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10-K 1 kmi-2017x10k.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, 2017
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 |
| Depositary Shares, each representing a 1/20th interest in a share of 9.75% Series A Mandatory Convertible Preferred Stock | New York Stock Exchange |
| 1.500% Senior Notes due 2022 | New York Stock Exchange |
| 2.250% Senior Notes due 2027 | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K(§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes o No þ
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 30, 2017 was approximately $36,830,209,065. As of February 8, 2018, the registrant had 2,206,066,684 Class P shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2018, are incorporated into PART III, as specifically set forth in PART III.
| KINDER MORGAN, INC. AND SUBSIDIARIES GLOSSARY Company Abbreviations | |||||
|---|---|---|---|---|---|
| Calnev | = | Calnev Pipe Line LLC | KMGP | = | Kinder Morgan G.P., Inc. |
| CIG | = | Colorado Interstate Gas Company, L.L.C. | KMI | = | Kinder Morgan, Inc. and its majority-owned and/or |
| Copano | = | Copano Energy, L.L.C. | controlled subsidiaries | ||
| CPGPL | = | Cheyenne Plains Gas Pipeline Company, L.L.C. | KML | = | Kinder Morgan Canada Limited and its majority- |
| EagleHawk | = | EagleHawk Field Services LLC | owned and/or controlled subsidiaries | ||
| Elba Express | = | Elba Express Company, L.L.C. | KMLP | = | Kinder Morgan Louisiana Pipeline LLC |
| ELC | = | Elba Liquefaction Company, L.L.C. | KMP | = | Kinder Morgan Energy Partners, L.P. and its |
| EP | = | El Paso Corporation and its majority-owned and | majority-owned and controlled subsidiaries | ||
| controlled subsidiaries | KMR | = | Kinder Morgan Management, LLC | ||
| EPB | = | El Paso Pipeline Partners, L.P. and its majority- | MEP | = | Midcontinent Express Pipeline LLC |
| owned and controlled subsidiaries | NGPL | = | Natural Gas Pipeline Company of America LLC | ||
| EPNG | = | El Paso Natural Gas Company, L.L.C. | Ruby | = | Ruby Pipeline Holding Company, L.L.C. |
| EPPOC | = | El Paso Pipeline Partners Operating Company, | SFPP | = | SFPP, L.P. |
| L.L.C. | SLNG | = | Southern LNG Company, L.L.C. | ||
| FEP | = | Fayetteville Express Pipeline LLC | SNG | = | Southern Natural Gas Company, L.L.C. |
| Hiland | = | Hiland Partners, LP | TGP | = | Tennessee Gas Pipeline Company, L.L.C. |
| KinderHawk | = | KinderHawk Field Services LLC | TMEP | = | Trans Mountain Expansion Project |
| KMCO2 | = | Kinder Morgan CO2 Company, L.P. | WIC | = | Wyoming Interstate Company, L.L.C. |
| KMEP | = | Kinder Morgan Energy Partners, L.P. | WYCO | = | WYCO Development L.L.C. |
| 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 | |||||
| 2017 Tax | IPO | = | Initial Public Offering | ||
| Reform | = | The Tax Cuts & Jobs Act of 2017 | LIBOR | = | London Interbank Offered Rate |
| /d | = | per day | LLC | = | limited liability company |
| AFUDC | = | allowance for funds used during construction | LNG | = | liquefied natural gas |
| BBtu | = | billion British Thermal Units | MBbl | = | thousand barrels |
| Bcf | = | billion cubic feet | MDth | = | thousand dekatherms |
| CERCLA | = | Comprehensive Environmental Response, | MLP | = | master limited partnership |
| Compensation and Liability Act | MMBbl | = | million barrels | ||
| C$ | = | Canadian dollars | MMcf | = | million cubic feet |
| CO2 | = | carbon dioxide or our CO2 business segment | NEB | = | National Energy Board |
| CPUC | = | California Public Utilities Commission | NGL | = | natural gas liquids |
| DCF | = | distributable cash flow | NYMEX | = | New York Mercantile Exchange |
| DD&A | = | depreciation, depletion and amortization | NYSE | = | New York Stock Exchange |
| DGCL | = | General Corporation Law of the state of Delaware | OTC | = | over-the-counter |
| Dth | = | dekatherms | PHMSA | = | United States Department of Transportation |
| EBDA | = | earnings before depreciation, depletion and | Pipeline and Hazardous Materials Safety | ||
| amortization expenses, including amortization of | Administration | ||||
| excess cost of equity investments | U.S. | = | United States of America | ||
| EPA | = | United States Environmental Protection Agency | SEC | = | United States Securities and Exchange |
| FASB | = | Financial Accounting Standards Board | Commission | ||
| FERC | = | Federal Energy Regulatory Commission | TBtu | = | trillion British Thermal Units |
| FTC | = | Federal Trade Commission | WTI | = | West Texas Intermediate |
| GAAP | = | United States Generally Accepted Accounting | |||
| Principles | |||||
| When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch. |
Information Regarding Forward-Looking Statements
This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “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; |
| • | issues, delays or stoppage associated with major expansion projects, including TMEP; |
| • | regulatory, environmental, political, legal, operational and geological uncertainties that could affect our ability to complete our expansion projects on time and on budget or at all; |
| • | 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; |
| • | natural disasters, sabotage, terrorism (including cyber attacks) or other similar acts or accidents causing damage to our properties greater than our insurance coverage limits; |
| • | possible changes in our and our 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—2018 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 85,000 miles of pipelines and 152 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals transload and store liquid commodities including petroleum products, ethanol and chemicals, and bulk products, including petroleum coke, steel and coal. 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.
Sale of Approximate 30% Interest in our Canadian Business
On May 30, 2017, our indirectly owned subsidiary, KML, completed an IPO of 102,942,000 restricted voting shares listed on the Toronto Stock Exchange (TSX) at a price to the public of C$17.00 per restricted voting share for total gross proceeds of approximately C$1,750 million. The net proceeds of C$1,677 million (U.S.$1,245 million) from the IPO were used by KML to indirectly acquire from us an approximate 30% interest in a limited partnership that holds our Canadian business, while we retained the remaining 70% interest. We used the proceeds from KML to pay down debt.
Subsequent to the IPO, we retained control of KML and the limited partnership, and as a result, they remain consolidated in our consolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in our consolidated statements of stockholders’ equity and consolidated balance sheets. Earnings attributable to the public ownership of KML are presented in “Net income attributable to noncontrolling interests” in our consolidated statements of income for the periods presented after May 30, 2017.
