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Kinder Morgan Declares Dividend of $0.125 for Third Quarter 2016

Mittwoch, 19.10.2016 22:05



HOUSTON --(BUSINESS WIRE)--

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 Nov. 15, 2016, to common shareholders of record as of the close of business on Nov. 1, 2016. KMI expects to declare dividends of $0.50 per share for 2016 and use cash in excess of dividend payments to fund growth investments and strengthen its balance sheet.

KMI continues to make significant progress toward enhancing its credit profile. On Sept. 1, 2016, KMI closed the previously announced agreement to partner with Southern Company through the sale of a 50 percent interest in the Southern Natural Gas (SNG) pipeline system for cash consideration of over $1.4 billion plus Southern Company’s share of SNG’s debt. KMI used the entire amount of cash proceeds to reduce its net debt. As of the end of the third quarter, $749 million was held in escrow to redeem debt and was not included in net debt reduction during the quarter. The debt was redeemed on Oct. 1, 2016, and will result in further net debt reduction in the fourth quarter of 2016.

“During the quarter, we substantially reduced our debt, further positioning Kinder Morgan for long-term value creation. We are ahead of our plan for 2016 year-end leverage and we’re pleased with the progress toward reaching our targeted leverage level of around 5.0 times net debt-to-Adjusted EBITDA,” said Richard D. Kinder, executive chairman. “This will position us to return substantial value to shareholders through some combination of dividend increases, share repurchases, additional attractive growth projects or further debt reduction.

“Additionally, we are pleased with our operational performance for the quarter despite continued weak market conditions in our industry. Our performance, adjusted for the SNG transaction, remains consistent with our guidance provided since April. We remain on track to generate full year 2016 distributable cash flow in excess of our expected dividends and our expected growth capital expenditures, eliminating our need to access the capital markets to fund growth projects in 2016. Moreover, given our continued efforts to high-grade our backlog, we do not expect to need to access the capital markets to fund our growth projects for the foreseeable future beyond 2016.”

President and CEO Steve Kean said, “We had a good third quarter and once again, we demonstrated the resiliency of our cash flows, generated by a large, diversified portfolio of predominately fee-based assets. We generated a loss per common share for the quarter of $0.10, primarily as a result of non-cash charges discussed below. That said, we produced distributable cash flow of $0.48 per share relative to our $0.125 per share dividend, resulting in $801 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 sizable project backlog. Our current project backlog is $13.0 billion, down from $13.5 billion at the end of the second quarter of 2016. This reduction was driven by the delivery of the Garden State and Bay State tankers as well as placing other projects in service. Excluding the CO2 segment projects, we expect the projects in our backlog to generate an average capital-to-EBITDA multiple of approximately 6.5 times.”

KMI reported a third quarter net loss available to common stockholders of $227 million, compared to net income available to common stockholders of $186 million for the third quarter of 2015, and distributable cash flow of $1,081 million versus $1,129 million for the comparable period in 2015. The decrease in distributable cash flow for the quarter was attributable to lower contributions from the CO2 segment primarily due to lower commodity prices. In total, KMI’s other business segments generated higher contributions than the third quarter of 2015. Net income available to common stockholders was also impacted by a $405 million unfavorable change in total certain items compared to the third quarter of 2015, including a partial write down of our equity investment in Midcontinent Express Pipeline (MEP) driven by expectations for lower future transportation contract rates as well as a non-cash book tax expense associated with the SNG transaction.

For the first nine months of 2016, KMI reported net income available to common stockholders of $382 million, compared to $948 million for the first nine months of 2015, and distributable cash flow of $3,364 million versus $3,466 million for the comparable period in 2015. The decrease in distributable cash flow was primarily attributable to lower contributions from the CO2 segment, higher preferred stock dividends and higher cash taxes, partially offset by increased contributions from all of KMI’s other segments and lower interest expense. Net income available to common stockholders was further impacted by a $480 million unfavorable change in total certain items compared to the first nine months of 2015, including the write down of our equity investment in MEP, the non-cash book tax expense associated with the SNG transaction, and a $170 million write-off of costs associated with the Northeast Energy Direct Market and Palmetto Pipeline projects during the first quarter of 2016.

2016 Outlook

For 2016, KMI expects to declare dividends of $0.50 per share. KMI's budgeted 2016 distributable cash flow was approximately $4.7 billion and budgeted 2016 Adjusted EBITDA was approximately $7.5 billion. Consistent with guidance provided the last two quarters, the company continues to expect Adjusted EBITDA to be about 3 percent below budget and distributable cash flow to be about 4 percent below budget. To be consistent with previous quarters, this guidance does not take the SNG transaction into account. Including the impact of the SNG transaction, the company expects Adjusted EBITDA and distributable cash flow to each be about 4 percent below budget. 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 quantifying 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 expects to generate excess cash sufficient to fund its growth capital requirements without needing to access capital markets and expects to end the year with a net debt-to-Adjusted EBITDA ratio of approximately 5.3 times, consistent with where KMI ended the third quarter and below the budgeted year-end ratio of 5.5 times. KMI’s growth capital forecast for 2016 is approximately $2.7 billion.

