| Exhibit 99.1 | ||||
KINDER MORGAN DECLARES DIVIDEND OF $0.125
FOR FIRST QUARTER 2017
Progressing Major Projects; Strengthening Balance Sheet
HOUSTON, Apr. 19, 2017 - Kinder Morgan, Inc. (NYSE: KMI) today announced that its board of directors approved a cash dividend of $0.125 per share for the quarter ($0.50 annualized) payable on May 15, 2017, to common shareholders of record as of the close of business on May 1, 2017. KMI expects to declare dividends of $0.50 per share for 2017 and use cash in excess of dividend payments to fully fund growth investments and further strengthen its balance sheet.
Richard D. Kinder, executive chairman, said, “We are pleased to have made additional progress on our two largest growth projects: Trans Mountain expansion and Elba Island Liquefaction. These are signature energy infrastructure assets for North America, and we expect they will contribute greatly to Kinder Morgan’s future growth. With respect to Trans Mountain, after receiving approval from the Canadian federal government and the province of British Columbia to proceed with the project, we completed our final cost estimate review process with the shippers. Despite the shippers’ right to terminate their contracts during this process, 100 percent of the original committed capacity (707,500 thousand barrels per day) remains under contract. Additionally, while making steady progress constructing our Elba Island Liquefaction facility, we welcomed EIG Global Energy Partners as a 49 percent joint venture participant in that project.”
“Meanwhile, consistent with previous guidance, we continue to develop financing alternatives for the Trans Mountain project, either by bringing in a joint venture partner or conducting an initial public offering of a portfolio that would include Trans Mountain and other Kinder Morgan Canadian assets,” said Kinder. “In doing so, we will stay on track toward our targeted leverage level of around 5.0 times net debt-to-Adjusted EBITDA. That leverage level will create options for us to return substantial value to shareholders through some combination of
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dividend increases, share repurchases, additional attractive growth projects or further debt reduction. Consistent with previous guidance, we expect to announce revised dividend guidance for 2018 in the latter part of this year. This progress, combined with our world class portfolio of fee-based energy infrastructure assets, the balancing of global crude oil supply and demand, and a more positive federal legislative and regulatory environment, makes us very confident about Kinder Morgan’s future in the near-term and long-term.”
President and CEO Steve Kean said, “We are pleased with our operational performance, which is slightly ahead of guidance we provided in January for the quarter, and we remain on target for the year. We generated earnings per common share for the quarter of $0.18 and distributable cash flow of $0.54 per common share, resulting in $935 million of excess distributable cash flow above our dividend.”
Kean added, “We continue to drive future growth by completing significant infrastructure development projects in our project backlog. Our current project backlog is $11.7 billion, down from $12.0 billion at the end of 2016. That total currently includes 100 percent of the Trans Mountain project costs and will be adjusted when we decide on a financing alternative. The reduction was primarily driven by placing the Kinder Morgan Export Terminal in service. Excluding the CO2 segment projects, we expect the projects in our backlog to generate an average capital-to-EBITDA multiple of approximately 6.7 times.”
KMI reported first quarter net income available to common stockholders of $401 million, compared to $276 million for the first quarter of 2016, and distributable cash flow of $1,215 million that was essentially flat versus $1,233 million for the comparable period in 2016. Net income available to common stockholders was impacted by a $162 million favorable change in total Certain Items compared to the first quarter of 2016. Certain Items in that quarter were primarily driven by project write-offs and losses on impairments and divestitures, partially offset by a favorable non-cash interest expense certain item.
2017 Outlook
For 2017, KMI expects to declare dividends of $0.50 per share, achieve distributable cash flow of approximately $4.46 billion ($1.99 per share) and Adjusted EBITDA of approximately $7.2 billion. KMI also expects to invest $3.2 billion in growth projects during 2017, to be funded with internally generated cash flow without the need to access equity markets, and to end the year with a net debt-to-Adjusted EBITDA ratio of approximately 5.4 times. KMI’s 2017 budget
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assumes a joint venture partner on the Trans Mountain expansion project and contributions from that partner to fund its share of growth capital, but does not include any potential proceeds in excess of the partner’s share of expansion capital to recognize the value created in developing the project to this stage. KMI does not provide budgeted net income attributable to common stockholders (the GAAP financial measure most directly comparable to distributable cash flow and Adjusted EBITDA) 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.
KMI’s expectations assume average annual prices for West Texas Intermediate (WTI) crude oil of $53 per barrel and Henry Hub natural gas of $3 per MMBtu, consistent with forward pricing during the company’s budget process. The vast majority of cash KMI generates is fee-based and therefore not directly exposed to commodity prices. The primary area where KMI has commodity price sensitivity is in its CO2 segment, with the majority of the segment’s next 12 months of oil and NGL production hedged to minimize this sensitivity. The segment is currently hedged for 35,969 barrels per day (Bbl/d) at $58.71 per barrel for the remainder of the year, as well as 18,427 Bbl/d at $62.80/Bbl in 2018; 11,000 Bbl/d at $56.13/Bbl in 2019; 6,000 Bbl/d at $53.35/Bbl in 2020; and, 1,200 Bbl/d at $52.46/Bbl in 2021. For 2017, the company estimates that every $1 per barrel change in the average WTI crude oil price impacts distributable cash flow by approximately $6 million and each $0.10 per MMBtu change in the price of natural gas impacts distributable cash flow by approximately $1 million.
