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10-K 1 kmi-2015x10k.htm 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
| [X] | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2015
or
| [ ] | 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)
| 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
Securities registered pursuant to Section 12(b) of the Act:
| 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 |
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
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, 2015 was approximately $69,734,282,635. As of February 11, 2016, the registrant had 2,231,555,976 Class P shares outstanding.
| KINDER MORGAN, INC. AND SUBSIDIARIES GLOSSARY Company Abbreviations | |||||
|---|---|---|---|---|---|
| Calnev | = | Calnev Pipe Line LLC | 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. |
| Hiland | = | Hiland Partners, LP | 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. | |||||
| Common Industry and Other Terms | |||||
| /d | = | per day | LIBOR | = | London Interbank Offered Rate |
| AFUDC | = | allowance for funds used during construction | LLC | = | limited liability company |
| BBtu | = | billion British Thermal Units | LNG | = | liquefied natural gas |
| Bcf | = | billion cubic feet | MBbl | = | thousand barrels |
| CERCLA | = | Comprehensive Environmental Response, | MDth | = | thousand dekatherms |
| Compensation and Liability Act | MLP | = | master limited partnership | ||
| CO2 | = | carbon dioxide or our CO2 business segment | MMBbl | = | million barrels |
| CPUC | = | California Public Utilities Commission | MMcf | = | million cubic feet |
| DCF | = | distributable cash flow | NEB | = | National Energy Board |
| DD&A | = | depreciation, depletion and amortization | NGL | = | natural gas liquids |
| DGCL | = | General Corporation Law of the state of Delaware | NYMEX | = | New York Mercantile Exchange |
| Dth | = | dekatherms | NYSE | = | New York Stock Exchange |
| EBDA | = | earnings before depreciation, depletion and | OTC | = | over-the-counter |
| amortization expenses, including amortization of | PHMSA | = | United States Department of Transportation | ||
| excess cost of equity investments | Pipeline and Hazardous Materials Safety | ||||
| EPA | = | United States Environmental Protection Agency | Administration | ||
| FASB | = | Financial Accounting Standards Board | SEC | = | United States Securities and Exchange |
| FERC | = | Federal Energy Regulatory Commission | Commission | ||
| FTC | = | Federal Trade Commission | TBtu | = | trillion British Thermal Units |
| 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,” “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 predict. Specific factors that could cause actual results to differ from those in our forward-looking statements include:
| • | the extent of volatility in prices for and resulting changes in 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 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, power shortages, strikes, riots, terrorism (including cyber attacks), war or other causes; |
| • | the uncertainty inherent in estimating future oil, natural gas, and CO2 production or reserves that we may experience; |
| • | regulatory, environmental, political, legal, operational and geological uncertainties that could affect our ability to complete our expansion projects on time and on budget; |
| • | the timing and success of our business development efforts, including our ability to renew long-term customer contracts; |
| • | the ability of our customers and other counterparties to perform under their contracts with us; |
| • | 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; |
| • | 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, 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 subsidiaries 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; |
| • | our ability to achieve cost savings and revenue growth; |
| • | foreign exchange fluctuations; |
| • | 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, 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 the forward-looking statements will occur, or if any of them do, 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 description of these and other factors that may affect our forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in Item 1A “Risk Factors.” The risk 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”, to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
PART I
Items 1 and 2. Business and Properties.
We are the largest energy infrastructure company in North America. We own an interest in or operate approximately 84,000 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. 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, petroleum coke and steel. We are also the leading producer and transporter of CO2, which is utilized for enhanced oil recovery projects in North America. Our common stock trades on the NYSE under the symbol “KMI.”
(a) General Development of Business
Organizational Structure
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 before 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.
Additionally, on January 1, 2015, EPB and its subsidiary, EPPOC merged with and into KMP. As a result of such merger, all 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 are reflected within “Noncontrolling interests” in our accompanying consolidated statements of stockholders’ equity. The earnings recorded by KMP, EPB and KMR that were attributed to the 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.