The overwhelming majority of cash generated by KMI is fee-based and therefore is not directly exposed to commodity prices. The primary area where KMI has direct commodity price sensitivity is in its CO2 segment, and KMI hedges the majority of its next 12 months of oil production to minimize this sensitivity. Additionally, KMI continues to closely monitor counterparty exposure and obtain collateral when appropriate. Moreover, the company has operations across a broad range of businesses and a diverse customer base, with its average customer representing less than one-tenth of 1 percent of annual revenues. Additionally, approximately two-thirds of KMI’s business is conducted with customers who are end-users of the products KMI transports and stores, such as utilities, local distribution companies, refineries and large integrated firms.

Overview of Business Segments

“The Natural Gas Pipelines segment’s performance for the third quarter of 2016 was impacted by the sale of a 50 percent interest in SNG. Excluding this sale, the Natural Gas Pipeline segment’s performance was in-line with the same period during 2015. The segment benefited from an increased contribution from Tennessee Gas Pipeline (TGP), driven by expansion projects placed into service during 2015, and increased contributions from both the Hiland midstream assets and the Texas Intrastate Natural Gas Pipelines. These contributions were offset by declines attributable to reduced volumes affecting certain of our midstream gathering and processing assets, unfavorable contract renewals on Colorado Interstate Gas pipeline, and a customer contract buyout at Kinder Morgan Louisiana pipeline during 2015,” Kean said.

Natural gas transport volumes were down 1 percent compared to the third quarter last year, driven by lower throughput on the Texas Intrastate Natural Gas Pipelines due to lower Eagle Ford Shale volumes, lower throughput on Ruby Pipeline due to increased Canadian imports to the Pacific Northwest, and lower throughput on Fayetteville Express Pipeline due to lower production from the Fayetteville Shale. These declines were partially offset by higher throughput on TGP due to projects placed in service, higher throughput on NGPL due to deliveries to Sabine Pass LNG facility and to South Texas to meet demand from Mexico, and higher throughput on Citrus pipeline due to strong weather-driven demand in Florida. Natural gas gathered volumes were down 17 percent from the third quarter last year due primarily to lower natural gas volumes on multiple systems gathering from the Eagle Ford Shale and lower volumes on the KinderHawk system compared to the third quarter of 2015.

Natural gas continues to be the fuel of choice for America’s evolving energy needs, and industry experts are projecting natural gas demand increases of approximately 35 percent to over 105 billion cubic feet per day (Bcf/d) over the next 10 years. Over the last 2.8 years, KMI has entered into new and pending firm transport capacity commitments totaling 8.2 Bcf/d (1.9 Bcf/d of which is existing, previously unsold capacity). Of the natural gas consumed in the United States, about 38 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, liquefied natural gas (LNG) exports, exports to Mexico and continued industrial development, particularly in the petrochemical industry. In fact, natural gas deliveries on KMI pipelines to gas-fired power plants, to Mexico and to LNG facilities were up 9 percent, 6 percent, and approximately 346,000 dekatherms per day (Dth/d), respectively, compared to the third quarter of 2015.

“The CO2 segment was impacted by lower commodity prices, as our realized weighted average oil price for the quarter was $62.12 per barrel compared to $74.18 per barrel for the third quarter of 2015,” Kean said. “Combined oil production across all of our fields was down 5 percent compared to 2015 on a net to Kinder Morgan basis, primarily driven by lower SACROC production. Third quarter 2016 net NGL sales volumes of 10.6 thousand barrels per day (MBbl/d) was consistent with volumes in the same period in 2015. Net CO2 volumes increased 3 percent versus the third quarter of 2015. We continued to offset some of the impact of lower commodity prices by generating cost savings across our CO2 business.”

Combined gross oil production volumes averaged 53.7 MBbl/d for the third quarter, down 6 percent from 57.3 MBbl/d for the same period in 2015. SACROC’s third quarter gross production was 11 percent below third quarter 2015 results, and Yates gross production was 6 percent below third quarter 2015 results. Both decreases were partially driven by project deferrals during 2016. Third quarter gross production from Katz, Goldsmith and Tall Cotton was 16 percent above the same period in 2015, but below plan. KMI had record high gross NGL production of 21.7 MBbl/d for the quarter and is on track for record annual NGL production. The average West Texas Intermediate unhedged crude oil price for the third quarter was $44.94 per barrel versus $46.43 for the third quarter of 2015.

“The Terminals segment experienced strong performance at our liquids terminals, which comprise more than 75 percent of the segment’s business. Growth in the liquids business during the quarter versus the third quarter of 2015 was driven by increased contributions from our Jones Act tankers, our refined products terminals joint venture with BP and various expansions across our network,” Kean said. The Lone Star State, Magnolia State, Garden State and Bay State tankers were delivered in December 2015, May 2016, July 2016 and September 2016, respectively. These tankers are each contracted with major energy customers under long-term, firm time charters.

Growth from the liquids terminals was partially offset by a decline in the bulk terminals as compared to the same period in 2015, largely driven by the bankruptcies of Arch Coal and Peabody Energy.

