frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas subject to severe weather. To the extent these phenomena occur, they could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone regions.
Any of the foregoing could have adverse effects on our business, financial position, results of operations or cash flows.
Increased regulation of exploration and production activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, as well as reductions in production from existing wells, which could adversely impact the volumes of natural gas transported on our natural gas pipelines and our own oil and gas development and production activities.
We gather, process or transport crude oil, natural gas or NGL from several areas in which the use of hydraulic fracturing is prevalent. Oil and gas development and production activities are subject to numerous federal, state, provincial and local laws and regulations relating to environmental quality and pollution control. The oil and gas industry is increasingly relying on supplies of hydrocarbons from unconventional sources, such as shale, tight sands and coal bed methane. The extraction of hydrocarbons from these sources frequently requires hydraulic fracturing. Hydraulic fracturing involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate gas production and is a commonly used stimulation process employed by oil and gas exploration and production operators in the completion of certain oil and gas wells. There have been initiatives at the federal and state levels to regulate or otherwise restrict the use of hydraulic fracturing. Adoption of legislation or regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of crude oil, natural gas or NGL and, in turn, adversely affect our revenues, cash flows and results of operations by decreasing the volumes of these commodities that we handle.
In addition, many states are promulgating stricter requirements not only for wells but also compressor stations and other facilities in the oil and gas industry sector. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, these activities are subject to laws and regulations
regarding the acquisition of permits before drilling, restrictions on drilling activities and location, emissions into the environment, water discharges, transportation of hazardous materials, and storage and disposition of wastes. In addition,
legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. These laws and regulations may adversely affect our oil and gas development and production activities.
Derivatives regulation could have an adverse effect on our ability to hedge risks associated with our business.
The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the OTC derivatives market and entities that participate in that market. TheIn December 2016, the CFTC has proposedre-proposed new rules pursuant to the Dodd-Frank Act that would institute broad new aggregate position limits for OTC swaps and futures and options traded on regulated exchanges. As the law favors exchange trading and clearing, the Dodd-Frank Act also may require us to move certain derivatives transactions to exchanges where no trade credit is provided. The Dodd-Frank Act, related regulations and the reduction in competition due to derivatives industry consolidation have (i) significantly increased the cost of derivative contracts (including those requirements to post collateral, which could adversely affect our available liquidity); (ii) reduced the availability of derivatives to protect against risks we encounter; and (iii) reduced the liquidity of energy related derivatives.
If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues and cash flows could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial condition and results of operations.
The Jones Act includes restrictions on ownership by non-U.S. citizens of our U.S. point to point maritime shipping vessels, and failure to comply with the Jones Act, or changes to or a repeal of the Jones Act, could limit our ability to operate our vessels in the U.S. coastwise trade, result in the forfeiture of our vessels or otherwise adversely impact our earnings, cash flows and operations.
We are subject to the Jones Act, which generally restricts U.S. point-to-point maritime shipping to vessels operating under the U.S. flag, built in the U.S., owned and operated by U.S.-organized companies that are controlled and at least 75% owned by U.S. citizens and manned by predominately U.S. crews. Our business would be adversely affected if we fail to comply with the Jones Act provisions on coastwise trade. If we do not comply with any of these requirements, we would be prohibited from operating our vessels in the U.S. coastwise trade and, under certain circumstances, we could be deemed to have undertaken an unapproved transfer to non-U.S. citizens that could result in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of vessels. Our business could be adversely affected if the Jones Act were to be modified or repealed so as to permit foreign competition that is not subject to the same U.S. government imposed burdens.
Item 1B. Unresolved Staff Comments.
None.
Item 3. Legal Proceedings.
See Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
Item 4. Mine Safety Disclosures.
The information concerningWe no longer own or operate mines for which reporting requirements apply under the mine safety violations or other regulatory matters required by Section 1503(a)disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104)(Dodd-Frank), except for one terminal that is in exhibit 95.1temporary idle status with the Mine Safety and Health Administration. We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to this annual report.the mine safety disclosure requirements of Dodd-Frank for the year ended December 31, 2017.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our Class P common stock is listed for trading on the NYSE under the symbol “KMI.” The high and low sale prices per Class P share as reported on the NYSE and the dividends declared per share by period for 2015, 20142017, 2016 and 2013,2015, are provided below.
| | | | Price Range | | Declared Cash Dividends(a) | Price Range | | Declared Cash Dividends(a) |
| | Low | | High | | Low | | High | |
| 2017 | | | | | | |
| First Quarter | | $ | 20.71 |
| | $ | 23.01 |
| | $ | 0.125 |
|
| Second Quarter | | 18.31 |
| | 21.92 |
| | 0.125 |
|
| Third Quarter | | 18.23 |
| | 21.25 |
| | 0.125 |
|
| Fourth Quarter | | 16.68 |
| | 19.17 |
| | 0.125 |
|
| 2016 | | | | | | |
| First Quarter | | $ | 11.20 |
| | $ | 19.32 |
| | $ | 0.125 |
|
| Second Quarter | | 16.63 |
| | 19.40 |
| | 0.125 |
|
| Third Quarter | | 17.95 |
| | 23.20 |
| | 0.125 |
|
| Fourth Quarter | | 19.43 |
| | 23.36 |
| | 0.125 |
|
| 2015 | | | | | | | | | | |
| First Quarter | $ | 39.45 |
| | $ | 42.93 |
| | $ | 0.48 |
| $ | 39.45 |
| | $ | 42.93 |
| | $ | 0.48 |
|
| Second Quarter | 38.33 |
| | 44.71 |
| | 0.49 |
| 38.33 |
| | 44.71 |
| | 0.49 |
|
| Third Quarter | 25.81 |
| | 38.58 |
| | 0.51 |
| 25.81 |
| | 38.58 |
| | 0.51 |
|
| Fourth Quarter | 14.22 |
| | 32.89 |
| | 0.125 |
| 14.22 |
| | 32.89 |
| | 0.125 |
|
| 2014 | | | | | | |
| First Quarter | $ | 30.81 |
| | $ | 36.45 |
| | $ | 0.42 |
| |
| Second Quarter | 32.10 |
| | 36.50 |
| | 0.43 |
| |
| Third Quarter | 35.20 |
| | 42.49 |
| | 0.44 |
| |
| Fourth Quarter | 33.25 |
| | 43.18 |
| | 0.45 |
| |
| 2013 | | | | | | |
| First Quarter | $ | 35.74 |
| | $ | 38.80 |
| | $ | 0.38 |
| |
| Second Quarter | 35.52 |
| | 41.49 |
| | 0.40 |
| |
| Third Quarter | 34.54 |
| | 40.45 |
| | 0.41 |
| |
| Fourth Quarter | 32.30 |
| | 36.68 |
| | 0.41 |
| |
_______
| |
| (a) | Dividend information is for dividends declared with respect to that quarter. Generally, our declared dividends for our Class P common stock are paid on or about the 16th15th day of each February, May, August and November. |
As of February 11, 2016,8, 2018, we had 12,73911,867 holders of our Class P common stock, which does not include beneficial owners whose shares are held by a nominee, such as a broker or bank.
For information on our equity compensation plans, see Note 10 “Share-based Compensation and Employee Benefits—Share-based Compensation” to our consolidated financial statements.
The warrant repurchase program, dated June 12, 2015, which authorized us to repurchase up to $100 million of warrants, expired along with the warrants on May 25, 2017.
| Our Purchases of Our Warrants |
| | | | | | | | | | | | | | |
| Period | | Total number of securities purchased(a) | | Average price paid per security | | Total number of securities purchased as part of publicly announced plans(a) | | Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs |
| October 1 to October 31, 2015 | | 212,345 |
| | $ | 0.90 |
| | 212,345 |
| | $ | 90,428,906 |
|
| November 1 to November 30, 2015 | | — |
| | — |
| | — |
| | 90,428,906 |
|
| December 1 to December 31, 2015 | | — |
| | — |
| | — |
| | 90,428,906 |
|
| | | | | | | | | |
| Total Warrants | | | | | | | | $ | 90,428,906 |
|
| Our Purchases of Our Class P Shares |
| | | | | | | | | | | | | | |
| Period | | Total number of securities purchased(a) | | Average price paid per security | | Total number of securities purchased as part of publicly announced plans(a) | | Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs |
| December 1 to December 31, 2017 | | 14,038,121 |
| | $ | 17.80 |
| | 14,038,121 |
| | $ | 1,750,009,426 |
|
| | | | | | | | | |
| | | | | | | | | $ | 1,750,009,426 |
|
_______
| |
| (a) | On June 12, 2015, we announced thatJuly 19, 2017, our board of directors had approved a warrant$2 billion common share buy-back program that began in December 2017. After repurchase, program authorizing us to repurchase up to $100 million of warrants.the shares are cancelled and no longer outstanding. |
Item 6. Selected Financial Data.
The following table sets forth, for the periods and at the dates indicated, our summary historical financial data. The table is derived from our consolidated financial statements and notes thereto, and should be read in conjunction with those audited financial statements. See also Item 7 “Management’s“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report for more information.
Five-Year Review Kinder Morgan, Inc. and Subsidiaries | Five-Year Review Kinder Morgan, Inc. and Subsidiaries | Five-Year Review Kinder Morgan, Inc. and Subsidiaries |
| | | As of or for the Year Ended December 31, | As of or for the Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (In millions, except per share and ratio data) | (In millions, except per share amounts) |
| Income and Cash Flow Data: | | | | | | | | | | | | | | | | | | |
| Revenues | $ | 14,403 |
| | $ | 16,226 |
| | $ | 14,070 |
| | $ | 9,973 |
| | $ | 7,943 |
| $ | 13,705 |
| | $ | 13,058 |
| | $ | 14,403 |
| | $ | 16,226 |
| | $ | 14,070 |
|
| Operating income | 2,447 |
| | 4,448 |
| | 3,990 |
| | 2,593 |
| | 1,423 |
| 3,544 |
| | 3,572 |
| | 2,447 |
| | 4,448 |
| | 3,990 |
|
| Earnings from equity investments | 384 |
| | 406 |
| | 327 |
| | 153 |
| | 226 |
| 578 |
| | 497 |
| | 414 |
| | 406 |
| | 327 |
|
| Income from continuing operations | 208 |
| | 2,443 |
| | 2,696 |
| | 1,204 |
| | 449 |
| 223 |
| | 721 |
| | 208 |
| | 2,443 |
| | 2,696 |
|
| (Loss) income from discontinued operations, net of tax | — |
| | — |
| | (4 | ) | | (777 | ) | | 211 |
| |
| Loss from discontinued operations, net of tax | | — |
| | — |
| | — |
| | — |
| | (4 | ) |
| Net income | 208 |
| | 2,443 |
| | 2,692 |
| | 427 |
| | 660 |
| 223 |
| | 721 |
| | 208 |
| | 2,443 |
| | 2,692 |
|
| Net income attributable to Kinder Morgan, Inc. | 253 |
| | 1,026 |
| | 1,193 |
| | 315 |
| | 594 |
| 183 |
| | 708 |
| | 253 |
| | 1,026 |
| | 1,193 |
|
| Net income available to common stockholders | 227 |
| | 1,026 |
| | 1,193 |
| | 315 |
| | 594 |
| 27 |
| | 552 |
| | 227 |
| | 1,026 |
| | 1,193 |
|
| Class P Shares | | | | | | | | | |
| | | | | | | | | |
| Basic and Diluted Earnings Per Common Share From Continuing Operations | $ | 0.10 |
| | $ | 0.89 |
| | $ | 1.15 |
| | $ | 0.56 |
| | $ | 0.70 |
| $ | 0.01 |
| | $ | 0.25 |
| | $ | 0.10 |
| | $ | 0.89 |
| | $ | 1.15 |
|
| Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations | — |
| | — |
| | — |
| | (0.21 | ) | | 0.04 |
| |
| Total Basic and Diluted Earnings Per Common Share | $ | 0.10 |
| | $ | 0.89 |
| | $ | 1.15 |
| | $ | 0.35 |
| | $ | 0.74 |
| |
| Class A Shares | | | | | | | | | |
| |
| Basic and Diluted Earnings Per Common Share From Continuing Operations | | | | | | | $ | 0.47 |
| | $ | 0.64 |
| |
| Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations | | | | | | | (0.21 | ) | | 0.04 |
| |
| Total Basic and Diluted Earnings Per Common Share | | | | | | | $ | 0.26 |
| | $ | 0.68 |
| |
| Basic Weighted Average Number of Common Shares Outstanding: | | | | | | | |
| | |
| |
| Class P shares | 2,187 |
| | 1,137 |
| | 1,036 |
| | 461 |
| | 118 |
| |
| Class A shares | | | | | | | 446 |
| | 589 |
| |
| Diluted Weighted Average Number of Common Shares Outstanding: | | | | | | | | | |
| |
| Class P shares | 2,193 |
| | 1,137 |
| | 1,036 |
| | 908 |
| | 708 |
| |
| Class A shares | | | | | | | 446 |
| | 589 |
| |
| Basic Weighted Average Common Shares Outstanding | | 2,230 |
| | 2,230 |
| | 2,187 |
| | 1,137 |
| | 1,036 |
|
| Diluted Weighted Average Common Shares Outstanding | | 2,230 |
| | 2,230 |
| | 2,193 |
| | 1,137 |
| | 1,036 |
|
| | | | | | | | | | | | | | | | | | | |
| Dividends per common share declared for the period(a)(b) | $ | 1.605 |
| | $ | 1.740 |
| | $ | 1.600 |
| | $ | 1.400 |
| | $ | 1.050 |
| |
| Dividends per common share declared for the period(a) | | $ | 0.50 |
| | $ | 0.50 |
| | $ | 1.605 |
| | $ | 1.74 |
| | $ | 1.60 |
|
| Dividends per common share paid in the period(a) | 1.93 |
| | 1.70 |
| | 1.56 |
| | 1.34 |
| | 0.74 |
| 0.50 |
| | 0.50 |
| | 1.93 |
| | 1.70 |
| | 1.56 |
|
| | | | | | | | | | | | | | | | | | | |
| Balance Sheet Data (at end of period): | | | | | | | | | | | | | | | | | | |
| Net property, plant and equipment | $ | 40,547 |
| | $ | 38,564 |
| | $ | 35,847 |
| | $ | 30,996 |
| | $ | 17,926 |
| |
| Property, plant and equipment, net | | $ | 40,155 |
| | $ | 38,705 |
| | $ | 40,547 |
| | $ | 38,564 |
| | $ | 35,847 |
|
| Total assets | 84,104 |
| | 83,049 |
| | 75,071 |
| | 68,133 |
| | 30,658 |
| 79,055 |
| | 80,305 |
| | 84,104 |
| | 83,049 |
| | 75,071 |
|
| Long-term debt(c) | 40,732 |
| | 38,312 |
| | 31,910 |
| | 29,409 |
| | 13,261 |
| |
| Long-term debt(b) | | 34,088 |
| | 36,205 |
| | 40,732 |
| | 38,312 |
| | 31,910 |
|
_______
| |
| (a) | Dividends for the fourth quarter of each year are declared and paid during the first quarter of the following year. |
| |
| (b) | 2011 declared dividend per share was prorated for the portion of the first quarter we were a public company ($0.14 per share). If we had been a public company for the entire year, the 2011 declared dividend would have been $1.20 per share. |
| |
(c) | Excludes debt fair value adjustments. Increases to long-term debt for debt fair value adjustments totaled $927 million, $1,149 million, $1,674 million, $1,785 million $1,863 million, $2,479 million and $1,036$1,863 million as of December 31, 2017, 2016, 2015, 2014 2013, 2012, and 2011,2013, respectively. |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto. We prepared our consolidated financial statements in accordance with GAAP. Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 “Business“Business and Properties—(c) Narrative Description of Business—Business Strategy;” (ii) a description of developments during 2015,2017, found in Items 1 and 2 “Business“Business and Properties—(a) General Development of Business—Recent Developments;” and (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors.”
Inasmuch as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements. These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management’s judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in Item 1A “Risk“Risk Factors” and at the beginning of this report in “Information Regarding Forward-Looking Statements.”
General
Our business model, through our ownership and operation of energy related assets, is built to support two principal objectives:
helping customers by providing safe and reliable energy,natural gas, liquids products and bulk commodity and liquids products transportation, storage and distribution; and
creating long-term value for our shareholders.
To achieve these objectives, we focus on providing fee-based services to customers from a business portfolio consisting of energy-related pipelines, natural gas storage, processing and treating facilities, and bulk and liquids terminal facilities. We also produce and sell crude oil. Our reportable business segments are based on the way our management organizes our enterprise, and each of our business segments represents a component of our enterprise that engages in a separate business activity and for which discrete financial information is available.
Our reportable business segments are:
Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG facilities;
| |
| • | CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas; |
Terminals—(i) the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, condensate,chemicals, and ethanol and bulk products, including coal, petroleum coke, cement, alumina, saltsteel and other bulk chemicalscoal; and (ii) Jones Act tankers;
Products Pipelines—the ownership and operation of our Jones Act tankers;refined petroleum products, NGL and crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, propane, ethane, crude oil and condensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; and
| |
�� | Products Pipelines—the ownership and operation of refined petroleum products and crude oil and condensate pipelines that deliver refined petroleum products (gasoline, diesel fuel and jet fuel), NGL, crude oil, condensate and bio-fuels to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; |
Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport; andAirport.
Other—primarily other miscellaneous assets and liabilities including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with legacy trading activities; and (iii) other miscellaneous assets and liabilities.
As an energy infrastructure owner and operator in multiple facets of the various U.S. and Canadian energy industries and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future.
With respect to our interstate natural gas pipelines, related storage facilities and LNG terminals, the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended periods of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. These long-term contracts are typically structured with a fixed-fee reserving the right to transport or store natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity. Similarly, the Texas Intrastate Natural Gas Pipeline operations, currently derives approximately 73%76% of its sales and transport margins from long-term transport and sales contracts. As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As of December 31, 2015,2017, the remaining weighted average contract life of our natural gas transportation contracts (including intrastate pipelines’ purchase andterminal sales contracts)portfolio) was approximately six years.
Our midstream assets provide gathering and processing services for natural gas and gathering services for crude oil. These assets are generallymostly fee-based and the revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into their base components, are affected by the volumes of natural gas made available to our systems. Such volumes are impacted by producer rig count and drilling activity. In addition to fee based arrangements, some of which may include minimum volume commitments, we also provide some services based on percent-of-proceeds, percent-of-index and keep-whole contracts some of which may include minimum volume requirements.contracts. Our service contracts may rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices.
The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2015,2017, had a remaining average contract life of approximatelynine eight years. CO2 sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed. Our recent contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price. On a volume-weighted basis, for third-party contracts making deliveries in 2016,2018, and utilizing the average oil price per barrel contained in our 20162018 budget, approximately 99%97% of our revenue is based on a fixed fee or floor price, and 1%3% fluctuates with the price of oil. In the long-term, our success in this portion of the CO2 business segment is driven by the demand for CO2. However, short-term changes in the demand for CO2 typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts. In the CO2 business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. In that regard, our production during any period is an important measure. In addition, the revenues we receive from our crude oil, NGL and CO2 sales are affected by the prices we realize from the sale of these products. Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products. In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program, in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil. The realized weighted average crude oil price per barrel, with allthe hedges allocated to oil, was $58.40 per barrel in 2017, $61.52 per barrel in 2016 and $73.11 per barrel in 2015, $88.41 per barrel in 2014, and $92.70 per barrel in 2013.2015. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $49.61 per barrel in 2017, $41.36 per barrel in 2016 and $47.56 per barrel in 2015, $86.48 per barrel in 2014, and $94.94 per barrel in 2013.2015.
The factors impacting our Terminals business segment generally differ between terminals and tankers and depending on whether the terminal is a liquids or bulk terminal, and in the case of a bulk terminal, the type of product being handled or stored. Our liquids terminals business generally has longer-termlong-term contracts that require the customer to pay regardless of whether they use the capacity. Thus, similar to our natural gas pipeline business, our liquids terminals business is less sensitive to short-term changes in supply and demand. Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of
the length of the underlying service contracts (which on average is approximately fourthree years), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time. As with our refined petroleum products pipeline transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored. While we handle and store a large variety of products in our bulk terminals, the primary products are steel, coal and petroleum coke, and steel.coke. For the most part, we have contracts for this business that contain minimum volume guarantees and/or service exclusivity arrangements under which customers are required to utilize our terminals for all or a specified percentage of their handling and storage needs. The profitability of our minimum volume contracts is generally unaffected by short-term variation in economic
conditions; however, to the extent we expect volumes above the minimum and/or have contracts which are volume-based we can be sensitive to changing market conditions. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. In addition, weather-related factors such as hurricanes, floods and droughts may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods. Our eightIn addition to liquid and bulk terminals, we also own Jones Act tankers. As of December 31, 2017, we have sixteen Jones Act qualified tankers that operate in the marine transportation of crude oil, condensate and refined products in the U.S. and are currently operating pursuant to multi-year fixed price charters with major integrated oil companies, major refiners and the U.S. Military Sealift Command.
The profitability of our refined petroleum products pipeline transportation and storage business is generally driven by the volume of refined petroleum products that we transport and the prices we receive for our services. We also have approximately 5551 liquids terminals in this business segment that store fuels and offer blending services for ethanol and biofuels. The transportation and storage volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored. Demand for refined petroleum products tends to track in large measure demographic and economic growth, and with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable. Because of that, we seek to own refined petroleum products pipelines located in, or that transport to, stable or growing markets and population centers. The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index.
Our crude and condensate transportation services are primarily provided either pursuant to (i) long-term contracts that normally contain minimum volume commitments or (ii) through terms prescribed by the toll settlements with shippers and approved by regulatory authorities. As a result of these contracts, our settlement volumes are generally not sensitive to changing market conditions in the shorter term, however, in the longer term the revenues and earnings we realize from our crude and condensate pipelines in the U.S. and Canada are affected by the volumes of crude and condensate available to our pipeline systems, which are impacted by the level of oil and gas drilling activity in the respective producing regions that we serve. Our petroleum condensate processing facility splits condensate into its various components, such as light and heavy naphtha, under a long-term fee-based agreement with a major integrated oil company.
A portion ofKML
The interest in the Canadian business operations that we sold to the public on May 30, 2017 in KML’s IPO represented an interest in all our business portfolio (including theoperating assets in our Kinder Morgan Canada business segment and our operating Canadian assets in our Terminals and Products Pipelines business segments. These Canadian assets include the Trans Mountain pipeline system (including related terminaling assets), the TMEP, the Puget Sound and Jet Fuel pipeline systems, the Canadian portion of the Cochin Pipeline,pipeline system, the Vancouver Wharves Terminal and the bulkNorth 40 Terminal; as well as three jointly controlled investments: the Edmonton Rail Terminal, the Alberta Crude Terminal and liquids terminal facilities locatedthe Base Line Terminal.
Subsequent to the IPO, we retained control of KML, and as a result, it remains consolidated in Canada) transactour consolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in our consolidated statements of stockholders’ equity and consolidated balance sheets. Earnings attributable to the public ownership of KML are presented in “Net income attributable to noncontrolling interests” in our consolidated statements of income for the periods presented after May 30, 2017. KML transacts in and/or useuses the Canadian dollar as the functional currency, which affectaffects segment results due to the variability in U.S. - Canadian dollar exchange rates.
In our discussionsSubsequent to its IPO, KML has obtained a credit facility and completed two preferred share offerings. KMI expects KML to be a self-funding entity and does not anticipate making contributions to fund its growth or specifically to fund the TMEP.
TMEP Permitting and Construction Progress
TMEP was approved by Order in Council on December 1, 2016, with 157 conditions. The Province of British Columbia (BC) stated its approval of the operatingTMEP on January 11, 2017, with 37 conditions. Trans Mountain has made filings with the NEB and BC Environment with respect to all of the federal and provincial conditions required prior to general construction. The BC Environmental Assessment Office (EAO) has now released all condition filings required prior to general construction. The NEB has released sufficient approvals for proceeding with the Westridge Terminal and Temporary Infrastructure work phase. Trans Mountain is now in receipt of a number of priority permits from regulatory authorities in Alberta and BC, including access to BC northern interior Crown lands. KML continues to make progress on approvals from the NEB, government of BC and government of Alberta. However, as of the end of 2017, even with this progress, TMEP has
yet to obtain numerous provincial and municipal permits and federal condition approvals necessary for construction.
On December 4, 2017, KML announced that, while TMEP had made incremental progress during 2017 on permitting, regulatory condition satisfaction and land access, the scope and pace of the permits and approvals received to date did not allow for significant additional construction to begin at that time. KML also stated that it must have a clear line of sight on the timely conclusion of the permitting and approvals processes before it would commit to full construction spending. Consistent with its primarily permitting strategy and to mitigate risk, KML set its 2018 budget assuming TMEP spend in the first part of 2018 would be focused primarily on advancing the permitting process, rather than spending at full construction levels, until KML has greater clarity on key permits, approvals and judicial reviews. In its January 17, 2018 earnings press release, KML announced a potential unmitigated delay to project completion of one year (to December 2020) primarily due to the time required to file for, process and obtain necessary permits and regulatory approvals. As stated in Trans Mountain's November 14, 2017 motion to the NEB discussed below, "it is critical for Trans Mountain to have certainty that once started, the TMEP can confidently be completed on schedule." The TMEP projected in service date remains subject to change due to risks and uncertainties described in “Information Regarding Forward-Looking Statements,” “Item 1A, Risk Factors,” elsewhere in this Item 7, and in Note 17 to our consolidated financial statements under the heading “TMEP Litigation.” Further, as stated in KML’s January 17, 2018 earnings press release, if TMEP continues to be "faced with unreasonable regulatory risks due to a lack of clear processes to secure necessary permits . . . it may become untenable for Trans Mountain's shareholders . . . to proceed." Trans Mountain continues to proceed in water work at the Westridge Terminal.
On October 26 and November 14, 2017, KML filed motions with the NEB to resolve delays as they relate to the City of Burnaby and to establish a fair, transparent and expedited backstop process for resolving any similar delays in other provincial and municipal permitting processes. On December 7, 2017, the NEB granted KML’s motion in respect to the City of Burnaby and indicated that Trans Mountain is not required to comply with two sections of the city’s bylaws, thereby allowing Trans Mountain to start work at its pipeline terminals subject to other permits or authorizations that may be required. The NEB indicated that it would release its reasons for decision at a later date. On January 18, 2018, the NEB issued its reasons for decision on the Burnaby motion and granted in part Trans Mountain’s motion for a backstop process, establishing a generic process to hear any future motions as they relate to provincial and municipal permitting issues.
Hearings were held in October and November 2017 related to two judicial reviews underway in the BC Supreme Court with respect to the environmental certificate granted to TMEP by the province of BC. Separate judicial reviews pending in the Federal Court of Appeal challenging the process leading to the federal government’s approval of TMEP were heard by the court from October 2 to October 13, 2017. Decisions from the courts are expected in the coming months. KMI is confident that the NEB, the Federal Government, and the BC Government properly assessed and weighed the various scientific and technical evidence through a comprehensive review process, while taking into consideration varying interests on the TMEP. The approvals granted followed many years of engagement and consultation with communities, Aboriginal groups and individuals.
As of the end of the fourth quarter 2017, a cumulative C$930 million has been spent on the TMEP. KML’s estimated total cost for the TMEP is C$7.4 billion (C$6.7 billion excluding capitalized equity financing costs). Construction related delays could result in increases to the estimated total costs; however, because the extent of the delay remains uncertain, KML has not updated its cost estimate at this time.
2017 Tax Reform
While the recently enacted 2017 Tax Reform will ultimately be moderately positive for us, the reduced corporate income tax rate caused certain of our deferred-tax assets to be revalued at 21 percent versus 35 percent at the end of 2017. Although there is no impact to the underlying related deductions, which can continue to be used to offset future taxable income, we took an estimated approximately $1.4 billion non-cash accounting charge in the fourth quarter of 2017. This charge is our initial estimate and may be refined in the future as permitted by recent guidance from the SEC and FASB. The positive impacts of the law include the reduced corporate income tax rate and the fact that several of our U.S. business units (essentially all but our interstate natural gas pipelines) will be able to deduct 100 percent of their capital expenditures through 2022. The net impact results in postponing the date when we become a significant federal cash taxpayer by approximately one year, to beyond 2024.
We continue to assess the impact of individual businesses that follow (see “—Results of Operations” below), we generally identify the important fluctuations between periods that2017 Tax Reform on our business in order to complete our analysis. Any adjustment to our provisional amount recorded during the year ended December 31, 2017 will be reported in the reporting period in which any such adjustments are attributabledetermined and may be material in the period in which the adjustments are made. See Note 5 “Income Taxes” to acquisitions and dispositions separately from those that are attributable to businesses owned in both periods.our consolidated financial statements.
Critical Accounting Policies and Estimates
Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of GAAP involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining: (i) revenue recognition and income taxes, (ii) the economic useful lives of our assets and related depletion rates; (ii)(iii) the fair values used to (a) assign purchase price from business combinations, (b) determine possible asset and equity investment impairment charges, and (c) calculate the annual goodwill impairment test; (iii)(iv) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (iv)(v) provisions for uncollectible accounts receivables; (v)and (vi) exposures under contractual indemnifications; and (vi) unbilled revenues.indemnifications.
For a summary of our significant accounting policies, see Note 2 “Summary of Significant Accounting Policies” to our consolidated financial statements. We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed as follows.
Acquisition Method of Accounting
For acquired businesses, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition. Determining the fair value of these items requires management’s judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. For more information on our acquisitions and application of the acquisition method, see Note 3 “Acquisitions“Acquisitions and Divestitures”to our consolidated financial statements.
Environmental Matters
With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, we do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at fair value, where appropriate, environmental liabilities assumed in a business combination.
Our recording of our environmental accruals often coincides with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations. These adjustments may result in increases in environmental expenses and are primarily related to quarterly reviews of potential environmental issues and resulting environmental liability estimates. In making these liability estimations, we consider the effect of environmental compliance, pending legal actions against us, and potential third party liability claims. For more information on environmental matters, see PART I, Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Environmental Matters”.Matters.” For more information on our environmental disclosures, see Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
Legal and Regulatory Matters
Many of our operations are regulated by various U.S. and Canadian regulatory bodies and we are subject to legal and regulatory matters as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify contingent liabilities, we identify a range of possible costs expected to be required to resolve the matter. Generally, if no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on legal proceedings, see Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
Intangible Assets
Intangible assets are those assets which provide future economic benefit but have no physical substance. Identifiable intangible assets having indefinite useful economic lives, including goodwill, are not subject to regular periodic amortization,
and such assets are not to be amortized until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We evaluate goodwill for impairment on May 31 of each year. At year end and during other interim periods we evaluate our reporting units for events and changes that could indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount.
Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets. These intangible assets have definite lives, are being amortized in a systematic and rational manner over their estimated useful lives, and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets.
For more information on our December 31, 2015 goodwill impairment evaluation and amortizable intangibles, see Note 8 “Goodwill” to our consolidated financial statements.
Estimated Net Recoverable Quantities of Oil and Gas
We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted or amortized into income, and the presentation of supplemental information on oil and gas producing activities. The expected future cash flows to be generated by oil and gas producing properties used in testing for impairment of such properties also rely in part on estimates of net recoverable quantities of oil and gas.
Proved reserves are the estimated quantities of oil and gas that geologic and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. For more information on our ownership interests in the net quantities of proved oil and gas reserves and our measures of discounted future net cash flows from oil and gas reserves, please see “Supplemental Information on Oil and Gas Producing Activities (Unaudited)”.
DD&A expense on our proved oil and gas properties is calculated using the unit of production (UOP) method. The reserves that are used to determine the UOP depletion rate for leasehold acquisition and the costs to acquire proved properties is the total of our developed and undeveloped proved reserves which are known as total proved reserves. The UOP depreciation rate for our tangible lease and well equipment costs, including development costs and exploration costs associated with successful drilling projects, is calculated based upon total proved developed reserves. Our estimated future well plugging and abandonment costs along with future expected salvage values are considered in the UOP DD&A expense calculation. For our oil and gas producing properties that have no proved reserves, the UOP depreciation rate is based on each property’s risk-adjusted probable reserves and NYMEX forward curve prices.
The sustained deterioration in the long-term outlook for commodity prices was a triggering event that required us to perform impairment testing of our assets that are sensitive to such commodity prices. During 2015, we performed a two-step impairment testing of certain long-lived assets within our CO2 segment, which resulted in the impairment of certain of our oil and gas producing properties in the amount of $399 million for the year ended December 31, 2015.
As of December 31, 2015, the net book value of productive properties, plant and equipment associated with our oil and gas proved reserves was approximately $932 million, which included 49.5 million barrels of oil equivalent of estimated proved developed reserves, and the DD&A expense recorded on these properties in 2015 was $376 million. If the estimates of proved reserves used in the unit-of-production calculation had been lower by 5%, DD&A expense in 2015 would have increased by approximately $15 million.
Continued lower commodity prices as indicated by forward curve pricing that is used in testing for impairment, estimated total proved and risk-adjusted probable oil and gas reserves, and related expected future cash flows, may result in additional impairments of our oil producing interests and increased DD&A expense in 2016. See Note 4 “Impairments and Disposals” to our consolidated financial statements.
Hedging Activities
We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices, foreign currency exposure on Euro denominated debt, and to balance our exposure to fixed and variable interest rates, and we believe that these hedges are generally effective in realizing these objectives. According to the provisions of GAAP, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged, and any ineffective portion of the hedge gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately. We may or may not apply hedge accounting to our derivative contracts depending on the circumstances.
All of our derivative contracts are recorded at estimated fair value. We utilize published prices, broker quotes, and estimates of market prices to estimate the fair value of these contracts; however, actual amounts could vary materially from estimated fair values as a result of changes in market prices. In addition, changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. For more information on our hedging activities, see Note 14 “Risk“Risk Management”to our consolidated financial statements.
Employee Benefit Plans
We reflect an asset or liability for our pension and other postretirement benefit plans based on their overfunded or underfunded status. As of December 31, 2015,2017, our pension plans were underfunded by $604686 million and our other postretirement benefits plans were underfunded by $18490 million. Our pension and other postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. For 2015, we selected our discount rates by matchingWe utilize a full yield curve approach in the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities. The selection of these assumptions is further discussed in Note 10 “Share-based Compensation and Employee Benefits” to our consolidated financial statements. Effective January 1, 2016, we changed our estimateestimation of the service and interest cost components of net periodic benefit cost (credit) for our pension and other postretirement benefit plans. The new estimate utilizes a full yield curve approach in the estimation of these components by applyingplans which applies the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The new estimate provides a more precise measurementselection of servicethese assumptions is further discussed in Note 10 “Share-based Compensation and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates. The change does not affect the measurement ofEmployee Benefits” to our pension and postretirement benefit obligations and it is accounted for as a change in accounting estimate, which is applied prospectively. The change in the service and interest costs going forward will not be significant.consolidated financial statements.
Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and other postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants, or over the expected future lives of inactive plan participants. As of December 31, 2015,2017, we had deferred net losses of approximately $535$547 million in pretax accumulated other comprehensive loss and noncontrolling interests related to our pension and other postretirement benefits.
The following table shows the impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended December 31, 2015:2017: | | | | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits |
| | | Net benefit cost (income) | | Change in funded status(a) | | Net benefit cost (income) | | Change in funded status(a) | | Net benefit cost (income) | | Change in funded status(a) | | Net benefit cost (income) | | Change in funded status(a) |
| | | (In millions) | | (In millions) |
| One percent increase in: | | | | | | | | | | | | | | | | |
| Discount rates | | $ | 10 |
| | $ | 219 |
| | $ | 2 |
| | $ | 44 |
| | $ | (13 | ) | | $ | 252 |
| | $ | (1 | ) | | $ | 33 |
|
| Expected return on plan assets | | (23 | ) | | — |
| | (4 | ) | | — |
| | (21 | ) | | — |
| | (3 | ) | | — |
|
| Rate of compensation increase | | 3 |
| | (10 | ) | | — |
| | — |
| | 4 |
| | (13 | ) | | — |
| | — |
|
| Health care cost trends | | — |
| | — |
| | 4 |
| | (31 | ) | | — |
| | — |
| | 3 |
| | (24 | ) |
| | | | | | | | | | | | | | | | | |
| One percent decrease in: | | | | | | | | | | | | | | | | |
| Discount rates | | 11 |
| | (258 | ) | | — |
| | (51 | ) | | 15 |
| | (299 | ) | | 1 |
| | (38 | ) |
| Expected return on plan assets | | 23 |
| | — |
| | 4 |
| | — |
| | 21 |
| | — |
| | 3 |
| | — |
|
| Rate of compensation increase | | (3 | ) | | 9 |
| | — |
| | — |
| | (3 | ) | | 13 |
| | — |
| | — |
|
| Health care cost trends | | — |
| | — |
| | (2 | ) | | 27 |
| | — |
| | — |
| | (3 | ) | | 21 |
|
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| (a) | Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations. |
Income Taxes
We record a valuation allowance to reduce our deferredIncome tax assets toexpense is recorded based on an amount that is more likely than notestimate of the effective tax rate in effect or to be realized. While we have considered estimated future taxable income and prudent and feasiblein effect during the relevant periods. Changes in tax planning strategies in determining the amount of our valuation allowance, any changelegislation are included in the amount that we expect to ultimately realize will be included in incomerelevant computations in the period in which such a determination is reached. In addition, wechanges are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.
Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance for the amount that is more likely than not to not be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached.
In determining the deferred income tax asset and liability balances attributable to our investments, we have appliedapply an accounting policy that looks through our investments. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments.
Results of Operations
Non-GAAP MeasuresOverview
The non-GAAP financialOur management evaluates our performance primarily using the measures of Segment EBDA and, as discussed below under “—Non-GAAP Measures,”DCF, before certain items and segmentSegment EBDA before certain items are presented below under “—Distributable Cash Flow”items. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and“—Consolidated Earnings Results,” respectively.Certain items are items certain expenses that are required by GAAP to be reflected in net income, but typically either do not have a cash impact, or by their nature are separately identifiable from our normal business operations and, in our view, are likely to occur only sporadically.
Our non-GAAP measures described below should not be considered as an alternative to GAAP net income or any other GAAP measure. DCF before certain items and segment EBDA before certain items are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider either of these non-GAAP measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Because DCF before certain items excludes some but not all items that affect net income and because DCF measures are defined differently by different companies in our industry, our DCF before certain items may not be comparable to DCF measures of other companies. Our computation of segment EBDA before certain items has similar limitations. Management compensates for the limitations of these non-GAAP measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.
Distributable Cash Flow
DCF before certain items is an overall performance metric we use to estimate the ability of our assets to generate cash flows on an ongoing basis and as a measure of cash available to pay dividends. We believe the primary measure of company performance used by us, investors and industry analysts is cash generation performance. Therefore, we believe DCF before certain items is an important measure to evaluate our operating and financial performance and to compare it with the performance of other publicly traded companies within the industry.
The table below details the reconciliation of Net Income to DCF before certain items:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | (In millions) |
| Net Income | $ | 208 |
| | $ | 2,443 |
| | $ | 2,692 |
|
| Add/(Subtract): | | | | | |
| Certain items before book tax(a)(b) | 1,781 |
| | 14 |
| | (609 | ) |
| Book tax certain items(b)(c) | (340 | ) | | (117 | ) | | (39 | ) |
| Certain items after book tax | 1,441 |
| | (103 | ) | | (648 | ) |
| Net income before certain items | 1,649 |
| | 2,340 |
| | 2,044 |
|
| Add/(Subtract): | | | | | |
| Net income attributable to third-party noncontrolling interests(d) | (18 | ) | | (12 | ) | | (5 | ) |
| DD&A expense(e) | 2,683 |
| | 2,390 |
| | 2,142 |
|
| Book taxes(f) | 976 |
| | 840 |
| | 847 |
|
| Cash taxes(g) | (32 | ) | | (448 | ) | | (552 | ) |
| Other items(h) | 32 |
| | 17 |
| | 6 |
|
| Sustaining capital expenditures(i) | (565 | ) | | (509 | ) | | (414 | ) |
| Declared distributions to noncontrolling interests(j) | — |
| | (2,000 | ) | | (2,355 | ) |
| Subtotal | 3,076 |
| | 278 |
| | (331 | ) |
| DCF before certain items available to equity | 4,725 |
| | 2,618 |
| | 1,713 |
|
| Preferred stock dividends | (26 | ) | | — |
| | — |
|
| DCF before certain items available to common stockholders | $ | 4,699 |
| | $ | 2,618 |
| | $ | 1,713 |
|
| | | | | | |
| Weighted average common shares outstanding for dividends(k) | 2,200 |
| | 1,312 |
| | 1,040 |
|
| DCF per common share before certain items | $ | 2.14 |
| | $ | 2.00 |
| | $ | 1.65 |
|
| Declared dividend per common share | 1.605 |
| | 1.740 |
| | 1.600 |
|
_______ | |
(a) | Consists of certain items summarized in footnotes (b) through (e) to the “—Consolidated Earnings Results” table included below, and described in more detail below in the footnotes to tables included in both our management’s discussion and analysis of segment results and “—General and Administrative, Interest, and Noncontrolling Interests.”
|
| |
(b) | 2015 amount includes a $175 million non-cash pre-tax impairment ($84 million net after-tax impact to common stockholders) of a terminal facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer, which occurred after the issuance of our 2015 fourth quarter earnings release containing our preliminary financial results ($175 million in certain items before book tax and $(48) million in book tax certain items). |
| |
(c) | Represents income tax provision on certain items plus discrete income tax items. |
| |
(d) | Represents net income allocated to third-party ownership interests in consolidated subsidiaries other than our former master limited partnerships. 2015 amount excludes losses attributable to noncontrolling interests of $63 million related to impairments included as certain items, which includes a $43 million loss attributable to noncontrolling interests associated with the impairment discussed in footnote (b) above. |
| |
(e) | Includes DD&A, amortization of excess cost of equity investments and our share of equity investee’s DD&A of $323 million, $305 million and $297 million in 2015, 2014 and 2013, respectively. |
| |
(f) | Excludes book tax certain items and includes income tax allocated to the segments. 2015, 2014 and 2013 amounts also include $72 million, $75 million and $66 million, respectively, of our share of taxable equity investee’s book tax expense. |
| |
(g) | Includes our share of taxable equity investee’s cash taxes of $(19) million, $(27) million and $(30) million in 2015, 2014 and 2013, respectively. |
| |
(h) | For 2015, consists primarily of non-cash compensation associated with our restricted stock awards program and for 2014 and 2013 consists primarily of excess coverage from our former master limited partnerships. |
| |
(i) | Includes our share of equity investee’s sustaining capital expenditures of $(70) million, $(59) million and $(48) million in 2015, 2014 and 2013, respectively. |
| |
(j) | Represents distributions to KMP and EPB limited partner units formerly owned by the public for the respective period. |
| |
(k) | Includes restricted stock awards that participate in dividends and, for 2015, the dilutive effect of warrants. 2014 amount also includes the shares issued on November 26, 2014 for the Merger Transactions as if outstanding for the entire fourth quarter which differs from our GAAP presentation on our Consolidated Statement of Income. |
Consolidated Earnings Results
In the Results of Operations table below and in the business segment tables that follow, segment EBDA before certain items is calculated by adjusting the segment earnings before DD&A for the applicable certain item amounts in the footnotes to those tables.
In general, interest expense, general and administrative expenses, DD&A, unallocable interest income and income taxes and net income attributable to noncontrolling interests aregenerally not controllable by our business segment operating managers, such as general and therefore are not included when we measure business segment operating performance.administrative expenses, interest expense, net, and income taxes. Our general and administrative expenses include such items as employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.
We evaluate business segment performance primarily based on segment EBDA before certain itemsIn our discussions of the operating results of individual businesses that follow, we generally identify the important fluctuations between periods that are attributable to acquisitions and dispositions separately from those that are attributable to businesses owned in relation to the level of capital allocated and consider this to be an important measure of our business segment performance. We account for intersegment sales at market prices, which are eliminated in consolidation. both periods.
Consolidated Earnings Results
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | (In millions) |
| Segment earnings before DD&A(a) | | | | | |
| Natural Gas Pipelines | $ | 3,063 |
| | $ | 4,259 |
| | $ | 4,207 |
|
CO2 | 657 |
| | 1,240 |
| | 1,435 |
|
| Terminals | 849 |
| | 944 |
| | 836 |
|
| Products Pipelines | 1,100 |
| | 856 |
| | 602 |
|
| Kinder Morgan Canada | 163 |
| | 182 |
| | 424 |
|
| Other | (53 | ) | | 13 |
| | (5 | ) |
| Total segment earnings before DD&A(b) | 5,779 |
| | 7,494 |
| | 7,499 |
|
| DD&A expense | (2,309 | ) | | (2,040 | ) | | (1,806 | ) |
| Amortization of excess cost of equity investments | (51 | ) | | (45 | ) | | (39 | ) |
| Other revenues | 37 |
| | 36 |
| | 36 |
|
| General and administrative expenses(c) | (690 | ) | | (610 | ) | | (613 | ) |
| Interest expense, net of unallocable interest income(d) | (2,055 | ) | | (1,807 | ) | | (1,688 | ) |
| Income from continuing operations before unallocable income taxes | 711 |
| | 3,028 |
| | 3,389 |
|
| Unallocable income tax expense | (503 | ) | | (585 | ) | | (693 | ) |
| Income from continuing operations | 208 |
| | 2,443 |
| | 2,696 |
|
| Loss from discontinued operations, net of tax(e) | — |
| | — |
| | (4 | ) |
| Net income | 208 |
| | 2,443 |
| | 2,692 |
|
| Net loss (income) attributable to noncontrolling interests | 45 |
| | (1,417 | ) | | (1,499 | ) |
| Net income attributable to Kinder Morgan, Inc. | 253 |
| | 1,026 |
| | 1,193 |
|
| Preferred Stock Dividends | (26 | ) | | — |
| | — |
|
| Net Income Available to Common Stockholders | $ | 227 |
| | $ | 1,026 |
| | $ | 1,193 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Segment EBDA(a) | | | | | |
| Natural Gas Pipelines | $ | 3,487 |
| | $ | 3,211 |
| | $ | 3,067 |
|
CO2 | 847 |
| | 827 |
| | 658 |
|
| Terminals | 1,224 |
| | 1,078 |
| | 878 |
|
| Products Pipelines | 1,231 |
| | 1,067 |
| | 1,106 |
|
| Kinder Morgan Canada | 186 |
| | 181 |
| | 182 |
|
| Total segment EBDA(b) | 6,975 |
| | 6,364 |
| | 5,891 |
|
| DD&A | (2,261 | ) | | (2,209 | ) | | (2,309 | ) |
| Amortization of excess cost of equity investments | (61 | ) | | (59 | ) | | (51 | ) |
| General and administrative and corporate charges(c) | (660 | ) | | (652 | ) | | (708 | ) |
| Interest, net(d) | (1,832 | ) | | (1,806 | ) | | (2,051 | ) |
| Income before income taxes | 2,161 |
| | 1,638 |
| | 772 |
|
| Income tax expense(e) | (1,938 | ) | | (917 | ) | | (564 | ) |
| Net income | 223 |
| | 721 |
| | 208 |
|
| Net (income) loss attributable to noncontrolling interests | (40 | ) | | (13 | ) | | 45 |
|
| Net income attributable to Kinder Morgan, Inc. | 183 |
| | 708 |
| | 253 |
|
| Preferred Stock Dividends | (156 | ) | | (156 | ) | | (26 | ) |
| Net Income Available to Common Stockholders | $ | 27 |
| | $ | 552 |
| | $ | 227 |
|
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| (a) | Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, other expense (income), net, losses on impairments of goodwill, losses on impairments and divestitures, net and losses on impairments and disposalsdivestitures of long-lived assets, net and equity investments.investments, net. Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes. Allocable income tax expenses included in segment earnings for the years ended December 31, 2015, 2014 and 2013 were $61 million, $63 million and $49 million, respectively. |
Certain item footnotesitems affecting Total Segment EBDA (see “—Non-GAAP Measures” below)
| |
| (b) | 2015, 20142017, 2016 and 20132015 amounts include decreases (increase) in earnings of $1,783$384 million, $45$1,121 million and $(573)$1,748 million, respectively, related to the combined net effect of the certain items impacting segment earnings before DD&A from continuing operations and disclosedTotal Segment EBDA. The extent to which these items affect each of our business segments is discussed below in our management discussion and analysis of segment results.the footnotes to the tables within “—Segment Earnings Results.” |
| |
| (c) | 2015, 20142017, 2016 and 20132015 amounts include (increase) decreasesan increase to expense of $(25)$15 million, $28a decrease to expense of $13 million and $8an increase to expense of $60 million, respectively, related to the combined net effect of the certain items related to general and administrative expensesand corporate charges disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”
|
| |
| (d) | 2015, 20142017, 2016 and 20132015 amounts include decreases in expense of $27$39 million, $3$193 million and $32$27 million, respectively, related to the combined net effect of the certain items related to interest expense, net of unallocable interest income disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”
|
| |
| (e) | 2013 amount represents an incremental loss2017, 2016 and 2015 amounts include increases in expense of $1,085 million and $18 million and a decrease in expense of $340 million, respectively, related to the salecombined net effect of our FTC Natural Gas Pipelines disposal group effective November 1, 2012.the certain items related to income tax expense representing the income tax provision on certain items plus discrete income tax items. |
Year Ended December 31, 20152017 vs. 20142016
The certain item totals reflected in footnotes (b), (c) and (d) to the table above accounted for $555 million of the increase in income before income taxes in 2017 as compared to 2016 (representing the difference between decreases of $360 million and $915 million in income before income taxes for 2017 and 2016, respectively). After giving effect to these certain items, which are discussed in more detail in the discussion that follows, the remaining decrease of $32 million (1%) from the prior year in income before income taxes is primarily attributable to decreased performance from our Natural Gas Pipelines business segment, largely associated with our sale of a 50% interest in SNG to The Southern Company (Southern Company) on September 1, 2016, and increased DD&A expense partially offset by decreased general and administrative expense and decreased interest expense.
Year Ended December 31, 2016 vs. 2015
The certain item totals reflected in footnotes (b), (c) and (d) to the tablestable above accounted for $1,767$866 million of the decreaseincrease in income from continuing operations before unallocable income taxes in 20152016 as compared to 20142015 (representing the difference between decreases of $915 million and $1,781 million and $14 million in total income from continuing operations before unallocable income taxes for 20152016 and 2014,2015, respectively). After giving effect to these certain items, which are discussed in more detail in the remaining decrease of $550 million (18%) from the prior year indiscussion that follows, income from continuing operations before unallocable income taxes is primarily attributable to increased DD&A expense, general and administrative expense and interest expense, net of unallocable interest income. As explained further below, our total segment earnings before DD&A did not change significantlyfor 2016 when compared to the prior year aswas flat. Increased results in our Products Pipelines and Terminals business segments and decreased DD&A expense and interest expense, net, were offset by unfavorable commodity prices affecting our CO2 business segment were offset by increasedand decreased results fromon our Products Pipelines, Terminals and Natural Gas Pipelines business segments.segment. The decrease in DD&A was primarily driven by lower DD&A in our CO2 business segment and the decrease in interest expense was due to lower weighted average debt balances, partially offset by a slightly higher overall weighted average interest rate on outstanding debt.
Year Ended December 31, 2014 vs. 2013Non-GAAP Financial Measures
TheOur non-GAAP performance measures are DCF, both in the aggregate and per share, and Segment EBDA before certain items. Certain items, as used to calculate our non-GAAP measures, are items that are required by GAAP to be reflected in net income, but typically either (i) do not have a cash impact (for example, asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example certain legal settlements, enactment of new tax legislation and casualty losses).
Our non-GAAP performance measures described below should not be considered alternatives to GAAP net income or other GAAP measures and have important limitations as analytical tools. Our computations of DCF and Segment EBDA before certain items may differ from similarly titled measures used by others. You should not consider these non-GAAP performance measures in isolation or as substitutes for an analysis of our results as reported under GAAP. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. Management compensates for the limitations of these non-GAAP performance measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.
DCF
DCF is calculated by adjusting net income available to common stockholders before certain items for DD&A, total book and cash taxes, sustaining capital expenditures and other items. DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt and preferred stock dividends, paying cash taxes and expending sustaining capital that could be used for discretionary purposes such as common stock dividends, stock repurchases, retirement of debt, or expansion capital expenditures. We believe the GAAP measure most directly comparable to DCF is net income available to common stockholders. A reconciliation of DCF to net income available to common stockholders is provided in the table below. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends.
Segment EBDA Before Certain Items
Segment EBDA before certain items is used by management in its analysis of segment performance and management of our business. General and administrative expenses are generally not under the control of our segment operating managers, and
therefore, are not included when we measure business segment operating performance. We believe Segment EBDA before certain items is a significant performance metric because it provides us and external users of our financial statements additional insight into the ability of our segments to generate segment cash earnings on an ongoing basis. We believe it is useful to investors because it is a performance measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable to Segment EBDA before certain items is segment earnings before DD&A and amortization of excess cost of equity investments (Segment EBDA).
In the tables for each of our business segments under “— Segment Earnings Results” below, Segment EBDA before certain items is calculated by adjusting the Segment EBDA for the applicable certain item totals reflectedamounts, which are totaled in footnotes (b), (c) and (d) to the tables above accounted for $627 million ofand described in the decrease in income from continuing operations before unallocable income taxes in 2014, when comparedfootnotes to 2013 (combining a decrease of $14 million and an increase of $613 million in total income from continuing operations before unallocable income taxes for 2014 and 2013, respectively). After giving effect to these certain items, the remaining increase of $266 million (10%) from the prior year in income from continuing operations before unallocable income taxes relates to better overall performance primarily from our Natural Gas Pipelines, Products Pipelines and Terminals segments in 2014.those tables.
Reconciliation of Net Income Available to Common Stockholders to DCF
49 |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Net Income Available to Common Stockholders | $ | 27 |
| | $ | 552 |
| | $ | 227 |
|
| Add/(Subtract): | | | | | |
| Certain items before book tax(a) | 141 |
| | 915 |
| | 1,781 |
|
| Book tax certain items(b) | (77 | ) | | 18 |
| | (340 | ) |
| Impact of 2017 Tax Reform(c) | 1,381 |
| | — |
| | — |
|
| Total certain items | 1,445 |
| | 933 |
| | 1,441 |
|
| | | | | | |
| Noncontrolling interest certain items(d) | — |
| | (8 | ) | | (63 | ) |
| Net income available to common stockholders before certain items | 1,472 |
| | 1,477 |
| | 1,605 |
|
| Add/(Subtract): | | | | | |
| DD&A expense(e) | 2,684 |
| | 2,617 |
| | 2,683 |
|
| Total book taxes(f) | 957 |
| | 993 |
| | 976 |
|
| Cash taxes(g) | (72 | ) | | (79 | ) | | (32 | ) |
| Other items(h) | 29 |
| | 43 |
| | 32 |
|
| Sustaining capital expenditures(i) | (588 | ) | | (540 | ) | | (565 | ) |
| DCF | $ | 4,482 |
| | $ | 4,511 |
| | $ | 4,699 |
|
| | | | | | |
| Weighted average common shares outstanding for dividends(j) | 2,240 |
| | 2,238 |
| | 2,200 |
|
| DCF per common share | $ | 2.00 |
| | $ | 2.02 |
| | $ | 2.14 |
|
| Declared dividend per common share | 0.500 |
| | 0.500 |
| | 1.605 |
|
| |
| (a) | Consists of certain items summarized in footnotes (b) through (d) to the “—Results of Operations—Consolidated Earnings Results” table included above, and described in more detail below in the footnotes to tables included in both our management’s discussion and analysis of segment results and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.” |
| |
| (b) | Represents income tax provision on certain items plus discrete income tax items. For 2017, discrete income tax items include a $36 million federal return-to-provision tax benefit as a result of the recognition of an enhanced oil recovery credit instead of deduction. For 2016, discrete income tax items include a $276 million increase in tax expense primarily due to the impact of the sale of a 50% interest in SNG discussed in Note 5 “Income Taxes” to our consolidated financial statements. |
| |
| (c) | Amount includes book tax certain items and $219 million pre-tax certain items related to our FERC regulated business. See Note 5 “Income Taxes” to our consolidated financial statements. |
| |
| (d) | Represents noncontrolling interests share of certain items. |
| |
| (e) | Includes DD&A, amortization of excess cost of equity investments and our share of certain equity investee’s DD&A, net of the noncontrolling interests’ portion of KML DD&A and consolidating joint venture partners’ share of DD&A of $362 million, $349 million and $323 million in 2017, 2016 and 2015, respectively. |
| |
| (f) | Excludes book tax certain items of $(1,085) million, $(18) million and $340 million for 2017, 2016 and 2015, respectively. 2017, 2016 and 2015 amounts also include $104 million, $94 million and $72 million, respectively, of our share of taxable equity investee’s book taxes, net of the noncontrolling interests’ portion of KML book taxes. |
| |
| (g) | Includes our share of taxable equity investee’s cash taxes of $(69) million, $(76) million and $(19) million in 2017, 2016 and 2015, respectively. |
| |
| (h) | Amounts include non-cash compensation associated with our restricted stock program. 2017 amount also includes a pension contribution. |
| |
| (i) | Includes our share of (i) certain equity investee’s, (ii) KML’s, and (ii) consolidating subsidiaries’ sustaining capital expenditures of $(107) million, $(90) million and $(70) million in 2017, 2016 and 2015, respectively. |
| |
| (j) | Includes restricted stock awards that participate in common share dividends and, for 2015, the dilutive effect of warrants, which expired on May 25, 2017 without the issuance of Class P common stock. |
Segment Earnings Results
Natural Gas Pipelines
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | (In millions, except operating statistics) |
| Revenues(a) | $ | 8,725 |
| | $ | 10,168 |
| | $ | 8,617 |
|
| Operating expenses | (4,738 | ) | | (6,241 | ) | | (5,235 | ) |
| Loss on impairment of goodwill(b) | (1,150 | ) | | — |
| | — |
|
| Loss on impairments and disposals of long-lived assets and equity investments, net(b) | (148 | ) | | (5 | ) | | (37 | ) |
| Other income (expense) | 3 |
| | — |
| | (4 | ) |
| Earnings from equity investments | 351 |
| | 318 |
| | 297 |
|
| Interest income and Other, net | 24 |
| | 25 |
| | 578 |
|
| Income tax expense | (4 | ) | | (6 | ) | | (9 | ) |
| Segment earnings before DD&A from continuing operations(b) | 3,063 |
| | 4,259 |
| | 4,207 |
|
| Discontinued operations(c) | — |
| | — |
| | (4 | ) |
| Certain items(b)(c) | 1,062 |
| | (190 | ) | | (486 | ) |
| EBDA before certain items | $ | 4,125 |
| | $ | 4,069 |
| | $ | 3,717 |
|
| | | | | | |
| Change from prior period | Increase/(Decrease) | | |
| Revenues before certain items | $ | (1,479 | ) | | $ | 1,339 |
| | |
| EBDA before certain items | $ | 56 |
| | $ | 352 |
| | |
| | | | | | |
| Natural gas transport volumes (BBtu/d)(d) | 28,398 |
| | 27,064 |
| | 25,144 |
|
| Natural gas sales volumes (BBtu/d)(e) | 2,419 |
| | 2,334 |
| | 2,458 |
|
| Natural gas gathering volumes (BBtu/d)(f) | 3,540 |
| | 3,394 |
| | 2,959 |
|
| Crude/condensate gathering volumes (MBbl/d)(g) | 340 |
| | 298 |
| | 225 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions, except operating statistics) |
| Revenues(a) | $ | 8,618 |
| | $ | 8,005 |
| | $ | 8,725 |
|
| Operating expenses(b) | (5,457 | ) | | (4,393 | ) | | (4,738 | ) |
| Loss on impairment of goodwill(c) | — |
| | — |
| | (1,150 | ) |
| Loss on impairments and divestitures, net(d) | (27 | ) | | (200 | ) | | (122 | ) |
| Other income | 1 |
| | 1 |
| | 3 |
|
| Earnings from equity investments(e) | 453 |
| | 385 |
| | 351 |
|
| Loss on impairments of equity investments(f) | (150 | ) | | (606 | ) | | (26 | ) |
| Other, net(g) | 49 |
| | 19 |
| | 24 |
|
| Segment EBDA(a)(b)(c)(d)(e)(f)(g) | 3,487 |
| | 3,211 |
| | 3,067 |
|
| Certain items(a)(b)(c)(d)(e)(f)(g) | 392 |
| | 825 |
| | 1,062 |
|
| Segment EBDA before certain items | $ | 3,879 |
| | $ | 4,036 |
| | $ | 4,129 |
|
| | | | | | |
| Change from prior period | Increase/(Decrease) | | |
| Revenues before certain items | $ | 594 |
| | $ | (477 | ) | | |
| Segment EBDA before certain items | $ | (157 | ) | | $ | (93 | ) | | |
| | | | | | |
| Natural gas transport volumes (BBtu/d)(h) | 29,108 |
| | 28,095 |
| | 28,196 |
|
| Natural gas sales volumes (BBtu/d) | 2,341 |
| | 2,335 |
| | 2,419 |
|
| Natural gas gathering volumes (BBtu/d)(h) | 2,653 |
| | 2,970 |
| | 3,540 |
|
| Crude/condensate gathering volumes (MBbl/d)(h) | 273 |
| | 292 |
| | 309 |
|
_______
Certain item footnotesitems affecting Segment EBDA
| |
| (a) | 2017 and 2015 amount includes increaseamounts include increases in revenues of $8 million and $32 million, respectively, and 2014 and 2013 amounts include decreases2016 amount includes a decrease in revenues of $2$50 million, and $16 million, respectively,all related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales. 2016 amount also includes an increase in revenue of $39 million associated with revenue collected on a customer’s early buyout of a long-term natural gas storage contract. 2015 and 2014 amountsamount also include increasesincludes an increase in revenues of $200 million and $198 million, respectively, associated with amounts collected on the early termination of a long-term natural gas transportation contractscontract on KMLP. |
| |
| (b) | In addition2017 amount includes a decrease in earnings of (i) $166 million related to the revenueimpact of the 2017 Tax Reform; (ii) $3 million related to the non-cash impairment loss associated with the Colden storage field; and (iii) $3 million from other certain items describeditems. 2016 and 2015 amounts include a decrease in footnote (a) above: earnings of $3 million and an increase in earnings of $1 million, respectively, from other certain items. |
| |
| (c) | 2015 amount also includes (i)decrease in earnings of $1,150 million of losses relatedrelates to goodwill impairments on our non-regulated midstream assets;reporting unit. |
| |
| (d) | 2017 amount includes a decrease in earnings of $27 million related to the non-cash impairment loss associated with the Colden storage field. 2016 amount includes (i) a decrease in earnings of $106 million of project write-offs; (ii) an $84 million pre-tax loss on the sale of a 50% interest in our SNG natural gas pipeline system; and (iii) an $11 million decrease in earnings from other certain items. 2015 amount includes (i) $52 million of losses related to disposalsdivestitures of ourcertain non-regulated midstream assets; (iii)(ii) $47 million of losses related to other impairments on our non-regulated midstream assets; and (iv) $45(iii) a $25 million net decrease in earnings related to project write-offs and other certain items. 2014 amount also includes $6 million decrease in earnings from other certain items. 2013 amount also includes (i) a $558 million gain from the remeasurement of a previously held 50% equity interest in Eagle Ford to fair value; (ii) a $36 million gain from the sale of certain Gulf Coast offshore and onshore TGP supply facilities; (iii) a $65 million non-cash equity investment impairment charge related to our ownership interest in NGPL Holdco LLC; and (iv) a combined $23 million decrease in earnings from other certain items. |
| |
(c)(e) | Represents2017 amount includes (i) a lossdecrease in earnings of $58 million related to 2017 Tax Reform adjustments recorded by equity investees; (ii) an increase in earnings from an equity investment of $22 million on the sale of our FTC Natural Gas Pipelines disposal group.a claim related to the early termination of a long-term natural gas transportation contract; (iii) an increase in earnings from an equity investment of $12 million related to a customer contract settlement; (iv) a decrease in earnings of $12 million related to early termination of debt at an equity investee; and (v) a decrease in earnings of $10 million related to a non-cash impairment at an equity investee. 2016 amount includes an increase in earnings of $18 million related to the early termination of a customer contract at an equity investee and a decrease in earnings of $12 million related to |
Other footnotes
other certain items at equity investees. 2015 amount includes an increase in earnings of $5 million related to other certain items at an equity investee.
| |
(d)(f) | Includes pipeline volumes for Kinder Morgan North Texas Pipeline LLC, Monterrey, TransColorado2017 amount includes a $150 million non-cash impairment loss related to our investment in FEP. 2016 amount includes $606 million of non-cash impairment losses primarily related to our investments in MEP and Ruby. 2015 amount includes $26 million of non-cash impairment losses primarily associated with our investment in Fort Union Gas Transmission Company LLC, |
MEP, KMLP, FEP, TGP, EPNG, South Texas Midstream, the Texas Intrastate Natural Gas Pipeline operations, CIG, WIC, CPG, SNG, Elba Express, Sierrita Gas Pipeline LLC, NGPL, Citrus and Ruby Pipeline,Gathering L.L.C. Joint Venture throughput is reported at our ownership share. Volumes for acquired pipelines are included at our ownership share for the entire period, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.
| |
(e) | Represents volumes for the Texas Intrastate Natural Gas Pipeline operations and Kinder Morgan North Texas Pipeline LLC. |
| |
(f)(g) | Includes Oklahoma Midstream, South Texas Midstream, Eagle Ford, North Texas Midstream, Camino Real Gathering Company, L.L.C. (Camino Real), Kinder Morgan Altamont LLC, KinderHawk, Endeavor, Bighorn Gas Gathering L.L.C., Webb Duval Gatherers, Fort Union Gas Gathering L.L.C., EagleHawk, Red Cedar Gathering Company2017 and Hiland Midstream throughput volumes. 2016 amounts include decreases in earnings of $5 million and $10 million, respectively, related to certain litigation matters. |
Other
| |
| (h) | Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included at our ownership share for the entire period. |
| |
(g) | Includes Hiland Midstream, EagleHawk and Camino Real. Joint Venture throughput is reported at our ownership share. Volumesperiod, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition. |
acquired pipelines
Below are included at our ownership share for the entire period.
Following is information, including discontinued operations, related to the increases and decreaseschanges in both Segment EBDA before certain items and revenues before certain items in 20152017 and 2014,2016, when compared with the respective prior year:
Year Ended December 31, 20152017 versus Year Ended December 31, 20142016
| | | | EBDA increase/(decrease) | | Revenues increase/(decrease) | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) |
| | (In millions, except percentages) | (In millions, except percentages) |
| Hiland Midstream | $ | 140 |
| | n/a | | $ | 404 |
| | n/a | |
| SNG | | $ | (200 | ) | | (62)% | | $ | (356 | ) | | (92)% |
| CIG | | (50 | ) | | (18)% | | (45 | ) | | (12)% |
| South Texas Midstream | | (49 | ) | | (18)% | | 10 |
| | 1% |
| KinderHawk | | (20 | ) | | (23)% | | (20 | ) | | (20)% |
| Oklahoma Midstream | | (11 | ) | | (26)% | | 199 |
| | 71% |
| TGP | 36 |
| | 4% | | 48 |
| | 4% | 68 |
| | 6% | | 93 |
| | 6% |
| Elba Express | | 40 |
| | 43% | | 44 |
| | 48% |
| NGPL(a) | | 22 |
| | 183% | | n/a |
| | n/a |
| EPNG | 34 |
| | 8% | | 56 |
| | 10% | 18 |
| | 4% | | 22 |
| | 4% |
| EagleHawk(a) | 31 |
| | 443% | | n/a |
| | n/a | |
| Texas Intrastate Natural Gas Pipeline Operations | 17 |
| | 5% | | (1,231 | ) | | (30)% | 13 |
| | 3% | | 605 |
| | 23% |
| KinderHawk | (67 | ) | | (34)% | | (69 | ) | | (31)% | |
| Oklahoma Midstream(b) | (38 | ) | | (57)% | | (247 | ) | | (47)% | |
| KMLP | (34 | ) | | (61)% | | (34 | ) | | (50)% | |
| CPG | (24 | ) | | (29)% | | (24 | ) | | (24)% | |
| Altamont Midstream | (21 | ) | | (35)% | | (60 | ) | | (37)% | 10 |
| | 27% | | 32 |
| | 32% |
| South Texas Midstream(b) | (9 | ) | | (3)% | | (417 | ) | | (25)% | |
All others (including eliminations)(b) | (9 | ) | | (1)% | | 95 |
| | 7% | 2 |
| | —% | | 10 |
| | 1% |
| Total Natural Gas Pipelines | $ | 56 |
| | 14% | | $ | (1,479 | ) | | (15)% | $ | (157 | ) | | (4)% | | $ | 594 |
| | 7% |
___________________
n/a - not applicable(a) Equity investment
| |
(b) | Includes amounts previously presented as part of “Copano operations.” |
The significant changes in Segment EBDA for our Natural Gas Pipelines business segment’ssegment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 20152017 and 2014 included the following:2016:
decrease of $200 million (62%) from SNG primarily due to our sale of a 50% interest in SNG to Southern Company on September 1, 2016;
decrease of $50 million (18%) from CIG primarily due to a decrease in tariff rates effective January 1, 2017 as a result of a rate case settlement entered into in 2016;
decrease of $49 million (18%) from South Texas Midstream primarily due to lower commodity based service revenues and residue gas sales as a result of lower volumes partially offset by higher NGL sales gross margin primarily due to rising NGL prices;
decrease of $20 million (23%) from KinderHawk primarily due to lower volumes;
decrease of $11 million (26%) from Oklahoma Midstream primarily due to lower volumes and unfavorable producer mix. Higher revenues of $199 million and associated increase in costs of goods sold were primarily due to higher commodity prices;
increase of $140$68 million from our February 2015 acquisition of the Hiland Midstream asset;
increase of $36 million (4%(6%) from TGP primarily due to higher revenues from firm transportation and storage services due largely torevenues driven by incremental capacity sales, expansion projects recently placed in service and an increase in operational gas sales, partially offset by an increase in the associated gas cost;
increase of $40 million (43%) from Elba Express primarily due to an expansion project placed in service in December 2016;
increase of $22 million (183%) from our equity investment in NGPL primarily due to lower interest expense due to a reduction in interest rates due to debt refinancing and the fourth quarter 2014repayment of bank borrowings in 2017;
increase of $18 million (4%) from EPNG primarily due to higher transportation revenues driven by incremental Permian capacity sales and during 2015. Partially offsetting this was an increase in the provision for revenue sharing during 2015, lower transportation usage revenues and natural gas park and loan revenuesvolumes due to milder winter weather in 2015the ramp up of existing customer volumes associated with an expansion project partially offset by increased operations and higher ad valorem taxes;maintenance expense;
increase of $34$13 million (8%) from EPNG due largely to additional firm transport revenues due, in part, to additional demand from Mexico;
increase of $31 million (443%) from EagleHawk driven by higher volumes and lower pipeline integrity costs;
increase of $17 million (5%(3%) from our Texas Intrastate Natural Gas Pipelineintrastate natural gas pipeline operations (including the operations of its Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems) primarily due largely to higher transportation and natural gas sales margins as a result of new customer contracts,higher volumes and higher park and loan revenues partially offset by lower processing margins due to the non-renewal of a customer contract in the second quarter of 2014storage and lower storagesales margins. The decreaseincreases in revenues of $1,231$605 million and associated decreaseresulted primarily from an increase in sales revenue due primarily to higher commodity prices which was largely offset by a corresponding increase in costs of goods sold were caused by lowersales; and
increase of $10 million (27%) from Altamont Midstream primarily due to higher natural gas prices;and liquids revenues due to higher commodity prices and volumes.