The portion of the Canadian business operations that we sold to the public on May 30, 2017 represented Canadian assets that are included in our Kinder Morgan Canada, Terminals and Products Pipelines business segments and included the Trans Mountain pipeline system (including related terminaling assets), TMEP, the Puget Sound and Jet Fuel pipeline systems, the Canadian portion of the Cochin pipeline system, the Vancouver Wharves Terminal and the North 40 Terminal; as well as three jointly controlled investments: the Edmonton Rail Terminal, the Alberta Crude Terminal and the Base Line Terminal.
Subsequent to its IPO, KML has obtained a credit facility and completed two preferred share offerings. KMI expects KML to be a self-funding entity and does not anticipate making contributions to fund its growth or specifically to fund the TMEP.
You should read the following in conjunction with our audited consolidated financial statements and the notes thereto. We have prepared our accompanying consolidated financial statements under GAAP and the rules and regulations of the SEC. Our accounting records are maintained in U.S. dollars and all references to dollars in this report are to U.S. dollars, except where stated otherwise. Our consolidated financial statements include our accounts and those of our majority-owned and/or controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation. The address of our principal executive offices is 1001 Louisiana Street, Suite 1000, Houston, Texas 77002, and our telephone number at this address is (713) 369-9000.
Recent Developments
The following is a brief listing of significant developments and updates related to our major projects 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 | ||||||
| ELC | Sold 49% interest in ELC to investment funds of EIG Global Energy Partners and formed a joint venture, which includes our remaining 51% interest in ELC. | Completed in February 2017. | n/a | |||
| Jones Act Tankers | Purchase of nine new-build, medium-range Jones Act tankers constructed by General Dynamics NASSCO Shipyard (five) and Philly Shipyard, Inc. (four). Each of the 50,000-deadweight-ton, LNG conversion-ready product tankers has a capacity of approximately 330,000 barrels and is contracted under a term charter agreement. | First tanker delivery took place in December 2015. Four additional tankers were delivered during 2016. The final four tankers were delivered during 2017. | $1.4 billion | |||
| Elba Express and SNG Expansion | Expansion project that provides 854,000 Dth/d of incremental natural gas transportation service supporting the needs of customers in Georgia, South Carolina and northern Florida, and also serving ELC. Supported by long-term firm contracts. | Initial service began in December 2016. As of December 31, 2017, more than 70% of capacity has been placed in service. The remaining work is expected to be completed by November 2018. | $284 million | |||
| KM Export Terminal | Brownfield expansion along Houston Ship Channel that adds 12 storage tanks with 1.5 MMBbl of liquids storage capacity, one ship dock, one barge dock and cross-channel pipelines to connect with the KM Galena Park terminal. Supported by a long-term contract with a major ship channel refiner. | Storage tanks placed in service in January 2017 followed by the terminal’s full marine capabilities, which were commissioned in March 2017. | $246 million | |||
| Pit 11 Expansion | Project adds 2 MMBbl of refined products storage at Pasadena terminal along the Houston Ship Channel. Supported by long-term commitments from existing customers. | Placed in service throughout fourth quarter 2017. | $186 million | |||
| TGP Susquehanna West | Expansion project that provides 145,000 Dth/d of incremental natural gas transportation capacity from the northeast Marcellus supply basin to points of liquidity. Subscribed under long-term firm transportation contracts. | Placed in service September 2017. | $126 million | |||
| TGP Orion | Expansion project that provides 135,000 Dth/d of incremental firm transportation 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. | Placed in service November 2017. | $104 million | |||
| TGP Connecticut Expansion | Expansion project that provides 72,100 Dth/d of incremental firm transportation capacity from Wright, New York to three local distribution companies in Connecticut. Subscribed under long-term firm transportation contracts. | Placed in service November 2017. | $104 million | |||
| TGP Triad Expansion | Expansion project that provides 180,000 Dth/d of incremental firm transportation capacity from the Marcellus supply basin to Invenergy’s Lackawanna Energy Center in Lackawanna County, Pennsylvania. Subscribed under long-term firm transportation contracts. | Project facilities placed in service November 2017 (customer contracts to begin June 2018). | $57 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 357,000 Dth/d of natural gas. Supported by a long-term firm contract with Shell. | First of 10 liquefaction units expected to be placed in service in mid-2018 with the remainder expected by mid-2019. | $1.2 billion | |||
| KMTP Gulf Coast Express Pipeline Project (GCX Project)(a) | New infrastructure joint venture project (KMTP 50%, DCP Midstream, LP 25% and Targa Resources Corp. 25% ownership interest) to provide up to 1.98 Bcf/d of transportation capacity from the Permian Basin to the Agua Dulce, Texas area with 1.76 Bcf/d under long-term contracts. A binding open season for the remaining 220,000 Dth/d of project capacity ends on March 1, 2018. | Pending regulatory approvals, the project is expected to be placed in service October 2019. | $638 million |
| Asset or project | Description | Activity | Approx. Capital Scope | |||
| TGP Broad Run Expansion | Second of two projects to create a total of 790,000 Dth/d of incremental firm transportation capacity from the southwest Marcellus and Utica supply basins to delivery points in Mississippi and Louisiana. Subscribed under long-term firm transportation contracts. | Broad Run Expansion (200,000 Dth/d) expected to be placed in service June 2018. Broad Run Flexibility facilities (590,000 Dth/d) were placed in service November 2015. | $453 million | |||
| Texas Intrastate Crossover Expansion | Expansion project that provides over 1,000,000 Dth/d of transportation capacity from the Katy Hub, the company’s Houston Central processing plant, and other third party receipt points to serve customers in Texas and Mexico. Phase I is supported by long-term firm transportation contracts of nearly 700,000 Dth/d, including a contract with Comisión Federal de Electricidad. Phase 2, which is supported by long-term firm transportation contracts with Cheniere Energy, Inc. at its Corpus Christi LNG facility and SK E&S LNG, LLC, that will provide service to the Freeport LNG export facility and other domestic markets. | Phase 1 was placed in service in September 2016. Phase 2 is expected to be placed in service by third quarter 2019. | $307 million | |||
| TGP Southwest Louisiana Supply | Expansion project to provide 900,000 Dth/d of incremental firm transportation capacity from multiple supply basins to the Cameron LNG export facility in Cameron Parish, Louisiana. Subscribed under long-term firm transportation contracts. | Expected in-service date March 2018. | $178 million | |||
