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10-K 1 kmi-2016x10k.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, 2016
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 |
| 1.500% Senior Notes due 2022 | New York Stock Exchange |
| 2.250% Senior Notes due 2027 | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K(§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o
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, 2016 was approximately $36,035,868,866. As of February 9, 2017, the registrant had 2,232,438,943 Class P shares outstanding.
| KINDER MORGAN, INC. AND SUBSIDIARIES GLOSSARY Company Abbreviations | |||||
|---|---|---|---|---|---|
| Calnev | = | Calnev Pipe Line LLC | KMEP | = | Kinder Morgan Energy Partners, L.P. |
| CIG | = | Colorado Interstate Gas Company, L.L.C. | KMGP | = | Kinder Morgan G.P., Inc. |
| Copano | = | Copano Energy, L.L.C. | KMI | = | Kinder Morgan Inc. and its majority-owned and/or |
| CPG | = | Cheyenne Plains Gas Pipeline Company, L.L.C. | controlled subsidiaries | ||
| EagleHawk | = | EagleHawk Field Services 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 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 | Ruby | = | Ruby Pipeline Holding Company, L.L.C. | ||
| EPNG | = | El Paso Natural Gas Company, L.L.C. | SFPP | = | SFPP, L.P. |
| EPPOC | = | El Paso Pipeline Partners Operating Company, | SLNG | = | Southern LNG Company, L.L.C. |
| L.L.C. | SNG | = | Southern Natural Gas Company, L.L.C. | ||
| FEP | = | Fayetteville Express Pipeline LLC | TGP | = | Tennessee Gas Pipeline Company, L.L.C. |
| Hiland | = | Hiland Partners, LP | WIC | = | Wyoming Interstate Company, L.L.C. |
| KinderHawk | = | KinderHawk Field Services LLC | WYCO | = | WYCO Development L.L.C. |
| KMCO2 | = | Kinder Morgan CO2 Company, L.P. | |||
| 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 | U.S. | = | United States of America |
| FERC | = | Federal Energy Regulatory Commission | SEC | = | United States Securities and Exchange |
| FTC | = | Federal Trade Commission | Commission | ||
| GAAP | = | United States Generally Accepted Accounting | TBtu | = | trillion British Thermal Units |
| Principles | WTI | = | West Texas Intermediate | ||
| 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,” “outlook,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or pay dividends, are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results may differ materially from those expressed in our forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or accurately predict. Specific factors that could cause actual results to differ from those in our forward-looking statements include:
| • | the extent of volatility in prices for and resulting changes in supply of and demand for NGL, refined petroleum products, oil, CO2, natural gas, electricity, coal, steel and other bulk materials and chemicals and certain agricultural products in North America; |
| • | economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand; |
| • | changes in our tariff rates required by the FERC, the CPUC, Canada’s NEB or another regulatory agency; |
| • | our ability to acquire new businesses and assets and integrate those operations into our existing operations, and make cost-saving changes in operations, particularly if we undertake multiple acquisitions in a relatively short period of time, as well as our ability to expand our facilities; |
| • | our ability to safely operate and maintain our existing assets and to access or construct new pipeline, gas processing, gas storage and NGL fractionation capacity; |
| • | our ability to attract and retain key management and operations personnel; |
| • | difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines; |
| • | shut-downs or cutbacks at major refineries, petrochemical or chemical plants, natural gas processing plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us; |
| • | changes in crude oil and natural gas production (and the NGL content of natural gas production) from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the shale plays in North Dakota, Oklahoma, Ohio, Pennsylvania and Texas, and the U.S. Rocky Mountains and the Alberta, Canada oil sands; |
| • | changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may increase our compliance costs, restrict our ability to provide or reduce demand for our services, or otherwise adversely affect our business; |
| • | interruptions of operations at our facilities due to natural disasters, damage by third-parties, power shortages, strikes, riots, terrorism (including cyber attacks), war or other causes; |
| • | 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 at economically attractive rates; |
| • | the ability of our customers and other counterparties to perform under their contracts with us; |
| • | competition from other pipelines or other forms of transportation; |
| • | changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities; |
| • | changes in tax laws; |
| • | our ability to access external sources of financing in sufficient amounts and on acceptable terms to the extent needed to fund acquisitions of operating businesses and assets and expansions of our facilities; |
| • | our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at a competitive disadvantage compared to our competitors that have less debt, or have other adverse consequences; |
| • | our ability to obtain insurance coverage without significant levels of self-retention of risk; |
| • | acts of nature, 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, including the effects of any enactment of import or export duties, tariffs or similar measures; |
| • | our ability to achieve cost savings and revenue growth; |
| • | foreign exchange fluctuations; |
| • | 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 work-overs, and in drilling new wells; and |
| • | unfavorable results of litigation and the outcome of contingencies referred to in Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements. |
The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that any of the actions, events or results expressed in forward-looking statements will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements.