Year Ended December 31, 2016 versus Year Ended December 31, 2015
|
| | | | | | | | | | | |
| | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) |
| | (In millions, except percentages) |
| SNG | $ | (109 | ) | | (25)% | | $ | (188 | ) | | (33)% |
| South Texas Midstream | (62 | ) | | (18)% | | (229 | ) | | (18)% |
| KinderHawk | (48 | ) | | (36)% | | (51 | ) | | (33)% |
| KMLP | (31 | ) | | (135)% | | (34 | ) | | (100)% |
| CIG | (27 | ) | | (9)% | | (31 | ) | | (8)% |
| CPGPL | (22 | ) | | (37)% | | (23 | ) | | (29)% |
| TransColorado | (15 | ) | | (48)% | | (16 | ) | | (42)% |
| TGP | 171 |
| | 18% | | 205 |
| | 17% |
| Hiland Midstream | 59 |
| | 42% | | 152 |
| | 38% |
| Texas Intrastate Natural Gas Pipeline Operations | 7 |
| | 2% | | (278 | ) | | (9)% |
| All others (including eliminations) | (16 | ) | | (1)% | | 16 |
| | 1% |
| Total Natural Gas Pipelines | $ | (93 | ) | | (2)% | | $ | (477 | ) | | (6)% |
The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:
decrease of $67$109 million (34%(25%) from KinderHawkSNG primarily due to the expirationour sale of a minimum volume contract;50% interest in SNG to Southern Company on September 1, 2016;
decrease of $38$62 million (57%(18%) from OklahomaSouth Texas Midstream primarily due to lower commodity pricesvolumes and lower volumes. Lower revenues of $247price. Revenue decreased approximately $229 million and associatedpartially offset by a decrease in costs of goods sold were alsosales;
decrease of $48 million (36%) from KinderHawk due to lower commodity prices;volumes;
decrease of $34$31 million (61%(135%) from KMLP as a result of a customer contract buyout in the thirdfourth quarter of 2014;2015;
decrease of $24$27 million (29%(9%) from CPGCIG primarily due to a recent rate case settlement and lower firm reservation revenues due to contract expirations and contract renewals at lower rates;
decrease of $22 million (37%) from CPGPL primarily due to lower transport revenues as a result of contract expirations;
decrease of $21$15 million (35%(48%) from Altamont MidstreamTransColorado primarily due to lower commodity prices partially offset by higher volumes; and
decreasetransport revenues as a result of $9 million (3%) from South Texas Midstream primarily due to lower commodity prices, partially offset by higher gathering and processing volumes. Lower revenues of $417 million and associated decrease in costs of goods sold were due to lower commodity prices.
Year Ended December 31, 2014 versus Year Ended December 31, 2013
|
| | | | | | | | | | | |
| | EBDA increase/(decrease) | | Revenues increase/(decrease) |
| | (In millions, except percentages) |
| Copano operations (including Eagle Ford)(a) | $ | 163 |
| | n/a | | $ | 998 |
| | n/a |
| TGP | 121 |
| | 15% | | 151 |
| | 14% |
| EPNG | 37 |
| | 10% | | 59 |
| | 11% |
| Ruby(b) | 18 |
| | 199% | | n/a |
| | n/a |
| Citrus(b) | 13 |
| | 15% | | n/a |
| | n/a |
| Texas Intrastate Natural Gas Pipeline Operations | 11 |
| | 3% | | 432 |
| | 12% |
| WIC | (24 | ) | | (17)% | | (26 | ) | | (15)% |
| SNG | (17 | ) | | (4)% | | (25 | ) | | (4)% |
| All others (including eliminations) | 30 |
| | 3% | | (250 | ) | | (24)% |
| Total Natural Gas Pipelines | $ | 352 |
| | 9% | | $ | 1,339 |
| | 16% |
_______
n/a – not applicable
| |
(a) | On May 1, 2013, as part of Copano acquisition, we acquired the remaining 50% interest of Eagle Ford. Prior to that date, we recorded earnings from Eagle Ford under the equity method of accounting, but we received distributions in amounts essentially equal to equity earnings plus our share of depreciation and amortization expenses less our share of sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput). |
The significant changes in our Natural Gas Pipelines business segment’s EBDA before certain items in the comparable years of 2014 and 2013 included the following:contract expirations;
increase of $163$171 million from full year ownership of our Copano operations, which we acquired effective May 1, 2013, including benefits from higher gathering volumes from the Eagle Ford Shale;
increase of $121 million (15%(18%) from TGP primarily due to higher revenuesa full year of earnings from (i) firm transportation and storage services due largely to new expansion projects placed in service in the latter part of 2013during 2015 and during 2014 and (ii) usage and interruptible transportation services due to weather-related demand relative to 2013. Partially offsetting the increase in 2014 revenues were higher operating and franchise tax expenses in 2014, and a favorable operational sales margin in 2013;2016 firm transport revenues;
increase of $37$59 million (10%(42%) from EPNG,Hiland Midstream primarily driven by higher transportation revenues and throughput due to increased deliveries to California for storage refillfavorable margins on renegotiated contracts, along with results of a full year from our February 2015 Hiland acquisition; and increased demand in Mexico. The increase in revenues was partially offset by higher field operation and maintenance expenses;
increase of $18$7 million (199%(2%) from Ruby due largely to higher contracted firm transportation revenues and lower interest expense;
increase of $13 million (15%) from Citrus assets, primarily due to higher transportation revenues and reduction in property taxes;
increase of $11 million (3%) fromour Texas Intrastate Natural Gas Pipelineintrastate natural gas pipeline operations (including the operations of its Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems), primarily due largely to higher natural gasstorage margins partially offset by lower sales and transportation margins driven by higher volumes, additional customer contracts and colder weather in the first quarter of 2014, which were offset by lower processing margin due to non-renewal of a certain contract;
decrease of $24 million (17%) from WIC, primarily due to lower reservation revenue as a result of rate reductions pursuant to its FERC Section 5 rate settlement effective November 1, 2013 and lower rates on contract renewals; and
volumes. The decrease in revenues of $17$278 million (4%)resulted primarily from SNG, driven by lower reservation and usage revenuesa decrease in sales revenue due to rate reductions pursuant to its rate case settlement effective September 1, 2013; partiallylower commodity prices which was largely offset by incremental revenues from increased firm transportation services and revenue related to an expansion project that was placeda corresponding decrease in service in late 2013.costs of sales.
CO2
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | (In millions, except operating statistics) |
| Revenues(a) | $ | 1,699 |
| | $ | 1,960 |
| | $ | 1,857 |
|
| Operating expenses | (432 | ) | | (494 | ) | | (439 | ) |
| Loss on impairments and disposals of long-lived assets, net(b) | (606 | ) | | (243 | ) | | — |
|
| Earnings from equity investments(b) | (3 | ) | | 25 |
| | 24 |
|
| Income tax expense | (1 | ) | | (8 | ) | | (7 | ) |
| Segment earnings before DD&A(b) | 657 |
| | 1,240 |
| | 1,435 |
|
| Certain items(b) | 484 |
| | 218 |
| | (3 | ) |
| EBDA before certain items | $ | 1,141 |
| | $ | 1,458 |
| | $ | 1,432 |
|
| | | | | | |
| Change from prior period | Increase/(Decrease) | | |
| Revenues before certain items | $ | (384 | ) | | $ | 81 |
| | |
| EBDA before certain items | $ | (317 | ) | | $ | 26 |
| | |
| | | | | | |
Southwest Colorado CO2 production (gross) (Bcf/d)(c) | 1.2 |
| | 1.3 |
| | 1.2 |
|
Southwest Colorado CO2 production (net) (Bcf/d)(c) | 0.6 |
| | 0.5 |
| | 0.5 |
|
| SACROC oil production (gross)(MBbl/d)(d) | 33.8 |
| | 33.2 |
| | 30.7 |
|
| SACROC oil production (net)(MBbl/d)(e) | 28.1 |
| | 27.6 |
| | 25.5 |
|
| Yates oil production (gross)(MBbl/d)(d) | 19.0 |
| | 19.5 |
| | 20.4 |
|
| Yates oil production (net)(MBbl/d)(e) | 8.5 |
| | 8.8 |
| | 9.0 |
|
| Katz, Goldsmith, and Tall Cotton Oil Production - Gross (MBbl/d)(d) | 5.7 |
| | 4.9 |
| | 3.4 |
|
| Katz, Goldsmith, and Tall Cotton Oil Production - Net (MBbl/d)(e) | 4.8 |
| | 4.1 |
| | 2.8 |
|
| NGL sales volumes (net)(MBbl/d)(e) | 10.4 |
| | 10.1 |
| | 9.9 |
|
| Realized weighted-average oil price per Bbl(f) | $ | 73.11 |
| | $ | 88.41 |
| | $ | 92.70 |
|
| Realized weighted-average NGL price per Bbl(g) | $ | 18.35 |
| | $ | 41.87 |
| | $ | 46.43 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions, except operating statistics) |
| Revenues(a) | $ | 1,196 |
| | $ | 1,221 |
| | $ | 1,699 |
|
| Operating expenses | (394 | ) | | (399 | ) | | (432 | ) |
| Gain (loss) on impairments and divestitures, net(b) | 1 |
| | (19 | ) | | (606 | ) |
| Earnings from equity investments(c) | 44 |
| | 24 |
| | (3 | ) |
| Segment EBDA(a)(b)(c) | 847 |
| | 827 |
| | 658 |
|
| Certain items(a)(b)(c) | 40 |
| | 92 |
| | 484 |
|
| Segment EBDA before certain items | $ | 887 |
| | $ | 919 |
| | $ | 1,142 |
|
| | | | | | |
| Change from prior period | Increase/(Decrease) | | |
| Revenues before certain items | $ | (43 | ) | | $ | (267 | ) | | |
| Segment EBDA before certain items | $ | (32 | ) | | $ | (223 | ) | | |
| | | | | | |
Southwest Colorado CO2 production (gross) (Bcf/d)(d) | 1.3 |
| | 1.2 |
| | 1.2 |
|
Southwest Colorado CO2 production (net) (Bcf/d)(d) | 0.6 |
| | 0.6 |
| | 0.6 |
|
| SACROC oil production (gross)(MBbl/d)(e) | 27.9 |
| | 29.3 |
| | 33.8 |
|
| SACROC oil production (net)(MBbl/d)(f) | 23.2 |
| | 24.4 |
| | 28.1 |
|
| Yates oil production (gross)(MBbl/d)(e) | 17.3 |
| | 18.4 |
| | 19.0 |
|
| Yates oil production (net)(MBbl/d)(f) | 7.7 |
| | 8.2 |
| | 8.5 |
|
| Katz, Goldsmith, and Tall Cotton Oil Production - Gross (MBbl/d)(e) | 8.1 |
| | 7.0 |
| | 5.7 |
|
| Katz, Goldsmith, and Tall Cotton Oil Production - Net (MBbl/d)(f) | 6.9 |
| | 5.9 |
| | 4.8 |
|
| NGL sales volumes (net)(MBbl/d)(f) | 9.9 |
| | 10.3 |
| | 10.4 |
|
| Realized weighted-average oil price per Bbl(g) | $ | 58.40 |
| | $ | 61.52 |
| | $ | 73.11 |
|
| Realized weighted-average NGL price per Bbl(h) | $ | 25.15 |
| | $ | 17.91 |
| | $ | 18.35 |
|
_______
Certain item footnotesitems affecting Segment EBDA
| |
| (a) | 2015, 20142017, 2016 and 20132015 amounts include unrealized gainslosses of $54 million and $63 million, and an unrealized gain of $138 million, $25 million and $3 million, respectively, all relatingrelated to non-cash mark to market derivative contracts used to hedge forecasted crude oilcommodity sales. 2017 amount also includes an increase in revenues of $9 million related to the settlement of a CO2 customer sales contract and 2015 amount also includes a favorable adjustment of $10 million related to carried working interest at McElmo Dome. |
| |
| (b) | In addition to the revenue certain items described in footnote (a) above:2017, 2016 and 2015 amount includes (i) oil and gas property impairments of $399 million; (ii) project write-offs of $207 million; and (iii)amounts include a $26 million decrease in equity earnings for our shareexpense of a$1 million and increases in expense of $20 million and $207 million, respectively, related to source and transportation project write-off. 2014write-offs. 2015 amount also includes oil and gas property impairments of $243$399 million. |
| |
| (c) | 2017, 2016 and 2015 amounts include an increase in equity earnings of $4 million and decreases in equity earnings of $9 million and $26 million, respectively, for our share of a project write-off recorded by an equity investee. |
Other footnotes
| |
(c)(d) | Includes McElmo Dome and Doe Canyon sales volumes. |
| |
(d)(e) | Represents 100% of the production from the field. We own an approximately 97% working interest in the SACROC unit, an approximately 50% working interest in the Yates unit, an approximately 99% working interest in the Katz unit and a 99% working interest in the Goldsmith Landreth unit.unit and a 100% working interest in the Tall Cotton field. |
| |
(e)(f) | Net after royalties and outside working interests. |
| |
(f)(g) | Includes all crude oil production properties. Hedge gains/losses for Oil and NGL are included with Crude Oil. |
| |
(g)(h) | Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements. Hedge gains/losses for Oil and NGL are included with Crude Oil. |
Following is information related toBelow are the increases and decreaseschanges in both Segment EBDA before certain items and revenues before certain items in 20152017 and 2014,2016, when compared with the respective prior year:
Year Ended December 31, 2015 versus Year Ended December 31, 2014
| |
Year Ended December 31, 2017 versus Year Ended December 31, 2016
| | Year Ended December 31, 2017 versus Year Ended December 31, 2016
|
| | | EBDA increase/(decrease) | | Revenues increase/(decrease) | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) |
| | (In millions, except percentages) | (In millions, except percentages) |
| Source and Transportation Activities | $ | (115 | ) | | (26)% | | $ | (116 | ) | | (23)% | $ | 2 |
| | 1% | | $ | (9 | ) | | (3)% |
| Oil and Gas Producing Activities | (202 | ) | | (20)% | | (303 | ) | | (20)% | (34 | ) | | (6)% | | (33 | ) | | (3)% |
| Intrasegment eliminations | — |
| | —% | | 35 |
| | 42% | — |
| | —% | | (1 | ) | | (3)% |
Total CO2 | $ | (317 | ) | | (22)% | | $ | (384 | ) | | (20)% | |
| Total CO2 | | $ | (32 | ) | | (3)% | | $ | (43 | ) | | (3)% |
The primary changes in Segment EBDA for our CO2 business segment’ssegment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 20152017 and 2014 was2016:
increase of $2 million (1%) from our Source and Transportation activities primarily due to increased earnings from an equity investee of $6 million and lower operating expenses of $5 million partially offset by lower revenues of $9 million driven by $405lower contract sales prices of $7 million and decreased volumes of $2 million; and
decrease of $34 million (6%) from our Oil and Gas Producing activities primarily due to decreased revenues of $33 million driven by lower volumes of $22 million and lower commodity prices partially offset by $62of $11 million, and higher operating expenses of increased volumes and $27 million in reduced operating expenses.$1 million.
Year Ended December 31, 2014 versus Year Ended December 31, 2013
| |
Year Ended December 31, 2016 versus Year Ended December 31, 2015
| | Year Ended December 31, 2016 versus Year Ended December 31, 2015
|
| | | EBDA increase/(decrease) | | Revenues increase/(decrease) | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) |
| | (In millions, except percentages) | (In millions, except percentages) |
| Source and Transportation Activities | $ | 56 |
| | 14% | | $ | 59 |
| | 13% | $ | (27 | ) | | (8)% | | $ | (36 | ) | | (9)% |
| Oil and Gas Producing Activities | (30 | ) | | (3)% | | 26 |
| | 2% | (196 | ) | | (24)% | | (241 | ) | | (20)% |
| Intrasegment Eliminations | — |
| | —% | | (4 | ) | | 5% | — |
| | —% | | 10 |
| | 21% |
Total CO2 | $ | 26 |
| | 2% | | $ | 81 |
| | 4% | |
| Total CO2 | | $ | (223 | ) | | (20)% | | $ | (267 | ) | | (17)% |
The primary changes in Segment EBDA for our CO2 business segment’ssegment are further explained by the significant factors driving Segment EBDA before certain items in the comparable years of 20142016 and 2013 included the following:
| |
• | increase of $56 million (14%) from source and transportation activities primarily due to higher2015 which factors include lower revenues driven by an increase of average CO2 contract prices and higher CO2 volumes partly offset by higher labor costs, power costs, property taxes and severance taxes.; and
|
decrease of $30$205 million (3%) from oillower commodity prices and gas producing activities primarily driven$72 million due to decreased volumes, partially offset by higher(i) $27 million in reduced operating expenses as a result of (i) incremental well work costs; (ii) increased power costs;$15 million of lower severance and ad valorem tax expenses; and (iii) higher property and severance tax expenses$11 million primarily related to higher revenues. Also contributing to the decrease was lower crude oil and NGL prices, which were offset by improved net crude oil production.increased earnings from an equity investee.
54
Terminals
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (In millions, except operating statistics) | (In millions, except operating statistics) |
| Revenues(a) | $ | 1,879 |
| | $ | 1,718 |
| | $ | 1,410 |
| $ | 1,966 |
| | $ | 1,922 |
| | $ | 1,879 |
|
Operating expenses | (836 | ) | | (746 | ) | | (657 | ) | (788 | ) | | (768 | ) | | (836 | ) |
| Loss on impairments and disposals of long-lived assets and equity investments, net(b)(c) | (195 | ) | | (29 | ) | | 73 |
| |
| Gain (loss) on impairments and divestitures, net(c) | | 14 |
| | (99 | ) | | (191 | ) |
| Other income | 1 |
| | — |
| | 1 |
| — |
| | — |
| | 1 |
|
Earnings from equity investments | 21 |
| | 18 |
| | 22 |
| 24 |
| | 35 |
| | 21 |
|
| Interest income and Other, net | 8 |
| | 12 |
| | 1 |
| |
| Income tax expense | (29 | ) | | (29 | ) | | (14 | ) | |
| Segment earnings before DD&A(b)(c) | 849 |
| | 944 |
| | 836 |
| |
| Loss on impairments and divestitures of equity investments, net(e) | | — |
| | (16 | ) | | (4 | ) |
| Other, net | | 8 |
| | 4 |
| | 8 |
|
| Segment EBDA(a)(b)(c)(d)(e) | | 1,224 |
| | 1,078 |
| | 878 |
|
Certain items, net(c)(e) | 206 |
| | 35 |
| | (38 | ) | (10 | ) | | 91 |
| | 206 |
|
| EBDA before certain items | $ | 1,055 |
| | $ | 979 |
| | $ | 798 |
| |
| Segment EBDA before certain items | | $ | 1,214 |
| | $ | 1,169 |
| | $ | 1,084 |
|
| | | | | | | | | | | |
| Change from prior period | Increase/(Decrease) | | | Increase/(Decrease) | | |
| Revenues before certain items | $ | 156 |
| | $ | 298 |
| | | $ | 68 |
| | $ | 38 |
| | |
| EBDA before certain items | $ | 76 |
| | $ | 181 |
| | | |
| Segment EBDA before certain items | | $ | 45 |
| | $ | 85 |
| | |
| | | | | | | | | | | |
Bulk transload tonnage (MMtons)(d) | 63.2 |
| | 79.8 |
| | 82.1 |
| 59.5 |
| | 54.8 |
| | 55.6 |
|
| Ethanol (MMBbl) | 63.1 |
| | 66.5 |
| | 61.2 |
| 68.1 |
| | 66.7 |
| | 63.1 |
|
| Liquids leaseable capacity (MMBbl) | 81.3 |
| | 77.8 |
| | 68.0 |
| 87.9 |
| | 84.7 |
| | 78.6 |
|
Liquids utilization %(e)(f) | 93.3 | % | | 95.3 | % | | 94.7 | % | 93.6 | % | | 94.7 | % | | 94.6 | % |
_______
Certain item footnotesitems affecting Segment EBDA
| |
| (a) | 20152017, 2016 and 20142015 amounts include increases in revenues of $23$9 million, $28 million and $18$23 million, respectively, from the amortization of a fair value adjustment (associated with the below market contracts assumed upon acquisition) from our Jones Act tankers. 20132017 amount also includes an $8 million increasea decrease in revenues of $5 million related to hurricane reimbursements.other certain items. |
| |
| (b) | In addition2017 amount includes (i) an increase in expense of $21 million related to the revenuehurricane repairs; (ii) a decrease in expense of $10 million related to accrued dredging costs; and (iii) a decrease in expense of $2 million related to other certain items describeditems. 2016 amount includes an increase in footnote (a) above:expense of $3 million related to other certain items. 2015 amount includes a $34 million increase in bad debt expense due to certain coal customers bankruptcies related to revenues recognized in prior years but not yet collected and $20 million primarily related to impairment charges. 2014 amount also includes a $29 million write-down associated with a sale of certain terminals to a third-party and $24 million of increased expense from other certain items. 2013 amount also includes (i) a $109 millionan increase in earnings from casualty indemnification gains; (ii) a $59expense of $2 million increase in clean-up and repair expense, all related to 2012 hurricane activity at the New York Harbor and Mid-Atlantic terminals; and (iii) a combined $20 million decrease of earnings from other certain items. |
| |
| (c) | An additional2017 amount includes a gain of $23 million primarily related to the sale of a 40% membership interest in the Deeprock Development joint venture in July 2017 and losses of $8 million related to other impairments and divestitures, net. 2016 amount includes an expense of $109 million related to various losses on impairments and divestitures, net. 2015 amount includes a $175 million non-cash pre-tax impairment ($84 million net after-tax impact to common stockholders) of a terminal facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer which occurred after the issuance of our 2015 fourth quarter earnings release containing our preliminary financial results.and $14 million related to other losses on impairments and divestitures, net. |
Other footnotes
| |
| (d) | Includes2016 amount includes an increase in earnings of $9 million related to our proportionate share of joint venture tonnage.the settlement of a certain litigation matter at an equity investee. 2015 amount includes a decrease in earnings of $4 million related to a non-cash impairment at an equity investee. |
| |
| (e) | 2016 amount includes $16 million related to various losses on impairments and divestitures of equity investments, net. |
Other
| |
| (f) | The ratio of our actual leased capacity to our estimated potential capacity. |
Following is information related toBelow are the increases and decreaseschanges in both Segment EBDA before certain items and revenues before certain items in 20152017 and 2014,2016, when compared with the respective prior year:
Year Ended December 31, 2015 versus Year Ended December 31, 2014
|
| | | | | | | | | | | |
| | EBDA increase/(decrease) | | Revenues increase/(decrease) |
| | (In millions, except percentages) |
| Alberta, Canada | $ | 45 |
| | 70% | | $ | 67 |
| | 102% |
| Marine Operations | 44 |
| | n/a | | 57 |
| | n/a |
| Gulf Liquids | 24 |
| | 11% | | 41 |
| | 14% |
| Gulf Central | 23 |
| | 52% | | 30 |
| | 51% |
| Watco | (17 | ) | | (77)% | | (57 | ) | | (67)% |
| Gulf Bulk | (16 | ) | | (18)% | | 22 |
| | 15% |
| Mid Atlantic | (14 | ) | | (21)% | | (25 | ) | | (18)% |
| All others (including intrasegment eliminations and unallocated income tax expenses) | (13 | ) | | (3)% | | 21 |
| | 3% |
| Total Terminals | $ | 76 |
| | 8% | | $ | 156 |
| | 9% |
_______
n/a – not applicableYear Ended December 31, 2017 versus Year Ended December 31, 2016
|
| | | | | | | | | | | |
| | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) |
| | (In millions, except percentages) |
| Marine Operations | $ | 42 |
| | 27% | | $ | 72 |
| | 31% |
| Gulf Liquids | 20 |
| | 8% | | 38 |
| | 11% |
| Alberta, Canada | 8 |
| | 6% | | 7 |
| | 5% |
| Midwest | 7 |
| | 11% | | 15 |
| | 11% |
| Held for sale operations | (19 | ) | | (100)% | | (55 | ) | | (90)% |
| Gulf Central | (17 | ) | | (16)% | | (11 | ) | | (8)% |
| All others (including intrasegment eliminations) | 4 |
| | 1% | | 2 |
| | —% |
| Total Terminals | $ | 45 |
| | 4% | | $ | 68 |
| | 4% |
The primary changes in theSegment EBDA for our Terminals business segment’ssegment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 20152017 and 2014 included the following:
increase of $45 million (70%) from our Alberta, Cananda terminals, driven by our recent Edmonton-area expansion projects, including storage and connectivity additions at our Edmonton South and North 40 terminals as well as the commissioning of two joint venture rail terminals;2016:
increase of $44$42 million (27%) from our Marine Operations related primarily to the incremental earnings from the May 2016, July 2016, September 2016, December 2016, March 2017, June 2017, July 2017 and December 2017 deliveries of the Jones Act tankers, we acquired in the firstMagnolia State, Garden State, Bay State, American Endurance, American Freedom, Palmetto State, American Liberty and fourth quarters of 2014 as well asAmerican Pride, respectively, partially offset by decreased charter rates on the December 2015 delivery from the NASSCO shipyard of the first new build tanker, the “Lone StarGolden State, Pelican State, Sunshine State, Empire State and Pennsylvania;” Jones Act tankers;
increase of $24$20 million (11%(8%) from our Gulf Liquids terminals primarily related to higher volumes as a result of various expansion projects, including the Vopakrecently commissioned Kinder Morgan Export Terminal and North Docks terminal, acquisition completed in first quarter 2015 and the addition of nine new tanks at Galena Park placed into service during fourth quarter 2014 and first quarter 2015;partially offset by lost revenue associated with Hurricane Harvey-related operational disruptions;
increase of $23$8 million (52%(6%) from our Alberta, Canada terminals primarily due to escalations in predominantly fixed, take-or-pay terminaling contracts and a true-up in terminal fees in connection with a favorable arbitration ruling;
increase of $7 million (11%) from our Midwest terminals primarily driven by increased ethanol throughput revenues in 2017 and a new bulk storage and handling contract entered into fourth quarter 2016;
decrease of $19 million (100%) from our sale of certain bulk terminal facilities to an affiliate of Watco Companies, LLC in December 2016 and early 2017; and
decrease of $17 million (16%) from our Gulf Central terminals primarily related to the sale of a 40% membership interest in the Deeprock Development joint venture in July 2017 and the subsequent change in accounting treatment of our retained 11% membership interest as well as lost revenue associated with Hurricane Harvey-related operational disruptions.
Year Ended December 31, 2016 versus Year Ended December 31, 2015
|
| | | | | | | | | | | |
| | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) |
| | (In millions, except percentages) |
| Marine Operations | $ | 52 |
| | 51% | | $ | 73 |
| | 46% |
| Alberta, Canada | 14 |
| | 12% | | 19 |
| | 14% |
| Gulf Liquids | 14 |
| | 6% | | 18 |
| | 5% |
| Northeast | 11 |
| | 10% | | 19 |
| | 10% |
| Lower River | 4 |
| | 7% | | (12 | ) | | (9)% |
| Gulf Bulk | (13 | ) | | (17)% | | (50 | ) | | (29)% |
| Held for sale operations | (2 | ) | | (67)% | | (18 | ) | | (100)% |
| All others (including intrasegment eliminations) | 5 |
| | 1% | | (11 | ) | | (2)% |
| Total Terminals | $ | 85 |
| | 8% | | $ | 38 |
| | 2% |
The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:
increase of $52 million (51%) from our Marine Operations related to the incremental earnings from the December 2015, May 2016, July 2016, September 2016 and December 2016 in-service of the Jones Act tankers the Lone Star State,Magnolia State,Garden State,Bay State,and American Endurance, respectively, and increased charter rates on the Empire State Jones Act tanker;
increase of $14 million (12%) from our Alberta, Canada terminals, driven by highera full year of earnings from our Edmonton South rail terminal joint venture expansion, which began operations in second quarter 2015;
increase of $14 million (6%) from our Gulf Liquids terminals, primarily related to higher volumes as a result of various expansion projects, including marine infrastructure improvements at our joint ventureGalena Park and North Docks terminals, Battleground Oil Specialty Terminal Company LLC (BOSTCO)as well as higher rates and Deeprock Development LLC;ancillary service activities on existing business;
increase of $11 million (10%) from our Northeast terminals, primarily due to contributions from two terminals acquired as part of the BP Products North America Inc. acquisition which was completed in February 2016;
increase of $4 million (7%) from our Lower River terminals, due to a $15 million write-off of certain coal customers accounts receivable which occurred in 2015 and favorable results from certain Lower River terminals, partially offset by decreased revenues and earnings of $18 million due to certain coal customer bankruptcies;
decrease of $17$13 million (77%(17%) from our Gulf Bulk terminals, driven by decreased revenues and earnings of $41 million due to certain coal customer bankruptcies offset by a $28 million write-off of a certain coal customer’s accounts receivable which occurred in the fourth quarter of 2015;
decrease of $2 million (67%) from our sale of certain small bulk and transload terminal facilities to Watco Companies, LLC in early 2015; and
included in “All others” is a decrease in revenues and earnings of $16$11 million (18%) from our Gulf Bulk terminals, primarily from reduced coal earnings due to certain coal customerscustomer bankruptcies of $27as compared to a $4 million partially offset by increased shortfall revenue from take-or-pay coal contracts;
decreasewrite-off of $14 million (21%) from our Mid Atlantic terminals, driven by lower revenues as a result of lower tonnage partially offset by higher shortfall revenue from take-or-pay coal contracts; and
decrease of $21 million primarily from reduced coal earnings due to certain coal customers bankruptcies,accounts receivable which impacted our International Marine Terminals and Mid River terminals includedoccurred in “All others” and the Mid Atlantic terminals noted above by $16 million, $3 million and $2 million, respectively.
Year Ended December 31, 2014 versus Year Ended December 31, 2013
|
| | | | | | | | | | | |
| | EBDA increase/(decrease) | | Revenues increase/(decrease) |
| | (In millions, except percentages) |
| Acquired assets and businesses | $ | 66 |
| | n/a | | $ | 109 |
| | n/a |
| Alberta, Canada | 32 |
| | 45% | | 49 |
| | 38% |
| Gulf Central | 30 |
| | 213% | | 51 |
| | 663% |
| Gulf Liquids | 20 |
| | 10% | | 22 |
| | 8% |
| Gulf Bulk | 19 |
| | 25% | | 26 |
| | 19% |
| All others (including intrasegment eliminations and unallocated income tax expenses) | 14 |
| | 3% | | 41 |
| | 5% |
| Total Terminals | $ | 181 |
| | 23% | | $ | 298 |
| | 21% |
_______
n/a – not applicable
The primary changes in the Terminals business segment’s EBDA before certain items in the comparable years of 2014 and 2013 included the following:
increase of $66 million from acquired assets and businesses, primarily the acquisition of the Jones Act tankers;
increase of $32 million (45%) from our Alberta, Canada terminals, driven by the completion of Edmonton expansion projects;
increase of $30 million (213%) from our Gulf Central terminals, driven by higher earnings from our 55% interest in BOSTCO oil terminal joint venture, which is located on the Houston Ship Channel and began operations in October 2013;
increase of $20 million (10%) from our Gulf Liquids terminals, due to higher liquids warehousing revenues from our Pasadena and Galena Park liquids facilities located along the Houston Ship Channel. The facilities benefited from high gasoline export demand, increased rail services and new and incremental customer agreements at higher rates, due in part to new tankage from completed expansion projects;
increase of $19 million (25%) from our Gulf Bulk terminals, driven by increased shortfall revenue from take-or-pay coal contracts and higher petcoke period-to-period volumes in 2014, due largely to refinery and coker shutdowns in 2013 as a result of turnarounds taken; and
increase of $14 million (3%) from the rest of the terminal operations was driven primarily by increased shortfall revenue recognized on take-or-pay contracts at our International Marine Terminal in Myrtle Grove, Louisiana and earnings from the BP Whiting terminal in Whiting, Indiana which was placed in service in the third quarter of 2013.2015.
Products Pipelines
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | (In millions, except operating statistics) |
| Revenues | $ | 1,831 |
| | $ | 2,068 |
| | $ | 1,853 |
|
| Operating expenses | (772 | ) | | (1,258 | ) | | (1,295 | ) |
| Other (expense) income | (2 | ) | | 3 |
| | (6 | ) |
| Earnings from equity investments | 45 |
| | 44 |
| | 45 |
|
| Interest income and Other, net | 6 |
| | 1 |
| | 3 |
|
| Income tax (expense) benefit | (8 | ) | | (2 | ) | | 2 |
|
| Segment earnings before DD&A(a) | 1,100 |
| | 856 |
| | 602 |
|
| Certain items(a) | (4 | ) | | 4 |
| | 182 |
|
| EBDA before certain items | $ | 1,096 |
| | $ | 860 |
| | $ | 784 |
|
| | | | | | |
| Change from prior period | Increase/(Decrease) | | |
| Revenues | $ | (237 | ) | | $ | 215 |
| | |
| EBDA before certain items | $ | 236 |
| | $ | 76 |
| | |
| | | | | | |
| Gasoline (MMBbl) (b) | 377.7 |
| | 364.7 |
| | 350.3 |
|
| Diesel fuel (MMBbl) | 131.8 |
| | 129.1 |
| | 125.1 |
|
| Jet fuel (MMBbl) | 103.1 |
| | 100.5 |
| | 98.6 |
|
| Total refined product volumes (MMBbl)(c) | 612.6 |
| | 594.3 |
| | 574.0 |
|
| NGL (MMBbl)(d) | 38.6 |
| | 25.3 |
| | 27.7 |
|
| Condensate (MMBbl)(e) | 99.7 |
| | 33.2 |
| | 10.7 |
|
| Total delivery volumes (MMBbl) | 750.9 |
| | 652.8 |
| | 612.4 |
|
| Ethanol (MMBbl)(f) | 41.4 |
| | 41.6 |
| | 38.7 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions, except operating statistics) |
| Revenues | $ | 1,661 |
| | $ | 1,649 |
| | $ | 1,831 |
|
| Operating expenses(a) | (487 | ) | | (573 | ) | | (772 | ) |
| Loss on impairments and divestitures, net(b) | — |
| | (76 | ) | | — |
|
| Other (expense) income | — |
| | — |
| | (2 | ) |
| Earnings from equity investments(c) | 58 |
| | 53 |
| | 45 |
|
| Gain on divestiture of equity investment(d) | — |
| | 12 |
| | — |
|
| Other, net | (1 | ) | | 2 |
| | 4 |
|
| Segment EBDA(a)(b)(c)(d) | 1,231 |
| | 1,067 |
| | 1,106 |
|
| Certain items(a)(b)(c)(d) | (38 | ) | | 113 |
| | (4 | ) |
| Segment EBDA before certain items | $ | 1,193 |
| | $ | 1,180 |
| | $ | 1,102 |
|
| | | | | | |
| Change from prior period | Increase/(Decrease) | | |
| Revenues before certain items | $ | 12 |
| | $ | (182 | ) | | |
| Segment EBDA before certain items | $ | 13 |
| | $ | 78 |
| | |
| | | | | | |
| Gasoline (MBbl/d) (e) | 1,038 |
| | 1,025 |
| | 1,011 |
|
| Diesel fuel (MBbl/d) | 351 |
| | 342 |
| | 354 |
|
| Jet fuel (MBbl/d) | 297 |
| | 288 |
| | 282 |
|
| Total refined product volumes (MBbl/d)(f) | 1,686 |
| | 1,655 |
| | 1,647 |
|
| NGL (MBbl/d)(f) | 112 |
| | 109 |
| | 106 |
|
| Condensate (MBbl/d)(f) | 327 |
| | 324 |
| | 273 |
|
| Total delivery volumes (MBbl/d) | 2,125 |
| | 2,088 |
| | 2,026 |
|
| Ethanol (MBbl/d)(g) | 117 |
| | 115 |
| | 113 |
|
_______
Certain item footnoteitems affecting Segment EBDA
| |
| (a) | 2017 amount includes a decrease in expense of $34 million related to a right-of-way settlement and an increase in expense of $1 million related to hurricane repairs. 2016 amount includes increases in expense of $31 million of rate case liability estimate adjustments associated with prior periods and $20 million related to a legal settlement. 2015 and 2014 amounts includeamount includes a $4 million decrease in expense and a $4 million increase in expense, respectively, associated with a certain Pacific operations litigation matter. 2013 amount includes (i) a $162 million increase in expense associated with rate case liability adjustments; (ii) a $15 million increase in expense associated with a legal liability adjustment related to a certain West Coast terminal environmental matter; and (iii) $5 million loss from the write-off of assets at our Los Angeles Harbor West Coast terminal. |
Other footnotes
| |
| (b) | Volumes include ethanol pipeline volumes. 2016 amount includes increases in expense of $65 million related to the Palmetto project write-off and $9 million of non-cash impairment charges related to the sale of a Transmix facility. |
| |
| (c) | Includes Pacific, Plantation Pipe Line Company, Calnev, Central Florida and Parkway pipeline volumes. Joint2017 amount includes an increase in equity earnings of $5 million related to the impact of the 2017 Tax Reform at an equity investee. |
Venture throughput is reported at our ownership share.
| |
| (d) | Includes Cochin and Cypress2016 amount includes a $12 million gain related to the sale of an equity investment. |
Other
| |
| (e) | Volumes include ethanol pipeline volumes. |
| |
| (f) | Joint Venture throughput is reported at our ownership share. |
| |
(e) | Includes Kinder Morgan Crude & Condensate, Double Eagle Pipeline LLC and Double H pipeline volumes. Joint Venture throughput is |
reported at our ownership share.
| |
(f)(g) | Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above. |
Following is information related toBelow are the increases and decreaseschanges in both Segment EBDA before certain items and revenues before certain items in 20152017 and 2014,2016, when compared with the respective prior year:
Year Ended December 31, 2015 versus Year Ended December 31, 2014
|
| | | | | | | | | | | |
| | EBDA increase/(decrease) | | Revenues increase/(decrease) |
| | (In millions, except percentages) |
| Crude & Condensate Pipeline | $ | 102 |
| | 124% | | $ | 90 |
| | 81% |
| KMCC - Splitter | 33 |
| | n/a | | 43 |
| | n/a |
| Double H pipeline | 44 |
| | n/a | | 56 |
| | n/a |
| Cochin | 29 |
| | 34% | | 54 |
| | 50% |
| Pacific operations | 23 |
| | 7% | | 27 |
| | 6% |
| Transmix operations | 8 |
| | 33% | | (490 | ) | | (49)% |
| All others (including eliminations) | (3 | ) | | (1)% | | (17 | ) | | (4)% |
| Total Products Pipelines | $ | 236 |
| | 27% | | $ | (237 | ) | | (12)% |
_______
n/a - not applicableYear Ended December 31, 2017 versus Year Ended December 31, 2016
|
| | | | | | | | | | | |
| | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) |
| | (In millions, except percentages) |
| Pacific operations | $ | 5 |
| | 1% | | $ | 11 |
| | 2% |
| South East Terminals | 4 |
| | 5% | | 6 |
| | 5% |
| Calnev | 3 |
| | 6% | | 2 |
| | 3% |
| Double Eagle | 3 |
| | 30% | | 2 |
| | 40% |
| Transmix | 1 |
| | 3% | | (14 | ) | | (6)% |
| Parkway | (3 | ) | | (100)% | | (1 | ) | | (100)% |
| All others (including eliminations) | — |
| | —% | | 6 |
| | 1% |
| Total Products Pipelines | $ | 13 |
| | 1% | | $ | 12 |
| | 1% |
The primary changes in theSegment EBDA for our Products Pipelines business segment’ssegment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 20152017 and 2014 included the following:2016:
increase of $102$5 million (124%(1%) from Pacific operations primarily due to higher service revenues driven by an increase in volumes partially offset by a volume driven increase in power costs and an increase in right-of-way expense;
increase of $4 million (5%) from our South East Terminals primarily due to higher revenues driven by higher volumes as a result of capital expansion projects being placed in service during 2017;
increase of $3 million (6%) from Calnev primarily due to higher service revenues driven by higher volumes and a decrease in expense related to the reduction of a rate reserve;
increase of $3 million (30%) from Double Eagle primarily due to higher revenues driven by higher volumes and price;
increase of $1 million (3%) from our Transmix processing operations. The decrease in revenues of $14 million and associated decrease in costs of goods sold were driven by lower sales volumes primarily due to the sale of our Indianola plant in August 2016 and lower brokered sales at the Dorsey plant due to an expired contract in May 2017; and
decrease of $3 million (100%) from Parkway pipeline due to our sale of our 50% interest in Parkway pipeline on July 1, 2016.
Year Ended December 31, 2016 versus Year Ended December 31, 2015
|
| | | | | | | | | | | |
| | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) |
| | (In millions, except percentages) |
| Crude & Condensate Pipeline | $ | 37 |
| | 20% | | $ | 36 |
| | 18% |
| KMCC - Splitter | 20 |
| | 53% | | 30 |
| | 71% |
| Double H pipeline | 15 |
| | 34% | | 22 |
| | 39% |
| Plantation Pipe Line | 9 |
| | 17% | | 1 |
| | 5% |
| Transmix | 8 |
| | 26% | | (286 | ) | | (57)% |
| Cochin | (13 | ) | | (11)% | | 3 |
| | 2% |
| All others (including eliminations) | 2 |
| | —% | | 12 |
| | 1% |
| Total Products Pipelines | $ | 78 |
| | 7% | | $ | (182 | ) | | (10)% |
The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:
increase of $37 million (20%) from Kinder Morgan Crude & Condensate Pipeline driven primarily by an increase ofin pipeline throughput volumes due to the ramp up offrom existing customer volumescustomers and additional volumes from new customers;associated with expansion projects;
increase of $33$20 million (53%) from our KMCC - Splitter due to the startup of the first and second phases being in full operation for 2016. Start up of first phase was in March 2015 and second phase was in July 2015;
increase of $44$15 million (34%) due to full year of results from our Double H pipeline, which was acquiredbegan operations in February 2015 as part of the Hiland acquisition;March 2015;
increase of $29$9 million (34%) from Cochin driven by higher service revenues due to the completion of the Cochin Reversal project in the third quarter of 2014;
increase of $23 million (7%(17%) from our Pacific operationsequity investment in Plantation Pipe Line primarily due to higher service revenues, resulting from higher volumes and margins; andlower operating costs;
increase of $8 million (33%(26%) from our Transmix processing operations primarilylargely due to favorable inventory adjustments impacting margins.unfavorable market price impacts during the fourth quarter of 2015. The decrease in revenues of $490$286 million and associated decrease in costs of goods sold were causeddriven by lower commodity prices.sales volumes primarily due to the sale of our Indianola plant in August 2016; and
Year Ended December 31, 2014 versus Year Ended December 31, 2013
|
| | | | | | | | | | | |
| | EBDA increase/(decrease) | | Revenues increase/(decrease) |
| | (In millions, except percentages) |
| Crude & Condensate Pipeline | $ | 67 |
| | 320% | | $ | 89 |
| | 402% |
| Pacific operations | 36 |
| | 13% | | 25 |
| | 6% |
| Transmix operations | (19 | ) | | (44)% | | 92 |
| | 10% |
| All others (including eliminations) | (8 | ) | | (2)% | | 9 |
| | 2% |
| Total Products Pipelines | $ | 76 |
| | 10% | | $ | 215 |
| | 12% |
The primary changes in the Products Pipelines business segment’s EBDA before certain items in the comparable yearsdecrease of 2014 and 2013 included the following:
increase of $67$13 million (320%(11%) from Kinder Morgan Crude & Condensate Pipeline, drivenCochin primarily by an increase of pipeline throughput volumes to 81.0 MBbl/d as compared to 24.1 MBbl/d in 2013 (236%);
increase of $36 million (13%) from our Pacific operations, due to higher service revenues driven by higher volumes and margins and lower operating expenses primarily due to lower rights-of-way expenses; and
decrease of $19 million (44%) from our transmix processing operations, primarily driven by unfavorable inventory pricing. The increase in revenues of $92 million and associated increase in costs of goods sold were caused by higher product sales volumes.pipeline integrity costs.
Kinder Morgan Canada
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | (In millions, except operating statistics) |
| Revenues | $ | 260 |
| | $ | 291 |
| | $ | 302 |
|
| Operating expenses | (87 | ) | | (106 | ) | | (110 | ) |
| Other income | 1 |
| | — |
| | — |
|
| Earnings from equity investments | — |
| | — |
| | 4 |
|
| Interest income and Other, net | 8 |
| | 15 |
| | 249 |
|
| Income tax expense | (19 | ) | | (18 | ) | | (21 | ) |
| Segment earnings before DD&A(a) | 163 |
| | 182 |
| | 424 |
|
| Certain items, net(a) | — |
| | — |
| | (224 | ) |
| EBDA before certain items | $ | 163 |
| | $ | 182 |
| | $ | 200 |
|
| | | | | | |
| Change from prior period | Increase/(Decrease) | | |
| Revenues | $ | (31 | ) | | $ | (11 | ) | | |
| EBDA before certain items | $ | (19 | ) | | $ | (18 | ) | | |
| | | | | | |
| Transport volumes (MMBbl)(b) | 115.4 |
| | 106.8 |
| | 101.1 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions, except operating statistics) |
| Revenues | $ | 256 |
| | $ | 253 |
| | $ | 260 |
|
| Operating expenses | (95 | ) | | (87 | ) | | (87 | ) |
| Other income | — |
| | — |
| | 1 |
|
| Other, net | 25 |
| | 15 |
| | 8 |
|
| Segment EBDA | $ | 186 |
| | $ | 181 |
| | $ | 182 |
|
| | | | | | |
| Change from prior period | Increase/(Decrease) | | |
| Revenues | $ | 3 |
| | $ | (7 | ) | | |
| Segment EBDA | $ | 5 |
| | $ | (1 | ) | | |
| | | | | | |
| Transport volumes (MBbl/d)(a) | 308 |
| | 316 |
| | 316 |
|
______
Certain item footnote
| |
| (a) | 2013 amount includes a $224 million pre-tax gain from the sale of our equity and debt investments in the Express pipeline system. |
Other footnote
| |
(b) | Represents Trans Mountain pipeline system volumes. |
Following is information relatedFor the comparable years of 2017 and 2016, the Kinder Morgan Canada business segment had an increase in Segment EBDA of $5 million (3%) and an increase in revenues of $3 million (1%) primarily due to increases(i) higher capitalized equity financing costs due to spending on the TMEP; (ii) currency translation gains due to the strengthening of the Canadian dollar; and decreases in both EBDA(iii) higher incentive revenues partly offset by lower state of Washington volumes and revenues before certain items in 2015 and 2014, when compared with the respective prior year:operating expense timing changes.
Year Ended December 31, 2015 versus Year Ended December 31, 2014
|
| | | | | | | | | | | |
| | EBDA increase/(decrease) | | Revenues increase/(decrease) |
| | (In millions, except percentages) |
| Trans Mountain Pipeline | $ | (12 | ) | | (7)% | | $ | (30 | ) | | (11)% |
| Express Pipeline(a) | (7 | ) | | (100)% | | n/a |
| | n/a |
| Jet Fuel Pipeline | — |
| | —% | | (1 | ) | | (17)% |
| Total Kinder Morgan Canada | $ | (19 | ) | | (10)% | | $ | (31 | ) | | (11)% |
_______
n/a - not applicable
| |
(a) | Amount consists of unrealized foreign currency gains, net of book tax, on 2014 outstanding, short-term intercompany borrowings that were repaid in December 2014. We sold our debt and equity investments in Express Pipeline on March 14, 2013. |
For the comparable years of 20152016 and 2014,2015, the Kinder Morgan Canada business segment had a decrease in earningsSegment EBDA of $19$1 million (10%(1%) which was driven primarily by an unfavorable impact from foreign currency exchange rates, and repayment of the Express note as discussed in footnote (a) above.
Year Ended December 31, 2014 versus Year Ended December 31, 2013
|
| | | | | | | | | | | |
| | EBDA increase/(decrease) | | Revenues increase/(decrease) |
| | (In millions, except percentages) |
| Express Pipeline(a) | $ | (6 | ) | | (44)% | | n/a |
| | n/a |
| Trans Mountain Pipeline | (12 | ) | | (6)% | | $ | (11 | ) | | (4)% |
| Total Kinder Morgan Canada | $ | (18 | ) | | (9)% | | $ | (11 | ) | | (4)% |
______
n/a - not applicable
| |
(a) | Amount consists of unrealized foreign currency gains, net of book tax, on outstanding, short-term intercompany borrowings that were repaid in December 2014. We sold our debt and equity investments in Express Pipeline on March 14, 2013. |
For the comparable years of 2014 and 2013, the Trans Mountain Pipeline had a decrease in earningsrevenues of $12$7 million (6%(3%) which was driven primarily by an unfavorable impact from foreign currency exchange rates. Due to the weakening of the Canadian dollar since the end of the third quarter of 2013, we translated Canadian denominated income and expense amounts into fewer U.S. dollars in 2014..
Other
This segment contributed a loss of $53 million, earnings of $13 million and a loss of $5 million for the years ended 2015, 2014 and 2013, respectively. However, 2015 and 2014 earnings include certain items of a $35 million decrease in earnings and a $22 million increase in earnings, respectively. The 2015 certain items related primarily to a litigation matter and the 2014 certain items were primarily related to our foreign operations. After taking into effect the certain items, the earnings for 2015 and 2014, decreased by $9 million and $4 million, respectively, when compared with the respective prior year.
General and Administrative, Interest, Corporate and Noncontrolling Interests
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | (In millions) |
| General and administrative expense(a)(d) | $ | 690 |
| | $ | 610 |
| | $ | 613 |
|
| Certain items(a) | (25 | ) | | 28 |
| | 8 |
|
| Management fee reimbursement(d) | (37 | ) | | (36 | ) | | (36 | ) |
| General and administrative expense before certain items | $ | 628 |
| | $ | 602 |
| | $ | 585 |
|
| | | | | | |
| Unallocable interest expense net of interest income and other, net(b) | $ | 2,055 |
| | $ | 1,807 |
| | $ | 1,688 |
|
| Certain items(b) | 27 |
| | 3 |
| | 32 |
|
| Unallocable interest expense net of interest income and other, net, before certain items | $ | 2,082 |
| | $ | 1,810 |
| | $ | 1,720 |
|
| | | | | | |
| Net (loss) income attributable to noncontrolling interests | $ | (45 | ) | | $ | 1,417 |
| | $ | 1,499 |
|
| Noncontrolling interests associated with certain items(c) | 63 |
| | — |
| | — |
|
| Net income attributable to noncontrolling interests before certain items | $ | 18 |
| | $ | 1,417 |
| | $ | 1,499 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| General and administrative and corporate charges(a) | $ | 660 |
| | $ | 652 |
| | $ | 708 |
|
| Certain items(a) | (15 | ) | | 13 |
| | (60 | ) |
| General and administrative and corporate charges before certain items | $ | 645 |
| | $ | 665 |
| | $ | 648 |
|
| | | | | | |
| Interest, net(b) | $ | 1,832 |
| | $ | 1,806 |
| | $ | 2,051 |
|
| Certain items(b) | 39 |
| | 193 |
| | 27 |
|
| Interest, net, before certain items | $ | 1,871 |
| | $ | 1,999 |
| | $ | 2,078 |
|
| | | | | | |
| Net income (loss) attributable to noncontrolling interests(c) | $ | 40 |
| | $ | 13 |
| | $ | (45 | ) |
| Noncontrolling interests associated with certain items(c) | — |
| | 8 |
| | 63 |
|
| Net income attributable to noncontrolling interests before certain items | $ | 40 |
| | $ | 21 |
| | $ | 18 |
|
_______
Certain item footnotesitems
| |
| (a) | 2015, 2014 and 2013 amounts include decreases2017 amount includes (i) an increase in expense of $35$10 million $39 millionfor acquisition and $59divestiture related costs; (ii) an increase in expense of $4 million related to certain corporate litigation matters; (iii) an increase in expense of $5 million related to a pension credit income. 2015settlement; and (iv) decrease in expense of $4 million related to other certain items. 2016 amount also includes increases in expense of $45(i) $14 million related to severance costs; and (ii) $12 million related to acquisition and divestiture costs; offset by decreases in expense of (i) $34 million related to certain corporate litigation matters; and (ii) $5 million related to other certain items. 2015 amount includes increases in expense of (i) $71 million related to certain corporate legal matters andmatters; (ii) $15 million related to costs associated with acquisitions. 2014 amount also includes a net increase of $11acquisitions; and (iii) $9 million in expense for variousassociated with other certain items. 2013 amount also includes increasesitems; offset by a decrease in expense of $41$35 million related to asset and business acquisition costs and unallocated legal expenses and a combined $10 million from other certain items primarily related to the acquisition of EP.pension credit income. |
| |
| (b) | 2015, 20142017, 2016 and 20132015 amounts include (i) decreases in interest expense of $71$44 million, $65$115 million and $67$71 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions. 2015acquisitions and 2014 amounts also include (i) a(ii) decreases of $3 million and $44 million and an increase of $23 million, increase and $1 million decrease, respectively, in interest expense primarily related to a non-cash true-uptrue-ups of our estimateestimates of swap ineffectiveness;ineffectiveness. 2017 amount also includes an $8 million increase in interest expense related to other certain items. 2016 and (ii)2015 amounts also include a $13$34 million decrease and $15a $21 million increase, respectively, in interest expense associated with arelated to certain Pacific operations litigation matter.matters. |
2015 amount also includes a $34 million increase in interest expense for a non-cash adjustment related to a litigation matter. 2014 and 2013 amounts also include increases in expense of $9 million and $21 million, respectively, of amortization of capitalized financing fees and $12 million and $14 million, respectively, of interest expense on margin for marketing contracts. 2014 amount also includes $27 million of interest expense related to the Merger Transactions.
| |
| (c) | 2015 amount includesAmounts reflect the noncontrolling interest portion of certain items including (i) a $43$49 million impairment recognized after the issuance of ourloss for 2015 fourth quarter earnings release containing our preliminary financial results and a $6 million loss associated with Terminals segment certain items and disclosed above in “—Terminals” and (ii) an $8 million loss for 2016 and a $14 million loss for 2015 associated with a Natural Gas Pipelines segment impairment certain itemitems and disclosed above in “—Natural Gas Pipelines.” |
Other footnote
| |
(d) | 2015, 2014 and 2013 amounts include NGPL Holdco LLC general and administrative reimbursements of $37 million, $36 million and $36 million, respectively. These amounts were recorded to the “Product sales and other” caption with the offsetting expenses primarily included in the “General and administrative” expense caption in our accompanying consolidated statements of income. |
The increase in generalGeneral and administrative expenses and corporate charges before certain items of $26decreased $20 million in 2017 and increased $17 million in 2015 and 20142016 when compared with the respective prior yearyear. The decrease in 2017 as compared to 2016 was primarily driven by the acquisitionsale of Hilanda 50% interest in our SNG natural gas pipeline system (effective February 13, 2015)September 1, 2016), higher capitalized costs, lower state franchise taxes, legal and Copano (effective May 1, 2013). Additional drivers for theinsurance costs, partially offset by higher labor accruals and pension costs. The increase betweenin 2016 as compared to 2015 was primarily driven by higher benefit costs, higher corporate charges and 2014 were lower capitalized costs and higher labor expenses partially offset by lower benefit and insurance costs while the increase between 2014 and 2013 was impacted by higher benefit costs, payroll taxes and labor, expenses partially offset by lower costs on our corporate headquarters buildingoutside services and insurance costs.
In the table above, we report our interest expense as “net,” meaning that we have subtracted unallocated interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense net of interest income and other, net before certain items, increased $272 million and $90decreased $128 million in 20152017 and 2014,$79 million in 2016, respectively, when compared with the respective prior year. The increasedecrease in interest expense in 20152017 as compared to 20142016 was primarily due to higherlower weighted average debt balances as proceeds from the May 2017 KML IPO and our September 2016 sale of a result of capital expenditures, joint venture contributions and acquisitions that50% interest in SNG were made during 2014 and 2015, and incrementalused to pay down debt, borrowings to fund the $3.9 billion cash portion of the Merger Transactions in November 2014.
partially offset by a slightly higher overall weighted average interest rate on our outstanding debt. The increasedecrease in interest expense in 20142016 as compared to 20132015 was primarily due to higherlower weighted average debt balances, as a result of capital expenditures, joint venture contributions and acquisitions that were made during 2014 and incremental debt borrowings to fund the $3.9 billion cash portion of the Merger Transactions in November 2014. In addition, the increase was impacted by the refinancing of the short-term KMI credit facility debt with a $1.5 billion long-term debt issuance in November 2013, which had a higher interest rate. This increase in interest expense was partially offset by (i) lowera slightly higher overall weighted average balances outstandinginterest rate on our EP acquisition term loan as a result of its termination in November 2014 and (ii) lower interest rates on our credit facility and EP acquisition term loan as a result of the refinancing of these facilities in 2014.outstanding debt.
We use interest rate swap agreements to transformconvert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of both December 31, 20152017 and December 31, 2014,2016, approximately 27% and 26%, respectively,28% of our debt balances (excluding debt fair value adjustments) were subject to variable interest rates-either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see Note 14 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.
Net income attributable to noncontrolling interests, represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not held by us. The $1,399 million decrease (99%)for 2015 as compared to 2014 was primarily due to our purchase of the KMP and EPB limited partner units and KMR shares formerly owned by the public in the fourth quarter of 2014 as part of the Merger Transactions. The $82 million decrease (5%) for 2014 as compared to 2013 was primarily due to our noncontrolling interests’ portion of (i) our 2013 $558 million pre-tax gain from the remeasurement of our previously held 50% equity interest in Eagle Ford to fair value; and (ii) our 2013 $140 million after-tax gain on the sale of our investments in the Express pipeline system; which was partially offset by our noncontrolling interests’ portion of our 2014 $198 million pre-tax increase associated with the early termination of a long-term natural gas transportation contract by a certain customer of KMLP and an increase in income allocated to noncontolling interests during the fourth quarter 2014 due to the elimination of the incentive distribution rights as a result of the Merger Transactions.
Subsequent to the Merger Transactions, netNet income attributable to noncontrolling interests representsbefore certain items for 2017 as compared to 2016 increased $19 million (90%) due to the May 30, 2017 sale of approximately 30% of our Canadian business operations to the public in the KML IPO. The portion of our Canadian business operations net income allocated to third-party ownership interests in consolidated subsidiaries. Priorattributable to the Merger Transactions it also included netpublic is now reflected in “Net income allocatedattributable to KMP and EPB limited partner units formerly owned by the public.noncontrolling interests.” Net income attributable to noncontrolling interests before certain items for 2016 as compared to 2015 increased $3 million (17%).
Income Taxes—Continuing OperationsTaxes
Year Ended December 31, 20152017 versus Year Ended December 31, 20142016
Our income tax expense from continuing operations for the year ended December 31, 2015 was $5642017 is approximately $1,938 million, as compared with 2014 income2016 tax expense of $648$917 million. The $84$1,021 million decreaseincrease in income tax expense is due primarily to (i) the tax impact of lower pretax earnings in 2015 primarily due to (i) an increase in year-over-year earnings as a result of fewer asset impairments and project write-offs in 2017 and (ii) higher tax expense as a result of the 2017 Tax Reform. These increases are partially offset by (i) the 2016 impact of our Regulated Natural Gas Pipeline segment’s $817 million non-tax-deductible goodwill as a result of the sale of a 50% interest in SNG; and (ii) the recognition of $929enhanced oil recovery credits.
Year Ended December 31, 2016 versus Year Ended December 31, 2015
Our tax expense for the year ended December 31, 2016 is approximately $917 million, as compared with 2015 tax expense of $564 million. The $353 million increase in tax expense is primarily due to (i) an increase in our earnings as a result of lower impairments on long-lived assets and investments and $1,150 million goodwill impairment of natural gas pipelines non-regulated midstream assets, of which $882 million is not tax deductible;in 2016; (ii) the tax benefit of anyear over year increase in the deferred state tax rateexpense as a result of our sale of a 50% interest in SNG in 2016 and the Hiland acquisition;acquisition in 2015; and (iii) the 2014 recording of a valuation allowance relatedallowances recorded in 2016 for foreign tax credits and capital loss carryforwards for which we do not expect to our investment in NGPL; and (iv) the elimination, as a result of the Merger Transactions, of the amortization of the deferred charge recorded as a result of the drop-downs of TGP, EPNG, and the midstream assets.recognize any future tax benefits. These decreasesincreases are partially offset by the 2014 benefit of a worthless stock deduction related to our Brazil operations.
Year Ended December 31, 2014 versus Year Ended December 31, 2013
Our income tax expense from continuing operations for the year ended December 31, 2014 was$648 million, as compared with 2013 income tax expense of $742 million.The$94 million decrease in income tax expense is due primarily to (i) the tax impact of lower pretax earnings in 2014 associated with our investment in KMP primarily related to KMP’s 2014 recognition of a $235 million impairment of CO2 assets compared to gains recognized in 2013 of $558 million on remeasurement to fair value of the initial 50% interest in the Eagle Ford joint venture and $224 million on the sale of the one-third interest in the Express pipeline system; (ii) a 2014 worthless stock deduction related to our Brazil operations; and (iii) a 2013 decrease in our share of non-tax-deductible goodwill associated with our investment in KMP (as a result of our change in ownership primarily due to KMP’s acquisition of Copano). These decreases are partially offset by (i) the tax benefit in 2013 of a decrease in the deferred state tax rate as a result of the drop-down of our 50% ownership interest in EPNG and midstream assets and KMP’s acquisition of Copano; (ii) 2013 adjustments to our income tax reserve for uncertain tax positions as a result of the settlement of legacy EP Internal Revenue Service audits; and (iii) the 2014 recording of a valuation allowance related to our investment in NGPL.positions.
Liquidity and Capital Resources
General
As of December 31, 2015,2017, we had $229$264 million of “Cash and cash equivalents,” on our consolidated balance sheet, a decrease of $86$420 million (27%(61%) from December 31, 2014.2016. We believe our cash position, remaining borrowing capacity on our credit facility (discussed below in “—Short-term Liquidity”), and our cash flows from operating activities are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.
We have consistently generated strongsubstantial cash flow from operations, providing a source of funds of $5,303$4,601 million and $4,467$4,795 million in 20152017 and 2014, respectively (the2016, respectively. The year-to-year increase of 19%decrease is discussed below in “Cash Flows—Operating Activities”). During 2015, weActivities.” We have primarily relied on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments, and dividend payments.during the last two years, our growth capital expenditures.
Historically, we have relied on cash from our equity and debt issuancesWe expect KML to fund in large part, expansionthe TMEP’s capital expenditures acquisitions and to refinance debt maturities. However, due toits other capital expenditures through (i) additional borrowings on KML’s Credit Facility; (ii) the recent unfavorable capital market conditions,additional issuance of KML preferred shares; (iii) the resulting increased costissuance of equityadditional KML restricted voting stock; (iv) the issuance of KML long-term notes payable; and debt issuances have made it less economical to do so. As(v) KML’s retained cash flow from operations or a result,combination of the above. KML established a dividend policy on December 8, 2015, we announced that our board of directors approved a planits restricted voting shares pursuant to which it will pay its quarterly dividend in an amount based on a portion of its DCF discussed below in “—Noncontrolling interests—KML Restricted Voting Share Dividends.”
On June 16, 2017, KML’s indirect subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the TMEP; (ii) a C$1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional TMEP costs (and, subject to the need to fund such additional costs and regulatory approval, meeting the Canadian NEB-mandated liquidity requirements); and (iii) a C$500 million revolving working capital facility, to be used for working capital and other general corporate purposes (collectively, the “KML Credit Facility”). On January 23, 2018, KML entered into an agreement amending certain terms of its Credit Facility to, among other things, provide additional funding certainty with respect to each tranche of its Credit Facility. The KML Credit Facility has a five-year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. As of December 31, 2017, KML had no amounts outstanding under the KML Credit Facility and C$53 million (U.S.$42 million) in letters of credit. In addition,
KML received C$537 million (U.S.$420 million) of net proceeds from the issuance of Series 1 Preferred Shares in August 2017 and Series 3 Preferred Shares in December 2017.
Generally, we expect that our short-term liquidity needs will be met primarily through retained cash from operations, short-term borrowings or by issuing new long-term debt to pay quarterly dividendsrefinance certain of $0.125 perour maturing long-term debt obligations. We also expect that KMI’s current common stock dividend level will allow us to use retained cash to fund our growth projects and the previously mentioned share repurchase program in 2018. Moreover, as a result of KMI’s current common stock dividend policy and by continuing to our common shareholders ($0.50 per common share annually), down from our third quarter 2015 dividend of $0.51 per common share, beginning with the fourth quarter 2015 dividend payablefocus on allocating capital to common shareholders on February 16, 2016. Wehigh return opportunities, we do not expect the reduced dividend level eliminates our need to access the equity capital markets to fund our other growth projects in 2016.for the foreseeable future.
Additionally, on January 26, 2016, we announced the issuance of a new $1 billion term loan facility and the expansion of our revolving credit facility from $4 billion to $5 billion. The proceeds of the three-year unsecured term loan were used to refinance maturing long-term debt.
Credit Ratings and Capital Market Liquidity
Based on our recent decision to retain a larger portion of our internally generated cash to fund our growth projects, weWe believe that our capital structure will continue to allow us to achieve our business objectives. We expect that our short-term liquidity needs will be met primarily through retained cash from operations or short-term borrowings. However, over theGenerally, we anticipate re-financing maturing long term wedebt obligations in the debt capital markets and are therefore subject to uncertain capitalcertain market conditions and there can be no assurance we will be able or willing to access the public or private markets for equity and/or long-term senior notes in the future. If we were unable or unwilling to access the capital markets, we would be required to either further utilize internally generated cash, restrict expansion capital expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involveresult in higher costs or negatively affect our and/or our subsidiaries’ credit ratings.
OurAs of December 31, 2017, our short-term corporate debt rating isratings were A-3, Prime-3 and F3 at Standard and Poor’s, Moody’s Investor Services and Fitch Ratings, Inc., respectively.
The following table represents KMI’s and KMP’s senior unsecured debt ratings as of December 31, 2015.2017.
|
| | | | | | |
| Rating agency | | Senior debt rating | | Date of last change | | Outlook |
| Standard and Poor’s | | BBB- | | November 20, 2014 | | Stable |
| Moody’s Investor Services | | Baa3 | | November 21, 2014 | | Stable |
| Fitch Ratings, Inc. | | BBB- | | November 20, 2014 | | Stable |
Short-term Liquidity
As of December 31, 20152017, our principal sources of short-term liquidity are (i) our $4.0$5.0 billion revolving credit facility (which capacity was increased to $5.0 billion on January 26, 2016) and associated $4.0 billion commercial paper program; (ii) the KML Credit Facility (for the purposes described above); and (ii)(iii) cash from operations. The loan commitments under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program and letters of credit reduce borrowings allowed under ourours and KML’s respective credit facility.facilities. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, we have consistently generated strong cash flowflows from operations.
Our short-term debt asAs of December 31, 2015 was $8212017, our $2,828 million comprised entirely of short-term debt consisted primarily of (i) $125 million outstanding borrowings under the current portionKMI $5.0 billion revolving credit facility; (ii) $240 million outstanding under our $4.0 billion commercial paper program; and (iii) $2,284 million of our long-term debt excluding $1.0 billion of debtsenior notes that maturedmature in January and February 2016 that was refinanced using proceeds from the $1.0 billion term loan issued in January 2016, and therefore included within “Long-term debt” on our consolidated balance sheet at December 31, 2015.next year. We intend to refinance our short-term debt through additional credit facility borrowings, commercial paper borrowings, or withby issuing new long-term debt or paying down short-term debt using cash retained from operations. Our combined balance of short-term debt balance as of December 31, 20142016 was $2,717$2,696 million.
We had working capital (defined as current assets less current liabilities) deficits of $1,241$3,466 million and $2,610$2,695 million as of December 31, 20152017 and 2014,2016, respectively. Our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which periodically we may periodically replace with long-term financing and/or partially pay down using retained cash from operations. The overall $1,369$771 million (52%(29%) favorableunfavorable change from year-end 20142016 was primarily due to a net decrease in cash and restricted deposits, and a net increase in our credit facility borrowings, commercial paper borrowings and current portion of long-term debt (largely refinanced with the new long-term issuances); offset partially by (i) lower other current assets driven by the 2015 receipt of a federal tax refund; and (ii) lower cash balances.accounts payable. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities (discussed below in “—Long-term Financing” and “— Capital Expenditures”).
We employ a centralized cash management program for our U.S.-based bank accounts that concentrates the cash assets of our subsidiaries, their operating partnerships and their wholly-ownedwholly owned subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. These programs provide that funds in excess of the daily needs of our subsidiaries, their operating partnerships and their wholly-ownedwholly owned subsidiaries are concentrated,
consolidated or otherwise made available for use by other entities within the consolidated group. We place no material restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to parent companiesKMI other than restrictions that may be contained in agreements governing the indebtedness of those entities.
Certain of our operatingwholly owned subsidiaries are subject to FERC-enacted reporting requirements for oil and natural gas pipeline companies that participate in cash management programs. FERC-regulated entities subject to these rules must, among other things, place their cash management agreements in writing, maintain current copies of the documents authorizing and supporting their cash management agreements, and file documentation establishing the cash management program with the FERC.
Long-term Financing
Our equity consists of Class P common stock and mandatory convertible preferred stock each with a par value of $0.01 per share. In 2015, throughWe have in place an equity distribution agreement we issuedwhich allows us to issue and soldsell through or to our sales agents and/or principals shares of our Class P common stock. However, with the exception of the issuance of KML preferred equity and/or common equity to partially finance the TMEP or other KML capital expenditures, we do not expect the need to access the equity capital markets to fund our growth projects for the foreseeable future. Furthermore, we began repurchasing shares of our Class P common stock under a $2 billion share buy-back program in December 2017 that we intend to fund through retained cash. For more information on our equity issuances during 2015buy-back program and our equity distribution agreement, see Note 11 “Stockholders’ Equity” to our consolidated financial statements.
From time to time, we issue long-term debt securities, often referred to as senior notes. All of our senior notes issued to date, other than those issued by certain of our subsidiaries, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date, and, in most cases, plus a make-whole premium. In addition, from time to time our subsidiaries, have issued long-term debt securities. Furthermore, we and almost all of our direct and indirect wholly-ownedwholly owned domestic subsidiaries are parties to a cross guaranty wherein we each guarantee the debt of each other. See Note 19 “Guarantee of Securities of Subsidiaries” to our consolidated financial statements. As of December 31, 20152017 and 2014,2016, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $40,732$34,088 million and $38,312$36,205 million, respectively. For more information regarding our debt-related transactions in 2017, see Note 9 “Debt” to our consolidated financial statements.
We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping the fixed rate interest payments for variable rate interest payments and through the issuance of commercial paper or credit facility borrowings.
To date, our and our subsidiaries’ debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt-related transactions in 2015,2017, see Note 9 “Debt” to our consolidated financial statements. For information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.Risk.”
Capital Expenditures
We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as discretionary capital expenditures). Expansion capital expenditures are those expenditures which increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF (see “Results of Operations—Distributable Cash Flow”DCF”). With respect to our oil and gas producing activities, we classify a capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e. production capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements. Maintenance capital expenditures are those which maintain throughput or capacity. The distinction between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.
Budgeting of maintenance capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally
expect to receive sufficient returns to justify the expenditures. Generally, the determination of whether a capital expenditure is classified as maintenance/sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion .discretion. The classification has an impact on cash available to pay dividendsDCF because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are. See “—Common Dividends” and “—Preferred Dividends”Dividends.”
Our capital expenditures for the year ended December 31, 2015,2017, and the amount we expect to spend for 20162018 to sustain and grow our business are as follows (in millions):
| | | | 2015 | | Expected 2016 | 2017 | | Expected 2018 |
Sustaining capital expenditures(a)(c) | $ | 565 |
| | $ | 574 |
| $ | 588 |
| | $ | 664 |
|
| Discretionary capital expenditures(b)(c) | $ | 3,532 |
| | $ | 3,281 |
| |
| KMI Discretionary capital investments(b)(c)(d)(e) | | $ | 2,982 |
| | $ | 2,215 |
|
| KML Discretionary capital investments post-IPO(c) | | $ | 384 |
| | $ | 1,500 |
|
_______
| |
| (a) | 20152017 and Expected 20162018 amounts include $70$107 million and $90$112 million, respectively, for our proportionate share of (i) certain equity investee’s, (ii) KML’s, and (ii) consolidating subsidiaries’ sustaining capital expenditures of certain unconsolidated joint ventures.expenditures. |
| |
| (b) | 2015 amount includes an increase2017 is net of $483$216 million of discretionarycontributions from certain partners for capital expendituresinvestments at non-wholly owned consolidated subsidiaries offset by $629 million of our contributions to certain unconsolidated joint ventures and small acquisitions (i.e. excludes Hiland acquisition) and divestitures and a decrease of a combined $352for capital investments. |
| |
| (c) | 2017 includes $246 million of net changes from accrued capital expenditures, contractor retainage, and contractor retainage.other. |
| |
(c)(d) | 2017 includes $107 million of capital expenditures spent on Canadian projects prior to KML’s May 25, 2017 IPO and excludes KML capital expenditures thereafter as it has the capacity to draw on its construction credit facility to fund its capital expenditures. |
| |
| (e) | Expected 20162018 amount includes our estimated contributions to certain unconsolidated joint ventures, and small acquisitions and divestitures, net of contributions estimated from unaffiliated joint venturecertain partners in non-wholly owned consolidated subsidiaries for consolidatedcapital investments. |
Off Balance Sheet Arrangements
We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 13 “Commitments and Contingent Liabilities” to our consolidated financial statements. Additional information regarding the nature and business purpose of our investments is included in Note 7 “Investments” to our consolidated financial statements.