Overview of Business Segments
“The Natural Gas Pipelines segment’s performance for the first quarter of 2017 was impacted by the third quarter 2016 sale of a 50 percent interest in SNG, declines attributable to reduced volumes affecting certain of our midstream gathering and processing assets, and a negative impact on our Colorado Interstate Gas Company (CIG) pipeline tariff rates as a result of a rate case settlement reached during 2016. The segment benefited from increased contributions from the Elba Express pipeline, which resulted from the substantial completion of an expansion project in the fourth quarter of 2016, and improved results from Natural Gas Pipeline Company of America (NGPL) as a result of several favorable factors including the completion of an expansion project to increase service to the Chicago area,” Kean said.
Natural gas transport volumes were up 1 percent compared to the first quarter of 2016, driven by higher throughput on the Tennessee Gas Pipeline (TGP) due to projects placed in
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service, higher throughput on NGPL due to deliveries to the Sabine Pass LNG facility and to South Texas to meet continuing demand from Mexico, higher throughput on the Texas Intrastate Natural Gas Pipelines due to contracts going into effect after the first quarter of 2016, and higher throughput on El Paso Natural Gas Pipeline due to colder weather in California. The increases were partially offset by lower throughput on the TransColorado pipeline due to lower Rockies production, as well as lower throughput on Cheyenne Plains due to fuel switching back to coal and on SNG due to a historically warm winter in the region. Natural gas gathered volumes were down 15 percent from the first quarter of 2016 due primarily to lower natural gas volumes on multiple systems gathering from the Eagle Ford Shale and on the KinderHawk system.
Natural gas continues to be the fuel of choice for America and the world’s evolving energy needs, and industry experts are projecting U.S. natural gas demand, including net exports of liquefied natural gas (LNG) and net exports to Mexico, to increase by approximately 35 percent to almost 107 billion cubic feet per day (Bcf/d) over the next 10 years. Of the natural gas consumed in the U.S., about 40 percent moves on KMI pipelines. KMI expects future natural gas infrastructure opportunities will be driven by greater demand for gas-fired power generation across the country, LNG exports, exports to Mexico, and continued industrial development, particularly in the petrochemical industry. In fact, compared to the first quarter of 2016, natural gas deliveries on KMI pipelines to Mexico were up 16 percent, increasing by approximately 391,000 dekatherms per day (Dth/d), and deliveries to LNG facilities increased by approximately 548,000 Dth/d.
“The CO2 segment was impacted by slightly lower commodity prices, as our realized weighted average oil price for the quarter was $58.14 per barrel compared to $59.55 per barrel for the first quarter of 2016,” Kean said. “Combined oil production across all of our fields was down 5 percent compared to 2016 on a net to Kinder Morgan basis, partially driven by project deferrals at SACROC and Yates as well as reallocating capital to higher return projects with longer lead times. First quarter 2017 net NGL sales volumes of 10.2 thousand barrels per day (MBbl/d) were up 3 percent from 2016. Net CO2 volumes increased 12 percent versus the first quarter of 2016 driven by strong demand from third parties, working interest partners and our own operations.” Southwest Colorado facilities produced record volumes of 1.339 Bcf/d and the Cortez Pipeline experienced record throughput volume of 1.314 Bcf/d for the quarter.
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Combined gross oil production volumes averaged 53.5 MBbl/d for the first quarter, down 4 percent from 56.0 MBbl/d for the same period last year. SACROC’s first quarter gross production was 7 percent below first quarter 2016 results but slightly above 2017 budget, and Yates gross production was 6 percent below first quarter 2016 results but 1 percent below plan. Both decreases were partially driven by project deferrals during 2016 as well as reallocating capital to higher return projects with longer lead times. First quarter gross production from Katz, Goldsmith and Tall Cotton was 7 percent above the same period in 2016, but below plan. Gross NGL sales volumes were 20.4 MBbl/d during the quarter, slightly ahead of first quarter 2016.
“The Terminals segment experienced strong performance at our liquids terminals that account for close to 80 percent of the segment’s business. Growth in the liquids business during the quarter versus the first quarter of 2016 was driven by increased contributions from our Jones Act tankers and various expansions across our network, including the recently commissioned Kinder Morgan Export Terminal, a 1.5 million barrel liquids terminal development along the Houston Ship Channel,” Kean said. The Magnolia State, Garden State, Bay State and American Endurance tankers were delivered in May 2016, July 2016, September 2016 and December 2016, respectively. The American Freedom tanker was delivered in March 2017 and placed on-hire in early April 2017, following final outfitting and a voyage to the U.S. Gulf Coast. All of these tankers are contracted with major energy customers under long-term charters.
The bulk terminals contribution was supported by improving volumes at our coal and steel handling operations as global market conditions for those commodities continue to improve.
“The Products Pipelines segment was largely in line with first quarter 2016 performance,” Kean said.
Total refined products volumes were up 1 percent for the first quarter versus the same period in 2016. NGL volumes were up 2 percent from the same period last year due to greater volumes on Cochin and Cypress pipelines. Crude and condensate pipeline volumes were up 1 percent from the first quarter of 2016, with strong performance by Kinder Morgan Crude and Condensate Pipeline.
Kinder Morgan Canada contributions were down 7 percent in the first quarter of 2017 compared to the first quarter of 2016 largely due to operating expense timing changes and a 17
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percent decrease in volumes to Washington state, caused by narrowing price differentials with competing sources.