| TGP Lone Star | Expansion project to provide 300,000 Dth/d of incremental firm transportation capacity from Louisiana receipt points to Cheniere’s Corpus Christi LNG export facility in Jackson County, Texas. Subscribed under long-term firm transportation contracts. | Expected in-service date July 2019. | $150 million | |||
| EPNG South Mainline Expansion (formerly upstream Sierrita) | Expansion project that provides 471,000 Dth/d of firm transportation 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. Subscribed under long-term firm transportation contracts. | Phase one placed in service October 2014, phase two expected to be in service July 2020. | $134 million | |||
| KMLP Magnolia LNG Liquefaction Transport | Expansion project to provide 700,000 Dth/d of incremental firm transportation capacity from various receipt points to the proposed Magnolia LNG export facility in Lake Charles, Louisiana. Subscribed under long-term firm agreements, subject to shipper’s final investment decision. | In-service date subject to timing of shipper’s final investment decision. | $127 million | |||
| KMLP Sabine Pass Expansion | Expansion project to provide 600,000 Dth/d of incremental firm transportation capacity from various receipt points to Cheniere’s Sabine Pass Liquefaction Terminal in Cameron Parish, Louisiana. Subscribed under long-term firm transportation contracts. | Expected in-service date as early as the first quarter 2019. | $122 million | |||
| SNG Fairburn Expansion | Expansion project in Georgia to provide 347,000 Dth/d of incremental long-term firm transportation capacity into the Southeast market, and includes the construction of a new compressor station, 6.5 miles of new pipeline and new meter stations. | Expected in-service date October 2018. | $119 million | |||
| NGPL Gulf Coast Southbound Expansion | Expansion project to provide 460,000 Dth/d of incremental firm transportation capacity from various interstate pipeline interconnects in Illinois, Arkansas and Texas, to points south on NGPL’s pipeline system to serve growing demand in the Gulf Coast area. Subscribed under long-term firm transportation contracts. | Partially in service April 2017 (75,000 Dth/d). Remaining (385,000 Dth/d) expected to be in service fourth quarter of 2018. | $106 million | |||
| Terminals | ||||||
| KM Base Line Terminal development(b) | A 4.8 MMBbl new-build merchant crude oil storage facility in Edmonton, Alberta. Developed as part of a 50-50 joint venture with Keyera Corp. Capital figure includes costs associated with the construction of a pipeline segment funded solely by Kinder Morgan. Subscribed under long-term contracts with an average initial term of 7.5 years. | Commissioning began in the first quarter of 2018. First four tanks placed in-service in January 2018 with balance expected to be phased into service throughout 2018. | C$398 million | |||
| Products Pipelines | ||||||
| Utopia Pipeline | Building of new 267 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 MBbl/d, expandable to more than 75 MBbl/d. | Placed in-service January 2018. | $275 million |
| Asset or project | Description | Activity | Approx. Capital Scope | |||
| Kinder Morgan Canada | ||||||
| TMEP(b) | An increase of capacity on our Trans Mountain pipeline system from approximately 300 to 890 MBbl/d, underpinned by long-term take-or-pay contracts. | Received federal government approval in December 2016. In the process of getting permits and other regulatory approval. | C$7.4 billion |
n/a - not applicable
| (a) | Our share of capital scope is adjusted to reflect the potential exercise of Apache Corp.’s option to purchase 15% equity in the project. |
| (b) | As of May 31, 2017, these assets are now included in KML and are partially owned by KML’s Restricted Voting Stockholders. |
KMI Financings
On August 10, 2017, we issued $1 billion of unsecured senior notes with a fixed rate of 3.15% and $250 million of unsecured senior notes with a floating rate, both due January 2023. The net proceeds from the notes were primarily used to repay all of the $225 million principal amount outstanding of Hiland’s 5.50% senior notes due 2022, plus accrued interest, and to repay the $1 billion term loan facility due 2019.
KML Financings
In addition to proceeds received from KML’s IPO discussed above, on June 16, 2017, KML entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the TMEP; (ii) a C$1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional TMEP costs (and, subject to the need to fund such additional costs and regulatory approval, meeting the Canadian NEB-mandated liquidity requirements); and (iii) a C$500 million revolving working capital facility, to be used for working capital and other general corporate purposes (collectively, the “KML Credit Facility”). The KML Credit Facility has a five year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. On January 23, 2018, KML entered into an agreement amending certain terms of the KML Credit Facility to, among other things, provide additional funding certainty with respect to the construction, contingent and working capital facilities. As of December 31, 2017, KML had no amounts outstanding under the KML Credit Facility and C$53 million (U.S.$42 million) in letters of credit.
On August 15, 2017, KML completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares) on the TSX at a price to the public of $25.00 per Series 1 Preferred Share for total net proceeds of C$293 million (U.S.$230 million) and on December 8, 2017, KML completed an offering of 10,000,000 cumulative redeemable minimum rate reset preferred shares, Series 3 (Series 3 Preferred Shares) on the TSX at a price to the public of $25.00 per Series 3 Preferred Share for total net proceeds of C$243 million (U.S.$189 million).
2018 Outlook
We expect to declare dividends of $0.80 per share for 2018, a 60% increase from the 2017 declared dividends of $0.50 per share, and generate approximately $4.57 billion of DCF. We also expect to invest $2.2 billion on expansion projects and other discretionary spending in 2018, excluding growth capital and discretionary spending by KML, which we expect to continue to be a self-funding entity. As in recent years, our discretionary spending will be funded with excess, internally generated cash flow, with no need to access equity markets during 2018. In addition, our board of directors authorized a $2 billion share buy-back program, and in December 2017 and January 2018 we bought back 27 million Class P shares for $500 million.
We are unable to provide budgeted net income attributable to common stockholders (the GAAP financial measure most directly comparable to DCF) due to the inherent difficulty and impracticality of 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 average annual prices for WTI crude oil and Henry Hub natural gas of $56.50 per barrel and $3.00 per MMBtu, respectively, consistent with forward pricing during our 2018 budget process. The vast 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, in which we hedge the majority of the next 12 months of oil and NGL production to minimize this sensitivity. For 2018, we estimate that every $1 change in the average WTI crude oil price from our budget of $56.50 per barrel would impact our DCF by approximately $7 million and each $0.10 per MMBtu change in the average price of natural gas from our budget of $3.00 per MMBtu would impact DCF by approximately $1 million.
In addition, our expectations for 2018 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 2018 expectations when we believe previously disclosed expectations no longer have a reasonable basis.