“The Products Pipelines segment was favorably impacted by the startup of the second petroleum condensate processing facility along the Houston Ship Channel during 2015, and favorable performance in our Transmix business compared to 2015 due to unfavorable market price impacts during the third quarter of 2015,” Kean said.

Total refined products volumes were up 3 percent for the third quarter versus the same period in 2015. NGL volumes were down 1 percent from the same period last year. Crude and condensate pipeline volumes were up 6 percent from the third quarter of 2015 primarily due to higher volumes on Double H and KMCC.

Kinder Morgan Canada contributions were up slightly in the third quarter of 2016 compared to the third quarter of 2015.

Other News

Natural Gas Pipelines

  • On Sept. 1, 2016, KMI and Southern Company closed on the previously announced joint venture transaction involving Southern Company’s acquisition of a 50 percent equity interest in SNG. As previously announced, Kinder Morgan will continue to operate the system, and the companies are pursuing specific growth opportunities to develop additional natural gas infrastructure for the strategic venture. Including SNG’s existing debt and cash consideration for Southern Company’s 50 percent share of the equity interest, the transaction implies a total enterprise value for SNG of approximately $4.15 billion.
  • On June 1, 2016, Elba Liquefaction Company and Southern LNG Company received FERC authorization for the Elba Liquefaction Project. As expected, requests for rehearing were filed by the Sierra Club and associated individuals and are currently pending before the FERC. Construction will begin on Nov. 1, 2016. The approximately $2 billion project will be constructed and operated at the existing Elba Island LNG Terminal near Savannah, Georgia. Initial liquefaction units are expected to be placed in service in mid-2018, with final units coming on line by early 2019. The project is supported by a 20-year contract with Shell. In 2012, the Elba Liquefaction Project received authorization from the Department of Energy to export to Free Trade Agreement (FTA) countries. An application to export to non-FTA countries is pending, but is not required for the project to move ahead. The project is expected to have a total capacity of approximately 2.5 million tonnes per year of LNG for export, equivalent to approximately 350 million cubic feet per day of natural gas.
  • Construction continues for Elba Express Company (EEC) and SNG facilities that will provide additional gas supplies for industrial customers and utilities in Georgia and Florida, and serve the Elba Island liquefaction facility. On June 1, 2016, FERC also issued certificates for both the EEC Modification Project and the SNG Zone 3 Expansion Project. These projects, which are supported by long-term customer contracts, total $302 million. The FERC approved the start of construction in late June, and the EEC and SNG facilities are expected to be placed in service beginning late in the fourth quarter of 2016.
  • On Sept. 6, 2016, the FERC issued separate certificate orders approving TGP’s Broad Run Expansion and Susquehanna West Projects:
  • Pending receipt of all required permits, TGP plans to begin construction of the Broad Run Expansion Project in December 2016 and place the project facilities in service on or before June 1, 2018. The project will provide an incremental 200,000 Dth/d of firm transportation capacity along the same capacity path (West Virginia to delivery points in Mississippi and Louisiana) as the Broad Run Flexibility Project, which was placed in service on Nov. 1, 2015 and provided an incremental 590,000 Dth/d of capacity. In 2014, Antero Resources Corporation was awarded a total of 790,000 Dth/d of 15-year firm capacity under the two projects. Estimated capital expenditures for the combined projects are approximately $800 million.
  • Pending receipt of all required permits, TGP plans to begin construction of the $156 million Susquehanna West Project in early 2017, and place the project facilities in service on or before Nov. 1, 2017. The project will provide 145,000 Dth/d of additional capacity to an interconnection with National Fuel Supply in Potter County, Pennsylvania, and is fully subscribed by StatOil Natural Gas LLC.
  • TGP continues to seek the remaining permits required for the start of construction of its FERC-approved $93 million Connecticut Expansion project, which will upgrade portions of TGP’s existing system in New York, Massachusetts and Connecticut, and provide approximately 72,100 Dth/d of additional firm transportation capacity for three local distribution company customers. Due to state and federal permit delays, the project’s original in-service date of Nov. 1, 2016, has been changed to Nov. 1, 2017.
  • TGP completed construction on the last phase of its $230 million, 500,000 Dth/d South System Flexibility Project on schedule and placed the final capacity increment in service on Oct. 1, 2016. The project, which is supported by long-term contracts, provides incremental supply access from TGP’s Station 87 Pool in Tennessee to delivery points in South Texas.
  • On Sept. 29, 2016, the FERC issued an Environmental Assessment for TGP’s proposed $178 million, 900,000 Dth/d Southwest Louisiana Supply Project, which is designed to serve the Cameron LNG export complex. The project, which is supported by long-term contracts, is expected to be placed in service by Feb. 1, 2018.
  • On Aug. 1, 2016, NGPL filed an application with the FERC for facilities associated with its approximately $212 million Gulf Coast Southbound Expansion Project. The project, which is fully subscribed under long-term customer contracts, is designed to transport 460,000 Dth/d of incremental firm transportation service from NGPL’s interstate pipeline interconnects in Illinois, Arkansas and Texas to points south on NGPL’s pipeline system to serve growing demand in the Gulf Coast area. Pending regulatory approvals, the project is expected to be fully in service by the fourth quarter of 2018.
  • Construction is nearing completion on NGPL’s Chicago Market Expansion project. This approximately $74 million project will increase NGPL’s capacity by 238,000 Dth/d and provide transportation service on its Gulf Coast mainline system from the Rockies Express Pipeline interconnection in Moultrie County, Illinois, to points north on NGPL’s system. NGPL has executed binding agreements with four customers for incremental firm transportation service to markets near Chicago and the project is expected to be placed in service on Nov. 1, 2016.
  • Phase 1 of the Texas Intrastate Natural Gas system’s Crossover project was placed in service on Sept. 1, 2016, as planned. Phase 1 provides transportation capacity to serve customers in Texas and Mexico and is supported by commitments of over 800,000 Dth/d, including contracts with Cheniere Energy, Inc. at its Corpus Christi LNG facility (once the facility is placed in service) and with Comisión Federal de Electricidad (CFE). Work continues on Phase 2 of the project, which is supported by a long-term commitment from SK E&S LNG, LLC for service to the Freeport LNG export facility. Phase 2 is expected to go into service in late 2018 and will bring the total project capacity to over 1,100,000 Dth/d. The total cost for both phases is approximately $326 million.