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. 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.
| Asset or project | Description | Activity | Approx. Capital Scope | |||
| Placed in service or acquisitions | ||||||
| Hiland Partners | Assets consist of crude oil gathering and transportation pipelines and gas gathering and processing systems, primarily serving production from the Bakken Formation in North Dakota and Montana, including the Double H crude oil pipeline. | Acquired February 2015. | $3.0 billion |
| Asset or project | Description | Activity | Approx. Capital Scope | |||
| TGP Broad Run Flexibility and Broad Run Expansion | Modification to existing pipelines under two separate projects to create 790,000 Dth/d of north-to-south gas transportation capacity from a receipt point in West Virginia to delivery points in Mississippi and Louisiana. Subscribed under long-term firm transportation contracts. | TGP Broad Run Flexibility facilities were placed 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. | $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. | $510 million | |||
| TGP South System Flexibility | Expansion project that provides more than 900 miles of north-to-south transportation capacity of 500,000 Dth/d on our TGP system from Tennessee to South Texas and expands our transportation service to Mexico. Subscribed under long-term firm transportation contracts. | Initial volume placed into service January 2015. The next capacity increment was placed in service December 2015, with the remainder expected in December 2016. | $216 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 Terminal | Expansion increases capacity to over 210,000 bpd at the joint venture crude rail terminal in Edmonton. The facility, supported by 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 customer contracts. | Placed in service March 2015 (phase 1) and July 2015 (phase 2). | $445 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 | |||
| ELC and SLNG expansion | 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/d of natural gas. Supported by a 20-year contract with Shell. | First of 10 liquefaction units expected in service first quarter 2018 with the remainder by the end of 2018. | $2.0 billion | |||
| EPNG upstream Sierrita Gas Pipeline LLC | Expansion projects 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 one placed in service October 2014 ($2 million), phase two expected fully in service July 2020 ($389 million). | $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. | $178 million |
| Asset or project | Description | Activity | Approx. Capital Scope | |||
| Texas Intrastate Crossover Expansion | Expansion project creating capacity from the Katy Hub, the company’s Houston Central processing plant, and other third party receipt points to serve the Texas Intrastate’s transportation commitments of 250,000 Dth/day to the Cheniere Corpus Christi LNG export facility and 527,000 Dth/day to the CFE at delivery points in South Texas. | Expected in-service September 2016 for the CFE commitment and January 2019 for the Cheniere commitment. | $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 | $161 million | |||
| TGP Susquehanna West | Expansion project that provides 145,000 Dth/d incremental natural gas transportation capacity, serving the northeast Marcellus to points of liquidity. Subscribed under long-term firm transportation contracts. | Expected 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. Subscribed under long-term firm transportation contracts. | Expected in-service fourth quarter 2018 | $156 million | |||
| KMLP Cheniere Sabine Pass LNG | Reconfiguration to flow northeast to southeast to deliver 600 MDth/d to the Cheniere Sabine Pass Liquefaction Terminal in Cameron Parish, LA. Subscribed under long-term firm transportation contracts. | Expected in-service fourth quarter 2019 | $146 million | |||
| TGP Orion (formerly Marcellus to Milford) | An expansion project to provide additional firm capacity from the Marcellus supply basin 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. Subscribed under long-term firm transportation contracts. | Expected in service June 2018. | $142 million | |||
| TGP Lone Star | Two Greenfield compressor stations to provide supply to the Corpus Christi LNG liquefaction project, for a capacity of 300,000 Dth/d. Subscribed under long-term firm transportation contracts. | Expected in-service July 2019. | $134 million | |||
| TGP Triad Expansion | Expansion project that provides 180,000 Dth/d of long-term capacity for Invernergy’s Lakawanna Energy Center to serve a planned new area power plant. Subscribed under long-term firm transportation contracts. | Expected in service November 2017. | $87 million | |||
| CO2 | ||||||
| Cortez Pipeline expansion | Project will increase capacity from 1.35 Bcf/d 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 full in service second quarter 2016. | $214 million | |||
| Terminals | ||||||