Contractual Obligations and Commercial Commitments
| | | | Payments due by period | Payments due by period |
| | Total | | Less than 1 year | | 2-3 years | | 4-5 years | | More than 5 years | Total | | Less than 1 year | | 2-3 years | | 4-5 years | | More than 5 years |
| | (In millions) | (In millions) |
| Contractual obligations: | | | | | | | | | | | | | | | | | | |
| Debt borrowings-principal payments(a) | $ | 41,553 |
| | $ | 821 |
| | $ | 5,389 |
| | $ | 6,772 |
| | $ | 28,571 |
| $ | 36,916 |
| | $ | 2,828 |
| | $ | 5,024 |
| | $ | 4,980 |
| | $ | 24,084 |
|
| Interest payments(b) | 29,311 |
| | 2,267 |
| | 4,109 |
| | 3,610 |
| | 19,325 |
| 24,555 |
| | 1,897 |
| | 3,462 |
| | 2,974 |
| | 16,222 |
|
| Leases and rights-of-way obligations(c) | 829 |
| | 103 |
| | 173 |
| | 147 |
| | 406 |
| 722 |
| | 118 |
| | 187 |
| | 117 |
| | 300 |
|
| Pension and postretirement welfare plans(d) | 932 |
| | 24 |
| | 34 |
| | 35 |
| | 839 |
| 975 |
| | 48 |
| | 32 |
| | 45 |
| | 850 |
|
| Transportation, volume and storage agreements(e) | 1,172 |
| | 160 |
| | 294 |
| | 256 |
| | 462 |
| 1,043 |
| | 159 |
| | 308 |
| | 258 |
| | 318 |
|
| Other obligations(f) | 302 |
| | 91 |
| | 95 |
| | 29 |
| | 87 |
| 279 |
| | 64 |
| | 82 |
| | 38 |
| | 95 |
|
| Total | $ | 74,099 |
| | $ | 3,466 |
| | $ | 10,094 |
| | $ | 10,849 |
| | $ | 49,690 |
| $ | 64,490 |
| | $ | 5,114 |
| | $ | 9,095 |
| | $ | 8,412 |
| | $ | 41,869 |
|
| Other commercial commitments: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Standby letters of credit(g) | $ | 243 |
| | $ | 205 |
| | $ | 38 |
| | $ | — |
| | $ | — |
| $ | 224 |
| | $ | 125 |
| | $ | 99 |
| | $ | — |
| | $ | — |
|
| Capital expenditures(h) | $ | 1,229 |
| | $ | 845 |
| | $ | 384 |
| | $ | — |
| | $ | — |
| $ | 845 |
| | $ | 845 |
| | $ | — |
| | $ | — |
| | $ | — |
|
_______
| |
| (a) | Less than 1 year amount primarily includes $667$2,717 million of current maturities on senior notes and $111 million associated with our Trust I Preferred Securities that are classified as current obligations because these securities have rights to convert into consideration consistent with the EP merger, and excludes $1,000 million of current maturities on long-term debt that were refinanced with proceeds from the issuance of a January 2016 three-year term loan.cash and/or KMI common stock. See Note 9 “Debt” to our consolidated financial statements. |
| |
| (b) | Interest payment obligations exclude adjustments for interest rate swap agreements and assume no change in variable interest rates from those in effect at December 31, 2015.2017. |
| |
| (c) | Represents commitments pursuant to the terms of operating lease agreements and liabilities for rights-of-way. |
| |
| (d) | Represents the amount by which the benefit obligations exceeded the fair value of fundplan assets at year-end for pension and other postretirement benefit plans at year-end.whose accumulated postretirement benefit obligations exceeded the fair value of plan assets. The payments by period include expected contributions to funded plans in 20162018 and estimated benefit payments for unfunded plans in all years. |
| |
| (e) | Primarily represents transportation agreements of$526425 million, volume agreements of $454$377 million and storage agreements for capacity on third party and an affiliate pipeline systems of $135$203 million. |
| |
| (f) | Primarily includes environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we will perform remediation activities. These liabilities are included within “Accrued contingencies” and “Other long-term liabilities and deferred credits” in our consolidated balance sheets. |
| |
| (g) | The $243$224 million in letters of credit outstanding as of December 31, 20152017 consisted of the following (i) $73$47 million under fourteeneleven letters of credit for insurance purposes; (ii) a $42 million letter of credit supporting our $30 million guarantee underpipeline and terminal operations in Canada; (iii) letters of credit totaling $46 million supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (iii) a $29 million letter of credit supporting our pipeline and terminal operations in Canada; (iv) a $25 million letter of credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (v) a $24 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; (vi) an $11a $9 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; and (vii) a combined $35$31 million in twenty-sixtwenty-four letters of credit supporting environmental power and marketing purposes, and other obligations of us and our subsidiaries. |
| |
| (h) | Represents commitments for the purchase of plant, property and equipment as of December 31, 2015 and obligations for the definitive construction agreement with Philly Tankers LLC for 2016 and 2017. |
Cash Flows
Operating Activities
The net increasedecrease of $836$194 million (19%(4%) in cash provided by operating activities in 20152017 compared to 20142016 was primarily attributable to:
a $726$348 million decrease in operating cash flow resulting from the combined effects of adjusting the $498 million decrease in net income for the period-to-period net increase in non-cash items primarily consisting of the following: (i) net losses on impairments and divestitures of assets and equity investments (see discussion above in “—Results of Operations”); (ii) change in fair market value of derivative contracts; (iii) DD&A expense (including amortization of excess cost of equity investments); (iv) deferred income taxes, which includes a $1,162 million adjustment associated with the 2017 Tax Reform; (v) earnings from equity investments; and (vi) loss (gain) on early extinguishment of debt; and
a $154 million increase in cash associated with net changes in working capital items and other non-current assets and liabilities. The increase was driven, among other things, primarily by $347a $144 million of federal and state income tax refunds werefund received in 2015 of which $195 million was previously reported as an income tax receivable as of December 31, 2014, and higher cash flows due to favorable changes in the collection of trade and exchange gas receivables. These increases were offset by lower cash flow due to the timing of payments from our trade payables;
a $243 million increase in cash due to the higher payments in 2014 for rate case reserve payments primarily driven by the 2014 CPUC settlement and refund payments; and
a $133 million decrease in cash from overall net income after adjusting our period-to-period $2,235 million decrease in net income for non-cash items primarily consisting of the following: (i) loss on impairment of goodwill (see discussion above in “—Results of Operations”); (ii) net losses on impairments and disposals of long-lived assets and equity investments (see discussion above in “—Results of Operations”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred income taxes; (v) a net increase in legal reserves (see discussion above in “—Results of Operations”); (vi) an increase in net unrealized gains relating to derivative contracts used to hedge forecasted natural gas, NGL, and crude oil sales (see discussion above in “—Results of Operations”); and (vii) an increase in equity earnings from our equity investments.2017.
Investing Activities
The $496$1,657 million net increase in cash used in investing activities in 20152017 compared to 20142016 was primarily attributable to:
a $691 million decrease in cash due to higher expenditures for acquisitions and investments. The overall increase in acquisitions was primarily related to the $1,706 million (net of cash acquired and debt assumed) and $158 million we paid for the Hiland and Vopak acquisitions, respectively, in the 2015 period, versus the $1,231 million we paid for the APT and Crowley tankers in 2014. In 2015 we also paid $134 million in cash for our additional 30% interest in NGPL Holdings LLC. See Note 3 “Acquisitions and Divestitures” for further information regarding these acquisitions;
a $279 million decrease in cash due to higher capital expenditures;
a $293$1,401 million increase in cash used due to lowerproceeds received in the 2016 period from the sale of a 50% equity interest in SNG;
| |
| • | a $306 million increase in capital expenditures primarily due to higher expenditures related to natural gas, CO2 and Trans Mountain expansion projects, offset in part by lower expenditures in the Terminals segment; |
a $276 million increase in cash used for contributions to our equity investments primarily due to a $175 million contributionthe contributions we made in the third quarter of 20142017 to our 50%-owned Midcontinent Express PipelineUtopia Holding LLC, to fund our share of its repayment of $350 million in senior notes that matured on September 15, 2014;FEP and SNG; and
$212 million lower cash proceeds from sales of property, plant and equipment and other net assets, primarily driven by the higher proceeds we received in 2016 from sales of other long-lived assets; partially offset by
a $135$329 million decrease in expenditures for acquisitions of assets and investments, primarily driven by the $324 million portion of the purchase price we paid in the 2016 period for the BP terminals acquisition;
a $143 million increase in cash for distributions received from equity investments in excess of cumulative earnings, primarily driven by the higher distributions from MEP, SNG and Ruby; and
a $66 million increase in Other, net primarily due to favorable changes in restricted deposit accountsdeposits associated with our hedging activities.activities, offset partially by increases in loans with an equity investee.
Financing Activities
The net decrease of $144$956 million in cash providedused by financing activities in 20152017 compared to 20142016 was primarily attributable to:
a $7,507$1,560 million increase in cash due to contributions from noncontrolling interests, primarily reflecting $1,245 million in net proceeds received from the May 2017 KML IPO and $420 million net decreaseproceeds received from the KML preferred share issuances in 2017, compared to the 2016 period which includes $84 million of contributions received from BP for its 25% share of a newly formed joint venture; and
a $485 million increase in cash resulting from overallcontributions received in the 2017 period from EIG, consisting of $386 million for the sale of a 49% partnership interest in ELC and $99 million as additional contributions for 2017 capital expenditures; partially offset by
an $816 million net increase in cash used related to debt financing activities.activities as a result of higher net debt payments in the 2017 period compared to the 2016 period. See Note 9 “Debt” to our consolidated financial statements for further information regarding our debt activity; and
a $2,464 million decrease in cash due to higher total dividend payments;
a $1,756 million decrease in contributions provided by noncontrolling interests, primarily reflecting the proceeds received from the issuance of KMP’s and EPB’s common units to the public in the 2014 period and no proceeds in the 2015 period due to the Merger Transactions;
a $4,009$250 million increase in cash resulting fromused for share repurchases under the cash portion of consideration for the Merger Transactions and related transaction costsshare buy-back program that commenced in 2014;
a $3,870 million increase in cash from the issuances of our Class P shares under our equity distribution agreement;
a $1,979 million increase in cash due to lower distributions to noncontrolling interests, primarily resulting from our acquisition of the noncontrolling interests associated with KMP and EPB in the Merger Transactions in November 2014;
a $1,541 million increase in cash from the issuance of our mandatory convertible preferred stock in 2015; and
a $180 million increase in cash due to the reduction of payments made to repurchase shares and warrants in 2015 compared to the 2014 period.December 2017.
Dividends and Stock Buyback Program
KMI Common Stock Dividends
The table below reflects the payment of cash dividends of $1.605$0.50 per common share for 2015.2017. |
| | | | | | | | | | |
| Three months ended | | Total quarterly dividend per share for the period | | Date of declaration | | Date of record | | Date of dividend |
| March 31, 2015 | | $ | 0.48 |
| | April 15, 2015 | | April 30, 2015 | | May 15, 2015 |
| June 30, 2015 | | $ | 0.49 |
| | July 15, 2015 | | July 31, 2015 | | August 14, 2015 |
| September 30, 2015 | | $ | 0.51 |
| | October 21, 2015 | | November 2, 2015 | | November 13, 2015 |
| December 31, 2015 | | $ | 0.125 |
| | January 20, 2016 | | February 1, 2016 | | February 16, 2016 |
|
| | | | | | | | | | |
| Three months ended | | Total quarterly dividend per share for the period | | Date of declaration | | Date of record | | Date of dividend |
| March 31, 2017 | | $ | 0.125 |
| | April 19, 2017 | | May 1, 2017 | | May 15, 2017 |
| June 30, 2017 | | 0.125 |
| | July 19, 2017 | | July 31, 2017 | | August 15, 2017 |
| September 30, 2017 | | 0.125 |
| | October 18, 2017 | | October 31, 2017 | | November 15, 2017 |
| December 31, 2017 | | 0.125 |
| | January 17, 2018 | | January 31, 2018 | | February 15, 2018 |
As previously announced, as a result of substantial balance sheet improvement achieved since the end of 2015, we have taken multiple steps to return significant value to our shareholders. First, we expect to declare an annual dividend of $0.80 per common share for 2018, a 60% increase from the 2017 dividend per common share. The first 2018 increase is expected to be the dividend declared for the first quarter of 2018. Additionally, we plan to increase our dividend to $1.00 per common share in 2019 and $1.25 per common share in 2020, a growth rate of 25% annually.
As disclosed elsewhere in this report, we expect to pay cash dividends totaling $0.50 per share on our common stock for 2016. The actual amount of common dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” All of these matters will be taken into consideration by our board of directors in declaring dividends.
Our common stock dividends are not cumulative. Consequently, if dividends on our common stock are not paid at the intended levels, our common stockholders are not entitled to receive those payments in the future. Our common stock dividends generally will be paid on or about the 16th15th day of each February, May, August and November.
KMI Preferred Stock Dividends
Dividends on our mandatory convertible preferred stock are payable on a cumulative basis when, as and if declared by our board of directors (or an authorized committee thereof) at an annual rate of 9.750% of the liquidation preference of $1,000 per share on January 26, April 26, July 26 and October 26 of each year, commencing on January 26, 2016 to, and including, October 26, 2018. We may pay dividends in cash or, subject to certain limitations, in shares of common stock or any combination of cash and shares of common stock. The terms of the mandatory convertible preferred stock provide that, unless full cumulative dividends have been paid or set aside for payment on all outstanding mandatory convertible preferred stock for all prior dividend periods, no dividends may be declared or paid on common stock.
|
| | | | | | | | | | |
| Period | | Total dividend per share for the period | | Date of declaration | | Date of record | | Date of dividend |
| January 26, 2017 through April 25, 2017 | | $ | 24.375 |
| | January 18, 2017 | | April 11, 2017 | | April 26, 2017 |
| April 26, 2017 through July 25, 2017 | | 24.375 |
| | April 19, 2017 | | July 11, 2017 | | July 26, 2017 |
| July 26, 2017 through October 25, 2017 | | 24.375 |
| | July 19, 2017 | | October 11, 2017 | | October 26, 2017 |
| October 26, 2017 through January 25, 2018 | | 24.375 |
| | October 18, 2017 | | January 11, 2018 | | January 26, 2018 |
The cash dividend of $24.375 per share of our mandatory convertible preferred stock is equivalent to $1.21875 per depository share.
Stock Buyback Program
On July 19, 2017, our board of directors approved a $2 billion common share buyback program that began in December 2017. During the year ended December 31, 2017, we repurchased approximately 14 million of our Class P shares for approximately $250 million. Subsequent to December 31, 2017 and through February 8, 2018, we repurchased approximately 13 million of our Class P shares for approximately $250 million.
Noncontrolling Interests
Contributions
KML Restricted Voting Shares
As discussed in Note 3 “Acquisitions and Divestitures” to our consolidated financial statements, on May 30, 2017 our indirect subsidiary, KML, issued 102,942,000 restricted voting shares in a public offering. The public ownership of the KML restricted voting shares represents an approximate 30% interest in the voting shares of our Canadian operations and is reflected within “Noncontrolling interests” in our consolidated financial statements as of and for the periods presented after May 30, 2017.
KML Preferred Share Offerings
On August 15, 2017, KML completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 1 Preferred Share for total gross proceeds of C$300 million (U.S.$235 million). On December 15, 2017, KML completed an offering of 10,000,000 cumulative redeemable minimum rate reset preferred shares, Series 3 (Series 3 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 3 Preferred Share for total gross proceeds of C$250 million (U.S.$195 million). The net proceeds from the Series 1 and Series 3 Preferred Share offerings of C$293 million (U.S.$230 million) and C$243 million (U.S.$189 million), respectively, were used by KML to indirectly subscribe for preferred units in Kinder Morgan Canada Limited Partnership (KMC LP), which in turn were used by KMC LP to repay KML Credit Facility indebtedness recently incurred to, directly or indirectly, finance the development, construction and completion of the TMEP and Base Line Terminal project, and for general corporate purposes.
KML Distributions
KML established a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its DCF. The payment of dividends is not guaranteed and the amount and timing of any dividends payable will be at the discretion of KML’s board of directors. The actual amount of cash dividends paid to KML’s shareholders, if any, will depend on numerous factors including: (i) KML’s results of operations; (ii) KML’s financial requirements, including the funding of its current and future growth projects; (iii) the amount of distributions paid indirectly by KMC LP to KML through Kinder Morgan Canada GP Inc. (KMC GP), including any contributions from the completion of its growth projects; (iv) the satisfaction by KML and KMC GP of certain liquidity and solvency tests; (v) any agreements relating to KML’s indebtedness or the limited partnership; and (vi) the cost and timely completion of current and future growth projects. KML intends to pay quarterly dividends, if any, on or about the 45th day (or next business day) following the end of each calendar quarter to holders of its restricted voting shares of record as of the close of business on or about the last business day of the month following the end of each calendar quarter.
KML also established a Dividend Reinvestment Plan (DRIP) which allows holders (excluding holders not resident in Canada) of restricted voting shares to elect to have any or all cash dividends payable to such shareholder automatically reinvested in additional restricted voting shares at a price per share calculated by reference to the volume-weighted average of the closing price of the restricted voting shares on the stock exchange on which the restricted voting shares are then listed for the five trading days immediately preceding the relevant dividend payment date, less a discount of between 0% and 5% (as determined from time to time by KML’s board of directors, in its sole discretion).
For 2018, KML announced that it expects to pay an annual dividend of C$0.65 per restricted voting share.
Dividends on the Series 1 Preferred Shares are fixed, cumulative, preferential and C$1.3125 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding November 15, 2022.
Dividends on the Series 3 Preferred Shares are fixed, cumulative, preferential and C$1.3000 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding February 15, 2023.
The following table provides information regarding distributions to our noncontrolling interests (in millions except per share and share distribution amounts):
|
| | | | | | |
| | | Year Ended December 31, 2017 |
| | | Shares | | U.S.$ | | C$ |
| KML Restricted Voting Shares(a) | | | | | | |
| Per restricted voting share declared for the period(b) | | | | | | $0.3821 |
| Per restricted voting share paid in the period | | | | $0.1739 | | 0.2196 |
| Total value of distributions paid in the period | | | | 18 | | 23 |
| Cash distributions paid in the period to the public | | | | 13 | | 16 |
| Share distributions paid in the period to the public under KML’s DRIP | | 418,989 | | | | |
| KML Series 1 Preferred Shares(c) | | | | | | |
| Per Series 1 Preferred Share paid in the period | | | | $0.2624 | | $0.3308 |
| Cash distributions paid in the period to the public | | | | 3 | | 4 |
_______
| |
| (a) | Represents dividends subsequent to KML’s May 30, 2017 IPO. |
| |
| (b) | The U.S.$ equivalent of the dividends declared is calculated based on the exchange rate on the dividend payment date, therefore, the U.S.$ equivalent of the dividend declared for the fourth quarter of 2017 will be calculated using the exchange rate on February 15, 2018. |
The combined U.S.$ equivalent of the dividends declared for the second and third quarters of 2017 was $0.1739.
| |
| (c) | Represents dividends subsequent to the issuance of KML’s Series 1 Preferred Shares. |
On January 17, 2015, our2018, KML’s board of directors declared a cash dividend of $23.291667C$0.328125 per share of our mandatory convertible preferred stock (equivalent of $1.164583 per depository share)its Series 1 Preferred Shares for the period from and including October 30, 2015November 15, 2017 through and including January 25, 2016, was paidFebruary 14, 2018, which is payable on January 26, 2016February 15, 2018 to mandatory convertible preferred shareholdersSeries 1 Preferred Shareholders of record as of the close of business on January 11, 2016.31, 2018.
On January 17, 2018, KML’s board of directors declared a cash dividend of C$0.22082 per share of its Series 3 Preferred Shares for the period from and including December 15, 2017 through and including February 14, 2018, which is payable on February 15, 2018 to Series 3 Preferred Shareholders of record as of the close of business on January 31, 2018.
Recent Accounting Pronouncements
Please refer to Note 18 “Recent Accounting Pronouncements” to our consolidated financial statements for information concerning recent accounting pronouncements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.” Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in energy commodity prices or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the
maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in energy commodity prices or interest rates and the timing of transactions.
Energy Commodity Market Risk
We are exposed to energy commodity market risk and other external risks in the ordinary course of business. However, we manage these risks by executing a hedging strategy that seeks to protect us financially against adverse price movements and serves to minimize potential losses. Our strategy involves the use of certain energy commodity derivative contracts to reduce and minimize the risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. The derivative contracts that we use include energy products traded on the NYMEX and OTC markets, including, but not limited to, futures and options contracts, fixed price swaps and basis swaps. In addition, we have power forward and swap contracts related to legacy operations of acquired businesses for which we entered into positions that offset the price risks associated with these contracts.
Our hedging strategy involves entering into a financial position intended to offset our physical position, or anticipated position, in order to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil and natural gas, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our crude oil or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby in whole or in part offsetting any change in prices, either positive or negative.
Our policies require that derivative contracts are only entered into with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our counterparties’ credit ratings. While it is our policy to enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future.
The credit ratings of the primary parties from whom we transact in energy commodity derivative contracts (based on contract market values) are as follows (credit ratings per Standard & Poor’s Rating Service):
|
| |
| | Credit Rating |
Bank of America / Merrill Lynch | BBB+ |
| Societe Generale | A |
| Macquarie | BBB |
J.P. MorganWells Fargo | A-A |
J Aron / Goldman SachsCanadian Imperial Bank | BBB+A+ |
| Nextera | A- |
As discussed above, the principal use of energy commodity derivative contracts is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, NGL and crude oil. Using derivative contracts for this purpose helps provide increased certainty with regard to operating cash flows which helps us to undertake further capital improvement projects, attain budget results and meet dividend targets. We may categorize such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but which value is uncertain.
We measure the risk of price changes in the natural gas, NGL and crude oil and power derivative instruments portfolios utilizing a sensitivity analysis model. The sensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the change in fair value of the derivative instrument portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. As of December 31, 2015 and 2014, aA hypothetical 10% movement in the underlying commodity natural gas prices would affecthave the following effect on the associated derivative contracts’ estimated fair value of natural gas derivatives by $13 million and $9 million, respectively. As of December 31, 2015 and 2014, a hypothetical 10% movement in(in millions):
|
| | | | | | | | |
| | | As of December 31, |
| Commodity derivative | | 2017 | | 2016 |
| Crude oil | | $ | 125 |
| | $ | 117 |
|
| Natural gas | | 15 |
| | 16 |
|
| NGL | | 10 |
| | 11 |
|
| Total | | $ | 150 |
| | $ | 144 |
|
underlying commodity crude oil prices would affect the estimated fair value of crude oil derivative by $97 million and $146 million, respectively. As of December 31, 2015 and 2014, a hypothetical 10% movement in underlying commodity NGL prices would affect the estimated fair value of our NGL derivatives by $4 million and $0.3 million, respectively. As of both December 31, 2015 and 2014, a hypothetical 10% movement in underlying commodity electricity prices would not affect the estimated fair value of our power derivatives.
As discussed above, we enter into derivative contracts largely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore both in the sensitivity analysis model and in reality, the change in the market value of the derivative contractscontracts’ portfolio is offset largely by changes in the value of the underlying physical transactions.
Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the natural gas, NGL and crude oil and power portfolios of derivative contracts assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year.
Interest Rate Risk
In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.
For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Generally, there is not an obligation to prepay fixed rate debt prior to maturity and, as a result, interest rate risk and changes in fair value should not have a significant impact on the fixed rate debt. We are generally subject to interest rate risk upon refinancing maturing debt. Below are our debt until we would be requiredbalances, including debt fair value adjustments and the preferred interest in KMGP, and sensitivity to refinance such debt.
As of December 31, 2015 and 2014, the carrying values of the fixed rate debt were $43,039 million and $41,390 million, respectively. These amounts compare to, as of December 31, 2015 and 2014, fair values of $37,329 million and $42,343 million, respectively. Fair values were determined using quoted market prices, where applicable, or future cash flow discounted at market rates for similar types of borrowing arrangements. A hypothetical 10% change in the average interest rates applicable to such debt for 2015 and 2014, would result in changes of approximately $1,667 million and $1,539 million, respectively, in the fair values of these instruments. (in millions):
As of December 31, 2015 and 2014, the carrying values of our variable rate debt were $188 million and $1,424 million, respectively. These amounts compare to, as of December 31, 2015 and 2014, fair values of $152 million and $1,418 million, respectively. As of December 31, 2015 and 2014 we were party to fixed-to-variable interest rate swap agreements with notional principal amounts of $11,000 million and $9,200 million, respectively. A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 49 basis points in 2015 and approximately 50 basis points in 2014) when applied to our outstanding balance of variable rate debt as of December 31, 2015 and 2014, including adjustments for the notional swap amounts described above, would result in changes of approximately $55 million and $53 million, respectively, in our 2015 and 2014 annual pre-tax earnings. |
| | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | Carrying
value | | Estimated
fair value(c) | | Carrying
value | | Estimated
fair value(c) |
| Fixed rate debt(a) | $ | 37,041 |
| | $ | 39,255 |
| | $ | 38,861 |
| | $ | 39,854 |
|
| | | | | | | | |
| Variable rate debt | $ | 802 |
| | $ | 795 |
| | $ | 1,189 |
| | $ | 1,161 |
|
| Notional principal amount of fixed-to-variable interest rate swap agreements | 9,575 |
| | | | 9,775 |
| | |
| Debt balances subject to variable interest rates(b) | $ | 10,377 |
| | | | $ | 10,964 |
| | |
_______
| |
| (a) | A hypothetical 10% change in the average interest rates applicable to such debt as of December 31, 2017 and 2016, would result in changes of approximately $1,525 million and $1,527 million, respectively, in the fair values of these instruments. |
| |
| (b) | A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 50 basis points in both 2017 and 2016) when applied to our outstanding balance of variable rate debt as of December 31, 2017 and 2016, including adjustments for the notional swap amounts described above, would result in changes of approximately $52 million and $54 million, respectively, in our 2017 and 2016 annual pre-tax earnings. |
| |
| (c) | Fair values were determined using quoted market prices, where applicable, or future cash flows discounted at market rates for similar types of borrowing arrangements. |
Fixed-to-variable interest rate swap agreements are entered into for the purpose of converting a portion of the underlying cash flows related to long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. Since the fair value of fixed rate debt varies with changes in the market rate of interest, swap agreements are entered into to receive a fixed and pay a variable rate of interest. Such swap agreements result in future cash flows that vary with the market rate of interest, and therefore hedge against changes in the fair value of the fixed rate debt due to market rate changes.
We monitor the mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time, may alter that mix by, for example, refinancing outstanding balances of variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements. As of December 31, 2015,2017, including debt converted to variable rates through the use of interest rate swaps but excluding our debt fair value adjustments, approximately 27%28% of our debt balances were subject to variable interest rates.
For more information on our interest rate risk management and on our interest rate swap agreements, see Note 14 “Risk Management” to our consolidated financial statements.
Foreign Currency Risk
In connection with the issuanceAs of our Euro denominated senior notes in March 2015,December 31, 2017, we entered intohad a notional principal amount of $1,358 million of cross-currency swap agreements that effectively convert all of the fixed-rateour fixed rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates. These swaps eliminate the foreign currency risk associated with our foreign currency denominated debt.
Item 8. Financial Statements and Supplementary Data.
The information required in this Item 8 is in this report as set forth in the “Index to Financial Statements” on page 77.76.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2015,2017, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an assessment of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management concluded that our internal control over financial reporting was effective as of December 31, 2015.2017.
The effectiveness of our internal control over financial reporting as of December 31, 2015,2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report, which appears herein.
We acquired Hiland in a purchase business acquisition on February 13, 2015. Hiland is a wholly-owned subsidiary and we excluded this business from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2015. Hiland total assets and total revenues represent 4% and 3%, respectively, of our related consolidated financial statement amounts as of and for the year ended December 31, 2015.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the fourth quarter of 20152017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 20162018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2016.2018.
Item 11. Executive Compensation.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 20162018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2016.2018.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 20162018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2016.2018.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 20162018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2016.2018.
Item 14. Principal Accounting Fees and Services.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 20162018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2016.2018.
PART IV
Item 15. Exhibits, Financial Statement Schedules.
| |
| (a) | (1) Financial Statements and (2) Financial Statement Schedules |
|
| |
See “Index to Financial Statements” set forth on Page 7776. | |
Exhibit Number Description |
| | | |
2.1 |
| * | Agreement and Plan of Merger, dated as of August 9, 2014, by and among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan, Inc. (KMI) and P Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.1 to KMI’s Current Report on Form 8-K, filed August 12, 2014 (File No. 001-35081)) |
| | |
2.2 |
| * | Agreement and Plan of Merger, dated as of August 9, 2014, by and among Kinder Morgan Management, LLC, KMI, and R Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.2 to KMI’s Current Report on Form 8-K, filed August 12, 2014 (File No. 001-35081)) |
| | |
2.3 |
| * | Agreement and Plan of Merger, dated as of August 9, 2014, by and among El Paso Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C., KMI, and E Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.3 to KMI’s Current Report on Form 8-K, filed August 12, 2014 (File No. 001-35081)) |
| | |
| 3.1 |
| * | |
| | | |
| 3.2 |
| * | |
| | | |
Exhibit
NumberDescription
|
| | | |
| 3.3 |
| * | |
| | | |
| 4.1 |
| * | |
| | | |
| 4.2 |
| * | |
| | | |
| 4.3 |
| * | |
| | | |
| 4.4 |
| * | |
| | | |
| 4.5 |
| * | Warrant Agreement, dated as of May 25, 2012, among KMI, Computershare Trust Company, N.A. and Computershare Inc., as Warrant Agent (filed as Exhibit 4.1 to KMI’s Current Report on Form 8-K filed on May 30, 2012 (File No. 001-35081)) |
| | |
4.6 |
| * | |
| | | |
4.7 Exhibit NumberDescription |
| | | |
| 4.6 |
| * | |
| | | |
4.84.7 |
| * | |
| | | |
10.14.8 |
| * | KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 4.5 to KMI’s Registration Statement on Form S-8, filed on July 1, 2015, and incorporated herein by reference (File No. 333-205430)) |
| | |
10.2 |
| * | 2015 Form of Employee Restricted Stock Unit Agreement (filed as Exhibit 4.6 to KMI’s Registration Statement on Form S-8, filed on July 1, 2015, and incorporated herein by reference (File No. 333-205430)) |
| | |
10.3 |
| * | 2011 Form of Employee Restricted Stock Agreement (filed as Exhibit 10.2 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2011 (File No. 001-35081)) |
| | |
10.4 |
| * | Amended and Restated Stock Compensation Plan for Non-Employee Directors (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081)) |
| | |
10.5 |
| * | 2015 Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.6 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081)) |
| | |
10.6 |
| * | 2011 Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.3 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2011 (File No. 001-35081)) |
| | |
10.7 |
| * | KMI Employees Stock Purchase Plan (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2011 (File No. 001-35081)) |
| | |
10.8 |
| * | Amended and Restated Annual Incentive Plan of KMI (filed as Exhibit 10.4 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081)) |
| | |
10.9 |
| * | |
| | | |
10.104.9 |
| * | |
| | | |
10.114.10 |
| * | |
| | | |
Exhibit
NumberDescription
|
| | | |
10.124.11 |
| * | |
| | | |
10.134.12 |
| * | |
| | | |
10.144.13 |
| * | |
| | | |
10.154.14 |
| * | |
| | | |
10.164.15 |
| * | |
| | | |
10.174.16 |
| * | |
| | | |
10.184.17 |
| * | |
| | | |
10.194.18 |
| * | |
| | | |
10.204.19 |
| * | |
| | | |
10.214.20 |
| * | |
| | | |
10.224.21 |
| * | |
| | | |
10.23 Exhibit NumberDescription |
| | | |
| 4.22 |
| * | |
| | | |
10.244.23 |
| * | |
| | | |
10.254.24 |
| * | |
| | | |
10.264.25 |
| * | |
| | | |
Exhibit
NumberDescription
|
| | | |
10.274.26 |
| * | |
| | | |
10.284.27 |
| * | |
| | | |
10.294.28 |
| * | |
| | | |
10.304.29 |
| * | |
| | | |
10.314.30 |
| * | |
| | | |
10.324.31 |
| * | Officers’ |
| | | |
10.334.32 |
| * | |
| | | |
10.344.33 |
| * | |
| | | |
10.354.34 |
| * | |
Exhibit NumberDescription |
| | | |
| | | |
10.364.35 |
| * | |
| | | |
10.374.36 |
| * | |
| | |
| 4.37 |
| * | |
| | | |
10.384.38 |
| * | |
| | | |
10.394.39 |
| * | |
| | | |
Exhibit
NumberDescription
|
| | | |
10.404.40 |
| * | Support |
| | |
| 4.41 |
| * | |
| | |
| 4.42 |
| | Certain instruments with respect to long-term debt of KMI and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of KMI and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec. #229.601. KMI hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request. |
| | |
| 10.1 |
| * | |
| | |
| 10.2 |
| * | |
| | |
| 10.3 |
| * | |
| | |
| 10.4 |
| * | |
| | |
| 10.5 |
| * | Amended and among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, El Paso Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C., Richard D. KinderRestated Stock Compensation Plan for Non-Employee Directors (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081)) |
| | |
| 10.6 |
| * | |
| | |
| 10.7 |
| * | |
| | |
| 10.8 |
| * | |
| | |
| 10.9 |
| * | |
| | |
| 10.10 |
| * | |
| | | |
10.4110.11 |
| * | Bridge Credit Agreement, dated September 19, 2014 among KMI, as borrower, Barclays Bank PLC, as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed September 25, 2014 (File No. 001-35081)) |
| | |
10.42 |
| * | |
| | |
Exhibit NumberDescription |
| | | |
| 10.12 |
| * | |
| | | |
10.4310.13 |
| * | |
| | |
| 10.14 |
| * | |
| | |
| 10.15 |
| * | |
| | |
| 10.16 |
| | |
| | | |
| 12.1 |
| | |
| | | |
| 21.1 |
| | |
| | | |
| 23.1 |
| | |
| | |
23.2 |
| | Consent of Netherland, Sewell & Associates, Inc. |
| | | |
| 31.1 |
| | |
| | | |
| 31.2 |
| | |
| | | |
| 32.1 |
| | |
| | | |
| 32.2 |
| | |
| | |
95.1 |
| | Mine Safety Disclosures |
| | |
99.1 |
| | Netherland, Sewell & Associates, Inc.’s report of estimates of the net reserves and future net revenues, as of December 31, 2015, related to Kinder Morgan CO2 Company, L.P.’s interest in certain oil and gas properties located in the state of Texas
|
| | | |
| 101 |
| | Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the years ended December 31, 2015, 2014,2017, 2016, and 2013;2015; (ii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2015, 2014,2017, 2016, and 2013;2015; (iii) our Consolidated Balance Sheets as of December 31, 20152017 and 2014;2016; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014,2017, 2016, and 2013;2015; (v) our Consolidated Statement of Stockholders’ Equity as of and for the years ended December 31, 2015, 2014,2017, 2016, and 2013;2015; and (vi) the notes to our Consolidated Financial Statements |
_______
*Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.
KINDER MORGAN, INC. AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS
|
| |
| | Page Number |
| | |
| |
| | |
| |
| | |
| 2015 | |
| | |
| |
| | |
| |
| | |
| |
| | |
| |
| |
| |
Report of Independent Registered Public Accounting Firm
To the the Board of Directors and Stockholders of Kinder Morgan, Inc.:
Opinions on the Financial Statements and Internal Control over Financial Reporting
In our opinion,We have audited the accompanying consolidatedbalance sheets of Kinder Morgan, Inc. and its subsidiaries (the “Company”)as of December 31, 2017and 2016, and the related consolidatedstatements of income, of comprehensive income (loss), of cash flows and of stockholders’ equity andfor each of cash flowsthe three years in the period ended December 31, 2017, including the related notes (collectively referred to as the “consolidatedfinancial statements”).We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of Kinder Morgan, Inc. and its subsidiaries (the “Company”)atthe Company as of December 31, 20152017 and and 2014,2016, and the results of theiroperations andtheircash flows for each of the three years in the period endedDecember 31, 20152017 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015,2017, based on criteria established in Internal Control - Integrated FrameworFrameworkk (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). COSO.
Basis for Opinions
The Company's management is responsible for these consolidatedfinancial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing inunder Item 9A of the Company’s 2015 Annual Report on Form 10-K. 9A.Our responsibility is to express opinions on these the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our integrated 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 Company 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 Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the consolidatedfinancial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the consolidatedfinancial statement presentation.statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As described in Management’s Report on Internal Control over Financial Reporting appearing in Item 9A of the Company’s 2015 Annual Report on Form 10- K, management has excluded Hiland Partners, LP from its assessment of internal control over financial reporting as of December 31, 2015 because it was acquired in a purchase business combination by Kinder Morgan, Inc. on February 13, 2015. We have also excluded Hiland Partners, LP from our audit of internal control over financial reporting. Hiland Partners, LP is a wholly-owned subsidiary whose total assets and total revenues represent 4% and 3%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2015.
/s/PricewaterhouseCoopers LLP
Houston, Texas
February 16, 20169, 2018
78We have served as the Company’s auditor since 1997.
KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions, Except Per Share Amounts) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Revenues | | | | | |
| Natural gas sales | $ | 2,839 |
| | $ | 4,115 |
| | $ | 3,605 |
|
| Services | 8,290 |
| | 7,650 |
| | 6,677 |
|
| Product sales and other | 3,274 |
| | 4,461 |
| | 3,788 |
|
| Total Revenues | 14,403 |
| | 16,226 |
| | 14,070 |
|
| | | | | | |
| Operating Costs, Expenses and Other | | | |
| | |
| Costs of sales | 4,115 |
| | 6,278 |
| | 5,253 |
|
| Operations and maintenance | 2,337 |
| | 2,157 |
| | 2,112 |
|
| Depreciation, depletion and amortization | 2,309 |
| | 2,040 |
| | 1,806 |
|
| General and administrative | 690 |
| | 610 |
| | 613 |
|
| Taxes, other than income taxes | 439 |
| | 418 |
| | 395 |
|
| Loss on impairment of goodwill | 1,150 |
| | — |
| | — |
|
| Loss (gain) on impairments and disposals of long-lived assets, net | 919 |
| | 274 |
| | (98 | ) |
| Other (income) expense, net | (3 | ) | | 1 |
| | (1 | ) |
| Total Operating Costs, Expenses and Other | 11,956 |
| | 11,778 |
| | 10,080 |
|
| | | | | | |
| Operating Income | 2,447 |
| | 4,448 |
| | 3,990 |
|
| | | | | | |
| Other Income (Expense) | | | |
| | |
| Earnings from equity investments | 414 |
| | 406 |
| | 392 |
|
| Loss on impairments of equity investments | (30 | ) | | — |
| | (65 | ) |
| Amortization of excess cost of equity investments | (51 | ) | | (45 | ) | | (39 | ) |
| Interest, net | (2,051 | ) | | (1,798 | ) | | (1,675 | ) |
| Gain on remeasurement of previously held equity investments to fair value (Note 3) | — |
| | — |
| | 558 |
|
| Gain on sale of investments in Express pipeline system (Note 3) | — |
| | — |
| | 224 |
|
| Other, net | 43 |
| | 80 |
| | 53 |
|
| Total Other Expense | (1,675 | ) | | (1,357 | ) | | (552 | ) |
| | | | | | |
| Income from Continuing Operations Before Income Taxes | 772 |
| | 3,091 |
| | 3,438 |
|
| | | | | | |
| Income Tax Expense | (564 | ) | | (648 | ) | | (742 | ) |
| | | | | | |
| Income from Continuing Operations | 208 |
| | 2,443 |
| | 2,696 |
|
| | | | |
| | |
| Discontinued Operations | | | | | |
| Loss on sale of the FTC Natural Gas Pipelines disposal group, net of tax | — |
| | — |
| | (4 | ) |
| | | | | | |
| Net Income | 208 |
| | 2,443 |
| | 2,692 |
|
| | | | | | |
| Net Loss (Income) Attributable to Noncontrolling Interests | 45 |
| | (1,417 | ) | | (1,499 | ) |
| | | | | | |
| Net Income Attributable to Kinder Morgan, Inc. | 253 |
| | 1,026 |
| | 1,193 |
|
| | | | | | |
| Preferred Stock Dividends | (26 | ) | | — |
| | — |
|
| | | | | | |
| Net Income Available to Common Stockholders | $ | 227 |
| | $ | 1,026 |
| | $ | 1,193 |
|
| | | | | | |
KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (continued) (In Millions, Except Per Share Amounts) | |
KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions, Except Per Share Amounts) | | KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions, Except Per Share Amounts) |
| | | Year Ended December 31, | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| Revenues | | | | | | |
| Natural gas sales | | $ | 3,053 |
| | $ | 2,454 |
| | $ | 2,839 |
|
| Services | | 7,901 |
| | 8,146 |
| | 8,290 |
|
| Product sales and other | | 2,751 |
| | 2,458 |
| | 3,274 |
|
| Total Revenues | | 13,705 |
| | 13,058 |
| | 14,403 |
|
| | | | | | | |
| Operating Costs, Expenses and Other | | | | |
| | |
| Costs of sales | | 4,345 |
| | 3,429 |
| | 4,059 |
|
| Operations and maintenance | | 2,472 |
| | 2,372 |
| | 2,393 |
|
| Depreciation, depletion and amortization | | 2,261 |
| | 2,209 |
| | 2,309 |
|
| General and administrative | | 673 |
| | 669 |
| | 690 |
|
| Taxes, other than income taxes | | 398 |
| | 421 |
| | 439 |
|
| Loss on impairment of goodwill | | — |
| | — |
| | 1,150 |
|
| Loss on impairments and divestitures, net | | 13 |
| | 387 |
| | 919 |
|
| Other income, net | | (1 | ) | | (1 | ) | | (3 | ) |
| Total Operating Costs, Expenses and Other | | 10,161 |
| | 9,486 |
| | 11,956 |
|
| | | | | | | |
| Operating Income | | 3,544 |
| | 3,572 |
| | 2,447 |
|
| | | | | | | |
| Other Income (Expense) | | | | |
| | |
| Earnings from equity investments | | 578 |
| | 497 |
| | 414 |
|
| Loss on impairments and divestitures of equity investments, net | | (150 | ) | | (610 | ) | | (30 | ) |
| Amortization of excess cost of equity investments | | (61 | ) | | (59 | ) | | (51 | ) |
| Interest, net | | (1,832 | ) | | (1,806 | ) | | (2,051 | ) |
| Other, net | | 82 |
| | 44 |
| | 43 |
|
| Total Other Expense | | (1,383 | ) | | (1,934 | ) | | (1,675 | ) |
| | | | | | | |
| Income Before Income Taxes | | 2,161 |
| | 1,638 |
| | 772 |
|
| | | | | | | |
| Income Tax Expense | | (1,938 | ) | | (917 | ) | | (564 | ) |
| | | | | | | |
| Net Income | | 223 |
| | 721 |
| | 208 |
|
| | | | | | | |
| Net (Income) Loss Attributable to Noncontrolling Interests | | (40 | ) | | (13 | ) | | 45 |
|
| | | | | | | |
| Net Income Attributable to Kinder Morgan, Inc. | | 183 |
| | 708 |
| | 253 |
|
| | | | | | | |
| Preferred Stock Dividends | | (156 | ) | | (156 | ) | | (26 | ) |
| | | | | | | |
| Net Income Available to Common Stockholders | | $ | 27 |
| | $ | 552 |
| | $ | 227 |
|
| | 2015 | | 2014 | | 2013 | | | | | |
| Class P Shares | | | |
| | |
| | | |
| | |
|
| Basic Earnings Per Common Share | $ | 0.10 |
| | $ | 0.89 |
| | $ | 1.15 |
| $ | 0.01 |
| | $ | 0.25 |
| | $ | 0.10 |
|
| | | | | | | | | | | |
| Basic Weighted Average Common Shares Outstanding | 2,187 |
| | 1,137 |
| | 1,036 |
| 2,230 |
| | 2,230 |
| | 2,187 |
|
| | | | | | | | | | | |
| Diluted Earnings Per Common Share | $ | 0.10 |
| | $ | 0.89 |
| | $ | 1.15 |
| $ | 0.01 |
| | $ | 0.25 |
| | $ | 0.10 |
|
| | | | |
| | |
| | | | | |
| Diluted Weighted Average Common Shares Outstanding | 2,193 |
| | 1,137 |
| | 1,036 |
| 2,230 |
| | 2,230 |
| | 2,193 |
|
| | | | | | | | | | | |
| Dividends Per Common Share Declared for the Period | $ | 1.605 |
| | $ | 1.740 |
| | $ | 1.600 |
| $ | 0.500 |
| | $ | 0.500 |
| | $ | 1.605 |
|
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In Millions)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Net income | $ | 208 |
| | $ | 2,443 |
| | $ | 2,692 |
|
| Other comprehensive income (loss), net of tax | |
| | |
| | |
|
| Change in fair value of hedge derivatives (net of tax (expense) benefit of $(94), $(163) and $10, respectively) | 164 |
| | 409 |
| | (38 | ) |
| Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $156, $13 and $(3), respectively) | (272 | ) | | (25 | ) | | 11 |
|
| Foreign currency translation adjustments (net of tax benefit of $123, $48, and $31, respectively) | (214 | ) | | (138 | ) | | (103 | ) |
| Benefit plan adjustments (net of tax benefit (expense) of $69, $126 and $(91), respectively) | (122 | ) | | (226 | ) | | 170 |
|
| Total other comprehensive (loss) income | (444 | ) | | 20 |
| | 40 |
|
| | | | | | |
| Comprehensive (loss) income | (236 | ) | | 2,463 |
| | 2,732 |
|
| Comprehensive loss (income) attributable to noncontrolling interests | 45 |
| | (1,486 | ) | | (1,445 | ) |
| Comprehensive (loss) income attributable to KMI | $ | (191 | ) | | $ | 977 |
| | $ | 1,287 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Net income | $ | 223 |
| | $ | 721 |
| | $ | 208 |
|
| Other comprehensive income (loss), net of tax | |
| | |
| | |
|
| Change in fair value of hedge derivatives (net of tax (expense) benefit of $(82), $60 and $(94), respectively) | 145 |
| | (104 | ) | | 164 |
|
| Reclassification of change in fair value of derivatives to net income (net of tax benefit of $97, $67 and $156, respectively) | (171 | ) | | (116 | ) | | (272 | ) |
| Foreign currency translation adjustments (net of tax (expense) benefit of $(56), $(20) and $123, respectively) | 101 |
| | 34 |
| | (214 | ) |
| Benefit plan adjustments (net of tax (expense) benefit of $(27), $19 and $69, respectively) | 40 |
| | (14 | ) | | (122 | ) |
| Total other comprehensive income (loss) | 115 |
| | (200 | ) | | (444 | ) |
| | | | | | |
| Comprehensive income (loss) | 338 |
| | 521 |
| | (236 | ) |
| Comprehensive (income) loss attributable to noncontrolling interests | (86 | ) | | (13 | ) | | 45 |
|
| Comprehensive income (loss) attributable to KMI | $ | 252 |
| | $ | 508 |
| | $ | (191 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions, Except Share and Per Share Amounts) | KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions, Except Share and Per Share Amounts) | KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions, Except Share and Per Share Amounts) |
| | | December 31, | December 31, |
| | 2015 | | 2014 | 2017 | | 2016 |
| ASSETS | | | | | | |
| Current assets | | | | | | |
| Cash and cash equivalents | $ | 229 |
| | $ | 315 |
| $ | 264 |
| | $ | 684 |
|
| Restricted deposits | | 62 |
| | 103 |
|
| Accounts receivable, net | 1,315 |
| | 1,641 |
| 1,448 |
| | 1,370 |
|
| Fair value of derivative contracts | 507 |
| | 535 |
| 114 |
| | 198 |
|
| Inventories | 407 |
| | 459 |
| 424 |
| | 357 |
|
| Deferred income taxes | — |
| | 56 |
| |
| Income tax receivable | | 165 |
| | 180 |
|
| Other current assets | 366 |
| | 746 |
| 238 |
| | 337 |
|
| Total current assets | 2,824 |
| | 3,752 |
| 2,715 |
| | 3,229 |
|
| | | | | | | |
| Property, plant and equipment, net | 40,547 |
| | 38,564 |
| 40,155 |
| | 38,705 |
|
| Investments | 6,040 |
| | 6,036 |
| 7,298 |
| | 7,027 |
|
| Goodwill | 23,790 |
| | 24,654 |
| 22,162 |
| | 22,152 |
|
| Other intangibles, net | 3,551 |
| | 2,302 |
| 3,099 |
| | 3,318 |
|
| Deferred income taxes | 5,323 |
| | 5,651 |
| 2,044 |
| | 4,352 |
|
| Deferred charges and other assets | 2,029 |
| | 2,090 |
| 1,582 |
| | 1,522 |
|
| Total Assets | $ | 84,104 |
| | $ | 83,049 |
| $ | 79,055 |
| | $ | 80,305 |
|
| | | | | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |
| | |
| |
| | |
|
| Current liabilities | |
| | |
| |
| | |
|
| Current portion of debt | $ | 821 |
| | $ | 2,717 |
| $ | 2,828 |
| | $ | 2,696 |
|
| Accounts payable | 1,324 |
| | 1,588 |
| 1,340 |
| | 1,257 |
|
| Accrued interest | 695 |
| | 637 |
| 621 |
| | 625 |
|
| Accrued contingencies | 298 |
| | 383 |
| 291 |
| | 261 |
|
| Other current liabilities | 927 |
| | 1,037 |
| 1,101 |
| | 1,085 |
|
| Total current liabilities | 4,065 |
| | 6,362 |
| 6,181 |
| | 5,924 |
|
| | | | | | | |
| Long-term liabilities and deferred credits | |
| | |
| |
| | |
|
| Long-term debt | | | | | | |
| Outstanding | 40,632 |
| | 38,212 |
| 33,988 |
| | 36,105 |
|
| Preferred interest in general partner of KMP | 100 |
| | 100 |
| 100 |
| | 100 |
|
| Debt fair value adjustments | 1,674 |
| | 1,785 |
| 927 |
| | 1,149 |
|
| Total long-term debt | 42,406 |
| | 40,097 |
| 35,015 |
| | 37,354 |
|
| Other long-term liabilities and deferred credits | 2,230 |
| | 2,164 |
| 2,735 |
| | 2,225 |
|
| Total long-term liabilities and deferred credits | 44,636 |
| | 42,261 |
| 37,750 |
| | 39,579 |
|
| Total Liabilities | 48,701 |
| | 48,623 |
| 43,931 |
| | 45,503 |
|
| | | | | | | |
| Commitments and contingencies (Notes 9, 13 and 17) |
|
| |
|
|
|
| |
|
|
| Stockholders’ Equity | |
| | |
| |
| | |
|
| Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,229,223,864 and 2,125,147,116 shares, respectively, issued and outstanding | 22 |
| | 21 |
| |
| Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,217,110,072 and 2,230,102,384 shares, respectively, issued and outstanding | | 22 |
| | 22 |
|
| Preferred stock, $0.01 par value, 10,000,000 shares authorized, 9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference, 1,600,000 shares issued and outstanding | — |
| | — |
| — |
| | — |
|
| Additional paid-in capital | 41,661 |
| | 36,178 |
| 41,909 |
| | 41,739 |
|
| Retained deficit | (6,103 | ) | | (2,106 | ) | (7,754 | ) | | (6,669 | ) |
| Accumulated other comprehensive loss | (461 | ) | | (17 | ) | (541 | ) | | (661 | ) |
| Total Kinder Morgan, Inc.’s stockholders’ equity | 35,119 |
| | 34,076 |
| 33,636 |
| | 34,431 |
|
| Noncontrolling interests | 284 |
| | 350 |
| 1,488 |
| | 371 |
|
| Total Stockholders’ Equity | 35,403 |
| | 34,426 |
| 35,124 |
| | 34,802 |
|
| Total Liabilities and Stockholders’ Equity | $ | 84,104 |
| | $ | 83,049 |
| $ | 79,055 |
| | $ | 80,305 |
|
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities | | | | | | | | | | |
| Net income | $ | 208 |
| | $ | 2,443 |
| | $ | 2,692 |
| $ | 223 |
| | $ | 721 |
| | $ | 208 |
|
| Adjustments to reconcile net income to net cash provided by operating activities | |
| | |
| | |
| |
| | |
| | |
|
| Depreciation, depletion and amortization | 2,309 |
| | 2,040 |
| | 1,806 |
| 2,261 |
| | 2,209 |
| | 2,309 |
|
| Deferred income taxes | 692 |
| | 615 |
| | 640 |
| 2,073 |
| | 1,087 |
| | 692 |
|
| Amortization of excess cost of equity investments | 51 |
| | 45 |
| | 39 |
| 61 |
| | 59 |
| | 51 |
|
| Change in fair market value of derivative contracts | | 40 |
| | 64 |
|
| (166 | ) |
| Loss (gain) on early extinguishment of debt | | 4 |
| | (45 | ) | | — |
|
| Loss on impairment of goodwill (Note 4) | 1,150 |
| | — |
| | — |
| — |
| | — |
| | 1,150 |
|
| Loss (gain) on impairments and disposals of long-lived assets and equity investments, net | 949 |
| | 274 |
| | (33 | ) | |
| Gain from the remeasurement of net assets to fair value and the sale of discontinued operations (net of cash selling expenses), net of tax (Note 3) | — |
| | — |
| | (556 | ) | |
| Gain from sale of investments in Express pipeline system (Note 3) | — |
| | — |
| | (224 | ) | |
| Loss on impairments and divestitures, net (Note 4) | | 13 |
| | 387 |
| | 919 |
|
| Loss on impairments and divestitures of equity investments, net (Note 4) | | 150 |
| | 610 |
| | 30 |
|
| Earnings from equity investments | (414 | ) | | (406 | ) | | (392 | ) | (578 | ) | | (497 | ) | | (414 | ) |
| Distributions of equity investment earnings | 391 |
| | 381 |
| | 398 |
| 426 |
| | 431 |
| | 391 |
|
| Proceeds from termination of interest rate swap agreements | — |
| | — |
| | 96 |
| |
| Pension contributions and noncash pension benefit credits | (85 | ) | | (88 | ) | | (120 | ) | |
| Changes in components of working capital, net of the effects of acquisitions | |
| | |
| | |
| |
| Accounts receivable | 382 |
| | (84 | ) | | (131 | ) | |
| Pension contributions and noncash pension benefit expenses (credits) | | 8 |
| | 9 |
| | (90 | ) |
| Changes in components of working capital, net of the effects of acquisitions and dispositions | | |
| | |
| | |
|
| Accounts receivable, net | | (78 | ) | | (107 | ) | | 382 |
|
| Income tax receivable | 195 |
| | (195 | ) | | — |
| 7 |
| | (148 | ) | | 195 |
|
| Inventories | 34 |
| | (30 | ) | | (53 | ) | (90 | ) | | 49 |
| | 34 |
|
| Other current assets | 113 |
| | (17 | ) | | (32 | ) | (25 | ) | | (81 | ) | | 113 |
|
| Accounts payable | (156 | ) | | (1 | ) | | (36 | ) | 73 |
| | 144 |
| | (154 | ) |
| Accrued interest, net of interest rate swaps | 37 |
| | 61 |
| | 50 |
| 10 |
| | (18 | ) | | 37 |
|
| Accrued contingencies and other current liabilities | (129 | ) | | 108 |
| | (100 | ) | 101 |
| | 79 |
| | (121 | ) |
| Rate reparations, refunds and other litigation reserve adjustments | 18 |
| | (280 | ) | | 174 |
| (100 | ) | | (32 | ) | | 18 |
|
| Other, net | (442 | ) | | (399 | ) | | (96 | ) | 22 |
| | (126 | ) | | (271 | ) |
| Net Cash Provided by Operating Activities | 5,303 |
| | 4,467 |
| | 4,122 |
| 4,601 |
| | 4,795 |
| | 5,313 |
|
| | | | | | | | | | | |
| Cash Flows From Investing Activities | |
| | |
| | |
| |
| | |
| | |
|
| Acquisitions of assets and investments, net of cash acquired | (2,079 | ) | | (1,388 | ) | | (292 | ) | (4 | ) | | (333 | ) | | (2,079 | ) |
| Proceeds from sales of assets and investments | — |
| | — |
| | 490 |
| |
| Capital expenditures | (3,896 | ) | | (3,617 | ) | | (3,369 | ) | (3,188 | ) | | (2,882 | ) | | (3,896 | ) |
| Proceeds from sale of equity interests in subsidiaries, net | | — |
| | 1,401 |
| | — |
|
| Sales of property, plant and equipment, investments, and other net assets, net of removal costs | | 118 |
| | 330 |
| | 39 |
|
| Contributions to investments | (96 | ) | | (389 | ) | | (217 | ) | (684 | ) | | (408 | ) | | (96 | ) |
| Distributions from equity investments in excess of cumulative earnings | 228 |
| | 182 |
| | 185 |
| 374 |
| | 231 |
| | 228 |
|
| Other, net | 137 |
| | 2 |
| | 81 |
| 22 |
| | (44 | ) | | 98 |
|
| Net Cash Used in Investing Activities | (5,706 | ) | | (5,210 | ) | | (3,122 | ) | (3,362 | ) | | (1,705 | ) | | (5,706 | ) |
| | | | | | | | | | | |
| Cash Flows From Financing Activities | | | | | | | | | | |
| Issuances of debt | 14,316 |
| | 24,573 |
| | 13,581 |
| 8,868 |
| | 8,629 |
| | 14,316 |
|
| Payments of debt | (15,116 | ) | | (17,801 | ) | | (12,393 | ) | (11,064 | ) | | (10,060 | ) | | (15,116 | ) |
| Debt issue costs | (24 | ) | | (89 | ) | | (38 | ) | (70 | ) | | (19 | ) | | (24 | ) |
| Issuances of common shares (Note 11) | 3,870 |
| | — |
| | — |
| — |
| | — |
| | 3,870 |
|
| Issuance of mandatory convertible preferred stock (Note 11) | 1,541 |
| | — |
| | — |
| — |
| | — |
| | 1,541 |
|
| Cash dividends (Note 11) | (4,224 | ) | | (1,760 | ) | | (1,622 | ) | |
| Repurchases of shares and warrants | (12 | ) | | (192 | ) | | (637 | ) | |
| Cash consideration of Merger Transactions (Note 1) | — |
| | (3,937 | ) | | — |
| |
| Merger Transactions costs | (2 | ) | | (74 | ) | | — |
| |
| Contributions from noncontrolling interests | 11 |
| | 1,767 |
| | 1,706 |
| |
| Cash dividends - common shares (Note 11) | | (1,120 | ) | | (1,118 | ) | | (4,224 | ) |
| Cash dividends - preferred shares (Note 11) | | (156 | ) | | (154 | ) | | — |
|
| Repurchases of shares and warrants (Note 11) | | (250 | ) | | — |
| | (12 | ) |
| Contributions from investment partner | | 485 |
| | — |
| | — |
|
| Contributions from noncontrolling interests - net proceeds from KML IPO (Note 3) | | 1,245 |
| | — |
| | — |
|
| Contributions from noncontrolling interests - net proceeds from KML preferred share issuances (Note 11) | | 420 |
| | — |
| | — |
|
| Contributions from noncontrolling interests - other | | 12 |
| | 117 |
| | 11 |
|
| Distributions to noncontrolling interests | (34 | ) | | (2,013 | ) | | (1,692 | ) | (42 | ) | | (24 | ) | | (34 | ) |
| Other, net | 1 |
| | (3 | ) | | — |
| (9 | ) | | (8 | ) | | (11 | ) |
| Net Cash Provided by (Used in) Financing Activities | 327 |
| | 471 |
| | (1,095 | ) | |
| Net Cash (Used in) Provided by Financing Activities | | (1,681 | ) | | (2,637 | ) | | 317 |
|
| | | �� | | | | | | | | |
| Effect of Exchange Rate Changes on Cash and Cash Equivalents | (10 | ) | | (11 | ) | | (21 | ) | 22 |
| | 2 |
| | (10 | ) |
| | | | | | | | | | | |
| Net decrease in Cash and Cash Equivalents | (86 | ) | | (283 | ) | | (116 | ) | |
| Net (decrease) increase in Cash and Cash Equivalents | | (420 | ) | | 455 |
| | (86 | ) |
| Cash and Cash Equivalents, beginning of period | 315 |
| | 598 |
| | 714 |
| 684 |
| | 229 |
| | 315 |
|
| Cash and Cash Equivalents, end of period | $ | 229 |
| | $ | 315 |
| | $ | 598 |
| $ | 264 |
| | $ | 684 |
| | $ | 229 |
|
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(In Millions)
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Noncash Investing and Financing Activities | |
| | |
| | |
| |
| | |
| | |
|
| Assets acquired by the assumption or incurrence of liabilities | $ | 1,681 |
| | $ | 106 |
| | $ | 1,510 |
| $ | — |
| | $ | 43 |
| | $ | 1,681 |
|
| Net assets contributed to equity investment | 46 |
| | — |
| | — |
| |
| Net assets and liabilities or noncontrolling interests acquired by the issuance of shares and warrants (Notes 1 and 3) | — |
| | 16,023 |
| | — |
| |
| Assets acquired or liabilities settled by contributions from noncontrolling interests | — |
| | — |
| | 3,733 |
| |
| Net assets contributed to equity investments | | — |
| | 37 |
| | 46 |
|
| Increase in property, plant and equipment from both accruals and contractor retainage | | 14 |
| | | | |
| | | | | | | | | | | |
| Supplemental Disclosures of Cash Flow Information | | | |
| | |
| | | |
| | |
|
| Cash paid during the period for interest (net of capitalized interest) | 1,985 |
| | 1,718 |
| | 1,652 |
| 1,854 |
| | 2,050 |
| | 1,985 |
|
| Cash (refund) paid during the period for income taxes, net | (331 | ) | | 227 |
| | 67 |
| |
| Cash (refunded) paid during the period for income taxes, net | | (140 | ) | | 4 |
| | (331 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
| | | | Common stock | | Preferred stock | | | | | | | | | | | | | Common stock | | Preferred stock | | | | | | | | | | | | |
| | Issued shares | | Par value | | Issued shares | | Par value | | Additional paid-in capital | | Retained deficit | | Accumulated other comprehensive loss | | Stockholders’ equity attributable to KMI | | Non-controlling interests | | Total | Issued shares | | Par value | | Issued shares | | Par value | | Additional paid-in capital | | Retained deficit | | Accumulated other comprehensive loss | | Stockholders’ equity attributable to KMI | | Non-controlling interests | | Total |
| Balance at December 31, 2012 | 1,036 |
| | $ | 10 |
| | — |
| | $ | — |
| | $ | 14,917 |
| | $ | (943 | ) | | $ | (118 | ) | | $ | 13,866 |
| | $ | 10,234 |
| | $ | 24,100 |
| |
| Repurchases of shares and warrants | (5 | ) | | | | | | | | (637 | ) | | | | | | (637 | ) | | | | (637 | ) | |
| Warrants exercised | | | | | | | | | 1 |
| | | | | | 1 |
| | | | 1 |
| |
| EP Trust I Preferred security conversions | | | | | | | | | 3 |
| | | | | | 3 |
| | | | 3 |
| |
| Restricted shares | | | | | | | | | 33 |
| | | | | | 33 |
| | | | 33 |
| |
| Impact from equity transactions of KMP, EPB and KMR | | | | | | | | | 161 |
| | | | | | 161 |
| | (254 | ) | | (93 | ) | |
| Net income | | | | | | | | | | | 1,193 |
| | | | 1,193 |
| | 1,499 |
| | 2,692 |
| |
| Distributions | | | | | | | | | | | | | | | — |
| | (1,692 | ) | | (1,692 | ) | |
| Contributions | | | | | | | | | | | | | | | — |
| | 5,439 |
| | 5,439 |
| |
| KMP’s acquisition of Copano noncontrolling interests | | | | | | | | | | | | | | | — |
| | 17 |
| | 17 |
| |
| Common stock dividends | | | | | | | | | | | (1,622 | ) | | | | (1,622 | ) | | | | (1,622 | ) | |
| Other | | | | | | | | | 1 |
| | | | | | 1 |
| | 3 |
| | 4 |
| |
| Other comprehensive income | | | | | | | | | | | | | 94 |
| | 94 |
| | (54 | ) | | 40 |
| |
| Balance at December 31, 2013 | 1,031 |
| | 10 |
| | — |
| | — |
| | 14,479 |
| | (1,372 | ) | | (24 | ) | | 13,093 |
| | 15,192 |
| | 28,285 |
| |
| Impact of Merger Transactions | 1,097 |
| | 11 |
| | | | | | 21,880 |
| | | | | | 21,891 |
| | (15,936 | ) | | 5,955 |
| |
| Merger Transactions costs | | | | | | | | | (75 | ) | | | | | | (75 | ) | | | | (75 | ) | |
| Repurchases of shares and warrants | (3 | ) | | | | | | | | (192 | ) | | | | | | (192 | ) | | | | (192 | ) | |
| Restricted shares | | | | | | | | | 52 |
| | | | | | 52 |
| | | | 52 |
| |
| Impact from equity transactions of KMP, EPB and KMR | | | | | | | | | 36 |
| | | | | | 36 |
| | (55 | ) | | (19 | ) | |
| Net income | | | | | | | | | | | 1,026 |
| | | | 1,026 |
| | 1,417 |
| | 2,443 |
| |
| Distributions | | | | | | | | | | | | | | | — |
| | (2,013 | ) | | (2,013 | ) | |
| Contributions | | | | | | | | | | | | | | | — |
| | 1,767 |
| | 1,767 |
| |
| Common stock dividends | | | | | | | | | | | (1,760 | ) | | | | (1,760 | ) | | | | (1,760 | ) | |
| Other | | | | | | | | | (2 | ) | | | | | | (2 | ) | | (4 | ) | | (6 | ) | |
| Other comprehensive (loss) income | | | | | | | | | | | | | (49 | ) | | (49 | ) | | 69 |
| | 20 |
| |
| Impact of Merger Transactions on Accumulated other comprehensive loss | | | | | | | | | | | | | 56 |
| | 56 |
| | (87 | ) | | (31 | ) | |
| Balance at December 31, 2014 | 2,125 |
| | 21 |
| | — |
| | — |
|
| 36,178 |
|
| (2,106 | ) |
| (17 | ) |
| 34,076 |
|
| 350 |
| | 34,426 |
| 2,125 |
| | $ | 21 |
| | — |
| | $ | — |
| | $ | 36,178 |
| | $ | (2,106 | ) | | $ | (17 | ) | | $ | 34,076 |
| | $ | 350 |
| | $ | 34,426 |
|
| Issuances of common shares | 103 |
| | 1 |
| | | | | | 3,869 |
| | | | | | 3,870 |
| | | | 3,870 |
| 103 |
| | 1 |
| | | | | | 3,869 |
| | | | | | 3,870 |
| | | | 3,870 |
|
| Issuances of preferred shares | | | | | 2 |
| | | | 1,541 |
| | | | | | 1,541 |
| | | | 1,541 |
| | | | | 2 |
| | | | 1,541 |
| | | | | | 1,541 |
| | | | 1,541 |
|
| Repurchases of warrants | | | | | | | | | (12 | ) | | | | | | (12 | ) | | | | (12 | ) | |
| Repurchase of warrants | | | | | | | | | | (12 | ) | | | | | | (12 | ) | | | | (12 | ) |
| EP Trust I Preferred security conversions | 1 |
| | | | | | | | 23 |
| | | | | | 23 |
| | | | 23 |
| 1 |
| | | | | | | | 23 |
| | | | | | 23 |
| | | | 23 |
|
| Warrants exercised | | | | | | | | | 2 |
| | | | | | 2 |
| | | | 2 |
| | | | | | | | | 2 |
| | | | | | 2 |
| | | | 2 |
|
| Restricted shares | | | | | | | | | 57 |
| | | | | | 57 |
| | | | 57 |
| | | | | | | | | 57 |
| | | | | | 57 |
| | | | 57 |
|
| Net income | | | | | | | | | | | 253 |
| | | | 253 |
| | (45 | ) | | 208 |
| | | | | | | | | | | 253 |
| | | | 253 |
| | (45 | ) | | 208 |
|
| Distributions | | | | | | | | | | | | | | | — |
| | (34 | ) | | (34 | ) | | | | | | | | | | | | | | | — |
| | (34 | ) | | (34 | ) |
| Contributions | | | | | | | | | | | | | | | — |
| | 11 |
| | 11 |
| | | | | | | | | | | | | | | — |
| | 11 |
| | 11 |
|
| Preferred stock dividends | | | | | | | | | | | (26 | ) | | | | (26 | ) | | | | (26 | ) | | | | | | | | | | | (26 | ) | | | | (26 | ) | | | | (26 | ) |
| Common stock dividends | | | | | | | | | | | (4,224 | ) | | | | (4,224 | ) | | | | (4,224 | ) | | | | | | | | | | | (4,224 | ) | | | | (4,224 | ) | | | | (4,224 | ) |
| Other | | | | | | | | | 3 |
| | | | | | 3 |
| | 2 |
| | 5 |
| | | | | | | | | 3 |
| | | | | | 3 |
| | 2 |
| | 5 |
|
| Other comprehensive loss | | | | | | | | | | | | | (444 | ) | | (444 | ) | | | | (444 | ) | | | | | | | | | | | | | (444 | ) | | (444 | ) | | | | (444 | ) |
| Balance at December 31, 2015 | 2,229 |
| | $ | 22 |
| | 2 |
| | $ | — |
|
| $ | 41,661 |
|
| $ | (6,103 | ) |
| $ | (461 | ) | | $ | 35,119 |
| | $ | 284 |
| | $ | 35,403 |
| 2,229 |
| | 22 |
| | 2 |
| | — |
| | 41,661 |
| | (6,103 | ) | | (461 | ) | | 35,119 |
| | 284 |
| | 35,403 |
|
| Restricted shares | | 1 |
| | | | | | | | 66 |
| | | | | | 66 |
| | | | 66 |
|
| Net income | | | | | | | | | | | | 708 |
| | | | 708 |
| | 13 |
| | 721 |
|
| Distributions | | | | | | | | | | | | | | | | — |
| | (24 | ) | | (24 | ) |
| Contributions | | | | | | | | | | | | | | | | — |
| | 117 |
| | 117 |
|
| Preferred stock dividends | | | | | | | | | | | | (156 | ) | | | | (156 | ) | | | | (156 | ) |
| Common stock dividends | | | | | | | | | | | | (1,118 | ) | | | | (1,118 | ) | | | | (1,118 | ) |
| Other | | | | | | | | | | 12 |
| | | | | | 12 |
| | (19 | ) | | (7 | ) |
| Other comprehensive loss | | | | | | | | | | | | | | (200 | ) | | (200 | ) | | | | (200 | ) |
| Balance at December 31, 2016 | | 2,230 |
| | 22 |
| | 2 |
| | — |
|
| 41,739 |
|
| (6,669 | ) |
| (661 | ) |
| 34,431 |
|
| 371 |
| | 34,802 |
|
| Repurchases of shares | | (14 | ) | | | | | | | | (250 | ) | | | | | | (250 | ) | | | | (250 | ) |
| Restricted shares | | 1 |
| | | | | | | | 65 |
| | | | | | 65 |
| | | | 65 |
|
| Net income | | | | | | | | | | | | 183 |
| | | | 183 |
| | 40 |
| | 223 |
|
| KML IPO | | | | | | | | | | 314 |
| | | | 51 |
| | 365 |
| | 684 |
| | 1,049 |
|
| KML preferred share issuance | | | | | | | | | | | | | | | | — |
| | 419 |
| | 419 |
|
| Reorganization of foreign subsidiaries | | | | | | | | | | 38 |
| | | | | | 38 |
| | | | 38 |
|
| Distributions | | | | | | | | | | | | | | | | — |
| | (48 | ) | | (48 | ) |
| Contributions | | | | | | | | | | | | | | | | — |
| | 18 |
| | 18 |
|
| Preferred stock dividends | | | | | | | | | | | | (156 | ) | | | | (156 | ) | | | | (156 | ) |
| Common stock dividends | | | | | | | | | | | | (1,120 | ) | | | | (1,120 | ) | | | | (1,120 | ) |
| Impact of adoption of ASU 2016-09 (See Note 5) | | | | | | | | | | | | 8 |
| | | | 8 |
| | | | 8 |
|
| Sale and deconsolidation of interest in Deeprock Development, LLC | | | | | | | | | | | | | | | | — |
| | (30 | ) | | (30 | ) |
| Other | | | | | | | | | | 3 |
| | | | | | 3 |
| | (12 | ) | | (9 | ) |
| Other comprehensive income | | | | | | | | | | | | | | 69 |
| | 69 |
| | 46 |
| | 115 |
|
| Balance at December 31, 2017 | | 2,217 |
| | $ | 22 |
| | 2 |
| | $ | — |
|
| $ | 41,909 |
|
| $ | (7,754 | ) |
| $ | (541 | ) | | $ | 33,636 |
| | $ | 1,488 |
| | $ | 35,124 |
|
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. General
We are one of the largest energy infrastructure companycompanies in North America and unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals transload and store petroleum products, ethanol and chemicals, and handle such products as coal,including petroleum coke, steel and steel.coal. We are also thea leading producer and transporter of CO2, which is utilizedwe and others utilize for enhanced oil recovery projects primarily in North America.