Additional discussion of factors that may affect our forward-looking statements appears elsewhere in this report, including in Item 1A, “Risk Factors,” Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk-Energy Commodity Market Risk.” In addition, there is a general level of uncertainty regarding the extent to which potential positive or negative changes to fiscal, tax and trade policies may impact us and those with whom we do business. It is not possible at this time to predict the extent of any such impact. When considering forward-looking statements, you should keep in mind the factors described in this section and the other sections referenced above. These factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation, other than as required by applicable law, and described below under Items 1 and 2, “Business and Properties—(a) General Development of Business—Recent Developments—2017 Outlook,” to update the above list or to announce publicly the result of any revisions to any of our forward-looking statements to reflect future events or developments.
PART I
Items 1 and 2. Business and Properties.
We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 84,000 miles of pipelines and 155 terminals. 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 steel, coal and petroleum coke. We are also a leading producer of CO2, which we and others utilize for enhanced oil recovery projects primarily in the Permian basin. Our common stock trades on the NYSE under the symbol “KMI.”
(a) General Development of Business
Organizational Structure
We are a Delaware corporation and our common stock has been publicly traded since February 2011. Prior to November 2014, we conducted most of our business through two master limited partnerships: KMP (whose business and affairs were managed by KMR, a publicly traded limited liability company), and EPB.
On November 26, 2014, we completed our acquisition, pursuant to three separate merger agreements, of all of the outstanding common units of KMP and EPB and all of the outstanding shares of KMR that we did not already own. The transactions 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 Merger Transactions, KMR was merged with and into KMI.
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.
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 statement of income for the year ended December 31, 2014.
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.
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 and other transactions. Additional information regarding most of these items may be found elsewhere in this report. “Capital Scope” is estimated for our share of the described project which may include portions not yet completed.
| Asset or project | Description | Activity | Approx. Capital Scope | |||
| Placed in service, acquisitions or divestitures | ||||||
| SNG natural gas pipeline system | Sold 50% interest in SNG natural gas pipeline system to The Southern Company and formed a joint venture, which includes our remaining 50% interest in SNG. | Completed in September 2016 | n/a | |||
| KM and BP Joint Venture | Acquired 15 refined products terminals and associated infrastructure. KM and BP formed a joint venture, with an equity ownership interest of 75% and 25%, respectively, which owns 14 of the acquired assets. One terminal is owned solely by KM. | Acquired February 2016. | $349 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. Supported by long-term contracts. | Initial service began in December 2016. | $285 million | |||
| Cow Canyon development | An expansion project that increases CO2 production in the Cow Canyon area of the McElmo Dome source field by 200 MMcf/d. | Majority placed in service in 2015 and completed during the 1st quarter of 2016. | $229 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. | 350,000 Dth/d placed into service during 2015. The final 150,000 Dth/d capacity increment was placed in service in October 2016. | $230 million | |||
| 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. | Placed in service November 2016. | $227 million | |||
| Other Announcements | ||||||
| Natural Gas Pipelines | ||||||
| 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 in mid-2018 with the remainder by early 2019. | $1.9 billion | |||
| TGP Broad Run Expansion | Second of two separate projects modifying existing pipeline facilities 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. | Broad Run Flexibility facilities (590,000 Dth/d) were placed in service November 2015. Broad Run Expansion (200,000 Dth/d) expected to be in service in June 2018. | $452 million | |||
| EPNG South Mainline Expansion (formerly upstream Sierrita) | Expansion projects to provide 471,000 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 in service July 2020 ($133 million). | $135 million | |||
| Texas Intrastate Crossover Expansion | Expansion project to provide transportation capacity from the Katy Hub, the company’s Houston Central processing plant, and other third party receipt points to serve customers in Texas and Mexico. Phase I is supported by commitments of over 800,000 Dth/d, including contracts with Cheniere Energy, Inc. at its Corpus Christi LNG facility and Comisión Federal de Electricidad. Phase 2, which is supported by a long-term commitment from SK E&S LNG, LLC, will provide service to the Freeport LNG export facility and bring the total project capacity to over 1,000,000 Dth/d. | Phase 1 was placed in service in September 2016. Phase 2 is expected to be in service by third quarter 2019. | $307 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. | $179 million |