2017 Tax Reform
While the recently enacted 2017 Tax Reform will ultimately be moderately positive for us, the reduced corporate income tax rate caused certain of our deferred-tax assets to be revalued at 21 percent versus 35 percent at the end of 2017. Although there is no impact to the underlying related deductions, which can continue to be used to offset future taxable income, we took an estimated approximately $1.4 billion non-cash accounting charge in the fourth quarter of 2017. This charge is our initial estimate and may be refined in the future as permitted by recent guidance from the SEC and FASB. The positive impacts of the law include the reduced corporate income tax rate and the fact that several of our U.S. business units (essentially all but our interstate natural gas pipelines) will be able to deduct 100 percent of their capital expenditures through 2022. The net impact results in postponing the date when we become a significant federal cash taxpayer by approximately one year, to beyond 2024.
(b) Financial Information about Segments
For financial information on our 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 petroleum coke, steel and coal; 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, ethane, 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 transportation, storage, natural gas sales, gathering, processing and treating, and the terminaling of LNG. Within this segment, are: (i) approximately 46,000 miles of wholly owned 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, 2017. 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 | 11,750 | 12.00 | 106 | North to south to Gulf Coast and U.S.-Mexico border, southeast U.S.; Haynesville, Marcellus, Utica, and Eagle Ford shale formations | |||||
| EPNG/Mojave pipeline system | 10,600 | 5.65 | 44 | Northern New Mexico, Texas, Oklahoma, to California, connects to San Juan, Permian and Anadarko basins | |||||
| NGPL (50%) | 9,100 | 7.60 | 288 | Chicago and other Midwest markets and all central U.S. supply basins; north to south for LNG and to U.S.-Mexico border | |||||
| SNG (50%) | 6,900 | 4.16 | 68 | Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee; basins in Texas, Louisiana, Mississippi and Alabama | |||||
| Florida Gas Transmission (Citrus) (50%) | 5,300 | 3.60 | — | Texas to Florida; basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico | |||||
| CIG | 4,350 | 5.15 | 37 | Colorado and Wyoming; Rocky Mountains and the Anadarko Basin |
| Asset (KMI ownership shown if not 100%) | Miles of Pipeline | Design (Bcf/d) Capacity | Storage (Bcf) [Processing (Bcf/d)] Capacity | Supply and Market Region | |||||
| WIC | 850 | 3.88 | — | Wyoming, Colorado and Utah; Overthrust, Piceance, Uinta, Powder River and Green River Basins | |||||
| Ruby (50%)(a) | 680 | 1.53 | — | Wyoming to Oregon with interconnects supplying California and the Pacific Northwest; Rocky Mountain basins | |||||
| MEP (50%) | 510 | 1.80 | — | Oklahoma and north Texas supply basins to interconnects with deliveries to interconnects with Transco, Columbia Gulf and various other pipelines | |||||
| CPGPL | 410 | 1.20 | — | Colorado and Kansas, natural gas basins in the Central Rocky Mountain area | |||||
| TransColorado Gas | 310 | 0.98 | — | Colorado and New Mexico; connects to San Juan, Paradox and Piceance basins | |||||
| WYCO (50%) | 224 | 1.20 | 7 | Northeast Colorado; interconnects with CIG, WIC, Rockies Express Pipeline, Young Gas Storage and PSCo’s pipeline system | |||||
| Elba Express | 200 | 0.95 | — | Georgia; connects to SNG (Georgia), Transco (Georgia/South Carolina), SLNG (Georgia) and Dominion Energy Carolina Gas Transmission (Georgia) | |||||
| FEP (50%) | 185 | 2.00 | — | Arkansas to Mississippi; connects to NGPL, Trunkline Gas Company, Texas Gas Transmission and ANR Pipeline Company | |||||
| KMLP | 135 | 2.20 | — | sources gas from Cheniere Sabine Pass LNG terminal to interconnects with Columbia Gulf, ANR and various other pipelines | |||||
| Sierrita Gas Pipeline LLC (35%) | 61 | 0.20 | — | near Tucson, Arizona, to the U.S.-Mexico border near Sasabe, Arizona; connects to EPNG and via an international border crossing with a third-party natural gas pipeline in Mexico | |||||
| Young Gas Storage (48%) | 16 | — | 5.8 | Morgan County, Colorado, capacity is committed to CIG and Colorado Springs Utilities | |||||
| Keystone Gas Storage | 15 | — | 6.4 | located in the Permian Basin and near the WAHA natural gas trading hub in West Texas | |||||
| Gulf LNG Holdings (50%) | 5 | — | 6.6 | near Pascagoula, Mississippi; connects to four interstate pipelines and a natural gas processing plant | |||||
| Bear Creek Storage (75%) | — | — | 59 | located in Louisiana; provides storage capacity to SNG and TGP | |||||
| SLNG | — | — | 11.5 | Georgia; connects to Elba Express, SNG and Dominion Energy Carolina Gas Transmission | |||||
| ELC (51%) | — | 0.35 | — | Georgia; expect phased in-service from mid-2018 to mid-2019 | |||||
| Midstream Natural Gas Assets | |||||||||
| KM Texas and Tejas pipelines | 5,660 | 7.00 | 132 [0.54] | Texas Gulf Coast | |||||
| Mier-Monterrey pipeline | 90 | 0.65 | — | Starr County, Texas to Monterrey, Mexico; connect to CENEGAS national system and multiple power plants in Monterrey | |||||
| KM North Texas pipeline | 80 | 0.33 | — | interconnect from NGPL; connects to 1,750-megawatt Forney, Texas, power plant and a 1,000-megawatt Paris, Texas, power plant | |||||
| Oklahoma | |||||||||
| Oklahoma System | 3,500 | .50 | [0.14] | Hunton Dewatering, Woodford Shale and Mississippi Lime | |||||
| Hiland - Midcontinent | 620 | .22 | — | Woodford Shale, Anadarko Basin and Arkoma Basin | |||||
| Cedar Cove (70%) | 85 | 0.03 | — | Oklahoma STACK, capacity excludes third-party offloads | |||||
| South Texas | |||||||||
| South Texas System | 1,300 | 1.74 | [1.02] | Eagle Ford shale, Woodbine and Eaglebine formations | |||||
| Webb/Duval gas gathering system (63%) | 145 | 0.15 | — | South Texas |
| Asset (KMI ownership shown if not 100%) | Miles of Pipeline | Design (Bcf/d) Capacity | Storage (Bcf) [Processing (Bcf/d)] Capacity | Supply and Market Region | |||||
| EagleHawk (25%) | 530 | 1.20 | — | South Texas, Eagle Ford shale formation | |||||
| KM Altamont | 1,380 | 0.08 | [0.08] | Utah, Uinta Basin | |||||
| Red Cedar (49%) | 900 | 0.70 | — | La Plata County, Colorado, Ignacio Blanco Field | |||||