Other News
Natural Gas Pipelines
| • | On Feb. 28, 2017, KMI announced that investment funds managed by EIG Global Energy Partners (EIG) became a 49 percent joint venture participant in Elba Liquefaction Company, L.L.C. (ELC). ELC will own 10 liquefaction units and other ancillary equipment comprising approximately 70 percent of the nearly $2 billion Elba Island Liquefaction Project under construction at KMI’s existing Southern LNG Company facility near Savannah, Georgia. To acquire its membership interest, EIG made a cash payment of approximately $385 million, consisting of: a $215 million reimbursement to KMI for EIG’s 49 percent share of prior ELC capital expenditures, excluding capitalized interest; and a payment of approximately $170 million excess of capital expenditures in consideration of the value created by KMI in developing the project to this stage. The liquefaction project is supported by a 20-year contract with Shell. Initial in-service is expected in mid-2018. Final units coming on line by early 2019 will bring total liquefaction capacity to approximately 2.5 million tonnes per year of LNG, equivalent to approximately 350 million cubic feet per day of natural gas. |
| • | On Feb. 3, 2017, Southern Natural Gas Company, L.L.C. (SNG), a joint venture equally owned by subsidiaries of KMI and Southern Company, filed an application with the Federal Energy Regulatory Commission (FERC) for the Fairburn Expansion Project in Georgia. The $240 million project is designed to provide approximately 340,000 Dth/d of incremental long-term firm natural gas transportation capacity into the Southeast market, and includes the construction of a new compressor station, 6.5 miles of new pipeline and pipeline loop, new meter stations and other upgrades on the current SNG system, as well as acquisition of certain assets from Southern Company. |
| • | Work continues on the approximately $285 million EEC Modification and SNG Zone 3 Expansion Projects, which are supported by long-term customer contracts. Two phases representing greater than 70 percent of the approximately 853,000 Dth/d incremental capacity are now in service. The SNG Zone 3 Project will be completed later this year, and additional compression is planned to be added in 2018 to complete the EEC Modification Project. |
| • | On Feb. 27, 2017, TGP received FERC Notice to Proceed (NTP) on Station 875, a new compressor station in Kentucky, for the planned Broad Run Expansion Project. All FERC approvals have been received with the exception of NTP on Station 563 near Nashville, Tennessee. A limited number of state and local permits in Tennessee and Kentucky are pending. The project, which is expected to be placed in service in June 2018, will provide an incremental 200,000 Dth/d of firm transportation capacity along the same capacity path as the Broad Run Flexibility Project, which was placed in service in late 2015. Antero Resources was awarded a total of 790,000 Dth/d of 15-year firm capacity under the two projects from a receipt point on TGP’s existing Broad Run Lateral in West Virginia to |
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delivery points in Mississippi and Louisiana. Estimated capital expenditures for the combined projects total approximately $800 million.
| • | Following receipt of required FERC approvals, construction is now underway on five other TGP projects with in-service dates in 2017 and 2018: |
| – | The approximately $179 million Southwest Louisiana Supply Project, which received FERC NTP during the first quarter of 2017, will provide 900,000 Dth/d of capacity to the Cameron LNG export facility in Cameron Parish, Louisiana. In-service is planned in the first quarter of 2018. |
| – | The approximately $156 million Susquehanna West Project, which received FERC NTP on Jan. 4, 2017, will provide 145,000 Dth/d of capacity for one customer. In-service is planned in November 2017. |
| – | The approximately $142 million Orion Project, which received its FERC Certificate on Feb. 2, 2017, and NTP on March 15, 2017, will provide 135,000 Dth/d of capacity for three customers. In-service is planned in June 2018. |
| – | The approximately $67 million Triad Project, which received FERC NTP on Feb. 15, 2017, will provide 180,000 Dth/d of capacity for one customer. In-service is planned in June 2018. |
| – | The approximately $93 million Connecticut Expansion Project, which received FERC full construction NTP on April 12, 2017, will provide 72,100 Dth/d of capacity for three local distribution company customers. In-service is planned in November 2017. |
| • | On March 22, 2017, KMI announced a non-binding open season for the Gulf Coast Express Pipeline Project that closes April 20, 2017, and subsequently announced that DCP Midstream, LP, signed a letter of intent regarding their expected participation in the development of the project as a partner and shipper. The proposed pipeline would transport up to 1.7 Bcf/d of natural gas from Waha to Agua Dulce, Texas, providing an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. The 42-inch pipeline would traverse approximately 430 miles and be in service in the second half of 2019, pending shipper commitments. |
| • | On Jan. 19, 2017, KMI was notified by FERC of separate rate proceedings involving NGPL and WIC pursuant to Section 5 of the Natural Gas Act. The companies are actively defending their rates and fully expect the evidence to show that the rates charged by NGPL and WIC have been and continue to be just and reasonable. KMI does not believe that the ultimate resolution of these proceedings will have a material adverse impact on results of operations or cash flows from operations. |
CO2
| • | Drilling operations and construction of field facilities continue on the approximately $66 million second phase of KMI’s Tall Cotton field project in Gaines County, Texas. Tall Cotton is the industry’s first greenfield Residual Oil Zone CO2 project, marking the first time CO2 has been used for enhanced oil recovery in a field without a main pay zone. KMI continues to expect first oil production from the second phase of the project to occur in the second quarter of 2017. |
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| • | The company continues to find high-return enhanced oil recovery projects in the current price environment across its robust portfolio of assets. |
Terminals