| Asset or project | Description | Activity | Approx. Capital Scope | |||
| 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 agreements, subject to shipper’s final investment decision. | Expected in-service fourth quarter 2020 | $127 million | |||
| KMLP Sabine Pass Expansion | Reconfiguration to flow northeast to southeast to deliver 600,000 Dth/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 | $151 million | |||
| TGP Orion | An expansion project to provide an additional 135,000 Dth/d of firm capacity from the Marcellus supply basin to TGP’s interconnection with Columbia Gas Transmission in Pike County, Pennsylvania. Subscribed under long-term firm transportation contracts. | Expected in service June 2018. | $141 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 | |||
| NGPL Gulf Coast Southbound Expansion | Expansion project, which is fully subscribed under long-term contracts, is designed to transport 460,000 Dth/d of incremental firm transportation service from NGPL’s interstate pipeline interconnects in Illinois, Arkansas and Texas to points south on NGPL’s pipeline system to serve growing demand in the Gulf Coast area. | Pending regulatory approvals, the project is expected in service by the fourth quarter of 2018. | $106 million | |||
| TGP Connecticut Expansion | Project will upgrade portions of TGP’s existing system in New York, Massachusetts and Connecticut, and provide 72,100 Dth/d of additional firm transportation capacity for three local distribution company customers. | Expected in-service November 2017. | $93 million | |||
| TGP Triad Expansion | Expansion project that provides 180,000 Dth/d of long-term capacity for Invenergy’s Lackawanna Energy Center in Lackawanna County, PA. Subscribed under long-term firm transportation contracts. | Expected in service between November 2017 and June 2018. | $69 million | |||
| Terminals | ||||||
| Jones Act 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. Also purchase of four new 50,000-deadweight-ton Tier II tankers constructed by Philly Shipyard. Each LNG conversion-ready will have a capacity of 337,000 barrels. | First tanker delivery took place in December 2015. Four additional tankers were delivered during 2016. The remaining four tankers are scheduled to be delivered through the end of 2017. | $1.4 billion | |||
| 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. | Storage tanks placed in service in January 2017 with the terminal’s full marine capabilities to follow by the end of the first quarter 2017. | $246 million | |||
| KM Base Line Terminal development | Announced a 50-50 joint venture with Keyera Corp. to build a new 4.8 million barrels of merchant crude oil storage facility in Edmonton, Alberta. Subscribed under long-term contracts with an average initial term of 7.5 years. | Construction continues. Commissioning expected to begin in the first quarter of 2018 with tanks phased-into service throughout 2018. | CAD$372 million | |||
| Pit 11 Expansion Project | Adds 2 million barrels of refined products storage at Pasadena terminal, along the Houston Ship Channel. Supported by long-term commitments from existing customers. | Commissioning is expected to begin in the third quarter of 2017, with the tanks phased into service through the first quarter of 2018. | $185 million | |||
| Products Pipelines | ||||||
| Utopia Pipeline | Building of new 215 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 barrels per day, expandable to more than 75,000 barrels per day. | Expected in service January 2018. | $540 million |
| Asset or project | Description | Activity | Approx. Capital Scope | |||
| 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. | Received federal government approval in December 2016. Construction is planned to begin in September 2017. Expected in service in December 2019. | $5.4 billion |
n/a - not applicable
Financings
On August 16, 2016, our wholly owned subsidiary, CIG, completed a private offering of $375 million in aggregate principal amount of 4.15% senior notes due August 15, 2026. On September 30, 2016 and October 1, 2016, a portion of the proceeds from the sale of a 50% interest in SNG was used to repay all of the $332 million principal amount outstanding of Copano’s 7.125% senior notes due 2021, plus accrued interest and all of the $749 million principal amount outstanding of Hiland’s 7.25% senior notes due 2020, plus accrued interest, respectively.
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 Losses on Divestitures” 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.”
2017 Outlook
We expect to declare dividends of $0.50 per share for 2017 and generate approximately $4.46 billion of distributable cash flow. We also expect to invest $3.2 billion on expansion projects during 2017 to be funded with internally generated cash flow without the need to access equity markets. Our 2017 budget assumes a joint venture partner on our Trans Mountain expansion project and contributions from that partner to fund its share of expansion capital, but does not include any potential proceeds in excess of the partner’s share of expansion capital to recognize the value created in developing the project to this stage. We are unable to provide budgeted net income attributable to common stockholders (the GAAP financial measure most directly comparable to distributable cash flow) due to the inherent difficulty and impracticality of predicting certain amounts required by GAAP, such as ineffectiveness on commodity, interest rate and foreign currency hedges, unrealized gains and losses on derivatives marked to market, and potential changes in estimates for certain contingent liabilities.