CO2

  • Construction is nearing completion on the northern portion of the Cortez Pipeline expansion project. The approximately $226 million project will increase CO2 transportation capacity on the Cortez Pipeline from 1.35 Bcf/d to 1.5 Bcf/d. The pipeline transports CO2 from southwestern Colorado to eastern New Mexico and West Texas for use in enhanced oil recovery projects. The third of five facilities was placed into service in the third quarter of 2016, with the final two facilities expected to be in service by the end of the year.
  • We continue to find high-return enhanced oil recovery projects in the current price environment across the portfolio and have benefited from cost savings in our operations and in our expansion capital program.

Terminals

  • Construction is nearly complete on the second of two new deep-water liquids berths being developed along the Houston Ship Channel, with in-service expected in the fourth quarter of this year. The first dock was placed in service at the end of March 2016. The docks, which are pipeline-connected to Kinder Morgan’s Pasadena and Galena Park terminals via three cross-channel lines, are capable of loading ocean-going vessels at rates up to 15,000 barrels per hour. The approximately $72 million project is a response to customers’ growing demand for waterborne outlets for refined products along the ship channel, and is supported by firm vessel commitments from existing customers at the Galena Park and Pasadena terminals.
  • Construction continues at the Base Line Terminal, a new crude oil storage facility being developed in Edmonton, Alberta. In March 2015, Kinder Morgan and Keyera Corp. announced the new 50-50 joint venture terminal and entered into long-term, firm take-or-pay agreements with strong, creditworthy customers to build 12 tanks with total crude oil storage capacity of 4.8 million barrels. KMI’s investment in the joint venture terminal is approximately CAD$372 million. Commissioning is expected to begin in the first quarter of 2018.
  • Work continues on the Kinder Morgan Export Terminal (KMET) along the Houston Ship Channel. The approximately $245 million project 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 Kinder Morgan’s Galena Park terminal. KMET is anticipated to be in service in the first quarter of 2017.
  • In July and September 2016, Kinder Morgan’s American Petroleum Tankers (APT) took delivery of the Garden State and Bay State, respectively, the third and fourth of five 50,000-deadweight-ton product tankers from General Dynamics’ NASSCO Shipyard in San Diego, California. Each of the ECO class vessels, with cargo capacities of 330,000-barrels and LNG conversion ready engine capabilities, is fixed under long-term, firm time charters with major energy companies. The construction programs at NASSCO and Philly Shipyard, Inc. remain on-budget and substantially on-time. Five additional vessels are scheduled to be delivered through the end of 2017, bringing APT’s best-in-class fleet to 16 vessels.
  • In August 2016, Kinder Morgan placed in service three 100,000 barrel tanks at its Carteret, New Jersey terminal. The tanks, which are outfitted with internal floating roofs and pipeline, dock and truck rack connectivity as well as in-tank butane blending capabilities, are leased pursuant to a long-term, firm take-or-pay storage agreement. The $32 million project adds to Kinder Morgan’s strong position in the strategic New York Harbor petroleum product hub.

Products Pipelines

  • Work continues on the Utopia Pipeline Project, with landowner discussions and permitting activities underway. The approximately $500 million new pipeline will have an initial design capacity of 50,000 barrels per day (bpd), and will move ethane and ethane-propane mixtures across Ohio to Windsor, Ontario, Canada. The project is fully supported by a long-term, fee-based transportation agreement with a petrochemical customer. The project has a planned in-service date of January 2018, subject to permitting and land acquisition.