| Rocky Mountain | |||||||||
| Fort Union (37%) | 310 | 1.25 | — | Powder River Basin (Wyoming) | |||||
| Bighorn (51%) | 290 | 0.60 | — | Powder River Basin (Wyoming) | |||||
| KinderHawk | 510 | 2.00 | — | Northwest Louisiana, Haynesville and Bossier shale formations | |||||
| North Texas | 550 | 0.14 | [0.10] | North Barnett Shale Combo | |||||
| Endeavor (40%) | 101 | 0.15 | — | East Texas, Cotton Valley Sands and Haynesville/ Bossier Shale | |||||
| Camino Real | 70 | 0.15 | — | South Texas, Eagle Ford shale formation | |||||
| KM Treating | — | — | — | Odessa, Texas, other locations in Tyler and Victoria, Texas | |||||
| Hiland - Williston | 2,030 | .32 | [0.20] | Bakken/Three Forks shale formations (North Dakota/Montana) | |||||
| Midstream Liquids/Oil/Condensate Pipelines | |||||||||
| (MBbl/d) | (MBbl) | ||||||||
| Liberty Pipeline (50%) | 87 | 140 | — | Y-grade pipeline from Houston Central complex to the Texas Gulf Coast | |||||
| South Texas NGL Pipelines | 340 | 115 | — | Ethane and propane pipelines from Houston Central complex to the Texas Gulf Coast | |||||
| Camino Real - Condensate | 69 | 110 | 60 | South Texas, Eagle Ford shale formation | |||||
| Hiland - Williston - Oil | 1,500 | 282 | — | Bakken/Three Forks shale formations (North Dakota/Montana) | |||||
| EagleHawk - Condensate (25%) | 400 | 220 | 60 | South Texas, Eagle Ford shale formation |
| (a) | We operate Ruby and own the common interest in Ruby. Pembina Pipeline Corporation (Pembina) owns the remaining interest in Ruby in the form of a convertible preferred interest. If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby. |
Competition
The market for supply of natural gas is highly competitive, and new pipelines, storage facilities, treating facilities, and facilities for related services are currently being built to serve the growing demand for natural gas in each of the markets served by the pipelines in our Natural Gas Pipelines 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. Our ownership of CO2 resources as of December 31, 2017 includes:
| Ownership Interest % | Recoverable CO2 (Bcf) | Compression Capacity (Bcf/d) | Location | ||||||
| Recoverable CO2 | |||||||||
| McElmo Dome unit | 45 | 4,159 | 1.5 | Colorado | |||||
| Doe Canyon Deep unit | 87 | 382 | 0.2 | Colorado | |||||
| Bravo Dome unit(a) | 11 | 285 | 0.3 | New Mexico |
| (a) | We do not operate this unit. |
CO2 Segment Pipelines
The principal market for transportation on our CO2 pipelines is to customers, including ourselves, using CO2 for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to remain stable for the next several years. The tariffs charged on the Wink crude oil pipeline system are regulated by both the FERC and the Texas Railroad Commission and the Pecos Carbon Dioxide Pipeline’s tariffs are regulated by the Texas Railroad Commission. The tariff charged on the Cortez pipeline is based on a consent decree and the tariffs charged by our other CO2 pipelines are not regulated.
Our ownership of CO2 and crude oil pipelines as of December 31, 2017 includes:
| Asset (KMI ownership shown if not 100%) | Miles of Pipeline | Transport Capacity (Bcf/d) | Supply and Market Region | |||||
| CO2 pipelines | ||||||||
| Cortez pipeline (53%) | 569 | 1.5 | McElmo Dome and Doe Canyon source fields to the Denver City, Texas hub | |||||
| Central Basin pipeline | 334 | 0.7 | Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers, and Pecos pipelines | |||||
| Bravo pipeline (13%)(a) | 218 | 0.4 | Bravo Dome to the Denver City, Texas hub | |||||
| Canyon Reef Carriers pipeline (98%) | 163 | 0.3 | McCamey, Texas, to the SACROC, Sharon Ridge, Cogdell and Reinecke units | |||||
| Centerline CO2 pipeline | 113 | 0.3 | between Denver City, Texas and Snyder, Texas | |||||
| Eastern Shelf CO2 pipeline | 98 | 0.1 | between Snyder, Texas and Knox City, Texas | |||||
| Pecos pipeline (95%) | 25 | 0.1 | McCamey, Texas, to Iraan, Texas, delivers to the Yates unit | |||||
| Goldsmith Landreth (99%) | 3 | 0.2 | Goldsmith Landreth San Andres field in the Permian Basin of West Texas | |||||
| (Bbls/d) | ||||||||
| Crude oil pipeline | ||||||||
| Wink pipeline | 457 | 145,000 | West Texas to Western Refining’s refinery in El Paso, Texas |
| (a) | We do not operate Bravo pipeline. |
Oil and Gas Producing Activities
Oil Producing Interests
Our ownership interests in oil-producing fields located in the Permian Basin of West Texas include the following:
| 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, 2017. The oil and gas producing fields in which we own interests are located in the Permian Basin area of West Texas. When used with respect to acres or wells, “gross” refers to the total acres or wells in which we have a working interest, and “net” refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by us:
| Productive Wells(a) | Service Wells(b) | Drilling Wells(c) | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Crude Oil | 2,327 | 1,518 | 1,412 | 1,088 | 27 | 26 | |||||||||||
| Natural Gas | 5 | 2 | — | — | — | — | |||||||||||
| Total Wells | 2,332 | 1,520 | 1,412 | 1,088 | 27 | 26 |
| (a) | Includes active wells and wells temporarily shut-in. As of December 31, 2017, we did not operate any productive wells with multiple completions. |
| (b) | Consists of injection, water supply, disposal wells and service wells temporarily shut-in. A disposal well is used for disposal of salt water into an underground formation; and an injection well is a well drilled in a known oil field in order to inject liquids and/or gases that enhance recovery. |
| (c) | Consists of development wells in the process of being drilled as of December 31, 2017. A development well is a well drilled in an already discovered oil field. |
The following table reflects our wells that were completed in each of the years ended December 31, 2017, 2016 and 2015:
| Year Ended December 31, | ||||||||
| 2017 | 2016 | 2015 | ||||||
| Productive | ||||||||
| Development | 108 | 40 | 87 | |||||
| Exploratory | 3 | 20 | ||||||
| Total Productive | 108 | 43 | 107 | |||||
| Dry Exploratory | — | — | — | |||||
| Total Wells | 108 | 43 | 107 |
Note: The above table includes wells that were completed during each year regardless of the year in which drilling was initiated, and does not include any wells where drilling and completion operations were not 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.