On November 26, 2014, we completed our acquisition, pursuant to three separate merger agreements, of all of the outstanding common units of Kinder Morgan Energy Partners, L.P. and El Paso Pipeline Partners, L.P. and all of the outstanding shares of Kinder Morgan Management, LLC that we did not already own. The transactions, valued at approximately $77 billion, are referred to collectively as the “Merger Transactions.”
As we controlled each of KMP, KMR and EPB and continued to control each of them after the Merger Transactions, the changes in our ownership interest in each of KMP, KMR and EPB were accounted for as an equity transaction and no gain or loss was recognized in our consolidated statements of income related to the Merger Transactions. After closing the KMR Merger Transaction, KMR was merged with and into KMI. On January 1, 2015, EPB and its subsidiary, EPPOC merged with and into KMP. References to EPB refer to EPB for periods prior to its merger into KMP.
Prior to the Merger Transactions, we owned an approximate 10% limited partner interest (including our interest in KMR) and the 2% general partner interest including incentive distribution rights in KMP, and an approximate 39% limited partner interest and the 2% general partner interest and incentive distribution rights in EPB. Effective with the Merger Transactions, the incentive distribution rights held by the general partner of KMP was eliminated.
The equity interests in KMP, EPB and KMR (which are all consolidated in our financial statements) owned by the public prior to the Merger Transactions are reflected within “Noncontrolling interests” in our accompanying consolidated statements of stockholders’ equity. The earnings recorded by KMP, EPB and KMR that are attributed to their units and shares, respectively, held by the public prior to the Merger Transactions are reported as “Net income attributable to noncontrolling interests” in our accompanying consolidated statements of income.Permian basin.
Our common stock trades on the NYSE under the symbol “KMI.”
2. Summary of Significant Accounting Policies
Basis of Presentation
Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, except whereunless stated otherwise. Our accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification, the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.
Use of Estimates
Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including as it relates to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
In addition, we believe that certainCertain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.
Cash Equivalents and Restricted Deposits
We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.
Restricted cash of $60deposits were $62 million and $118$103 million as of December 31, 20152017 and 2014, respectively, is included in “Other current assets.”2016, respectively.
Accounts Receivable, net
The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of December 31, 20152017 and 20142016 primarily consist of amounts due from customers.customers net of the allowance for doubtful accounts.
Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved.
The allowance for doubtful accounts was $91$35 million and $10$39 million as of December 31, 20152017 and 2014,2016, respectively. The increase was primarily associated with reserves established related to certain coal customers.
Inventories
Our inventories consist of materials and supplies and products such as, NGL, crude oil, condensate, refined petroleum products, transmix and natural gas. We report these assetsproducts inventory at the lower of weighted-average cost or market.net realizable value. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.
Gas Imbalances
We value gas imbalances due to or due from interconnecting pipelines at market prices. As of December 31, 20152017 and 20142016, our gas imbalance receivables—including both trade and related party receivables—totaled $2142 million and $103108 million, respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 20152017 and 20142016, our gas imbalance payables—consisting of onlyincluding both trade and related party payables—totaled $1747 million and $3645 million, respectively, and we included these amounts within “Other current liabilities” on our accompanying consolidated balance sheets.
Property, Plant and Equipment, net
Capitalization, Depreciation and Depletion and Disposals
We report property, plant and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in the period incurred.
We generally compute depreciation using either the straight-line method based on estimated economic lives or for certain depreciable assets, we employ the composite depreciation method, applyingwhich applies a single depreciation rate for a group of assets. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 0.9%1.09% to 23.0% excluding certain short-lived assets such as vehicles. For FERC-regulated entities, the FERC-accepted composite depreciation rate is applied to the total cost of the composite group until the net book value equals the salvage value. For other entities, depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances, contract term for assets on leased or customer property and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. Subsequent events could cause us to change our estimates, thus
impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.
Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method costs that are incurred to acquire leasehold and subsequent development costs are capitalized. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset.
We engage in enhanced recovery techniques in which CO2 is injected into certain producing oil reservoirs. In some cases, the cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected. When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. The units-of-production depreciation rate is determined by field and for our oil and gas producing fields that have no proved reserves, the units-of-production depreciation rate is based on each field’s probable reserves and NYMEX forward curve prices.
A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our bulk and liquids terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the market value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset. For our pipeline system assets under the composite method of depreciation, we generally charge the original cost of property sold or retired to accumulated
depreciation and amortization, net of salvage and cost of removal. Gains and losses are booked for operating unit sales and land sales and are recorded to income or expense accounts in accordance with regulatory accounting guidelines. In those instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount.
Asset Retirement Obligations
We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.
We have various other obligations throughout our businesses to remove facilities and equipment on rights-of-way and other leased facilities. We currently cannot reasonably estimate the fair value of these obligations because the associated assets have indeterminate lives. These assets include pipelines, certain processing plants and distribution facilities, and certain bulk and liquids terminal facilities. An asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.
Long-lived Asset and Other Intangibles Impairments
We evaluate long-lived assets and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable. We recognize impairment losses when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount.
PriorIn addition to us conducting theour annual goodwill impairment test, to the extent triggering events exist, we complete a review of the carrying value of our long-lived assets, including property, plant and equipment as well as other intangibles, and record, as applicable, the appropriate impairments. Because the impairment test for long-lived assets held in use is based on undiscounted cash flows, there may be instances where an asset or asset group is not considered impaired, even when its fair
value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset or asset group.
We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on total proved and risk-adjusted probable reserves. For the purpose of impairment testing, adjustments for the inclusion of risk-adjusted probable reserves, as well as forward curve pricing and estimates of future costs, will cause impairment calculation cash flows to differ from the amounts presented in our supplemental information on oil and gas producing activities disclosed in “Supplemental Information on Oil and Gas Producing Activities (Unaudited).”
Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on total proved and risk-adjusted probable and possible reserves or, if available, comparable market values. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment.
Equity Method of Accounting and Excess Investment Cost
We account for investments—investments which we do not control, but do have the ability to exercise significant influence—byinfluence using the equity method of accounting. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received.
With regard to our equity investments in unconsolidated affiliates, in almost all cases, either (i) the price we paid to acquire our share of the net assets of such equity investees or (ii) the revaluation of our share of the net assets of any retained noncontrolling equity investment (from the sale of a portion of our ownership interest in a consolidated subsidiary, thereby losing our controlling financial interest in the subsidiary) differed from the underlying carrying value of such net assets. This differential consists of two pieces. First, an amount related to the difference between the investee’s recognized net assets at book value and at current fair values (representing the appreciated value in plant and other net assets), and secondly, to any premium in excess of fair value (referred to as equity method goodwill) we paid to acquire the investment. We include both amounts within “Investments” on our accompanying consolidated balance sheets.
The first differential, representing the excess of the fair market value of our investees’ plant and other net assets over its underlying book value at either the date of acquisition or the date of the loss of control totaled $808732 million and $870$767 million as of December 31, 20152017 and 20142016, respectively. Generally, this basis difference relates to our share of the underlying depreciable assets, and, as such, we amortize this portion of our investment cost against our share of investee earnings. As of December 31, 2015,2017, this excess investment cost is being amortized over a weighted average life of approximately fifteenfourteen years.
The second differential, representing equity method goodwill, totaled $138$956 million for both periods as of both December 31, 20152017 and 20142016. This differential is not subject to amortization but rather to impairment testing as part of our periodic evaluation of the recoverability of our investment as compared to the fair value of net assets accounted for under the equity method. Our impairment test considers whether the fair value of the equity investment as a whole has declined and whether that decline is other than temporary.
Goodwill
Goodwill is the cost of an acquisition in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually. This test requires us to assign goodwill to an appropriate reporting unit and to determine if the implied fair value of the reporting unit’s goodwill is less than its carrying amount.
We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have seven reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; (vi) Terminals; and (vii) Kinder Morgan Canada. We also evaluate goodwill for impairment to the extent events or conditions indicate a risk of possible impairment during the interim periods subsequent to our annual impairment test. Generally, the evaluation of goodwill for impairment involves a two-step test, although under certain circumstance an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test.
Step 1 involves comparing the estimated fair value of each respective reporting unit to its carrying value, including goodwill. If the estimated fair value exceeds the carrying value, the reporting unit’s goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, step 2 must be performed to determine whether goodwill is impaired and, if so, the amount of the impairment. Step 2 involves calculating an implied fair value of goodwill by performing a hypothetical allocation of the estimated fair value of the reporting unit determined in step 1 to the respective tangible and intangible net assets of the reporting unit. The remaining implied goodwill is then compared to the actual carrying amount of the goodwill for the reporting unit. To the extent the carrying amount of goodwill exceeds the implied goodwill, the difference is the amount of the goodwill impairment.
A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit.
Refer to Note 8 “Goodwill” for further information.
Other Intangibles
Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets. As of both periods of December 31, 20152017 and 20142016, the gross carrying amounts of these intangible assets totaled $3,551was $4,305 million and $2,302the accumulated amortization was $1,206 million and $987 million, respectively, resulting in net carrying amounts of $3,099 million and $3,318 million, respectively. These intangible assets primarily consisted of customer contracts, relationships and agreements associated with our Natural Gas Pipelines and Terminals business segments.
Primarily, these contracts, relationships and agreements relate to the gathering of natural gas, and the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline and other refined petroleum products, coal, petroleum coke, fertilizer, steel and ores. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate.
We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in
the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. Among the factors we weigh, depending on the nature of the asset, are the effect of obsolescence, new technology, and competition.
For the years ended December 31, 20152017, 20142016 and 20132015, the amortization expense on our intangibles totaled $221$220 million, $143223 million and $125221 million, respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2016(2018 – 2020)2022) is approximately $221 million, $218 million, $216 million, $214 million, $212 million, $209 million, $209 million, and $211$206 million, , respectively. As of December 31, 20152017, the weighted average amortization period for our intangible assets was approximately eighteensixteen years.
Other intangibles are evaluated for recoverability consistent with the discussion above on long-lived asset impairments.
Revenue Recognition
We recognize revenue as services are rendered or goods are delivered and, if applicable, risk of loss has passed. We recognize natural gas, crude and NGL sales revenue when the commodity is sold to a purchaser at a fixed or determinable price, delivery has occurred and risk of loss has transferred, and collectability of the revenue is reasonably assured. Our sales and purchases of natural gas, crude and NGL are primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales, except in circumstances where we soleysolely act as an agent and do not have price and related risk of ownership, in which case we recognize revenue on a net basis.
In addition to storing and transporting a significant portion of the natural gas volumes we purchase and resell, we provide various types of natural gas storage and transportation services for third-party customers. Under these contracts, the natural gas remains the property of these customers at all times. In many cases, generally described as firm service, the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue
when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities.
In other cases, generally described as interruptible service, there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements.
We provide crude oil and refined petroleum products transportation and storage services to customers. Revenues are recorded when products are delivered and services have been provided, and adjusted according to terms prescribed by the toll settlements with shippers and approved by regulatory authorities.
We recognize bulk terminal transfer service revenues based on volumes loaded and unloaded. We recognize liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal throughput revenue based on volumes received and volumes delivered. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when risk of loss has passed. We recognize energy-related product sales revenues based on delivered quantities of product.
Revenues from the sale of crude oil, NGL, CO2 and natural gas production within the CO2 business segment are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices. Since there is a ready market for oil and gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the buyer.
Cost of Sales
Cost of sales primarily includes the cost of energy commodities sold, including natural gas, NGL and other refined petroleum products, adjusted for the effects of our energy commodity activities, as applicable, other than production from our CO2 business segment.
Operations and Maintenance
Operations and maintenance include costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our oil, gas and CO2 producing activities included within operations and maintenance totaled $342 million, $349 million and $366 million for the years ended December 31, 2017, 2016 and 2015, respectively.
Environmental Matters
We capitalize or expense, as appropriate, environmental expenditures. We capitalize certain environmental expenditures required in obtaining rights-of-way, regulatory approvals or permitting as part of the construction. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities assumed in a business combination.
We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable.
Pensions and Other Postretirement Benefits
We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheet. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—in “Accumulated other comprehensive loss”loss,” with the proportionate share associated with less than wholly owned consolidated subsidiaries allocated and included within “Noncontrolling interests,” or as a regulatory asset or liability for certain of our regulated operations, until they are amortized as a component of benefit expense.
Noncontrolling Interests
Noncontrolling interests represents the interests in our consolidated subsidiaries that are not owned by us. In our accompanying consolidated income statements, the noncontrolling interest in the net income (or loss) of our consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net Income(Income) Loss Attributable
to Noncontrolling Interests.” In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”
Income Taxes
Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.
Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount that is, more likely than not, to not be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any tax benefitchange in the amount that we do not
expect to ultimately realize will be realized.included in income in the period in which such a determination is reached.
In determining the deferred income tax asset and liability balances attributable to our investments, we apply an accounting policy that looks through our investments. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments.
Foreign Currency Transactions and Translation
Foreign currency transaction gains or losses result from a change in exchange rates between (i) the functional currency, for example the Canadian dollar for a Canadian subsidiary and (ii) the currency in which a foreign currency transaction is denominated, for example the U.S. dollar for a Canadian subsidiary. In our accompanying consolidated statements of income, gains and losses from our foreign currency transactions are included within “Other Income (Expense)—Other, net.”
Foreign currency translation is the process of expressing, in U.S. dollars, amounts recorded in a local functional currency other than U.S. dollars, for example the Canadian dollar for a Canadian subsidiary. We translate the assets and liabilities of each of our consolidated foreign subsidiaries that have a local functional currency to U.S. dollars at year-end exchange rates. Income and expense items are translated at weighted-average rates of exchange prevailing during the year and stockholders’ equity accounts are translated by using historical exchange rates. The cumulative translation adjustments balance is reported as a component of “Accumulated other comprehensive loss.”
Comprehensive Income
For each of the years ended December 31, 2015, 2014 and 2013, the difference between our net income and our comprehensive income resulted from (i) unrealized gains or losses on derivative contracts accounted for as cash flow hedges; (ii) foreign currency translation adjustments; and (iii) unrealized gains or losses related to changes in pension and other postretirement benefit plan liabilities. For more information on our risk management activities, see Note 14.
Risk Management Activities
We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of commodities including natural gas, NGL and crude oil. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations. We also enter into cross-currency swap agreements to manage our foreign currency risk.risk with certain debt obligations. We measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability. For certain physical forward commodity derivatives contracts, we apply the normal purchase/normal sale exception, whereby the revenues and expenses associated with such transactions are recognized during the period when the commodities are physically delivered or received.
For qualifying accounting hedges, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives and the methods used for assessing and testing effectiveness, and how any ineffectiveness will be measured and recorded. If we designate a derivative contract as a cash flow accounting hedge, the effective portion of the change in fair value of the derivative is deferred in accumulated“Accumulated other comprehensive income/(loss)loss” and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value or amount excluded from the assessment of hedge effectiveness is recognized currently in earnings. If we designate a derivative contract as a fair value accounting hedge, the effective portion of the change in fair value of the derivative is recorded as an adjustment to the item being hedged. Any ineffective portion of the derivative’s change in fair value is recognized currently in earnings.
For derivative instruments that are not designated as accounting hedges, or for which we have not elected the normal purchase/normal sales exception, changes in fair value are recognized currently in earnings.
Regulatory Assets and Liabilities
Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We included the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets. As of December 31, 2015, the recovery period for these regulatory assets was approximatelyone year to forty-one years.
The following table summarizes our regulatory asset and liability balances as of December 31, 20152017 and 20142016 (in millions):
| | | | December 31, | December 31, |
| | 2015 | | 2014 | 2017 | | 2016 |
| Current regulatory assets | $ | 55 |
| | $ | 81 |
| $ | 60 |
| | $ | 49 |
|
| Non-current regulatory assets | 378 |
| | 406 |
| 288 |
| | 330 |
|
Total regulatory assets | $ | 433 |
| | $ | 487 |
| $ | 348 |
| | $ | 379 |
|
| | | | | | | |
| Current regulatory liabilities | $ | 161 |
| | $ | 189 |
| $ | 107 |
| | $ | 101 |
|
| Non-current regulatory liabilities | 166 |
| | 290 |
| 236 |
| | 108 |
|
Total regulatory liabilities | $ | 327 |
| | $ | 479 |
| $ | 343 |
| | $ | 209 |
|
_______
| |
| (a) | Regulatory assets as of December 31, 2017 include (i) $193 million of unamortized losses on disposal of assets; (ii) $55 million income tax gross up on equity AFUDC; and (iii) $100 million of other assets including amounts related to fuel tracker arrangements. Approximately $124 million of the regulatory assets, with a weighted average remaining recovery period of 17 years, are recoverable without earning a return, including the income tax gross up on equity AFUDC for which there is an offsetting deferred income tax balance for FERC rate base purposes, and therefore, it does not earn a return. |
| |
| (b) | Regulatory liabilities as of December 31, 2017 are comprised of customer prepayments to be credited to shippers or other over-collections that are expected to be returned to shippers or netted against under-collections over time. Approximately $20 million of the $236 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 28 years, while the remaining $216 million is not subject to a defined period. |
Transfer of Net Assets Between Entities Under Common Control
We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the historical income statement or balance sheet of the combined entity.
Earnings per Share
We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares of common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be stock or stock units issued to management employees and include dividend equivalent payments, do not participate in excess distributions over earnings.
The following tables set forth the allocation of net income available to shareholders of Class P shares and participating securities and the reconciliation of Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding (in millions): |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Class P | $ | 214 |
| | $ | 1,015 |
| | $ | 1,187 |
|
| Participating securities: | | | | | |
| Restricted stock awards(a) | 13 |
| | 11 |
| | 6 |
|
| Net Income Available to Common Stockholders | $ | 227 |
| | $ | 1,026 |
| | $ | 1,193 |
|
|
| | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Basic Weighted Average Common Shares Outstanding | 2,187 |
| | 1,137 |
| | 1,036 |
|
| Effect of dilutive securities: | | | | | |
| Warrants(b) | 6 |
| | — |
| | — |
|
| Diluted Weighted Average Common Shares Outstanding | 2,193 |
| | 1,137 |
| | 1,036 |
|
________ |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Net Income Available to Common Stockholders | $ | 27 |
| | $ | 552 |
| | $ | 227 |
|
| Participating securities: | | | | | |
| Less: Net Income Allocated to Restricted stock awards(a) | (5 | ) | | (4 | ) | | (13 | ) |
| Net Income Allocated to Class P Stockholders | $ | 22 |
| | $ | 548 |
| | $ | 214 |
|
| | | | | | |
| Basic Weighted Average Common Shares Outstanding | 2,230 |
| | 2,230 |
| | 2,187 |
|
| Basic Earnings Per Common Share | $ | 0.01 |
| | $ | 0.25 |
| | $ | 0.10 |
|
|
| | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Basic Weighted Average Common Shares Outstanding | 2,230 |
| | 2,230 |
| | 2,187 |
|
| Effect of dilutive securities: | | | | | |
| Warrants | — |
| | — |
| | 6 |
|
| Diluted Weighted Average Common Shares Outstanding | 2,230 |
| | 2,230 |
| | 2,193 |
|
_______
| |
| (a) | As of December 31, 2015,2017, there were approximately 811 million such restricted stock awards. |
| |
(b) | Each warrant entitles the holder to purchase one share of our common stock for an exercise price of $40 per share, payable in cash or by cashless exercise, at any time until May 25, 2017. |
The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share (in millions on a weighted average basis):
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Unvested restricted stock awards | 7 |
| | 7 |
| | 4 |
| 10 |
| | 8 |
| | 7 |
|
Warrants to purchase our Class P shares | 291 |
| | 312 |
| | 401 |
| 116 |
| | 293 |
| | 291 |
|
| Convertible trust preferred securities | 8 |
| | 10 |
| | 10 |
| 3 |
| | 8 |
| | 8 |
|
Mandatory convertible preferred stock | 10 |
| | n/a |
| | n/a |
| 58 |
| | 58 |
| | 10 |
|
_______
n/a - not applicable
| |
| (a) | On May 25, 2017, approximately 293 million of unexercised warrants expired without the issuance of Class P common stock. Prior to expiration, each warrant entitled the holder to purchase one share of our common stock for an exercise price of $40 per share. The potential dilutive effect of the warrants did not consider the assumed proceeds to KMI upon exercise. |
| |
| (b) | Until our mandatory convertible preferred shares are converted to common shares, on or before the expected mandatory conversion date of October 26, 2018, the holder of each preferred share participates in our earnings by receiving preferred stock dividends. |
3. Acquisitions and Divestitures
Business Combinations
There were no significant acquisitions during 2017. During 2015, 20142016 and 2013,2015, we completed the following significant acquisitions.
Allocation of Purchase Price
As of December 31, 2017, the purchase allocation for our significant acquisitions accounted for in accordance withcompleted during the “Business Combinations” Topic of the Codification.reporting periods are detailed below (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Assignment of Purchase Price |
| Ref. | | Date | | Acquisition | | Purchase price | | Current assets | | Property plant & equipment | | Deferred charges & other | | Goodwill | | Debt | | Other liabilities |
| (1) | | 2/16 | | BP Products North America Inc. Terminal Assets | | $ | 349 |
| | $ | 2 |
| | $ | 396 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (49 | ) |
| (2) | | 2/15 | | Vopak Terminal Assets | | 158 |
| | 2 |
| | 155 |
| | — |
| | 6 |
| | — |
| | (5 | ) |
| (3) | | 2/15 | | Hiland | | 1,709 |
| | 79 |
| | 1,492 |
| | 1,498 |
| | 310 |
| | (1,413 | ) | | (257 | ) |
After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, goodwill is an intangible asset representing the future economic benefits expected to be derived from an acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that generated our goodwill are both the value of the synergies created between the acquired assets and our pre-existing assets, and our expected ability to grow the business we acquired by leveraging our pre-existing business experience. Additionally, we adjust goodwill asWe apply a result of applying the look-throughlook through method of recording deferred income taxes on the outside book taxbook-tax basis differences in our investments without regard to non-tax deductible goodwill.investments. As a result, no deferred income taxes are recorded associated with non-deductible goodwill recorded at the investee level.
The following table discloses our assignment of the purchase price for each of our significant acquisitions (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Assignment of Purchase Price |
| Ref. | Date | Acquisition | Purchase price | | Current assets | | Property plant & equipment | | Deferred charges & other | | Goodwill | | Long-term debt | | Other liabilities | | Non-controlling interest | | Previously held equity interest |
| (1) | 2/15 | Vopak Terminal Assets | $ | 158 |
| | $ | 2 |
| | $ | 155 |
| | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | (6 | ) | | $ | — |
| | $ | — |
|
| (2) | 2/15 | Hiland | 1,709 |
| | 79 |
| | 1,497 |
| | 1,498 |
| | 310 |
| | (1,411 | ) | | (264 | ) | | — |
| | — |
|
| (3) | 11/14 | Pennsylvania and Florida Jones Act Tankers | 270 |
| | — |
| | 270 |
| | 8 |
| | 25 |
| | — |
| | (33 | ) | | — |
| | — |
|
| (4) | 1/14 | American Petroleum Tankers and State Class Tankers | 961 |
| | 6 |
| | 951 |
| | 6 |
| | 64 |
| | — |
| | (66 | ) | | — |
| | — |
|
| (5) | 6/13 | Goldsmith-Landreth Field Unit | 280 |
| | — |
| | 298 |
| | — |
| | — |
| | — |
| | (18 | ) | | — |
| | — |
|
| (6) | 5/13 | Copano | 3,733 |
| | 218 |
| | 2,788 |
| | 1,973 |
| | 963 |
| | (1,252 | ) | | (236 | ) | | (17 | ) | | (704 | ) |
(1) BP Products North America Inc. (BP) Terminal Assets
On February 1, 2016, we completed the acquisition of 15 products terminals and associated infrastructure from BP for $349 million, including a transaction deposit paid in 2015 and working capital adjustments paid in 2016. In conjunction with this transaction, we and BP formed a joint venture with an equity ownership interest of 75% and 25%, respectively. Subsequent to the acquisition, we contributed 14 of the acquired terminals to the joint venture, which we operate, and the remaining terminal is solely owned by us. BP acquired its 25% interest in the joint venture for $84 million, which we reported as “Contributions from noncontrolling interests” within our accompanying consolidated statement of cash flows for the year ended December 31, 2016. Of the acquired assets, 10 terminals are included in our Terminals business segment and 5 terminals are included in our Products Pipelines business segment based on synergies with each segment’s respective existing operations.
(2) Vopak Terminal Assets
On February 27, 2015, we acquired three U.S. terminals and one undeveloped site from Royal Vopak (Vopak) for approximately $158 million in cash. The acquisition included (i) a 36-acre, 1,069,500-barrel storage facility at Galena Park, Texas that handles base oils, biodiesel and crude oil and is immediately adjacent to our Galena Park terminal facility; (ii) two terminals in North Carolina: one in North Wilmington that handles chemicals and black oil and the other in South Wilmington that is not currently operating; and (iii) an undeveloped waterfront access site in Perth Amboy, New Jersey. We include the acquired assets as part of theour Terminals business segment.
(2)(3) Hiland
On February 13, 2015, we acquired Hiland, a privately held Delaware limited partnership for aggregate consideration of approximately $3,120$3,122 million, including assumed debt. Approximately $368 million of the debt assumed was immediately paid down after closing. Hiland’s assets consist primarily of crude oil gathering and transportation pipelines and gas gathering and processing systems, primarily handling production from the Bakken Formation in North Dakota and Montana. The acquired gathering and processing assets are included in our Natural Gas Pipelines business segment while the acquired crude oil transport pipeline (Double H pipeline) is included in our Products Pipelines business segment. Deferred charges and other relates to customer contracts and relationships with a weighted average amortization period of 16.8 years.
(3) Pennsylvania and Florida Jones Act Tankers
On November 5, 2014, we acquired two Jones Act tankers from Crowley Maritime Corporation (Crowley) for approximately $270 million. The MT Pennsylvania and the MT Florida engage in the marine transportation of crude oil, condensate and refined products in the U.S. domestic trade, commonly referred to as the Jones Act trade, and are currently operating pursuant to multi-year charters with a major integrated oil company. The vessels each have approximately 330 MBbl of cargo capacity and are included in the Terminals business segment. The acquired vessels will continue to be operated by Crowley.
(4) American Petroleum Tankers and State Class Tankers
Effective January 17, 2014, we acquired APT and State Class Tankers (SCT) for aggregate consideration of $961 million in cash (the APT acquisition). APT is engaged in Jones Act trade and its primary assets consist of a fleet of five medium range Jones Act qualified product tankers, each with 330 MBbl of cargo capacity, and each operating pursuant to long-term time charters with high quality counterparties, including major integrated oil companies, major refiners and the U.S. Military Sealift Command. As of the closing date, the vessels’ time charters had an average remaining term of approximately four years, with renewal options to extend the terms by an average of two years. APT’s vessels are operated by Crowley.
SCT commissioned the construction of four medium range Jones Act qualified product tankers, by General Dynamics’ NASSCO shipyard, each with 330 MBbl of cargo capacity and delivery dates in 2015 and 2016. The time charters for each vessel upon completion has an initial term of five years, with renewal options to extend the term by up to three years. The APT
acquisition complements and extends our existing crude oil and refined products transportation and storage business. We include the acquired assets as part of the Terminals business segment.
(5) Goldsmith Landreth Field Unit
On June 1, 2013, we acquired certain oil and gas properties, rights, and related assets in the Permian Basin of West Texas from Legado Resources LLC for an aggregate consideration of $298 million consisting of $280 million in cash and assumed liabilities of $18 million (including $12 million of long-term asset retirement obligations). The acquisition of the Goldsmith Landreth San Andres oil field unit includes more than 6,000 acres located in Ector County, Texas. The acquired oil field is in the early stages of CO2 flood development and includes a residual oil zone along with a classic San Andres waterflood. As part of the transaction, we obtained a long-term supply contract for up to 150 MMcf/d of CO2. The acquisition complemented our existing oil and gas producing assets in the Permian Basin, and we included the acquired assets as part of the CO2 business segment.
(6) Copano
Effective May 1, 2013, we acquired all of Copano’s outstanding units for a total purchase price of approximately $5.2 billion (including assumed debt and all other assumed liabilities). The transaction was a 100% unit for unit transaction with an exchange ratio of 0.4563 of KMP’s common units for each Copano common unit. Due to the fact that our acquisition included the remaining 50% interest in Eagle Ford that we did not already own, we remeasured the carrying value ($146 million) of our existing 50% equity investment in Eagle Ford to its fair value ($704 million) as of the May 1, 2013 acquisition date. As a resultdate of this remeasurement, we recognized a $558 million non-cash gain and we reported this gain within “Gain on remeasurement of previously held equity investments to fair value” in our accompanying consolidated statement of income for the year ended December 31, 2013.
Pro Forma Information
Pro forma information regarding consolidated income statement information that assumes all of the business acquisitions we have made since January 1, 2014, including the ones listed above, had occurred as of January 1, 2014, is not materially different from the information presented in our accompanying Consolidated Statements of Income.16.4 years.
Asset Purchase and Subsequent Sale of Noncontrolling Interest
On July 15, 2015, we purchased from Shell US Gas & Power LLC (Shell) its 49% interest in a joint venture, ELC, that was in the pre-construction stage of development for liquefaction facilities at Elba Island, Georgia. The transaction was treated as an asset purchase for the net cash consideration of $185 million. TheImmediately subsequent to the purchase gives usand before the partial sale discussed below, we had full ownership and control of ELC. Therefore, weELC and prospectively changed our method of accounting for ELC from the equity method to full consolidation. Shell remains subscribed to 100% of the liquefaction capacity.
Effective February 28, 2017, we sold a 49% partnership interest in ELC to investment funds managed by EIG Global Energy Partners (EIG). We continue to own a 51% controlling interest in and operate ELC. Under the terms of ELC’s limited liability company agreement, we are responsible for placing in service and operating certain supply pipelines and terminal facilities that support the operations of ELC and which are wholly owned by us. In certain limited circumstances which are not expected to occur, EIG has the right to relinquish its interest in ELC and redeem its capital account.
As a result of these contingencies, the sale proceeds of $386 million, and subsequent EIG contributions, have been recorded as a deferred credit within “Other long-term liabilities and deferred credits” on our consolidated balance sheet as of December 31, 2017. EIG is not entitled to any specified return on its capital. Once these contingencies expire, EIG’s capital account will be reflected in Noncontrolling interests on our consolidated balance sheet.
Investment Acquisition
On December 10, 2015, we and Brookfield Infrastructure Partners L.P. (Brookfield) acquired from Myria Holdings, Inc. the 53% equity interest in NGPL Holdings LLC not previously owned by us and Brookfield, increasing our ownership to 50% with Brookfield owning the remaining 50%. We paid $136 million for our additional 30% interest in NGPL Holdings LLC. See Note 7 “Investments” for additional information regarding our equity interests in Kinder Morgan NGPL Holdings LLC.
Investment Divestiture
Sale of Approximate 30% Interest in Canadian Business
Effective March 14, 2013, we sold bothOn May 30, 2017, our one-third ownershipindirectly owned subsidiary, KML, completed an IPO of 102,942,000 restricted voting shares listed on the Toronto Stock Exchange at a price to the public of $17.00 per restricted voting share for total gross proceeds of approximately C$1,750 million (US$1,299 million). The net proceeds from the IPO were used by KML to indirectly acquire from us an approximate 30% interest in a limited partnership that holds our Canadian business while we retained the Express pipeline systemremaining 70% interest. We used the proceeds from KML’s IPO to pay down debt.
Subsequent to the IPO, we retained control of KML and the limited partnership, and as a result, they remain consolidated in our subordinated debenture investmentconsolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in Expressour consolidated statements of stockholders’ equity and consolidated balance sheets. Earnings attributable to Spectra Energy Corp. With respectthe public ownership of KML are presented in “Net (income) loss attributable to this sale, duringnoncontrolling interests” in our consolidated statements of income for the periods presented after May 30, 2017.
The net proceeds received of $1,245 million are presented as “Contributions from noncontrolling interests - net proceeds from KML IPO” on our consolidated statement of cash flows for the year ended December 31, 2013,2017. Because we reportedretained control of KML subsequent to the IPO, the $314 million adjustment made to “Additional paid-in capital” on our consolidated statement of stockholders equity for the year ended December 31, 2017 represents the difference between our book value prior to the sale and our share of book value in KML’s net assets after the sale. The impact of the IPO resulted in a $166 million deferred income tax adjustment. At the date of the IPO, $765 million was attributed to the KML public shareholders to reflect their proportionate ownership percentage in the net assets of KML acquired from us and is included in “Noncontrolling interests” on our consolidated statement of stockholders equity. The above amounts recorded to “Additional paid-in capital” and “Noncontrolling interests” are net of IPO fees.
In addition, the amount recorded to “Noncontrolling interests” at the date of the IPO was reduced by $81 million primarily associated with the allocation of currency translation adjustments from “Accumulated other comprehensive loss” to “Noncontrolling interests.”
The portion of the Canadian business operations that we sold to the public on May 30, 2017 represented Canadian assets that are included in our Kinder Morgan Canada, Terminals and Product Pipelines business segments and include (i) the Trans Mountain pipeline system; (ii) the Canadian Cochin pipeline system; (iii) the Puget Sound pipeline system; (iv) the Jet Fuel pipeline system; and (v) terminal facilities located in Western Canada. In January 2018, KML completed the registration of its restricted voting shares pursuant to Section 12(g) of the United States Securities Exchange Act of 1934 (the “Exchange Act”) and KML is now subject to the reporting requirements of Section 13(a) of the Exchange Act.
In conjunction with the IPO, Kinder Morgan Canada Limited Partnership (KMC LP) and Kinder Morgan Canada GP Inc. (KMC GP) were formed to hold our Canadian business. We have determined that KMC LP is a variable interest entity because a simple majority or lower threshold of the limited partnership interests do not possess substantive “kick-out rights” (i.e., the right to remove the general partner or to dissolve (liquidate) the entity without cause) or substantive participation rights. We have also determined KMC GP is the primary beneficiary because it has the power to direct the activities that most significantly impact KMC LP’s performance, the right to receive benefits and the obligation to absorb losses, that could be significant to KMC LP. As a result, KMC GP consolidates KMC LP. KMC GP is a wholly owned subsidiary of KML, which is indirectly controlled by us through our 100% interest in KML’s special voting shares that represent approximately 70% of KML’s total voting shares (comprised of restricted voting shares and special voting shares). Consequently, we consolidate KML and the variable interest entity, KMC LP, in our consolidated financial statements.
The following table shows the carrying amount and classification of KMC LP’s assets and liabilities in our consolidated balance sheet (in millions):
|
| | | | |
| | | December 31, 2017 |
| Assets | | |
| Total current assets | | $ | 270 |
|
| Property, plant and equipment, net | | 2,956 |
|
| Total goodwill, deferred charges and other assets | | 322 |
|
| Total assets | | $ | 3,548 |
|
| Liabilities | | |
| Current portion of debt | | $ | — |
|
| Total other current liabilities | | 236 |
|
| Long-term debt, excluding current maturities | | — |
|
| Total other long-term liabilities and deferred credits | | 414 |
|
| Total liabilities | | $ | 650 |
|
We receive distributions from KMC LP through our indirectly owned limited partnership interests in KMC LP, but otherwise the assets of KMC LP cannot be used to settle our obligations other than those of KML. Our subsidiaries that are the direct owners of our limited partnership interests in KMC LP have guaranteed the obligations of KMC LP’s wholly owned subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, under the Credit Facility (see Note 9 “Debt”), but recourse in respect of such guarantee is limited solely to the limited partnership interests of KMC LP held by such subsidiaries and any proceeds thereof. Additionally, in connection with the Credit Facility, we entered into an Equity Nomination and Support Agreement whereby, among other things, we commit to contribute or cause to be contributed at the time of each drawdown on the construction credit facility or the contingent credit facility either equity or subordinated debt to Kinder Morgan Cochin ULC in an amount sufficient to cause the outstanding indebtedness under the credit facilities and any other funded debt for the TMEP not to exceed 60% of the total project costs for the project as projected over the six month period following the date of such drawdown. Other than such guarantees and the Equity Nomination and Support Agreement, we do not guarantee the debt, commercial paper or other similar commitments of KMC LP or any of its subsidiaries, and the obligations of KMC LP may only be settled using the assets of KMC LP. KMC LP does not guarantee the debt or other similar commitments of KMI.
Terminals Asset Sale
In October 2016, we entered into a definitive agreement to sell several bulk terminals to an affiliate of Watco Companies, LLC for approximately $100 million. The terminals are predominantly located along the inland river system and handle mostly coal and steel products, and are included within our Terminals business segment. The sale of eight of the locations closed in the fourth quarter of 2016, for which we received $37 million of the total consideration, and the balance of this transaction, which included an additional eleven locations, closed in the second quarter of 2017 as certain conditions were satisfied. As a result of this transaction, we recognized a pre-tax loss of $81 million, including a $7 million reduction of goodwill, which is included within “Loss on impairments and divestitures, net” on our accompanying consolidated statement of cash flows $402income for the year ended December 31, 2016, and we classified $61 million as “Proceedsheld for sale for the remaining locations which is included within “Other current assets” on our accompanying consolidated balance sheet at December 31, 2016.
Sale of Equity Interest in SNG
On September 1, 2016, we completed the sale of a 50% interest in our SNG natural gas pipeline system to The Southern Company (Southern Company), receiving proceeds of $1.4 billion, and the formation of a joint venture, which includes our remaining 50% interest in SNG. We used the proceeds from salesthe sale to reduce outstanding debt. We recognized a pre-tax loss of assets$84 million on the sale of our interest in SNG which is included within “Loss on impairments and investments” and withindivestitures, net” on the accompanying consolidated statement of income for the year ended December 31, 2016. As a combined $224 million pre-tax gain as “Gain on saleresult of investments in Express pipeline system” and $84 million of expense within “Income Tax Expense.”
Subsequent Event of Terminal Acquisition From and Joint Venture With BP
On February 1, 2016, we completed the acquisition of 15 products terminals and associated infrastructure from BP for $350 million. In conjunction with this transaction, we and BP formedno longer hold a joint venture, with an equity ownershipcontrolling interest in SNG or Bear Creek Storage Company, LLC (Bear Creek) (50% of 75%
and 25%, respectively. We contributed 14 of the acquired terminals to the joint venture, which we will operate, and the remaining terminal is solely owned by us. Of the acquired assets, 10 terminals are includedSNG) and, as such, we now account for our remaining equity interests in our Terminals business segmentSNG and 5 terminals are included in our Products Pipelines business segment.Bear Creek as equity investments.
4. Impairments and DisposalsLosses on Divestitures
During the years ended December 31, 2017, 2016, and 2015, we recorded impairments of certain equity investments, long-lived assets, and intangible assets, and net losses on divestitures totaling $172 million, $1,013 million, and $2,125 million, respectively. During 2015 and 2016, and to a lesser degree in 2017, a sustained lower commodity price environment, and negative outlook for certain long-term transportation contracts, led us to cancel certain construction projects, divest of certain assets, write-down certain assets and investments to fair value. In addition, an interim goodwill impairment test was performed during the fourth quarter of 2015 resulting in a partial impairment of goodwill in our Natural Gas Pipelines Non-Regulated reporting unit of approximately $1,150 million. See Note 8 “Goodwill” for further information.
These impairments were driven by market conditions that existed at the time and required management to estimate the fair value of these assets. The estimates of fair value are based on Level 3 valuation estimates using industry standard income approach valuation methodologies which include assumptions primarily involving management’s significant judgments and estimates with respect to general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. In certain cases, management’s decisions to dispose of certain assets may trigger an impairment. We typically use discounted cash flow analyses to determine the fair value of our assets. We may probability weight various forecasted cash flow scenarios utilized in the analysis as we consider the possible outcomes. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular asset.
We may identify additional triggering events requiring future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill. Because certain of our assets, including some equity investments and oil and gas producing properties, have been written down to fair value, any deterioration in fair value relative to our carrying value increases the likelihood of further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to be not fully recoverable.
We recognized the following non-cash pre-tax impairment charges and losses (gains) on disposalsdivestitures of assets (in millions):
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Natural Gas Pipelines | | | | | |
| Impairment of goodwill | $ | 1,150 |
| | $ | — |
| | $ | — |
|
| Impairments of long-lived assets(a) | 79 |
| | — |
| | — |
|
| Losses (gains) on disposals of long-lived assets | 43 |
| | 5 |
| | (28 | ) |
| Impairment of equity investments(b) | 26 |
| | — |
| | 65 |
|
CO2 | | | | | |
| Impairments of long-lived assets(c) | 606 |
| | 243 |
| | — |
|
| Impairment at equity investee(d) | 26 |
| | — |
| | — |
|
| Terminals | | | | | |
| Impairments of long-lived assets(e) | 188 |
| | — |
| | — |
|
| Losses (gains) on disposals of long-lived assets | 3 |
| | 29 |
| | (73 | ) |
| Impairment of equity investments(e) | 4 |
| | — |
| | — |
|
| | | | | | |
| Other (gains) losses on disposals of long-lived assets | — |
| | (3 | ) | | 3 |
|
| Total losses (gains) on impairments and disposals | $ | 2,125 |
| | $ | 274 |
| | $ | (33 | ) |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Natural Gas Pipelines | | | | | |
| Impairment of goodwill | $ | — |
| | $ | — |
| | $ | 1,150 |
|
| Impairments of long-lived assets(a) | 30 |
| | 106 |
| | 79 |
|
| Losses on divestitures of long-lived assets(b) | — |
| | 94 |
| | 43 |
|
| Impairments of equity investments(c) | 150 |
| | 606 |
| | 26 |
|
| Impairments at equity investees(d) | 10 |
| | 7 |
| | — |
|
CO2 | | | | | |
| Impairments of long-lived assets(e) | (1 | ) | | 20 |
| | 606 |
|
| Gains on divestitures of long-lived assets | — |
| | (1 | ) | | — |
|
| Impairments at equity investee(d) | (4 | ) | | 9 |
| | 26 |
|
| Terminals | | | | | |
| Impairments of long-lived assets(f) | 3 |
| | 19 |
| | 188 |
|
| (Gains) losses on divestitures of long-lived assets(g) | (18 | ) | | 80 |
| | 3 |
|
| Losses on impairments and divestitures of equity investments, net | — |
| | 16 |
| | 4 |
|
| Products Pipelines | | | | | |
| Impairments of long-lived assets(h) | — |
| | 66 |
| | — |
|
| Losses (gains) on divestitures of long-lived assets | — |
| | 10 |
| | 1 |
|
| Gain on divestiture of equity investment | — |
| | (12 | ) | | — |
|
| | | | | | |
| Other losses (gains) on divestitures of long-lived assets | 2 |
| | (7 | ) | | (1 | ) |
| Pre-tax losses on impairments and divestitures, net | $ | 172 |
| | $ | 1,013 |
| | $ | 2,125 |
|
_______
(a) Represents2017 amount represents the impairment of our Colden storage facility, of which $3 million is included in “Costs of sales” on our accompanying consolidated statement of income. 2016 amount represents the project write-off of our portion of the Northeast Energy Direct (NED) Market project. 2015 amount represents $47 million and $32 million of project write-offs in our non-regulated midstream and regulated natural gas pipelines assets, respectively.
(b) 2016 amount primarily relates to our sale of a 50% interest in SNG.
(c) 2017 amount represents the impairment of our investment in FEP. 2016 amount includes a $350 million impairment of our investment in MEP and a $250 million impairment of our investment in Ruby. 2015 amount is primarily related to an impairment of an investment in a gathering and processing asset in OklahomaOklahoma.
(d) Amounts represent losses on impairments recorded by equity investees and the 2013 amount is related to an investmentare included in “Earnings from equity investments” on our regulated natural gas pipelines.accompanying consolidated statements of income.
(c)(e) 2015 amount includes (i) $399 million related to oil and gas properties and (ii) $207 million related to the certain CO2 source and transportation project write-offs. 2014 amount is primarily related to oil and gas properties.
(d) 2015 amount is a loss on impairment recorded by an investee and included in “Earnings from equity investments” in our accompanying consolidated statement of income.
(e)(f) 2015 amount is primarily related to certain terminals with significant coal operations, including a $175 million impairment ($84 million net after-tax impact to common stockholders) of a terminal facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer in February 2016.
(g) 2017 amount includes a $23 million gain related to the sale of a 40% membership interest in the Deeprock Development joint venture. 2016 amount primarily relates to the sale of 20 bulk terminals that handle mostly coal and steel products, predominately located along the inland river system.
Impairment of Goodwill(h) 2016 amount represents project write-offs associated with the canceled Palmetto project.
Due to recent events and conditions, interim goodwill impairment testing was performed during December 2015, which resulted in a partial impairment of goodwill in our Natural Gas Pipelines Non-Regulated reporting unit of approximately $1,150 million. See Note 8 for further information.
Impairments of Long-lived Assets
During 2015, the sustained deterioration in the long-term outlook for commodity prices was a triggering event requiring us to perform impairment testing of our assets that are sensitive to such commodity prices. The impairment testing of our long-lived assets was based upon a two-step process as prescribed in the accounting standards.
Step one was performed on each of our oil and gas producing properties and involved a determination as to whether the property’s net book value is expected to be recovered from the estimated undiscounted future cash flows for each respective property. To compute estimated future cash flows, we used our independent reserve engineers’ estimates of proved reserves, along with our internally developed estimates of probable reserves to develop a long-range plan. Proved reserves are those reserves that our independent reserve engineers have determined are “reasonably certain” to be produced as defined by SEC
guidance. Reasonable certainty implies a high degree of confidence, of at least a 90% probability that quantities will equal or exceed the estimate of proved reserves. Probable reserves are those quantities that we have identified in our long range plan that are in excess of our independent reserve engineers’ estimates of proved reserves and meet the SEC definition of probable reserves. Probable reserves are defined as reserves that are as “likely as not” to be recoverable with a probability of at least 50% or greater. These estimates of proved and probable reserves are based upon historical performance along with adjustments for expected oil and gas field development. In calculating future cash flows, management utilized estimates of commodity prices based on forward curves. We also included the impact of our existing oil and gas sales contracts to determine the applicable net crude oil and natural gas pricing for each property. Operating expenses were determined based on estimated future fixed and variable field production requirements, and capital expenditures were based on currently authorized projects or economically viable future projects that have been identified for each of our properties. Risk factors were applied to each property’s probable reserves based on its operational history or the success of similar properties. Based on the results of the step one test, we determined that certain properties’ estimated undiscounted future cash flows were less than their respective carrying values.
For those properties that failed the impairment test’s first step, we then made a fair market value assessment using a discounted cash flow analysis as well as an estimate of fair value based upon recent sales prices of comparable properties. Our cash flow analysis was discounted utilizing an estimated weighted average cost of capital of 12%, representing our estimate of the risk-adjusted discount rate that would be used by market participants. We consider the inputs for our impairment calculations to be Level 3 inputs in the fair value hierarchy. Based on these results, we recognized $399 million of impairments on those properties where the carrying value exceeded its estimated fair market value in the period that such a determination was made.
In addition, during 2015 we recorded a $207 million impairment in our CO2 business segment for certain source and transportation assets. Since we expect CO2 demand to remain flat for the foreseeable future under the current commodity price environment, we deferred certain source and transportation growth projects beyond our five-year capital expenditures backlog. The extended deferral period necessitated a review of the recoverability of the net book values of these growth projects, resulting in a full impairment of $207 million.
During the year ended December 31, 2015, similar impairment analyses were performed in our other segments resulting in impairments of long-lived assets of $79 million and $188 million, respectively, in our Natural Gas Pipelines and Terminals business segments. These impairments resulted from certain capital projects that were canceled or postponed as well as in our Terminals segment for which certain facilities were impaired as a result of management’s re-evaluation of the estimated future cash flows expected to be generated at our coal handling assets.
In the current commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill. Because certain of our oil and gas producing properties have been written down to fair value, any deterioration in fair value that exceeds the rate of depletion of the related asset would result in further impairments. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future cash flow estimates, future volume expectations, current and future commodity prices, management’s decisions to dispose of certain assets and estimates of the fair values of our reporting units, as well as general economic conditions and the related demand for products handled or transported by our assets. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.
5. Income Taxes
The components of “Income from Continuing Operations Before Income Taxes” are as follows (in millions): | | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| U.S. | $ | 611 |
| | $ | 2,941 |
| | $ | 3,107 |
| $ | 1,976 |
| | $ | 1,466 |
| | $ | 611 |
|
| Foreign | 161 |
| | 150 |
| | 331 |
| 185 |
| | 172 |
| | 161 |
|
| Total Income from Continuing Operations Before Income Taxes | $ | 772 |
| | $ | 3,091 |
| | $ | 3,438 |
| |
| Total Income Before Income Taxes | | $ | 2,161 |
| | $ | 1,638 |
| | $ | 772 |
|
Components of the income tax provision applicable to continuing operations for federal, foreign and state taxes are as follows (in millions):
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Current tax expense (benefit) | | | | | | | | | | |
| Federal | $ | (125 | ) | | $ | (16 | ) | | $ | 57 |
| $ | (137 | ) | | $ | (148 | ) | | $ | (125 | ) |
| State | (7 | ) | | 36 |
| | 36 |
| (16 | ) | | (28 | ) | | (7 | ) |
| Foreign | 4 |
| | 13 |
| | 9 |
| 18 |
| | 6 |
| | 4 |
|
| Total | (128 | ) | | 33 |
| | 102 |
| (135 | ) | | (170 | ) | | (128 | ) |
| Deferred tax expense (benefit) | |
| | |
| | |
| |
| | |
| | |
|
| Federal | 653 |
| | 572 |
| | 612 |
| 2,022 |
| | 998 |
| | 653 |
|
| State | (4 | ) | | 14 |
| | — |
| 4 |
| | 51 |
| | (4 | ) |
| Foreign | 43 |
| | 29 |
| | 28 |
| 47 |
| | 38 |
| | 43 |
|
| Total | 692 |
| | 615 |
| | 640 |
| 2,073 |
| | 1,087 |
| | 692 |
|
| Total tax provision | $ | 564 |
| | $ | 648 |
| | $ | 742 |
| $ | 1,938 |
| | $ | 917 |
| | $ | 564 |
|
We are subject to taxation in Canada and Mexico. In Canada we recognized income tax expense of $58 million, $38 million and $46 million at December 31, 2017, 2016, and 2015, respectively. In Mexico we recognized income tax expense of $7 million, $6 million and $1 million at December 31, 2017, 2016, and 2015, respectively.
The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows (in millions, except percentages):
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Federal income tax | $ | 271 |
| | 35.0 | % | | $ | 1,082 |
| | 35.0 | % | | $ | 1,203 |
| | 35.0 | % | $ | 756 |
| | 35.0 | % | | $ | 573 |
| | 35.0 | % | | $ | 271 |
| | 35.0 | % |
| Increase (decrease) as a result of: | |
| | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
|
| State deferred tax rate change | (24 | ) | | (3.1 | )% | | — |
| | — | % | | (21 | ) | | (0.6 | )% | 10 |
| | 0.5 | % | | 11 |
| | 0.7 | % | | (24 | ) | | (3.1 | )% |
| Taxes on foreign earnings | 26 |
| | 3.5 | % | | 40 |
| | 1.3 | % | | 112 |
| | 3.3 | % | |
| Net effects of consolidating KMP and EPB and other noncontrolling interests | 15 |
| | 2.0 | % | | (433 | ) | | (14.0 | )% | | (488 | ) | | (14.2 | )% | |
| Taxes on foreign earnings, net of federal benefit | | 42 |
| | 1.9 | % | | 28 |
| | 1.7 | % | | 26 |
| | 3.5 | % |
| Net effects of noncontrolling interests | | (14 | ) | | (0.7 | )% | | (4 | ) | | (0.3 | )% | | 15 |
| | 2.0 | % |
| State income tax, net of federal benefit | 12 |
| | 1.5 | % | | 37 |
| | 1.2 | % | | 45 |
| | 1.3 | % | 38 |
| | 1.8 | % | | 26 |
| | 1.6 | % | | 12 |
| | 1.5 | % |
| Dividend received deduction | (51 | ) | | (6.6 | )% | | (50 | ) | | (1.6 | )% | | (54 | ) | | (1.6 | )% | (56 | ) | | (2.6 | )% | | (48 | ) | | (2.9 | )% | | (51 | ) | | (6.6 | )% |
| Adjustments to uncertain tax positions | (14 | ) | | (1.9 | )% | | (5 | ) | | (0.2 | )% | | (87 | ) | | (2.5 | )% | (12 | ) | | (0.6 | )% | | (23 | ) | | (1.4 | )% | | (14 | ) | | (1.9 | )% |
| Valuation allowance on investment in NGPL | — |
| | — | % | | 61 |
| | 2.0 | % | | — |
| | — | % | |
| Disposition of certain international holdings | — |
| | — | % | | (112 | ) | | (3.6 | )% | | — |
| | — | % | |
| Nondeductible goodwill impairment | 323 |
| | 41.7 | % | | — |
| | — | % | | — |
| | — | % | |
| Valuation allowance on investment and tax credits | | 13 |
| | 0.6 | % | | 34 |
| | 2.1 | % | | — |
| | — | % |
| Impact of the 2017 Tax Reform | | 1,240 |
| | 57.4 | % | | — |
| | — | % | | — |
| | — | % |
| Nondeductible goodwill | | — |
| | — | % | | 301 |
| | 18.5 | % | | 323 |
| | 41.7 | % |
| General business credit | | (95 | ) | | (4.4 | )% | | — |
| | — | % | | — |
| | — | % |
| Other | 6 |
| | 0.8 | % | | 28 |
| | 0.9 | % | | 32 |
| | 0.9 | % | 16 |
| | 0.8 | % | | 19 |
| | 1.1 | % | | 6 |
| | 0.8 | % |
| Total | $ | 564 |
| | 72.9 | % | | $ | 648 |
| | 21.0 | % | | $ | 742 |
| | 21.6 | % | $ | 1,938 |
| | 89.7 | % | | $ | 917 |
| | 56.1 | % | | $ | 564 |
| | 72.9 | % |
Deferred tax assets and liabilities result from the following (in millions):
| | | | December 31, | December 31, |
| | 2015 | | 2014 | 2017 | | 2016 |
| Deferred tax assets | | | | | | |
| Employee benefits | $ | 394 |
| | $ | 329 |
| $ | 251 |
| | $ | 401 |
|
| Accrued expenses | 129 |
| | 123 |
| 73 |
| | 118 |
|
| Net operating loss, capital loss, tax credit carryforwards | 1,344 |
| | 778 |
| |
| Net operating loss, capital loss and tax credit carryforwards | | 1,113 |
| | 1,307 |
|
| Derivative instruments and interest rate and currency swaps | 45 |
| | 43 |
| 12 |
| | 22 |
|
| Debt fair value adjustment | 110 |
| | 102 |
| 37 |
| | 74 |
|
| Investments | 3,607 |
| | 4,858 |
| 968 |
| | 2,804 |
|
| Other | 3 |
| | 31 |
| 6 |
| | 14 |
|
| Valuation allowances | (152 | ) | | (154 | ) | (171 | ) | | (184 | ) |
| Total deferred tax assets | 5,480 |
| | 6,110 |
| 2,289 |
| | 4,556 |
|
| Deferred tax liabilities | |
| | |
| |
| | |
|
| Property, plant and equipment | 143 |
| | 373 |
| 225 |
| | 177 |
|
| Other | 14 |
| | 30 |
| 20 |
| | 27 |
|
| Total deferred tax liabilities | 157 |
| | 403 |
| 245 |
| | 204 |
|
| Net deferred tax assets | $ | 5,323 |
| | $ | 5,707 |
| $ | 2,044 |
| | $ | 4,352 |
|
| | | | | | | |
| Current deferred tax asset | $ | — |
| | $ | 56 |
| |
| Non-current deferred tax assets | 5,323 |
| | 5,651 |
| |
| Net deferred tax assets | $ | 5,323 |
| | $ | 5,707 |
| |
On November 20, 2015, the FASB issued Accounting Standards Update (ASU) 2015-17, “Balance Sheet Classification of Deferred Taxes,” as part of the FASB’s simplification initiative to reduce complexity in accounting standards. The new guidance requires that all deferred tax assets and liabilities for each jurisdiction, along with any valuation allowance, be classified as noncurrent on the balance sheet. The new guidance is effective for public businesses in fiscal years beginning after December 15, 2016. However, as early adoption is permitted as of the beginning of an interim or annual reporting period in which the ASU 2015-17 was issued, we decided to apply the new standard for the December 31, 2015 period. As the guidance allows for prospective application of the new standard, prior period financial statements have not been retrospectively adjusted.
Deferred Tax Assets and Valuation Allowances: The step-up in tax basis from the Merger Transactionsmerger transactions that occurred in November 2014 resulted in a deferred tax asset, primarily related to our investments (primarilyinvestment in KMP) of $3.6 billion and $4.9 billion at December 31, 2015 and 2014, respectively.KMP. As book earnings from our investment in KMP are projected to exceed taxable income (primarily as a result of the partnership’s tax depreciation in excess of book depreciation), the deferred tax asset related to our investment in KMP is expected to be fully realized.
We recordeddecreased our valuation allowances in 2017 by $13 million, primarily due to $4 million release for capital loss carryover as a full valuation allowanceresult of $61the 2016 return to provision adjustment, $5 million against the deferred tax asset at December 31, 2014release for foreign operating losses and $24 million reduction related to our investment in NGPL as we concluded it was no longer realizable.a result of the reduction of federal tax rate, partially offset by $18 million for state net operating losses and $2 million for foreign tax credits.
We have deferred tax assets of $1,005$935 million related to net operating loss carryovers, $339$178 million related to general business, alternative minimum and foreign tax credits and $133 million of valuation allowances related to these deferred tax assets at December 31, 2017. As of December 31, 2016, we had deferred tax assets of $1,128 million related to net operating loss carryovers, $175 million related to alternative minimum and foreign tax credits, and $91 million of valuation allowances related to deferred tax assets at December 31, 2015. As of December 31, 2014, we had deferred tax assets of $466$4 million related to net operatingcapital loss carryovers $312 million related to alternative minimum and foreign tax credits, and valuation allowances related to these deferred tax assets of $93$123 million. We expect to generate taxable income beginning in 2019 and utilize all federal net operating loss carryforwards and tax credits beginning in 2022.
Our alternative minimum tax credit carryforwards decreased by $143 million in 2017 as a result of our decision to elect to forgo bonus depreciation on property placed in service in that year. Code Section 168(k)(4) allows for corporate taxpayers with minimum tax credit carryforwards to forgo bonus depreciation and accelerate their use of the endcredits to reduce tax liability in that same tax year if the amount of 2023.the allowable credit exceeds the taxpayer’s tax liability. The corporation may receive a cash refund of the excess notwithstanding that it may not otherwise be paying taxes. We received an income tax refund of $144 million in 2017.
The tax impact of ASU 2016-09, which was adopted and effective January 1, 2017, resulted in $8 million of deferred tax assets being recorded through a cumulative-effect adjustment to our retained deficit. The previously unrecorded deferred tax asset is related to net operating loss carryovers as a result of the delayed recognition of a windfall tax benefit related to share-based compensation. Post-adoption the excess tax benefits or deficiencies are recognized for income tax purposes in the period in which they occur through the income statement.
Expiration Periods for Deferred Tax Assets: As of December 31, 2015,2017, we have U.S. federal net operating loss carryforwards of $2.4$3.4 billion, which will expire from 2018 - 2035;2037; state losses of $3.1$3.2 billion which will expire from 20152018 - 2035;2037; and foreign losses of $154$134 million of which approximately $115 million carries over indefinitely and $39 million expireswill expire from 20282029 - 2035.2036. We also have $312$8 million of federal alternative minimum tax credits which do not expire; $147 million of general business credits which will expire from 2018 - 2027; and approximately $26$21 million of foreign tax credits, the majority of which will expire from 20162018 - 2025.2023. Use of a portion of our U.S. federal carryforwards is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation rules of Internal Revenue Service regulations. If certain substantial changes in our ownership occur, there would be an annual limitation on the amount of carryforwards that could be utilized.
Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.
A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows (in millions):
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Balance at beginning of period | $ | 189 |
| | $ | 209 |
| | $ | 269 |
| $ | 122 |
| | $ | 148 |
| | $ | 189 |
|
| Uncertain tax positions of EP | — |
| | — |
| | 4 |
| |
| Subtotal | 189 |
| | 209 |
| | 273 |
| |
| Additions based on current year tax positions | 4 |
| | 12 |
| | 11 |
| 3 |
| | 3 |
| | 4 |
|
| Additions based on prior year tax positions | — |
| | — |
| | 26 |
| — |
| | 7 |
| | — |
|
| Reductions based on prior year tax positions | (6 | ) | | (3 | ) | | — |
| — |
| | (1 | ) | | (6 | ) |
| Reductions based on settlements with taxing authority | (25 | ) | | (24 | ) | | (86 | ) | (22 | ) | | (26 | ) | | (25 | ) |
| Reductions due to lapse in statute of limitations | (14 | ) | | (5 | ) | | (15 | ) | (2 | ) | | (9 | ) | | (14 | ) |
| Impact of the 2017 Tax Reform | | (4 | ) | | — |
| | — |
|
| Balance at end of period | $ | 148 |
| | $ | 189 |
| | $ | 209 |
| $ | 97 |
| | $ | 122 |
| | $ | 148 |
|
We recognize interest and/or penalties related to income tax matters in income tax expense. We recognized a tax benefit of $9 million, expense of $2 million and a benefit of $4 million at December 31, 2017, 2016, and 2015, respectively. As of December 31, 20152017, 2014,2016, and 2013,2015, we had $2419 million, $28 million and $29$24 million, respectively, of accrued interestinterest. We
had no accrued penalties as of both December 31, 2017 and $2 million, $2 million2016 and $2 million respectively, in accrued penalties.penalties as of December 31, 2015. All of the $14897 million of unrecognized tax benefits, if recognized, would affect our effective tax rate in future periods. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by approximately $56 million during the next year to approximately $14391 million., primarily due to lapses in statute of limitations partially offset by additions for state filing positions taken in prior years.
We are subject to taxation, and have tax years open to examination for the periods 2011-20142011-2016 in the U.S., 2002-20142005-2016 in various states and 2007-20142007-2016 in various foreign jurisdictions.
Impact of 2017 Tax Reform
On December 22, 2017, the U.S. enacted the 2017 Tax Reform. Among the many provisions included in the 2017 Tax Reform is a provision to reduce the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018.
As of December 31, 2017, we had deferred tax assets related to our net operating loss carryforwards and tax credits, in addition to tax basis in excess of accounting basis primarily related to our investment in KMP. Prior to the 2017 Tax Reform, the value of these deferred tax assets was recorded at the previous income tax rate of 35%, which represented their expected future benefit to us. As a result of the 2017 Tax Reform, the future benefit of these deferred tax assets was re-measured at the new income tax rate of 21% and we recorded an approximate $1,240 million provisional non-cash adjustment for the year ended December 31, 2017. We determined the effects of the rate change using our best estimate of temporary book-to-tax differences. Upon final analysis and remeasurement of our deferred tax balances, the December 31, 2017 adjustment we recorded to reflect the change in corporate income tax rates may need to be adjusted in subsequent periods.
In addition, the 2017 Tax Reform will require a mandatory deemed repatriation of post-1986 undistributed foreign earnings and profits. As of December 31, 2017, we have recorded a provisional amount for this 2017 Tax Reform provision and we are continuing to finalize earnings and profits used in this calculation as well assess other 2017 Tax Reform impacts to complete our analysis on this provision. However, we do not expect this provision of the 2017 Tax Reform to be material to us.
The income tax rate change in the 2017 Tax Reform had an impact not only on our corporate income taxes but also resulted in us recording an approximate $144 million after-tax ($219 million pre-tax) provisional non-cash adjustment, including our share of equity investee provisional adjustments, related to our FERC regulated business for the year ended December 31, 2017. We have determined a reasonable estimate of its impact and recorded a provisional regulatory reserve as of December 31, 2017. However, as the impact on the regulatory rate making process is currently uncertain, we have not completed our assessment of the 2017 Tax Reform’s effect on our FERC regulated business.
As described above, we continue to assess the impact of the 2017 Tax Reform on our business in order to complete our analysis. Any adjustment to our provisional amounts will be reported in the reporting period in which any such adjustments are determined and may be material in the period in which the adjustments are made.
6. Property, Plant and Equipment, net
Classes and Depreciation
As of December 31, 20152017 and 2014,2016, our property, plant and equipment, net consisted of the following (in millions):
| | | | December 31, | December 31, |
| | 2015 | | 2014 | 2017 | | 2016 |
Pipelines (Natural gas, liquids, crude oil and CO2) | $ | 19,855 |
| | $ | 18,119 |
| $ | 20,157 |
| | $ | 19,341 |
|
Equipment (Natural gas, liquids, crude oil, CO2, and terminals) | 22,979 |
| | 21,233 |
| 24,152 |
| | 23,298 |
|
| Other(a) | 4,719 |
| | 4,484 |
| 5,570 |
| | 4,780 |
|
| Accumulated depreciation, depletion and amortization | (10,851 | ) | | (8,369 | ) | (14,175 | ) | | (12,306 | ) |
| | 36,702 |
| | 35,467 |
| 35,704 |
| | 35,113 |
|
| Land and land rights-of-way | 1,450 |
| | 1,324 |
| 1,456 |
| | 1,431 |
|
| Construction work in process | 2,395 |
| | 1,773 |
| 2,995 |
| | 2,161 |
|
| Property, plant and equipment, net | $ | 40,547 |
| | $ | 38,564 |
| $ | 40,155 |
| | $ | 38,705 |
|
_______
(a) Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and other.miscellaneous property, plant and equipment.
As of December 31, 20152017 and 2014,2016, property, plant and equipment, net included $16,08914,055 million and $15,026$12,900 million, respectively, of assets which were regulated by either the FERC or the NEB. Depreciation, depletion, and amortization expense charged against property, plant and equipment was $2,0592,022 million, $1,8621,970 million, and $1,663$2,059 million for the years ended December 31, 20152017, 20142016, and 20132015, respectively.
Asset Retirement Obligations
As of December 31, 20152017 and 20142016, we recognized asset retirement obligations in the aggregate amount of $215208 million and $192$193 million, respectively, of which $9$4 million and $7$9 million, respectively, were classified as current. The majority of our asset retirement obligations are associated with our CO2 business segment, where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors.
7. Investments
Our investments primarily consist of equity investments where we hold significant influence over investee actions and for which we apply the equity method of accounting. As of December 31, 20152017 and 20142016, our investments consisted of the following (in millions):
| | | | December 31, | December 31, |
| | 2015 | | 2014 | 2017 | | 2016 |
| Citrus Corporation | $ | 1,719 |
| | $ | 1,805 |
| $ | 1,698 |
| | $ | 1,709 |
|
| Ruby Pipeline Holding Company, L.L.C. | 1,093 |
| | 1,123 |
| |
| SNG | | 1,495 |
| | 1,505 |
|
| Ruby | | 774 |
| | 798 |
|
| NGPL Holdings LLC | | 687 |
| | 475 |
|
| Gulf LNG Holdings Group, LLC | | 461 |
| | 485 |
|
| Plantation Pipe Line Company | | 331 |
| | 333 |
|
| EagleHawk | | 314 |
| | 329 |
|
| Utopia Holding LLC | | 276 |
| | 55 |
|
| MEP | 713 |
| | 748 |
| 253 |
| | 328 |
|
| Gulf LNG Holdings Group, LLC | 516 |
| | 547 |
| |
| EagleHawk | 348 |
| | 337 |
| |
| Plantation Pipe Line Company | 327 |
| | 303 |
| |
| Red Cedar Gathering Company | | 187 |
| | 191 |
|
| Watco Companies, LLC | 201 |
| | 103 |
| 182 |
| | 180 |
|
| Red Cedar Gathering Company | 185 |
| | 184 |
| |
| Double Eagle Pipeline LLC | 158 |
| | 150 |
| 149 |
| | 151 |
|
| Kinder Morgan NGPL Holdings LLC | 153 |
| | — |
| |
| Parkway Pipeline LLC | 131 |
| | 144 |
| |
| FEP | 116 |
| | 130 |
| 112 |
| | 101 |
|
| Liberty Pipeline Group LLC | | 71 |
| | 75 |
|
| Bear Creek Storage | | 63 |
| | 61 |
|
| Sierrita Gas Pipeline LLC | | 55 |
| | 57 |
|
| Fort Union Gas Gathering L.L.C. | 50 |
| | 70 |
| 12 |
| | 25 |
|
| Sierrita Gas Pipeline LLC | 60 |
| | 63 |
| |
| Cortez Pipeline Company | — |
| | 17 |
| |
| All others | 262 |
| | 304 |
| 178 |
| | 169 |
|
| Total equity investments | 6,032 |
| | 6,028 |
| |
| Bond investments | 8 |
| | 8 |
| |
| Total investments | $ | 6,040 |
| | $ | 6,036 |
| $ | 7,298 |
| | $ | 7,027 |
|
As shown in the investment balance table above and the earnings (losses) from equity investments table below, our significant equity investments, as of December 31, 20152017 consisted of the following:
Citrus Corporation—We own a 50% interest in Citrus Corporation, the sole owner of Florida Gas Transmission Company, L.L.C. (Florida Gas). Florida Gas transports natural gas to cogeneration facilities, electric utilities, independent power producers, municipal generators, and local distribution companies through a 5,300-mile natural gas pipeline. Energy Transfer Partners L.P. operates Florida Gas and owns the remaining 50% interest;interest in Citrus;
Ruby Pipeline Holding Company, L.L.C.—SNG—We operate SNG and own a 50% interest in SNG; and Evergreen Enterprise Holdings, LLC, a subsidiary of Southern Company, owns the remaining 50% interest.
Ruby—We operate Ruby Pipeline Holding Company, L.L.C.,and own the common interest in Ruby, the sole owner of the Ruby Pipeline natural gas transmission system. Pembina Pipeline Corporation (Pembina) owns the remaining interest in Ruby in the form of a convertible preferred interest. If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby;
NGPL Holdings LLC— We operate NGPL Holdings LLC and own a 50% interest in NGPL Holdings LLC, the indirect owner of NGPL and certain affiliates, collectively referred to in this report as NGPL, a major interstate natural gas pipeline and storage system. The remaining 50% interest is owned by a subsidiary of Veresen Inc. as convertible preferred interests;
MEP—We operate and own a 50% interest in MEP, the sole owner of the Midcontinent Express natural gas pipeline system. The remaining 50% ownership interest is owned by subsidiaries of Energy Transfer Partners L.P.;
Brookfield;Gulf LNG Holdings Group, LLC—We operate Gulf LNG Holdings Group, LLC and own a 50% interest in Gulf LNG Holdings Group, LLC, the owner of a LNG receiving, storage and regasification terminal near Pascagoula, Mississippi, as well as pipeline facilities to deliver vaporized natural gas into third party pipelines for delivery into various markets around the country. The remaining 50% ownership interests are wholly and partiallyinterest is owned by a variety of investment entities, including subsidiaries of GE Financial Services and The Blackstone Group, L.P.;
BHP Billiton Petroleum (Eagle Ford) LLC, f/k/a EagleHawkLP; Warburg Pincus, LLC; Kelso and referred to in this report as EagleHawk—We own a 25% interest in EagleHawk, the sole owner of natural gasCompany; and condensate gathering systems serving the producers of the Eagle Ford shale formation. A subsidiary of BHP Billiton Petroleum operates EagleHawk and owns the remaining 75% ownership interest;Lightfoot Capital Partners, LP, which is majority owned by GE Energy Financial Services.