Kinder Morgan Canada

  • On May 19, 2016, the National Energy Board (NEB) issued a report recommending that the federal government approve the Trans Mountain Expansion Project, subject to 157 conditions. The deadline for the Federal Government Order in Council decision is Dec. 20, 2016. As previously announced, the government conducted further consultation with First Nations related to the 157 conditions and the project impact. In addition, the federal government implemented a Ministerial Panel to hear from the general public with respect to identifying views not heard by the initial NEB review. The Ministerial Panel held public and by invitation-only sessions in 19 communities in Alberta and British Columbia and launched an online questionnaire for Canadians to submit feedback on the project. The panel is required to produce a report for the Minister of Natural Resources by Nov. 1, 2016. If approved, the project is expected to be in service by the end of 2019. The in-service date for the expansion will depend on the final conditions contained in the Order in Council from the federal government. The proposed USD$5.4 billion expansion will increase capacity on Trans Mountain from approximately 300,000 to 890,000 bpd. Thirteen companies have signed firm long-term contracts supporting the project for approximately 708,000 bpd. Kinder Morgan Canada is currently in negotiations with construction contractors and continues to engage extensively with landowners, Aboriginal groups, communities and stakeholders along the proposed expansion route and adjacent marine areas.

Financings

  • On Aug. 16, 2016, CIG issued $375 million of 10-year senior notes at a fixed rate of 4.15 percent.
  • On Sept. 1, 2016, KMI sold a 50 percent equity interest in SNG. As a result, KMI will no longer consolidate SNG, including its $1,211 million of public debt outstanding as of Sept. 30, 2016. SNG’s debt will continue to be guaranteed by KMI until Dec. 2, 2016, when SNG’s investment grade rating requirement imposed by the cross guarantee is expected to be met.
  • On Sept. 30, 2016, KMI repaid the $332 million principal amount of Copano Energy, LLC’s 7.125 percent senior notes due 2021, plus accrued interest and a fixed price premium.
  • On Oct. 1, 2016, KMI repaid the $749 million principal amount of Hiland Partners, LP’s 7.25 percent senior notes due 2020. As of Sept. 30, 2016, funds for this extinguishment, plus $54 million for accrued interest and a fixed price premium, were held in escrow as a restricted deposit.

Kinder Morgan, Inc. (NYSE: KMI) is the largest energy infrastructure company in America. It owns an interest in or operates approximately 84,000 miles of pipelines and approximately 180 terminals. KMI’s pipelines transport natural gas, gasoline, crude oil, CO2 and other products, and its terminals store petroleum products and chemicals, and handle bulk materials like coal and petroleum coke. For more information please visit www.kindermorgan.com.

Please join Kinder Morgan at 4:30 p.m. Eastern Time on Wednesday, Oct. 19, at www.kindermorgan.com for a LIVE webcast conference call on the company’s third 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), and net income before interest expense, taxes, DD&A and certain items (Adjusted EBITDA) 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 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 DCF to net income available to common stockholders 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.

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 Kinder Morgan believes that these forward-looking statements are based on 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 Kinder Morgan’s reports filed with the Securities and Exchange Commission (SEC), including its Annual Report on Form 10-K for the year-ended December 31, 2015 (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, Kinder Morgan 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.

 
Kinder Morgan, Inc. and Subsidiaries

Preliminary Consolidated Statements of Income

(Unaudited)

(In millions, except per share amounts)

 
       

Three Months Ended

September 30,

       

Nine Months Ended

September 30,

   
2016     2015 2016     2015
 
Revenues $ 3,330   $ 3,707   $ 9,669   $ 10,767  
 
Costs, expenses and other
Costs of sales 971 1,106 2,454 3,281
Operations and maintenance 576 612 1,744 1,707
Depreciation, depletion and amortization 549 617 1,652 1,725
General and administrative 171 160 550 540
Taxes, other than income taxes 106 108 324 339
Loss on impairments and divestitures, net 76 385 307 489
Other income, net (1 ) (2 )   (5 )
2,448   2,986   7,031   8,076  
Operating income 882 721 2,638 2,691
 
Other income (expense)
Earnings from equity investments 137 114 343 330
Loss on impairments and divestitures of equity investments, net (350 ) (344 ) (26 )
Amortization of excess cost of equity investments (15 ) (13 ) (45 ) (39 )
Interest, net (472 ) (540 ) (1,384 ) (1,524 )
Other, net 12   9   42   33  
Income before income taxes 194 291 1,250 1,465
Income tax expense (377 ) (108 ) (744 ) (521 )
Net (loss) income (183 ) 183 506 944
Net (income) loss attributable to noncontrolling interests (5 ) 3   (7 ) 4  
Net (loss) income attributable to Kinder Morgan, Inc. (188 ) 186 499 948
Preferred stock dividends (39 )   (117 )  
Net (loss) income available to common stockholders $ (227 ) $ 186   $ 382   $ 948  
Class P Shares
Basic and diluted (loss) earnings per common share $ (0.10 ) $ 0.08   $ 0.17   $ 0.43  
Basic weighted average common shares outstanding (1) 2,230   2,203   2,229   2,173  
Diluted weighted average common shares outstanding (1) 2,230   2,203   2,229   2,181  
Declared dividend per common share $ 0.125   $ 0.510   $ 0.375   $ 1.480  
 
Segment EBDA

%

change

%

change

Natural Gas Pipelines $ 540 $ 993 (46 )% $ 2,498 $ 2,936 (15 )%
CO2 217 29 648 % 606 605 %
Terminals 286 249 15 % 831 798 4 %
Products Pipelines 293 288 2 % 765 811 (6 )%
Kinder Morgan Canada 43 42 2 % 123 120 3 %
Other 2   (9 ) 122 % (11 ) (55 ) 80 %
Total Segment EBDA $ 1,381   $ 1,592   (13 )% $ 4,812   $ 5,215   (8 )%
 

Note

(1)  

For all periods presented, all potential common share equivalents were antidilutive, except for the nine months ended September 30,

   2015 during which the KMI warrants were dilutive.