| KM General Dynamics’ NASSCO Tankers | Purchase of five medium-range Jones Act tankers constructed by General Dynamics’ NASSCO Shipyard in San Diego. All of the tankers will be 50,000-deadweight-ton, LNG conversion-ready product carriers, with a capacity of 330,000 barrels and contracted for an average of 5 years. | First tanker delivery took place in December 2015. Delivery of remaining four tankers expected between early 2016 and mid-2017. | $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. | $220 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 Project | An increase of capacity on our Trans Mountain pipeline system from approximately 300,000 to 890,000 barrels per day, underpinned by long-term take-or-pay contracts. | Currently engaged in final approval process with the NEB and federal government, expected in service third quarter 2019. | $5.4 billion |
Financings
On January 26, 2016, we closed on a three-year, unsecured $1 billion term loan and a $1 billion expansion of our unsecured revolving credit facility, increasing the capacity of that facility from $4 billion to $5 billion. Proceeds from the term loan were used to repay existing borrowings and for general corporate purposes. Pricing and the covenant package of both facilities are consistent with our existing revolving credit facility.
Current Commodity Price Environment
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.
2016 Outlook
We expect to declare 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 billion of cash flow in excess of our dividend. These expectations assume an average 2016 WTI crude oil price of $38 per barrel, an average 2016 Henry Hub natural gas price of $2.50 per MMBtu and interest rates consistent with the current forward curve at the time that our 2016 budget was prepared.
The overwhelming majority of cash we generate is fee-based and therefore is not directly exposed to commodity prices. The primary area where we have direct commodity price sensitivity is in our CO2 segment, where we hedge the majority of the next 12 months of oil production to minimize this sensitivity. For 2016, we estimate that every $1 change in the average WTI crude oil price per barrel would impact our distributable cash flow by approximately $6.5 million and each $0.10 per MMBtu change in the average price of natural gas impacts distributable cash flow 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 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 2016 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 2016 expectations when we believe previously disclosed expectations no longer have a reasonable basis.
(b) Financial Information about Segments
For financial information on our six 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 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 are currently contemplating potential acquisitions. 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 agreements for the acquisition 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 liquids and bulk terminal facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, condensate, and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals and (ii) the ownership and operation of our Jones Act tankers; |
| • | 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; 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. |
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 natural gas sales, transportation, storage, gathering, processing and treating, and the terminaling of LNG. Within this segment, are: (i) approximately 52,000 miles of natural gas pipelines and (ii) our equity interests in entities that have approximately 19,000 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. 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 |
| 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) |
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 and fuel oils. 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.
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 | |||||
| Working | Developed | ||||
| Interest % | Acres | ||||
| SACROC | 97 | 49,156 | |||
| Yates | 50 | 9,576 | |||
| Goldsmith Landreth San Andres(a) | 99 | 6,166 | |||
| Katz Strawn | 99 | 7,194 | |||
| Sharon Ridge | 14 | 2,619 | |||
| Tall Cotton (ROZ) | 100 | 461 | |||
| H.T. Boyd(b) | 21 | n/a | |||
| MidCross | 13 | 320 | |||
| Reinecke(c) | — | 80 |
| (a) | Acquired June 1, 2013 |
| (b) | Net profits interest |
| (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. 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) | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Crude Oil | 2,199 | 1,415 | 1,157 | 910 | 2 | 2 | |||||||||||
| Natural Gas | 5 | 2 | — | — | — | — | |||||||||||
| Total Wells | 2,204 | 1,417 | 1,157 | 910 | 2 | 2 |
| (a) | Includes active wells and wells temporarily shut-in. As of December 31, 2015, 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. 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, 2014 and 2013:
| Year Ended December 31, | ||||||||
| 2015 | 2014 | 2013 | ||||||
| Productive | ||||||||
| Development | 130 | 83 | 51 | |||||
| Exploratory | 31 | 26 | 4 | |||||
| Total Productive | 161 | 109 | 55 | |||||
| Dry Exploratory | — | 1 | — | |||||
| Total Wells | 161 | 110 | 55 |
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 operations were not completed as of the end of the applicable year. A development well is a well drilled in an already discovered oil field.