Plantation—We operate Plantation and own a 51.17% interest in Plantation, the sole owner of the Plantation refined petroleum products pipeline system. A subsidiary of Exxon Mobil Corporation owns the remaining interest. Each investor has an equal number of directors on Plantation’s board of directors, and board approval is required for certain corporate actions that are considered substantive participating rights; therefore, we do not control Plantation, and account for the investment under the equity method;
BHP Billiton Petroleum (Eagle Ford) LLC, (EagleHawk)—We own a 25% interest in EagleHawk, the sole owner of natural gas and condensate gathering systems serving the producers of the Eagle Ford shale formation. A subsidiary of BHP Billiton Petroleum operates EagleHawk and owns the remaining 75% ownership interest;
Utopia Holding L.L.C. — We operate Utopia Holding L.L.C. and own a 50% interest in Utopia Holding L.L.C. Riverstone Investment Group LLC owns the remaining 50% interest;
MEP—We operate MEP and own a 50% interest in MEP, the sole owner of the MEP natural gas pipeline system. The remaining 50% ownership interest is owned by subsidiaries of Energy Transfer Partners L.P.;
Red Cedar Gathering Company—We own a 49% interest in Red Cedar Gathering Company, the sole owner of the Red Cedar natural gas gathering, compression and treating system. The Southern Ute Indian Tribe owns the remaining 51% interest and serves as operator of Red Cedar;
Watco Companies, LLC—We hold a preferred and common equity investment in Watco Companies, LLC, the largest privately held short line railroad company in the U.S. We own 100,000 Class A and 50,000 Class B preferred shares and pursuant to the terms of the investment, receive priority, cumulative cash and stock distributions from the preferred shares at a rate of 3.25% and 3.00% per quarter, respectively, and participate partially in additional profit distributions at a rate equal to 0.5%0.4%. The Class A preferred shares have no conversion features and neitherNeither class holds any voting powers, but do provide us certain approval rights, including the right to appoint one of the members to Watco’s board of managers. In addition to the senior interests, we also hold approximately 26,00013,000 common equity units, which represents a 7.2% ownership that is accounted for under the equity method of accounting;
Red Cedar Gathering Company—We own a 49% interest in Red Cedar Gathering Company, the sole owner of the Red Cedar natural gas gathering, compression and treating system. The Southern Ute Indian Tribe owns the remaining 51% interest;3.2% common ownership;
Double Eagle Pipeline LLC - We own a 50% equity interest in Double Eagle Pipeline LLC. The remaining 50% interest is owned by Magellan Midstream Partners;
Kinder Morgan NGPL Holdings LLC— We operate and own a 50% interest in NGPL Holdings LLC, the indirect owner of NGPL and certain affiliates, collectively referred to in this report as NGPL, a major interstate natural gas pipeline and storage system. Effective December 10, 2015 we and Brookfield acquired from Myria Holdings, Inc. the 53% equity interest in NGPL Holdings LLC not previously owned by us and Brookfield, increasing our ownership to 50% with Brookfield owning the remaining 50%. We paid $136 million for our additional 30% interest in NGPL Holdings LLC and during December 2015 we made an additional contribution of $17 million.
Parkway Pipeline LLC —We operate and own a 50% interest in Parkway Pipeline LLC, the sole owner of the Parkway Pipeline refined petroleum products pipeline system. Valero Energy Corp. owns the remaining 50% interest;
FEP —We own a 50% interest in FEP, the sole owner of the Fayetteville Express natural gas pipeline system. Energy Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of FEP;
Liberty Pipeline Group, LLC (Liberty) —We own a 50% interest in Liberty. ETC NGL Transport, LLC, a subsidiary of Energy Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of Liberty;
Bear Creek Storage—We own a combined 75% interest in Bear Creek through: our wholly owned subsidiary’s (TGP) 50% interest and an additional 25% indirect interest through our 50% equity interest in SNG, which owns the remaining 50% interest;
Sierrita Gas Pipeline LLC — We operate Sierrita Gas Pipeline LLC and own a 35% equity interest in the Sierrita Gas Pipeline LLC. MGI Enterprises U.S. LLC, a subsidiary of PEMEX, owns 35%; and MIT Pipeline Investment Americas, Inc., a subsidiary of Mitsui & Co., Ltd, owns 30%;
Fort Union Gas Gathering LLC—We own a 37.04% equity interest in the Fort Union Gas Gathering LLC. Crestone Powder River LLC, a subsidiary of ONEOK Partners L.P., owns 37.04%; Powder River Midstream, LLC owns 11.11%; and Western Gas Wyoming, LLC owns the remaining 14.81%. Western Gas Resources, Inc. serves as operator of Fort Union Gas Gathering LLC;
Sierrita Gas Pipeline LLC — We operate and own a 35% equity interest in the Sierrita Gas Pipeline LLC. MGI Enterprises U.S. LLC, a subsidiary of PEMEX, owns 35%; and MIT Pipeline Investment Americas, Inc., a subsidiary of Mitsui & Co., Ltd, owns 30%; and
Cortez Pipeline Company—We operate and own a 50% interest in the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system. A subsidiary of Exxon Mobil Corporation owns a 37% interest and Cortez Vickers Pipeline Company owns the remaining 13% interest. | |
| • | Cortez Pipeline Company—We operate the Cortez CO2 pipeline system, and as of December 31, 2017, we owned a 52.98% interest in the Cortez Pipeline Company, the sole owner of the Cortez CO2 pipeline system. Mobil Cortez Pipeline Inc. owns 33.25%; and Cortez Vickers Pipeline Company owns the remaining 13.77%. |
Our earnings (losses) from equity investments were as follows (in millions):
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Citrus Corporation | $ | 96 |
| | $ | 97 |
| | $ | 84 |
| $ | 108 |
| | $ | 102 |
| | $ | 96 |
|
| SNG | | 77 |
| | 58 |
| | — |
|
| FEP | 55 |
| | 55 |
| | 55 |
| 53 |
| | 51 |
| | 55 |
|
| Gulf LNG Holdings Group, LLC | 49 |
| | 48 |
| | 47 |
| 47 |
| | 48 |
| | 49 |
|
| Plantation Pipe Line Company | | 46 |
| | 37 |
| | 29 |
|
| Cortez Pipeline Company(a) | | 44 |
| | 24 |
| | (3 | ) |
| Ruby | | 44 |
| | 15 |
| | 18 |
|
| MEP | 45 |
| | 45 |
| | 40 |
| 38 |
| | 40 |
| | 45 |
|
| Red Cedar Gathering Company | 26 |
| | 33 |
| | 31 |
| |
| EagleHawk | 24 |
| | (7 | ) | | 9 |
| 24 |
| | 10 |
| | 24 |
|
| Plantation Pipe Line Company | 29 |
| | 29 |
| | 35 |
| |
| Ruby Pipeline Holding Company, L.L.C. | 18 |
| | 15 |
| | (6 | ) | |
| Watco Companies, LLC | 16 |
| | 13 |
| | 13 |
| 19 |
| | 25 |
| | 16 |
|
| Red Cedar Gathering Company(b) | | 14 |
| | 24 |
| | 26 |
|
| Fort Union Gas Gathering L.L.C.(c) | | 10 |
| | 1 |
| | 16 |
|
| NGPL Holdings LLC | | 10 |
| | 12 |
| | — |
|
| Liberty Pipeline Group LLC | | 9 |
| | 11 |
| | 9 |
|
| Bear Creek Storage | | 8 |
| | 2 |
| | — |
|
| Sierrita Gas Pipeline LLC | 9 |
| | 3 |
| | — |
| 7 |
| | 7 |
| | 9 |
|
| Double Eagle Pipeline LLC | | 7 |
| | 5 |
| | 3 |
|
| Parkway Pipeline LLC | 5 |
| | 8 |
| | 1 |
| — |
| | 14 |
| | 5 |
|
| Double Eagle Pipeline LLC(a) | 3 |
| | (1 | ) | | 1 |
| |
| Cortez Pipeline Company(b) | (3 | ) | | 25 |
| | 24 |
| |
| Fort Union Gas Gathering L.L.C.(a)(c) | (4 | ) | | 16 |
| | 11 |
| |
| NGPL Holdco LLC(d) | — |
| | — |
| | (66 | ) | |
| All others | 16 |
| | 27 |
| | 48 |
| 13 |
| | 11 |
| | 17 |
|
| Total | $ | 384 |
|
| $ | 406 |
| | $ | 327 |
| |
| Total earnings from equity investments | | $ | 578 |
|
| $ | 497 |
| | $ | 414 |
|
| Amortization of excess costs | $ | (51 | ) | | $ | (45 | ) | | $ | (39 | ) | (61 | ) | | (59 | ) | | (51 | ) |
_______
| |
| (a) | 20132017, 2016 and 2015 amounts are for the period from May 1, 2013 through December 31, 2013. |
| |
(b) | 2015 amount includesinclude $(4) million, $9 million and $26 million, respectively, representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company. |
| |
(c)(b) | 20152017 amount includes a non-cash impairment chargecharges of $20$10 million (pre-tax) related to our investment. |
| |
(d)(c) | 20132016 amount includes non-cash impairment charges of $65$7 million (pre-tax) related to our investment. |
Summarized combined financial information for our significant equity investments (listed or described above) is reported below (in millions; amounts represent 100% of investee financial information):
| | | | | Year Ended December 31, | | Year Ended December 31, |
| Income Statement | | 2015 | | 2014 | | 2013 | | 2017 | | 2016 | | 2015 |
| Revenues | | $ | 3,857 |
| | $ | 3,829 |
| | $ | 3,615 |
| | $ | 4,703 |
| | $ | 4,084 |
| | $ | 3,857 |
|
| Costs and expenses | | 3,408 |
| | 3,063 |
| | 2,803 |
| | 3,398 |
| | 3,056 |
| | 3,408 |
|
| Net income (loss) | | $ | 449 |
| | $ | 766 |
| | $ | 812 |
| |
| Net income | | | $ | 1,305 |
| | $ | 1,028 |
| | $ | 449 |
|
| | | | | December 31, | | December 31, |
| Balance Sheet | | 2015 | | 2014 | | 2017 | | 2016 |
| Current assets | | $ | 811 |
| | $ | 943 |
| | $ | 956 |
| | $ | 892 |
|
| Non-current assets | | 19,745 |
| | 20,630 |
| | 22,344 |
| | 22,170 |
|
| Current liabilities | | 1,009 |
| | 1,643 |
| | 1,241 |
| | 3,532 |
|
| Non-current liabilities | | 11,227 |
| | 10,841 |
| | 10,605 |
| | 9,187 |
|
| Partners’/owners’ equity | | 8,320 |
| | 9,089 |
| | 11,454 |
| | 10,343 |
|
8. Goodwill
Changes in the amounts of our goodwill for each of the years ended December 31, 20152017 and 20142016 are summarized by reporting unit as follows (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Natural Gas Pipelines Regulated | | Natural Gas Pipelines Non-Regulated | | CO2 | | Products Pipelines | | Products Pipelines Terminals | | Terminals | | Kinder Morgan Canada | | Total |
| Historical Goodwill | $ | 17,527 |
| | $ | 5,637 |
| | $ | 1,528 |
| | $ | 1,908 |
| | $ | 221 |
| | $ | 1,486 |
| | $ | 610 |
| | $ | 28,917 |
|
| Accumulated impairment losses | (1,643 | ) | | (447 | ) | | — |
| | (1,197 | ) | | (70 | ) | | (679 | ) | | (377 | ) | | (4,413 | ) |
| December 31, 2013 | 15,884 |
| | 5,190 |
| | 1,528 |
| | 711 |
| | 151 |
| | 807 |
| | 233 |
| | 24,504 |
|
| Acquisitions(a) | — |
| | 82 |
| | — |
| | — |
| | — |
| | 89 |
| | — |
| | 171 |
|
| Currency translation | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (19 | ) | | (19 | ) |
| Divestiture | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
| December 31, 2014 | 15,884 |
| | 5,272 |
| | 1,528 |
| | 711 |
| | 151 |
| | 894 |
| | 214 |
| | 24,654 |
|
| Acquisitions(b) | — |
| | 93 |
| | — |
| | 217 |
| | — |
| | 11 |
| | — |
| | 321 |
|
| Currency translation | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (35 | ) | | (35 | ) |
| Impairment | — |
| | (1,150 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (1,150 | ) |
| December 31, 2015 | $ | 15,884 |
| | $ | 4,215 |
| | $ | 1,528 |
| | $ | 928 |
| | $ | 151 |
| | $ | 905 |
| | $ | 179 |
| | $ | 23,790 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Natural Gas Pipelines Regulated | | Natural Gas Pipelines Non-Regulated | | CO2 | | Products Pipelines | | Products Pipelines Terminals | | Terminals | | Kinder Morgan Canada | | Total |
| Historical Goodwill | $ | 17,527 |
| | $ | 5,812 |
| | $ | 1,528 |
| | $ | 2,125 |
| | $ | 221 |
| | $ | 1,584 |
| | $ | 556 |
| | $ | 29,353 |
|
| Accumulated impairment losses | (1,643 | ) | | (1,597 | ) | | — |
| | (1,197 | ) | | (70 | ) | | (679 | ) | | (377 | ) | | (5,563 | ) |
| December 31, 2015 | 15,884 |
| | 4,215 |
| | 1,528 |
| | 928 |
| | 151 |
| | 905 |
| | 179 |
| | 23,790 |
|
| Currency translation | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 6 |
| | 6 |
|
| Divestitures(a) | (1,635 | ) | | — |
| | — |
| | — |
| | — |
| | (9 | ) | | — |
| | (1,644 | ) |
| December 31, 2016 | 14,249 |
| | 4,215 |
| | 1,528 |
| | 928 |
| | 151 |
| | 896 |
| | 185 |
| | 22,152 |
|
| Currency translation | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 13 |
| | 13 |
|
| Divestitures(b) | — |
| | — |
| | — |
| | — |
| | — |
| | (3 | ) | | — |
| | (3 | ) |
| December 31, 2017 | $ | 14,249 |
| | $ | 4,215 |
| | $ | 1,528 |
| | $ | 928 |
| | $ | 151 |
| | $ | 893 |
| | $ | 198 |
| | $ | 22,162 |
|
_______
| |
| (a) | 20142016 includes $82$1,635 million related to the May 2013 Copano acquisitionsale of a 50% interest in our SNG natural gas pipeline system by Natural Gas Pipelines Non-RegulatedRegulated to Southern Company and $89$9 million related to Terminals’ acquisitions of APT tankers in January 2014 and Crowley tankers in November 2014, as discussed in Note 3.certain terminal divestitures. |
| |
| (b) | 20152017 includes $93 million and $217 million, respectively, related to the February 2015 acquisition of Hiland by Natural Gas Pipelines Non-Regulated and Products Pipelines, and $7$3 million related to the February 2015 acquisition of Vopakcertain terminal assets by Terminals, all of which are discussed in Note 3.divestitures. |
Refer to Note 2 “Summary of Significant Accounting Policies—Goodwill” for a description of our accounting for goodwill and Note 4 “Impairments and Losses on Divestitures” for further discussion regarding impairments.
We determineddetermine the fair value of each reporting unit as of May 31 2015,of each year based primarily on a market approach utilizing a median dividend/distribution yieldenterprise value to estimated EBITDA multiples of comparable companies. The value of each reporting unit wasis determined on a stand-alone basis from the perspective of a market participant and representedrepresenting the price estimated to be received in a sale of the reporting unit in an orderly transaction between market participants at the measurement date. The results of our annual test during the second quarter indicated fair value in excess of carrying value for each of our reporting units. We noted no significant events or conditions during the third quarter of 2015 that would have affected the conclusions from our annual assessment in the prior quarter.
During the month of December 2015, consistent with decreases in certain market indices which track the market sectors in which we operate, the Company’s market capitalization decreased by approximately 36% after experiencing declines earlier in the quarter. During the fourth quarter 2015, many energy companies also indicated their dividends/distributions may be impacted by the ongoing effect of commodity prices on market conditions in the energy sector. As discussed above, our step 1 test performed as of May 31, 2015, used market valuations primarily based on dividend/distribution yields. This indicated that our prior step 1 valuations required re-evaluation. Based on these indicators and related factors, we conducted an interim test of the recoverability of goodwill as of December 31, 2015.
Our step 1 test as of December 31, 2015, utilized both a market approach and income approach to estimate the fair values of our reporting units. The market approach was based on enterprise value (EV) to estimated EBITDA multiples. We believe these multiples appropriately reflect fair value for purposes of our step 1 goodwill impairment test because EV/EBITDA is not dependent on dividend/distribution policy, capital structure or tax profile. For our Natural Gas Pipelines Regulated and Non-Regulated andreporting unit, our CO2 reporting units, we also conductedMay 31, 2017 annual test included a discounted cash flow analysis (income approach) to evaluate the fair value of thesethis reporting unitsunit to provide additional indication of fair value based on the present value of cash flows thesethis reporting units areunit is expected to generate in the future. We weighted the market and income approaches for thesethis reporting unitsunit to arrive at an estimated fair value of these respectivethis reporting unitsunit giving more weighting on the income approach and less
on the market approach as we believed the valuesvalue indicated using the income approach areis more representative of the value that could be received from a market participant. With the exceptionAs of our Natural Gas Pipelines Non-Regulated reporting unit,May 31, 2017, each of our reporting units indicated a fair value in excess of their respective carrying values.values and step 2 was not required. The amount of excess fair value over the carrying value ranged from approximately 3% for our Natural Gas Pipelines RegulatedNon-Regulated reporting unit to 104%89% for our Products Pipelines Terminals. IfTerminals as of May 31, 2017. The results of our Step 1 analysis did not indicate an impairment of goodwill and we did not identify any triggers for further impairment analysis during the fair valueremainder of the Natural Gas Pipelines Regulated reporting unit decreased by approximately 3%, it could indicate a possible failureyear.
Due to the effect of commodity prices on market conditions that impacted the energy sector, during the fourth quarter 2015, we conducted an interim test of the step 1 test. The primary assumptions in our step 1 market approach test include the following:
| |
• | We selected a peer group of midstream companies with large market capitalizations with comparable operations, economic characteristics, and assets which generally include significant holdings of interstate transmission pipelines, midstream gathering and processing systems, and/or terminal operations. We use this peer group for all of our reporting units with the exception of our CO2 reporting unit. We estimated the median enterprise value to EBITDA multiple to be approximately 12.7x, without consideration of any control premium.
|
| |
• | For our CO2 reporting unit, we utilized a group of large independent oil and gas exploration and production companies which generally have operations similar to ours and include assets in the Permian basin where we operate and may have enhanced oil recovery operations similar to ours. We estimated the median enterprise value to EBITDA multiple for this peer group to be approximately 7.9x, without consideration of any control premium.
|
In calculating the market multiples, we used estimatesrecoverability of enterprise valuegoodwill as of December 31, 2015, and consensus estimates ofconcluded that the 2015 EBITDA for each company in the peer group obtained from a third party provider of financial data. Estimates of enterprise value were calculated based on market capitalization plus net debt utilizing the most recent data available as of December 31, 2015. EV/EBITDA multiples are sensitive to changes in the components that comprise the ratio, including EBITDA, market capitalizations, and debt of the peer group companies.
We assessed the reasonableness of the control premium implied by the above market valuations as the market multiples include equity values on a non-controlling basis. As such, we considered the implied control premium as part of our reconciliation of our total reporting unit estimated fair value to our market capitalization which indicated an implied control premium of 34%, which we considered to be reasonable.
For our CO2 reporting unit, the above market approach indicated a fair value of approximately 7.9x EBITDA. Management concluded because of current commodity price conditions, the fair value based on the market approach should be given partial weighting with a discounted cash flow analysis. The discounted cash flow analysis indicated a fair value of approximately 4.1x EBITDA. Based on a weighting of the market and income approaches, we determined a fair value of the CO2 reporting unit of approximately 5.1x EBITDA. If the fair value of the CO2 reporting unit decreased by approximately 12%, this could indicate a possible impairment of goodwill requiring a step 2 analysis.
Applying the market approach to our Natural Gas Pipeline Non-Regulated reporting unit indicated an 18% deficit of fair value as compared to carrying value. We also applied an income approach to this reporting unit, which indicated a deficit of fair value of approximately 4% as compared to the carrying value. The results of our step 1 test of our Natural Gas Pipelines - Non-Regulated reporting unit indicated that our carrying value exceeded the fair value thereby requiring us to perform a step 2 evaluation. The primary assumptions in our step 1 income approach for this reporting unit include the following:was impaired by $1.15 billion.
Based on the weighted-average cost of capital of the peer group, we determined the appropriate rate at which to discount the cash flows is 8%. Each 100 basis points change in the discount rate changes the estimated fair value by approximately 5%.
We used a five-year forward commodity price curve which assumed $38 crude and $2.50 natural gas in 2016 gradually increasing over the following five years to $65 and $3.50, respectively, and then remaining flat. Management developed this price curve based on the year-end NYMEX price curve and a third party median consensus five year forward price curve.
We estimated cash flows based on 6 years of projections and applied exit multiples, ranging from 10x to 15x based on management’s expectations of those that would be applied by a market participant and market transactions for comparable assets, to year 6 cash flows. These cash flows have various assumptions on volumes and prices based on management’s expectations for each underlying component asset within the reporting unit.
We estimated ethane fractionation spreads based on the relationship between ethane and natural gas prices. Our estimates assumed $(0.01) for 2016-2017, increasing to $0.15 in 2018 through 2021 based on a trailing five-year average spreads as management expects demand to increase commensurate with expected petrochemical capacity and export facilities coming online around that time.
Consistent with how we evaluate potential acquisitions and we believe a market participant would do, we assumed a certain amount of capital expenditure, including for projects that are already in progress, and consistent with historical levels as adjusted for commodity prices assumptions and customer activity. We assumed an approximate 12% return on this invested capital beginning in the years the assets are expected to be placed in service.
After considering the market and income approaches, we determined the $19.0 billion carrying value of this reporting unit exceeded the estimated fair value of $17.2 billion, and therefore conducted a step 2 analysis. The fair value was estimated based on a weighting of the market and income approaches for this reporting unit. This implies an EBITDA valuation of approximately 14.0x. Management believes this is a reasonable estimate of fair value based on comparable sales transactions and the fact that it implies a reasonable control premium at the reporting unit level.
Below is a hypothetical allocation of the fair value to the assets and liabilities of this reporting unit, including goodwill. The amount of implied goodwill is then compared to the carrying value of goodwill to determine the amount of impairment (in millions).
|
| | | | |
| Allocation of Fair Value: | | |
| Working capital, net | | $ | 232 |
|
| Property, plant and equipment | | 9,627 |
|
| Other intangible assets | | 3,121 |
|
| Other liabilities, net | | (7 | ) |
| Goodwill | | 4,215 |
|
| Estimated Reporting Unit Fair Value | | $ | 17,188 |
|
| Prior carrying amount of goodwill | | $ | 5,365 |
|
| Goodwill impairment | | $ | 1,150 |
|
The key assumptions used in determining the fair value of the assets and liabilities of the reporting unit are as follows:
Working capital and other liabilities were assumed to have fair values that approximate carrying value as these generally relate to monetary assets and liabilities that settle in the short-term, derivative positions that are recorded at fair value, and inventory which has been subjected to lower of cost or market adjustments in a declining commodity price environment.
With respect to property, plant and equipment, and other intangibles, the company based its determination of fair values on previously completed fair value studies conducted for these assets as updated for developments subsequent to the date of the initial studies.
The fair value allocation assumed theestimates of our reporting unit would be sold in a taxable transaction.
The result of our step 2 analysis was a partial impairment of goodwill in our Natural Gas Pipelines Non-Regulated reporting unit of approximately $1,150 million. The above fair value, estimates areand in arriving at the fourth quarter 2015 impairment amount, were based on Level 3 Inputsinputs of the fair value hierarchy.
The sustained decrease and the long-term outlook in commodity prices have adversely impacted our customers and their future capital and operating plans. A continued or prolonged period of lowervolatile commodity prices could result in further deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital, and our cash flow estimates. A significant unfavorable change to any one or combination of these factors would result in a change to the reporting unit fair values discussed above which could lead to further impairment charges. This would negatively impact our estimates of the fair values of our reporting units and could causepotentially resulting in additional impairments of long-lived assets, equity method investments, and/or goodwill. Such non-cash impairments from one or both, or any, of these reportable units could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value exceeds fair value.operations.
9. Debt
We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statements of income. In 2015, we adopted Accounting Standards Updates (ASU) 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” and ASU 2015-15, “Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements—Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update).” These ASUs are designed to simplify presentation of debt issuance costs. The standards require that debt issuance costs related to a recognized debt liability, except for line-of-credit debt issuance costs, be presented in the balance sheet as an
offset to the carrying amount of that debt liability, consistent with debt discounts. The application of this new accounting guidance resulted in the reclassification of $149 million of debt issuance costs from “Deferred charges and other assets” to “Debt fair value adjustments” in our accompanying consolidated balance sheet as of December 31, 2014.
The following table provides detail on the principal amount of our outstanding debt balances. The table amounts exclude all debt fair value adjustments, including debt discounts, premiums and premiumsissuance costs (in millions):
|
| | | | | | | |
| | December 31, |
| | 2015 | | 2014 |
| KMI | | | |
| Senior notes 1.50% through 8.25%, due 2015 through 2098(a)(b)(c) | $ | 13,346 |
| | $ | 11,438 |
|
| Credit facility due November 26, 2019(d)(e) | — |
| | 850 |
|
| Commercial paper borrowings(d)(e) | — |
| | 386 |
|
| KMP | | | |
| Senior notes, 2.65% through 9.00%, due 2015 through 2044(b)(f) | 19,985 |
| | 20,660 |
|
| TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(b)(h) | 1,790 |
| | 1,790 |
|
| EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(b) | 1,115 |
| | 1,115 |
|
| Copano senior notes, 7.125%, due April 1, 2021(b) | 332 |
| | 332 |
|
| CIG senior notes, 5.95% through 6.85%, due 2015 through 2037(b) | 100 |
| | 475 |
|
| SNG notes, 4.40% through 8.00%, due 2017 through 2032(b)(g) | 1,211 |
| | 1,211 |
|
| Other Subsidiary Borrowings (as obligor) | | | |
| Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(b)(h) | 1,636 |
| | 1,636 |
|
| Hiland Partners Holdings LLC, senior notes, 5.50% and 7.25%, due 2020 and 2022(b)(i) | 974 |
| | — |
|
| EPC Building, LLC, promissory note, 3.967%, due 2015 through 2035 | 443 |
| | 453 |
|
| Preferred securities, 4.75%, due March 31, 2028(j) | 221 |
| | 280 |
|
| KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(k) | 100 |
| | 100 |
|
| Other miscellaneous debt(l) | 300 |
| | 303 |
|
| Total debt – KMI and Subsidiaries | 41,553 |
| | 41,029 |
|
| Less: Current portion of debt(m) | 821 |
| | 2,717 |
|
| Total long-term debt – KMI and Subsidiaries(n) | $ | 40,732 |
| | $ | 38,312 |
|
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| Unsecured term loan facility, variable rate, due January 26, 2019(a) | $ | — |
| | $ | 1,000 |
|
| Senior note, floating rate, due January 15, 2023(a) | 250 |
| | — |
|
| Senior notes, 1.50% through 8.05%, due 2017 through 2098(a)(b)(c) | 13,136 |
| | 13,236 |
|
| Credit facility due November 26, 2019 | 125 |
| | — |
|
| Commercial paper borrowings | 240 |
| | — |
|
| KML Credit Facility(d) | — |
| | — |
|
| KMP senior notes, 2.65% through 9.00%, due 2017 through 2044(c)(e) | 18,885 |
| | 19,485 |
|
| TGP senior notes, 7.00% through 8.375%, due 2017 through 2037(c)(f) | 1,240 |
| | 1,540 |
|
| EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(c)(g) | 760 |
| | 1,115 |
|
| CIG senior notes, 4.15% and 6.85%, due 2026 and 2037(c) | 475 |
| | 475 |
|
| Kinder Morgan Finance Company, LLC, senior notes, 6.00% and 6.40%, due 2018 and 2036(c) | 786 |
| | 786 |
|
| Hiland Partners Holdings LLC, senior notes, 5.50%, due 2022(a)(h) | — |
| | 225 |
|
| EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035 | 421 |
| | 433 |
|
| Trust I preferred securities, 4.75%, due March 31, 2028(i) | 221 |
| | 221 |
|
| KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(j) | 100 |
| | 100 |
|
| Other miscellaneous debt(k) | 277 |
| | 285 |
|
| Total debt – KMI and Subsidiaries | 36,916 |
| | 38,901 |
|
| Less: Current portion of debt(l) | 2,828 |
| | 2,696 |
|
| Total long-term debt – KMI and Subsidiaries(m) | $ | 34,088 |
| | $ | 36,205 |
|
_______
| |
| (a) | On August 10, 2017, we issued $1 billion of unsecured senior notes with a fixed rate of 3.15% and $250 million of unsecured senior notes with a floating rate, both due January 2023. The net proceeds from the notes were primarily used to repay the principal amount of Hiland’s 5.50% senior notes due 2022, plus accrued interest, and to repay the $1 billion term loan facility due 2019. Interest on the 3.15% senior notes due 2023 is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2018, and the notes will mature on January 15, 2023. Interest on the floating rate senior notes due 2023 is payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, beginning on October 15, 2017, and such notes will mature on January 15, 2023. We may redeem all or a part of the 3.15% fixed rate notes at any time at the redemption prices. The floating rate notes are not redeemable prior to maturity. See (b) and (h) below. |
| |
| (b) | December 31, 2015 amount includesAmounts include senior notes that are denominated in Euros and have been converted to U.S. dollars and are respectively reported above at the December 31, 20152017 exchange rate of 1.08621.2005 U.S. dollars per Euro and the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro. FromFor the issuance date of these senior notes in March 2015 throughyear ended December 31, 2015,2017, our debt balance increased by less than $1$186 million as a result of the change in the exchange rate of U.S dollars per Euro. WeThe increase in debt due to the changes in exchange rates is offset by a corresponding change in the value of cross-currency swaps reflected in “Deferred charges and other assets” and “ Other long-term liabilities and deferred credits” on our consolidated balance sheets. At the time of issuance, we entered into cross-currency swap agreements associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 14 “Risk Management—Foreign Currency Risk Management”). In June 2017, we repaid $786 million of maturing 7.00% senior notes and in December 2017, we repaid $500 million of maturing 2.00% senior notes. The December 31, 2017 balance includes the $1 billion of unsecured term notes with a fixed rate of 3.15% due January 15, 2023 discussed in (a) above.
|
| |
(b)(c) | Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. |
| |
(c) | Includes $6.0 billion of senior notes issued on November 26, 2014 as a result of the Merger Transactions (see “—Long-term Debt Issuances and Repayments” below). |
| |
| (d) | As ofThe KML Credit Facility is denominated in C$ and has been converted to U.S. dollars and reported above at the December 31, 2014, the weighted average interest2017 exchange rate on our credit facility borrowings, including commercial paper borrowings, was 1.54%of 0.7971 U.S. dollars per C$. See “—Credit Facilities and Restrictive Covenants” below. |
| |
| (e) | On November 26, 2014,In February 2017, we entered into a $4 billion replacement credit facility and a commercial paper programrepaid $600 million of up to $4 billion of unsecured notes (see “—Credit Facilities and Restrictive Covenants” below).maturing 6.00% senior notes. |
| |
| (f) | On January 1, 2015, EPB and EPPOC merged with and into KMP. On that date, KMP succeeded EPPOC as the issuerIn April 2017, we repaid $300 million of approximately $2.9 billion of EPPOC’s senior notes, which were guaranteed by EPB, and EPB and EPPOC ceased to be obligors for thosematuring 7.50% senior notes. |
| |
| (g) | Southern Natural Issuing Corporation is a wholly owned finance subsidiaryIn April 2017, we repaid $355 million of SNG and is the co-issuer of certain of SNG’s outstanding debt securities.maturing 5.95% senior notes. |
| |
| (h) | In January and February 2016,August 2017, we refinanced $850repaid $225 million of maturing Kinder Morgan Finance Company LLCthe outstanding principal amount of 5.50% senior notes and $150 millionwith a maturity date of maturing TGP senior notesMay 15, 2022 using net proceeds from the sale of the January 2023 notes (see (a) above). We recognized a new three-year term loan facility (see “— Subsequent Event—Debt Issuances$3.8 million loss from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2017 consisting of a $9.3 million premium on the debt repaid and Repayments” below).a $5.5 million gain from the write-off of unamortized purchase accounting associated with the early extinguished debt. |
| |
| (i) | Represents the remaining principal amount outstanding of senior notes assumed in the Hiland acquisition. |
| |
(j) | Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2015,2017, had 4.4 million of 4.75% trust convertible preferred securities outstanding (referred to as the Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We provide a full and unconditional guarantee of the Trust I Preferred Securities. There are no significant restrictions from these securities on our ability to obtain funds from our subsidiaries by distribution, dividend or loan. The Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75%, carry a liquidation value of $50$50 per security plus accrued and unpaid distributions and are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; (ii) $25.18$25.18 in cash without interest; and (iii) 1.100 warrants to purchase a share of our Class P common stock. Our warrants expired on May 25, 2017, along with the portion of the mixed consideration that provided for the conversion into 1.100 warrants to purchase a share of our Class P common stock. We have the right to redeem these Trust I Preferred Securities at any time. Because of the substantive conversion rights of the securities into the mixed consideration, we bifurcated the fair value of the Trust I Preferred Securities into debt and equity components and as of December 31, 2017, the outstanding balance of $221 million (of which $111 million was classified as current) was bifurcated between debt ($200 million) and equity ($21 million). |
Preferred Securities into debt and equity components and as of December 31, 2015, the outstanding balance of $221 million (of which $111 million is classified as current) was bifurcated between debt ($197 million) and equity ($24 million). During the years ended December 31, 2015 and 2014, 1,176,015 and 3,923 Trust I Preferred Securities had been converted into (i) 846,369 and 2,820 shares of our Class P common stock; (ii) approximately $30 million and $99,000 in cash; and (iii) 1,293,615 and 4,315 in warrants, respectively.
| |
(k)(j) | As of December 31, 20152017 and 2014,2016, KMGP had outstanding, 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057. Since August 18, 2012, dividends on the preferred stock accumulate at a floating rate of the 3-month LIBOR plus 3.8975% and are payable quarterly in arrears, when and if declared by KMGP’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2012. The preferred stock has approval rights over a commencement of or filing of voluntary bankruptcy by KMP or its SFPP or Calnev subsidiaries. |
| |
(l)(k) | In conjunction with the construction of the Totem Gas Storage facility (Totem) and the High Plains pipeline (High Plains), CIG’s joint venture partner in WYCO funded 50% of the construction costs. Upon project completion, the advances were converted into a financing obligation to WYCO. As of December 31, 2015,2017, the principal amounts of the Totem and High Plains financing obligations were $72$69 million and $96$88 million, respectively, which will be paid in monthly installments through 2039 based on the initial lease term. The interest rate on these obligations is 15.5%, payable on a monthly basis. |
| |
(m)(l) | Amounts include KMI and KML outstanding credit facility andborrowings, commercial paper borrowings and other debt maturing within 12 months. See “—Maturities“—Current Portion of Debt” below. |
| |
(n)(m) | Excludes our “Debt fair value adjustments” which, as of December 31, 20152017 and December 31, 2014,2016, increased our combined debt balances by $1,674$927 million and $1,785$1,149 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs (resulting from the implementation of ASU No. 2015-03 and 2015-15) and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see Note 15 “Fair Value——“Debt Fair Value Adjustments.” Adjustments” below. |
We and substantially all of our wholly owned domestic subsidiaries are a party to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Also, see Note 19.19 “Guarantee of Securities of Subsidiaries.”
Credit Facilities and Restrictive Covenants
KMI
On September 19, 2014,January 26, 2016, we entered into a new five-year $4.0 billionincreased the capacity of our revolving credit agreement, with a syndicate of lenders, which can be increasedinitially entered into during 2014, from $4.0 billion to $5.0 billion if certain conditions are met (see “—Subsequent Event—Credit Facility Capacity” following).billion. The newother terms of our revolving credit agreement was effective uponremain the closing of the Merger Transactions on November 26, 2014 and replaced the prior KMI credit agreement, the KMP credit agreement and the EPB credit agreement. On November 26, 2014, we entered intosame. We also maintain a $4.0 billion commercial paper program through the private placement of short-term notes. The notes mature up to 270 days from the date of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less a discount representing an interest factor or if interest bearing, at par. Borrowings under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.
Our credit facility borrowings bear interest at either (i) LIBOR plus an applicable margin ranging from 1.125% to 2.000% per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; and (3) LIBOR Rate for a one month eurodollar loan, plus 1%, plus, in each case, an applicable margin ranging from 0.125% to 1.00% per annum based on our credit rating. As of December 31, 2015, we were in compliance with all required financial covenants.
Our credit facility included the following restrictive covenants as of December 31, 2015:2017:
total debt divided by earnings before interest, income taxes, depreciation and amortization may not exceed:
6.50: 1.00, for the period ended on or prior to December 31, 2017; or
6.25: 1.00, for the period ended after December 31, 2017 and on or prior to December 31, 2018; or
6.00: 1.00, for the period ended after December 31, 2018;
certain limitations on indebtedness, including payments and amendments;
certain limitations on entering into mergers, consolidations, sales of assets and investments;
limitations on granting liens; and
prohibitions on making any dividend to shareholders if an event of default exists or would exist upon making such dividend.
As of December 31, 2015,2017, we had no borrowings$125 million outstanding under our five-year $4.0 billion revolving credit facility, no borrowings$240 million outstanding under our $4.0 billion commercial paper program and $115$107 million in letters of credit. Our availability under this facility as of December 31, 20152017 was $3,885$4,528 million.
On February 13, 2015, As of December 31, 2017, we were in connectioncompliance with the Hiland acquisition, we entered into and made borrowings of $1,641 million under a new six-month bridge credit facility with UBS AG, Stamford Branch. Interest under this bridge credit facility was charged at the same rate as our $4.0 billion revolving credit facility. Prior to March 31, 2015, we repaid outstanding borrowings and the facility was terminated on April 6, 2015.all required covenants.
Subsequent Event—Credit Facility CapacityKML
On June 16, 2017, KML’s indirect subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the TMEP, (ii) a C$1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional TMEP costs (and, subject to the need to fund such additional costs, meeting the Canadian NEB-mandated liquidity requirements) and (iii) a C$500 million revolving working capital facility to be used for working capital and other general corporate purposes (collectively, the “KML Credit Facility”). On January 26, 2016, in accordance23, 2018, KML entered into an agreement amending certain terms of its Credit Facility to, among other things, provide additional funding certainty with respect to each tranche of its Credit Facility. The KML Credit Facility has a five-year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. Any undrawn commitments under the KML Credit Facility will incur a standby fee of 0.30% to 0.625%, with the termsrange dependent on the credit ratings of our revolving credit agreement, we increased the capacity of our revolving credit agreement from $4.0 billion to $5.0 billion.Kinder Morgan Cochin ULC or KML. The termsKML Credit Facility is guaranteed by KML and all of the revolving credit agreement remainnon-borrower subsidiaries of KML and are secured by a first lien security interest on all of the same.assets of KML and the equity and assets of the other guarantors.
Hiland Debt AcquiredDraw downs of funds on the KML Credit Facility bear interest dependent on the type of loans requested and are as follows:
bankers’ acceptances or LIBOR loans are at an annual rate of approximately Canadian Dealer Offered Rate (CDOR);
or the LIBOR, as the case may be, plus a fixed spread ranging from 1.50% to 2.50%;
loans in Canadian dollars or U.S. dollars are at an annual rate of approximately the Canadian prime rate or the U.S. dollar base rate, as the case may be, plus a fixed spread ranging from 0.50% to 1.50%, in each case, with the range dependent on the credit ratings of KML; and
letters of credit (under the working capital facility only) will have issuance fees based on an annual rate of approximately CDOR plus a fixed spread ranging from 1.50% to 2.50%, with the range dependent on the credit ratings of the Company.
The foregoing rates and fees will increase by 0.25% upon the fourth anniversary of the KML Credit Facility.
The KML Credit Facility includes various financial and other covenants including:
a maximum ratio of consolidated total funded debt to consolidated capitalization of 70%;
restrictions on ability to incur debt;
restrictions on ability to make dispositions, restricted payments and investments;
restrictions on granting liens and on sale-leaseback transactions;
restrictions on ability to engage in transactions with affiliates; and
restrictions on ability to amend organizational documents and engage in corporate reorganization transactions.
As of December 31, 2017, KML had C$447 million available under its five year C$500 million working capital facility (after reducing the February 13, 2015 Hiland acquisition date, we assumed (i) $975capacity for the C$53.0 million (U.S.$42 million) in principal amountletters of senior notes (which were valued at $1,043 million as of the acquisition date)credit) and (ii) $368 million of other borrowings that were immediately repaid after closing, primarily consisting of borrowingsno amounts outstanding under aits C$4.0 billion construction facility or its C$1.0 billion revolving contingent credit facility. The senior notes are subject to our cross guarantee agreement discussedAs of December 31, 2017, KML was in Note 19.compliance with all required covenants.
Long-term
Current Portion of Debt Issuances and Repayments
Apart fromThe primary components of our current portion of debt include the assumptionfollowing significant series of the Hiland debt discussed above, following are significant long-term debt issuances and repayments made during 2015 and 2014:
|
| | | | |
| | | 2015 | | 2014 |
| | | | | |
| Issuances | | $800 million 5.05% notes due 2046 | | $650 million senior term loan facility due 2017 |
| | | $815 million 1.50% notes due 2022(a) | | $500 million 2.00% notes due 2017(b) |
| | | $543 million 2.25% notes due 2027(a) | | $1,500 million 3.05% notes due 2019(b) |
| | | | | $1,500 million 4.30% notes due 2025(b) |
| | | | | $750 million 5.30% notes due 2034(b) |
| | | | | $1,750 million 5.55% notes due 2045(b) |
| | | | | $750 million 3.50% notes due 2021 |
| | | | | $750 million 5.50% notes due 2044 |
| | | | | $650 million 4.25% notes due 2024 |
| | | | | $550 million 5.40% notes due 2044 |
| | | | | $600 million 4.30% notes due 2024 |
| | | | | |
| Repayments | | $300 million 5.625% notes due 2015 | | $500 million 5.125% notes due 2014 |
| | | $250 million 5.15% notes due 2015 | | $1,528 million senior term loan facility due 2015 |
| | | $340 million 6.80% notes due 2015 | | $650 million senior term loan facility due 2017(b) |
| | | $375 million 4.10% notes due 2015 | | $207 million 6.875% notes due 2014 |
________
(a) Senior notes are denominated in Euros and are presented above in U.S. dollars at the exchange rate on the issuance date of 1.0860 U.S. dollars per Euro. We entered into cross-currency swap agreements associated with these senior notes (see Note 14—“Risk Management—Foreign Currency Risk Management”).
(b) Debt issued or repaid associated with the Merger Transactions. |
| | | | |
| As of December 31, 2017 | | $750 | | Kinder Morgan Finance Company, LLC, 6.00% senior notes due January 2018 |
| | $82 | | 7.00% senior notes due February 2018 |
| | $975 | | KMP 5.95% senior notes due February 2018 |
| | $477 | | 7.25% senior notes due June 2018 |
| | | | |
| As of December 31, 2016 | | $600 | | KMP 6.00% senior notes due February 2017 |
| | $300 | | TGP 7.50% senior notes due April 2017 |
| | $355 | | EPNG 5.95% senior notes due April 2017 |
| | $786 | | 7.00% senior notes due June 2017 |
| | $500 | | 2.00% senior notes due December 2017 |
Subsequent Event—Debt Issuances and Repayments
In January 2016, we entered into a $1.0 billion three-year unsecured term loan facility due in 2019 at a variable interest rate which is determined in the same manner as interest on our revolving credit facility borrowings. In January 2016,2018, we repaid $850$750 million of maturing 5.70%6.00% Kinder Morgan Finance Company, LLC senior notes and in February 20162018, we repaid $250$82 million of maturing 8.00%7.00% senior notes primarily using proceeds from the three-year term loan. Since we refinanced aboth listed above in current portion of the maturing debt with proceeds from long-term debt, we classified $1 billionas of the maturing debt within “Long-term debt” on our consolidated balance sheet at December 31, 2015.2017.
Maturities of Debt
The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2015,2017, are summarized as follows (in millions):
| | | Year | | Total | | Total |
| 2016(a) | | $ | 821 |
| |
| 2017 | | 3,060 |
| |
| 2018 | | 2,329 |
| | $ | 2,828 |
|
| 2019(a) | | 3,819 |
| |
| 2019 | | | 2,820 |
|
| 2020 | | 2,953 |
| | 2,204 |
|
| 2021 | | | 2,422 |
|
| 2022 | | | 2,558 |
|
| Thereafter | | 28,571 |
| | 24,084 |
|
| Total | | $ | 41,553 |
| | $ | 36,916 |
|
________
| |
(a) | 2016 amount primarily includes $667 million of current maturities on senior notes and $111 million associated with our Trust I Preferred Securities that are classified as current obligations because these securities have rights to convert into consideration consistent with the EP merger, and excludes $1,000 million of current maturities on long-term debt that were refinanced with proceeds from the issuance of a January 2016 three-year term loan which is reflected in 2019. |
Debt Fair Value Adjustments
The carrying value adjustment to debt securities whose fair value is being hedged is included within “Debt fair value adjustments” on our accompanying consolidated balance sheets. “Debt fair value adjustments” also include unamortized debt discount/premiums, purchase accounting debt fair value adjustments, unamortized portion of proceeds received from the early termination of interest rate swap agreements, and debt issuance costs. As of December 31, 2015,2017, the weighted-average amortization period of the unamortized premium from the termination of the interest rate swaps was approximately 16 years. The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets (in millions):
| | | | | December 31, | | December 31, |
| Debt Fair Value Adjustments | | 2015 | | 2014 | | 2017 | | 2016 |
| Purchase accounting debt fair value adjustments | | $ | 1,135 |
| | $ | 1,221 |
| | $ | 719 |
| | $ | 806 |
|
| Carrying value adjustment to hedged debt | | 380 |
| | 347 |
| | 115 |
| | 220 |
|
| Unamortized portion of proceeds received from the early termination of interest rate swap agreements | | 397 |
| | 454 |
| | 297 |
| | 342 |
|
| Unamortized debt discount/premiums | | (86 | ) | | (88 | ) | |
| Unamortized debt discounts, net | | | (74 | ) | | (80 | ) |
| Unamortized debt issuance costs | | (152 | ) | | (149 | ) | | (130 | ) | | (139 | ) |
| Total debt fair value adjustments | | $ | 1,674 |
| | $ | 1,785 |
| | $ | 927 |
| | $ | 1,149 |
|
Interest Rates, Interest Rate Swaps and Contingent Debt
The weighted average interest rate on all of our borrowings was 4.92%5.02% during 20152017 and 5.02%4.95% during 2014.2016. Information on our interest rate swaps is contained in Note 14.14 “Risk Management.” For information about our contingent debt agreements, see Note 13 “Commitments and Contingent Liabilities—Contingent Debt”).
10. Share-based Compensation and Employee Benefits
Share-based Compensation
Class P Shares
Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors
We have a Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors, in which our eligible non-employee directors participate. The plan recognizes that the compensation paid to each eligible non-employee
director is fixed by our board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving some or all of the cash compensation, each eligible non-employee director may elect to receive shares of Class P common stock. Each election will be generally at or around the first board meeting in January of each calendar year and will be effective for the entire calendar year. An eligible director may make a new election each calendar year. The total number of shares of Class P common stock authorized under the plan is 250,000. During 20152017, 20142016 and 2013,2015, we made restricted Class P common stock grants to our non-employee directors of 9,58017,740, 6,21031,880 and 5,710,9,580, respectively. These grants were valued at time of issuance at $401,000400,000, $220,000400,000 and $210,000,$401,000, respectively. All of the restricted stock awards made to non-employee directors vest during a six-monthsix-month period.
Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan
The Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan is an equity awards plan available to eligible employees. The total number of shares of Class P common stock authorized under the plan is 33,000,000. The following table sets forth a summary of activity and related balances of our restricted stock awards excluding that issued to non-employee directors (in millions, except share and per share amounts):
| | | | | | | | | | | | | | Year Ended | | Year Ended | | Year Ended |
| | Year Ended
December 31, 2015 | | Year Ended
December 31, 2014 | | Year Ended December 31, 2013 | December 31, 2017 | | December 31, 2016 | | December 31, 2015 |
| | Shares | | Weighted Average Grant Date Fair Value | | Shares | | Weighted Average Grant Date Fair Value | | Shares | | Weighted Average Grant Date Fair Value | Shares | | Weighted Average
Grant Date
Fair Value | | Shares | | Weighted Average
Grant Date
Fair Value | | Shares | | Weighted Average Grant Date Fair Value |
| Outstanding at beginning of period | 7,373,294 |
| | $ | 277 |
| | 6,382,885 |
| | $ | 239 |
| | 2,154,022 |
| | $ | 69 |
| 9,038,137 |
| | $ | 32.72 |
| | 7,645,105 |
| | $ | 37.91 |
| | 7,373,294 |
| | $ | 37.63 |
|
| Granted | 1,488,467 |
| | 57 |
| | 1,694,668 |
| | 61 |
| | 4,563,495 |
| | 181 |
| 3,221,691 |
| | 19.52 |
| | 2,816,599 |
| | 21.36 |
| | 1,488,467 |
| | 38.20 |
|
| Vested | (817,797 | ) | | (29 | ) | | (460,032 | ) | | (14 | ) | | (83,444 | ) | | (3 | ) | (1,501,939 | ) | | 36.67 |
| | (1,226,652 | ) | | 38.53 |
| | (817,797 | ) | | 35.66 |
|
| Forfeited | (398,859 | ) | | (15 | ) | | (244,227 | ) | | (9 | ) | | (251,188 | ) | | (8 | ) | (239,545 | ) | | 28.34 |
| | (196,915 | ) | | 35.74 |
| | (398,859 | ) | | 38.51 |
|
| Outstanding at end of period | 7,645,105 |
| | $ | 290 |
| | 7,373,294 |
| | $ | 277 |
| | 6,382,885 |
| | $ | 239 |
| 10,518,344 |
| | $ | 28.21 |
| | 9,038,137 |
| | $ | 32.72 |
| | 7,645,105 |
| | $ | 37.91 |
|
| Intrinsic value of restricted stock awards vested during the period | | | $ | 31 |
| | | | $ | 17 |
| | | | $ | 3 |
| |
The intrinsic value of restricted stock awards vested during the years ended December 31, 2017, 2016 and 2015 was $30 million, $25 million and $31 million, respectively. Restricted stock awards made to employees have vesting periods ranging from 1 year with variable vesting dates to 10 years. Following is a summary of the future vesting of our outstanding restricted stock awards:
| | | Year | | Vesting of Restricted Shares | | Vesting of Restricted Shares |
| 2016 | | 1,096,290 |
| |
| 2017 | | 1,563,549 |
| |
| 2018 | | 2,443,888 |
| | 2,272,019 |
|
| 2019 | | 1,688,831 |
| | 4,268,118 |
|
| 2020 | | 585,574 |
| | 3,647,967 |
|
| 2021 | | | 199,850 |
|
| 2022 | | | 65,928 |
|
| Thereafter | | 266,973 |
| | 64,462 |
|
| Total Outstanding | | 7,645,105 |
| | 10,518,344 |
|
The related expensecompensation costs less estimated forfeitures is generally recognized ratably over the vesting period of the restricted stock awards. Upon vesting, the grants will be paid in our Class P common shares.
During 2015, 20142017, 2016 and 2013,2015, we recorded $6765 million, $5766 million and $35$52 million, respectively, in expense related to restricted stock awards.awards and capitalized approximately $9 million, $9 million and $15 million, respectively. At December 31, 20152017 and 2014,2016, unrecognized restricted stock awards compensation expense,costs, less estimated forfeitures, was approximately $154112 million and $170$133 million, respectively.
KML Restricted Shares
KML adopted the 2017 Restricted Share Unit Plan for Employees, an equity awards plan, for its eligible employees, and the 2017 Restricted Share Unit Plan for Non-Employee Directors, in which its eligible non-employee directors participate.During the year ended December 31, 2017, we recognized $1 million of expense and capitalized $1 million related to these compensation programs. At December 31, 2017, unrecognized compensation costs, less estimated forfeitures associated with KML’s restricted share unit awards, was approximately $8 million.
Pension and Other Postretirement Benefit Plans
Savings Plan
We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain plan participants’ contributions andcollectively bargained participants receive Company contributions are based onin accordance with collective bargaining agreements. The total expensecost for our savings plan was approximately $46$47 million, $42$47 million, and $40 $46
million for the years ended December 31, 2017, 2016 and 2015, 2014 and 2013, respectively.
Pension Plans
Our U.S. pension plan is aplans are defined benefit planplans that coverscover substantially all of our U.S. employees and providesprovide benefits under a cash balance formula. A participant in the cash balance planformula accrues benefits through contribution credits based on a combination of age and years of service, timesmultiplied by eligible compensation. Interest is also credited to the participant’s plan account. A participant becomes fully vested in the plan after three years and may take a lump sum distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees continue to accrue benefits through career pay or final pay formulas.
Two of our subsidiaries, Kinder Morgan Canada Inc. and Trans Mountain Pipeline ULC (as general partner of Trans Mountain Pipeline L.P.), are sponsors of pension plans for eligible Canadian and Trans Mountain pipeline employees. The plans include registered defined benefit pension plans, supplemental unfunded arrangements (which provide pension benefits in excess of statutory limits) and defined contributory plans. Benefits under the defined benefit components accrue through career pay or final pay formulas. The net periodic benefit costs, contributions and liability amounts associated with our Canadian plans are not material to our consolidated income statements or balance sheets; however, we began to include the activity and balances associated with our Canadian plans (including our Canadian OPEB plans discussed below) in the following disclosures on a prospective basis beginning in 2016. For the year ended December 31, 2015, the associated net periodic benefit costs for these combined Canadian plans of $12 million were reported separately.
Other Postretirement Benefit Plans
We and certain of our U.S. subsidiaries provide other postretirement benefits (OPEB), including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees. Our Canadian subsidiaries also provide OPEB benefits to current and future retirees and their dependents. The U.S. plans provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange. Medical benefits forunder these closed groups of retireesOPEB plans may be subject to deductibles, co-payment provisions, dollar caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits. Effective January 1, 2014, the plan was amended to provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange.
Additionally, our subsidiary SFPP has incurred certain liabilities for postretirement benefits to certain current and former employees, their covered dependents, and their beneficiaries. However, the net periodic benefit costs, contributions and liability amounts associated with the SFPP postretirement benefit plan are not material to our consolidated income statements or balance sheets.
Benefit Obligation, Plan Assets and Funded Status. The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 20152017 and 20142016 (in millions):
| | | | Pension Benefits | | OPEB | Pension Benefits | | OPEB |
| | 2015 | | 2014 | | 2015 | | 2014 | 2017 | | 2016 | | 2017 | | 2016 |
| Change in benefit obligation: | | | | | | | | | | | | | | |
| Benefit obligation at beginning of period | $ | 2,804 |
| | $ | 2,563 |
| | $ | 624 |
| | $ | 631 |
| $ | 2,884 |
| | $ | 2,654 |
| | $ | 473 |
| | $ | 509 |
|
| Service cost | 33 |
| | 21 |
| | — |
| | — |
| 40 |
| | 36 |
| | 1 |
| | 1 |
|
| Interest cost | 99 |
| | 112 |
| | 21 |
| | 25 |
| 88 |
| | 89 |
| | 13 |
| | 16 |
|
| Actuarial (gain) loss | (109 | ) | | 294 |
| | (101 | ) | | 15 |
| |
| Actuarial loss (gain) | | 155 |
| | 127 |
| | (16 | ) | | (42 | ) |
| Benefits paid | (173 | ) | | (186 | ) | | (39 | ) | | (52 | ) | (180 | ) | | (180 | ) | | (38 | ) | | (41 | ) |
| Participant contributions | — |
| | — |
| | 2 |
| | 3 |
| 3 |
| | 3 |
| | 2 |
| | 2 |
|
| Medicare Part D subsidy receipts | — |
| | — |
| | 2 |
| | 2 |
| — |
| | — |
| | 1 |
| | 1 |
|
| Exchange rate changes | | 13 |
| | 4 |
| | 1 |
| | 1 |
|
| Settlements | | (21 | ) | | — |
| | — |
| | — |
|
| Other(a) | | — |
| | 151 |
| | (12 | ) | | 26 |
|
| Benefit obligation at end of period | 2,654 |
| | 2,804 |
| | 509 |
| | 624 |
| 2,982 |
| | 2,884 |
| | 425 |
| | 473 |
|
| | | Change in plan assets: | | | | | | | | | | | | | | |
| Fair value of plan assets at beginning of period | 2,377 |
| | 2,333 |
| | 389 |
| | 380 |
| 2,160 |
| | 2,050 |
| | 332 |
| | 325 |
|
| Actual (loss) return on plan assets | (204 | ) | | 180 |
| | (45 | ) | | 32 |
| |
| Actual return on plan assets | | 292 |
| | 157 |
| | 29 |
| | 29 |
|
| Employer contributions | 50 |
| | 50 |
| | 16 |
| | 25 |
| 32 |
| | 8 |
| | 9 |
| | 16 |
|
| Participant contributions | — |
| | — |
| | 2 |
| | 3 |
| 3 |
| | 3 |
| | 2 |
| | 2 |
|
| Medicare Part D subsidy receipts | — |
| | — |
| | 2 |
| | 1 |
| — |
| | — |
| | 1 |
| | 1 |
|
| Benefits paid | (173 | ) | | (186 | ) | | (39 | ) | | (52 | ) | (180 | ) | | (180 | ) | | (38 | ) | | (41 | ) |
| Exchange rate changes | | 10 |
| | 3 |
| | — |
| | — |
|
| Settlements | | (21 | ) | | — |
| | — |
| | — |
|
| Other(a) | | — |
| | 119 |
| | — |
| | — |
|
| Fair value of plan assets at end of period | 2,050 |
| | 2,377 |
| | 325 |
| | 389 |
| 2,296 |
| | 2,160 |
| | 335 |
| | 332 |
|
| Funded status - net liability at December 31, | $ | (604 | ) | | $ | (427 | ) | | $ | (184 | ) | | $ | (235 | ) | $ | (686 | ) | | $ | (724 | ) | | $ | (90 | ) | | $ | (141 | ) |
_______
| |
| (a) | 2017 amounts represent December 31, 2016 balances associated with our Plantation Pipeline OPEB plan that are no longer included in these disclosures. 2016 amounts primarily represent December 31, 2015 balances associated with our Canadian pension and OPEB plans for prospective inclusion in these disclosures, which associated net periodic benefit costs were reported separately in years prior to 2016. |
Components of Funded Status. The following table details the amounts recognized in our balance sheetsheets at December 31, 20152017 and 20142016 related to our pension and OPEB plans (in millions):
| | | | Pension Benefits | | OPEB | Pension Benefits | | OPEB |
| | 2015 | | 2014 | | 2015 | | 2014 | 2017 | | 2016 | | 2017 | | 2016 |
Non-current benefit asset | $ | — |
| | $ | — |
| | $ | 139 |
| | $ | 173 |
| $ | — |
| | $ | — |
| | $ | 198 |
| | $ | 153 |
|
| Current benefit liability | — |
| | — |
| | (16 | ) | | (22 | ) | — |
| | — |
| | (15 | ) | | (16 | ) |
| Non-current benefit liability | (604 | ) | | (427 | ) | | (307 | ) | | (386 | ) | (686 | ) | | (724 | ) | | (273 | ) | | (278 | ) |
| Funded status - net liability at December 31, | $ | (604 | ) | | $ | (427 | ) | | $ | (184 | ) | | $ | (235 | ) | $ | (686 | ) | | $ | (724 | ) | | $ | (90 | ) | | $ | (141 | ) |
_______
| |
| (a) | 2017 and 2016 OPEB amounts include $33 million and $29 million, respectively, of non-current benefit assets related to a plan we sponsor which is associated with employee services provided to an unconsolidated joint venture, and for which we have recorded an offsetting related party deferred credit. |
Components of Accumulated Other Comprehensive (Loss) Income. The following table details the amounts of pre-tax accumulated other comprehensive (loss) income at December 31, 20152017 and 20142016 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets, including the portion attributable to our noncontrolling interests, (in millions):
| | | | Pension Benefits | | OPEB | Pension Benefits | | OPEB |
| | 2015 | | 2014 | | 2015 | | 2014 | 2017 | | 2016 | | 2017 | | 2016 |
| Unrecognized net actuarial (loss) gain | $ | (558 | ) | | $ | (296 | ) | | $ | 23 |
| | $ | (27 | ) | $ | (635 | ) | | $ | (682 | ) | | $ | 88 |
| | $ | 69 |
|
| Unrecognized prior service (cost) credit | (4 | ) | | (4 | ) | | 19 |
| | 20 |
| (4 | ) | | (5 | ) | | 17 |
| | 18 |
|
| Accumulated other comprehensive (loss) income | $ | (562 | ) | | $ | (300 | ) | | $ | 42 |
| | $ | (7 | ) | $ | (639 | ) | | $ | (687 | ) | | $ | 105 |
| | $ | 87 |
|
We anticipate that approximately $2834 million of pre-tax accumulated other comprehensive loss, inclusive of amounts reported as noncontrolling interests, will be recognized as part of our net periodic benefit cost in 2016,2018, including approximately $2936 million of unrecognized net actuarial loss and approximately $12 million of unrecognized prior service credit.
Our accumulated benefit obligation for our pension plans was $2,6152,840 million and $2,7192,834 million at December 31, 20152017 and 2014,2016, respectively.
Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $444373 million and $553415 million at December 31, 20152017 and 2014,2016, respectively. The fair value of these plans’ assets was approximately $12184 million and $145$121 million at December 31, 20152017 and 2014,2016, respectively.
Plan Assets. The investment policies and strategies are established by the Fiduciary Committee for the assets of each of the U.S. pension and OPEB plans are establishedand by the FiduciaryPension Committee for the assets of the Canadian pension plans (the “Committee”“Committees”), which isare responsible for investment decisions and management oversight of each plan.the plans. The stated philosophy of each of the CommitteeCommittees is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (1) meet or exceed plan actuarial earnings assumptions over the long term and (2) provide a reasonable return on assets within established risk tolerance guidelines and to maintain the liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the Committee recognizesCommittees recognize that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the Committee hasCommittees have each adopted a strategy of using multiple asset classes.
As of December 31, 2015,2017, the allowable range for asset allocations in effect for theour U.S. pension plan were 34% to 59% equity, 37% to 57% fixed income, 0% to 5% cash, 0% to 2% alternative investments and 0% to 10% company securities (KMI Class P common stock)stock and/or debt securities). As of December 31, 2015,2017, the allowable range for asset allocations in effect for theour U.S. retiree medical and retiree life insurance plans were 15% to 56%55% equity, 15% to 47% fixed income, 0% to 19%20% cash and 13% to 38% master limited partnerships.39% MLPs. As of December 31, 2017, the target asset allocation for our Canadian pension plans that are closed to new participants was 90% fixed income and 10% equity. The target allocation for the remaining Canadian pension plans were 45% fixed income and 55% equity.
In 2015, we adopted ASU No. 2015-07, “Fair Value Measurement (Topic 820) — Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent).” This ASU removes the requirement to include investments in the fair value hierarchy for which the fair value is measured at Net Asset Value (NAV) using the practical expedient under Topic 820. Below are the details of our pension and OPEB plan assets by class and a description of the valuation methodologies used for assets measured at fair value.
Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are cash, common and preferred stock,equities, exchange traded mutual funds and limited partnerships.MLPs. These investments are valued at the closing price reported on the active market on which the individual securities are traded.
Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are money marketshort-term investment funds, and fixed income securities. Money marketsecurities and derivatives. Short-term investment funds are valued at amortized cost, which approximates fair value. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market. Derivatives are exchange-traded through clearinghouses and are valued based on these prices.
Level 3 assets’ fair values are calculated using valuation techniques that require inputs that are both significant to the fair value measurement and are unobservable, or are similar to Level 2 assets. Included in this level are guaranteed
insurance contracts and interest rate swaps. Insuranceimmediate participation guarantee contracts. These contracts are valued at contract value, which approximates fair value.
Plan assets with fair values that are based on the net asset value per share, or its equivalent (NAV), as reported by the issuers are determined based on the fair value of the underlying securities as of the valuation date and include common/collective trust funds, equity trusts, mutualprivate investment funds, limited partnerships, private equity and fixed income trusts. These amountsThe plan assets measured at NAV are not categorized within the fair value hierarchy described above, but are separately identified in the following tables.
Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value by class and categorized by fair value measurement used at December 31, 20152017 and 20142016 (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Assets |
| | 2015 | | 2014 |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Measured within fair value hierarchy | | | | | | | | | | | | | | | |
| Cash and money market funds | $ | 15 |
| | $ | 110 |
| | $ | — |
| | $ | 125 |
| | $ | 5 |
| | $ | 91 |
|
| $ | — |
| | $ | 96 |
|
| Insurance contracts | — |
| | — |
| | 15 |
| | 15 |
| | — |
| | — |
|
| 15 |
| | 15 |
|
| Mutual funds(a) | 70 |
| | — |
| | — |
| | 70 |
| | 71 |
| | — |
| | — |
| | 71 |
|
| Common and preferred stocks(b) | 271 |
| | — |
| | — |
| | 271 |
| | 459 |
| | — |
|
| — |
| | 459 |
|
| Corporate bonds | — |
| | 244 |
| | — |
| | 244 |
| | — |
| | 247 |
|
| — |
| | 247 |
|
| U.S. government securities | — |
| | 171 |
| | — |
| | 171 |
| | — |
| | 190 |
|
| — |
| | 190 |
|
| Asset backed securities | — |
| | 34 |
| | — |
| | 34 |
| | — |
| | 28 |
|
| — |
| | 28 |
|
| Other | — |
| | — |
| | (14 | ) | | (14 | ) | | — |
| | — |
| | (15 | ) | | (15 | ) |
| Subtotal | $ | 356 |
| | $ | 559 |
| | $ | 1 |
| | 916 |
| | $ | 535 |
| | $ | 556 |
| | $ | — |
| | 1,091 |
|
| Measured at NAV(c) | | | | | | | | | | | | | | | |
| Common/collective trusts(d) | | | | | | | 775 |
| | | | | | | | 863 |
|
| Equity trusts | | | | | | | 187 |
| | | | | | | | 199 |
|
| Mutual funds(e) | | | | | | | 160 |
| | | | | | | | 198 |
|
| Limited partnerships(f) | | | | | | | 1 |
| | | | | | | | 13 |
|
| Private equity(g) | | | | | | | 11 |
| | | | | | | | 13 |
|
| Subtotal |
|
| |
|
| |
|
| | 1,134 |
| |
|
| |
|
| |
|
| | 1,286 |
|
| Total plan assets fair value |
|
| |
|
| |
|
| | $ | 2,050 |
| |
|
| |
|
| |
|
| | $ | 2,377 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Assets |
| | 2017 | | 2016 |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Measured within fair value hierarchy | | | | | | | | | | | | | | | |
| Cash | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
| | $ | 10 |
| | $ | — |
|
| $ | — |
| | $ | 10 |
|
| Short-term investment funds | — |
| | 65 |
| | — |
| | 65 |
| | — |
| | 100 |
|
| — |
| | 100 |
|
| Mutual funds(a) | 245 |
| | — |
| | — |
| | 245 |
| | 197 |
| | — |
| | — |
| | 197 |
|
| Equities(b) | 278 |
| | — |
| | — |
| | 278 |
| | 283 |
| | — |
|
| — |
| | 283 |
|
| Fixed income securities(c) | — |
| | 416 |
| | — |
| | 416 |
| | — |
| | 428 |
|
| — |
| | 428 |
|
| Immediate participation guarantee contract | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| 16 |
| | 16 |
|
| Derivatives | — |
| | 5 |
| | — |
| | 5 |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
| Subtotal | $ | 529 |
| | $ | 486 |
| | $ | — |
| | 1,015 |
| | $ | 490 |
| | $ | 526 |
| | $ | 16 |
| | 1,032 |
|
| Measured at NAV(d) | | | | | | | | | | | | | | | |
| Common/collective trusts(e) | | | | | | | 895 |
| | | | | | | | 829 |
|
| Private investment funds(f) | | | | | | | 337 |
| | | | | | | | 290 |
|
| Private limited partnerships(g) | | | | | | | 49 |
| | | | | | | | 9 |
|
| Subtotal |
|
| |
|
| |
|
| | 1,281 |
| |
|
| |
|
| |
|
| | 1,128 |
|
| Total plan assets fair value |
|
| |
|
| |
|
| | $ | 2,296 |
| |
|
| |
|
| |
|
| | $ | 2,160 |
|
_______
| |
| (a) | For 2015 and 2014, this category includesIncludes mutual funds which are invested in equity. |
| |
| (b) | Plan assets include $91$110 million and $252$126 million of KMI Class P common stock for 20152017 and 2014,2016, respectively. |
| |
| (c) | For 2016, plan assets include $1 million of KMI debt securities. |
| |
| (d) | Plan assets for which fair value was measured using NAV as a practical expedient. |
| |
(d)(e) | Common/collective trust funds were invested in approximately 45%36% fixed income and 55%64% equity in 20152017 and 47%39% fixed income and 53%61% equity in 2014.2016. |
| |
(e)(f) | MutualPrivate investment funds were invested in approximately 52% fixed income for 2015 and 2014. |
| |
(f) | Limited partnerships were invested48% equity in real estate partnerships for 20152017 and 2014.54% fixed income and 46% equity in 2016. |
| |
| (g) | Private equity wasIncludes assets invested in limited partnerships that primarily invest inreal estate, venture and buyout funds for 2015 and 2014.funds. 2016 also includes high yield investments. |
| | | | OPEB Assets | OPEB Assets |
| | 2015 | | 2014 | 2017 | | 2016 |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Measured within fair value hierarchy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and money market funds | $ | — |
| | $ | 16 |
| | $ | — |
| | $ | 16 |
| | $ | (3 | ) | | $ | 26 |
| | $ | — |
| | $ | 23 |
| |
| Domestic equity securities | 8 |
| | — |
| | — |
| | 8 |
| | 14 |
| | — |
| | — |
| | 14 |
| |
| Limited partnerships | 51 |
| | — |
| | — |
| | 51 |
| | 87 |
| | — |
| | — |
| | 87 |
| |
| Insurance contracts | — |
| | — |
| | 49 |
| | 49 |
| | — |
| | — |
| | 51 |
| | 51 |
| |
| Short-term investment funds | | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | 15 |
|
| Equities(a) | | 16 |
| | — |
| | — |
| | 16 |
| | 11 |
| | — |
| | — |
| | 11 |
|
| MLPs | | 50 |
| | — |
| | — |
| | 50 |
| | 57 |
| | — |
| | — |
| | 57 |
|
| Guaranteed insurance contracts | | — |
| | — |
| | 49 |
| | 49 |
| | — |
| | — |
| | 47 |
| | 47 |
|
| Mutual funds | 1 |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
| | 1 |
| 1 |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Subtotal | $ | 60 |
| | $ | 16 |
| | $ | 49 |
| | 125 |
| | $ | 99 |
| | $ | 26 |
| | $ | 51 |
| | 176 |
| $ | 67 |
| | $ | 7 |
| | $ | 49 |
| | 123 |
| | $ | 69 |
| | $ | 15 |
| | $ | 47 |
| | 131 |
|
Measured at NAV(a)(b) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Common/collective trusts(b)(c) | | | | | | | 71 |
| | | | | | | | 71 |
| | | | | | | 68 |
| | | | | | | | 68 |
|
| Fixed income trusts | | | | | | | 58 |
| | | | | | | | 63 |
| | | | | | | 66 |
| | | | | | | | 64 |
|
Limited partnerships(c)(d) | | | | | | | 71 |
| | | | | | | | 79 |
| | | | | | | 78 |
| | | | | | | | 69 |
|
| Subtotal | | | | | | | 200 |
| | | | | | | | 213 |
| | | | | | | 212 |
| | | | | | | | 201 |
|
| Total plan assets fair value |
|
| |
|
| |
|
| | $ | 325 |
| |
|
| |
|
| |
|
| | $ | 389 |
|
|
| |
|
| |
|
| | $ | 335 |
| |
|
| |
|
| |
|
| | $ | 332 |
|
_______
| |
| (a) | Plan assets include $2 million of KMI Class P common stock for each 2017 and 2016. |
| |
| (b) | Plan assets for which fair value was measured using NAV as a practical expedient. |
| |
(b)(c) | For 2015 and 2014, this category includes common/Common/collective trust funds which arewere invested in approximately 67%71% equity and 33%29% fixed income securities respectively.for 2017 and 72% equity and 28% fixed income securities for 2016. |
| |
(c)(d) | For 2015 and 2014, limitedLimited partnerships were invested in global equity securities. |
The following tables present the changes in our pension and OPEB plans’ assets included in Level 3 for the years ended December 31, 20152017 and 20142016 (in millions):
|
| | | | | | | | | | | | | | | | | | | |
| | Pension Assets |
| | Balance at Beginning of Period | | Transfers In (Out) | | Realized and Unrealized Gains (Losses), net | | Purchases (Sales), net | | Balance at End of Period |
| 2015 | | | | | | | | | |
| Insurance contracts | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
| Other | (15 | ) | | — |
| | (2 | ) | | 3 |
| | (14 | ) |
| Total | $ | — |
| | $ | — |
| | $ | (2 | ) | | $ | 3 |
| | $ | 1 |
|
| | | | | | | | | | |
| 2014 | | | | | | | | | |
| Insurance contracts | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
| Other | 11 |
| | — |
| | (18 | ) | | (8 | ) | | (15 | ) |
| Total | $ | 26 |
| | $ | — |
| | $ | (18 | ) | | $ | (8 | ) | | $ | — |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Pension Assets |
| | Balance at Beginning of Period | | Transfers In (Out) | | Realized and Unrealized Gains (Losses), net | | Purchases (Sales), net | | Balance at End of Period |
| 2017 | | | | | | | | | |
| Insurance contracts | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | (16 | ) | | $ | — |
|
| | | | | | | | | | |
| 2016 | | | | | | | | | |
| Insurance contracts | $ | 15 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 16 |
|
| | | | OPEB Assets | OPEB Assets |
| | Balance at Beginning of Period | | Transfers In (Out) | | Realized and Unrealized Gains (Losses), net | | Purchases (Sales), net | | Balance at End of Period | Balance at Beginning of Period | | Transfers In (Out) | | Realized and Unrealized Gains (Losses), net | | Purchases (Sales), net | | Balance at End of Period |
| 2015 | | | | | | | | | | |
| 2017 | | | | | | | | | | |
| Insurance contracts | $ | 51 |
| | $ | — |
| | $ | (1 | ) | | $ | (1 | ) | | $ | 49 |
| $ | 47 |
| | $ | — |
| | $ | 5 |
| | $ | (3 | ) | | $ | 49 |
|
| | | | | | | | | | | | | | | | | | | |
| 2014 | | | | | | | | | | |
| 2016 | | | | | | | | | | |
| Insurance contracts | $ | 50 |
| | $ | — |
| | $ | (4 | ) | | $ | 5 |
| | $ | 51 |
| $ | 49 |
| | $ | — |
| | $ | (2 | ) | | $ | — |
| | $ | 47 |
|
Changes in the underlying value of Level 3 assets due to the effect of changes of fair value were immaterial for the years ended December 31, 20152017 and 2014.2016.