| • | Construction continues at KMI and Keyera’s Base Line Terminal, a 50-50 joint venture crude oil merchant storage terminal being developed in Edmonton, Alberta, Canada. The 12-tank, 4.8 million barrel new-build facility is fully contracted with long-term, firm take-or-pay agreements with strong, creditworthy customers. KMI’s investment in the joint venture terminal is approximately CAD$374 million. Commissioning is expected to begin in the first quarter of 2018 with tanks phased into service throughout that year. |
| • | Work is substantially complete at the Kinder Morgan Export Terminal (KMET) along the Houston Ship Channel. The approximately $246 million project, supported by a long-term contract with a major ship channel refiner, includes 12 storage tanks with 1.5 million barrels of storage capacity, one ship dock, one barge dock and cross-channel pipelines to connect with KMI’s Galena Park terminal. Storage tanks at KMET were placed into service in January 2017 followed by the terminal’s full marine capabilities, which were commissioned at the end of March 2017. |
| • | Work continues on the previously announced Pit 11 expansion project at KMI’s Pasadena terminal. The approximately $185 million project, back-stopped by long-term commitments from existing customers, adds 2.0 million barrels of refined products storage to KMI’s best-in-class liquids storage hub along the Houston Ship Channel. The first four tanks are expected to be placed in service in the third quarter of 2017 with the balance following in the fourth quarter of 2017. |
| • | On March 25, 2017, KMI’s American Petroleum Tankers (APT) took delivery of the American Freedom from Philly Shipyard, Inc. (PSI) in Philadelphia, Pennsylvania, bringing APT’s fleet size to 13 tankers. The final two vessels under construction at PSI are scheduled for delivery in the third and fourth quarters of 2017, while delivery of the final vessel contracted from General Dynamics’ NASSCO shipyard in San Diego, California, is scheduled for June 2017. The construction programs at both PSI and NASSCO, which added nine ECO class vessels to APT’s best-in-class fleet, remain on time and on budget. Each of the 330,000-barrel capacity and LNG conversion-ready tankers is fixed under charter with a major energy company. |
Products Pipelines
| • | KMI remains on schedule to begin operations for the approximately $540 million Utopia Pipeline Project in January 2018. Pipeline construction started in April 2017, and commissioning of the pipeline is anticipated in the fourth quarter of 2017. The Utopia Pipeline will have an initial design capacity of 50,000 barrels per day, and will move ethane from Ohio to Windsor, Ontario, Canada. The project is fully supported by a long-term, fee-based transportation agreement with a petrochemical customer. |
Kinder Morgan Canada
| • | Since receiving Government of Canada approval in 2016, Kinder Morgan Canada has been moving forward with the regulatory, commercial and construction planning aspects of the |
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Trans Mountain Expansion Project, achieving significant positive progress. Next steps for the project include arranging acceptable financing and a final investment decision by KMI’s board of directors. Construction is set to begin in the fall of 2017, and the project is expecting an in-service date of late 2019. In the first quarter, the project successfully completed a final cost review with its shippers and a supplemental open season. All available long-term firm service capacity remains contracted on the pipeline with a diverse group of 13 customers. The conclusion of these steps demonstrates continued strong market support for the project and the much-needed access to new markets it will bring to Canadian producers, as well as providing a secure supply of Canadian crude to refineries throughout the Pacific basin. Collectively, the firm shippers have made 15- and 20-year commitments of 707,500 barrels per day, or roughly 80 percent of the capacity on the expanded pipeline, with the remaining 20 percent reserved for spot volumes as required by the National Energy Board. Aboriginal support for the project continues to grow, with 51 Aboriginal communities in support of the project.
Kinder Morgan, Inc. (NYSE: KMI) is one of the largest energy infrastructure companies in North America. It owns an interest in or operates approximately 84,000 miles of pipelines and 155 terminals. KMI’s pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and its terminals transload and store petroleum products, ethanol and chemicals, and handle such products as steel, coal and petroleum coke. It is also a leading producer of CO2 that we and others use for enhanced oil recovery projects primarily in the Permian basin. For more information please visit www.kindermorgan.com.
Please join Kinder Morgan, Inc. at 4:30 p.m. Eastern Time on Wednesday, April 19, at
www.kindermorgan.com for a LIVE webcast conference call on the company’s first quarter earnings.
Non-GAAP Financial Measures
The non-generally accepted accounting principles (non-GAAP) financial measures of distributable cash flow (DCF), both in the aggregate and per share, segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments (DD&A) and Certain Items (Segment EBDA before Certain Items), net income before interest expense, taxes, DD&A and Certain Items (Adjusted EBITDA), Adjusted Earnings and Adjusted Earnings per share are presented herein.
Certain Items are items that are required by GAAP to be reflected in net income, but typically either (1) do not have a cash impact (for example, asset impairments), or (2) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example certain legal settlements, hurricane impacts and casualty losses).
DCF is a significant performance measure used by us and by external users of our financial statements to evaluate our performance and to measure and estimate the ability of our assets to generate cash earnings after servicing our debt and preferred stock dividends, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as common stock dividends, stock repurchases, retirement of debt, or expansion capital expenditures. Management
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uses this measure and believes it provides users of our financial statements a useful measure reflective of our business’s ability to generate cash earnings to supplement the comparable GAAP measure. We believe the GAAP measure most directly comparable to DCF is net income available to common stockholders. A reconciliation of net income available to common stockholders to DCF is provided herein. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends.