These expectations assume an average 2017 WTI crude oil price of $53 per barrel and an average 2017 Henry Hub natural gas price of $3 per MMBtu, which were consistent with the current forward curve at the time that our 2017 budget was prepared.
The overwhelming majority of cash we generate is supported by multi-year fee-based customer arrangements and therefore is not directly exposed to commodity prices. The primary area where we have direct commodity price sensitivity is in our CO2 segment, where we hedge the majority of the next 12 months of oil production to minimize this sensitivity. For 2017, we estimate that every $1 change in the average WTI crude oil price per barrel would impact our distributable cash flow by approximately $6 million and each $0.10 per MMBtu change in the average price of natural gas would impact distributable cash flow by approximately $1 million.
In addition, our expectations for 2017 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 2017 expectations when we believe previously disclosed expectations no longer have a reasonable basis.
(b) Financial Information about Segments
For financial information on our five 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 full and partial divestitures, and we are currently contemplating potential transactions. Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, receipt of fairness opinions, and approval of our board of directors, if applicable. While there are currently no unannounced purchase or sale agreements for the acquisition or sale of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.
Business Segments
We operate the following reportable business segments. These segments and their principal sources of revenues are as follows:
| • | Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG facilities; |
| • | CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas; |
| • | Terminals—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, chemicals, and ethanol and bulk products, including coal, petroleum coke, fertilizer, steel and ores and (ii) Jones Act tankers; |
| • | Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, propane, crude oil and condensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; and |
| • | Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport. |
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 46,000 miles of natural gas pipelines and (ii) our equity interests in entities that have approximately 26,000 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, 2016. The Design Capacity represents either transmission, gathering or liquefaction capacity depending on the nature of the asset.
| Asset (KMI ownership shown if not 100%) | Miles of Pipeline | Design (Bcf/d) Capacity | Storage (Bcf) [Processing (Bcf/d)] Capacity | Supply and Market Region | |||||
| Natural Gas Pipelines | |||||||||
| TGP | 11,800 | 10.23 | 104 | North to south to Gulf Coast and U.S.-Mexico border, southeast U.S.; Haynesville, Marcellus, Utica, and Eagle Ford shale formations | |||||
| EPNG/Mojave pipeline system | 10,600 | 5.65 | 44 | Northern New Mexico, Texas, Oklahoma, to California, connects to San Juan, Permian and Anadarko basins | |||||
| NGPL (50%) | 9,100 | 6.90 | 288 | Chicago and other Midwest markets and all central U.S. supply basins; north to south for LNG and to U.S.-Mexico border | |||||
| SNG (50%) | 6,900 | 4.07 | 68 | Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee; basins in Texas, Louisiana, Mississippi and Alabama | |||||
| Florida Gas Transmission (Citrus) (50%) | 5,300 | 3.60 | — | Texas to Florida; basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico | |||||
| CIG | 4,350 | 5.15 | 37 | Colorado and Wyoming; Rocky Mountains and the Anadarko Basin | |||||
| WIC | 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 | 410 | 1.20 | — | Colorado and Kansas, natural gas basins in the Central Rocky Mountain area | |||||
| TransColorado Gas | 310 | 0.98 | — | Colorado and New Mexico; connects to San Juan, Paradox and Piceance basins | |||||
| WYCO (50%) | 224 | 1.20 | 7 | Northeast Colorado; interconnects with CIG, WIC, Rockies Express Pipeline, Young Gas Storage and PSCo’s pipeline system | |||||
| Elba Express | 200 | 0.95 | — | Georgia; connects to SNG (Georgia), Transco (Georgia/South Carolina), SLNG (Georgia) and CGT (Georgia). | |||||
| FEP (50%) | 185 | 2.00 | — | Arkansas to Mississippi; connects to NGPL, Trunkline Gas Company, Texas Gas Transmission and ANR Pipeline Company | |||||
| KMLP | 135 | 2.20 | — | sources gas from Cheniere Sabine Pass LNG terminal to interconnects with Columbia Gulf, ANR and various other pipelines | |||||