 
 
Kinder Morgan, Inc. and Subsidiaries

Preliminary Earnings Contribution by Business Segment

(Unaudited)

(In millions, except per share amounts)

 
       

Three Months Ended

September 30,

       

Nine Months Ended

September 30,

   
2016     2015

%

change

2016     2015

%

change

Segment EBDA before certain items (1)
Natural Gas Pipelines $ 957 $ 975 (2 )% $ 3,045 $ 3,027 1 %
CO2 229 282 (19 )% 679 849 (20 )%
Terminals 285 263 8 % 837 798 5 %
Product Pipelines 294 287 2 % 877 807 9 %
Kinder Morgan Canada 43 42 2 % 123 120 3 %
Other (2 ) (10 ) 80 % (19 ) (23 ) 17 %
Subtotal 1,806 1,839 (2 )% 5,542 5,578 (1 )%
DD&A and amortization of excess investments (564 ) (630 ) (1,697 ) (1,764 )
General and administrative (1) (2) (159 ) (152 ) (493 ) (485 )
Interest, net (1) (3) (505 ) (524 ) (1,526 ) (1,565 )
Subtotal 578   533   1,826   1,764  
 
Corporate book taxes (4) (191 ) (185 ) (626 ) (606 )
Certain items
Acquisition related costs (5) (4 ) (2 ) (12 ) (14 )
Pension plan net benefit 5 28
Fair value amortization 53 24 106 72
Contract early termination revenue 18 57
Legal and environmental reserves (6) 1 (1 ) (55 ) (78 )
Mark to market and ineffectiveness (7) (30 ) 118 (23 ) 162
Losses on impairments and divestitures, net (8) (426 ) (387 ) (505 ) (516 )
Project write-offs (170 )
Other (10 ) (17 ) (22 ) (4 )
Subtotal certain items before tax (398 ) (260 ) (624 ) (350 )
Book tax certain items (9) (172 ) 95   (70 ) 136  
Total certain items (570 ) (165 ) (694 ) (214 )
Net (loss) income (183 ) 183 506 944
Net (income) loss attributable to noncontrolling interests (5 ) 3 (7 ) 4
Preferred stock dividends (39 )   (117 )  
Net (loss) income available to common stockholders $ (227 ) $ 186   $ 382   $ 948  
 
Net (loss) income available to common stockholders $ (227 ) $ 186 $ 382 $ 948
Total certain items 570 165 694 214
Noncontrolling interests certain item (10)   (6 ) (9 ) (20 )
Net income available to common stockholders before certain items 343 345 1,067 1,142
DD&A and amortization of excess investments (11) 653 708 1,961 2,004
Total book taxes (12) 230 224 745 713
Cash taxes (13) (22 ) (3 ) (61 ) (19 )
Other items (14) 11 7 31 23
Sustaining capital expenditures (15) (134 ) (152 ) (379 ) (397 )
DCF $ 1,081   $ 1,129   $ 3,364   $ 3,466  
Weighted average common shares outstanding for dividends (16) 2,239 2,210 2,237 2,189
DCF per common share $ 0.48 $ 0.51 $ 1.50 $ 1.58
Declared dividend per common share $ 0.125 $ 0.510 $ 0.375 $ 1.480
 
Adjusted EBITDA (17) $ 1,770 $ 1,803 $ 5,414 $ 5,425
 

Notes ($ million)

