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 fourth quarter ($0.50 annualized) payable on February 15, 2018, to common stockholders of record as of the close of business on January 31, 2018. KMI continues to expect to increase its dividend to $0.80 per share for 2018 ($0.20 per share for Q1 2018). KMI also continues to expect to use cash in excess of dividend payments to fully fund growth investments, further strengthening its balance sheet.
“Kinder Morgan thrived in 2017. We had very good financial performance despite facing continued strong headwinds (including an epic rain event), we strengthened the balance sheet beyond our original projections, and we announced our plan to return value to shareholders through an increasing dividend and a $2 billion share repurchase program. Our previously announced 2018 guidance, with $0.80 dividends to be declared for 2018, and the early start to our share repurchases, which we began in December 2017, shows our commitment to that plan. We are highly confident in our ability to maintain robust dividend coverage while delivering a substantial dividend increase to stockholders out of operating cash flows in excess of growth capital. And of course we will continue the important work of strengthening our balance sheet by funding all growth capital through operating cash flows with no need for external funding for growth capital for the third straight year,” said Richard D. Kinder, Executive Chairman.
President and CEO Steve Kean said, “During 2017 we completed the Elba Liquefaction Project joint venture and the IPO of our Canadian pipelines and terminals assets (KML). Those transactions helped us outperform our original target for strengthening our balance sheet, leading to a year-end 2017 Net Debt-to-Adjusted EBITDA ratio of 5.1 times versus our plan of 5.4 times. We are committed to achieving or beating our longer term leverage target of 5.0 times. We also placed almost $1.8 billion of projects in service throughout the year and added a substantial additional natural gas project in Gulf Coast Express. We had good commercial and operating performance, slightly exceeding our plan for the year. We are pleased with the strength and resiliency of the company’s business and with our operational performance.”
“We also had a solid fourth quarter, but because of a non-cash accounting charge resulting from the reduction in corporate income tax rates, we are showing a fourth quarter loss of $0.47 in earnings per common share. While the recently enacted Tax Cuts and Jobs Act of 2017 will ultimately be moderately positive for KMI, the reduced corporate income tax rate causes certain deferred-tax assets to be revalued at 21 percent versus 35 percent. Although there is no impact to the underlying related deductions, which can continue to be used to offset future taxable income, KMI will take an estimated approximately $1.4 billion non-cash accounting charge for the 4th quarter. This charge is our initial estimate and may be refined in the future as permitted by recent guidance from the Securities and Exchange Commission and the Financial Accounting Standards Board. The positive impacts of the law include the reduced corporate income tax rate and the fact that several of our U.S. business units (essentially all but our interstate natural gas pipelines) will be able to deduct 100 percent of their capital expenditures through 2022. The net impact results in postponing the date when KMI becomes a federal cash taxpayer by approximately one year, to beyond 2024,” continued Kean.
For the quarter, we achieved distributable cash flow (DCF) of $0.53 per common share, representing 4 percent growth over the fourth quarter of 2016, resulting in $910 million of excess DCF above our dividend. The discrepancy between a reported net income loss and a DCF gain illustrates why we and those who follow our businesses view the DCF metric as an important measure of our financial performance.”
Kean added, “We continue to drive future growth by completing significant infrastructure development projects that we track as part of our project backlog. Our current project backlog is essentially flat with last quarter at $11.8 billion, with a small decrease primarily due to projects going into service, which was mostly offset by the addition of our Gulf Coast Express joint venture. 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 fourth quarter net loss available to common stockholders of $1,045 million, compared to net income available to common stockholders of $170 million for the fourth quarter of 2016, and DCF of $1,190 million, up 4 percent from $1,147 million for the comparable period in 2016. The increase in DCF was driven by greater contributions from the Natural Gas, Terminals and Products Pipelines Business Units, as well as from Kinder Morgan Canada, partially offset by decreased contributions from CO2. Net income available to common stockholders was impacted by a $1,276 million unfavorable change in total Certain Items (as described under “Non-GAAP Financial Measures” below) compared to the fourth quarter of 2016. Fourth quarter 2017 Certain Items were driven largely by the non-cash accounting charge resulting from the 2017 Tax Cuts and Jobs Act as previously discussed.