| Sierrita Gas Pipeline LLC (35%) | 61 | 0.20 | — | near Tucson, Arizona, to the U.S.-Mexico border near Sasabe, Arizona; connects to EPNG and via an international border crossing with a third-party natural gas pipeline in Mexico | |||||
| Young Gas Storage (48%) | 16 | — | 6 | Morgan County, Colorado, capacity is committed to CIG and Colorado Springs Utilities | |||||
| Keystone Gas Storage | 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 a natural gas processing plant | |||||
| Bear Creek Storage (75%) | — | — | 59 | located in Louisiana; provides storage capacity to SNG and TGP |
| Asset (KMI ownership shown if not 100%) | Miles of Pipeline | Design (Bcf/d) Capacity | Storage (Bcf) [Processing (Bcf/d)] Capacity | Supply and Market Region | |||||
| SLNG | — | — | 11.5 | Georgia; connects to Elba Express, SNG and CGT | |||||
| ELC | — | 0.35 | — | Georgia; expect phased in service from mid-2018 to early 2019 | |||||
| Midstream Natural Gas Assets | |||||||||
| KM Texas and Tejas pipelines | 5,650 | 6.40 | 136 [0.51] | Texas Gulf Coast | |||||
| Mier-Monterrey pipeline | 90 | 0.65 | — | Starr County, Texas to Monterrey, Mexico; connect to CENEGAS national system and multiple power plants in Monterrey | |||||
| KM North Texas pipeline | 80 | 0.33 | — | interconnect from NGPL; connects to 1,750-megawatt Forney, Texas, power plant and a 1,000-megawatt Paris, Texas, power plant | |||||
| Oklahoma | |||||||||
| Oklahoma System | 3,500 | 0.35 | [0.15] | Hunton Dewatering, Woodford Shale and Mississippi Lime | |||||
| Hiland - Midcontinent | 622 | 0.20 | — | Woodford Shale, Anadarko Basin and Arkoma Basin | |||||
| Southern Dome (73%) | — | — | [0.02] | currently idle | |||||
| Cedar Cove (70%) | 89 | 0.03 | [0.01] | Oklahoma STACK, capacity excludes third-party offloads | |||||
| South Texas | |||||||||
| South Texas System | 1,300 | 1.74 | [1.06] | Eagle Ford shale, Woodbine and Eaglebine formations | |||||
| Webb/Duval gas gathering system (63%) | 145 | 0.15 | — | South Texas | |||||
| EagleHawk (25%) | 590 | 1.20 | — | South Texas, Eagle Ford shale formation | |||||
| KM Altamont | 1,350 | 0.08 | [0.08] | Utah, Uinta Basin | |||||
| Red Cedar (49%) | 750 | 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 | 500 | 2.00 | — | Northwest Louisiana, Haynesville and Bossier shale formations | |||||
| North Texas | 550 | 0.14 | [0.10] | North Barnett Shale Combo | |||||
| Endeavor (40%) | 101 | 0.15 | — | East Texas, Cotton Valley Sands and Haynesville/ Bossier Shale | |||||
| Camino Real | 70 | 0.15 | — | South Texas, Eagle Ford shale formation | |||||
| KM Treating | — | — | — | Odessa, Texas, other locations in Tyler and Victoria, Texas | |||||
| Hiland - Williston | 2,000 | 0.31 | [0.20] | Bakken/Three Forks shale formations (North Dakota/Montana) | |||||
| Midstream Liquids/Oil/Condensate Pipelines | |||||||||
| (MBbl/d) | (MBbl) | ||||||||
| Liberty Pipeline (50%) | 87 | 170 | — | Y-grade pipeline from Houston Central complex to the Texas Gulf Coast | |||||
| South Texas NGL Pipelines | 340 | 115 | — | Ethane and propane pipelines from Houston Central complex to the Texas Gulf Coast | |||||
| Camino Real - Condensate | 68 | 110 | 20 | South Texas, Eagle Ford shale formation | |||||
| Hiland - Williston - Oil | 1,480 | 240 | — | Bakken/Three Forks shale formations (North Dakota/Montana) | |||||
| EagleHawk - Condensate (25%) | 410 | 220 | 60 | South Texas, Eagle Ford shale formation |
Competition
The market for supply of natural gas is highly competitive, and new pipelines, storage facilities, treating facilities, and facilities for related services are currently being built to serve the growing demand for natural gas in each of the markets served by the pipelines in our Natural Gas Pipelines business segment. Our operations compete with interstate and intrastate pipelines, and their shippers, for connections to new markets and supplies and for transportation, processing and treating services. We believe the principal elements of competition in our various markets are location, rates, terms of service and flexibility and reliability of service. From time to time, other projects are proposed that would compete with us. We do not know whether or when any such projects would be built, or the extent of their impact on our operations or profitability.
Shippers on our natural gas pipelines compete with other forms of energy available to their natural gas customers and end users, including electricity, coal, propane, fuel oils and renewables such as wind and solar. Several factors influence the demand for natural gas, including price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the ability to convert to alternative fuels and weather.