Segment EBDA before Certain Items is used by management in its analysis of segment performance and management of our business. General and administrative expenses are generally not under the control of our segment operating managers, and therefore, are not included when we measure business segment operating performance. We believe Segment EBDA before Certain Items is a significant performance metric because it provides us and external users of our financial statements additional insight into the ability of our segments to generate segment cash earnings on an ongoing basis. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable to Segment EBDA before Certain Items is segment earnings before DD&A and amortization of excess cost of equity investments (Segment EBDA). Segment EBDA before Certain Items is calculated by adjusting Segment EBDA for the Certain Items attributable to a segment, which are specifically identified in the footnotes to the accompanying tables.
Adjusted EBITDA is used by management and external users, in conjunction with our net debt, to evaluate certain leverage metrics. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is net income. Adjusted EBITDA is calculated by adjusting net income before interest expense, taxes, and DD&A (EBITDA) for Certain Items, noncontrolling interests before Certain Items, and KMI’s share of certain equity investees’ DD&A and book taxes, which are specifically identified in the footnotes to the accompanying tables.
Adjusted Earnings is used by certain external users of our financial statements to assess the earnings of our business excluding Certain Items as another reflection of our business’s ability to generate earnings. We believe the GAAP measure most directly comparable to Adjusted Earnings is net income available to common stockholders. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at diluted earnings per common share.
Our non-GAAP measures described above should not be considered alternatives to GAAP net income or other GAAP measures and have important limitations as analytical tools. Our computations of DCF, Segment EBDA before Certain Items and Adjusted EBITDA may differ from similarly titled measures used by others. You should not consider these non-GAAP measures in isolation or as substitutes for an analysis of our results as reported under GAAP. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. Management compensates for the limitations of these non-GAAP measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.
Important Information Relating to Forward-Looking Statements
This news release includes forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities and Exchange Act of 1934. Generally the words “expects,” “believes,” anticipates,” “plans,” “will,” “shall,” “estimates,” and similar expressions identify forward-looking statements, which are generally not historical in nature. Forward-looking statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management, based on information currently available to them. Although KMI believes that these forward-looking statements are based on
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reasonable assumptions, it can give no assurance that any such forward-looking statements will materialize. Important factors that could cause actual results to differ materially from those expressed in or implied from these forward-looking statements include the risks and uncertainties described in KMI’s reports filed with the Securities and Exchange Commission (SEC), including its Annual Report on Form 10-K for the year-ended December 31, 2016 (under the headings “Risk Factors” and “Information Regarding Forward-Looking Statements” and elsewhere) and its subsequent reports, which are available through the SEC’s EDGAR system at www.sec.gov and on our website at ir.kindermorgan.com. Forward-looking statements speak only as of the date they were made, and except to the extent required by law, KMI undertakes no obligation to update any forward-looking statement because of new information, future events or other factors. Because of these risks and uncertainties, readers should not place undue reliance on these forward-looking statements.
| CONTACTS | ||
| Dave Conover | Investor Relations | |
| Media Relations | (713) 369-9490 | |
| (713) 369-9407 | km_ir@kindermorgan.com | |
| dave_conover@kindermorgan.com | www.kindermorgan.com | |
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Kinder Morgan, Inc. and Subsidiaries Preliminary Consolidated Statements of Income (Unaudited) (In millions, except per share amounts) | ||||||||||
| Three Months Ended March 31, | ||||||||||
| 2017 | 2016 | |||||||||
| Revenues | $ | 3,424 | $ | 3,195 | ||||||
| Costs, expenses and other | ||||||||||
| Costs of sales | 1,081 | 731 | ||||||||
| Operations and maintenance | 513 | 565 | ||||||||
| Depreciation, depletion and amortization | 558 | 551 | ||||||||