(1)   Excludes certain items:
3Q 2016 - Natural Gas Pipelines $(417), CO2 $(12), Terminals $1, Products Pipelines $(1), Other $4, general and administrative $(4), interest expense $31.
3Q 2015 - Natural Gas Pipelines $18, CO2 $(253), Terminals $(14), Products Pipelines $1, Other $1, general and administrative $2, interest expense $(15).
YTD 2016 - Natural Gas Pipelines $(547), CO2 $(73), Terminals $(6), Products Pipelines $(112), Other $8, general and administrative $(32), interest expense $140.
YTD 2015 - Natural Gas Pipelines $(91), CO2 $(244), Products Pipelines $4, Other $(32), general and administrative $(27), interest expense $40.
(2) General and administrative expense is net of management fee revenues from an equity investee:
3Q 2016 - $(8)
3Q 2015 - $(10)
YTD 2016 - $(25)
YTD 2015 - $(28)
(3) Interest expense excludes interest income that is allocable to the segments:
3Q 2016 - Other $2.
3Q 2015 - Products Pipelines $1, Other $(2).
YTD 2016 - Products Pipelines $1, Other $1.
YTD 2015 - Products Pipelines $2, Other $(1).
(4) Corporate book taxes exclude book tax certain items not allocated to the segments of $(172) in 3Q 2016, $95 in 3Q 2015, $(72) YTD 2016, and $136 YTD 2015. Also excludes income tax that is allocated to the segments:
3Q 2016 - Natural Gas Pipelines $(2), Terminals $(8), Products Pipelines $1, Kinder Morgan Canada $(5).
3Q 2015 - Natural Gas Pipelines $(1), CO2 $(1), Terminals $(8), Products Pipelines $(3), Kinder Morgan Canada $(5).
YTD 2016 - Natural Gas Pipelines $(5), CO2 $(2), Terminals $(25), Products Pipelines $3, Kinder Morgan Canada $(17).
YTD 2015 - Natural Gas Pipelines $(5), CO2 $(3), Terminals $(21), Products Pipelines $(7), Kinder Morgan Canada $(15).
(5) Acquisition related costs for closed or pending acquisitions.
(6) Legal reserve adjustments related to certain litigation and environmental matters.
(7) Gains or losses are reflected when realized.
(8) Includes the following non-cash impairments:
3Q 2016 and YTD 2016 include a $350 million impairment of our equity investment in Midcontinent Express Pipeline LLC. 3Q 2015 and YTD 2015 includes $388 million of CO2 long lived asset impairments primarily related to our Goldsmith oil and gas field.
(9) 3Q and YTD 2016 include a $276 million book tax expense certain item due to the non-deductibility, for tax purposes, of approximately $800 million of goodwill included in the loss calculation related to the sale of a 50% interest in SNG, resulting in a gain for tax purposes.
(10) Represents noncontrolling interest share of certain items.
(11) Includes KMI's share of certain equity investees' DD&A:
3Q 2016 - $89
3Q 2015 - $78
YTD 2016 - $264
YTD 2015 - $240
(12) Excludes book tax certain items and includes income tax allocated to the segments. Also, includes KMI's share of taxable equity investees' book tax expense:
3Q 2016 - $25
3Q 2015 - $21
YTD 2016 - $71
YTD 2015 - $56
(13) YTD 2015 excludes a $195 million income tax refund received. Includes KMI's share of taxable equity investees' cash taxes:
3Q 2016 - $(25)
3Q 2015 - $(2)
YTD 2016 - $(59)
YTD 2015 - $(8)
(14) Consists primarily of non-cash compensation associated with our restricted stock program.
(15) Includes KMI's share of certain equity investees' sustaining capital expenditures (the same equity investees for which DD&A is added back):
3Q 2016 - $(24)
3Q 2015 - $(16)
YTD 2016 - $(66)
YTD 2015 - $(50)
(16) Includes restricted stock awards that participate in common share dividends and dilutive effect of warrants, as applicable.
(17) Adjusted EBITDA is net (loss) 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 income tax allocated to the segments and KMI’s share of certain 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
September 30,

Nine Months Ended
September 30,

2016   2015 2016   2015
Net (loss) income $ (183 ) $ 183 $ 506 $ 944
Total certain items 570 166 694 214
Net income attributable to noncontrolling interests (5 ) (3 ) (16 ) (16 )
DD&A and amortization of excess investments (see (11) above) 653 708 1,960 2,005
Book taxes (see (12) above) 230 224 745 713
Interest, net (see (1) and (3) above)   505     525     1,525     1,565  
Adjusted EBITDA $ 1,770   $ 1,803   $ 5,414   $ 5,425  
                 
Volume Highlights

(historical pro forma for acquired assets)

 

Three Months Ended
September 30,

Nine Months Ended
September 30,

2016 2015 2016 2015
Natural Gas Pipelines
Transport Volumes (BBtu/d) (1) (2) 28,144 28,438 28,162 28,076
Sales Volumes (BBtu/d) (3) 2,438 2,445 2,350 2,416
Gas Gathering Volumes (BBtu/d) (2) (4) 2,935 3,541 3,044 3,554
Crude/Condensate Gathering Volumes (MBbl/d) (2) (5) 283 343 310 340
 
CO2

Southwest Colorado Production - Gross (Bcf/d) (6)

1.20 1.20 1.18 1.22
Southwest Colorado Production - Net (Bcf/d) (6) 0.62 0.60 0.60 0.58
Sacroc Oil Production - Gross (MBbl/d) (7) 28.92 32.49 29.72 34.44
Sacroc Oil Production - Net (MBbl/d) (8) 24.09 27.07 24.76 28.69
Yates Oil Production - Gross (MBbl/d) (7) 17.85 18.89 18.52 18.94
Yates Oil Production - Net (MBbl/d) (8) 7.94 7.60 8.24 8.20
Katz, Goldsmith, and Tall Cotton Oil Production - Gross (MBbl/d) (7) 6.89 5.95 6.86 5.60
Katz, Goldsmith, and Tall Cotton Oil Production - Net (MBbl/d) (8) 5.84 4.99 5.78 4.71
NGL Sales Volumes (MBbl/d) (9) 10.55 10.51 10.26 10.33
Realized Weighted Average Oil Price per Bbl (10) $ 62.12 $ 74.18 $ 61.27 $ 73.19
Realized Weighted Average NGL Price per Bbl $ 18.03 $ 16.29 $ 16.42 $ 18.96
 