CO2
Our CO2 business segment produces, transports, and markets CO2 for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. Our CO2 pipelines and related assets allow us to market a complete package of CO2 supply, transportation and technical expertise to our customers. We also hold ownership interests in several oil-producing fields and own a crude oil pipeline, all located in the Permian Basin region of West Texas.
Sales and Transportation Activities
Our principal market for CO2 is for injection into mature oil fields in the Permian Basin, where industry demand is expected to remain stable for the next several years. Our ownership of CO2 resources as of December 31, 2016 includes:
| Ownership Interest % | Recoverable CO2 (Bcf) | Compression Capacity (Bcf/d) | Location | ||||||
| Recoverable CO2 | |||||||||
| McElmo Dome unit(a) | 45 | 4,570 | 1.5 | Colorado | |||||
| Doe Canyon Deep unit(a) | 87 | 420 | 0.2 | Colorado | |||||
| Bravo Dome unit | 11 | 367 | 0.3 | New Mexico |
| (a) | We also operate this unit. |
CO2 Segment Pipelines
The principal market for transportation on our CO2 pipelines is to customers, including ourselves, using CO2 for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to remain stable for the next several years. The tariffs charged on the Wink 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, 2016 includes:
| Asset (KMI ownership shown if not 100%) | Miles of Pipeline | Transport Capacity(Bcf/d) | Supply and Market Region | |||||
| CO2 pipelines | ||||||||
| Cortez pipeline (50%) | 569 | 1.5 | McElmo Dome and Doe Canyon source fields to the Denver City, Texas hub | |||||
| Central Basin pipeline | 334 | 0.7 | Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers, and Pecos pipelines | |||||
| Bravo pipeline (13%)(a) | 218 | 0.4 | Bravo Dome to the Denver City, Texas hub | |||||
| Canyon Reef Carriers pipeline (98%) | 163 | 0.3 | McCamey, Texas, to the SACROC, Sharon Ridge, Cogdell and Reinecke units | |||||
| Centerline CO2 pipeline | 113 | 0.3 | between Denver City, Texas and Snyder, Texas | |||||
| Eastern Shelf CO2 pipeline | 98 | 0.1 | between Snyder, Texas and Knox City, Texas | |||||
| Pecos pipeline (95%) | 25 | 0.1 | McCamey, Texas, to Iraan, Texas, delivers to the Yates unit | |||||
| Goldsmith Landreth (99%) | 3 | 0.2 | Goldsmith Landreth San Andres field in the Permian Basin of West Texas | |||||
| (Bbls/d) | ||||||||
| Crude oil pipeline | ||||||||
| Wink pipeline | 457 | 145,000 | West Texas to Western Refining’s refinery in El Paso, Texas |
| (a) | We do not operate Bravo pipeline. |
Oil and Gas Producing Activities
Oil Producing Interests
Our ownership interests in oil-producing fields located in the Permian Basin of West Texas, include the following:
| KMI Gross | |||||
| Working | Developed | ||||
| Interest % | Acres | ||||
| SACROC | 97 | 49,156 | |||
| Yates | 50 | 9,576 | |||
| Goldsmith Landreth San Andres | 99 | 6,166 | |||
| Katz Strawn | 99 | 7,194 | |||
| Sharon Ridge | 14 | 2,619 | |||
| Tall Cotton (ROZ) | 100 | 641 | |||
| MidCross | 13 | 320 | |||
| Reinecke(a) | — | 80 |
| (a) | 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, 2016. 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 | 2,239 | 1,447 | 1,227 | 984 | 6 | 6 | |||||||||||
| Natural Gas | 5 | 2 | — | — | — | — | |||||||||||
| Total Wells | 2,244 | 1,449 | 1,227 | 984 | 6 | 6 |
| (a) | Includes active wells and wells temporarily shut-in. As of December 31, 2016, 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, 2016. 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, 2016, 2015 and 2014:
| Year Ended December 31, | ||||||||
| 2016 | 2015 | 2014 | ||||||
| Productive | ||||||||
| Development | 40 | 87 | 84 | |||||
| Exploratory | 3 | 20 | 10 | |||||
| Total Productive | 43 | 107 | 94 | |||||
| Dry Exploratory | — | — | 1 | |||||
| Total Wells | 43 | 107 | 95 |
Note: The above table includes wells that were completed during each year regardless of the year in which drilling was initiated, and does not include any wells where drilling and completion operations were not finalized as of the end of the applicable year. A completed well refers to the installation of permanent equipment for the production of oil and gas. A development well is a well drilled in an already discovered oil field. A dry hole is reflected once the well has been abandoned and reported to the appropriate governmental agency. Prior year amounts have been adjusted to be consistent with the current period presentation.