The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2015:
| 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.
See “Supplemental Information on Oil and Gas Activities (Unaudited)” for additional information with respect to operating statistics and supplemental information on our oil and gas producing activities.
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 |
| (a) | We also operate. |
| (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 petroleum, chemical, ethanol and other liquids 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. 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 have Jones Act qualified product tankers that provide marine transportation of crude oil, condensate and refined products in the U.S. The following summarizes our Terminals segment assets, as of December 31, 2015:
| Number | Capacity (MMBbl) | ||||
| Liquids terminals(a) | 52 | 87.6 | |||
| Bulk terminals | 59 | n/a | |||
| Jones Act qualified tankers | 8 | 2.6 |
| (a) | Includes 10 terminals acquired in February 2016. |
Competition
We are one of the largest independent operators of liquids terminals in the U.S, 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 and pipeline 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 terminal 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, and our transmix processing facilities. The following summarizes our significant Products Pipelines segment assets we own and operate as of December 31, 2015:
| 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. | ||||||||||
| West Coast Products Pipelines(b) | |||||||||||||
| Pacific (SFPP) | 100 | 2,823 | 13 | 15.3 | six western states | ||||||||
| Calnev | 100 | 570 | 2 | 2.1 | Colton, CA to Las Vegas, NV; Mojave region | ||||||||
| West Coast Terminals | 100 | 43 | 7 | 10.1 | 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. | ||||||||
| 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 | ||||||||
| Double H Pipeline | 100 | 511 | Bakken shale in Montana and North Dakota to Guernsey, Wyoming | ||||||||||
| Central Florida pipeline | 100 | 206 | 3 | 3.1 | 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 | ||||||||||
| Southeast Terminals | 100 | 32 | 10.8 | from Mississippi through Virginia, including Tennessee | |||||||||
| Transmix Operations | 100 | 6 | 1.5 | Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; 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 operated Trans Mountain pipeline system and a 25-mile Jet Fuel pipeline system.
Trans Mountain Pipeline System
The Trans Mountain pipeline system 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 pipeline 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.
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
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 sole pipeline carrying crude oil and refined petroleum products from Alberta to the west coast. Furthermore, as demonstrated by our previously announced expansion proposal, discussed above in “—(a) General Development of Business—Recent Developments—Kinder Morgan Canada,” we believe that the Trans Mountain pipeline facilities provide us the opportunity to execute on capacity expansions to the west coast as the market for offshore exports continues to develop.
In December 2013, the British Columbia Ministry of Environment granted approval for a new, airport fuel consortium owned, jet fuel terminal to be located near the Vancouver International Airport. The impact of this facility on our existing Jet Fuel pipeline system is uncertain at this time.
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, 2014 and 2013, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. 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, 2014 and 2013 accounted for 20%, 25% and 28%, 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 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 Energy Policy Act of 1992. The Energy Policy Act 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, 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 Commission 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 the natural gas commodity, transportation and storage); |
| • | 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 Regulating 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 limitations (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 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.
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 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 million as of December 31, 2015. Our reserve estimates range in value from approximately $284 million to approximately $457 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 KM 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.
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, in September 2015, 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, this rule would be 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 Morgan facilities.
On October 23, 2015, the EPA published as a final rule the Clean Power Plan, which sets interim and final CO2 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. 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 11,290 full-time people at December 31, 2015, including approximately 787 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 2016 and 2018. 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) 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 Website 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.