For the full year, KMI reported net income available to common stockholders of $27 million, versus $552 million for 2016, and DCF of $4,482 million ($2.00 per share) that was down slightly from $4,511 million for the comparable period in 2016. The decrease in DCF was driven by the sale of 50 percent of Southern Natural Gas (SNG) in 2016, negative impacts of Hurricane Harvey, a contribution to KMI’s pension plan, and the KML IPO, partially offset by increased contributions from the Terminals Business Unit, growth projects in the Natural Gas Business Unit, lower interest expense, and lower general and administrative expenses. Excluding the impact of Hurricane Harvey, the SNG sale and the KML IPO, DCF was up over 1 percent from 2016. Net income available to common stockholders was also impacted by a $512 million increase in total Certain Items compared to 2016. Certain Items in 2017 were driven by the revaluation of certain deferred-tax assets described above, partially offset by asset impairment charges taken during 2016.
2018 Outlook
For 2018, KMI’s budget is set to declare dividends of $0.80 per common share, achieve DCF of approximately $4.57 billion ($2.05 per common share) and Adjusted EBITDA of approximately $7.5 billion. KMI also budgeted to invest $2.2 billion in growth projects during 2018 (excluding growth capital expected to be funded by KML), 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 5.1 times.
KMI previously announced it will further enhance shareholder value through a $2 billion share buy-back program. KMI’s Board of Directors authorized the program to begin in December 2017, and during that month KMI repurchased approximately 14 million shares for approximately $250 million. In 2018, KMI plans to further utilize this program opportunistically.
KMI does not provide budgeted net income attributable to common stockholders (the GAAP financial measure most directly comparable to DCF 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 $56.50 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 31,419 barrels per day (Bbl/d) at $59.58/Bbl in 2018; 17,401 Bbl/d at $54.85/Bbl in 2019; 9,300 Bbl/d at $52.86/Bbl in 2020; and 4,300 Bbl/d at $51.92/Bbl in 2021. For 2018, KMI estimates that every $1 per barrel change in the average West Texas Intermediate crude oil price from the company’s budget of $56.50 would impact budgeted DCF by approximately $7 million and each $0.10 per MMBtu change in the price of natural gas from the company’s budget of $3 per MMBtu would impact budgeted DCF by approximately $1 million.
Overview of Business Segments
“The Natural Gas Pipelines segment’s performance for the fourth quarter of 2017 was 4 percent higher relative to the fourth quarter of 2016. The segment benefited from increased contributions from Tennessee Gas Pipeline (TGP), driven by incremental short-term capacity sales and projects placed in service; from Natural Gas Pipeline of America (NGPL) due to lower interest expense; from the Elba Express pipeline resulting from the completion of expansion projects; from SNG due to completion of an expansion project and lower interest expense; and from Hiland Midstream due to increased gathering volumes and the effect of renegotiated contracts. These benefits were partially offset by lower contributions from certain midstream gathering and processing assets and from Colorado Interstate Gas Company (CIG) as a result of a 2016 rate case settlement,” Kean said.
Natural gas transport volumes were up 8 percent compared to the fourth quarter of 2016, driven by higher throughput on TGP and Elba Express due to projects placed in service, on NGPL due to incremental demand from LNG facilities and to Mexico, and on El Paso Natural Gas (EPNG) due to additional Permian capacity sales. The increases were partially offset by lower throughput on Cheyenne Plains due to mild weather and fuel switching to coal in the Rockies market. Natural gas gathering volumes were down 2 percent from the fourth quarter of 2016 due primarily to lower natural gas volumes on multiple systems gathering from the Eagle Ford Shale and on the KinderHawk system, partially offset by increases in Hiland and Altamont volumes due to increased drilling activities in the basins.