The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2016:
| Gross | Net | ||||
| Developed Acres | 75,752 | 72,561 | |||
| Undeveloped Acres | 17,282 | 15,093 | |||
| Total | 93,034 | 87,654 |
Note: As of December 31, 2016, we have no material amount of acreage expiring in the next three years.
Our oil and gas producing activities are not significant and therefore, we do not include the supplemental information on oil and gas producing activities under Accounting Standards Codification Topic 932, Extractive Activities - Oil and Gas.
Gas and Gasoline Plant Interests
Operated gas plants in the Permian Basin of West Texas:
| Ownership | ||||
| Interest % | Source | |||
| Snyder gasoline plant(a) | 22 | The SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and Cogdell units | ||
| Diamond M gas plant | 51 | Snyder gasoline plant | ||
| North Snyder plant | 100 | Snyder gasoline plant |
| (a) | This is a working interest, in addition, we have a 28% net profits interest. The average net to us does not include the value associated with the net profits interest. |
Competition
Our primary competitors for the sale of CO2 include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain CO2 resources, and Oxy U.S.A., Inc., which controls waste CO2 extracted from natural gas production in the Val Verde Basin of West Texas. Our ownership interests in the Central Basin, Cortez and Bravo pipelines are
in direct competition with other CO2 pipelines. We also compete with other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of CO2 to the Denver City, Texas market area.
Terminals
Our Terminals segment includes the operations of our refined petroleum product, crude oil, chemical, ethanol and other liquid 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 terminal facilities. Our terminals are located throughout the U.S. and in portions of Canada. We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide expansion opportunities. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, Terminals’ marine operations include Jones Act qualified product tankers that provide marine transportation of crude oil, condensate and refined petroleum products in the U.S. The following summarizes our Terminals segment assets, as of December 31, 2016:
| Number | Capacity (MMBbl) | ||||
| Liquids terminals | 51 | 85.2 | |||
| Bulk terminals | 37 | — | |||
| Jones Act tankers | 12 | 4.0 |
Competition
We are one of the largest independent operators of liquids terminals in North America, based on barrels of liquids terminaling capacity. Our liquids terminals compete with other publicly or privately held independent liquids terminals, and terminals owned by oil, chemical, pipeline, and refining 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 terminaling services. In some locations, competitors are smaller, independent operators with lower cost structures. Our Jones Act qualified product tankers compete with other Jones Act qualified vessel fleets.
Products Pipelines
Our Products Pipelines segment consists of our refined petroleum products, crude oil and condensate, and NGL pipelines and associated terminals, Southeast terminals, our condensate processing facility and our transmix processing facilities. The following summarizes our significant Products Pipelines segment assets we own and operate as of December 31, 2016:
| Asset (KMI ownership shown if not 100%) | Miles of Pipeline | Number of Terminals (a) or locations | Terminal Capacity(MMBbl) | Supply and Market Region | |||||||
| Plantation pipeline (51%) | 3,182 | — | — | Louisiana to Washington D.C. | |||||||
| West Coast Products Pipelines(b) | |||||||||||
| Pacific (SFPP) | 2,823 | 13 | 15.5 | six western states | |||||||
| Calnev | 570 | 2 | 2.1 | Colton, CA to Las Vegas, NV; Mojave region | |||||||
| West Coast Terminals | 43 | 7 | 10.1 | Seattle, Portland, San Francisco and Los Angeles areas | |||||||
| Cochin pipeline | 1,877 | 4 | 1.1 | three provinces in Canada and seven states in the U.S. | |||||||
| KM Crude & Condensate pipeline | 252 | 5 | 2.6 | Eagle Ford shale field in South Texas (Dewitt, Karnes, and Gonzales Counties) to the Houston ship channel refining complex | |||||||
| Double H Pipeline | 511 | — | — | Bakken shale in Montana and North Dakota to Guernsey, Wyoming | |||||||
| Central Florida pipeline | 206 | 2 | 2.5 | Tampa to Orlando | |||||||
| Double Eagle pipeline (50%) | 194 | 2 | 0.6 | Live Oak County, Texas; Corpus Christi, Texas; Karnes County, Texas; and LaSalle County | |||||||
| Cypress pipeline (50%) | 104 | Mont Belvieu, Texas to Lake Charles, Louisiana | |||||||||
| Southeast Terminals | — | 32 | 10.8 | from Mississippi through Virginia, including Tennessee | |||||||
| KM Condensate Processing Facility | — | 1 | 1.9 | Houston Ship Channel, Galena Park, Texas | |||||||
| Transmix Operations | — | 5 | 1.0 | Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; St. Louis, Missouri; and Greensboro, North Carolina |
| (a) | The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending. |
| (b) | Our West Coast Products Pipelines assets include interstate common carrier pipelines rate-regulated by the FERC, intrastate pipelines in the state of California rate-regulated by the CPUC, and certain non rate-regulated operations and terminal facilities. |
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.