The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2017:
| Gross | Net | ||||
| Developed Acres | 75,752 | 72,562 | |||
| Undeveloped Acres | 17,282 | 15,351 | |||
| Total | 93,034 | 87,913 |
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. |
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 petroleum coke, steel and coal facilities. Our terminals are located throughout the U.S. and in portions of Canada. We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide expansion opportunities. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, Terminals’ marine operations include Jones Act qualified product tankers that provide marine transportation of crude oil, condensate and refined petroleum products between U.S. ports. The following summarizes our Terminals segment assets, as of December 31, 2017:
| Number | Capacity (MMBbl) | ||||
| Liquids terminals | 51 | 87.4 | |||
| Bulk terminals | 35 | — | |||
| Jones Act tankers | 16 | 5.3 |
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, 2017:
| 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) | 2,845 | 13 | 15.2 | six western states | |||||||
| Calnev | 566 | 2 | 2.0 | Colton, CA to Las Vegas, NV; Mojave region | |||||||
| West Coast Terminals | 38 | 7 | 10.3 | Seattle, Portland, San Francisco and Los Angeles areas | |||||||
| Cochin pipeline | 1,810 | 3 | 1.1 | three provinces in Canada and seven states in the U.S. | |||||||
| KM Crude & Condensate pipeline | 264 | 5 | 2.6 | Eagle Ford shale field in South Texas (Dewitt, Karnes, and Gonzales Counties) to the Houston ship channel refining complex | |||||||
| Double H Pipeline | 511 | — | — | Bakken shale in Montana and North Dakota to Guernsey, Wyoming | |||||||
| Central Florida pipeline | 206 | 2 | 2.4 | Tampa to Orlando | |||||||
| Double Eagle pipeline (50%) | 204 | 2 | 0.6 | Live Oak County, Texas; Corpus Christi, Texas; Karnes County, Texas; and LaSalle County | |||||||
| Cypress pipeline (50%) | 104 | — | — | Mont Belvieu, Texas to Lake Charles, Louisiana | |||||||
| Southeast Terminals | — | 32 | 10.7 | from Mississippi through Virginia, including Tennessee | |||||||
| KM Condensate Processing Facility | — | 1 | 1.9 | Houston Ship Channel, Galena Park, Texas | |||||||
| Transmix Operations | — | 5 | 0.6 | Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; St. Louis, Missouri; and Greensboro, North Carolina |
| (a) | The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending. |
| (b) | Our West Coast Products Pipelines assets include interstate common carrier pipelines rate-regulated by the FERC, intrastate pipelines in the state of California rate-regulated by the CPUC, and certain non rate-regulated operations and terminal facilities. |
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 the Trans Mountain pipeline system and a 25-mile Jet Fuel pipeline system. Effective with KML’s May 2017 IPO, the operating assets in our Kinder Morgan Canada segment are included in KML. Operating assets in our Terminals and Products Pipelines segments are also included in KML, in which we retain a controlling interest, and KML and these operating assets are included in our consolidated financial statements.
Trans Mountain Pipeline System
The Trans Mountain pipeline system (TMPL) originates at Edmonton, Alberta and transports crude oil and refined petroleum products to destinations in the interior and on the west coast of British Columbia. The TMPL is 713 miles in length. The capacity of the line at Edmonton ranges from 300 MBbl/d when heavy crude oil represents 20% of the total throughput (which is a historically normal heavy crude oil percentage), to 400 MBbl/d with no heavy crude oil. The TMPL mainline is a common carrier pipeline, providing transportation services under a cost of service model that is negotiated with shippers and regulated by the NEB. Although Trans Mountain takes custody of its shippers’ products, it does not own any of the product it ships. The TMPL system has posted tariff rates that are available to all shippers based on a monthly contract which varies according to the type of product being shipped as well as receipt and delivery points. As such, it provides service to producers, marketers, refineries and terminals who sell or resell products to domestic markets, oil marketers and international shippers moving oil to such places as California, Washington State and Asia.
We also own and operate a connecting pipeline that delivers crude oil to refineries in the state of Washington referred to as the Puget Sound Pipeline System which is regulated by the FERC for tariffs and the U.S. Department of Transportation for safety and integrity.
TMEP
KML continues to move forward with its C$7.4 billion TMEP that upon completion would provide western Canadian crude oil producers with an additional 590 MBbl/d of shipping capacity and tidewater access to the western U.S. (most notably states of Washington, California and Hawaii) and global markets (most notably Asia). TMEP has firm transportation services agreements with 13 companies for a total of 707.5 MBbl/d based on a capacity of 890 MBbl/d (the maximum amount that Trans Mountain anticipated the NEB would authorize).
See “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—General—KML—TMEP Construction Progress.”
Jet Fuel Pipeline System
We also own and operate the approximate 25-mile aviation fuel pipeline that serves the Vancouver International Airport, located in Vancouver, British Columbia, Canada. The turbine fuel pipeline is referred to in this report as the Jet Fuel pipeline system. In addition to its receiving and storage facilities located at the Westridge Marine terminal, located in Port Metro Vancouver, the Jet Fuel pipeline system’s operations include a terminal at the Vancouver airport that consists of five jet fuel storage tanks with an overall capacity of 15 MBbl.
Competition
Although Trans Mountain is the only pipeline carrying crude oil and refined petroleum products from Alberta to the west coast, it is subject to competition resulting from the shipment of oil from the Western Canadian Sedimentary Basis (WCSB) to markets other than the Canadian and U.S. West Coast, including shipments to refineries in Ontario, the U.S. Midwest and the U.S. Gulf Coast. In addition, refineries in Washington State and California, which comprise an important point of sale on the U.S. West Coast, have, in the past, been supplied primarily by crude oil from the Alaska North Slope. As such, there has historically been some competitive pressure on supply originating from the WCSB for sale in the states of Washington and California refinery markets. A further source of competition exists from the transportation of oil to the Canadian West Coast by rail. We expect that such supply and demand conditions in the oil markets served from the Canadian West Coast will continue to impact the long-term value and economics of the TMPL system.