Expected Payment of Future Benefits and Employer Contributions. As of December 31, 2015,2017, we expect to make the following benefit payments under our plans (in millions):
| | | Fiscal year | | Pension Benefits | | OPEB(a) | | Pension Benefits | | OPEB(a) |
| 2016 | | $ | 230 |
| | $ | 39 |
| |
| 2017 | | 197 |
| | 39 |
| |
| 2018 | | 196 |
| | 39 |
| | $ | 244 |
| | $ | 36 |
|
| 2019 | | 198 |
| | 39 |
| | 241 |
| | 36 |
|
| 2020 | | 197 |
| | 38 |
| | 242 |
| | 35 |
|
| 2021-2025 | | 962 |
| | 182 |
| |
| 2021 | | | 232 |
| | 34 |
|
| 2022 | | | 230 |
| | 33 |
|
| 2023 - 2027 | | | 1,029 |
| | 149 |
|
_______
| |
| (a) | Includes a reduction of approximately $32 million in each of the years 20162018 - 20202022 and approximately $1813 million in aggregate for 20212023 - 20252027 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. |
We do not have any statutory funding requirements in 2016 for our pension plan; however, we may decide to make a contribution in 2016 depending on the market performance of our pension plan assets and other factors. In 2016,2018, we expect to contribute approximately $14$30 million to our U.S. pension plans and $7 million, net of anticipated subsidies, to our U.S. OPEB plans. In 2018, we expect to contribute approximately $10 million to our Canadian pension plans and $1 million to our Canadian OPEB plan.
Actuarial Assumptions and Sensitivity Analysis. Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit obligation and net benefit costs of our pension and OPEB plans for 2015, 20142017, 2016 and 2013:2015:
| | | | | Pension Benefits | | OPEB | | Pension Benefits | | OPEB |
| | | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Assumptions related to benefit obligations: | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount rate | | 4.05 | % | | 3.66 | % | | 4.45 | % | | 3.91 | % | | 3.56 | % | | 4.34 | % | | 3.56 | % | | 3.83 | % | | 4.05 | % | | 3.48 | % | | 3.69 | % | | 3.91 | % |
| Rate of compensation increase | | 3.50 | % | | 4.50 | % | | 3.50 | % | | n/a | | n/a | | n/a | | 3.53 | % | | 3.52 | % | | 3.50 | % | | n/a |
| | n/a |
| | n/a |
|
| Assumptions related to benefit costs: | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount rate(a) | | 3.66 | % | | 4.45 | % | | 3.40 | % | | 3.56 | % | | 4.34 | % | | 3.62 | % | |
| Expected return on plan assets(b) | | 7.50 | % | | 7.50 | % | | 8.00 | % | | 7.08 | % | | 7.43 | % | | 7.35 | % | |
| Discount rate for benefit obligations | | | 3.83 | % | | 4.05 | % | | 3.66 | % | | 3.69 | % | | 3.91 | % | | 3.56 | % |
| Discount rate for interest on benefit obligations | | | 3.09 | % | | 3.24 | % | | 3.66 | % | | 3.05 | % | | 3.18 | % | | 3.56 | % |
| Discount rate for service cost | | | 3.88 | % | | 4.15 | % | | 3.66 | % | | 4.15 | % | | 4.36 | % | | 3.56 | % |
| Discount rate for interest on service cost | | | 3.24 | % | | 3.50 | % | | 3.66 | % | | 3.95 | % | | 4.17 | % | | 3.56 | % |
| Expected return on plan assets(a) | | | 7.07 | % | | 7.31 | % | | 7.50 | % | | 6.84 | % | | 7.07 | % | | 7.08 | % |
| Rate of compensation increase | | 4.50 | % | | 3.50 | % | | 3.00 | % | | n/a | | n/a | | n/a | | 3.52 | % | | 3.51 | % | | 4.50 | % | | n/a |
| | n/a |
| | n/a |
|
_______
| |
| (a) | The discount rate related to other postretirement benefit cost was 3.34% for the period from January 1, 2013 to July 31, 2013 (the period prior to an OPEB plan amendment that resulted in a remeasurement) and 4.00% for the period from August 1, 2013 to December 31, 2013. |
| |
(b) | The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the OPEB assets subject to unrelated business income taxes (UBIT), we utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on a UBIT rate of 21% for both 20152017, 2016 and 2014 and 24% for 2013.2015. |
For 2015,Prior to 2016, we selected our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities. Effective January 1, 2016, we changed our estimate of the service and interest cost components of net periodic benefit cost (credit) for our pension and other postretirement benefit plans. The new estimate utilizes a full yield curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The new estimate provides a more precise
measurement of service and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates. The change doesdid not affect the measurement of our pension and postretirement benefit obligations and it iswas accounted for as a change in accounting estimate, which iswas applied prospectively. The change in the service and interest costs going forward will not be significant. The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ investment policy, and capital market projections for the asset classes in which the portfolio is invested and the target weightings of each asset class.
Actuarial estimates for our OPEB plans assumed a weighted-average annual rate of increase in the per capita cost of covered health care benefits of 9.89%7.71%, gradually decreasing to 4.54% by the year 2038. Assumed health care cost trends have a significant effect on the amounts reported for OPEB plans. A one-percentage point change in assumed health care cost trends would have the following effects as of December 31, 20152017 and 20142016 (in millions):
| | | | | 2015 | | 2014 | | 2017 | | 2016 |
| One-percentage point increase: | | | | | | | | |
| Aggregate of service cost and interest cost | | $ | 2 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
| Accumulated postretirement benefit obligation | | 31 |
| | 47 |
| | 22 |
| | 27 |
|
| One-percentage point decrease: | | | | | | | | |
| Aggregate of service cost and interest cost | | $ | (1 | ) | | $ | (2 | ) | | $ | (1 | ) | | $ | (1 | ) |
| Accumulated postretirement benefit obligation | | (27 | ) | | (40 | ) | | (19 | ) | | (23 | ) |
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows (in millions): | | | | | Pension Benefits | | OPEB | | Pension Benefits | | OPEB |
| | | 2015 | | 2014 | | 2013 | | 2015 | | 2014 | | 2013 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Components of net benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 33 |
| | $ | 21 |
| | $ | 25 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 40 |
| | $ | 36 |
| | $ | 33 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
|
| Interest cost | | 99 |
| | 112 |
| | 92 |
| | 21 |
| | 25 |
| | 23 |
| | 88 |
| | 89 |
| | 99 |
| | 13 |
| | 16 |
| | 21 |
|
| Expected return on assets | | (172 | ) | | (171 | ) |
| (175 | ) | | (23 | ) | | (24 | ) | | (22 | ) | | (147 | ) | | (151 | ) |
| (172 | ) | | (19 | ) | | (19 | ) | | (23 | ) |
| Amortization of prior service credit | | — |
| | — |
|
| — |
| | (3 | ) | | (2 | ) | | (1 | ) | |
| Amortization of prior service cost (credit) | | | 1 |
| | 1 |
|
| — |
| | (3 | ) | | (3 | ) | | (3 | ) |
| Amortization of net actuarial loss (gain) | | 5 |
| | — |
| | — |
| | 1 |
| | (1 | ) | | 3 |
| | 52 |
| | 35 |
| | 5 |
| | (6 | ) | | — |
| | 1 |
|
| Curtailment and settlement gain | | — |
| | — |
| | (3 | ) | | — |
| | — |
| | — |
| |
| Curtailment and settlement loss | | | 5 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net benefit (credit) cost | | (35 | ) | | (38 | ) | | (61 | ) | | (4 | ) | | (2 | ) | | 3 |
| | 39 |
| | 10 |
| | (35 | ) | | (14 | ) | | (5 | ) | | (4 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss (gain) arising during period | | 267 |
| | 285 |
| | (211 | ) | | (49 | ) | | 10 |
| | (50 | ) | | 17 |
| | 116 |
| | 267 |
| | (25 | ) | | (48 | ) | | (49 | ) |
| Prior service cost (credit) arising during period | | — |
| | — |
| | 25 |
| | — |
| | — |
| | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Amortization or settlement recognition of net actuarial (loss) gain | | (5 | ) | | — |
| | 3 |
| | (1 | ) | | — |
| | (3 | ) | | (64 | ) | | (34 | ) | | (5 | ) | | 6 |
| | — |
| | (1 | ) |
| Amortization of prior service credit | | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | 1 |
| | (1 | ) | | — |
| | — |
| | 1 |
| | 1 |
| | 1 |
|
| Exchange rate changes | | | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
| Total recognized in total other comprehensive (income) loss | | 262 |
| | 285 |
| | (183 | ) | | (49 | ) | | 11 |
| | (70 | ) | | (48 | ) | | 83 |
| | 262 |
| | (18 | ) | | (47 | ) | | (49 | ) |
| Total recognized in net benefit cost (credit) and other comprehensive (income) loss | | $ | 227 |
| | $ | 247 |
| | $ | (244 | ) | | $ | (53 | ) | | $ | 9 |
| | $ | (67 | ) | | $ | (9 | ) | | $ | 93 |
| | $ | 227 |
| | $ | (32 | ) | | $ | (52 | ) | | $ | (53 | ) |
_______
| |
| (a) | 2017 and 2016 OPEB amounts each include $4 million of net benefit credits related to a plan that we sponsor that is associated with employee services provided to an unconsolidated joint venture. We charge or refund these costs or credits associated with this plan to the joint venture as an offset to our net benefit cost or credit and receive our proportionate share of these costs or credits through our share of the equity investee’s earnings. |
Other Plans
Plans Associated with Foreign Operations
Two of our subsidiaries, Kinder Morgan Canada Inc. and Trans Mountain Pipeline Inc. (as general partner of Trans Mountain Pipeline L.P.) are sponsors of pension plans for eligible Trans Mountain pipeline system employees. The plans include registered defined benefit pension plans, supplemental unfunded arrangements (which provide pension benefits in excess of statutory limits) and defined contributory plans. These subsidiaries also provide postretirement benefits other than pensions for retired employees. Our combined net periodic benefit costs for these Trans Mountain pension and other postretirement benefit plans for the years ended December 31, 2015, 2014 and 2013 was $12 million, $10 million and $11 million, respectively, recognized ratably over each year. As of December 31, 2015, we estimate the overall net periodic pension and other postretirement benefit costs for these plans for the year 2016 will be approximately $10 million, although this estimate could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. Furthermore, we expect to contribute approximately $10 million to these benefit plans in 2016.
Multiemployer Plans
As a result of acquiring several terminal operations, primarily the acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, weWe participate in several multi-employer pension plans for the benefit of employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs. Amounts charged to expense for these plans were approximately $108 million, $138 million and $1110 million for the years ended December 31, 2015, 20142017, 2016 and 2013,2015, respectively. We consider the overall multi-employer pension plan liability exposure to be minimal in relation to the value of its total consolidated assets and net income.
11. Stockholders’ Equity
Common Equity
As of December 31, 2015,2017, our common equity consisted of our Class P common stock.
During the years 2013 through 2015, as authorized byOn July 19, 2017, our board of directors under various repurchase programs, we repurchased shares and warrants. As ofapproved a $2 billion common share buy-back program that began in December 31, 2015, we had $90 million of availability to repurchase warrants.2017. During the yearsyear ended December 31, 2015, 2014 and 2013, we paid a total of $12 million, $98 million and $465 million, respectively, for the repurchase of warrants. During the years ended December 31, 2014 and 2013,2017, we repurchased $94approximately 14 million and $172 million respectively, of our Class P shares.shares for approximately $250 million. Subsequent to December 31, 2017 and through February 8, 2018, we repurchased approximately 13 million of our Class P shares for approximately $250 million.
On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the managers party thereto, as sales agents and/or principals, shares of our Class P common stock having an aggregate offering of up to $5.0 billion from time to time during the term of this agreement. During the years ended December 31, 2017 and 2016 we did not issue any Class P common stock under this agreement. During the year ended December 31, 2015, we issued and sold 102,614,508 shares of our Class P common stock pursuant to the equity distribution agreement resulting in net proceeds of $3.9 billion.
KMI Common Stock Dividends
Holders of our common stock participate in any dividend declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Per common share cash dividend declared for the period | $ | 1.605 |
| | $ | 1.740 |
| | $ | 1.600 |
| $ | 0.50 |
| | $ | 0.50 |
| | $ | 1.605 |
|
| Per common share cash dividend paid in the period | 1.93 |
| | 1.70 |
| | 1.56 |
| 0.50 |
| | 0.50 |
| | 1.93 |
|
On January 20, 2016,17, 2018, our board of directors declared a cash dividend of $0.125 per common share for the quarterly period ended December 31, 2015,2017, which is payable on February 16, 201615, 2018 to shareholders of record as of February 1, 2016.January 31, 2018.
Warrants
EachDuring the year ended December 31, 2015, we paid a total of our$12 million for the repurchases of warrants. The warrant repurchase program dated June 12, 2015, which authorized us to repurchase up to $100 million of warrants, entitlesexpired along with the warrants on May 25, 2017, at which time 293 million of unexercised warrants to buy KMI common stock expired without the issuance of Class P common stock. Prior to expiration, each of the warrants entitled the holder to purchase one share of our common stock for an exercise price of $40 per share, payable in cash or by cashless exercise, at any time until May 25, 2017. The table below sets forth the changes in our outstanding warrants:exercise.
|
| | | | | | | | |
| | Warrants |
| | 2015 | | 2014 | | 2013 |
| Beginning balance | 298,135,976 |
| | 347,933,107 |
| | 439,809,442 |
|
| Warrants issued in acquisition of EP(a) | — |
| | — |
| | 81 |
|
| Warrants issued with conversions of EP Trust I Preferred securities(b) | 1,293,615 |
| | 4,315 |
| | 118,377 |
|
| Warrants exercised | (71,268 | ) | | (18,040 | ) | | (21,208 | ) |
| Warrants repurchased and canceled | (6,094,526 | ) | | (49,783,406 | ) | | (91,973,585 | ) |
| Ending balance | 293,263,797 |
| | 298,135,976 |
| | 347,933,107 |
|
_______
| |
(a) | 2013 amount represents warrants issued upon the settlement of an EP dissenter. The settlement of the dissenter’s 128 EP shares was determined based on the same conversion of EP shares into cash, KMI Class P shares and KMI warrants that was received by other EP shareholders at the time of the acquisition. |
Mandatory Convertible Preferred Stock
On October 30, 2015, we completed an offering of 32,000,000 depositary shares, each of which represents a 1/20th interest in a share of our 1,600,000 shares of 9.75% Series A mandatory convertible preferred stock, with a liquidating preference of $1,000 per share (equal to a $50 liquidation preference per depositary share). Net proceeds, after underwriting discount and
expenses, from the depositary share offering were approximately $1,541 million. The proceeds from the offering were used to repay borrowings under our revolving credit facility and commercial paper debt and for general corporate purposes.
Unless converted earlier at the option of the holders, on or around October 26, 2018, each share of convertible preferred stock will automatically convert into between 30.8800 and 36.2840 shares of our common stock (and, correspondingly, each depositary share will convert into between 1.5440 and 1.8142 shares of our common stock), subject to customary anti-dilution adjustments. The conversion range depends on the volume-weighted average price of our common stock over a 20 trading day averaging period immediately prior to that date (Applicable Market Value). If the Applicable Market Value for our common stock is greater than $32.38 or less than $27.56, the conversion rate per preferred stock will be 30.8800 or 36.2840, respectively. If the Applicable Market Value is between $32.38 and $27.56, the conversion rate per preferred stock will be between 30.8800 and 36.2840.
Preferred Stock Dividends
Dividends on our mandatory convertible preferred stock are payable on a cumulative basis when, as and if declared by our board of directors (or an authorized committee thereof) at an annual rate of 9.75% of the liquidation preference of $1,000 per share on January 26, April 26, July 26 and October 26 of each year, commencing on January 26, 2016 to, and including, October 26, 2018. We may pay dividends in cash or, subject to certain limitations, in shares of common stock or any combination of cash and shares of common stock. The terms of the mandatory convertible preferred stock provide that, unless full cumulative dividends have been paid or set aside for payment on all outstanding mandatory convertible preferred stock for all prior dividend periods, no dividends may be declared or paid on common stock. The following table provides information regarding our preferred stock dividends:
|
| | | | | | | | |
| Period | | Total dividend per share for the period | | Date of declaration | | Date of record | | Date of dividend |
| January 26, 2017 through April 25, 2017 | | $24.375 | | January 18, 2017 | | April 11, 2017 | | April 26, 2017 |
| April 26, 2017 through July 25, 2017 | | 24.375 | | April 19, 2017 | | July 11, 2017 | | July 26, 2017 |
| July 26, 2017 through October 25, 2017 | | 24.375 | | July 19, 2017 | | October 11, 2017 | | October 26, 2017 |
| October 26, 2017 through January 25, 2018 | | 24.375 | | October 18, 2017 | | January 11, 2018 | | January 26, 2018 |
The cash dividend of $24.375 per share of our mandatory convertible preferred stock is equivalent to $1.21875 per depository share.
Noncontrolling Interests
KML Restricted Voting Shares
As discussed in Note 3 “Acquisitions and Divestitures,” on May 30, 2017 our indirect subsidiary, KML, issued 102,942,000 restricted voting shares in a public offering listed on the Toronto Stock Exchange. The public ownership of the KML restricted voting shares represents an approximate 30% interest in our Canadian operations and is reflected within “Noncontrolling interests” in our consolidated financial statements as of and for the period presented after May 30, 2017.
KML Preferred Share Offerings
On August 15, 2017, KML completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 1 Preferred Share for total gross proceeds of C$300 million (U.S.$235 million). On December 15, 2017, KML completed an offering of 10,000,000 cumulative redeemable minimum rate reset preferred shares, Series 3 (Series 3 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 3 Preferred Share for total gross proceeds of C$250 million (U.S.$195 million). The net proceeds from the Series 1 and Series 3 Preferred Share offerings of C$293 million (U.S. $230 million) and C$243 million (U.S.$189 million), respectively, were used by KML to indirectly subscribe for preferred units in KMC LP, which in turn were used by KMC LP to repay the KML Credit Facility indebtedness recently incurred to, directly or indirectly, finance the development, construction and completion of the TMEP and Base Line Terminal project, and for its general corporate purposes.
KML Distributions
KML established a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its DCF. The payment of dividends is not guaranteed and the amount and timing of any dividends payable will be at the discretion of KML’s board of directors. If declared by KML’s board of directors, KML will pay quarterly dividends, on or about the 45th day (or next business day) following the end of each calendar quarter to holders of its restricted voting shares of record as of the close of business on or about the last business day of the month following the end of each calendar quarter. KML also established a Dividend Reinvestment Plan (DRIP) which allows holders (excluding holders not resident in Canada) of restricted voting shares to elect to have any or all cash dividends payable to such shareholder automatically reinvested in additional restricted voting shares at a price per share calculated by reference to the volume-weighted average of the closing price of the restricted voting shares on the stock exchange on which the restricted voting shares
are then listed for the five trading days immediately preceding the relevant dividend payment date, less a discount of between 0% and 5% (as determined from time to time by KML’s board of directors, in its sole discretion).
Dividends on the Series 1 Preferred Shares are fixed, cumulative, preferential and C$1.3125 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding November 15, 2022.
Dividends on the Series 3 Preferred Shares are fixed, cumulative, preferential and C$1.3000 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding February 15, 2023.
The following table provides information regarding distributions to our noncontrolling interests (in millions except per share and share distribution amounts):
|
| | | | | | |
| | | Year Ended December 31, 2017 |
| | | Shares | | U.S.$ | | C$ |
| KML Restricted Voting Shares(a) | | | | | | |
| Per restricted voting share declared for the period(b) | | | | | | $0.3821 |
| Per restricted voting share paid in the period | | | | $0.1739 | | 0.2196 |
| Total value of distributions paid in the period | | | | 18 | | 23 |
| Cash distributions paid in the period to the public | | | | 13 | | 16 |
| Share distributions paid in the period to the public under KML’s DRIP | | 418,989 | | | | |
| KML Series 1 Preferred Shares(c) | | | | | | |
| Per Series 1 Preferred Share paid in the period | | | | $0.2624 | | $0.3308 |
| Cash distributions paid in the period to the public | | | | 3 | | 4 |
_______
| |
| (a) | Represents dividends subsequent to KML’s May 30, 2017 IPO. |
| |
| (b) | The U.S.$ equivalent of the dividends declared is calculated based on the exchange rate on the dividend payment date, therefore, the U.S.$ equivalent of the dividend declared for the fourth quarter of 2017 will be calculated using the exchange rate on February 15, 2018. |
The combined U.S.$ equivalent of the dividends declared for the second and third quarters of 2017 was $0.1739.
| |
| (c) | Represents dividends subsequent to the issuance of KML’s Series 1 Preferred Shares. |
On January 17, 2015, our2018, KML’s board of directors declared a cash dividend of $23.291667C$0.328125 per share of our mandatory convertible preferred stock (equivalent of $1.164583 per depository share)its Series 1 Preferred Shares for the period from and including October 30, 2015November 15, 2017 through and including January 25, 2016,February 14, 2018, which was paidis payable on January 26, 2016February 15, 2018 to mandatory convertible preferred shareholdersSeries 1 Preferred Shareholders of record as of the close of business on January 11, 2016.31, 2018.
Noncontrolling InterestsOn January 17, 2018, KML’s board of directors declared a cash dividend of C$0.22082 per share of its Series 3 Preferred Shares for the period from and including December 15, 2017 through and including February 14, 2018, which is payable on February 15, 2018 to Series 3 Preferred Shareholders of record as of the close of business on January 31, 2018.
Contributions
Prior to the completion of the Merger Transactions on November 26, 2014, contributions from our noncontrolling interests consisted primarily of equity issuances to the public of common units or shares by KMP, EPB and KMR. Each of these subsidiaries had an equity distribution agreement in place which allowed the subsidiary to sell its equity interests from time to time through a designated sales agent. The equity distribution agreement provided the subsidiary with the right, but not the obligation to offer and sell its equity units or shares, at prices to be determined by market conditions. For the periods ended November 26, 2014 and December 31, 2013, KMP, EPB and KMR made equity issuances of 30 million and 63 million units or shares, respectively, resulting in net proceeds of $1,695 million and $1,580 million, respectively. These equity issuances during the periods ended November 26, 2014 and December 31, 2013 had the associated effects of increasing our (i) noncontrolling interests by $1,640 million and $5,059 million, respectively; (ii) accumulated deferred income taxes by $19 million and $93 million, respectively; and (iii) additional paid-in capital by $36 million and $161 million, respectively.
Distributions
The following table provides information about distributions from our noncontrolling interests (in millions except per unit and i-unit distribution amounts):
|
| | | | | | | |
| | Year Ended December 31, |
| | 2014 | | 2013 |
| KMP(a) | | | |
| Per unit cash distribution declared for the period | $ | 4.17 |
| | $ | 5.33 |
|
| Per unit cash distribution paid in the period | $ | 5.53 |
| | $ | 5.26 |
|
| Cash distributions paid in the period to the public | $ | 1,654 |
| | $ | 1,372 |
|
| EPB(a) | | | |
| Per unit cash distribution declared for the period | $ | 1.95 |
| | $ | 2.55 |
|
| Per unit cash distribution paid in the period | $ | 2.60 |
| | $ | 2.51 |
|
| Cash distributions paid in the period to the public | $ | 347 |
| | $ | 318 |
|
| KMR(a)(b) | | | |
| Share distributions paid in the period to the public | 7,794,183 |
| | 6,588,477 |
|
_______
| |
(a) | As a result of the Merger Transactions, no distribution was declared starting with the fourth quarter of 2014. |
| |
(b) | KMR’s distributions were paid in the form of additional shares or fractions thereof calculated by dividing the KMP cash distribution per common unit by the average of the market closing prices of a KMR share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Represents share distributions made in the period to noncontrolling interests and excludes 1,127,712 and 976,723 of shares distributed in 2014 and 2013, respectively, on KMR shares we directly and indirectly owned.
|
12. Related Party Transactions
Affiliate Balances
We have transactions with affiliates which consist of (i) unconsolidated affiliates in which we hold an investment accounted for under the equity method of accounting (see Note 7 “Investments” for additional information related to these investments); and (ii) external joint venture partners of our proportional method joint ventures, for which we include our proportionate share of balances and activity in our financial statements. The following tables summarize our affiliate balance sheet balances and income statement activity (in millions):
|
| | | | | | | |
| | December 31, |
| | 2015 | | 2014 |
| Balance sheet location | | | |
| Accounts receivable, net | $ | 25 |
| | $ | 31 |
|
| Other current assets | 36 |
| | 3 |
|
| Deferred charges and other assets | — |
| | 46 |
|
| | $ | 61 |
| | $ | 80 |
|
| | | | |
| Current portion of debt(a) | $ | 6 |
| | $ | 6 |
|
| Accounts payable | 22 |
| | 22 |
|
| Other current liabilities | 10 |
| | — |
|
| Long-term debt(a) | 167 |
| | 172 |
|
| | $ | 205 |
| | $ | 200 |
|
_______
| |
(a) | Includes financing obligations payable to WYCO (See Note 9). |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Income statement location | | | | | |
| Services | $ | 72 |
| | $ | 29 |
| | $ | 31 |
|
| Product sales and other | 71 |
| | 86 |
| | 36 |
|
| | $ | 143 |
| | $ | 115 |
| | $ | 67 |
|
| | | | | | |
| Cost of sales | $ | 60 |
| | $ | 74 |
| | $ | 17 |
|
| General and administrative | 55 |
| | 57 |
| | 57 |
|
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| Balance sheet location | | | |
| Accounts receivable, net | $ | 34 |
| | $ | 37 |
|
| Other current assets | 8 |
| | — |
|
| Deferred charges and other assets | 23 |
| | 10 |
|
| | $ | 65 |
| | $ | 47 |
|
| | | | |
| Current portion of debt | $ | 6 |
| | $ | 6 |
|
| Accounts payable | 18 |
| | 28 |
|
| Other current liabilities | 4 |
| | 9 |
|
| Long-term debt | 155 |
| | 161 |
|
| Other long-term liabilities and deferred credits | 35 |
| | 29 |
|
| | $ | 218 |
| | $ | 233 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Income statement location | | | | | |
| Revenues | | | | | |
| Services | $ | 73 |
| | $ | 71 |
| | $ | 72 |
|
| Product sales and other | 89 |
| | 71 |
| | 71 |
|
| | $ | 162 |
| | $ | 142 |
| | $ | 143 |
|
| | | | | | |
| Operating Costs, Expenses and Other | | | | | |
| Costs of sales | $ | 20 |
| | $ | 38 |
| | $ | 60 |
|
| Other operating expenses | 100 |
| | 75 |
| | 55 |
|
Notes Receivable
Plantation
We and ExxonMobil Corporation have a term loan agreement covering a note receivable due from Plantation. We own a 51.17% equity interest in Plantation and our proportionate share of the outstanding principal amount of the note receivable was $35 million and $47 million as of December 31, 2015 and 2014, respectively. The note bears interest at the rate of 4.25% per annum and provides for semiannual payments of principal and interest on December 31 and June 30 each year, with a final principal payment for our remaining portion of the note due on July 20, 2016. We included $35 million and $1 million of the note receivable balance within “Other current assets” on our accompanying balance sheets as of December 31, 2015 and 2014, respectively, and we included $46 million as of December 31, 2014 within “Deferred charges and other assets.”
Subsequent Event
MEP Loan Agreement
On February 3, 2016 we renewed our loan agreement for an additional one-year term with MEP, our 50%-owned equity investee. The loan agreement allows us, at our sole option, to make loans from time to time to MEP to fund its working capital needs and for other LLC purposes. Each individual loan must be in an amount not less than $2 million, and the aggregate loan balance outstanding must not exceed $40 million. Borrowings under the loan agreement bear interest at a rate of one month LIBOR plus 1.50%, and all borrowings can be prepaid before maturity without penalty or premium. As of both December 31, 2015 and 2014 there was no amount outstanding pursuant to this loan agreement.
13. Commitments and Contingent Liabilities
Leases and Rights-of-Way Obligations
The table below depicts future gross minimum rental commitments under our operating leases and rights-of-way obligations as of December 31, 20152017 (in millions):
| | | Year | | Commitment | | Commitment |
| 2016 | | $ | 103 |
| |
| 2017 | | 90 |
| |
| 2018 | | 83 |
| | $ | 118 |
|
| 2019 | | 78 |
| | 106 |
|
| 2020 | | 69 |
| | 81 |
|
| 2021 | | | 62 |
|
| 2022 | | | 55 |
|
| Thereafter | | 406 |
| | 300 |
|
| Total minimum payments | | $ | 829 |
| | $ | 722 |
|
The remaining terms on our operating leases, including probable elections to exercise renewal options, range from one to fortyforty-one years. Total lease and rental expenses were $143140 million, $114138 million and $126143 million for the years ended December 31, 20152017, 20142016 and 20132015, respectively. The amount of capital leases included within “Property, plant and equipment, net” in our accompanying consolidated balance sheets as of December 31, 20152017 and 20142016 is not material to our consolidated balance sheets.
Contingent Debt
Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote.
As of December 31, 20152017 and 2014,2016, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $1,202$1,070 million and $1,069$1,179 million, respectively. Both December 31, 20152017 and 20142016 amounts are primarily represented by our proportional share of the debt obligations of two equity investees. Under such guarantees we are severally liable for our percentage ownership share of these equity investees’ debt issued in the event of their non-performance. Also included in our contingent debt obligations is a guarantee of thea throughput and deficiency agreement supporting certain debt obligations of a subsidiary of our50%-owned investee, Cortez Pipeline Company (weCompany. Through this guarantee, we are severally liable for its percentage ownership share (50%)50% of thea Cortez Pipeline Company subsidiary’s debt obligations with respect to a $50 million credit facility and $100 million in bonds. In addition, we have guaranteed 100% of the debt issued by oneanother Cortez Pipeline Company subsidiary to fund an expansion project, of its subsidiaries in the eventwhich debt consists of their non-performance) which has a $200$50 million credit facility and a $120 million private placement note to fund an expansion project.note.
Guarantees and Indemnifications
We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.
While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are also circumstances where the amount and duration are unlimited. Currently, we are not subject to any material requirements to perform under quantifiable arrangements, and we expect future requirements to perform under quantifiable arrangements will be immaterial. We are unable to estimate a maximum exposure for our guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.
See Note 17 “Litigation, Environmental and Other Contingencies” for a description of matters that we have identified as contingencies requiring accrual of liabilities and/or disclosure, including any such matters arising under guarantee or indemnification agreements.
Commitment for Jones Act Trade Fleet Expansion
In August 2015, we entered into a definitive agreement with Philly Tankers LLC totaling $568 million for the construction of four new Tier II, LNG-conversion-ready tankers each with a capacity of 337 MBbl. The tankers are expected to be delivered between November 2016 and November 2017 and would increase our Jones Act tanker fleet to 16 ships by late 2017. Our obligation for payments due under the terms of this agreement total $170 million in 2016 and $384 million in 2017.
14. Risk Management
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to certainsome of these risks. In addition, prior to May 2016, we havehad legacy power forward and swap contracts related to legacy operations of acquired businesses for which we entered into positions that offset the price risks associated with these contracts.businesses.
As of December 31, 2014, we discontinued hedge accounting on certain of our crude derivative contracts as we did not expect them to continue to be highly effective, for accounting purposes, in offsetting the variability in cash flows. This was caused primarily by volatility in basis differentials. As the forecasted transactions are still probable, accumulated gains and losses remain in other comprehensive income until earnings are impacted by the forecasted transactions. Changes in the derivative contracts’ fair value subsequent to the discontinuance of hedge accounting are reported in earnings. As of December 31, 2015, all of these hedging relationships had been re-designated as the effectiveness improved to required levels.
Energy Commodity Price Risk Management
As of December 31, 2015,2017, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
|
| | | |
| | Net open position long/(short) |
| Derivatives designated as hedging contracts | | |
| Crude oil fixed price | (21.721.0 | ) | MMBbl |
| Crude oil basis | (6.47.2 | ) | MMBbl |
| Natural gas fixed price | (37.646.4 | ) | Bcf |
| Natural gas basis | (30.121.7 | ) | Bcf |
| Derivatives not designated as hedging contracts | |
| |
| Crude oil fixed price | (0.61.9 | ) | MMBbl |
| Crude oil basis | (1.31.2 | ) | MMBbl |
| Natural gas fixed price | (14.39.0 | ) | Bcf |
| Natural gas basis | (8.623.1 | ) | Bcf |
NGL and other fixed price | (1.94.1 | ) | MMBbl |
As of December 31, 2015,2017, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2019.2021.
Interest Rate Risk Management
As of December 31, 20152017, and December 31, 2016, we had a combined notional principal amount of $11,000$9,575 million of fixed-to-variable interest rate swap agreements, of which $9,700and $9,775 million, were designated as fair value hedges. As of December 31, 2014, we had a combined notional principal amount of $9,200 millionrespectively, of fixed-to-variable interest rate swap agreements, all of which were designated as fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of December 31, 20152017, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035.
In December 2015, we entered into nine separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $1,300 million. These agreements effectively convert a portion of the interest expense associated with our 4.15% senior notes due February 2, 2024, 3.50% senior notes due September 1, 2023 and 4.30% senior notes due May 1, 2024, from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread.
Foreign Currency Risk Management
In connection with the issuanceAs of our Euro denominated senior notes in March 2015 (see Note 9),both December 31, 2017 and 2016, we entered intohad a notional principal amount of $1,358 million of cross-currency swap agreements to manage the related foreign currency risk related to our Euro denominated senior notes by effectively converting all of the fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates equivalent to approximately 3.79% and 4.67% for the 7-year and 12-year senior notes, respectively. These cross-currency swaps are accounted for as cash flow hedges. The terms of the cross-currency swap agreements correspond to the related hedged senior notes, and such agreements have the same maturities as the hedged senior notes.
Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets (in millions):
|
| | | | | | | | | | | | | | | | | |
| Fair Value of Derivative Contracts |
| | | | Asset derivatives | | Liability derivatives |
| | | | December 31, | | December 31, |
| | | | 2015 | | 2014 | | 2015 | | 2014 |
| | Location | | Fair value | | Fair value |
Derivatives designated as hedging contracts | | | | | | | | | |
| Natural gas and crude derivative contracts | Fair value of derivative contracts/(Other current liabilities) | | $ | 359 |
| | $ | 309 |
| | $ | (13 | ) | | $ | (34 | ) |
| | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 244 |
| | 6 |
| | — |
| | — |
|
| Subtotal | | | 603 |
| | 315 |
| | (13 | ) | | (34 | ) |
| Interest rate swap agreements | Fair value of derivative contracts/(Other current liabilities) | | 111 |
| | 143 |
| | — |
| | — |
|
| | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 273 |
| | 260 |
| | (9 | ) | | (53 | ) |
| Subtotal | | | 384 |
| | 403 |
| | (9 | ) | | (53 | ) |
| Cross-currency swap agreements | Fair value of derivative contracts/(Other current liabilities) | | — |
| | — |
| | (6 | ) | | — |
|
| | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | — |
| | — |
| | (46 | ) | | — |
|
| Subtotal | | | — |
| | — |
| | (52 | ) | | — |
|
| Total | | | 987 |
| | 718 |
| | (74 | ) | | (87 | ) |
Derivatives not designated as hedging contracts | | | |
| | |
| | |
| | |
|
| Natural gas, crude, NGL and other derivative contracts | Fair value of derivative contracts/(Other current liabilities) | | 35 |
| | 73 |
| | (1 | ) | | (2 | ) |
| | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | — |
| | 196 |
| | — |
| | — |
|
| Subtotal | | | 35 |
| | 269 |
| | (1 | ) | | (2 | ) |
| Interest rate swap agreements | Fair value of derivative contracts/(Other current liabilities) | | 1 |
| | — |
| | (11 | ) | | — |
|
| | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | — |
| | — |
| | (5 | ) | | — |
|
| Subtotal | | | 1 |
| | — |
| | (16 | ) | | — |
|
| Power derivative contracts | Fair value of derivative contracts/(Other current liabilities) | | 1 |
| | 10 |
| | (17 | ) | | (57 | ) |
| | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | — |
| | — |
| | — |
| | (16 | ) |
| Subtotal | | | 1 |
| | 10 |
| | (17 | ) | | (73 | ) |
| Total | | | 37 |
| | 279 |
| | (34 | ) | | (75 | ) |
| Total derivatives | | | $ | 1,024 |
| | $ | 997 |
| | $ | (108 | ) | | $ | (162 | ) |
Effect of Derivative Contracts on the Income Statement
The following tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income (in millions):
|
| | | | | | | | | | | | | | |
| Derivatives in fair value hedging relationships | | Location | | Gain/(loss) recognized in income on derivatives and related hedged item |
| | | | | Year Ended December 31, |
| | | | | 2015 | | 2014 | | 2013 |
| Interest rate swap agreements | | Interest, net | | $ | 25 |
| | $ | 207 |
| | $ | (425 | ) |
| | | | | | | | | |
| Hedged fixed rate debt | | Interest, net | | $ | (33 | ) | | $ | (204 | ) | | $ | 425 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivatives in cash flow hedging relationships | | Gain/(loss) recognized in OCI on derivative (effective portion)(a) | | Location | | Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b) | | Location | | Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) |
| | | Year Ended | | | | Year Ended | | | | Year Ended |
| | | December 31, | | | | December 31, | | | | December 31, |
| | | 2015 | | 2014 | | 2013 | | | | 2015 | | 2014 | | 2013 | | | | 2015 | | 2014 | | 2013 |
| Energy commodity derivative contracts | | $ | 201 |
| | $ | 424 |
| | $ | (45 | ) | | Revenues—Natural gas sales | | $ | 54 |
| | $ | (1 | ) | | $ | — |
| | Revenues—Natural gas sales | | $ | — |
| | $ | — |
| | $ | — |
|
| | | |
| | |
| | | | Revenues—Product sales and other | | 236 |
| | 26 |
| | (13 | ) | | Revenues—Product sales and other | | 2 |
| | 11 |
| | 3 |
|
| | | |
| | |
| | | | Costs of sales | | (15 | ) | | 4 |
| | — |
| | Costs of sales | | — |
| | — |
| | — |
|
| Interest rate swap agreements(c) | | (4 | ) | | (15 | ) | | 7 |
| | Interest, net | | (3 | ) | | (4 | ) | | 2 |
| | Interest, net | | — |
| | — |
| | — |
|
| Cross-currency swap | | (33 | ) | | — |
| | — |
| | Other, net | | — |
| | — |
| | — |
| | Other, net | | — |
| | — |
| | — |
|
| Total | | $ | 164 |
| | $ | 409 |
| | $ | (38 | ) | | Total | | $ | 272 |
| | $ | 25 |
| | $ | (11 | ) | | Total | | $ | 2 |
| | $ | 11 |
| | $ | 3 |
|
_______
| |
(a) | We expect to reclassify an approximate $181 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of December 31, 2015 into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur), however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
|
| |
(b) | Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred). |
| |
(c) | Amounts represent our share of an equity investee’s accumulated other comprehensive income/(loss). |
|
| | | | | | | | | | | | | | |
| Derivatives not designated as accounting hedges | | Location | | Gain/(loss) recognized in income on derivatives |
| | | | | Year Ended December 31, |
| | | | | 2015 | | 2014 | | 2013 |
| Energy commodity derivative contracts | | Revenues—Natural gas sales | | $ | 17 |
| | $ | (7 | ) | | $ | — |
|
| | | Revenues—Product sales and other | | 176 |
| | 20 |
| | (10 | ) |
| | | Costs of sales | | (2 | ) | | — |
| | 2 |
|
| | | Other expense (income) | | — |
| | (2 | ) | | (2 | ) |
| Interest rate swap agreements | | Interest, net | | (15 | ) | | — |
| | — |
|
| Total(a) | | | | $ | 176 |
| | $ | 11 |
| | $ | (10 | ) |
________
(a) For the year ended December 31, 2015, includes approximate gain of $31 million associated with natural gas, crude and NGL derivative contract settlements.
Credit Risks
In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2015 and 2014, we had $2 million and $20 million, respectively, of outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2015 and December 31, 2014, we had no cash margin and $47 million posted by us with our counterparties as collateral and $37 million and $13 million, respectively, held by us as collateral from our counterparties.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of December 31, 2015, based on our current mark to market positions and posted collateral, we estimate that if our credit rating was downgraded one or two notches, we would be required to post $1 million and $4 million, respectively, of additional collateral.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss
Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions):
|
| | | | | | | | | | | | | | | |
| | Net unrealized gains/(losses) on cash flow hedge derivatives | | Foreign currency translation adjustments | | Pension and other postretirement liability adjustments | | Total Accumulated other comprehensive loss |
| Balance as of December 31, 2012 | $ | 7 |
| | $ | 51 |
| | $ | (176 | ) | | $ | (118 | ) |
| Other comprehensive income before reclassifications | (14 | ) | | (49 | ) | | 151 |
| | 88 |
|
| Amounts reclassified from accumulated other comprehensive loss | 4 |
| | — |
| | 2 |
| | 6 |
|
| Net current-period other comprehensive income | (10 | ) | | (49 | ) | | 153 |
| | 94 |
|
| Balance as of December 31, 2013 | (3 | ) | | 2 |
| | (23 | ) | | (24 | ) |
| Other comprehensive loss before reclassifications | 254 |
| | (68 | ) | | (212 | ) | | (26 | ) |
| Amounts reclassified from accumulated other comprehensive loss | (22 | ) | | — |
| | (1 | ) | | (23 | ) |
| Impact of Merger Transactions (See Note 1) | 98 |
| | (42 | ) | | — |
| | 56 |
|
| Net current-period other comprehensive income | 330 |
| | (110 | ) | | (213 | ) | | 7 |
|
| Balance as of December 31, 2014 | 327 |
| | (108 | ) | | (236 | ) | | (17 | ) |
| Other comprehensive loss before reclassifications | 164 |
| | (214 | ) | | (122 | ) | | (172 | ) |
| Amounts reclassified from accumulated other comprehensive loss | (272 | ) | | — |
| | — |
| | (272 | ) |
| Net current-period other comprehensive loss | (108 | ) | | (214 | ) | | (122 | ) | | (444 | ) |
| Balance as of December 31, 2015 | $ | 219 |
| | $ | (322 | ) | | $ | (358 | ) | | $ | (461 | ) |
15. Fair Value
The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.
The three broad levels of inputs defined by the fair value hierarchy are as follows:
Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;
Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).
Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets (in millions):
|
| | | | | | | | | | | | | | | | | |
| Fair Value of Derivative Contracts |
| | | | Asset derivatives | | Liability derivatives |
| | | | December 31, | | December 31, |
| | | | 2017 | | 2016 | | 2017 | | 2016 |
| | Location | | Fair value | | Fair value |
Derivatives designated as hedging contracts | | | | | | | | | |
| Energy commodity derivative contracts | Fair value of derivative contracts/(Other current liabilities) | | $ | 65 |
| | $ | 101 |
| | $ | (53 | ) | | $ | (57 | ) |
| | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 14 |
| | 70 |
| | (24 | ) | | (24 | ) |
| Subtotal | | | 79 |
| | 171 |
| | (77 | ) | | (81 | ) |
| Interest rate swap agreements | Fair value of derivative contracts/(Other current liabilities) | | 41 |
| | 94 |
| | (3 | ) | | — |
|
| | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 164 |
| | 206 |
| | (62 | ) | | (57 | ) |
| Subtotal | | | 205 |
| | 300 |
| | (65 | ) | | (57 | ) |
| Cross-currency swap agreements | Fair value of derivative contracts/(Other current liabilities) | | — |
| | — |
| | (6 | ) | | (7 | ) |
| | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 166 |
| | — |
| | — |
| | (24 | ) |
| Subtotal | | | 166 |
| | — |
| | (6 | ) | | (31 | ) |
| Total | | | 450 |
| | 471 |
| | (148 | ) | | (169 | ) |
Derivatives not designated as hedging contracts | | | |
| | |
| | |
| | |
|
| Energy commodity derivative contracts | Fair value of derivative contracts/(Other current liabilities) | | 8 |
| | 3 |
| | (22 | ) | | (29 | ) |
| | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | — |
| | — |
| | (2 | ) | | (1 | ) |
| Total | | | 8 |
| | 3 |
| | (24 | ) | | (30 | ) |
| Total derivatives | | | $ | 458 |
| | $ | 474 |
| | $ | (172 | ) | | $ | (199 | ) |
Effect of Derivative Contracts on the Income Statement
The following tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income (in millions):
|
| | | | | | | | | | | | | | |
| Derivatives in fair value hedging relationships | | Location | | Gain/(loss) recognized in income on derivatives and related hedged item |
| | | | | Year Ended December 31, |
| | | | | 2017 | | 2016 | | 2015 |
| Interest rate swap agreements | | Interest, net | | $ | (103 | ) | | $ | (180 | ) | | $ | 25 |
|
| | | | | | | | | |
| Hedged fixed rate debt | | Interest, net | | $ | 105 |
| | $ | 160 |
| | $ | (33 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivatives in cash flow hedging relationships | | Gain/(loss) recognized in OCI on derivative (effective portion)(a) | | Location | | Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b) | | Location | | Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) |
| | | Year Ended | | | | Year Ended | | | | Year Ended |
| | | December 31, | | | | December 31, | | | | December 31, |
| | | 2017 | | 2016 | | 2015 | | | | 2017 | | 2016 | | 2015 | | | | 2017 | | 2016 | | 2015 |
| Energy commodity derivative contracts | | $ | 24 |
| | $ | (115 | ) | | $ | 201 |
| | Revenues—Natural gas sales | | $ | 12 |
| | $ | 15 |
| | $ | 54 |
| | Revenues—Natural gas sales | | $ | — |
| | $ | — |
| | $ | — |
|
| | | |
| | |
| | | | Revenues—Product sales and other | | 35 |
| | 148 |
| | 236 |
| | Revenues—Product sales and other | | 11 |
| | (12 | ) | | 2 |
|
| | | |
| | |
| | | | Costs of sales | | 9 |
| | (17 | ) | | (15 | ) | | Costs of sales | | — |
| | — |
| | — |
|
| Interest rate swap agreements(c) | | — |
| | (2 | ) | | (4 | ) | | Interest, net | | (3 | ) | | (3 | ) | | (3 | ) | | Interest, net | | — |
| | — |
| | — |
|
| Cross-currency swap | | 121 |
| | 13 |
| | (33 | ) | | Other, net | | 118 |
| | (27 | ) | | — |
| | Other, net | | — |
| | — |
| | — |
|
| Total | | $ | 145 |
| | $ | (104 | ) | | $ | 164 |
| | Total | | $ | 171 |
| | $ | 116 |
| | $ | 272 |
| | Total | | $ | 11 |
| | $ | (12 | ) | | $ | 2 |
|
_______
| |
| (a) | We expect to reclassify an approximate $1 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of December 31, 2017 into earnings during the next twelve months (when the associated forecasted transactions are also expected to occur), however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices. |
| |
| (b) | Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred). |
| |
| (c) | Amounts represent our share of an equity investee’s accumulated other comprehensive loss. |
|
| | | | | | | | | | | | | | |
| Derivatives not designated as accounting hedges | | Location | | Gain/(loss) recognized in income on derivatives |
| | | | | Year Ended December 31, |
| | | | | 2017 | | 2016 | | 2015 |
| Energy commodity derivative contracts | | Revenues—Natural gas sales | | $ | 20 |
| | $ | (10 | ) | | $ | 17 |
|
| | | Revenues—Product sales and other | | (16 | ) | | (26 | ) | | 176 |
|
| | | Costs of sales | | — |
| | 3 |
| | (2 | ) |
| Interest rate swap agreements | | Interest, net | | — |
| | 63 |
| | (15 | ) |
| Total(a) | | | | $ | 4 |
| | $ | 30 |
| | $ | 176 |
|
________
(a) For the years ended December 31, 2017, 2016 and 2015 includes approximate gains of $57 million, $73 million and $31 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.
Credit Risks
In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2017 and 2016, we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2017 and December 31, 2016, we had cash margins of $1 million and $37 million, respectively, posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets. The balance at December 31, 2017, consisted of initial margin requirements of $13 million, offset by variation margin requirements of $12 million. We also use industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of December 31, 2017, based on our current mark to market positions and posted collateral, we estimate that if our credit rating were downgraded one notch we would be required to post $31 million of additional collateral and no additional collateral beyond this $31 million if we were downgraded two notches.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss
Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions):
|
| | | | | | | | | | | | | | | |
| | Net unrealized gains/(losses) on cash flow hedge derivatives | | Foreign currency translation adjustments | | Pension and other postretirement liability adjustments | | Total Accumulated other comprehensive loss |
| Balance as of December 31, 2014 | $ | 327 |
| | $ | (108 | ) | | $ | (236 | ) | | $ | (17 | ) |
| Other comprehensive gain (loss) before reclassifications | 164 |
| | (214 | ) | | (122 | ) | | (172 | ) |
| Gains reclassified from accumulated other comprehensive loss | (272 | ) | | — |
| | — |
| | (272 | ) |
| Net current-period other comprehensive loss | (108 | ) | | (214 | ) | | (122 | ) | | (444 | ) |
| Balance as of December 31, 2015 | 219 |
| | (322 | ) | | (358 | ) | | (461 | ) |
| Other comprehensive (loss) gain before reclassifications | (104 | ) | | 34 |
| | (14 | ) | | (84 | ) |
| Gains reclassified from accumulated other comprehensive loss | (116 | ) | | — |
| | — |
| | (116 | ) |
| Net current-period other comprehensive (loss) income | (220 | ) | | 34 |
| | (14 | ) | | (200 | ) |
| Balance as of December 31, 2016 | (1 | ) | | (288 | ) | | (372 | ) | | (661 | ) |
| Other comprehensive gain before reclassifications | 145 |
| | 55 |
| | 40 |
| | 240 |
|
| Gains reclassified from accumulated other comprehensive loss | (171 | ) | | — |
| | — |
| | (171 | ) |
| KML IPO | — |
| | 44 |
| | 7 |
| | 51 |
|
| Net current-period other comprehensive (loss) income | (26 | ) | | 99 |
| | 47 |
| | 120 |
|
| Balance as of December 31, 2017 | $ | (27 | ) | | $ | (189 | ) | | $ | (325 | ) | | $ | (541 | ) |
15. Fair Value
The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.
The three broad levels of inputs defined by the fair value hierarchy are as follows:
Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;
Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).
Fair Value of Derivative Contracts
The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the Codification (in millions). The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.
| | | | Balance sheet asset fair value measurements by level | | | | | Balance sheet asset fair value measurements by level | | | | |
| |
Level 1 | |
Level 2 | |
Level 3 | | Gross amount | | Contracts available for netting | | Cash collateral held(b) | | Net amount |
Level 1 | |
Level 2 | |
Level 3 | | Gross amount | | Contracts available for netting | | Cash collateral held(b) | | Net amount |
| As of December 31, 2015 | | | | | | | | | | | | | | |
| As of December 31, 2017 | | | | | | | | | | | | | | |
| Energy commodity derivative contracts(a) | $ | 48 |
| | $ | 589 |
| | $ | 2 |
| | $ | 639 |
| | $ | (12 | ) | | $ | (37 | ) | | $ | 590 |
| $ | 17 |
| | $ | 70 |
| | $ | — |
| | $ | 87 |
| | $ | (42 | ) | | $ | (12 | ) | | $ | 33 |
|
| Interest rate swap agreements | $ | — |
| | $ | 385 |
| | $ | — |
| | $ | 385 |
| | $ | (8 | ) | | $ | — |
| | $ | 377 |
| $ | — |
| | $ | 205 |
| | $ | — |
| | $ | 205 |
| | $ | (15 | ) | | $ | — |
| | $ | 190 |
|
| Cross-currency swap agreements | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | 166 |
| | $ | — |
| | $ | 166 |
| | $ | (6 | ) | | $ | — |
| | $ | 160 |
|
| As of December 31, 2014 | |
| | |
| | |
| | | | | | | | | |
| As of December 31, 2016 | | |
| | |
| | |
| | | | | | | | |
| Energy commodity derivative contracts(a) | $ | 49 |
| | $ | 533 |
| | $ | 12 |
| | $ | 594 |
| | $ | (46 | ) | | $ | (13 | ) | | $ | 535 |
| $ | 6 |
| | $ | 168 |
| | $ | — |
| | $ | 174 |
| | $ | (43 | ) | | $ | — |
| | $ | 131 |
|
| Interest rate swap agreements | $ | — |
| | $ | 403 |
| | $ | — |
| | $ | 403 |
| | $ | (44 | ) | | $ | — |
| | $ | 359 |
| $ | — |
| | $ | 300 |
| | $ | — |
| | $ | 300 |
| | $ | (18 | ) | | $ | — |
| | $ | 282 |
|
| | | | Balance sheet liability fair value measurements by level | | | | | Balance sheet liability fair value measurements by level | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Gross amount | | Contracts available for netting | | Collateral posted(c) | | Net amount | Level 1 | | Level 2 | | Level 3 | | Gross amount | | Contracts available for netting | | Collateral posted(b) | | Net amount |
| As of December 31, 2015 | | | | | | | | | | | | | | |
| As of December 31, 2017 | | | | | | | | | | | | | | |
| Energy commodity derivative contracts(a) | $ | (4 | ) | | $ | (10 | ) | | $ | (17 | ) | | $ | (31 | ) | | $ | 12 |
| | $ | — |
| | $ | (19 | ) | $ | (3 | ) | | $ | (98 | ) | | $ | — |
| | $ | (101 | ) | | $ | 42 |
| | $ | — |
| | $ | (59 | ) |
| Interest rate swap agreements | $ | — |
| | $ | (25 | ) | | $ | — |
| | $ | (25 | ) | | $ | 8 |
| | $ | — |
| | $ | (17 | ) | $ | — |
| | $ | (65 | ) | | $ | — |
| | $ | (65 | ) | | $ | 15 |
| | $ | — |
| | $ | (50 | ) |
| Cross-currency swap agreements | $ | — |
| | $ | (52 | ) | | $ | — |
| | $ | (52 | ) | | $ | — |
| | $ | — |
| | $ | (52 | ) | $ | — |
| | $ | (6 | ) | | $ | — |
| | $ | (6 | ) | | $ | 6 |
| | $ | — |
| | $ | — |
|
| As of December 31, 2014 | | | | | | | | | | | | | | |
| As of December 31, 2016 | | | | | | | | | | | | | | |
| Energy commodity derivative contracts(a) | $ | (25 | ) | | $ | (11 | ) | | $ | (73 | ) | | $ | (109 | ) | | $ | 46 |
| | $ | 47 |
| | $ | (16 | ) | $ | (29 | ) | | $ | (82 | ) | | $ | — |
| | $ | (111 | ) | | $ | 43 |
| | $ | 37 |
| | $ | (31 | ) |
| Interest rate swap agreements | $ | — |
| | $ | (53 | ) | | $ | — |
| | $ | (53 | ) | | $ | 44 |
| | $ | — |
| | $ | (9 | ) | $ | — |
| | $ | (57 | ) | | $ | — |
| | $ | (57 | ) | | $ | 18 |
| | $ | — |
| | $ | (39 | ) |
| Cross-currency swap agreements | | $ | — |
| | $ | (31 | ) | | $ | — |
| | $ | (31 | ) | | $ | — |
| | $ | — |
| | $ | (31 | ) |
_______
| |
| (a) | Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and options. Level 3 consists primarily of power derivative contracts.NGL swaps. |
| |
| (b) | Cash margin deposits held by usAny cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities”derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on our accompanying consolidated balance sheets. |
| |
(c) | Cash margin deposits posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current assets” on our accompanying consolidated balance sheets.their volumetric notional amounts are excluded from this table. |
The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts (in millions):
| Significant unobservable inputs (Level 3) |
| | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 |
| Derivatives-net asset (liability) | | | |
| Beginning of period | $ | (61 | ) | | $ | (110 | ) |
| Transfers out(a) | — |
| | (88 | ) |
| Total gains or (losses) | |
| | |
|
| Included in earnings | (13 | ) | | 22 |
|
| Included in other comprehensive loss | — |
| | 78 |
|
| Settlements | 59 |
| | 37 |
|
| End of period | $ | (15 | ) | | $ | (61 | ) |
| The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date | $ | — |
| | $ | 1 |
|
_______
(a) On December 31, 2014, we transferred WTI options from Level 3 to Level 2 due to increased observability of significant inputs in their valuations.| Significant unobservable inputs (Level 3) |
| | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 |
| Derivatives-net asset (liability) | | | |
| Beginning of period | $ | — |
| | $ | (15 | ) |
| Total gains or (losses) included in earnings | — |
| | (9 | ) |
| Settlements | — |
| | 24 |
|
| End of period | $ | — |
| | $ | — |
|
| The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date | $ | — |
| | $ | — |
|
As of December 31, 2015,
During 2016, our Level 3 derivative assetsasset and liabilitiesliability activity consisted primarily of power derivative contracts (which expired in April 2016), where a significant portion of fair value is calculated from underlying market data that is not readily observable. The derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value.value, and management would not expect materially different valuation results were we to use different input amounts within reasonable ranges.
Fair Value of Financial Instruments
The carrying value and estimated fair value of our outstanding debt balances is disclosed below (in millions):
|
| | | | | | | | | | | | | | | |
| | December 31, 2015 | | December 31, 2014 |
| | Carrying value | | Estimated fair value | | Carrying value | | Estimated fair value |
| Total debt | $ | 43,227 |
| | $ | 37,481 |
| | $ | 42,814 |
| | $ | 43,761 |
|
|
| | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | Carrying value | | Estimated fair value | | Carrying value | | Estimated fair value |
| Total debt | $ | 37,843 |
| | $ | 40,050 |
| | $ | 40,050 |
| | $ | 41,015 |
|
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 20152017 and 2014.2016.
16. Reportable Segments
We divide our operations into the followingOur reportable business segments. These segments and their principal sources of revenues are as follows:are:
Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG facilities;
| |
| • | CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas; |
Terminals—(i) the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, condensate,chemicals, and ethanol and bulk products, including coal, petroleum coke, cement, alumina, saltsteel and other bulk chemicalscoal; and (ii) the ownership and operation of our Jones Act tankers;
Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate pipelines that primarily deliver, refined petroleumamong other products, (gasoline,gasoline, diesel fuel and jet fuel), NGL,fuel, propane, ethane, crude oil condensate and bio-fuelscondensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; and
Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport; and
Other—primarily other miscellaneous assets and liabilities including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with legacy trading activities; and (iii) other miscellaneous assets and liabilities.Airport.
We evaluate performance principally based on each segment’s EBDA, (including amortization of excess cost of equity investments), which excludes general and administrative expenses, third-party debt costs and interest expense, unallocable interest income,net, and unallocable income tax expense. Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision makers organize their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and marketing strategies.
We consider each period’s earnings before all non-cash DD&A expenses to be an important measure of business segment performance for our reporting segments. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.
During 2015, 20142017, 2016 and 2013,2015, we did not have revenues from any single external customer that exceeded 10% of our consolidated revenues.
Financial information by segment follows (in millions):
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Revenues | | | | | | | | | | |
| Natural Gas Pipelines | | | | | | | | | | |
| Revenues from external customers | $ | 8,704 |
| | $ | 10,153 |
| | $ | 8,613 |
| $ | 8,608 |
| | $ | 7,998 |
| | $ | 8,704 |
|
| Intersegment revenues | 21 |
| | 15 |
| | 4 |
| 10 |
| | 7 |
| | 21 |
|
CO2 | 1,699 |
| | 1,960 |
| | 1,857 |
| 1,196 |
| | 1,221 |
| | 1,699 |
|
| Terminals | |
| | |
| | |
| | | | | |
|
| Revenues from external customers | 1,878 |
| | 1,717 |
| | 1,408 |
| 1,965 |
| | 1,921 |
| | 1,878 |
|
| Intersegment revenues | 1 |
| | 1 |
| | 2 |
| 1 |
| | 1 |
| | 1 |
|
| Products Pipelines | | | | | | | | | | |
| Revenues from external customers | 1,828 |
| | 2,068 |
| | 1,853 |
| 1,645 |
| | 1,631 |
| | 1,828 |
|
| Intersegment revenues | 3 |
| | — |
| | — |
| 16 |
| | 18 |
| | 3 |
|
| Kinder Morgan Canada | 260 |
| | 291 |
| | 302 |
| 256 |
| | 253 |
| | 260 |
|
| Other | (3 | ) | | 1 |
| | 1 |
| |
| Total segment revenues | 14,391 |
| | 16,206 |
| | 14,040 |
| |
| Other revenues(a) | 37 |
| | 36 |
| | 36 |
| |
| Less: Total intersegment revenues | (25 | ) | | (16 | ) | | (6 | ) | |
| Corporate and intersegment eliminations(a) | | 8 |
| | 8 |
| | 9 |
|
| Total consolidated revenues | $ | 14,403 |
| | $ | 16,226 |
| | $ | 14,070 |
| $ | 13,705 |
| | $ | 13,058 |
| | $ | 14,403 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Operating expenses(b) | | | | | |
| Natural Gas Pipelines | $ | 5,457 |
| | $ | 4,393 |
| | $ | 4,738 |
|
CO2 | 394 |
| | 399 |
| | 432 |
|
| Terminals | 788 |
| | 768 |
| | 836 |
|
| Products Pipelines | 487 |
| | 573 |
| | 772 |
|
| Kinder Morgan Canada | 95 |
| | 87 |
| | 87 |
|
| Corporate and intersegment eliminations | (6 | ) | | 2 |
| | 26 |
|
| Total consolidated operating expenses | $ | 7,215 |
| | $ | 6,222 |
| | $ | 6,891 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Operating expenses(b) | | | | | |
| Natural Gas Pipelines | $ | 4,738 |
| | $ | 6,241 |
| | $ | 5,235 |
|
CO2 | 432 |
| | 494 |
| | 439 |
|
| Terminals | 836 |
| | 746 |
| | 657 |
|
| Products Pipelines | 772 |
| | 1,258 |
| | 1,295 |
|
| Kinder Morgan Canada | 87 |
| | 106 |
| | 110 |
|
| Other | 51 |
| | 24 |
| | 30 |
|
| Total segment operating expenses | 6,916 |
| | 8,869 |
| | 7,766 |
|
| Less: Total intersegment operating expenses | (25 | ) | | (16 | ) | | (6 | ) |
| Total consolidated operating expenses | $ | 6,891 |
| | $ | 8,853 |
| | $ | 7,760 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Other expense (income)(c) | | | | | |
| Natural Gas Pipelines | $ | 1,269 |
| | $ | 5 |
| | $ | (24 | ) |
CO2 | 606 |
| | 243 |
| | — |
|
| Terminals | 190 |
| | 29 |
| | (74 | ) |
| Products Pipelines | 2 |
| | (3 | ) | | 6 |
|
| Kinder Morgan Canada | (1 | ) | | — |
| | — |
|
| Other | — |
| | 1 |
| | (7 | ) |
| Total consolidated other expense (income) | $ | 2,066 |
| | $ | 275 |
| | $ | (99 | ) |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| DD&A | | | | | |
| Natural Gas Pipelines | $ | 1,046 |
| | $ | 897 |
| | $ | 797 |
|
CO2 | 556 |
| | 570 |
| | 533 |
|
| Terminals | 433 |
| | 337 |
| | 247 |
|
| Products Pipelines | 206 |
| | 166 |
| | 155 |
|
| Kinder Morgan Canada | 46 |
| | 51 |
| | 54 |
|
| Other | 22 |
| | 19 |
| | 20 |
|
| Total consolidated DD&A | $ | 2,309 |
| | $ | 2,040 |
| | $ | 1,806 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments | | | | | |
| Natural Gas Pipelines | $ | 285 |
| | $ | 279 |
| | $ | 200 |
|
CO2 | (5 | ) | | 26 |
| | 22 |
|
| Terminals | 17 |
| | 18 |
| | 22 |
|
| Products Pipelines | 36 |
| | 37 |
| | 40 |
|
| Kinder Morgan Canada | — |
| | — |
| | 4 |
|
| Other | — |
| | 1 |
| | — |
|
| Total consolidated equity earnings | $ | 333 |
| | $ | 361 |
| | $ | 288 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Interest income | | | | | |
| Natural Gas Pipelines | $ | — |
| | $ | 1 |
| | $ | — |
|
| Products Pipelines | 2 |
| | 2 |
| | 2 |
|
| Kinder Morgan Canada | — |
| | — |
| | 3 |
|
| Other | 2 |
| | 6 |
| | 8 |
|
| Total segment interest income | 4 |
| | 9 |
| | 13 |
|
| Unallocated interest income | — |
| | — |
| | 2 |
|
| Total consolidated interest income | $ | 4 |
| | $ | 9 |
| | $ | 15 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Other, net-income (expense) | | | | | |
| Natural Gas Pipelines | $ | 24 |
| | $ | 24 |
| | $ | 578 |
|
CO2 | — |
| | — |
| | — |
|
| Terminals | 8 |
| | 12 |
| | 1 |
|
| Products Pipelines | 4 |
| | (1 | ) | | 1 |
|
| Kinder Morgan Canada | 8 |
| | 15 |
| | 246 |
|
| Other | (1 | ) | | 30 |
| | 9 |
|
| Total consolidated other, net-income (expense) | $ | 43 |
| | $ | 80 |
| | $ | 835 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Income tax benefit (expense) | | | | | |
| Natural Gas Pipelines | $ | (4 | ) | | $ | (6 | ) | | $ | (9 | ) |
CO2 | (1 | ) | | (8 | ) | | (7 | ) |
| Terminals | (29 | ) | | (29 | ) | | (14 | ) |
| Products Pipelines | (8 | ) | | (2 | ) | | 2 |
|
| Kinder Morgan Canada | (19 | ) | | (18 | ) | | (21 | ) |
| Total segment income tax expense | (61 | ) | | (63 | ) | | (49 | ) |
| Unallocated income tax expense | (503 | ) | | (585 | ) | | (693 | ) |
| Total consolidated income tax expense | $ | (564 | ) | | $ | (648 | ) | | $ | (742 | ) |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Segment EBDA(d) | | | | | |
| Natural Gas Pipelines | $ | 3,063 |
| | $ | 4,259 |
| | $ | 4,207 |
|
CO2 | 657 |
| | 1,240 |
| | 1,435 |
|
| Terminals | 849 |
| | 944 |
| | 836 |
|
| Products Pipelines | 1,100 |
| | 856 |
| | 602 |
|
| Kinder Morgan Canada | 163 |
| | 182 |
| | 424 |
|
| Other | (53 | ) | | 13 |
| | (5 | ) |
| Total segment EBDA | 5,779 |
| | 7,494 |
| | 7,499 |
|
| Total segment DD&A | (2,309 | ) | | (2,040 | ) | | (1,806 | ) |
| Total segment amortization of excess cost of equity investments | (51 | ) | | (45 | ) | | (39 | ) |
| Other revenues | 37 |
| | 36 |
| | 36 |
|
| General and administrative expenses | (690 | ) | | (610 | ) | | (613 | ) |
| Interest expense, net of unallocable interest income(e) | (2,055 | ) | | (1,807 | ) | | (1,688 | ) |
| Unallocable income tax expense | (503 | ) | | (585 | ) | | (693 | ) |
| Loss from discontinued operations, net of tax | — |
| | — |
| | (4 | ) |
| Total consolidated net income | $ | 208 |
| | $ | 2,443 |
| | $ | 2,692 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Other expense (income)(c) | | | | | |
| Natural Gas Pipelines | $ | 26 |
| | $ | 199 |
| | $ | 1,269 |
|
CO2 | (1 | ) | | 19 |
| | 606 |
|
| Terminals | (14 | ) | | 99 |
| | 190 |
|
| Products Pipelines | — |
| | 76 |
| | 2 |
|
| Kinder Morgan Canada | — |
| | — |
| | (1 | ) |
| Corporate | 1 |
| | (7 | ) | | — |
|
| Total consolidated other expense (income) | $ | 12 |
| | $ | 386 |
| | $ | 2,066 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Capital expenditures | | | | | |
| Natural Gas Pipelines | $ | 1,642 |
| | $ | 935 |
| | $ | 1,085 |
|
CO2 | 725 |
| | 792 |
| | 667 |
|
| Terminals | 847 |
| | 1,049 |
| | 1,108 |
|
| Products Pipelines | 524 |
| | 680 |
| | 416 |
|
| Kinder Morgan Canada | 142 |
| | 156 |
| | 77 |
|
| Other | 16 |
| | 5 |
| | 16 |
|
| Total consolidated capital expenditures | $ | 3,896 |
| | $ | 3,617 |
| | $ | 3,369 |
|
| | | | 2015 | | 2014 | | Year Ended December 31, |
| Investments at December 31 | | | | | |
| | | 2017 | | 2016 | | 2015 |
| DD&A | | | | | | |
| Natural Gas Pipelines | $ | 5,080 |
| | $ | 5,174 |
| | $ | 1,011 |
| | $ | 1,041 |
| | $ | 1,046 |
|
CO2 | — |
| | 17 |
| | 493 |
| | 446 |
| | 556 |
|
| Terminals | 306 |
| | 219 |
| | 472 |
| | 435 |
| | 433 |
|
| Products Pipelines | 641 |
| | 624 |
| | 216 |
| | 221 |
| | 206 |
|
| Kinder Morgan Canada | 10 |
| | 1 |
| | 46 |
| | 44 |
| | 46 |
|
| Other | 3 |
| | 1 |
| | |
| Total consolidated investments | $ | 6,040 |
| | $ | 6,036 |
| | |
| Corporate | | 23 |
| | 22 |
| | 22 |
|
| Total consolidated DD&A | | $ | 2,261 |
| | $ | 2,209 |
| | $ | 2,309 |
|
|
| | | | | | | | | |
| | 2015 | | 2014 | | |
| Assets at December 31 | | | | | |
| Natural Gas Pipelines | $ | 53,704 |
| | $ | 52,532 |
| | |
CO2 | 4,706 |
| | 5,227 |
| | |
| Terminals | 9,083 |
| | 8,850 |
| | |
| Products Pipelines | 8,464 |
| | 7,179 |
| | |
| Kinder Morgan Canada | 1,434 |
| | 1,593 |
| | |
| Other | 418 |
| | 455 |
| | |
| Total segment assets | 77,809 |
| | 75,836 |
| | |
| Corporate assets(f) | 6,276 |
| | 7,157 |
| | |
| Assets held for sale | 19 |
| | 56 |
| | |
| Total consolidated assets | $ | 84,104 |
| | $ | 83,049 |
| | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments | | | | | |
| Natural Gas Pipelines | $ | 253 |
| | $ | (269 | ) | | $ | 285 |
|
CO2 | 42 |
| | 22 |
| | (5 | ) |
| Terminals | 24 |
| | 19 |
| | 17 |
|
| Products Pipelines | 48 |
| | 56 |
| | 36 |
|
| Total consolidated equity earnings | $ | 367 |
| | $ | (172 | ) | | $ | 333 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Other, net-income (expense) | | | | | |
| Natural Gas Pipelines | $ | 49 |
| | $ | 19 |
| | $ | 24 |
|
| Terminals | 8 |
| | 4 |
| | 8 |
|
| Products Pipelines | (1 | ) | | 2 |
| | 4 |
|
| Kinder Morgan Canada | 25 |
| | 15 |
| | 8 |
|
| Corporate | 1 |
| | 4 |
| | (1 | ) |
| Total consolidated other, net-income (expense) | $ | 82 |
| | $ | 44 |
| | $ | 43 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Segment EBDA(d) | | | | | |
| Natural Gas Pipelines | $ | 3,487 |
| | $ | 3,211 |
| | $ | 3,067 |
|
CO2 | 847 |
| | 827 |
| | 658 |
|
| Terminals | 1,224 |
| | 1,078 |
| | 878 |
|
| Products Pipelines | 1,231 |
| | 1,067 |
| | 1,106 |
|
| Kinder Morgan Canada | 186 |
| | 181 |
| | 182 |
|
| Total segment EBDA | 6,975 |
| | 6,364 |
| | 5,891 |
|
| DD&A | (2,261 | ) | | (2,209 | ) | | (2,309 | ) |
| Amortization of excess cost of equity investments | (61 | ) | | (59 | ) | | (51 | ) |
| General and administrative and corporate charges | (660 | ) | | (652 | ) | | (708 | ) |
| Interest, net | (1,832 | ) | | (1,806 | ) | | (2,051 | ) |
| Income tax expense | (1,938 | ) | | (917 | ) | | (564 | ) |
| Total consolidated net income | $ | 223 |
| | $ | 721 |
| | $ | 208 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Capital expenditures | | | | | |
| Natural Gas Pipelines | $ | 1,376 |
| | $ | 1,227 |
| | $ | 1,642 |
|
CO2 | 436 |
| | 276 |
| | 725 |
|
| Terminals | 888 |
| | 983 |
| | 847 |
|
| Products Pipelines | 127 |
| | 244 |
| | 524 |
|
| Kinder Morgan Canada | 338 |
| | 124 |
| | 142 |
|
| Corporate | 23 |
| | 28 |
| | 16 |
|
| Total consolidated capital expenditures | $ | 3,188 |
| | $ | 2,882 |
| | $ | 3,896 |
|
|
| | | | | | | | | |
| | 2017 | | 2016 | | |
| Investments at December 31 | | | | | |
| Natural Gas Pipelines | $ | 6,218 |
| | $ | 6,185 |
| | |
CO2 | 6 |
| | — |
| | |
| Terminals | 263 |
| | 252 |
| | |
| Products Pipelines | 777 |
| | 566 |
| | |
| Kinder Morgan Canada | 34 |
| | 20 |
| | |
| Corporate | — |
| | 4 |
| | |
| Total consolidated investments | $ | 7,298 |
| | $ | 7,027 |
| | |
|
| | | | | | | | | |
| | 2017 | | 2016 | | |
| Assets at December 31 | | | | | |
| Natural Gas Pipelines | $ | 51,173 |
| | $ | 50,428 |
| | |
CO2 | 3,946 |
| | 4,065 |
| | |
| Terminals | 9,935 |
| | 9,725 |
| | |
| Products Pipelines | 8,539 |
| | 8,329 |
| | |
| Kinder Morgan Canada | 2,080 |
| | 1,572 |
| | |
| Corporate assets(e) | 3,382 |
| | 6,108 |
| | |
| Assets held for sale | — |
| | 78 |
| | |
| Total consolidated assets | $ | 79,055 |
| | $ | 80,305 |
| | |
_______
| |
| (a) | Includes a management fee for services we perform for NGPL.as operator of an equity investee. |
| |
| (b) | Includes natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes. |
| |
| (c) | Includes loss on impairment of goodwill, loss (gain) on impairments and disposals of long-lived assets,divestitures, net and other expense (income),income, net. |
| |
| (d) | Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income),income, net, loss on impairment of goodwill, and losses (gain)loss on impairments and disposals of long-lived assets,divestitures, net and loss on impairments and divestitures of equity investments.investments, net. |
| |
| (e) | Includes (i) interest expense and (ii) miscellaneous other income and expenses not allocated to business segments. |
| |
(f) | Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and telecommunications equipment)legacy activity) not allocated to individualthe reportable segments. |
We do not attribute interest and debt expense to any of our reportable business segments.