| General and administrative | 181 | 190 | ||||||||
| Taxes, other than income taxes | 104 | 108 | ||||||||
| Loss on impairments and divestitures, net | 6 | 235 | ||||||||
| Other expense (income), net | 1 | (1 | ) | |||||||
| 2,444 | 2,379 | |||||||||
| Operating income | 980 | 816 | ||||||||
| Other income (expense) | ||||||||||
| Earnings from equity investments | 175 | 100 | ||||||||
| Loss on impairments and divestitures of equity investments, net | — | (6 | ) | |||||||
| Amortization of excess cost of equity investments | (15 | ) | (14 | ) | ||||||
| Interest, net | (465 | ) | (441 | ) | ||||||
| Other, net | 16 | 13 | ||||||||
| Income before income taxes | 691 | 468 | ||||||||
| Income tax expense | (246 | ) | (154 | ) | ||||||
| Net income | 445 | 314 | ||||||||
| Net (income) loss attributable to noncontrolling interests | (5 | ) | 1 | |||||||
| Net income attributable to Kinder Morgan, Inc. | 440 | 315 | ||||||||
| Preferred stock dividends | (39 | ) | (39 | ) | ||||||
| Net income available to common stockholders | $ | 401 | $ | 276 | ||||||
| Class P Shares | ||||||||||
| Basic and diluted earnings per common share | $ | 0.18 | $ | 0.12 | ||||||
| Basic weighted average common shares outstanding | 2,230 | 2,229 | ||||||||
| Diluted weighted average common shares outstanding | 2,230 | 2,229 | ||||||||
| Declared dividend per common share | $ | 0.125 | $ | 0.125 | ||||||
| Adjusted earnings per common share (1) | $ | 0.17 | $ | 0.18 | ||||||
| Segment EBDA | % change | |||||||||
| Natural Gas Pipelines | $ | 1,055 | $ | 994 | 6 | % | ||||
CO2 | 218 | 187 | 17 | % | ||||||
| Terminals | 307 | 260 | 18 | % | ||||||
| Products Pipelines | 287 | 177 | 62 | % | ||||||
| Kinder Morgan Canada | 43 | 46 | (7 | )% | ||||||
| Total Segment EBDA | $ | 1,910 | $ | 1,664 | 15 | % | ||||
| (1) | Adjusted earnings per common share uses adjusted earnings and applies the same two-class method used in arriving at diluted earnings per common share. See the following page, Preliminary Earnings Contribution by Business Segment, for a reconciliation of net income available to common stockholders to adjusted earnings. |
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Kinder Morgan, Inc. and Subsidiaries Preliminary Earnings Contribution by Business Segment (Unaudited) (In millions, except per share amounts) | ||||||||||
| Three Months Ended March 31, | ||||||||||
| 2017 | 2016 | % change | ||||||||
| Segment EBDA before certain items (1) | ||||||||||
| Natural Gas Pipelines | $ | 1,019 | $ | 1,132 | (10 | )% | ||||
CO2 | 222 | 224 | (1 | )% | ||||||
| Terminals | 302 | 276 | 9 | % | ||||||
| Product Pipelines | 287 | 285 | 1 | % | ||||||
| Kinder Morgan Canada | 43 | 46 | (7 | )% | ||||||
| Subtotal | 1,873 | 1,963 | (5 | )% | ||||||
| DD&A and amortization of excess investments | (573 | ) | (565 | ) | ||||||
| General and administrative and corporate charges (1) (2) | (174 | ) | (185 | ) | ||||||
| Interest, net (1) | (477 | ) | (510 | ) | ||||||
| Subtotal | 649 | 703 | ||||||||
| Book taxes (1) | (234 | ) | (257 | ) | ||||||
| Certain items | ||||||||||
| Acquisition related costs (3) | (4 | ) | (3 | ) | ||||||
| Pension plan net benefit | — | 1 | ||||||||
| Fair value amortization | 17 | 24 | ||||||||
| Contract early termination earnings (4) | 22 | — | ||||||||
| Legal and environmental reserves (5) | (2 | ) | (35 | ) | ||||||
| Change in fair market value of derivative contracts (6) | 6 | 30 | ||||||||
| Losses on impairments and divestitures, net | (5 | ) | (85 | ) | ||||||
| Project write-offs (7) | — | (170 | ) | |||||||
| Other | 8 | 3 | ||||||||
| Subtotal certain items before tax | 42 | (235 | ) | |||||||
| Book tax certain items | (12 | ) | 103 | |||||||
| Total certain items | 30 | (132 | ) | |||||||
| Net income | 445 | 314 | ||||||||
| Net (income) loss attributable to noncontrolling interests | (5 | ) | 1 | |||||||
| Preferred stock dividends | (39 | ) | (39 | ) | ||||||
| Net income available to common stockholders | $ | 401 | $ | 276 | ||||||
| Net income available to common stockholders | $ | 401 | $ | 276 | ||||||
| Total certain items | (30 | ) | 132 | |||||||
| Noncontrolling interests certain item (8) | — | (6 | ) | |||||||
| Adjusted earnings | 371 | 402 | ||||||||
| DD&A and amortization of excess investments (9) | 671 | 652 | ||||||||
| Total book taxes (10) | 261 | 279 | ||||||||
| Cash taxes (11) | 3 | (2 | ) | |||||||
| Other items (12) | 13 | 10 | ||||||||
| Sustaining capital expenditures (13) | (104 | ) | (108 | ) | ||||||
| DCF | $ | 1,215 | $ | 1,233 | ||||||
| Weighted average common shares outstanding for dividends (14) | 2,239 | 2,237 | ||||||||
| DCF per common share | $ | 0.54 | $ | 0.55 | ||||||
| Declared dividend per common share | $ | 0.125 | $ | 0.125 | ||||||
| Adjusted EBITDA (15) | $ | 1,820 | $ | 1,883 | ||||||
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| Notes ($ million) | ||||||||||||||||||