Historically, the Jet Fuel pipeline has transported a significant proportion of the jet fuel used at the Vancouver International Airport. However, the airport also receives jet fuel through other means including trucks and an airport approved, and yet to be constructed, jet fuel barge-receiving terminal near the airport. The Jet Fuel pipeline systems’ supplying refinery was sold in 2017. As a result of that sale, we are unable to predict whether, and to what extent, that refinery will continue to supply jet fuel to the Jet Fuel pipeline. These developments have made it unclear how much jet fuel will continue to be available for shipment to the Vancouver International Airport by way of the Jet Fuel pipeline in the future. We continue to assess our options relating to our Jet Fuel pipeline assets.
Major Customers
Our revenue is derived from a wide customer base. For each of the years ended December 31, 2017, 2016 and 2015, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.
Our Texas Intrastate Natural Gas Pipeline operations (includes the operations of Kinder Morgan Tejas Pipeline LLC, Kinder Morgan Border Pipeline LLC, Kinder Morgan Texas Pipeline LLC, Kinder Morgan North Texas Pipeline LLC and the Mier-Monterrey Mexico pipeline system) buys and sells significant volumes of natural gas within the state of Texas, and, to a far lesser extent, the CO2 business segment also sells natural gas. Combined, total revenues from the sales of natural gas from the Natural Gas Pipelines and CO2 business segments in 2017, 2016 and 2015 accounted for 22%, 19% and 20%, respectively, of our total consolidated revenues. To the extent possible, we attempt to balance the pricing and timing of our natural gas purchases to our natural gas sales, and these contracts are often settled in terms of an index price for both purchases and sales.
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.
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 transportation services and storage services for natural gas); |
| • | Order No. 637 (2000) which revised, among other things, FERC regulations relating to scheduling procedures, capacity segmentation, and pipeline penalties in order to improve the competitiveness and efficiency of the interstate pipeline grid; and |
| • | Order No. 717 (2008) amending the Standards of Conduct for Transmission Providers (the Standards of Conduct or the Standards) to make them clearer and to refocus the marketing affiliate rules on the areas where there is the greatest potential for abuse. The FERC standards of conduct address and clarify multiple issues with respect to the actions and operations of interstate natural gas pipelines and public utilities using a functional approach to ensure that natural gas transmission is provided on a nondiscriminatory basis, including (i) the definition of transmission function and transmission function employees; (ii) the definition of marketing function and marketing function employees; (iii) the definition of transmission function information and non-disclosure requirements regarding non-public information; (iv) independent functioning and no conduit requirements; (v) transparency requirements; and (vi) the interaction of FERC standards with the NAESB business practice standards. The Standards of Conduct rules also require that a transmission provider provide annual training on the standards of conduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information. |
In addition to regulatory changes initiated by the FERC, the U.S. Congress passed the Energy Policy Act of 2005. Among other things, the Energy Policy Act amended the Natural Gas Act to: (i) prohibit market manipulation by any entity; (ii) direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce; and (iii) significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder.
CPUC Rate Regulation
The intrastate common carrier operations of our Pacific operations’ pipelines in California are subject to regulation by the CPUC under a “depreciated book plant” methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of the Pacific operations’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC. A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates also could arise with respect to its intrastate rates. The intrastate rates for movements in California on our SFPP and Calnev systems have been, and may in the future be, subject to complaints before the CPUC, as is more fully described in Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
Railroad Commission of Texas (RCT) Rate Regulation
The intrastate operations of our crude oil and liquids pipelines and natural gas pipelines and storage facilities in Texas are subject to regulation with respect to such intrastate transportation by the RCT. The RCT has the authority to regulate our rates, though it generally has not investigated the rates or practices of our intrastate pipelines in the absence of shipper complaints.
Mexico - Energy Regulatory Commission
The Mier-Monterrey Pipeline has a natural gas transportation permit granted by the Energy 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 limitation (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 standards of Mexico regarding safety; (iii) compliance with the technical and economic specifications of the natural gas transportation system authorized by the Commission; (iv) compliance with certain technical studies established by the Commission; and (v) compliance with a minimum contributed capital not entitled to withdrawal of at least the equivalent of 10% of the investment proposed in the project.
Mexico - National Agency for Industrial Safety and Environmental Protection (ASEA)
ASEA regulates environmental compliance and industrial and operational safety. The Mier-Monterrey Pipeline must satisfy and maintain ASEA’s requirements, including compliance with certain safety measures, contingency plans, maintenance plans and the official standards of Mexico regarding safety, including a Safety Administration Program.
Safety Regulation
We are also subject to safety regulations imposed by PHMSA, including those requiring us to develop and maintain pipeline Integrity Management programs to comprehensively evaluate areas along our pipelines and take additional measures to protect pipeline segments located in what are referred to as High Consequence Areas, or HCAs, where a leak or rupture could potentially do the most harm.
The ultimate costs of compliance with pipeline Integrity Management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional integrity threats and changes to the amount of pipe determined to be located in HCAs can have a significant impact on costs to perform integrity testing and repairs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by PHMSA regulations. These tests could result in significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.
The Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 or “PIPES Act of 2016” requires PHMSA, among others, to set minimum safety standards for underground natural gas storage facilities and allows states to go above those standards for intrastate pipelines. In compliance with the PIPES Act of 2016, we have implemented procedures for underground natural gas storage facilities.
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which was signed into law in 2012, increased penalties for violations of safety laws and rules and may result in the imposition of more stringent regulations in the next few
years. In 2012, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine maximum pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the Advisory Bulletin requirements, could significantly increase our costs. Additionally, failure to locate such records to verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines. There can be no assurance as to the amount or timing of future expenditures for pipeline Integrity Management regulation, and actual expenditures may be different from the amounts we currently anticipate. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Repair, remediation, and preventative or mitigating actions may require significant capital and operating expenditures.
From time to time, our pipelines may experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
We are also subject to the requirements of the Occupational Safety and Health Administration (OSHA) and other federal and state agencies that address employee health and safety. In general, we believe current expenditures are addressing the OSHA requirements and protecting the health and safety of our employees. Based on new regulatory developments, we may increase expenditures in the future to comply with higher industry and regulatory safety standards. However, such increases in our expenditures, and the extent to which they might be offset, cannot be estimated at this time.