Following is geographic information regarding the revenues and long-lived assets of our business segments (in millions):
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Revenues from external customers | | | | | | | | | | |
| U.S. | $ | 13,797 |
| | $ | 15,605 |
| | $ | 13,656 |
| $ | 13,073 |
| | $ | 12,459 |
| | $ | 13,797 |
|
| Canada | 479 |
| | 437 |
| | 398 |
| 503 |
| | 483 |
| | 479 |
|
| Mexico | 127 |
| | 184 |
| | 16 |
| 129 |
| | 116 |
| | 127 |
|
| Total consolidated revenues from external customers | $ | 14,403 |
| | $ | 16,226 |
| | $ | 14,070 |
| $ | 13,705 |
| | $ | 13,058 |
| | $ | 14,403 |
|
| | | | December 31, | | December 31, |
| | 2015 | | 2014 | | 2017 | | 2016 | | 2015 |
| Long-term assets, excluding goodwill and other intangibles | | | | | | | | | |
| U.S. | $ | 51,679 |
| | $ | 49,992 |
| | $ | 47,928 |
| | $ | 49,125 |
| | $ | 51,679 |
|
| Canada | 2,193 |
| | 2,268 |
| | 3,071 |
| | 2,399 |
| | 2,193 |
|
| Mexico | 67 |
| | 81 |
| | 80 |
| | 82 |
| | 67 |
|
| Total consolidated long-lived assets | $ | 53,939 |
| | $ | 52,341 |
| |
| $ | 51,079 |
| | $ | 51,606 |
| | $ | 53,939 |
|
17. Litigation, Environmental and Other Contingencies
We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or dividends to our shareholders. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed.
Federal Energy Regulatory Commission
FERC Proceedings
SFPP
The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the complaints and protests of various shippers the most recent of which was filed in late 2015 with the FERC (docketed at OR16-6) challenging SFPP’s filed East Line rates. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. If the shippers are successful in proving these claimsprevail on their arguments or other of their claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing date of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. On March 22, 2016, the D.C. Circuit issued a decision in United Airlines, Inc. v. FERC remanding to FERC for further consideration of two issues: (1) the appropriate data to be used to determine the return on equity for SFPP in the underlying docket, and (2) the just and reasonable return to be provided to a tax pass-through entity that includes an income tax allowance in its underlying cost of service. On July 21, 2017, an initial decision by the Administrative Law Judge (ALJ) in OR16-6 concluded that the Complainants are due reparations, with appropriate interest, equal to the difference between what SFPP collected from the Complainants for service on the East Line and the amounts SFPP would have collected had it charged just and reasonable rates for that line. The ALJ ruled that an income tax allowance should be included in the cost of service both to determine reparations and to set going forward rates, and found that the new just and reasonable rates are not knowable until the FERC reviews the initial decision and orders a compliance filing. The FERC will determine which portions of the initial decision to affirm, reject or amend. With respect to the various SFPP related complaints and protest proceedings at the FERC, we estimate that the shippers are seeking approximately $40 million in annual rate reductions and approximately $160$230 million in refunds. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. However, to the extent the shippers are successful in one or more of the complaints or protest proceedings, SFPP estimates that applying the principles of several recent FERC decisions in SFPP cases,precedent, as applicable, to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers.
EPNG
The tariffs and rates charged by EPNG are subject to two ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it will apply its findings in Opinion 517-A to the same issues in the 2010 rate case. EPNG has sought federal appellate review of Opinion 517-A.517-A and oral arguments were held on February 15, 2017. On February 21, 2017, the reviewing court delayed the case until the FERC rules on the rehearing requests pending in the 2010 Rate Case. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528)528-A) on October 17, 2013.February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG sought rehearing on certain issues in Opinion 528. As required by Opinion 528, EPNG filedto file revised pro forma recalculated rates consistent with the terms of Opinion 528. The FERC also required an Administrative Law Judge (ALJ) to conduct an additional hearing concerning oneOpinions 517-A and 528-A. EPNG and two intervenors sought rehearing of certain aspects of the decision, and the judicial review sought by certain intervenors has been delayed until the FERC issues in Opinion 528. On September 17, 2014,an order on rehearing. All refund obligations related to the ALJ issued an initial decision finding certain shippers qualify for lower rates under a prior settlement. EPNG has sought FERC review of2008 rate case were satisfied during calendar year 2015. With respect to the ALJ decision.2010 rate case, EPNG believes it has an appropriate reserve which is classified as a current liability, related to the findings in Opinions 517-A and 528 for both rate cases.528-A.
NGPL and WIC
On January 19, 2017, FERC initiated separate proceedings against NGPL and WICpursuant to section 5 of the Natural Gas Act. The matters were intended to determine whether NGPL’s and WIC’s current rates were just and reasonable. NGPL and WIC each submitted an Offer of Settlement to the FERC in their respective proceedings. The FERC approved WIC’s Offer of Settlement on November 27, 2017, and the FERC approved NGPL’s Offer of Settlement on January 5, 2018. These settlements will not have a material adverse impact on KMI’s results of operations or cash flows from operations.
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TMEP Litigation
There are numerous legal challenges pending before the Federal Court of Appeal which have been filed by various governmental and non-governmental organizations, Aboriginal groups or other parties that seek judicial review of the recommendation of the NEB and subsequent decision by the Federal Governor in Council to conditionally approve the TMEP.
The petitions allege, among other things, that additional consultation, engagement or accommodation is required and that various non-economic impacts of the TMEP were not adequately considered. The remedies sought include requests that the NEB recommendation be quashed, that additional consultations be undertaken, and that the order of the Governor in Council approving the TMEP be quashed. After provincial elections in British Columbia (BC) on May 9, 2017, the New Democratic Party and Green Party formed a majority government. The new BC government sought and was granted limited intervenor status in the Federal Court of Appeal proceedings to argue against the government’s approval of the TMEP. A hearing was conducted by the Federal Court of Appeal from October 2 through October 13, 2017. A decision is expected in the coming months, and is subject to potential further appeal to the Supreme Court of Canada. Although we believe that each of the foregoing appeals lacks merit, in the event an applicant is successful at the Supreme Court of Canada, among other potential impacts, the NEB recommendation or Governor in Council’s approval may be quashed, permits may be revoked, the TMEP may be subject to additional significant regulatory reviews, there may be significant changes to the TMEP plans, further obligations or restrictions may be implemented, or the TMEP may be stopped altogether, which could materially impact the overall feasibility or economic benefits of the TMEP, which in turn would have a material adverse effect on the TMEP and, consequently, our investment in KML.
In addition to the judicial reviews of the NEB recommendation report and Governor in Council’s order, two judicial review proceedings have been commenced at the Supreme Court of BC (Squamish Nation; and the City of Vancouver). The petitions allege a duty and failure to consult or accommodate First Nations, and generally, among other claims, that the Province ought not to have approved the TMEP. Each Applicant seeks to quash the Environmental Assessment Certificate (EAC) that was issued by the BC Environmental Assessment Office. On September 29, 2017, the BC government filed evidence in support of the EAC approval in the judicial review proceeding involving the Squamish Nation. Hearings were conducted in October and November 2017, respectively, for the City of Vancouver and the Squamish Nation judicial review proceedings and the Court took the matters under consideration with decisions expected in the coming months. Although we believe that each of the foregoing appeals lacks merit, in the event that an applicant for judicial review is successful, among other potential impacts, the EAC may be quashed, provincial permits may be revoked, the TMEP may be subject to additional significant regulatory reviews, there may be significant changes to the TMEP plans, further obligations or restrictions may be imposed or the TMEP may be stopped altogether. In the event that an applicant is unsuccessful at the Supreme Court of BC, they may further seek to appeal the decision to the BC Court of Appeal. Any decision of the BC Court of Appeal may be appealed to the Supreme Court of Canada. A successful appeal at either of these levels could result in the same types of consequences described above.
On October 26, 2017 and November 14, 2017, Trans Mountain filed motions with the NEB. The first motion sought to resolve delays experienced by Trans Mountain in obtaining preliminary plan approvals from the City of Burnaby. The second motion sought to establish an NEB process to backstop provincial and municipal processes in a fair, transparent and expedited fashion. On December 7, 2017, the NEB issued an order granting the relief requested by Trans Mountain in respect of its motion related to Burnaby. On January 19, 2018, the NEB granted, in part, Trans Mountain’s motion by establishing a generic process to hear any future motions as they relate to provincial and municipal permitting issues. Burnaby or other interested parties may seek leave to appeal to the Federal Court of Appeal and, if unsuccessful at the Federal Court of Appeal, may further seek to appeal the decision to the Supreme Court of Canada. A successful appeal at either of these levels could result in either one or both of the NEB orders being quashed.
Other Commercial Matters
Union Pacific Railroad Company Easements & Related Litigation
SFPP and Union Pacific Railroad Company (UPRR) arehave engaged in a proceedinglitigation since 2004 to determine both the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted, pursuant to existing contractual arrangements forand the ten-year period beginning January 1, 2004 (Union Pacific Railroad Company v. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). In September 2011, the trial judge determined that the annual rent payable as of January 1, 2004 was $14 million, subject to annual consumer price index increases. SFPP appealed the judgment.
By notice dated October 25, 2013, UPRR demanded the payment of $22.3 million in rent for the first year of the next ten-year period beginning January 1, 2014,circumstances and conditions under which SFPP rejected.must pay to relocate its pipeline within the UPRR rights-of-way. In July 2017, UPRR and SFPP reached a confidential settlement of both the rental and relocation litigation. The amount paid by SFPP to settle the rental litigation was within the right-of-way liability previously recorded by SFPP, and the parties generally agreed to share and allocate the cost of future potential relocations. Although the cost sharing mechanism in the settlement is expected to reduce the cost of future relocations, SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations such that it is difficult to quantify the cost of future potential relocations. Such costs could have an adverse effect on our financial position, results of operations, cash flows, and dividends to our shareholders.
On November 5, 2014, the Court of Appeals issued an opinion which reversed the judgment, including the award of prejudgment interest, and remanded the matter to the trial court for a determination of UPRR’s property interest in its right-of-way, including whether UPRR has sufficient interest to grant SFPP’s easements. UPRR filed a petition for review to the California Supreme Court which was denied. The trial court has not set a date for the retrial.
After the above-referenced decision by the California Court of Appeals which held that UPRR does not own the subsurface rights to grant certain easements and may not be able to collect rent from those easements, aA purported class action lawsuit was filed in 2015 in thea U.S. District Court for the Southern District ofin California by private landowners in California who claim to be the lawful owners of subsurface real property allegedly used or occupied by UPRR or SFPP. Substantially similar follow-on lawsuits were filed and are pending in federal courts by landowners in Nevada, Arizona and New Mexico. These suits, which are brought purportedly as class actions on behalf of all landowners who own land in fee adjacent to and underlying the railroad easement under which the SFPP pipeline is located in those respective states, assert claims against UPRR, SFPP, KMGP, and Kinder
Morgan Operating L.P. “D” for declaratory judgment, trespass, ejectment, quiet title, unjust enrichment, accounting,alleging that the defendants occupation and alleged unlawful business acts and practices arising from defendants’ alleged improper use or occupation of the subsurface real property.property was improper. Plaintiffs’ motions for class certification were denied by the federal courts in Arizona and California. The Ninth Circuit Court of Appeals denied Plaintiffs’ request for interlocutory review of the decisions on class certification. The New Mexico and Nevada lawsuits have been stayed. An additional suit was filed in a U.S. District Court in Arizona by private landowners seeking recovery for claims substantially the same as those made in the purported class actions. SFPP views these casesthe litigation involving private landowners as primarily a dispute between UPRR and the plaintiffs. UPRR purportedplaintiff landowners; as such, we expect the lawsuits will be resolved on terms that are not material to grant SFPP a networkKMI’s results of subsurface pipeline easements along UPRR’s railroad right-of-way. SFPP relied on the validity of those easements and paid rentoperations, cash flows or dividends to UPRR for the value of those easements. We believe we have recorded a right-of-way liability sufficient to cover our potential liability, if any, for back rent.shareholders.
SFPPGulf LNG Facility Arbitration
On March 1, 2016, Gulf LNG Energy, LLC and UPRR have engaged in multiple disputes over the circumstances under which SFPP must payGulf LNG Pipeline, LLC (GLNG) received a Notice of Disagreement and Disputed Statements and a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for relocations of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In 2006, following a bench trial regarding the circumstances under which SFPP must pay for relocations, the judge determined that SFPP must pay for any relocations resulting from any legitimate business purposecapacity of the UPRR. The decision was affirmed on appeal. In addition, UPRR contendsGulf LNG Facility in Mississippi for an initial term that SFPP must comply withis not scheduled to expire until the more expensive American Railway Engineering and Maintenance-of-Way Association (AREMA) standardsyear 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in determining when relocations are necessary and in completing relocations. Each party has sought declaratory relief with respectMilan, Italy. Pursuant to its positions regardingNotice of Arbitration, Eni USA seeks declaratory and monetary relief based upon its assertion that (i) the applicationterminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of these standards with respect to relocations. In 2011, a jury verdict was reached that SFPP was obligated to comply with AREMA standardsthe agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a railroad projectplan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement. As set forth in Beaumont Hills, California. In 2014, the trial court entered judgment against SFPP, consistent withterminal use agreement, disputes are meant to be resolved by final and binding arbitration. A three-member arbitration panel conducted an arbitration hearing in January 2017. During fourth quarter 2017 the jury’s verdict. On June 29, 2015,arbitration panel informed the parties entered into a confidential settlement of allthat it expects to issue its decision on or before February 28, 2018. Eni USA has indicated that it will continue to pay the amounts claimed to be due pending resolution of the claims relatingdispute. The successful assertion by Eni USA of its claim to terminate or amend its payment obligations under the agreement prior to the project in Beaumont Hills and the case was dismissed.
Since SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations, it is difficult to quantify the effectsexpiration of the outcome of these cases on SFPP. Even if SFPP is successful in advancing its positions, significant relocations for which SFPP must nonetheless bear the cost (i.e., for railroad purposes, with the standards in the federal Pipeline Safety Act applying)initial term could have an adverse effect on ourthe business, financial position, results of operations, or cash flows of GLNG and our dividendsdistributions to our shareholders. These effects couldKMI, a 50% shareholder of GLNG. We view the demand for arbitration to be even greater in the event SFPP is unsuccessful in one or more of these lawsuits.without merit, and we will continue to contest it vigorously.
Plains Gas Solutions, LLC v. Tennessee Gas Pipeline Company, L.L.C. et al.Brinckerhoff Merger Litigation
On October 16, 2013, Plains Gas Solutions, LLC (Plains)In April 2017, a purported class action suit was filed in the Delaware Court of Chancery by Peter Brinckerhoff, a former EPB unitholder on behalf of a class of former unaffiliated unitholders of EPB, seeking to challenge the $9.2 billion merger of EPB into a subsidiary of KMI as part of a series of transactions in November 2014 whereby KMI acquired all of the outstanding equity interests in KMP, KMR, and EPB that KMI and its subsidiaries did not already own. The suit alleges that the merger consideration did not sufficiently compensate EPB unitholders for the value of three derivative suits concerning drop down transactions which the derivative plaintiff lost standing to pursue after the merger and which the present suit now alleges were collectively worth as much as $700 million. The suit claims that the alleged failure to obtain sufficient merger consideration for the drop down lawsuits constitutes a breach of the EPB limited partnership agreement and the implied covenant of good faith and fair dealing. The suit also asserts claims against KMI and certain individual defendants for allegedly tortiously interfering with and/or aiding and abetting the alleged breach of the limited partnership agreement. Defendants’ motion to dismiss was granted, and the Court dismissed the suit in its entirety. Brinckerhoff filed a petitionnotice to appeal the dismissal. In November 2017, counsel for Brinckerhoff filed a separate lawsuit against KMEP and KMI seeking to recover up to $44 million in the 151st Judicial District Court for Harris County, Texas (Case No. 62528) against TGP, Kinetica Partners, LLC and two other Kinetica entities. The suit arises from the sale by TGP of the Cameron System in Louisiana to Kinetica Partners, LLC on September 1, 2013. Plains alleges that defendants breached a straddle agreement requiring that gas on the Cameron System be committed to Plains’ Grand Chenier
gas-processing facility, that requisite daily volume reports were not provided, that TGP improperly assigned its obligations under the straddle agreement to Kinetica, and that defendants interfered with Plains’ contracts with producers. The petition alleges damages of at least $100 million. Under the Amended and Restated Purchase and Sale Agreement with Kinetica, Kinetica is obligated to defend and indemnify TGPattorneys’ fees allegedly incurred in connection with the gas commitment and reporting claims. After agreeing initiallyassertion of derivative claims that Brinckerhoff lost standing to defend and indemnify TGP against such claims, Kinetica withdrew its defense and disputed its indemnity obligation. We intend to vigorously defend the suit and pursue Kinetica, if necessary, for indemnity and costs of defense.
Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al.
In December 2011 (Brinckerhoff I), March 2012, (Brinckerhoff II), May 2013 (Brinckerhoff III) and June 2014 (Brinckerhoff IV), derivative lawsuits were filed in Delaware Chancery Court against El Paso Corporation, El Paso Pipeline GP Company, L.L.C., the general partner of EPB, and the directors of the general partner at the time of the relevant transactions. EPB was named in these lawsuits as a “Nominal Defendant.” The lawsuits arise from the March 2010, November 2010, May 2012 and June 2011 drop-down transactions involving EPB’s purchase of SLNG, Elba Express, CPG and interests in SNG and CIG. The lawsuits allege various conflicts of interest and that the consideration paid by EPB was excessive. Brinckerhoff I and II were consolidated into one proceeding. Motions to dismiss were filed in Brinckerhoff III and Brinckerhoff IV, and such motions remain pending. On June 12, 2014, defendants’ motion for summary judgment was granted in Brinckerhoff I, dismissing the case in its entirety. Defendants’ motion for summary judgment in Brinckerhoff II was granted in part, dismissing certain claims and allowing the matter to go to trial in late 2014 on the remaining claims. On April 20, 2015, the Court issued a post-trial memorandum opinion (Memorandum Opinion) in Brinckerhoff II entering judgment in favor of all of the defendants other than the general partner of EPB, but finding the general partner liable for breach of contract in connection with EPB’s purchase of 49% interests in Elba and SLNG and a 15% interest in SNG in a $1.13 billion drop-down transaction that closed on November 19, 2010 (Fall Dropdown), prior to our acquisition of El Paso Corporation in 2012. In its Memorandum Opinion, the Court determined that EPB suffered damages of $171 million from the Fall Dropdown, which the Court determined to be the amount that EPB overpaid for Elba. We believe the claim is derivative in nature and was extinguished by our acquisition on November 26, 2014, pursuant to a merger agreement, of all of the outstanding common units of EPB that we did not already own. On December 2, 2015, the Court denied our motionpursue. Defendants have moved to dismiss the remaining claims in Brinckerhoff II based upon our acquisition of all of the outstanding common units of EPB, and held that damages should be calculated by considering the unaffiliated unitholders’ ownership percentage as of the effective date of the merger. Based on this ruling, the Court entered judgment on February 4, 2016 in the amount of $100.2 million plus interest at the legal rate for the period from November 15, 2010 until the date of payment, if any payment is ultimately required. We will file an appeal to the Delaware Supreme Court and execution on the judgment has been stayed until the appeal is decided. At the present time, we do not believe that an ultimate award, if any, will have a material financial impact on our Company.suit. We continue to believe that both the merger and the drop down transactions at issue were appropriate and in the best interests of EPB, and we intend to continue to defend thethese lawsuits vigorously.
Price Reporting Litigation
Beginning in 2003, several lawsuits were filed by purchasers of natural gas against El Paso Corporation, El Paso Marketing L.P. and numerous other energy companies based on a claim under state antitrust law that such defendants conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Several of the cases have been settled or dismissed. The remaining cases, which wereare pending in a U.S. District Court in Nevada, federal court, were dismissed, but the dismissal was reversed by the 9Ninthth Circuit Court of Appeals. The U.S. Supreme Court affirmed the 9th Ninth Circuit Court of Appeals in a decision dated April 21, 2015, and the cases were then remanded to the Nevada federal courtDistrict Court for further consideration and trial, if necessary, of numerous remaining issues. AlthoughOn May 24, 2016, the District Court granted a motion for summary judgment dismissing a lawsuit brought by an industrial consumer in Kansas in which approximately $500 million in damages in excesshas been alleged. That ruling has been appealed to the Ninth Circuit Court of $140 millionAppeals. Settlements have been allegedreached in totalclass actions originally filed in Kansas and Missouri, which settlements received final court approval and have been paid. In the remaining case, a Wisconsin class action in which approximately $300 million in damages
has been alleged against all defendants, in onethe District Court denied plaintiff’s motion for class certification. The Ninth Circuit Court of the remaining lawsuits where a damage number is provided, thereAppeals granted plaintiff’s request for an interlocutory appeal of this ruling. There remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, thatwhich may be allocated to us. Therefore,us in the remaining lawsuits and therefore, our costs and legal exposure, related to the remaining outstanding lawsuitsif any, and claimscosts are not currently determinable.
Kinder Morgan, Inc. Corporate Reorganization Litigation
Certain unitholders of KMP and EPB filed five putative class action lawsuits in the Court of Chancery of the State of Delaware in connection with the Merger Transactions, which the Court consolidated under the caption In re Kinder Morgan, Inc. Corporate Reorganization Litigation (Consolidated Case No. 10093-VCL). The plaintiffs originally sought to enjoin one or more of the proposed Merger Transactions, which relief the Court denied on November 5, 2014. On December 12, 2014, the plaintiffs filed a Verified Second Consolidated Amended Class Action Complaint, which purports to assert claims on behalf of both the former EPB unitholders and the former KMP unitholders. The EPB plaintiff alleged that (i) El Paso Pipeline GP Company, L.L.C. (EPGP), the general partner of EPB, and the directors of EPGP breached duties under the EPB partnership agreement, including the implied covenant of good faith and fair dealing, by entering into the EPB Transaction; (ii) EPB, E
Merger Sub LLC, KMI and individual defendants aided and abetted such breaches; and (iii) EPB, E Merger Sub LLC, KMI, and individual defendants tortiously interfered with the EPB partnership agreement by causing EPGP to breach its duties under the EPB partnership agreement.
The KMP plaintiffs allege that (i) KMR, KMGP, and individual defendants breached duties under the KMP partnership agreement, including the implied duty of good faith and fair dealing, by entering into the KMP Transaction and by failing to adequately disclose material facts related to the transaction; (ii) KMI aided and abetted such breach; and (iii) KMI, KMP, KMR, P Merger Sub LLC, and individual defendants tortiously interfered with the rights of the plaintiffs and the putative class under the KMP partnership agreement by causing KMGP to breach its duties under the KMP partnership agreement. The complaint seeks declaratory relief that the transactions were unlawful and unenforceable, reformation, rescission, rescissory or compensatory damages, interest, and attorneys’ and experts’ fees and costs. On December 30, 2014, the defendants moved to dismiss the complaint. On April 2, 2015, the EPB plaintiff and the defendants submitted a stipulation and proposed order of dismissal, agreeing to dismiss all claims brought by the EPB plaintiff with prejudice as to the EPB lead plaintiff and without prejudice to all other members of the putative EPB class. The Court entered such order on April 2, 2015.
On August 24, 2015, the Court issued an order granting the defendants’ motion to dismiss the remaining counts of the complaint for failure to state a claim. On September 21, 2015, plaintiffs filed a notice of appeal to the Supreme Court of the State of Delaware, captioned Haynes Family Trust et al. v. Kinder Morgan G.P., Inc. et al. (Case No. 515). The plaintiffs are only appealing the dismissal of claims brought against defendants KMGP, Ted A. Gardner, Gary L. Hultquist, and Perry M. Waughtal and not those asserted against KMI, P. Merger Sub LLC, Richard D. Kinder, Steven J. Kean, KMP and KMR. The Supreme Court will hear oral argument on March 9, 2016. The defendants believe the allegations against them lack merit, and they intend to vigorously defend the lawsuit.
Kinder Morgan Energy Partners, L.P. Capex Litigation
Putative class action and derivative complaints were filed in the Court of Chancery in the State of Delaware against defendants KMI, KMGP and nominal defendant KMEP on February 5, 2014 and March 27, 2014 captioned Slotoroff v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al (Case No. 9318) and Burns et al v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al (Case No. 9479) respectively. The cases were consolidated on April 8, 2014 (Consolidated Case No. 9318). The consolidated suit asserted claims both individually and on behalf of a putative class consisting of all public holders of KMEP units during the period of February 5, 2011 through the date of the filing of the complaints. The suit alleged direct and derivative causes of action for breach of the partnership agreement, breach of the duty of good faith and fair dealing, aiding and abetting, and tortious interference. Among other things, the suit alleged that defendants made a bad faith allocation of capital expenditures to expansion capital expenditures rather than maintenance capital expenditures for the alleged purpose of “artificially” inflating KMEP’s distributions and growth rate. The suit alleged that hundreds of millions of dollars were distributed improperly and sought disgorgement of any distributions to KMGP, KMI and any related entities, beyond amounts that would have been distributed in accordance with a “good faith” allocation of maintenance capital expenses, together with other unspecified monetary damages including punitive damages and attorney fees.
On August 14, 2015, the parties entered into a Stipulation and Agreement of Settlement pursuant to which defendants paid $27.5 million (the “Settlement Fund”) to a class of former holders of KMEP common units, and all claims asserted in the consolidated suit are released. Following notice to the putative class members, on December 22, 2015, the Court approved the settlement which also includes a release of all claims asserted in the Walker litigation discussed below, and awarded attorneys’ fees and litigation expenses to Plaintiffs’ counsel to be paid from the Settlement Fund. All of the defendants believe they acted properly, in good faith, and in a manner consistent with any and all legal, contractual and equitable duties and obligations, including those contained in the Limited Partnership Agreement. We entered into this settlement solely to avoid the substantial burden, expense, inconvenience and distraction of continued litigation and to resolve each of the released claims.
Walker v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al.
On March 6, 2014, a putative class action and derivative complaint was filed in the District Court of Harris County, Texas (Case No. 2014-11872 in the 215th Judicial District) against KMI, KMGP, KMR, Richard D. Kinder, Steven J. Kean, Ted A. Gardner, Gary L. Hultquist, Perry M. Waughtal and nominal defendant KMEP. The suit was filed by Kenneth Walker, a purported unit holder of KMEP, and alleged derivative causes of action for alleged violation of duties owed under the partnership agreement, breach of the implied covenant of good faith and fair dealing, “abuse of control” and “gross mismanagement” in connection with the calculation of distributions and allocation of capital expenditures to expansion capital expenditures and maintenance capital expenditures. The suit sought unspecified money damages, interest, punitive damages, attorney and expert fees, costs and expenses, unspecified equitable relief, and demanded a trial by jury. On January 5, 2016,
Plaintiffs filed a Notice of Nonsuit, with prejudice, which the Court subsequently granted, dismissing all claims in the action with prejudice.
Pipeline Integrity and Releases
From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
General
As of December 31, 20152017 and 2014,2016, our total reserve for legal matters was $463$350 million and $400$407 million, respectively. The reserve primarily relates to various claims from regulatory proceedings arising in our products and natural gas pipeline segments and certain corporate matters. The overall increase in the reserve from December 31, 2014 is related to certain legal developments during the year ended December 31, 2015 on corporate matters.segments.
Environmental Matters
We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental lawlaws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.
We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations.regulations, including alleged violations of the Risk Management Program and leak detection and repair requirements of the Clean Air Act. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. WeThese alleged violations may result in fines and penalties, but we do not believe that these alleged violationsany such fines and penalties, individually or in the aggregate, will have a material adverse effect on our business, financial position, results of operations or dividends to our shareholders.
be material. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the cleanup.
In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas and CO2.
Portland Harbor Superfund Site, Willamette River, Portland, Oregon
In December 2000, the EPA issued General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). At that time, GATX owned two liquids terminals along the lower reach of the Willamette River, an industrialized area known as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-voting member and pays a minimal fee to be part of the group.member. The LWG agreed to conduct the remedial investigation and feasibility study (RI/FS) leading to the proposed remedy for cleanup of the Portland Harbor site. OnceThe EPA issued the FS and the Proposed Plan on June 8, 2016 which included a proposed combination of dredging, capping, and enhanced natural recovery. On January 6, 2017, the EPA determines the cleanup remedy from the remedial investigations and feasibility studies conducted during the last decade at the site, it will issue aissued its Record of Decision (ROD). Currently, for the final cleanup plan. The final remedy is more stringent than the remedy proposed in the EPA’s Proposed Plan. The estimated cost increased from approximately $750 million to approximately $1.1 billion and active cleanup is now expected to take as long as 13 years to complete. KMLT and 90 other parties are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs. We are participating in the allocation process on behalf of KMLT and KMBT in connection with their current or former ownership or
operation of four facilities located in Portland Harbor. We expectOur share of responsibility for Portland Harbor Superfund Site costs will not be determined until the RI/FSongoing non-judicial allocation process is concluded in several years or a lawsuit is filed that results in a judicial decision allocating responsibility. Until the allocation process is completed, we are unable to conclude in 2016. We expect EPA will publish a Proposed Remedial Action Plan by April 2016 leadingreasonably estimate the extent of our liability for the costs related to a final ROD targeted for late 2016 or early 2017. The allocation
process will follow the issuancedesign of the ROD with an expected completion dateproposed remedy and cleanup of 2018. We anticipate that the site. In addition to CERCLA cleanup activitiescosts, we are reviewing and will begin within two years afterattempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the ROD is issued.site. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.
Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona
The Roosevelt Irrigation District sued KMGP, KMEP and others under CERCLA for alleged contamination of the water purveyor’s wells. The First Amended Complaint sought $175 million in damages againstfrom approximately 70 defendants. On August 6, 2013 plaintiffs filed their Second Amended Complaint seeking monetary damages in unspecified amounts and reducing the number of defendants to 26 including KMEP and SFPP. The claims now presented against KMEP and SFPP are related to alleged releases from a specific parcel within the SFPP Phoenix Terminal and the alleged impact of such releases on water wells owned by the plaintiffs and located in the vicinity of the Terminal. We have filed an answer general denial, and affirmative defenses in response to the Second Amended Complaint.
Mission Valley Terminal Lawsuit
In August 2007, the City of San Diego, on its own behalfComplaint and purporting to act on behalf of the People of the State of California, filed a lawsuit against us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and methyl tertiary butyl ether (MTBE) impacted soils and groundwater beneath the City’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility. The case was filed in the Superior Court of California, San Diego County and was removed in 2007 to the U.S. District Court, Southern District of California (Case No. 07CV1883WCAB). The City disclosed infact discovery that it is seeking approximately $170 million in damages for alleged lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property. Later, in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of other claims that increased its claim for damages to approximately $365 million.
On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties’ summary adjudication motions. The Court tentatively granted our partial motions for summary judgment on the City’s claims for water and real estate damages and the State’s claims for violations of California Business and Professions Code § 17200, tentatively denied the City’s motion for summary judgment on its claims of liability for nuisance and trespass, and tentatively granted our cross motion for summary judgment on such claims. On January 25, 2013, the Court rendered judgment in favor of all defendants on all claims asserted by the City.
On February 20, 2013, the City of San Diego filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit. On May 21, 2015, the Court of Appeals issued a memorandum decision which affirmed the District Court’s summary judgment in our favor with respect to the City’s claim under California Safe Drinking Water and Toxic Enforcement Act, but reversed both the District Court’s summary judgment decision in our favor on the City’s remaining claims and the District Court’s decision to exclude the City’s expert testimony. The Court of Appeals issued a mandate returning the case to the U.S. District Court. On January 25, 2016, the District Court heard oral argument on motions we previously filed to exclude certain expert testimony offered by the City and for partial summary judgment on the City’s claims. By its Order dated February 2, 2016, the Court granted in part and denied in part our motion to exclude certain expert testimony, granted in part and denied in part our motion for partial summary judgment, found that the City is limited to seeking alleged damages relating to the three year period immediately preceding the filing of the lawsuit, found that the City lacks expert opinions or testimony to support its claim for water damages, including the alleged loss of use of the Mission Valley aquifer as a source of both supply and storage of potable water, and denied our motion for partial summary judgment on the City’s alleged real estate and restoration damages. As a result of the Court’s Order, the City’s alleged damages will be reduced from approximately $365 million to approximately $160 million. Trial is scheduled to begin April 5, 2016. We intend to continue to vigorously defend the case.
This site remains under the regulatory oversight and order of the California Regional Water Quality Control Board (RWQCB). SFPP has completed the soil and groundwater remediation at the City of San Diego’s stadium property site and conducted quarterly sampling and monitoring through 2015 as part of the compliance evaluation required by the RWQCB. SFPP expects the RWQCB to issue a notice of no further action with respect to the stadium property site. SFPP’s remediation effort is now focused on its adjacent Mission Valley Terminal site.proceeding.
Uranium Mines in Vicinity of Cameron, Arizona
In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately twenty uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support
the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a potentially responsible party within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work pursuant to which EPNG will conductis conducting a radiological assessment of the surface of the mines.mines and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona (Case No. 3:14-08165-DGC) seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, given the position of the U.S. as owner of the Navajo Reservation, the U.S.’s exploration activities at the mines, and the pervasive control of such federal agencies over all aspects of the nuclear weapons program. Defendants filed an answer and counterclaims seeking contribution and recovery of response costs allegedly incurred by the federal agencies in investigating uranium impacts on the Navajo Reservation. The counterclaim of defendant EPA has been settled, subject to final judicial approval, and no viable claims for reimbursement by the other defendants are known to exist. In August 2017, the District Court found the U.S. liable under CERCLA as owner of the Navajo Reservation. The matter seeking cost recovery and contribution from federal government agencies is set for trial in February 2019. We intend to continue to prosecute and defend this case vigorously.
Lower Passaic River Study Area of the Diamond Alkali Superfund Site, Essex, Hudson, Bergen and Passaic Counties, New Jersey
EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area Superfund Site (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be potentially responsible parties (PRPs) under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group (JDG) of approximately 70 cooperating parties, referred to as the Cooperating Parties Group (CPG), which havehas entered into AOCs and areis directing and funding the work required by the EPA. Under the first AOC, draft remedial investigation and feasibility studies (RI/FS) of the Site were submitted to the EPA in 2015, and comments from the EPA are expected by the end of 2016.remain pending. Under the second AOC, the JDGCPG members conducted a CERCLA removal action at the Passaic River Mile 10.9, and the group is currently conducting EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with the AOCs.
On April 11, 2014, the EPA announced the issuance of its Focused Feasibility Study (FFS) for the lower eight miles of the Passaic River Study Area, and its proposed plan for remedial alternatives to address the dioxin sediment contamination from the mouth of Newark Bay to River Mile 8.3. The EPA estimates the cost for the alternatives will range from $365 million to $3.2 billion. The EPA’s preferred alternative would involve dredging the river bank-to-bank and installing an engineered cap at
an estimated cost of $1.7 billion. In its FFS,On March 4, 2016, the EPA stated that it has identified over 100 industrial facilities as potentially responsible parties and it is likely that there are hundreds more private and public entities that could be named in any litigation concerning responsibility for the Site contamination.
No final remedy for this portion of the Site will be selected until the public comment and response period for the FFS is completed and theissued its Record of Decision (ROD) is issued byfor the EPA, which is expected by March 31, 2016. Untillower eight miles of the Passaic River Study area. The final cleanup plan in the ROD is issued, theresubstantially similar to the EPA’s preferred alternative announced on April 11, 2014. On October 5, 2016, the EPA entered into an AOC with one member of the PRP group requiring such member to spend $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight miles of the Passaic River. The design work is uncertainty about what remedy will be implementedexpected to take four years to complete and the extentcleanup is expected to take six years to complete.
In addition, the EPA has notified PRPs, including EPEC Polymers and EPEC Oil Trust that it intends to propose an allocation for the implementation of potential costs.the remedy for the lower eight miles of the Passaic River Study area. The allocation process has not been finalized and we anticipate the EPA will propose an allocation during 2018. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the FFS and ROD. There is also uncertainty as to the impact of the RI/FS that the CPG is currently preparing for portions of the Site. The draft RI/FS was submitted by the CPG earlier in 2015 and proposes a different remedy than the FFS announced by the EPA. Therefore, the scope of potential EPA claims for the lower eight miles of the Passaic River is not reasonably estimable at this time.
Philadelphia and Point Breeze Terminals, Notices of Violation
On August 7, 2015, KMLT’s Philadelphia Terminal received a Notice of Violation (NOV) from the Pennsylvania Department of Environmental Protection (PADEP) related to an alleged ethanol release from an above ground storage tank at the facility. The NOV alleged a failure to investigate and confirm a suspected release within the regulatory time period and failure of emergency containment to contain a release from a tank. On July 30, 2015, KMLT’s Point Breeze Terminal received a NOV from the PADEP relating to an alleged violation of a regulatory requirement to remove storm water from the emergency containment areas surrounding above ground storage tanks at the facility prior to capacity of containment being reduced by ten percent (10%) or more. Following an informal administrative hearing with the PADEP on October 14, 2015 with respect to both matters, the NOV related to the Philadelphia Terminal was settled for $570,000 and the NOV related to the Point Breeze Terminal was settled for $175,000.
Central Florida Pipeline Release, Tampa, Florida
On July 22, 2011, our subsidiary Central Florida Pipeline LLC (CFPL) reported a refined petroleum products release on a section of its 10-inch diameter pipeline near Tampa, Florida. The pipeline carries jet fuel and diesel to Orlando and was
carrying jet fuel at the time of the incident. There was no fire and no injuries associated with the incident. CFPL cleaned up the release in coordination with federal, state and local agencies. The cause of the incident was determined to be a third party line strike. In August 2015, the EPA requested that CFPL engage in settlement discussions regarding potential penalties sought by the EPA under the Clean Water Act up to the statutory maximum of approximately $0.9 million. Although CFPL does not believe it caused the incident, and is prepared to vigorously defend any claims that might be asserted by the EPA, we are engaging in good faith settlement negotiations as requested by the EPA.
Southeast Louisiana Flood Protection Litigation
On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (SLFPA) filed a petition for damages and injunctive relief in a state district court for Orleans Parish, Louisiana (Case No. 13-6911) against TGP, SNG and approximately 100 other energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The SLFPA asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana. On February 13, 2015, the Court granted defendants’ motion to dismiss the suit for failure to state a claim, and issued an order dismissing the SLFPA’s claims with prejudice. The SLFPA filed a notice of appeal on February 20, 2015. The U.S.On March 3, 2017, the Fifth Circuit Court of Appeals affirmed the U.S. District Court’s decision, and the SLFPA’s petition for writ of certiorari to the Fifth Circuit will hear oral argumentU.S. Supreme Court was denied on February 29, 2016.October 30, 2017, thereby resolving this matter in its entirety.
Plaquemines Parish Louisiana Coastal Zone Litigation
On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana (Docket No. 60-999) against TGP and 17 other energy companies, alleging that defendants’ oil and gas exploration, production and transportation operations in the Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish, including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal Zone Management Act). As a result of such alleged violations of the Coastal Zone Management Act, Plaquemines Parish seeks, among other relief, unspecified monetary relief, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxify the Coastal Zone. In connection with this suit, TGP has made two tenders for defense and indemnity: (1) to Anadarko, as successor to the entity that purchased TGP’s oil and gas assets in Bastian Bay, and (2) to Kinetica, which purchased TGP’s pipeline assets in Bastian Bay in 2013. Anadarko has accepted TGP’s tender (limited to oil and gas assets), and Kinetica rejected TGP’s tender. The Louisiana Department of Natural Resources and Attorney General have intervened in the lawsuit. The Court has separated the defendants into several trial groups with trials expected to be set to begin in 2019. We expect the case involving TGP respondedwill be set for trial in 2020. We will continue to Kineticavigorously defend the suit.
Vermilion Parish Louisiana Coastal Zone Litigation
On July 28, 2016, the District Attorney for the Fifteenth Judicial District of Louisiana, purporting to act on behalf of Vermilion Parish and the State of Louisiana, filed suit in the state district court for Vermilion Parish, Louisiana against TGP and 52 other energy companies, alleging that the defendants’ oil and gas and transportation operations associated with the development of several fields in Vermilion Parish (Operational Areas) were conducted in violation of the Coastal Zone Management Act. The suit alleges such operations caused substantial damage to the coastal waters and nearby lands (Coastal Zone) of Vermilion Parish, resulting in the release of pollutants and contaminants into the environment, improper discharge of oil field wastes, the improper use of waste pits and failure to close such pits, and the dredging of canals, which resulted in degradation of the Operational Areas, including erosion of marshes and degradation of terrestrial and aquatic life therein. As a
result of such alleged violations of the Coastal Zone Management Act, the suit seeks a judgment against the defendants awarding all appropriate damages, the payment of costs to clear, revegetate, detoxify and otherwise restore the Vermilion Parish Coastal Zone, actual restoration of the affected Coastal Zone to its original condition, and reasonable costs and attorney fees. On September 2, 2016, the case was removed to the U.S. District Court for the Western District of Louisiana. Plaintiffs filed a motion to remand the case to the state district court. On September 26, 2017, the U.S. District Court remanded the case to the State District Court for Vermillion Parish. We intend to vigorously defend the suit.
Vintage Assets, Inc. Coastal Erosion Litigation
On December 18, 2015, Vintage Assets, Inc. and several individual landowners filed a petition in the State District Court for Plaquemines Parish, Louisiana alleging that its 5,000 acre property is composed of coastal wetlands, and that SNG and TGP failed to maintain pipeline canals and banks, causing widening of the canals, land loss, and damage to the ecology and hydrology of the marsh, in breach of right of way agreements, prudent operating practices, and Louisiana law. The suit also claims that defendants’ alleged failure to maintain pipeline canals and banks constitutes negligence and has resulted in encroachment of the canals, constituting trespass. The suit seeks in excess of $80 million in money damages, including recovery of litigation costs, damages for trespass, and money damages associated with an alleged loss of natural resources and projected reconstruction cost of replacing or restoring wetlands. The suit was removed to the U.S. District Court for the Eastern District of Louisiana. The SNG assets at issue were sold to Highpoint Gas Transmission, LLC in 2011, which was subsequently purchased by reasserting TGP’sAmerican Midstream Partners, LP. In response to SNG’s demand for defense and indemnity, American Midstream Partners agreed to pay 50% of joint defense costs and reserving its rights.expenses, with a percentage of indemnity to be determined upon final resolution of the suit. On November 12, 2015, the Plaquemines Parish Council adoptedOctober 20, 2016, plaintiffs filed an amended complaint naming Highpoint Gas Transmission, LLC as an additional defendant. A non-jury trial was held during September 2017. We anticipate a resolution directing its legal counsel in all its Coastal Zone cases to take all actions necessary to cause the dismissal of all such cases. By the end of 2015, the Parish’s legal counsel had not taken any action to dismiss the cases, and the defendantsruling in the cases, including TGP infirst quarter 2018. We will continue to vigorously defend the instant case, filed motionssuit, and intend to dismiss onappeal any adverse ruling that may result from the basis of the Parish Council’s November 12, 2015 resolution. Those motions are pending.trial.
General
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business, financial position, results of operations or cash flows. As of December 31, 20152017 and 2014,2016, we have accrued a total reserve for environmental liabilities in the amount of $284$279 million and $340$302 million, respectively. In addition, as of both December 31, 20152017 and 2014,2016, we have recorded a receivable of $13 million and $14 million, respectively, for expected cost recoveries that have been deemed probable.
18. Recent Accounting Pronouncements
Accounting Standards Updates
ASU No. 2014-09Topic 606
On May 28, 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASUfollowed by a series of related accounting standard updates (collectively referred to as “Topic 606”). Topic 606 is designed to create greater revenue recognition and disclosure comparability forin financial statement users across industries and jurisdictions.statements. The provisions of ASU No. 2014-09Topic 606 include a five-step process by which entitiesan entity will recognizedetermine revenue to depictrecognition, depicting the transfer of goods or services to customers in amounts that reflectreflecting the payment to which an entity expects to be entitled in exchange for those goods or services. The standard also will require enhancedTopic 606 requires certain disclosures provideabout contracts with customers and provides more comprehensive guidance for transactions such as service revenue, and contract modifications, and enhance guidance for multiple-element arrangements. ASU No. 2014-09
Topic 606 will be effective forrequire that our revenue recognition policy disclosure include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. Topic 606 will require us to reclassify certain gathering and processing service fees currently reflected as revenues within our Natural Gas segment as reductions to Cost of sales in the Consolidated Statements of Income prospectively beginning January 1, 2018. Early adoption is permitted forTopic 606 will also require disclosure of significant changes in contract asset and contract liability balances period to period and the interim periods withinamount of the adoption year. We are currently reviewing the effect of ASU No. 2014-09 on our revenue recognition and assessing the timing of our adoption.
ASU No. 2015-02
On February 18, 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810) - Amendmentstransaction price allocated to the Consolidated Analysis.” This ASU focuses on the consolidation evaluation for reporting organizationsperformance obligations that are requiredunsatisfied (or partially unsatisfied) as of the end of the reporting period, as applicable. We utilized the modified retrospective method to evaluate whether they should consolidate certain legal entities. ASU No. 2015-02 wasadopt the provisions of this standard effective January 1, 2016. We do2018, which required us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to our retained deficit balance. In accordance with this approach, our consolidated revenues for periods
prior to January 1, 2018 will not expect thebe revised. The cumulative effect of ASU No. 2015-02 to have a material impact on our financial statements.the adoption of this standard as of January 1, 2018 was not material.
ASU No. 2015-11
On July 22, 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory.” This ASU requires entities to subsequently measure inventory at the lower of cost and net realizable value, and defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. ASU No. 2015-11 was effective January 1, 2017. We adopted ASU No. 2015-11 with no material impact to our financial statements.
ASU No. 2016-02
On February 25, 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” This ASU requires that lessees recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. ASU 2016-02 will be effective for us as of January 1, 2017.2019. We are currently reviewing the effect of ASU No. 2015-11.2016-02.
ASU No. 2016-09
On March 30, 2016, the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718).” This ASU was issued as part of the FASB’s simplification initiative and affects all entities that issue share-based payment awards to their employees. This ASU covers accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU No. 2016-09 was effective January 1, 2017. We adopted ASU No. 2016-09 with no material impact to our financial statements. See Note 5 “Income Taxes.”
ASU No. 2016-13
On June 16, 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. ASU No. 2016-13 will be effective for us as of January 1, 2020. We are currently reviewing the effect of ASU No. 2016-13.
ASU No. 2016-18
On November 17, 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” This ASU requires the statement of cash flows to explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statement of cash flows. We adopted ASU No. 2016-18 effective January 1, 2018 with no material impact to our financial statements.
ASU No. 2017-04
On January 26, 2017, the FASB issued ASU No. 2017-04, “Simplifying the Test for Goodwill Impairment (Topic 350)” to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU No. 2017-04 will be effective for us as of January 1, 2020. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2017-05
On February 22, 2017, the FASB issued ASU No. 2017-05, “Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets.” This ASU clarifies the scope and application of ASC 610-20 on contracts for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU also clarifies that the derecognition of all businesses is in the scope of ASC 810 and defines an “in substance nonfinancial asset.” We utilized the modified retrospective method to adopt the provisions of this ASU effective January 1, 2018, which required us to apply the
new standard to (i) all new contracts entered into after January 1, 2018, and (ii) to contracts that were not completed contracts as of January 1, 2018 through a cumulative adjustment to our retained deficit balance. The cumulative effect of the adoption of this standard as of January 1, 2018 was less than $100 million. We will also reclassify EIG’s cumulative contribution to ELC of $485 million from “Other long-term liabilities and deferred credits” to a mezzanine equity classification described as “Redeemable noncontrolling interest” on our future consolidated balance sheets.
ASU No. 2017-07
On March 10, 2017, the FASB issued ASU No. 2017-07, “Compensation - Retirement Benefits (Topic 715).” This ASU requires an employer to disaggregate the service cost component from the other components of net benefit cost, allows only the service cost component of net benefit cost to be eligible for capitalization, and addresses how to present the service cost component and the other components of net benefit cost in the income statement. We adopted ASU No. 2017-07 effective January 1, 2018 with no material impact to our financial statements.
ASU No. 2017-12
On August 28, 2017, the FASB issued ASU No. 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance in order to allow companies to more accurately present the economic effects of risk management activities in the financial statements. ASU No. 2017-12 will be effective for us as of January 1, 2019, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2018-01
On January 25, 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842.” This ASU provides an optional transition practical expedient that, if elected, would not require companies to reconsider its accounting for existing or expired land easements before the adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. ASU No. 2018-01 will be effective for us as of January 1, 2019, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
19. Guarantee of Securities of Subsidiaries
KMI, along with its direct and indirect subsidiariessubsidiary KMP, and Copano, are issuers of certain public debt securities. After the completion of the Merger Transactions, KMI, KMP Copano and substantially all of KMI’s wholly owned domestic subsidiaries, entered intoare parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the parent issuer, subsidiary issuersissuer and other subsidiaries are all guarantors of each series of public debt. As a result of the cross guarantee agreement, a holder of any of the guaranteed public debt securities issued by KMI KMP, or CopanoKMP are in the same position with respect to the net assets, income and cash flows of KMI and the Subsidiary IssuersIssuer and Guarantors. The only amounts that are not available to the holders of each of the guaranteed public debt securities to satisfy the repayment of such securities are the net assets, income and cash flows of the Subsidiary Non-Guarantors.
In lieu of providing separate financial statements for each subsidiary issuer and guarantor, we have included the accompanying condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X. We have presented each of the parent and subsidiary issuersissuer in separate columns in this single set of condensed consolidating financial statements.
On September 1, 2016, we sold a 50% equity interest in SNG (see further details discussed in Note 3, “Acquisitions and Divestitures”). Subsequent to the transaction, we deconsolidated SNG and now account for our equity interest in SNG as an equity investment. Our wholly owned subsidiary which holds our interest in SNG is reflected within the Subsidiary Guarantors column of these condensed consolidating financial statements.
On December 31, 2017, KMP’s interests in Kinder Morgan Bulk Terminals LLC were transferred to KMI. The following condensed consolidating financial information reflects this transaction for all periods presented.
Excluding fair value adjustments, as of December 31, 2015,2017, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Issuer and Guarantor-Copano, and Subsidiary Guarantors had $13,346$13,750 million, $19,985 million, $332$18,885 million, and $6,882$3,310 million of Guaranteed Notes outstanding, respectively. Included in the Subsidiary Guarantors debt balance as presented in the accompanying December 31, 2015
2017 condensed consolidating balance sheetssheet are approximately $177$162 million of capitalized lease debt that is not subject to the cross guarantee agreement.
The accounts within the Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Issuer and Guarantor-Copano, Subsidiary Guarantors and Subsidiary Non-Guarantors are presented using the equity method of accounting for investments in subsidiaries, including subsidiaries that are guarantors and non-guarantors, for purposes of these condensed consolidating financial statements only. These intercompany investments and related activity eliminate in consolidation and are presented separately in the accompanying condensed consolidating balance sheets and statements of income and cash flows.
A significant amount of each Issuers’ income and cash flow is generated by its respective subsidiaries. As a result, the funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it receives from its respective subsidiaries. We utilize a centralized cash pooling program among our majority-owned and consolidated subsidiaries, including the Subsidiary Issuers and Guarantors and Subsidiary Non-Guarantors. The following Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities.
Effective December 31, 2015, Kinder Morgan (Delaware), Inc. and Kinder Morgan Services LLC merged into KMI. As a result of such merger, both entities are no longer Subsidiary Guarantors, and for all periods presented, financial statement balances and activities for Kinder Morgan (Delaware), Inc. and Kinder Morgan Services LLC are reflected within the Parent Issuer and Guarantor column.
Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2017 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Total Revenues | | $ | 35 |
| | $ | — |
| | $ | 12,202 |
| | $ | 1,614 |
| | $ | (146 | ) | | $ | 13,705 |
|
| | | | | | | | | | | | | |
| Operating Costs, Expenses and Other | | | | | | | | | | | | |
| Costs of sales | | — |
| | — |
| | 4,124 |
| | 322 |
| | (101 | ) | | 4,345 |
|
| Depreciation, depletion and amortization | | 16 |
| | — |
| | 1,933 |
| | 312 |
| | — |
| | 2,261 |
|
| Other operating expenses | | 76 |
| | 1 |
| | 2,999 |
| | 524 |
| | (45 | ) | | 3,555 |
|
| Total Operating Costs, Expenses and Other | | 92 |
|
| 1 |
|
| 9,056 |
|
| 1,158 |
|
| (146 | ) |
| 10,161 |
|
| | | | | | | | | | | | | |
| Operating (Loss) Income | | (57 | ) | | (1 | ) |
| 3,146 |
|
| 456 |
|
| — |
| | 3,544 |
|
| | | | | | | | | | | | | |
| Other Income (Expense) | | | | | | | | | | | | |
| Earnings from consolidated subsidiaries | | 3,575 |
| | 2,681 |
| | 419 |
| | 59 |
| | (6,734 | ) | | — |
|
| Earnings from equity investments | | — |
| | — |
| | 428 |
| | — |
| | — |
| | 428 |
|
| Interest, net | | (701 | ) | | 7 |
| | (1,104 | ) | | (34 | ) | | — |
| | (1,832 | ) |
| Amortization of excess cost of equity investments and other, net | | — |
| | — |
| | (2 | ) | | 23 |
| | — |
| | 21 |
|
| | | | | | | | | | | | | |
| Income Before Income Taxes | | 2,817 |
| | 2,687 |
|
| 2,887 |
|
| 504 |
|
| (6,734 | ) | | 2,161 |
|
| | | | | | | | | | | | | |
| Income Tax (Expense) Benefit | | (2,634 | ) | | (5 | ) | | 237 |
| | 464 |
| | — |
| | (1,938 | ) |
| | | | | | | | | | | | | |
| Net Income | | 183 |
| | 2,682 |
|
| 3,124 |
|
| 968 |
|
| (6,734 | ) | | 223 |
|
| Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | — |
| | — |
| | (40 | ) | | (40 | ) |
| | | | | | | | | | | | | |
| Net Income Attributable to Controlling Interests | | 183 |
| | 2,682 |
|
| 3,124 |
|
| 968 |
|
| (6,774 | ) | | 183 |
|
| Preferred Stock Dividends | | (156 | ) | | — |
| | — |
| | — |
| | — |
| | (156 | ) |
| Net Income Available to Common Stockholders | | $ | 27 |
| | $ | 2,682 |
| | $ | 3,124 |
| | $ | 968 |
| | $ | (6,774 | ) | | $ | 27 |
|
| | | | | | | | | | | | | |
| Net Income | | $ | 183 |
| | $ | 2,682 |
|
| $ | 3,124 |
|
| $ | 968 |
|
| $ | (6,734 | ) | | $ | 223 |
|
| Total other comprehensive income | | 69 |
| | 194 |
| | 217 |
| | 160 |
| | (525 | ) | | 115 |
|
| Comprehensive income | | 252 |
| | 2,876 |
|
| 3,341 |
|
| 1,128 |
|
| (7,259 | ) | | 338 |
|
| Comprehensive income attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | (86 | ) | | (86 | ) |
| Comprehensive income attributable to controlling interests | | $ | 252 |
| | $ | 2,876 |
|
| $ | 3,341 |
|
| $ | 1,128 |
|
| $ | (7,345 | ) | | $ | 252 |
|
On January 1, 2015, EPB and its subsidiary, EPPOC merged with and into KMP with KMP surviving the merger. As a result of such merger, all of the wholly owned subsidiaries of EPB became wholly owned subsidiaries of KMP and effective January 1, 2015, EPB is no longer a Subsidiary Issuer and Guarantor. The condensed consolidating financial information reflects this transaction for all periods presented below.Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2016 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Total Revenues | | $ | 34 |
| | $ | — |
| | $ | 11,572 |
| | $ | 1,511 |
| | $ | (59 | ) | | $ | 13,058 |
|
| | | | | | | | | | | | | |
| Operating Costs, Expenses and Other | | | | | | | | | | | | |
| Costs of sales | | — |
| | — |
| | 3,176 |
| | 266 |
| | (13 | ) | | 3,429 |
|
| Depreciation, depletion and amortization | | 18 |
| | — |
| | 1,872 |
| | 319 |
| | — |
| | 2,209 |
|
| Other operating expenses | | 725 |
| | (36 | ) | | 2,459 |
| | 746 |
| | (46 | ) | | 3,848 |
|
| Total Operating Costs, Expenses and Other | | 743 |
| | (36 | ) | | 7,507 |
| | 1,331 |
| | (59 | ) | | 9,486 |
|
| | | | | | | | | | | | | |
| Operating (Loss) Income | | (709 | ) | | 36 |
| | 4,065 |
| | 180 |
| | — |
| | 3,572 |
|
| | | | | | | | | | | | | |
| Other Income (Expense) | | | | | | | | | | | | |
| Earnings from consolidated subsidiaries | | 2,948 |
| | 2,802 |
| | 245 |
| | 58 |
| | (6,053 | ) | | — |
|
| Losses from equity investments | | — |
| | — |
| | (113 | ) | | — |
| | — |
| | (113 | ) |
| Interest, net | | (696 | ) | | 90 |
| | (1,149 | ) | | (51 | ) | | — |
| | (1,806 | ) |
| Amortization of excess cost of equity investments and other, net | | — |
| | — |
| | (20 | ) | | 5 |
| | — |
| | (15 | ) |
| | | | | | | | | | | | | |
| Income Before Income Taxes | | 1,543 |
| | 2,928 |
| | 3,028 |
| | 192 |
| | (6,053 | ) | | 1,638 |
|
| | | | | | | | | | | | | |
| Income Tax Expense | | (835 | ) | | (5 | ) | | (33 | ) | | (44 | ) | | — |
| | (917 | ) |
| | | | | | | | | | | | | |
| Net Income | | 708 |
| | 2,923 |
| | 2,995 |
| | 148 |
| | (6,053 | ) | | 721 |
|
| Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | — |
| | — |
| | (13 | ) | | (13 | ) |
| | | | | | | | | | | | | |
| Net Income Attributable to Controlling Interests | | 708 |
| | $ | 2,923 |
| | $ | 2,995 |
| | $ | 148 |
| | $ | (6,066 | ) | | $ | 708 |
|
| Preferred Stock Dividends | | (156 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (156 | ) |
| Net Income Available to Common Stockholders | | $ | 552 |
| | $ | 2,923 |
| | $ | 2,995 |
| | $ | 148 |
| | $ | (6,066 | ) | | $ | 552 |
|
| | | | | | | | | | | | | |
| Net Income | | $ | 708 |
| | $ | 2,923 |
| | $ | 2,995 |
| | $ | 148 |
| | $ | (6,053 | ) | | $ | 721 |
|
| Total other comprehensive (loss) income | | (200 | ) | | (341 | ) | | (352 | ) | | 55 |
| | 638 |
| | (200 | ) |
| Comprehensive income | | 508 |
| | 2,582 |
| | 2,643 |
| | 203 |
| | (5,415 | ) | | 521 |
|
| Comprehensive income attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | (13 | ) | | (13 | ) |
| Comprehensive income attributable to controlling interests | | $ | 508 |
| | $ | 2,582 |
| | $ | 2,643 |
| | $ | 203 |
| | $ | (5,428 | ) | | $ | 508 |
|
Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2015 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Total Revenues | | $ | 37 |
| | $ | — |
| | $ | 12,840 |
| | $ | 1,575 |
| | $ | (49 | ) | | $ | 14,403 |
|
| | | | | | | | | | | | | |
| Operating Costs, Expenses and Other | | | | | | | | | | | | |
| Costs of sales | | — |
| | — |
| | 3,691 |
| | 367 |
| | 1 |
| | 4,059 |
|
| Depreciation, depletion and amortization | | 22 |
| | — |
| | 1,929 |
| | 358 |
| | — |
| | 2,309 |
|
| Other operating expenses | | 71 |
| | 38 |
| | 4,770 |
| | 759 |
| | (50 | ) | | 5,588 |
|
| Total Operating Costs, Expenses and Other | | 93 |
| | 38 |
| | 10,390 |
| | 1,484 |
| | (49 | ) | | 11,956 |
|
| | | | | | | | | | | | | |
| Operating (Loss) Income | | (56 | ) | | (38 | ) | | 2,450 |
| | 91 |
| | — |
| | 2,447 |
|
| | | | | | | | | | | | | |
| Other Income (Expense) | | | | | | | | | | | | |
| Earnings (losses) from consolidated subsidiaries | | 1,430 |
| | 1,631 |
| | 118 |
| | (30 | ) | | (3,149 | ) | | — |
|
| Earnings from equity investments | | — |
| | — |
| | 384 |
| | — |
| | — |
| | 384 |
|
| Interest, net | | (686 | ) | | 23 |
| | (1,345 | ) | | (43 | ) | | — |
| | (2,051 | ) |
| Amortization of excess cost of equity investments and other, net | | — |
| | 1 |
| | (17 | ) | | 8 |
| | — |
| | (8 | ) |
| | | | | | | | | | | | | |
| Income Before Income Taxes | | 688 |
| | 1,617 |
| | 1,590 |
| | 26 |
| | (3,149 | ) | | 772 |
|
| | | | | | | | | | | | | |
| Income Tax Expense | | (435 | ) | | (4 | ) | | (6 | ) | | (119 | ) | | — |
| | (564 | ) |
| | | | | | | | | | | | | |
| Net Income (Loss) | | 253 |
| | 1,613 |
| | 1,584 |
| | (93 | ) | | (3,149 | ) | | 208 |
|
| Net Loss Attributable to Noncontrolling Interests | | — |
| | — |
| | — |
| | — |
| | 45 |
| | 45 |
|
| | | | | | | | | | | | | |
| Net Income (Loss) Attributable to Controlling Interests | | 253 |
| | 1,613 |
| | 1,584 |
| | (93 | ) | | (3,104 | ) | | 253 |
|
| Preferred Stock Dividends | | (26 | ) | | — |
| | — |
| | — |
| | — |
| | (26 | ) |
| Net Income (Loss) Available to Common Stockholders | | 227 |
| | 1,613 |
| | 1,584 |
| | (93 | ) | | (3,104 | ) | | 227 |
|
| | | | | | | | | | | | | |
| Net Income (Loss) | | $ | 253 |
| | $ | 1,613 |
| | $ | 1,584 |
| | $ | (93 | ) | | $ | (3,149 | ) | | $ | 208 |
|
| Total other comprehensive loss | | (444 | ) | | (460 | ) | | (325 | ) | | (326 | ) | | 1,111 |
| | (444 | ) |
| Comprehensive (loss) income | | (191 | ) | | 1,153 |
| | 1,259 |
| | (419 | ) | | (2,038 | ) | | (236 | ) |
| Comprehensive loss attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 45 |
| | 45 |
|
| Comprehensive (loss) income attributable to controlling interests | | $ | (191 | ) | | $ | 1,153 |
| | $ | 1,259 |
| | $ | (419 | ) | | $ | (1,993 | ) | | $ | (191 | ) |
Condensed Consolidating Balance Sheet as of December 31, 2017 (In Millions)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| ASSETS | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 262 |
| | $ | (1 | ) | | $ | 264 |
|
| Other current assets - affiliates | | 6,214 |
| | 5,201 |
| | 22,402 |
| | 858 |
| | (34,675 | ) | | — |
|
| All other current assets | | 243 |
| | 59 |
| | 1,938 |
| | 235 |
| | (24 | ) | | 2,451 |
|
| Property, plant and equipment, net | | 236 |
| | — |
| | 31,093 |
| | 8,826 |
| | — |
| | 40,155 |
|
| Investments | | 665 |
| | — |
| | 6,498 |
| | 135 |
| | — |
| | 7,298 |
|
| Investments in subsidiaries | | 37,983 |
| | 36,728 |
| | 5,417 |
| | 4,232 |
| | (84,360 | ) | | — |
|
| Goodwill | | 13,789 |
| | 22 |
| | 5,166 |
| | 3,185 |
| | — |
| | 22,162 |
|
| Notes receivable from affiliates | | 1,033 |
| | 20,363 |
| | 1,233 |
| | 776 |
| | (23,405 | ) | | — |
|
| Deferred income taxes | | 3,635 |
| | — |
| | — |
| | — |
| | (1,591 | ) | | 2,044 |
|
| Other non-current assets | | 254 |
| | 164 |
| | 4,080 |
| | 183 |
| | — |
| | 4,681 |
|
| Total assets | | $ | 64,055 |
| | $ | 62,537 |
|
| $ | 77,827 |
|
| $ | 18,692 |
|
| $ | (144,056 | ) | | $ | 79,055 |
|
| | | | | | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | |
| Current portion of debt | | $ | 924 |
| | $ | 975 |
| | $ | 805 |
| | $ | 124 |
| | $ | — |
| | $ | 2,828 |
|
| Other current liabilities - affiliates | | 13,225 |
| | 14,188 |
| | 6,512 |
| | 750 |
| | (34,675 | ) | | — |
|
| All other current liabilities | | 468 |
| | 347 |
| | 2,055 |
| | 508 |
| | (25 | ) | | 3,353 |
|
| Long-term debt | | 13,104 |
| | 18,206 |
| | 3,052 |
| | 653 |
| | — |
| | 35,015 |
|
| Notes payable to affiliates | | 2,009 |
| | 448 |
| | 20,593 |
| | 355 |
| | (23,405 | ) | | — |
|
| Deferred income taxes | | — |
| | — |
| | 449 |
| | 1,142 |
| | (1,591 | ) | | — |
|
| Other long-term liabilities and deferred credits | | 689 |
| | 117 |
| | 1,462 |
| | 467 |
| | — |
| | 2,735 |
|
| Total liabilities | | 30,419 |
| | 34,281 |
|
| 34,928 |
|
| 3,999 |
|
| (59,696 | ) |
| 43,931 |
|
| | | | | | | | | | | | | |
| Stockholders’ equity | | | | | | | | | | | | |
| Total KMI equity | | 33,636 |
| | 28,256 |
| | 42,899 |
| | 14,693 |
| | (85,848 | ) | | 33,636 |
|
| Noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 1,488 |
| | 1,488 |
|
| Total stockholders’ equity | | 33,636 |
| | 28,256 |
|
| 42,899 |
|
| 14,693 |
|
| (84,360 | ) | | 35,124 |
|
| Total liabilities and stockholders’ equity | | $ | 64,055 |
| | $ | 62,537 |
|
| $ | 77,827 |
|
| $ | 18,692 |
|
| $ | (144,056 | ) | | $ | 79,055 |
|
Condensed Consolidating Balance Sheet as of December 31, 2016 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| ASSETS | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 471 |
| | $ | — |
| | $ | 9 |
| | $ | 205 |
| | $ | (1 | ) | | $ | 684 |
|
| Other current assets - affiliates | | 5,739 |
| | 1,999 |
| | 13,207 |
| | 655 |
| | (21,600 | ) | | — |
|
| All other current assets | | 269 |
| | 139 |
| | 1,935 |
| | 205 |
| | (3 | ) | | 2,545 |
|
| Property, plant and equipment, net | | 242 |
| | — |
| | 30,795 |
| | 7,668 |
| | — |
| | 38,705 |
|
| Investments | | 665 |
| | 2 |
| | 6,236 |
| | 124 |
| | — |
| | 7,027 |
|
| Investments in subsidiaries | | 26,907 |
| | 28,894 |
| | 4,307 |
| | 4,015 |
| | (64,123 | ) | | — |
|
| Goodwill | | 13,789 |
| | 22 |
| | 5,167 |
| | 3,174 |
| | — |
| | 22,152 |
|
| Notes receivable from affiliates | | 516 |
| | 21,608 |
| | 1,132 |
| | 412 |
| | (23,668 | ) | | — |
|
| Deferred income taxes | | 6,647 |
| | — |
| | — |
| | — |
| | (2,295 | ) | | 4,352 |
|
| Other non-current assets | | 72 |
| | 206 |
| | 4,455 |
| | 107 |
| | — |
| | 4,840 |
|
| Total assets | | $ | 55,317 |
| | $ | 52,870 |
| | $ | 67,243 |
| | $ | 16,565 |
| | $ | (111,690 | ) | | $ | 80,305 |
|
| | | | | | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | |
| Current portion of debt | | $ | 1,286 |
| | $ | 600 |
| | $ | 687 |
| | $ | 123 |
| | $ | — |
| | $ | 2,696 |
|
| Other current liabilities - affiliates | | 3,551 |
| | 13,299 |
| | 4,197 |
| | 553 |
| | (21,600 | ) | | — |
|
| All other current liabilities | | 432 |
| | 362 |
| | 2,016 |
| | 422 |
| | (4 | ) | | 3,228 |
|
| Long-term debt | | 13,308 |
| | 19,277 |
| | 4,095 |
| | 674 |
| | — |
| | 37,354 |
|
| Notes payable to affiliates | | 1,533 |
| | 448 |
| | 20,520 |
| | 1,167 |
| | (23,668 | ) | | — |
|
| Deferred income taxes | | — |
| | — |
| | 681 |
| | 1,614 |
| | (2,295 | ) | | — |
|
| Other long-term liabilities and deferred credits | | 776 |
| | 111 |
| | 821 |
| | 517 |
| | — |
| | 2,225 |
|
| Total liabilities | | 20,886 |
| | 34,097 |
| | 33,017 |
| | 5,070 |
| | (47,567 | ) | | 45,503 |
|
| | | | | | | | | | | | | |
| Stockholders’ equity | | | | | | | | | | | | |
| Total KMI equity | | 34,431 |
| | 18,773 |
| | 34,226 |
| | 11,495 |
| | (64,494 | ) | | 34,431 |
|
| Noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 371 |
| | 371 |
|
| Total stockholders’ equity | | 34,431 |
| | 18,773 |
| | 34,226 |
| | 11,495 |
| | (64,123 | ) | | 34,802 |
|
| Total liabilities and stockholders’ equity | | $ | 55,317 |
| | $ | 52,870 |
| | $ | 67,243 |
| | $ | 16,565 |
| | $ | (111,690 | ) | | $ | 80,305 |
|
Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2015 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Issuer and
Guarantor -
Copano | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Total revenues | | $ | 37 |
| | $ | — |
| | $ | — |
| | $ | 12,607 |
| | $ | 1,808 |
| | $ | (49 | ) | | $ | 14,403 |
|
| | | | | | | | | | | | | | | |
| Operating costs, expenses and other | | | | | | | | | | | | | | |
| Costs of sales | | — |
| | — |
| | — |
| | 3,745 |
| | 369 |
| | 1 |
| | 4,115 |
|
| Depreciation, depletion and amortization | | 22 |
| | — |
| | — |
| | 1,898 |
| | 389 |
| | — |
| | 2,309 |
|
| Other operating expenses | | 71 |
| | 38 |
| | 632 |
| | 4,071 |
| | 770 |
| | (50 | ) | | 5,532 |
|
| Total operating costs, expenses and other | | 93 |
|
| 38 |
|
| 632 |
|
| 9,714 |
|
| 1,528 |
|
| (49 | ) |
| 11,956 |
|
| | | | | | | | | | | | | | | |
| Operating (loss) income | | (56 | ) | | (38 | ) |
| (632 | ) |
| 2,893 |
|
| 280 |
|
| — |
| | 2,447 |
|
| | | | | | | | | | | | | | | |
| Other income (expense) | | | | | | | | | | | | | | |
| Earnings (losses) from consolidated subsidiaries | | 1,430 |
| | 1,643 |
| | 68 |
| | 307 |
| | (30 | ) | | (3,418 | ) | | — |
|
| Earnings from equity investments | | — |
| | — |
| | — |
| | 384 |
| | — |
| | — |
| | 384 |
|
| Interest, net | | (686 | ) | | 23 |
| | (47 | ) | | (1,299 | ) | | (42 | ) | | — |
| | (2,051 | ) |
| Amortization of excess cost of equity investments and other, net | | — |
| | 1 |
| | — |
| | (17 | ) | | 8 |
| | — |
| | (8 | ) |
| | | | | | | | | | | | | | | |
| Income (loss) from continuing operations before income taxes | | 688 |
| | 1,629 |
|
| (611 | ) |
| 2,268 |
|
| 216 |
|
| (3,418 | ) | | 772 |
|
| | | | | | | | | | | | | | | |
| Income tax expense | | (435 | ) | | (4 | ) | | — |
| | (5 | ) | | (120 | ) | | — |
| | (564 | ) |
| | | | | | | | | | | | | | | |
| Net income (loss) | | 253 |
| | 1,625 |
|
| (611 | ) |
| 2,263 |
|
| 96 |
|
| (3,418 | ) | | 208 |
|
| | | | | | | | | | | | | | | |
| Net loss attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | 45 |
| | 45 |
|
| | | | | | | | | | | | | | | |
| Net income (loss) attributable to controlling interests | | 253 |
| | 1,625 |
|
| (611 | ) |
| 2,263 |
|
| 96 |
|
| (3,373 | ) | | 253 |
|
| | | | | | | | | | | | | | | |
| Preferred stock dividends | | (26 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (26 | ) |
| Net income (loss) available to common stockholders | | $ | 227 |
| | $ | 1,625 |
| | $ | (611 | ) | | $ | 2,263 |
| | $ | 96 |
| | $ | (3,373 | ) | | $ | 227 |
|
| | | | | | | | | | | | | | | |
| Net income (loss) | | $ | 253 |
| | $ | 1,625 |
|
| $ | (611 | ) |
| $ | 2,263 |
|
| $ | 96 |
|
| $ | (3,418 | ) | | $ | 208 |
|
| Total other comprehensive loss | | (444 | ) | | (460 | ) | | — |
| | (325 | ) | | (326 | ) | | 1,111 |
| | (444 | ) |
| Comprehensive (loss) income | | (191 | ) | | 1,165 |
|
| (611 | ) |
| 1,938 |
|
| (230 | ) |
| (2,307 | ) | | (236 | ) |
| Comprehensive loss attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | 45 |
| | 45 |
|
| Comprehensive (loss) income attributable to controlling interests | | $ | (191 | ) | | $ | 1,165 |
|
| $ | (611 | ) |
| $ | 1,938 |
|
| $ | (230 | ) |
| $ | (2,262 | ) | | $ | (191 | ) |
Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2014 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Issuer and
Guarantor -
Copano | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Total revenues | | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | 14,310 |
| | $ | 1,886 |
| | $ | (6 | ) | | $ | 16,226 |
|
| | | | | | | | | | | | | | | |
| Operating costs, expenses and other | | | | | | | | | | | | | | |
| Costs of sales | | — |
| | — |
| | — |
| | 5,737 |
| | 499 |
| | 42 |
| | 6,278 |
|
| Depreciation, depletion and amortization | | 21 |
| | — |
| | — |
| | 1,655 |
| | 364 |
| | — |
| | 2,040 |
|
| Other operating expenses | | 30 |
| | 5 |
| | 32 |
| | 2,927 |
| | 514 |
| | (48 | ) | | 3,460 |
|
| Total operating costs, expenses and other | | 51 |
| | 5 |
| | 32 |
| | 10,319 |
| | 1,377 |
| | (6 | ) | | 11,778 |
|
| | | | | | | | | | | | | | | |
| Operating (loss) income | | (15 | ) | | (5 | ) | | (32 | ) | | 3,991 |
| | 509 |
| | — |
| | 4,448 |
|
| | | | | | | | | | | | | | | |
| Other income (expense) | | | | | | | | | | | | | | |
| Earnings from consolidated subsidiaries | | 2,080 |
| | 3,977 |
| | 224 |
| | 664 |
| | 1,120 |
| | (8,065 | ) | | — |
|
| Earnings from equity investments | | — |
| | — |
| | — |
| | 407 |
| | (1 | ) | | — |
| | 406 |
|
| Interest, net | | (513 | ) | | (111 | ) | | (46 | ) | | (1,039 | ) | | (89 | ) | | — |
| | (1,798 | ) |
| Amortization of excess cost of equity investments and other, net | | — |
| | — |
| | — |
| | (13 | ) | | 48 |
| | — |
| | 35 |
|
| | | | | | | | | | | | | | | |
| Income from continuing operations before income taxes | | 1,552 |
| | 3,861 |
| | 146 |
| | 4,010 |
| | 1,587 |
| | (8,065 | ) | | 3,091 |
|
| | | | | | | | | | | | | | | |
| Income tax expense | | (278 | ) | | (7 | ) | | — |
| | (71 | ) | | (292 | ) | | — |
| | (648 | ) |
| | | | | | | | | | | | | | | |
| Net income | | 1,274 |
| | 3,854 |
| | 146 |
| | 3,939 |
| | 1,295 |
| | (8,065 | ) | | 2,443 |
|
| Net income attributable to noncontrolling interests | | (248 | ) | | (211 | ) | | — |
| | — |
| | — |
| | (958 | ) | | (1,417 | ) |
| Net income attributable to controlling interests | | $ | 1,026 |
| | $ | 3,643 |
| | $ | 146 |
| | $ | 3,939 |
| | $ | 1,295 |
| | $ | (9,023 | ) | | $ | 1,026 |
|
| | | | | | | | | | | | | | | |
| Net income | | $ | 1,274 |
| | $ | 3,854 |
| | $ | 146 |
| | $ | 3,939 |
| | $ | 1,295 |
| | $ | (8,065 | ) | | $ | 2,443 |
|
| Total other comprehensive (loss) income | | (24 | ) | | 275 |
| | — |
| | 288 |
| | (168 | ) | | (351 | ) | | 20 |
|
| Comprehensive income | | 1,250 |
| | 4,129 |
| | 146 |
| | 4,227 |
| | 1,127 |
| | (8,416 | ) | | 2,463 |
|
| Comprehensive income attributable to noncontrolling interests | | (273 | ) | | (203 | ) | | — |
| | — |
| | — |
| | (1,010 | ) | | (1,486 | ) |
| Comprehensive income attributable to controlling interests | | $ | 977 |
| | $ | 3,926 |
| | $ | 146 |
| | $ | 4,227 |
| | $ | 1,127 |
| | $ | (9,426 | ) | | $ | 977 |
|
Condensed Consolidating Statements of Income and Comprehensive Income for the Year Ended December 31, 2013 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Issuer and
Guarantor -
Copano | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Total revenues | | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | 12,511 |
| | $ | 1,512 |
| | $ | 11 |
| | $ | 14,070 |
|
| | | | | | | | | | | | | | | |
| Operating costs, expenses and other | | | | | | | | | | | | | | |
| Costs of sales | | — |
| | — |
| | — |
| | 4,739 |
| | 468 |
| | 46 |
| | 5,253 |
|
| Depreciation, depletion and amortization | | 20 |
| | — |
| | — |
| | 1,466 |
| | 320 |
| | — |
| | 1,806 |
|
| Other operating expenses | | 22 |
| | 8 |
| | 38 |
| | 2,325 |
| | 663 |
| | (35 | ) | | 3,021 |
|
| Total operating costs, expenses and other | | 42 |
| | 8 |
| | 38 |
| | 8,530 |
| | 1,451 |
| | 11 |
| | 10,080 |
|
| | | | | | | | | | | | | | | |
| Operating (loss) income | | (6 | ) | | (8 | ) | | (38 | ) | | 3,981 |
| | 61 |
| | — |
| | 3,990 |
|
| | | | | | | | | | | | | | | |
| Other income (expense) | | | | | | | | | | | | | | |
| Earnings from consolidated subsidiaries | | 2,025 |
| | 4,010 |
| | 163 |
| | 255 |
| | 1,755 |
| | (8,208 | ) | | — |
|
| Earnings from equity investments | | — |
| | — |
| | — |
| | 323 |
| | 4 |
| | — |
| | 327 |
|
| Interest, net | | (539 | ) | | (100 | ) | | (36 | ) | | (965 | ) | | (35 | ) | | — |
| | (1,675 | ) |
| Amortization of excess cost of equity investments and other, net | | (1 | ) | | — |
| | (1 | ) | | 549 |
| | 249 |
| | — |
| | 796 |
|
| | | | | | | | | | | | | | | |
| Income from continuing operations before income taxes | | 1,479 |
| | 3,902 |
| | 88 |
| | 4,143 |
| | 2,034 |
| | (8,208 | ) | | 3,438 |
|
| | | | | | | | | | | | | | | |
| Income tax (expense) benefit | | (41 | ) | | (11 | ) | | — |
| | 50 |
| | (740 | ) | | — |
| | (742 | ) |
| | | | | | | | | | | | | | | |
| Income from continuing operations | | 1,438 |
| | 3,891 |
| | 88 |
| | 4,193 |
| | 1,294 |
| | (8,208 | ) | | 2,696 |
|
| | | | | | | | | | | | | | | |
| Loss from discontinued operations | | — |
| | — |
| | — |
| | (4 | ) | | — |
| | — |
| | (4 | ) |
| | | | | | | | | | | | | | | |
| Net income | | 1,438 |
| | 3,891 |
| | 88 |
| | 4,189 |
| | 1,294 |
| | (8,208 | ) | | 2,692 |
|
| Net income attributable to noncontrolling interests | | (245 | ) | | (236 | ) | | — |
| | — |
| | — |
| | (1,018 | ) | | (1,499 | ) |
| Net income attributable to controlling interests | | $ | 1,193 |
| | $ | 3,655 |
| | $ | 88 |
| | $ | 4,189 |
| | $ | 1,294 |
| | $ | (9,226 | ) | | $ | 1,193 |
|
| | | | | | | | | | | | | | | |
| Net income | | $ | 1,438 |
| | $ | 3,891 |
| | $ | 88 |
| | $ | 4,189 |
| | $ | 1,294 |
| | $ | (8,208 | ) | | $ | 2,692 |
|
| Total other comprehensive income (loss) | | 81 |
| | (135 | ) | | — |
| | (99 | ) | | (172 | ) | | 365 |
| | 40 |
|
| Comprehensive income | | 1,519 |
|
| 3,756 |
|
| 88 |
|
| 4,090 |
|
| 1,122 |
|
| (7,843 | ) | | 2,732 |
|
| Comprehensive income attributable to noncontrolling interests | | (232 | ) | | (237 | ) | | — |
| | — |
| | — |
| | (976 | ) | | (1,445 | ) |
| Comprehensive income attributable to controlling interests | | $ | 1,287 |
|
| $ | 3,519 |
|
| $ | 88 |
|
| $ | 4,090 |
|
| $ | 1,122 |
| | $ | (8,819 | ) | | $ | 1,287 |
|
Condensed Consolidating Balance Sheets as of December 31, 2015 (In Millions)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Issuer and
Guarantor -
Copano | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| ASSETS | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 123 |
| | $ | — |
| | $ | — |
| | $ | 12 |
| | $ | 142 |
| | $ | (48 | ) | | $ | 229 |
|
| Other current assets - affiliates | | 2,233 |
| | 1,600 |
| | — |
| | 9,451 |
| | 695 |
| | (13,979 | ) | | — |
|
| All other current assets | | 126 |
| | 119 |
| | — |
| | 2,163 |
| | 195 |
| | (8 | ) | | 2,595 |
|
| Property, plant and equipment, net | | 252 |
| | — |
| | — |
| | 32,195 |
| | 8,100 |
| | — |
| | 40,547 |
|
| Investments | | 16 |
| | 2 |
| | — |
| | 5,906 |
| | 116 |
| | — |
| | 6,040 |
|
| Investments in subsidiaries | | 27,401 |
| | 28,038 |
| | 2,341 |
| | 4,361 |
| | 3,320 |
| | (65,461 | ) | | — |
|
| Goodwill | | 15,089 |
| | 22 |
| | 287 |
| | 5,221 |
| | 3,171 |
| | — |
| | 23,790 |
|
| Notes receivable from affiliates | | 850 |
| | 21,319 |
| | — |
| | 2,070 |
| | 380 |
| | (24,619 | ) | | — |
|
| Deferred income taxes | | 7,501 |
| | — |
| | — |
| | — |
| | — |
| | (2,178 | ) | | 5,323 |
|
| Other non-current assets | | 215 |
| | 307 |
| | 1 |
| | 4,943 |
| | 114 |
| | — |
| | 5,580 |
|
| Total assets | | $ | 53,806 |
| | $ | 51,407 |
|
| $ | 2,629 |
|
| $ | 66,322 |
|
| $ | 16,233 |
|
| $ | (106,293 | ) | | $ | 84,104 |
|
| | | | | | | | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | |
| Current portion of debt | | $ | 67 |
| | $ | 500 |
| | $ | — |
| | $ | 132 |
| | $ | 122 |
| | $ | — |
| | $ | 821 |
|
| Other current liabilities - affiliates | | 1,328 |
| | 8,682 |
| | 39 |
| | 3,216 |
| | 714 |
| | (13,979 | ) | | — |
|
| All other current liabilities | | 321 |
| | 458 |
| | 7 |
| | 1,987 |
| | 527 |
| | (56 | ) | | 3,244 |
|
| Long-term debt | | 13,845 |
| | 20,053 |
| | 378 |
| | 7,447 |
| | 683 |
| | — |
| | 42,406 |
|
| Notes payable to affiliates | | 2,404 |
| | 448 |
| | 622 |
| | 19,840 |
| | 1,305 |
| | (24,619 | ) | | — |
|
| Deferred income taxes | | — |
| | — |
| | 2 |
| | 594 |
| | 1,582 |
| | (2,178 | ) | | — |
|
| Other long-term liabilities and deferred credits | | 722 |
| | 193 |
| | — |
| | 907 |
| | 408 |
| | — |
| | 2,230 |
|
| Total liabilities | | 18,687 |
| | 30,334 |
|
| 1,048 |
|
| 34,123 |
|
| 5,341 |
|
| (40,832 | ) |
| 48,701 |
|
| | | | | | | | | | | | | | | |
| Stockholders’ equity | | | | | | | | | | | | | | |
| Total KMI equity | | 35,119 |
| | 21,073 |
| | 1,581 |
| | 32,199 |
| | 10,892 |
| | (65,745 | ) | | 35,119 |
|
| Noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | 284 |
| | 284 |
|
| Total stockholders’ equity | | 35,119 |
| | 21,073 |
|
| 1,581 |
|
| 32,199 |
|
| 10,892 |
|
| (65,461 | ) | | 35,403 |
|
| Total liabilities and stockholders’ equity | | $ | 53,806 |
| | $ | 51,407 |
|
| $ | 2,629 |
|
| $ | 66,322 |
|
| $ | 16,233 |
|
| $ | (106,293 | ) | | $ | 84,104 |
|
Condensed Consolidating Balance Sheets as of December 31, 2014 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Issuer and
Guarantor -
Copano | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| ASSETS | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 4 |
| | $ | 15 |
| | $ | — |
| | $ | 17 |
| | $ | 279 |
| | $ | — |
| | $ | 315 |
|
| Other current assets - affiliates | | 2,251 |
| | 1,335 |
| | 11 |
| | 11,565 |
| | 403 |
| | (15,565 | ) | | — |
|
| All other current assets | | 655 |
| | 152 |
| | 3 |
| | 2,547 |
| | 358 |
| | (278 | ) | | 3,437 |
|
| Property, plant and equipment, net | | 263 |
| | — |
| | 5 |
| | 29,490 |
| | 8,806 |
| | — |
| | 38,564 |
|
| Investments | | 16 |
| | 1 |
| | — |
| | 5,910 |
| | 109 |
| | — |
| | 6,036 |
|
| Investments in subsidiaries | | 25,286 |
| | 33,414 |
| | 1,911 |
| | 4,628 |
| | 3,337 |
| | (68,576 | ) | | — |
|
| Goodwill | | 15,087 |
| | 22 |
| | 920 |
| | 5,419 |
| | 3,206 |
| | — |
| | 24,654 |
|
| Notes receivable from affiliates | | 522 |
| | 19,832 |
| | — |
| | 2,415 |
| | 496 |
| | (23,265 | ) | | — |
|
| Deferred income taxes | | 7,644 |
| | — |
| | — |
| | — |
| | — |
| | (1,993 | ) | | 5,651 |
|
| Other non-current assets | | 258 |
| | 249 |
| | — |
| | 3,772 |
| | 113 |
| | — |
| | 4,392 |
|
| Total assets | | $ | 51,986 |
| | $ | 55,020 |
| | $ | 2,850 |
| | $ | 65,763 |
| | $ | 17,107 |
| | $ | (109,677 | ) | | $ | 83,049 |
|
| | | | | | | | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | |
| Current portion of debt | | $ | 1,486 |
| | $ | 699 |
| | $ | — |
| | $ | 381 |
| | $ | 151 |
| | $ | — |
| | $ | 2,717 |
|
| Other current liabilities - affiliates | | 1,153 |
| | 11,949 |
| | 115 |
| | 1,482 |
| | 866 |
| | (15,565 | ) | | — |
|
| All other current liabilities | | 236 |
| | 498 |
| | 12 |
| | 2,153 |
| | 1,024 |
| | (278 | ) | | 3,645 |
|
| Long-term debt | | 11,833 |
| | 20,564 |
| | 386 |
| | 6,599 |
| | 715 |
| | — |
| | 40,097 |
|
| Notes payable to affiliates | | 2,619 |
| | 153 |
| | 753 |
| | 18,500 |
| | 1,240 |
| | (23,265 | ) | | — |
|
| Deferred income taxes | | — |
| | — |
| | 2 |
| | 487 |
| | 1,504 |
| | (1,993 | ) | | — |
|
| All other long-term liabilities and deferred credits | | 583 |
| | 78 |
| | 2 |
| | 987 |
| | 514 |
| | — |
| | 2,164 |
|
| Total liabilities | | 17,910 |
| | 33,941 |
| | 1,270 |
| | 30,589 |
| | 6,014 |
| | (41,101 | ) | | 48,623 |
|
| | | | | | | | | | | | | | | |
| Stockholders’ equity | | | | | | | | | | | | | | |
| Total KMI equity | | 34,076 |
| | 21,079 |
| | 1,580 |
| | 35,174 |
| | 11,093 |
| | (68,926 | ) | | 34,076 |
|
| Noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | 350 |
| | 350 |
|
| Total stockholders’ equity | | 34,076 |
| | 21,079 |
| | 1,580 |
| | 35,174 |
| | 11,093 |
| | (68,576 | ) | | 34,426 |
|
| Total liabilities and stockholders’ equity | | $ | 51,986 |
| | $ | 55,020 |
| | $ | 2,850 |
| | $ | 65,763 |
| | $ | 17,107 |
| | $ | (109,677 | ) | | $ | 83,049 |
|
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2015 (In Millions)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Issuer and
Guarantor -
Copano | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Net cash (used in) provided by operating activities | | $ | (4,218 | ) | | $ | 6,824 |
| | $ | 98 |
| | $ | 10,691 |
| | $ | 811 |
| | $ | (8,903 | ) | | $ | 5,303 |
|
| | | | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | | | |
| Funding to affiliates | | (3,204 | ) | | (8,388 | ) | | (1 | ) | | (8,004 | ) | | (1,066 | ) | | 20,663 |
| | — |
|
| Capital expenditures | | (10 | ) | | — |
| | (2 | ) | | (3,557 | ) | | (332 | ) | | 5 |
| | (3,896 | ) |
| Contributions to investments | | (21 | ) | | — |
| | — |
| | (70 | ) | | (10 | ) | | 5 |
| | (96 | ) |
| Investment in KMP | | (159 | ) | | — |
| | — |
| | — |
| | — |
| | 159 |
| | — |
|
| Acquisitions of assets and investments, net of cash acquired | | (1,843 | ) | | — |
| | — |
| | (236 | ) | | — |
| | — |
| | (2,079 | ) |
| Distributions from equity investments in excess of cumulative earnings | | 2,653 |
| | — |
| | — |
| | 143 |
| | — |
| | (2,568 | ) | | 228 |
|
| Other, net | | — |
| | 24 |
| | 5 |
| | 55 |
| | 58 |
| | (5 | ) | | 137 |
|
| Net cash (used in) provided by investing activities | | (2,584 | ) | | (8,364 | ) |
| 2 |
|
| (11,669 | ) |
| (1,350 | ) |
| 18,259 |
| | (5,706 | ) |
| | | | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | | | |
| Issuances of debt | | 14,316 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 14,316 |
|
| Payments of debt | | (14,048 | ) | | (675 | ) | | — |
| | (383 | ) | | (10 | ) | | — |
| | (15,116 | ) |
| Funding from (to) affiliates | | 5,502 |
| | 6,989 |
| | (100 | ) | | 7,486 |
| | 786 |
| | (20,663 | ) | | — |
|
| Debt issue costs | | (24 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (24 | ) |
| Issuances of common shares | | 3,870 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 3,870 |
|
| Issuance of mandatory convertible preferred stock | | 1,541 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,541 |
|
| Cash dividends | | (4,224 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (4,224 | ) |
| Repurchases of shares and warrants | | (12 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (12 | ) |
| Contributions from parents | | — |
| | 156 |
| | — |
| | 3 |
| | 16 |
| | (175 | ) | | — |
|
| Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | 11 |
| | 11 |
|
| Distributions to parents | | — |
| | (4,944 | ) | | — |
| | (6,133 | ) | | (380 | ) | | 11,457 |
| | — |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | (34 | ) | | (34 | ) |
| Other, net | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
| | (1 | ) |
| Net cash provided by (used in) financing activities | | 6,921 |
| | 1,525 |
|
| (100 | ) |
| 973 |
|
| 412 |
|
| (9,404 | ) | | 327 |
|
| | | | | | | | | | | | | | | |
| Effect of exchange rate changes on cash and cash equivalents | | — |
| | — |
| | — |
| | — |
| | (10 | ) | | — |
| | (10 | ) |
| | | | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | 119 |
| | (15 | ) |
| — |
|
| (5 | ) |
| (137 | ) |
| (48 | ) | | (86 | ) |
| Cash and cash equivalents, beginning of period | | 4 |
| | 15 |
| | — |
| | 17 |
| | 279 |
| | — |
| | 315 |
|
| Cash and cash equivalents, end of period | | $ | 123 |
| | $ | — |
|
| $ | — |
|
| $ | 12 |
|
| $ | 142 |
|
| $ | (48 | ) | | $ | 229 |
|
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2014 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Issuer and
Guarantor -
Copano | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Net cash provided by (used in) operating activities | | $ | 1,419 |
| | $ | 3,810 |
| | $ | (77 | ) | | $ | 5,876 |
| | $ | 1,174 |
| | $ | (7,735 | ) | | $ | 4,467 |
|
| | | | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | | | |
| Funding to affiliates | | (1,949 | ) | | (6,644 | ) | | — |
| | (3,886 | ) | | (1,088 | ) | | 13,567 |
| | — |
|
| Capital expenditures | | (1 | ) | | — |
| | (63 | ) | | (3,050 | ) | | (705 | ) | | 202 |
| | (3,617 | ) |
| Contributions to investments | | — |
| | (189 | ) | | — |
| | (389 | ) | | — |
| | 189 |
| | (389 | ) |
| Investment in KMP | | (550 | ) | | — |
| | — |
| | — |
| | — |
| | 550 |
| | — |
|
| Acquisitions of assets and investments | | — |
| | — |
| | — |
| | (1,370 | ) | | (18 | ) | | — |
| | (1,388 | ) |
| Drop down assets to KMP | | 875 |
| | (875 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
| Distributions from equity investments in excess of cumulative earnings | | 93 |
| | 440 |
| | — |
| | 183 |
| | — |
| | (534 | ) | | 182 |
|
| Other, net | | — |
| | 27 |
| | 202 |
| | 20 |
| | (46 | ) | | (201 | ) | | 2 |
|
| Net cash (used in) provided by investing activities | | (1,532 | ) | | (7,241 | ) | | 139 |
| | (8,492 | ) | | (1,857 | ) | | 13,773 |
| | (5,210 | ) |
| | | | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | | | |
| Issuances of debt | | 10,594 |
| | 13,979 |
| | — |
| | — |
| | — |
| | — |
| | 24,573 |
|
| Payments of debt | | (5,479 | ) | | (12,171 | ) | | — |
| | (142 | ) | | (9 | ) | | — |
| | (17,801 | ) |
| Funding from (to) affiliates | | 956 |
| | 4,129 |
| | (63 | ) | | 7,624 |
| | 921 |
| | (13,567 | ) | | — |
|
| Debt issue costs | | (74 | ) | | (15 | ) | | — |
| | — |
| | — |
| | — |
| | (89 | ) |
| Cash dividends | | (1,760 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (1,760 | ) |
| Repurchases of shares and warrants | | (192 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (192 | ) |
| Cash consideration of Merger Transactions | | (3,937 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (3,937 | ) |
| Merger Transactions costs | | (74 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (74 | ) |
| Contributions from parents | | — |
| | 1,912 |
| | — |
| | 533 |
| | 64 |
| | (2,509 | ) | | — |
|
| Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | 1,767 |
| | 1,767 |
|
| Distributions to parents | | — |
| | (4,475 | ) | | — |
| | (5,398 | ) | | (411 | ) | | 10,284 |
| | — |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | (2,013 | ) | | (2,013 | ) |
| Other, net | | — |
| | (1 | ) | | — |
| | (2 | ) | | — |
| | — |
| | (3 | ) |
| Net cash provided by (used in) financing activities | | 34 |
| | 3,358 |
| | (63 | ) | | 2,615 |
| | 565 |
| | (6,038 | ) | | 471 |
|
| | | | | | | | | | | | | | | |
| Effect of exchange rate changes on cash and cash equivalents | | — |
| | — |
| | — |
| | 1 |
| | (12 | ) | | — |
| | (11 | ) |
| | | | | | | | | | | | | | | |
| Net decrease in cash and cash equivalents | | (79 | ) | | (73 | ) | | (1 | ) | | — |
| | (130 | ) | | — |
| | (283 | ) |
| Cash and cash equivalents, beginning of period | | 83 |
| | 88 |
| | 1 |
| | 17 |
| | 409 |
| | — |
| | 598 |
|
| Cash and cash equivalents, end of period | | $ | 4 |
| | $ | 15 |
| | $ | — |
| | $ | 17 |
| | $ | 279 |
| | $ | — |
| | $ | 315 |
|
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2013 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Issuer and
Guarantor -
Copano | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Net cash provided by (used in) operating activities | | $ | 1,792 |
| | $ | 3,669 |
| | $ | (408 | ) | | $ | 5,118 |
| | $ | 769 |
| | $ | (6,818 | ) | | $ | 4,122 |
|
| | | | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | | | |
| Funding to affiliates | | (413 | ) | | (7,183 | ) | | (1 | ) | | (3,944 | ) | | (1,332 | ) | | 12,873 |
| | — |
|
| Capital expenditures | | (6 | ) | | — |
| | (141 | ) | | (2,418 | ) | | (804 | ) | | — |
| | (3,369 | ) |
| Proceeds from sales of assets and investments | | — |
| | — |
| | — |
| | 118 |
| | 372 |
| | — |
| | 490 |
|
| Contributions to investments | | (6 | ) | | (52 | ) | | — |
| | (217 | ) | | — |
| | 58 |
| | (217 | ) |
| Investment in KMP | | (68 | ) | | — |
| | — |
| | — |
| | — |
| | 68 |
| | — |
|
| Acquisitions of assets and investments | | — |
| | — |
| | 5 |
| | (297 | ) | | — |
| | — |
| | (292 | ) |
| Drop down assets to KMP | | 994 |
| | — |
| | — |
| | (994 | ) | | — |
| | — |
| | — |
|
| Distributions from equity investments in excess of cumulative earnings | | 41 |
| | 296 |
| | — |
| | 183 |
| | — |
| | (335 | ) | | 185 |
|
| Other, net | | — |
| | (12 | ) | | — |
| | 105 |
| | (12 | ) | | — |
| | 81 |
|
| Net cash provided by (used in) investing activities | | 542 |
| | (6,951 | ) | | (137 | ) | | (7,464 | ) | | (1,776 | ) | | 12,664 |
| | (3,122 | ) |
| | | | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | | | |
| Issuances of debt | | 3,028 |
| | 10,300 |
| | — |
| | 14 |
| | 239 |
| | — |
| | 13,581 |
|
| Payments of debt | | (3,624 | ) | | (7,802 | ) | | (854 | ) | | (106 | ) | | (7 | ) | | — |
| | (12,393 | ) |
| Funding from affiliates | | 570 |
| | 2,984 |
| | 1,400 |
| | 7,127 |
| | 792 |
| | (12,873 | ) | | — |
|
| Debt issue costs | | (15 | ) | | (22 | ) | | — |
| | — |
| | (1 | ) | | — |
| | (38 | ) |
| Cash dividends | | (1,622 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (1,622 | ) |
| Repurchases of shares and warrants | | (637 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (637 | ) |
| Contributions from parents | | — |
| | 1,620 |
| | — |
| | 75 |
| | 132 |
| | (1,827 | ) | | — |
|
| Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | 1,706 |
| | 1,706 |
|
| Distributions to parents | | — |
| | (3,914 | ) | | — |
| | (4,776 | ) | | (150 | ) | | 8,840 |
| | — |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | (1,692 | ) | | (1,692 | ) |
| Other, net | | 1 |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
| Net cash (used in) provided by financing activities | | (2,299 | ) | | 3,165 |
| | 546 |
| | 2,334 |
| | 1,005 |
| | (5,846 | ) | | (1,095 | ) |
| | | | | | | | | | | | | | | |
| Effect of exchange rate changes on cash and cash equivalents | | — |
| | — |
| | — |
| | 1 |
| | (22 | ) | | — |
| | (21 | ) |
| | | | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | 35 |
| | (117 | ) | | 1 |
| | (11 | ) | | (24 | ) | | — |
| | (116 | ) |
| Cash and cash equivalents, beginning of period | | 48 |
| | 205 |
| | — |
| | 28 |
| | 433 |
| | — |
| | 714 |
|
| Cash and cash equivalents, end of period | | $ | 83 |
| | $ | 88 |
| | $ | 1 |
| | $ | 17 |
| | $ | 409 |
| | $ | — |
| | $ | 598 |
|
Supplemental Selected Quarterly Financial Data (Unaudited)
|
| | | | | | | | | | | | | | | |
| | Quarters Ended |
| | March 31 | | June 30 | | September 30 | | December 31 |
| | (In millions, except per share amounts) |
| 2015 | | | | | | | |
| Revenues | $ | 3,597 |
| | $ | 3,463 |
| | $ | 3,707 |
| | $ | 3,636 |
|
| Operating Income (Loss) | 1,078 |
| | 892 |
| | 721 |
| | (244 | ) |
| Net Income (Loss) | 419 |
| | 342 |
| | 183 |
| | (736 | ) |
| Net Income (Loss) Attributable to Kinder Morgan, Inc. | 429 |
| | 333 |
| | 186 |
| | (695 | ) |
| Net Income (Loss) Available to Common Stockholders | 429 |
| | 333 |
| | 186 |
| | (721 | ) |
| Basic and Diluted Earnings (Loss) Per Common Share | 0.20 |
| | 0.15 |
| | 0.08 |
| | (0.32 | ) |
| | | | | | | | |
| 2014 | | | | | | | |
| Revenues | $ | 4,047 |
| | $ | 3,937 |
| | $ | 4,291 |
| | $ | 3,951 |
|
| Operating Income | 1,147 |
| | 1,013 |
| | 1,332 |
| | 956 |
|
| Net Income | 601 |
| | 497 |
| | 779 |
| | 566 |
|
| Net Income Attributable to Kinder Morgan, Inc. | 287 |
| | 284 |
| | 329 |
| | 126 |
|
| Basic and Diluted Earnings Per Common Share | 0.28 |
| | 0.27 |
| | 0.32 |
| | 0.08 |
|
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Operating statistics from our oil and gas producing activities for each of the years ended December 31, 2015, 2014 and 2013 are shown in the following table:
| Results of Operations for Oil and Gas Producing Activities – Unit Prices and Costs |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Consolidated Companies(a) | | | | | |
| Production costs per barrel of oil equivalent(b)(c)(d) | $ | 17.68 |
| | $ | 20.55 |
| | $ | 18.81 |
|
| Crude oil production(MBbl/d) | 41.7 |
| | 40.8 |
| | 37.6 |
|
| SACROC crude oil production(MBbl/d) | 28.1 |
| | 27.6 |
| | 25.5 |
|
| Yates crude oil production(MBbl/d) | 8.5 |
| | 8.8 |
| | 9.0 |
|
| | | | | | |
| NGL production(MBbl/d)(d) | 4.1 |
| | 4.2 |
| | 4.1 |
|
| NGL production from gas plants(MBbl/d)(e) | 6.2 |
| | 5.9 |
| | 5.8 |
|
| Total NGL production(MBbl/d) | 10.3 |
| | 10.1 |
| | 9.9 |
|
| SACROC NGL production(MBbl/d)(d) | 3.9 |
| | 3.9 |
| | 3.8 |
|
| Yates NGL production(MBbl/d)(d) | 0.2 |
| | 0.2 |
| | 0.2 |
|
| | | | | | |
| Natural gas production(MMcf/d)(d)(f) | 0.5 |
| | 1.0 |
| | 1.1 |
|
| Natural gas production from gas plants(MMcf/d)(e)(f) | 2.2 |
| | 1.2 |
| | 1.7 |
|
| Total natural gas production(MMcf/d)(f) | 2.7 |
| | 2.2 |
| | 2.8 |
|
| Yates natural gas production(MMcf/d)(d)(f) | 0.3 |
| | 1.0 |
| | 1.1 |
|
| | | | | | |
| Average sales prices including hedge gains/losses: | | | | | |
| Crude oil price per Bbl(g) | $ | 73.11 |
| | $ | 88.41 |
| | $ | 92.70 |
|
| NGL price per Bbl(d)(g) | $ | 18.85 |
| | $ | 42.61 |
| | $ | 46.11 |
|
| Natural gas price per Mcf(d)(h) | $ | 2.19 |
| | $ | 4.04 |
| | $ | 3.23 |
|
| Total NGL price per Bbl(e) | $ | 18.35 |
| | $ | 41.87 |
| | $ | 46.43 |
|
| Total natural gas price per Mcf(e) | $ | 2.30 |
| | $ | 3.91 |
| | $ | 3.21 |
|
| | | | | | |
| Average sales prices excluding hedge gains/losses: | | | | | |
| Crude oil price per Bbl(g) | $ | 47.56 |
| | $ | 86.48 |
| | $ | 94.94 |
|
| NGL price per Bbl(g) | $ | 18.85 |
| | $ | 42.61 |
| | $ | 46.11 |
|
| Natural gas price per Mcf(h) | $ | 2.19 |
| | $ | 4.04 |
| | $ | 3.23 |
|
_______
| |
(a) | Amounts relate to KMCO2 and its consolidated subsidiaries.
|
| |
(b) | Computed using production costs, excluding transportation costs, as defined by the SEC. Natural gas volumes were converted to barrels of oil equivalent using a conversion factor of six Mcf of natural gas to one barrel of oil. |
| |
(c) | Production costs include labor, repairs and maintenance, materials, supplies, fuel and power, and general and administrative expenses directly related to oil and gas producing activities. |
| |
(d) | Includes only production attributable to leasehold ownership. |
| |
(e) | Includes production attributable to our ownership in processing plants and third party processing agreements. |
| |
(f) | Excludes natural gas production used as fuel. |
| |
(g) | Hedge gains/losses for crude oil and NGL are included with crude oil. |
| |
(h) | Natural gas sales were not hedged. |
The following three tables provide supplemental information on oil and gas producing activities, including (i) capitalized costs related to oil and gas producing activities; (ii) costs incurred for the acquisition of oil and gas producing properties and for exploration and development activities; and (iii) the results of operations from oil and gas producing activities.
Our capitalized costs consisted of the following (in millions):Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2017 (In Millions)
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Net cash (used in) provided by operating activities | | $ | (3,184 | ) | | $ | 3,911 |
| | $ | 11,523 |
| | $ | 1,121 |
| | $ | (8,770 | ) | | $ | 4,601 |
|
| | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | |
| Acquisitions of assets and investments, net of cash acquired | | — |
| | — |
| | (4 | ) | | — |
| | — |
| | (4 | ) |
| Capital expenditures | | (23 | ) | | — |
| | (2,390 | ) | | (775 | ) | | — |
| | (3,188 | ) |
| Sales of property, plant and equipment, investments and other net assets, net of removal costs | | 16 |
| | — |
| | 94 |
| | 8 |
| | — |
| | 118 |
|
| Contributions to investments | | (237 | ) | | — |
| | (435 | ) | | (12 | ) | | — |
| | (684 | ) |
| Distributions from equity investments in excess of cumulative earnings | | 2,297 |
| | — |
| | 326 |
| | — |
| | (2,249 | ) | | 374 |
|
| Funding (to) from affiliates | | (4,419 | ) | | 779 |
| | (7,040 | ) | | (1,028 | ) | | 11,708 |
| | — |
|
| Other, net | | (23 | ) | | 36 |
| | 4 |
| | 5 |
| | — |
| | 22 |
|
| Net cash (used in) provided by investing activities | | (2,389 | ) | | 815 |
| | (9,445 | ) |
| (1,802 | ) |
| 9,459 |
| | (3,362 | ) |
| | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | |
| Issuances of debt | | 8,609 |
| | — |
| | — |
| | 259 |
| | — |
| | 8,868 |
|
| Payments of debt | | (9,288 | ) | | (600 | ) | | (897 | ) | | (279 | ) | | — |
| | (11,064 | ) |
| Debt issue costs | | (12 | ) | | — |
| | — |
| | (58 | ) | | — |
| | (70 | ) |
| Cash dividends - common shares | | (1,120 | ) | | — |
| | — |
| | — |
| | — |
| | (1,120 | ) |
| Cash dividends - preferred shares | | (156 | ) | | — |
| | — |
| | — |
| | — |
| | (156 | ) |
| Repurchases of shares | | (250 | ) | | — |
| | — |
| | — |
| | — |
| | (250 | ) |
| Funding from (to) affiliates | | 7,327 |
| | 776 |
| | 3,797 |
| | (192 | ) | | (11,708 | ) | | — |
|
| Contributions from investment partner | | — |
| | — |
| | 485 |
| | — |
| | — |
| | 485 |
|
| Contributions from parents, including net proceeds from KML IPO and preferred share issuance | | — |
| | — |
| | — |
| | 1,673 |
| | (1,673 | ) | | — |
|
| Contributions from noncontrolling interests - net proceeds from KML IPO | | 4 |
| | — |
| — |
| — |
| | — |
| | 1,241 |
| | 1,245 |
|
| Contributions from noncontrolling interests - net proceeds from KML preferred share issuances | | — |
| | — |
| | — |
| | — |
| | 420 |
| | 420 |
|
| Contributions from noncontrolling interests - other | | — |
| | — |
| | — |
| | — |
| | 12 |
| | 12 |
|
| Distributions to parents | | — |
| | (4,902 | ) | | (5,472 | ) | | (687 | ) | | 11,061 |
| | — |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | (42 | ) | | (42 | ) |
| Other, net | | (9 | ) | | — |
| | — |
| | — |
| | — |
| | (9 | ) |
| Net cash provided by (used in) financing activities | | 5,105 |
| | (4,726 | ) | | (2,087 | ) |
| 716 |
|
| (689 | ) | | (1,681 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rate changes on cash and cash equivalents | | — |
| | — |
| | — |
| | 22 |
| | — |
| | 22 |
|
| | | | | | | | | | | | | |
| Net (decrease) increase in cash and cash equivalents | | (468 | ) | | — |
| | (9 | ) |
| 57 |
|
| — |
| | (420 | ) |
| Cash and cash equivalents, beginning of period | | 471 |
| | — |
| | 9 |
| | 205 |
| | (1 | ) | | 684 |
|
| Cash and cash equivalents, end of period | | $ | 3 |
| | $ | — |
| | $ | — |
|
| $ | 262 |
|
| $ | (1 | ) | | $ | 264 |
|
| Capitalized Costs Related to Oil and Gas Producing Activities |
| | | | | | | | | | | |
| | As of December 31, |
| | 2015 | | 2014 | | 2013 |
| Consolidated Companies(a) | | | | | |
| Wells and equipment, facilities and other | $ | 5,332 |
| | $ | 4,937 |
| | $ | 4,432 |
|
| Leasehold | 658 |
| | 658 |
| | 660 |
|
| Total proved oil and gas properties | 5,990 |
| | 5,595 |
| | 5,092 |
|
| Unproved property(b) | 142 |
| | 103 |
| | 38 |
|
| Accumulated depreciation and depletion(c) | (5,052 | ) | | (4,226 | ) | | (3,520 | ) |
| Net capitalized costs | $ | 1,080 |
| | $ | 1,472 |
| | $ | 1,610 |
|
_______
| |
(a) | Amounts relate to KMCO2 and its consolidated subsidiaries. Includes capitalized asset retirement costs and associated accumulated depreciation.
|
| |
(b) | As of December 31, 2015, capitalized costs related to the unproved property for the Tall Cotton Residual Oil Zone (ROZ) unproved exploration property was $135 million and other miscellaneous unproved property was $7 million. |
| |
(c) | 2015 amount includes impairment charges of $378 million for Goldsmith Landreth San Andres Unit, $10 million for Katz Strawn Unit and $11 million on other miscellaneous property. 2014 amount includes an impairment charge of $234 million on the Katz Strawn Unit and $1 million on other miscellaneous property. |
For each of the years ended December 31, 2015, 2014 and 2013, our costs incurred for property acquisition, development and exploration were as follows (in millions):Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2016 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Net cash (used in) provided by operating activities | | $ | (3,981 | ) | | $ | 4,980 |
| | $ | 11,641 |
| | $ | 885 |
| | $ | (8,730 | ) | | $ | 4,795 |
|
| | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | |
| Acquisitions of assets and investments | | (2 | ) | | — |
| | (331 | ) | | — |
| | — |
| | (333 | ) |
| Capital expenditures | | (27 | ) | | — |
| | (2,258 | ) | | (597 | ) | | — |
| | (2,882 | ) |
| Proceeds from sale of equity interests in subsidiaries net | | — |
| | — |
| | 1,401 |
| | — |
| | — |
| | 1,401 |
|
| Sales of property, plant and equipment, investments and other net assets, net of removal costs | | 6 |
| | — |
| | 326 |
| | (2 | ) | | — |
| | 330 |
|
| Contributions to investments | | (343 | ) | | — |
| | (54 | ) | | (11 | ) | | — |
| | (408 | ) |
| Distributions from equity investments in excess of cumulative earnings | | 2,417 |
| | 298 |
| | 190 |
| | — |
| | (2,674 | ) | | 231 |
|
| Funding to affiliates | | (2,820 | ) | | (535 | ) | | (5,062 | ) | | (727 | ) | | 9,144 |
| | — |
|
| Other, net | | — |
| | (73 | ) | | 39 |
| | (10 | ) | | — |
| | (44 | ) |
| Net cash used in investing activities | | (769 | ) | | (310 | ) | | (5,749 | ) | | (1,347 | ) | | 6,470 |
| | (1,705 | ) |
| | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | |
| Issuances of debt | | 8,255 |
| | — |
| | 374 |
| | — |
| | — |
| | 8,629 |
|
| Payments of debt | | (7,322 | ) | | (500 | ) | | (2,227 | ) | | (11 | ) | | — |
| | (10,060 | ) |
| Debt issue costs | | (16 | ) | | — |
| | (2 | ) | | (1 | ) | | — |
| | (19 | ) |
| Cash dividends - common shares | | (1,118 | ) | | — |
| | — |
| | — |
| | — |
| | (1,118 | ) |
| Cash dividends - preferred shares | | (154 | ) | | — |
| | — |
| | — |
| | — |
| | (154 | ) |
| Funding from affiliates | | 5,461 |
| | 1,116 |
| | 1,959 |
| | 608 |
| | (9,144 | ) | | — |
|
| Contributions from parents | | — |
| | — |
| | 117 |
| | — |
| | (117 | ) | | — |
|
| Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 117 |
| | 117 |
|
| Distributions to parents | | — |
| | (5,286 | ) | | (6,116 | ) | | (73 | ) | | 11,475 |
| | — |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | (24 | ) | | (24 | ) |
| Other, net | | (8 | ) | | — |
| | — |
| | — |
| | — |
| | (8 | ) |
| Net cash provided by (used in) financing activities | | 5,098 |
| | (4,670 | ) | | (5,895 | ) | | 523 |
| | 2,307 |
| | (2,637 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rate changes on cash and cash equivalents | | — |
| | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | 348 |
| | — |
| | (3 | ) | | 63 |
| | 47 |
| | 455 |
|
| Cash and cash equivalents, beginning of period | | 123 |
| | — |
| | 12 |
| | 142 |
| | (48 | ) | | 229 |
|
| Cash and cash equivalents, end of period | | $ | 471 |
| | $ | — |
| | $ | 9 |
| | $ | 205 |
| | $ | (1 | ) | | $ | 684 |
|
| Costs Incurred in Exploration, Property Acquisitions and Development |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Consolidated Companies | | | | | |
| Acquisitions(a) | $ | — |
| | $ | — |
| | $ | 285 |
|
| Development(b) | 399 |
| | 481 |
| | 471 |
|
| Exploration(c) | 35 |
| | 95 |
| | 11 |
|
_______
| |
(a) | Acquisition of Goldsmith Landreth San Andres Unit effective June 1, 2013. |
| |
(b) | Amounts relate to KMCO2 and its consolidated subsidiaries.
|
| |
(c) | 2015 amounts relate to exploration wells drilled in the Tall Cotton Residual Oil Zone (ROZ) for $35 million. 2014 amounts relate to exploration wells drilled in the Residual Oil Zone (ROZ) for $87 million and the Yates Wolfcamp for $8 million. |
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2015 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Net cash (used in) provided by operating activities | | $ | (4,208 | ) | | $ | 6,824 |
| | $ | 11,039 |
| | $ | 347 |
| | $ | (8,689 | ) | | $ | 5,313 |
|
| | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | |
| Acquisitions of assets and investments | | (1,843 | ) | | — |
| | (236 | ) | | — |
| | — |
| | (2,079 | ) |
| Capital expenditures | | (10 | ) | | — |
| | (3,555 | ) | | (331 | ) | | — |
| | (3,896 | ) |
| Sales of property, plant and equipment, investments, and other net assets, net of removal costs | | — |
| | — |
| | 39 |
| | — |
| | — |
| | 39 |
|
| Contributions to investments | | (21 | ) | | — |
| | (70 | ) | | (10 | ) | | 5 |
| | (96 | ) |
| Distributions from equity investments in excess of cumulative earnings | | 2,653 |
| | — |
| | 143 |
| | — |
| | (2,568 | ) | | 228 |
|
| Investment in KMP | | (159 | ) | | — |
| | — |
| | — |
| | 159 |
| | — |
|
| Funding to affiliates | | (3,204 | ) | | (8,388 | ) | | (7,980 | ) | | (779 | ) | | 20,351 |
| | — |
|
| Other, net | | — |
| | 24 |
| | 16 |
| | 58 |
| | — |
| | 98 |
|
| Net cash used in investing activities | | (2,584 | ) | | (8,364 | ) | | (11,643 | ) | | (1,062 | ) | | 17,947 |
| | (5,706 | ) |
| | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | |
| Issuances of debt | | 14,316 |
| | — |
| | — |
| | — |
| | — |
| | 14,316 |
|
| Payments of debt | | (14,048 | ) | | (675 | ) | | (383 | ) | | (10 | ) | | — |
| | (15,116 | ) |
| Debt issue costs | | (24 | ) | | — |
| | — |
| | — |
| | — |
| | (24 | ) |
| Issuances of common shares | | 3,870 |
| | — |
| | — |
| | — |
| | — |
| | 3,870 |
|
| Issuance of mandatory convertible preferred stock | | 1,541 |
| | — |
| | — |
| | — |
| | — |
| | 1,541 |
|
| Cash dividends - common shares | | (4,224 | ) | | — |
| | — |
| | — |
| | — |
| | (4,224 | ) |
| Repurchases of warrants | | (12 | ) | | — |
| | — |
| | — |
| | — |
| | (12 | ) |
| Funding from affiliates | | 5,502 |
| | 6,989 |
| | 7,112 |
| | 748 |
| | (20,351 | ) | | — |
|
| Contributions from parents | | — |
| | 156 |
| | 3 |
| | 16 |
| | (175 | ) | | — |
|
| Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 11 |
| | 11 |
|
| Distributions to parents | | — |
| | (4,944 | ) | | (6,133 | ) | | (166 | ) | | 11,243 |
| | — |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | (34 | ) | | (34 | ) |
| Other, net | | (10 | ) | | (1 | ) | | — |
| | — |
| | — |
| | (11 | ) |
| Net cash provided by financing activities | | 6,911 |
| | 1,525 |
| | 599 |
| | 588 |
| | (9,306 | ) | | 317 |
|
| | | | | | | | | | | | | |
| Effect of exchange rate changes on cash and cash equivalents | | — |
| | — |
| | — |
| | (10 | ) | | — |
| | (10 | ) |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | 119 |
| | (15 | ) | | (5 | ) | | (137 | ) |
| (48 | ) | | (86 | ) |
| Cash and cash equivalents, beginning of period | | 4 |
| | 15 |
| | 17 |
| | 279 |
| | — |
| | 315 |
|
| Cash and cash equivalents, end of period | | $ | 123 |
| | $ | — |
| | $ | 12 |
| | $ | 142 |
|
| $ | (48 | ) | | $ | 229 |
|
Our results of operations from oil and gas producing activities for each of the years ended December 31, 2015, 2014 and 2013 are shown in the following table (in millions):
| Results of Operations for Oil and Gas Producing Activities |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Consolidated Companies(a) | | | | | |
| Revenues(b) | $ | 1,155 |
| | $ | 1,412 |
| | $ | 1,376 |
|
| Expenses: | | | | | |
| Production costs | 337 |
| | 403 |
| | 344 |
|
| Other operating expenses(c) | 60 |
| | 99 |
| | 95 |
|
| Exploration expense(d) | — |
| | 8 |
| | — |
|
| Impairment(e) | 399 |
| | 235 |
| | — |
|
| DD&A expenses | 388 |
| | 430 |
| | 415 |
|
| Total expenses | 1,184 |
| | 1,175 |
| | 854 |
|
| Results of operations for oil and gas producing activities | $ | (29 | ) | | $ | 237 |
| | $ | 522 |
|
_______
| |
(a) | Amounts relate to KMCO2 and its consolidated subsidiaries.
|
| |
(b) | Revenues include gains attributable to our hedging contracts of $389 million for the year ended December 31, 2015, $28 million for the year ended December 31, 2014 and losses of $31 million for the year ended December 31, 2013. |
| |
(c) | Consists primarily of CO2 expense.
|
| |
(d) | Exploration charge for Yates Wolfcamp. |
| |
(e) | 2015 amount includes impairment charges of $378 million on the Goldsmith Landreth San Andres Unit, $10 million for Katz Strawn Unit and $11 million on other miscellaneous property. 2014 amount includes impairment charge of $234 million on the Katz Strawn Unit and $1 million on other miscellaneous property. |
Supplemental information is also provided for the following three items (i) estimated quantities of proved oil and gas reserves; (ii) the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and (iii) a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.Supplemental Selected Quarterly Financial Data (Unaudited)
|
| | | | | | | | | | | | | | | |
| | Quarters Ended |
| | March 31 | | June 30 | | September 30 | | December 31 |
| | (In millions, except per share amounts) |
| 2017 | | | | | | | |
| Revenues | $ | 3,424 |
| | $ | 3,368 |
| | $ | 3,281 |
| | $ | 3,632 |
|
| Operating Income | 980 |
| | 922 |
| | 830 |
| | 812 |
|
| Net Income (Loss) | 445 |
| | 383 |
| | 387 |
| | (992 | ) |
| Net Income (Loss) Attributable to Kinder Morgan, Inc. | 440 |
| | 376 |
| | 373 |
| | (1,006 | ) |
| Net Income (Loss) Available to Common Stockholders | 401 |
| | 337 |
| | 334 |
| | (1,045 | ) |
| Basic and Diluted Earnings (Loss) Per Common Share | 0.18 |
| | 0.15 |
| | 0.15 |
| | (0.47 | ) |
| | | | | | | | |
| 2016 | | | | | | | |
| Revenues | $ | 3,195 |
| | $ | 3,144 |
| | $ | 3,330 |
| | $ | 3,389 |
|
| Operating Income | 816 |
| | 940 |
| | 882 |
| | 934 |
|
| Net Income (Loss) | 314 |
| | 375 |
| | (183 | ) | | 215 |
|
| Net Income (Loss) Attributable to Kinder Morgan, Inc. | 315 |
| | 372 |
| | (188 | ) | | 209 |
|
| Net Income (Loss) Available to Common Stockholders | 276 |
| | 333 |
| | (227 | ) | | 170 |
|
| Basic and Diluted Earnings (Loss) Per Common Share | 0.12 |
| | 0.15 |
| | (0.10 | ) | | 0.08 |
|
The technical persons responsible for preparing the reserves estimates presented in this Supplemental Information meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. They are independent petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our oil and gas properties; and we do not employ them on a contingent basis.Item 16. Form 10-K Summary.
The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Derek Newton and Mr. Mike Norton. Mr. Newton, a Licensed Professional
Engineer in the State of Texas (No. 97689), has been practicing consulting petroleum engineering at NSAI since 1997 and has over 14 years of prior industry experience. He graduated from University College, Cardiff, Wales, in 1983 with a Bachelor of Science Degree in Mechanical Engineering and from Strathclyde University, Scotland, in 1986 with a Master of Science Degree in Petroleum Engineering. Mr. Norton, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.Not Applicable.
Our employee who is primarily responsible for overseeing NSAI’s preparation of the reserves estimates is a registered Professional Engineer in the states of Texas and Kansas with a Doctorate of Engineering from the University of Kansas. He is
a member of the Society of Petroleum Engineers and has over 30 years of professional engineering experience. We believe the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information become available and contractual and economic conditions change.
Furthermore, our management is responsible for establishing and maintaining adequate internal control over financial reporting, which includes the estimation of our oil and gas reserves. We maintain internal controls and guidance to ensure the reliability of our crude oil, NGL and natural gas reserves estimations, as follows:
no employee’s compensation is tied to the amount of recorded reserves;
we follow comprehensive SEC compliant internal policies to determine and report proved reserves, and our reserve estimates are made by experienced oil and gas reservoir engineers or under their direct supervision;
| |
• | we review our reported proved reserves at each year-end, and at each year-end, the CO2 business segment managers and the Vice President (President, CO2) review all significant reserves changes and all new proved developed and undeveloped reserves additions; and
|
| |
• | the CO2 business segment reports independently of our five remaining reportable business segments.
|
For more information on our controls and procedures, see Item 9A “Controls and Procedures—Management’s Report on Internal Control Over Financial Reporting” included in our Annual Report on Form 10-K for the year ended December 31, 2015.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and NGL which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, current prices and costs calculated as of the date the estimate is made. Pricing is applied based upon the twelve month unweighted arithmetic average of the first day of the month price for the year. Future development and production costs are determined based upon actual cost at year-end. Proved developed reserves are the quantities of crude oil, NGL and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.
As of December 31, 2013, we had 67.4 MMBbl of crude oil and 6.7 MMBbl of NGL classified as proved developed reserves. Also, as of year end 2013, we had 39.6 MMBbl of crude oil and 8.0 MMBbl of NGL classified as proved undeveloped reserves. Total proved reserves as of December 31, 2013, were 107.0 MMBbl of crude oil and 14.8 MMBbl of NGL.
During 2014, production from the fields totaled 14.8 MMBbl of crude oil and 1.5 MMBbl of NGL. For 2014, we incurred $502 million in capital costs, and this capital investment resulted in the development of 5.7 MMBbl of crude oil and their transfer from the proved undeveloped category to the proved developed category. The reclassifications from proved undeveloped to proved developed reserves reflect the transfer of 14.5% of crude oil from the proved undeveloped reserves reported as of December 31, 2013 to the proved developed classification of reserves reported as of December 31, 2014. Revisions to previous transfers of NGL’s resulted a downward revision of 0.1 MMBbl for NGL‘s in the proved developed category that have been reclassified to the proved undeveloped category as of December 31, 2014. This reclassification reflects the transfer of 1.8% of proved developed NGL’s reported as of December 31, 2013 to the proved undeveloped classification of reserves reported as of December 31, 2014.
Also during 2014, previous estimates of proved developed reserves were revised upward by 2.0 MMBbl of crude oil and downward 0.5 MMBbl of NGL, and proved undeveloped reserves were revised upward by 3.4 MMBbl of crude oil and downward 1.9 MMBbl of NGL. These revisions are mainly attributed to the addition of projects and the use of higher projected oil recoveries resulting from updated performance at SACROC used to calculate reserves. The proved developed reserves for SACROC represent 32.5% of proved developed reserves. The Katz Strawn Unit also received an addition of proved developed nonproducing reserves volumes. The proved developed reserves for Katz Strawn Unit represent 12.3% of proved developed reserves. Contrarily, there was also a decrease of proved developed producing reserves and proved undeveloped reserves in Goldsmith due to higher operating costs and lower well performance. The proved developed reserves for Goldsmith represent 13.4% of proved developed reserves.
These revisions to our previous estimates, as well as the transfer of proved undeveloped reserves to the proved developed category as discussed above, resulted in the percentage of proved undeveloped reserves increasing from 39.0% at year end 2013 to 40.0% at year end 2014. After giving effect to production and revisions to previous estimates during 2014, total proved reserves of crude oil decreased by 9.5 MMBbl and total proved reserves of NGL decreased by 4.0 MMBbl.
As of December 31, 2014, we had 60.3 MMBbl of crude oil and 4.6 MMBbl of NGL classified as proved developed reserves. Also, as of year end 2014, we had 37.3 MMBbl of crude oil and 6.2 MMBbl of NGL classified as proved undeveloped reserves. Total proved reserves as of December 31, 2014, were 97.6 MMBbl of crude oil and 10.8 MMBbl of NGL.
During 2015, production from the fields totaled 15.2 MMBbl of crude oil and 1.56 MMBbl of NGL. For 2015, we incurred $396 million in capital costs, and this capital investment resulted in the development of 17.3 MMBbl of crude oil and 1.1 MMBbl of NGL and their transfer from the proved undeveloped category to the proved developed category. The reclassifications from proved undeveloped to proved developed reserves reflect the transfer of 46.4% of crude oil and 17.1% of NGL’s from the proved undeveloped reserves reported as of December 31, 2014 to the proved developed classification of reserves reported as of December 31, 2015.
Also during 2015, previous estimates of proved developed reserves were revised downward by 15.8 MMBbl of crude oil and downward 1.3 MMBbl of NGL, and proved undeveloped reserves were revised downward by 18.3 MMBbl of crude oil and downward 5.2 MMBbl of NGL. These revisions are mainly attributed to the substantial deterioration in the price of crude oil. As the result of the decrease in the crude oil price and high operating costs, both the Katz Strawn Unit and the Goldsmith Unit do not have economic proved reserves as of December 31, 2015. The proved developed reserves for the Yates field unit represent 55.2% of proved developed reserves. The proved developed reserves for SACROC represent 44.0% of proved developed reserves.
As of December 31, 2015, we had 46.6 MMBbl of crude oil and 2.8 MMBbl of NGL classified as proved developed reserves. Also, as of year end 2015, we had 1.7 MMBbl of crude oil and no NGL’s classified as proved undeveloped reserves. Total proved reserves as of December 31, 2015, were 48.4 MMBbl of crude oil and 2.8 MMBbl of NGL. We currently expect that the proved undeveloped reserves we report as of December 31, 2015 will be developed within the next five years.
During 2015, we filed estimates of our oil and gas reserves for the year 2014 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil and gas reserves reported on Form EIA-23 and those reported in this Supplemental Information exceeds 5%.
The following Reserve Quantity Information table discloses estimates, as of December 31, 2015, of proved crude oil, NGL and natural gas reserves, prepared by Netherland, Sewell & Associates, Inc. (independent oil and gas consultants), of KMCO2 and its consolidated subsidiaries’ interests in oil and gas properties, all of which are located in the state of Texas. This data has been prepared using current prices and costs, as discussed above, and the estimates of reserves and future revenues in this Supplemental Information conform to the guidelines of the SEC.
| Reserve Quantity Information |
| | | | | | | | |
| | Consolidated Companies(a) |
| | Crude Oil (MBbl) | | NGL
(MBbl) | | Natural Gas (MMcf)(b) |
| Proved developed and undeveloped reserves: | | | | | |
| As of December 31, 2012 | 81,950 |
| | 5,976 |
| | 7,539 |
|
| Revisions of previous estimates(c) | (2,573 | ) | | (43 | ) | | (5,063 | ) |
| Purchases of reserves in place(d) | 41,389 |
| | 10,347 |
| | — |
|
| Production | (13,735 | ) | | (1,499 | ) | | (406 | ) |
| As of December 31, 2013 | 107,031 |
| | 14,781 |
| | 2,070 |
|
| Revisions of previous estimates(e) | 5,378 |
| | (2,419 | ) | | 372 |
|
| Production | (14,852 | ) | | (1,542 | ) | | (373 | ) |
| As of December 31, 2014 | 97,557 |
| | 10,820 |
| | 2,069 |
|
| Revisions of previous estimates(f) | (34,041 | ) | | (6,434 | ) | | (1,234 | ) |
| Production | (15,152 | ) | | (1,553 | ) | | (309 | ) |
| As of December 31, 2015 | 48,364 |
| | 2,833 |
| | 526 |
|
| | | | | | |
| Proved developed reserves: | | | | | |
| As of December 31, 2013 | 67,436 |
| | 6,733 |
| | 2,070 |
|
| As of December 31, 2014 | 60,252 |
| | 4,584 |
| | 2,069 |
|
| As of December 31, 2015 | 46,627 |
| | 2,833 |
| | 526 |
|
| | | | | | |
| Proved undeveloped reserves: | | | | | |
| As of December 31, 2013 | 39,595 |
| | 8,048 |
| | — |
|
| As of December 31, 2014 | 37,305 |
| | 6,236 |
| | — |
|
| As of December 31, 2015 | 1,737 |
| | — |
| | — |
|
_______
| |
(a) | Amounts relate to KMCO2 and its consolidated subsidiaries.
|
| |
(b) | Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit. |
| |
(c) | Predominantly due to higher operating costs at the Katz Strawn Unit. |
| |
(d) | Represents volumes added with acquisition of the Goldsmith Landreth San Andres Unit in June 2013. |
| |
(e) | Predominately due to the addition of projects and redefined original oil in place values at SACROC, the addition of proved developed nonproducing reserves volumes in the Katz Strawn Unit offset by decreased expected oil recoveries in the Goldsmith Landreth San Andres Unit based on higher operating costs and lower well performance. |
| |
(f) | Predominately due to lower crude oil prices which resulted in the Goldsmith Landreth San Andres Unit and the Katz Strawn Unit proved reserves being uneconomical under SEC pricing guidelines. |
The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year-to-year are prepared in accordance with the “Extractive Activities—Oil and Gas” Topic of the Codification. The assumptions that underly the computation of the standardized measure of discounted cash flows, presented in the table below, may be summarized as follows:
the standardized measure includes our estimate of proved crude oil, NGL and natural gas reserves and projected future production volumes based upon year-end economic conditions;
pricing is applied based upon the 12 month unweighted arithmetic average of the first day of the month price for the year;
future development and production costs are determined based upon actual cost at year-end;
the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and
a discount factor of 10% per year is applied annually to the future net cash flows.
The standardized measure of discounted future net cash flows from proved reserves were as follows (in millions):
Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Gas Reserves |
| | | | | | | | | | | |
| | As of December 31, |
| | 2015 | | 2014 | | 2013 |
| Consolidated Companies(a) | | | | | |
| Future cash inflows from production | $ | 2,500 |
| | $ | 9,406 |
| | $ | 10,945 |
|
| Future production costs | (1,276 | ) | | (4,294 | ) | | (4,214 | ) |
| Future development costs(b) | (466 | ) | | (2,113 | ) | | (1,948 | ) |
| Undiscounted future net cash flows | 758 |
| | 2,999 |
| | 4,783 |
|
| 10% annual discount | (178 | ) | | (1,089 | ) | | (2,096 | ) |
| Standardized measure of discounted future net cash flows | $ | 580 |
| | $ | 1,910 |
| | $ | 2,687 |
|
_______
| |
(a) | Amounts relate to KMCO2 and its consolidated subsidiaries.
|
| |
(b) | Includes abandonment costs. |
The following table represents our estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in millions):
Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Gas Reserves |
| | | | | | | | | | | |
| | As of December 31, |
| | 2015 | | 2014 | | 2013 |
| Consolidated Companies(a) | | | | | |
| Present value as of January 1 | $ | 1,910 |
| | $ | 2,687 |
| | $ | 2,705 |
|
| Changes during the year: | | | | | |
| Revenues less production and other costs(b) | (375 | ) | | (880 | ) | | (965 | ) |
| Net changes in prices, production and other costs | (1,871 | ) | | (504 | ) | | 258 |
|
| Development costs incurred | 396 |
| | 502 |
| | 452 |
|
| Net changes in future development costs | 844 |
| | (479 | ) | | (629 | ) |
| Revisions of previous quantity estimates(c) | (502 | ) | | 329 |
| | (114 | ) |
| Purchase of reserves in place(d) | — |
| | — |
| | 683 |
|
| Accretion of discount | 178 |
| | 255 |
| | 297 |
|
| Net change for the year | (1,330 | ) | | (777 | ) | | (18 | ) |
| Present value as of December 31 | $ | 580 |
| | $ | 1,910 |
| | $ | 2,687 |
|
_______
| |
(a) | Amounts relate to KMCO2 and its consolidated subsidiaries.
|
| |
(b) | Excludes gains attributable to our hedging contracts of $389 million for the year ended December 31, 2015, $28 million for the year ended December 31, 2014 and losses of $31 million for the year ended December 31, 2013. |
| |
(c) | 2015 revisions were primarily due to lower crude oil prices which resulted in the Goldsmith Landreth San Andres Unit and the Katz Strawn Unit proved reserves being uneconomical under SEC pricing guidelines. 2014 revisions were primarily due to, increases due to the addition of projects and redefined original oil in place values at SACROC, additional proved developed nonproducing reserves volumes in the Katz Strawn Unit offset by decreased oil recoveries and higher operating costs for the Goldsmith Landreth San Andres Unit. 2013 revisions were primarily due to increased operating costs at the Katz Strawn Unit. |
| |
(d) | Acquisition of the Goldsmith Landreth San Andres Unit in June 2013. |
SIGNATURES
Pursuant to the requirements 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.
|
| | |
| | | KINDER MORGAN, INC. Registrant |
| | | |
| | | By: /s/ Kimberly A. Dang |
| | | Kimberly A. Dang Vice President and Chief Financial Officer (principal financial and accounting officer) |
| Date: | February 16, 20169, 2018 | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
|
| | | | |
| Signature | | Title | | Date |
| | | | | |
| /s/ KIMBERLY A. DANG | | Vice President and Chief Financial Officer (principal financial officer and principal accounting officer); Director | | February 16, 20169, 2018 |
| Kimberly A. Dang | | |
| | | | | |
| /s/ STEVEN J. KEAN | | President and Chief Executive Officer (principal executive officer); Director | | February 16, 20169, 2018 |
| Steven J. Kean | | |
| | | | | |
| /s/ RICHARD D. KINDER | | Executive Chairman | | February 16, 20169, 2018 |
| Richard D. Kinder | | |
| | | | | |
| /s/ TED A. GARDNER | | Director | | February 16, 20169, 2018 |
| Ted A. Gardner | | |
| | | | | |
| /s/ ANTHONY W. HALL, JR. | | Director | | February 16, 20169, 2018 |
| Anthony W. Hall, Jr. | | |
| | | | | |
| /s/ GARY L. HULTQUIST | | Director | | February 16, 20169, 2018 |
| Gary L. Hultquist | | |
| | | | | |
| /s/ RONALD L. KUEHN, JR. | | Director | | February 16, 20169, 2018 |
| Ronald L. Kuehn, Jr. | | |
| | | | | |
| /s/ DEBORAH A. MACDONALD | | Director | | February 16, 20169, 2018 |
| Deborah A. Macdonald | | |
| | | | | |
| /s/ MICHAEL C. MORGAN | | Director | | February 16, 20169, 2018 |
| Michael C. Morgan | | |
| | | | | |
| /s/ ARTHUR C. REICHSTETTER | | Director | | February 16, 20169, 2018 |
| Arthur C. Reichstetter | | |
| | | | | |
| /s/ FAYEZ SAROFIM | | Director | | February 16, 20169, 2018 |
| Fayez Sarofim | | |
| | | | | |
| /s/ C. PARK SHAPER | | Director | | February 16, 20169, 2018 |
| C. Park Shaper | | |
| | | | | |
| /s/ WILLIAM A. SMITH | | Director | | February 16, 20169, 2018 |
| William A. Smith | | |
| | | | | |
| /s/ JOEL V. STAFF | | Director | | February 16, 20169, 2018 |
| Joel V. Staff | | |
| | | | | |
| /s/ ROBERT F. VAGT | | Director | | February 16, 20169, 2018 |
| Robert F. Vagt | | |
| | | | | |
| /s/ PERRY M. WAUGHTAL | | Director | | February 16, 20169, 2018 |
| Perry M. Waughtal | | |
| | | | | |