| (1) | Excludes certain items: 1Q 2017 - Natural Gas Pipelines $36, CO2 $(4), Terminals $5, general and administrative and corporate charges $(7), interest expense $12, book tax $(12). 1Q 2016 - Natural Gas Pipelines $(138), CO2 $(37), Terminals $(16), Products Pipelines $(108), general and administrative and corporate charges $(5), interest expense $69, book tax $103. | |||||||||||||||||
| (2) | Includes corporate charges: 1Q 2017 - $9 1Q 2016 - $8 General and administrative expense is also net of management fee revenues from an equity investee: 1Q 2017 - $(9) 1Q 2016 - $(8) | |||||||||||||||||
| (3) | Acquisition related costs for closed or pending acquisitions. | |||||||||||||||||
| (4) | Comprised of income recognized related to the early termination of customer contracts, including income from the sale of a contract termination claim related to a customer bankruptcy. | |||||||||||||||||
| (5) | Legal reserve adjustments related to certain litigation and environmental matters. | |||||||||||||||||
| (6) | Gains or losses in our DCF are reflected when realized. | |||||||||||||||||
| (7) | Includes the following project write-offs: 1Q 2016 includes $106 million of project write-offs associated with our Northeast Energy Direct Market project and $64 million of write-offs associated with our Palmetto project. | |||||||||||||||||
| (8) | Represents noncontrolling interest share of certain items. | |||||||||||||||||
| (9) | Includes KMI's share of certain equity investees' DD&A: 1Q 2017 - $98 1Q 2016 - $87 | |||||||||||||||||
| (10) | Excludes book tax certain items. Also, includes KMI's share of taxable equity investees' book tax expense: 1Q 2017 - $27 1Q 2016 - $22 | |||||||||||||||||
| (11) | Includes KMI's share of taxable equity investees' cash taxes: 1Q 2016 - $(4) | |||||||||||||||||
| (12) | Consists primarily of non-cash compensation associated with our restricted stock program. | |||||||||||||||||
| (13) | Includes KMI's share of certain equity investees' sustaining capital expenditures (the same equity investees for which DD&A is added back): 1Q 2017 - $(18) 1Q 2016 - $(22) | |||||||||||||||||
| (14) | Includes restricted stock awards that participate in common share dividends. | |||||||||||||||||
| (15) | Adjusted EBITDA is net income before certain items, less net income attributable to noncontrolling interests before certain items, plus DD&A (including KMI's share of certain equity investees' DD&A), book taxes (including KMI’s share of equity investees’ book tax), and interest expense (before certain items). Adjusted EBITDA is reconciled as follows, with any difference due to rounding: | |||||||||||||||||
| Three Months Ended March 31, | ||||||||
| 2017 | 2016 | |||||||
| Net income | $ | 445 | $ | 314 | ||||
| Total certain items | (30 | ) | 132 | |||||
| Net income attributable to noncontrolling interests before certain items | (5 | ) | (5 | ) | ||||
| DD&A and amortization of excess investments (see (9) above) | 671 | 652 | ||||||
| Book taxes (see (10) above) | 262 | 279 | ||||||
| Interest, net (see (1) above) | 477 | 511 | ||||||
| Adjusted EBITDA | $ | 1,820 | $ | 1,883 | ||||
14
Volume Highlights (historical pro forma for acquired assets) | |||||||
| Three Months Ended March 31, | |||||||
| 2017 | 2016 | ||||||
| Natural Gas Pipelines | |||||||
| Transport Volumes (BBtu/d) (1) (2) | 29,326 | 28,928 | |||||
| Sales Volumes (BBtu/d) (3) | 2,563 | 2,331 | |||||
| Gas Gathering Volumes (BBtu/d) (2) (4) | 2,712 | 3,207 | |||||
| Crude/Condensate Gathering Volumes (MBbl/d) (2) (5) | 272 | 332 | |||||
CO2 | |||||||
| Southwest Colorado Production - Gross (Bcf/d) (6) | 1.34 | 1.18 | |||||
| Southwest Colorado Production - Net (Bcf/d) (6) | 0.66 | 0.59 | |||||
| Sacroc Oil Production - Gross (MBbl/d) (7) | 28.30 | 30.54 | |||||
| Sacroc Oil Production - Net (MBbl/d) (8) | 23.58 | 25.44 | |||||
| Yates Oil Production - Gross (MBbl/d) (7) | 17.87 | 19.03 | |||||
| Yates Oil Production - Net (MBbl/d) (8) | 8.00 | 8.47 | |||||
| Katz, Goldsmith, and Tall Cotton Oil Production - Gross (MBbl/d) (7) | 7.29 | 6.83 | |||||
| Katz, Goldsmith, and Tall Cotton Oil Production - Net (MBbl/d) (8) | 6.18 | 5.77 | |||||
| NGL Sales Volumes (MBbl/d) (9) | 10.16 | 9.90 | |||||
| Realized Weighted Average Oil Price per Bbl (10) | $ | 58.14 | $ | 59.55 | |||
| Realized Weighted Average NGL Price per Bbl | $ | 24.50 | $ | 13.32 | |||
| Terminals | |||||||
| Liquids Leasable Capacity (MMBbl) | 88.0 | 86.1 | |||||
| Liquids Utilization % | 95.3 | % | 94.8 | % | |||
| Bulk Transload Tonnage (MMtons) (11) | 14.5 | 12.3 | |||||
| Ethanol (MMBbl) | 17.7 | 15.3 | |||||
| Products Pipelines | |||||||
| Pacific, Calnev, and CFPL (MMBbl) | |||||||
| Gasoline (12) | 69.1 | 68.0 | |||||
| Diesel | 24.6 | 24.8 | |||||
| Jet Fuel | 22.6 | 22.1 | |||||
| Sub-Total Refined Product Volumes - excl. Plantation | 116.3 | 114.9 | |||||