State and Local Regulation
Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, pollution, protection of the environment, and human health and safety.
Marine Operations
The operation of tankers and marine equipment create maritime obligations involving property, personnel and cargo under General Maritime Law. These obligations create a variety of risks including, among other things, the risk of collision, which may precipitate claims for personal injury, cargo, contract, pollution, third party claims and property damages to vessels and facilities.
We are subject to the Jones Act and other federal laws that restrict maritime transportation (between U.S. departure and destination points) to vessels built and registered in the U.S. and owned and manned by U.S. citizens. As a result, we monitor the foreign ownership of our common stock and under certain circumstances, consistent with our certificate of incorporation, we have the right to redeem shares of our common stock owned by non-U.S. citizens. If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels. Furthermore, from time to time, legislation has been introduced unsuccessfully in Congress to amend the Jones Act to ease or remove the requirement that vessels operating between U.S. ports be built and registered in the U.S. and owned and manned by U.S. citizens. If the Jones Act were amended in such fashion, we could face competition from foreign flagged vessels.
In addition, the U.S. Coast Guard and the American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flag operators than for owners of vessels registered under foreign flags of convenience. The Jones Act and General Maritime Law also provide damage remedies for crew members injured in the service of the vessel arising from employer negligence or vessel unseaworthiness.
The Merchant Marine Act of 1936 is a federal law that provides, upon proclamation by the U.S. President of a national emergency or a threat to the national security, the U.S. Secretary of Transportation the authority to requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our vessels were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire.
However, we would not be entitled to compensation for any consequential damages suffered as a result of such purchase or requisition.
Environmental Matters
Our business operations are subject to federal, state, provincial and local laws and regulations relating to environmental protection, pollution and human health and safety in the U.S. and Canada. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, or at or from our storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damages, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. Furthermore, new projects may require approvals and environmental analysis under federal and state laws, including the National Environmental Policy Act and the Endangered Species Act. The resulting costs and liabilities could materially and negatively affect our business, financial condition, results of operations and cash flows. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities.
Environmental and human health and safety laws and regulations are subject to change. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health. There can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.
In accordance with GAAP, we accrue liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. We have accrued liabilities for estimable and probable environmental remediation obligations at various sites, including multi-party sites where the EPA, or similar state or Canadian agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multi-party sites could increase or mitigate our actual joint and several liability exposures.
We believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or cash flows in any particular reporting period. We have accrued an environmental reserve in the amount of $279 million as of December 31, 2017. Our aggregate reserve estimate ranges in value from approximately $279 million to approximately $443 million, and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability. For additional information related to environmental matters, see Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
Hazardous and Non-Hazardous Waste
We generate both hazardous and non-hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state and Canadian statutes. From time to time, the EPA and state and Canadian regulators consider the adoption of stricter disposal standards for non‑hazardous waste. Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations, may in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.
Superfund
The CERCLA or the Superfund law, and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons for releases of hazardous substances into the environment. These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any. Although petroleum is excluded from CERCLA’s definition of a hazardous substance, in the course of our ordinary operations, we have and will generate
materials that may fall within the definition of hazardous substance. By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any.
Clean Air Act
Our operations are subject to the Clean Air Act, its implementing regulations, and analogous state and Canadian statutes and regulations. The EPA regulations under the Clean Air Act contain requirements for the monitoring, reporting, and control of greenhouse gas emissions from stationary sources. For further information, see “—Climate Change” below.
Clean Water Act
Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the U.S. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal, state or Canadian authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention and response to oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state and Canadian laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release of oil.
EPA Revisions to Ozone National Ambient Air Quality Standard (NAAQS)
As required by the Clean Air Act, EPA establishes National Ambient Air Quality Standards (NAAQS) for how much pollution is permissible and then the states have to adopt rules so their air quality meets the NAAQS. In October 2015, EPA published a rule lowering the ground level ozone NAAQS from 75 ppb to a more stringent 70 ppb standard. This change triggers a process under which EPA will designate the areas of the country that are in or out of attainment with the new NAAQS standard. Then, certain states will have to adopt more stringent air quality regulations to meet the NAAQS standard. These new state rules, which are expected in 2020 or 2021, will likely require the installation of more stringent air pollution controls on newly installed equipment and possibly require retrofitting existing 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. For example, in August 2016, the EPA 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, became effective. This rule is the first federal rule under the Clean Air Act to regulate methane as a pollutant and 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. In October 2017, EPA proposed to repeal the Clean Power Plan. The ultimate resolution of the final rule’s validity remains uncertain. While we do not operate power plants that would be subject to the Clean Power Plan final rule, it remains unclear what effect the final rule, if it comes into force, might have on the anticipated demand for natural gas, including natural gas that we gather, process, store and transport.
At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already
have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. Although many of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that sources such as our gas-fired compressors and processing plants could become subject to related state regulations. Various states are also proposing or have implemented more strict regulations for greenhouse gases that go beyond the requirements of the EPA. Depending on the particular program, we could be required to conduct monitoring, do additional emissions reporting and/or purchase and surrender emission allowances.
Because our operations, including the compressor stations and processing plants, emit various types of greenhouse gases, primarily methane and CO2, such new legislation or regulation could increase the costs related to operating and maintaining the facilities. Depending on the particular law, regulation or program, we or our subsidiaries could be required to incur capital expenditures for installing new monitoring equipment of emission controls on the facilities, acquire and surrender allowances for the greenhouse gas emissions, pay taxes related to the greenhouse gas emissions and administer and manage a greenhouse gas emissions program. We are not able at this time to estimate such increased costs; however, as is the case with similarly situated entities in the industry, they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our or our subsidiaries’ pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond their control, including the outcome of future rate proceedings before the FERC or other regulatory bodies, and the provisions of any final legislation or other regulations. Any of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects.
Some climatic models indicate that global warming is likely to result in rising sea levels, increased intensity of hurricanes and tropical storms, and increased frequency of extreme precipitation and flooding. We may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather. To the extent these phenomena occur, they could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone regions. However, the timing and location of these climate change impacts is not known with any certainty and, in any event, these impacts are expected to manifest themselves over a long time horizon. Thus, we are not in a position to say whether the physical impacts of climate change pose a material risk to our business, financial position, results of operations or cash flows.
Because natural gas emits less greenhouse gas emissions per unit of energy than competing fossil fuels, cap-and-trade legislation or EPA regulatory initiatives such as the 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 10,897 full-time people at December 31, 2017, including approximately 801 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 2018 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.