Terminals
Liquids Leasable Capacity (MMBbl) 88.9 81.5 88.9 81.5
Liquids Utilization % 95.6 % 93.1 % 95.6 % 93.1 %
Bulk Transload Tonnage (MMtons) (11) 17.2 16.9 46.3 48.9
Ethanol (MMBbl) 17.3 15.0 48.9 47.3
 
Products Pipelines
Pacific, Calnev, and CFPL (MMBbl)
Gasoline (12) 76.3 74.1 218.4 216.0
Diesel 28.2 28.5 80.8 80.8
Jet Fuel   24.7     23.2     69.8     67.0  
Sub-Total Refined Product Volumes - excl. Plantation and Parkway 129.2 125.8 369.0 363.8
Plantation (MMBbl) (13)
Gasoline 21.1 19.1 62.5 59.5
Diesel 4.7 5.6 13.9 15.9
Jet Fuel   3.2     3.5     9.2     10.8  
Sub-Total Refined Product Volumes - Plantation 29.0 28.2 85.6 86.2
Total (MMBbl)
Gasoline (12) 97.4 93.2 280.9 275.5
Diesel 32.9 34.1 94.7 96.7
Jet Fuel   27.9     26.7     79.0     77.8  
Total Refined Product Volumes 158.2 154.0 454.6 450.0
NGLs (MMBbl) (14) 9.9 10.0 28.9 29.4
Crude and Condensate (MMBbl) (15)   28.8     27.3     87.6     70.9  
Total Delivery Volumes (MMBbl) 196.9 191.3 571.1 550.3
Ethanol (MMBbl) (16) 10.1 10.7 30.9 31.1
 
Trans Mountain (MMBbls - mainline throughput) 30.7 29.5 88.1 86.9
   
(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.
       
Kinder Morgan, Inc. and Subsidiaries

Preliminary Consolidated Balance Sheets

(Unaudited)

(In millions)

 
September 30, December 31,
2016 2015
ASSETS
Cash and cash equivalents $ 357 $ 229
Other current assets 3,006 2,595
Property, plant and equipment, net 38,780 40,547
Investments 7,358 6,040
Goodwill 22,163 23,790
Deferred charges and other assets   9,940     10,903  
TOTAL ASSETS $ 81,604   $ 84,104  
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
Liabilities
Short-term debt $ 2,944 $ 821
Other current liabilities 3,100 3,244
Long-term debt 36,708 40,632
Preferred interest in general partner of KMP 100 100
Debt fair value adjustments 1,710 1,674
Other   2,074     2,230  
Total liabilities   46,636     48,701  
 
Shareholders’ Equity
Accumulated other comprehensive loss (557 ) (461 )
Other shareholders’ equity   35,163     35,580  
Total KMI equity 34,606 35,119
Noncontrolling interests   362     284  
Total shareholders’ equity   34,968     35,403  
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 81,604   $ 84,104  
 
Net Debt (1) (3) $ 39,248 $ 41,224
 

Adjusted EBITDA
Twelve Months Ended

September 30, December 31,
Reconciliation of Net (Loss) Income to Adjusted EBITDA (2) 2016 2015
Net (loss) income $ (228 ) $ 208
Total certain items 1,920 1,441
Net income attributable to noncontrolling interests (18 ) (18 )
DD&A and amortization of excess investments 2,638 2,683
Book taxes 1,007 976
Interest, net   2,042     2,082  
Adjusted EBITDA $ 7,361   $ 7,372  
 
Net Debt to Adjusted EBITDA (3) 5.3 5.6
 
Year ended
December 31,
2016
Reconciliation of Forecasted GAAP Capital Expenditures to Growth Capital Forecast for 2016
Forecasted capital expenditures(4) $ 2,728
Growth capital expenditures of unconsolidated joint ventures and acquisitions, net of divestitures 450
Less: Sustaining capital expenditures   (455 )
Growth Capital Forecast for 2016 $ 2,723  
 

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 $47 million and less than $1 million as of September 30, 2016 and December 31, 2015, respectively, as we have entered into swaps to convert that debt to US$.
(2) Adjusted EBITDA is net (loss) 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 income tax allocated to the segments and KMI’s share of certain equity investees’ book tax), and interest expense (before certain items), with any difference due to rounding.
(3) As of September 30, 2016, $749 million of cash was held in escrow to redeem debt, which occurred on October 1, 2016, and therefore, not included in cash and cash equivalents or the calculation of Net Debt. Had this cash been included in cash and cash equivalents as of September 30, 2016, Net Debt would have been $38,499 million and the Net Debt to Adjusted EBITDA ratio would have been 5.2 times for the twelve months ended September 30, 2016.
(4) Excludes accrued capital expenditures and contractor retainage.

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