| Plantation (MMBbl) (13) | |||||||
| Gasoline | 20.3 | 20.7 | |||||
| Diesel | 4.4 | 4.7 | |||||
| Jet Fuel | 3.1 | 3.0 | |||||
| Sub-Total Refined Product Volumes - Plantation | 27.8 | 28.4 | |||||
| Total (MMBbl) | |||||||
| Gasoline (12) | 89.4 | 88.7 | |||||
| Diesel | 29.0 | 29.5 | |||||
| Jet Fuel | 25.7 | 25.1 | |||||
| Total Refined Product Volumes | 144.1 | 143.3 | |||||
| NGLs (MMBbl) (14) | 9.6 | 9.4 | |||||
| Crude and Condensate (MMBbl) (15) | 31.3 | 30.9 | |||||
| Total Delivery Volumes (MMBbl) | 185.0 | 183.6 | |||||
| Ethanol (MMBbl) (16) | 9.9 | 10.1 | |||||
| Trans Mountain (MMBbls - mainline throughput) | 27.6 | 28.6 | |||||
15
| (1) | Includes Texas Intrastates, Copano South Texas, KMNTP, Monterrey, TransColorado, MEP, KMLA, FEP, TGP, EPNG, CIG, WIC, Cheyenne Plains, SNG, Elba Express, Ruby, Sierrita, NGPL, and Citrus pipeline volumes. Joint Venture throughput reported at KMI share. | |||||||
| (2) | Volumes for acquired pipelines are included for all periods. | |||||||
| (3) | Includes Texas Intrastates and KMNTP. | |||||||
| (4) | Includes Copano Oklahoma, Copano South Texas, Eagle Ford Gathering, Copano, North Texas, Altamont, KinderHawk, Camino Real, Endeavor, Bighorn, Webb/Duval Gatherers, Fort Union, EagleHawk, Red Cedar, and Hiland Midstream throughput. Joint Venture throughput reported at KMI share. | |||||||
| (5) | Includes Hiland Midstream, EagleHawk, and Camino Real. Joint Venture throughput reported at KMI share. | |||||||
| (6) | Includes McElmo Dome and Doe Canyon sales volumes. | |||||||
| (7) | Represents 100% production from the field. | |||||||
| (8) | Represents KMI's net share of the production from the field. | |||||||
| (9) | Net to KMI. | |||||||
| (10) | Includes all KMI crude oil properties. | |||||||
| (11) | Includes KMI's share of Joint Venture tonnage. | |||||||
| (12) | Gasoline volumes include ethanol pipeline volumes. | |||||||
| (13) | Plantation reported at KMI share. | |||||||
| (14) | Includes Cochin and Cypress (KMI share). | |||||||
| (15) | Includes KMCC, Double Eagle (KMI share), and Double H. | |||||||
| (16) | Total ethanol handled including pipeline volumes included in gasoline volumes above. | |||||||
16
Kinder Morgan, Inc. and Subsidiaries Preliminary Consolidated Balance Sheets (Unaudited) (In millions) | |||||||
| March 31, | December 31, | ||||||
| 2017 | 2016 | ||||||
| ASSETS | |||||||
| Cash and cash equivalents | $ | 396 | $ | 684 | |||
| Other current assets | 2,279 | 2,545 | |||||
| Property, plant and equipment, net | 39,023 | 38,705 | |||||
| Investments | 7,136 | 7,027 | |||||
| Goodwill | 22,154 | 22,152 | |||||
| Deferred charges and other assets | 8,805 | 9,192 | |||||
| TOTAL ASSETS | $ | 79,793 | $ | 80,305 | |||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | |||||||
| Liabilities | |||||||
| Short-term debt | $ | 3,928 | $ | 2,696 | |||
| Other current liabilities | 2,761 | 3,228 | |||||
| Long-term debt | 34,285 | 36,105 | |||||
| Preferred interest in general partner of KMP | 100 | 100 | |||||
| Debt fair value adjustments | 1,079 | 1,149 | |||||
| Other | 2,635 | 2,225 | |||||
| Total liabilities | 44,788 | 45,503 | |||||
| Shareholders’ Equity | |||||||
| Other shareholders’ equity | 35,238 | 35,092 | |||||
| Accumulated other comprehensive loss | (593 | ) | (661 | ) | |||
| Total KMI equity | 34,645 | 34,431 | |||||
| Noncontrolling interests | 360 | 371 | |||||
| Total shareholders’ equity | 35,005 | 34,802 | |||||
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 79,793 | $ | 80,305 | |||
| Net Debt (1) | $ | 37,843 | $ | 38,160 | |||
| Adjusted EBITDA Twelve Months Ended | |||||||
| March 31, | December 31, | ||||||
| Reconciliation of Net Income to Adjusted EBITDA (2) | 2017 | 2016 | |||||
| Net income | $ | 852 | $ | 721 | |||
| Total certain items | 770 | 933 | |||||
| Net income attributable to noncontrolling interests before certain items | (21 | ) | (21 | ) | |||
| DD&A and amortization of excess investments | 2,635 | 2,617 | |||||
| Book taxes | 976 | 993 | |||||
| Interest, net | 1,969 | 2,002 | |||||
| Adjusted EBITDA | $ | 7,181 | $ | 7,245 | |||
| Net Debt to Adjusted EBITDA | 5.3 | 5.3 | |||||
| Notes | ||||
| (1) | Amounts exclude: (i) the preferred interest in general partner of KMP, (ii) debt fair value adjustments and (iii) the foreign exchange impact on our Euro denominated debt of $(26) million and $(43) million as of March 31, 2017 and December 31, 2016, respectively, as we have entered into swaps to convert that debt to US$. | |||
| (2) | Adjusted EBITDA is net income before certain items, less net income attributable to noncontrolling interests before certain items, plus DD&A (including KMI's share of certain equity investees' DD&A), book taxes (including KMI’s share of certain equity investees’ book tax), and interest expense (before certain items), with any difference due to rounding. | |||
17