Natural gas is critical to the American economy and to meeting the world’s evolving energy and manufacturing needs. Objective analysts project U.S. natural gas demand, including net exports of liquefied natural gas (LNG) and net exports to Mexico, will increase by more than 30 percent to approximately 105 billion cubic feet per day (Bcf/d) by 2027. Of the natural gas consumed in the U.S., about 40 percent moves on KMI pipelines. While a substantial majority of natural gas is consumed in industrial, commercial and residential heating uses, KMI expects future natural gas infrastructure opportunities will also 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. Compared to the fourth quarter of 2016, natural gas deliveries on KMI pipelines to Mexico were up 6 percent, and deliveries to the Sabine Pass LNG facility increased by 33 percent. KMI transports roughly 70 percent of all U.S. natural gas exports destined for Mexico.
“The CO2 segment was impacted by lower commodity prices, as our realized weighted average oil price for the quarter was $59.32 per barrel compared to $62.30 per barrel for the fourth quarter of 2016,” Kean said. “Combined oil production across all of our fields was up 2 percent compared to 2016 on a net to Kinder Morgan basis. Fourth quarter 2017 net NGL sales volumes of 10.1 thousand barrels per day (MBbl/d) were down 3 percent from 2016, due to an operational interruption during the quarter.”
Combined gross oil production volumes averaged 54.1 MBbl/d for the fourth quarter, up 1 percent from 53.5 MBbl/d for the same period last year. SACROC’s fourth quarter gross production was 1 percent above fourth quarter 2016 results and slightly above 2017 budget, and Yates gross production was 5 percent below fourth quarter 2016 results and below plan. Fourth quarter gross production from Katz, Goldsmith and Tall Cotton was 18 percent above the same period in 2016, but below plan. Gross NGL sales volumes were 20.5 MBbl/d during the quarter, 4 percent below fourth quarter 2016. Southwest Colorado and the Cortez Pipeline set annual records in 2017.
“The Terminals segment earnings contributions were up 4 percent compared to the fourth quarter of 2016 despite several divestitures and a negative impact on earnings associated with Hurricane Harvey.
“Growth in the liquids business during the quarter versus the fourth quarter of 2016 was primarily driven by increased contributions from our Jones Act tankers, including the fourth quarter delivery of our final new-build tanker, the American Pride, as well as various expansions across our network, including the Kinder Morgan Export Terminal and the Pit 11 project at our Pasadena Terminal, which combined added 3.5 million barrels of storage to our best-in-class refined products storage hub along the Houston Ship Channel,” Kean said.
A 9 percent increase in the bulk business during the quarter versus the fourth quarter of 2016 was attributable primarily to increased volumes and earnings from our petroleum coke and steel handling activities that more than offset the impact of various non-core asset divestitures.
“The Products Pipelines segment contributions were up 2 percent compared with fourth quarter 2016 performance due largely to increased contributions from SFPP, CalNev, and Kinder Morgan Southeast Terminals,” Kean said.
Total refined products volumes were up 4 percent for the fourth quarter versus the same period in 2016. Crude and condensate pipeline volumes were up 2 percent from the fourth quarter of 2016.
Kinder Morgan Canada contributions were up 22 percent in the fourth quarter of 2017 compared to the fourth quarter of 2016. This was largely due to higher capitalized equity financing costs associated with spending on the Trans Mountain Expansion Project, timing of operating costs, and foreign exchange effects driven by a stronger Canadian dollar in 2017.
Other News
Natural Gas Pipelines
- Substantial progress is being made on the nearly $2 billion Elba Liquefaction Project as construction is well underway. The federally approved liquefaction project at the existing Southern LNG Company facility at Elba Island near Savannah, Georgia, is supported by a 20-year contract with Shell. Total liquefaction capacity will be approximately 2.5 million tonnes per year of LNG, equivalent to approximately 350 million cubic feet per day of natural gas. Initial in-service is expected in mid-2018 with final units coming on line by mid-2019. Elba Liquefaction Company, L.L.C. (ELC), a KMI joint venture with EIG Global Energy Partners as a 49 percent partner, will own 10 liquefaction units and other ancillary equipment. Certain other facilities associated with the project are 100 percent owned by KMI. Additional upstream compression facilities are being constructed by a KMI affiliate at two compressor stations on the Elba Express pipeline to facilitate transportation of ample feed gas for liquefaction.