Major Customers
Our revenue is derived from a wide customer base. For each of the years ended December 31, 2016, 2015 and 2014, 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 2016, 2015 and 2014 accounted for 19%, 20% and 25%, respectively, of our total consolidated revenues. To the extent possible, we attempt to balance the pricing and timing of our natural gas purchases to our natural gas sales, and these contracts are often settled in terms of an index price for both purchases and sales. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.
Regulation
Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation - U.S. Operations
Some of our U.S. refined petroleum products and crude oil gathering and transmission pipelines are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain our tariffs on file with the FERC. Those tariffs set forth the rates we charge for providing gathering or transportation services on our interstate common carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.
The Energy Policy Act of 1992 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 FERC 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 Regulatory 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.
Mexico - Nacional Agency for Industrial Safety and Environmental Protection (ASEA)
ASEA regulates environmental compliance and industrial and operational safety. The Mier-Monterrey Pipeline must satisfy and maintain ASEA’s requirements, including compliance with certain safety measures, contingency plans, maintenance plans and the official Mexican standards regarding safety, including a Safety Administration Program.
Safety Regulation
We are also subject to safety regulations imposed by PHMSA, including those requiring us to develop and maintain pipeline Integrity Management programs to comprehensively evaluate areas along our pipelines and take additional measures to protect pipeline segments located in what are referred to as High Consequence Areas, or HCAs, where a leak or rupture could potentially do the most harm.
The ultimate costs of compliance with pipeline Integrity Management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional integrity threats and changes to the amount of pipe determined to be located in HCAs can have a significant impact on costs to perform integrity testing and repairs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by PHMSA regulations. These tests could result in significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.
The Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 or “PIPES Act of 2016” requires PHMSA, among others, to set minimum safety standards for underground natural gas storage facilities and allows states to go above those standards for intrastate pipelines. The Act also authorizes emergency order authority that is tailored to the pipeline sector, taking into account public health and safety, network, and customer impacts. The financial impact of these two requirements, if any, is unknown at this time.
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 $302 million as of December 31, 2016. Our aggregate reserve estimate ranges in value from approximately $302 million to approximately $477 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 KMI facilities with air pollution controls. Given the nationwide implications of the new rule, it is expected that it will have financial impacts for each of our business units.
Climate Change
Studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and CO2, which is naturally occurring and
also a byproduct of the burning of natural gas, are examples of greenhouse gases. Various laws and regulations exist or are under development that seek to regulate the emission of such greenhouse gases, including the EPA programs to control greenhouse gas emissions and state actions to develop statewide or regional programs. The U.S. Congress has in the past considered legislation to reduce emissions of greenhouse gases.
Beginning in December 2009, EPA published several findings and rulemakings under the Clean Air Act requiring the permitting and reporting of certain greenhouse gases including CO2 and methane. Our facilities are subject to these requirements. Operational and/or regulatory changes could require additional facilities to comply with greenhouse gas emissions reporting and permitting requirements. Additionally, in June 2016, the EPA published a proposed rule regarding the “Oil and Natural Gas Sector: Emission Standards for New and Modified Sources,” otherwise known as the Proposed New Source Performance Standard (NSPS) Part OOOOa Rule. This rule is 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 KMI 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 11,121 full-time people at December 31, 2016, including approximately 907 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 2017 and 2022. We consider relations with our employees to be good.
Most of our employees are employed by us and a limited number of our subsidiaries and provide services to one or more of our business units. The direct costs of compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated to our subsidiaries. Our human resources department provides the administrative support necessary to implement these payroll and benefits services, and the related administrative costs are allocated to our subsidiaries pursuant to our board-approved expense allocation policy. The effect of these arrangements is that each business unit bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs.
Properties
We believe that we generally have satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties or the use of such properties in our businesses. Our terminals, storage facilities, treating and processing plants, regulator and compressor stations, oil and gas wells, offices and related facilities are located on real property owned or leased by us. In some cases, the real property we lease is on federal, state, provincial or local government land.
We generally do not own the land on which our pipelines are constructed. Instead, we obtain the right to construct and operate the pipelines on other people’s land for a period of time. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of a majority of the interests have been obtained. Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense. Permits also have been obtained from railroad companies to run along or cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. Some such permits require annual or other periodic payments. In a few minor cases, property for pipeline purposes was purchased in fee.
(d) 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.