- On Dec. 21, 2017, Kinder Morgan Texas Pipeline (KMTP), DCP Midstream and an affiliate of Targa Resources Corp. announced their final investment decision to proceed with the Gulf Coast Express Pipeline Project (GCX Project) after having executed definitive joint venture agreements and having secured sufficient firm transportation agreements with shippers. Approximately 85 percent of the project capacity is subscribed and committed under long-term, binding transportation agreements, and the partners expect that the remaining capacity will be subscribed by early 2018. The approximately $1.7 billion GCX Project is designed to transport up to 1.92 billion cubic feet per day (Bcf/d) of natural gas from the Permian Basin to the Agua Dulce, Texas, area. The project is expected to be in service in October 2019, pending the receipt of necessary regulatory approvals. As previously announced, KMTP will build, operate and own a 50 percent interest in the GCX Project, and DCP Midstream and Targa will each hold a 25 percent equity interest in the project. In addition to their transportation agreements, shipper Apache Corporation has an option to purchase up to a 15 percent equity stake in the project from KMI.
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On Nov. 20, 2017 and Dec. 15, 2017, the FERC issued two Certificates
of Public Convenience and Necessity to:
- Kinder Morgan Louisiana Pipeline (KMLP) for its proposed project to provide 600,000 Dth/d of capacity to serve Train 5 at Cheniere’s Sabine Pass LNG Terminal. The approximately $122 million KMLP project is expected to be placed into commercial service as early as the first quarter of 2019, earlier than initially planned, and
- TGP for its Lone Star Project. The approximately $150 million project will provide 300,000 Dth/d of capacity under a long-term contract to Cheniere’s planned Corpus Christi Liquefaction Project in South Texas and is anticipated to be placed into commercial service in January 2019.
- Construction is nearly complete on the approximately $178 million Southwest Louisiana Supply Project, and it is expected to be placed into commercial service with initial deliveries beginning in the first quarter of 2018. The project will provide 900,000 Dth/d of capacity to the Cameron LNG export facility in Cameron Parish, Louisiana.
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Three fully-subscribed TGP projects were made available for service in
the fourth quarter of 2017:
- The approximately $104 million Connecticut Expansion Project provides 72,100 Dth/d of capacity for three local distribution company customers in the Northeast. Deliveries under the long-term contracts began in the fourth quarter of 2017.
- The approximately $104 million Orion Project provides 135,000 Dth/d of capacity for three customers. Deliveries under the long-term contracts began in the fourth quarter of 2017.
- The approximately $57 million Triad Project provides 180,000 Dth/d of capacity for one customer. Deliveries under the long-term contract will begin on June 1, 2018.
- On Dec. 21, 2017, Sierrita Gas Pipeline, LLC filed a Certificate Application with the FERC for its approximately $56 million Sierrita Gas Pipeline Expansion. This expansion project will increase the Sierrita pipeline’s capacity by approximately 323,000 Dth/d to 524,000 Dth/d and consists of a new 15,900 horsepower compressor station in Pima County, Arizona. Pending regulatory approvals, the project is expected to be placed into service in the second quarter of 2020. KMI is a 35 percent owner and the operator of Sierrita Gas Pipeline.
- On Nov. 8, 2017, NGPL received a Certificate of Public Convenience and Necessity for its approximately $212 million Gulf Coast Southbound Expansion Project, and construction is underway following receipt of FERC’s Notice to Proceed. The project, which is fully subscribed under long-term contracts, is designed to transport 460,000 Dth/d of incremental firm transportation service from NGPL’s interstate pipeline interconnects in Illinois, Arkansas and Texas to points south on NGPL’s pipeline system to serve growing demand in the Gulf Coast area. The project is anticipated to be fully in service by the fourth quarter of 2018.
- On Nov. 27, 2017, the FERC approved Wyoming Interstate Company, LLC’s Offer of Settlement in a proceeding pursuant to Section 5 of the Natural Gas Act, and on Jan. 5, 2018, the FERC approved NGPL’s Offer of Settlement in a separate proceeding pursuant to Section 5 of the Natural Gas Act. These settlements will not have a material adverse impact on KMI’s results of operations or cash flows from operations.
CO2
- The approximately $66 million second phase of KMI’s Tall Cotton field project is more than 90 percent complete and the field is experiencing continued strong production results of approximately 3,000 Bbls/d of oil. 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 find high-return enhanced oil recovery projects in the current price environment across its robust portfolio of assets.
Terminals
- At the Base Line Terminal, a 50-50 joint venture crude oil merchant storage terminal being developed in Edmonton, Alberta, Canada, by KML and Keyera, construction of all major facilities is materially complete, including off-site pipe rack and bridges required to connect the terminal with the North 40 Terminal, Edmonton South Terminal, and Edmonton Rail Terminal. Commissioning of the 12-tank, 4.8 million barrel new-build facility, which is fully contracted with long-term, firm take-or-pay agreements with creditworthy customers, is underway, and the first 4 tanks were placed into service in January 2018 with the balance to be phased into service throughout the year. KMI and KML’s investment in the joint venture terminal is approximately C$398 million, including costs associated with the construction of a pipeline segment funded solely by KML. The project is forecast to be on schedule and on budget.
- Construction is complete on the Pit 11 expansion project at KMI’s Pasadena terminal. The approximately $186 million project, back-stopped by long-term commitments from existing customers, adds 2.0 million barrels of storage to KMI’s best-in-class refined products storage hub along the Houston Ship Channel.
- On Nov. 20, 2017, KMI’s American Petroleum Tankers (APT) took delivery of its final product tanker, the American Pride, from Philly Shipyard, Inc. (PSI) and later in the fourth quarter placed the vessel on-hire pursuant to a term charter agreement with a major refiner. APT’s construction program at PSI is complete following the delivery of the final tanker, bringing APT’s best-in-class fleet to 16 vessels. The entire fleet, including each of the 330,000-barrel capacity and LNG conversion-ready new-build tankers, is fixed under charter with major energy companies.
Products Pipelines
- Construction is nearing completion on the $550 million Utopia Pipeline Project, and the pipeline is expected to be placed in service in January 2018. With an initial design capacity of 50,000 Bbls/d, the 267-mile Utopia Pipeline transports 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
- On Dec. 15, 2017, KML completed its offering of cumulative redeemable minimum rate reset preferred shares, Series 3 (the “Series 3 Preferred Shares”) for aggregate gross proceeds of $250 million. KML issued 10 million Series 3 Preferred Shares with a coupon rate of 5.20 percent, including 2 million Series 3 shares issued due to the full exercise of the underwriter's option, as a result of strong investor demand. KML ended the year with no outstanding debt by carefully managing funds while seeking clarity on the remaining permitting, regulatory and judicial review processes for TMEP.
- On Dec. 4, 2017, KML announced that TMEP had made incremental progress during 2017 on permitting, regulatory condition satisfaction and land access. However the scope and pace of the permits and approvals received to date does not allow for significant additional construction to begin at this time. KML also stated that it must have a clear line of sight on the timely conclusion of the permitting and approvals processes before it will commit to full construction spending. Consistent with its primarily permitting strategy and to mitigate risk, KML set its 2018 budget assuming TMEP spend in the first part of 2018 will be focused primarily on advancing the permitting process, rather than spending at full construction levels, until KML has greater clarity on key permits, approvals and judicial reviews. KML previously announced a potential unmitigated delay to project completion of nine months (to September 2020) due primarily to the time required to file for, process and obtain necessary permits and regulatory approvals. KML indicated that the September 2020 in-service date could extend beyond September 2020, depending on progress on regulatory, permit and legal approvals, and now projects an unmitigated delay to a December 2020 in-service date. Trans Mountain continues to proceed in water work at Westridge Terminal. As of the end of the fourth quarter 2017, a cumulative C$930 million has been spent on the project.
- On Nov. 14, 2017, KML filed motions with the National Energy Board (NEB) to resolve delays as they relate to the City of Burnaby, and to establish a fair, transparent and expedited backstop process for resolving any similar delays in other provincial and municipal permitting processes. On Dec. 7, 2017, the NEB granted KML’s motion in respect to the City of Burnaby and indicated that Trans Mountain is not required to comply with two sections of the city’s bylaws, thereby allowing Trans Mountain to start work at its pipeline terminals subject to other permits or authorizations that may be required. The NEB indicated that it would release its reasons for decision at a later date. The NEB has not yet issued a decision on establishing an expedited NEB process that will backstop provincial and municipal processes.
- TMEP was approved by Order in Council on Dec. 1, 2016, with 157 conditions. The Province of British Columbia (BC) stated its approval of the Project on Jan. 11, 2017, with 37 conditions. Trans Mountain has made filings with the NEB and BC Environment with respect to all of the federal and provincial conditions required prior to general construction. The BC Environmental Assessment Office (EAO) has now released all condition filings required prior to general construction. The NEB has released sufficient approvals for proceeding with Westridge Terminal and Temporary Infrastructure work phase. Trans Mountain is now in receipt of a number of priority permits from regulatory authorities in Alberta and British Columbia, including access to British Columbia northern interior Crown lands. KML continues to make progress on approvals from the NEB, government of BC and government of Alberta. However, as of the end of 2017, even with this progress, TMEP has yet to obtain numerous provincial and municipal permits and federal condition approvals necessary for construction.
- Hearings were held in October and November 2017 related to two judicial reviews underway in the British Columbia Supreme Court with respect to the environmental certificate granted to TMEP by the province of British Columbia. Separate judicial reviews pending in the Federal Court of Appeal challenging the process leading to the federal government’s approval of TMEP were heard by the court from Oct. 2 to Oct. 13, 2017. Decisions from the courts are expected in the coming months. KMI is confident that the NEB, the Federal Government, and the BC Government properly assessed and weighed the various scientific and technical evidence through a comprehensive review process, while taking into consideration varying interests on the Project. The approvals granted followed many years of engagement and consultation with communities, Aboriginal groups and individuals.
Kinder Morgan, Inc. (NYSE: KMI) is one of the largest energy infrastructure companies in North America. It owns an interest in or operates approximately 85,000 miles of pipelines and 152 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, January 17, at www.kindermorgan.com for a LIVE webcast conference call on the company’s fourth 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 common share are presented herein.
Certain Items as used to calculate our Non-GAAP measures, 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, enactment of new tax legislation and casualty losses).
DCF is calculated by adjusting net income available to common stockholders before Certain Items for DD&A, total book and cash taxes, sustaining capital expenditures and other items. DCF is a significant performance measure useful to management and by external users of our financial statements in evaluating 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. 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 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 (net of consolidating joint venture partners’ share of DD&A) and book taxes, 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 Earnings is net income available to common stockholders before Certain Items. 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 Adjusted 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 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.
| Kinder Morgan, Inc. and Subsidiaries | ||||||||||||||||||||||
| Preliminary Consolidated Statements of Income | ||||||||||||||||||||||
| (Unaudited) | ||||||||||||||||||||||
| (In millions, except per share amounts) | ||||||||||||||||||||||
| Three Months Ended |
Year Ended |
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| December 31, |
December 31, |
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| 2017 | 2016 | 2017 | 2016 | |||||||||||||||||||
| Revenues | $ | 3,632 | $ | 3,389 | $ | 13,705 | $ | 13,058 | ||||||||||||||
| Costs, expenses and other | ||||||||||||||||||||||
| Costs of sales | 1,207 | 1,024 | 4,345 | 3,429 | ||||||||||||||||||
| Operations and maintenance | 774 | 579 | 2,472 | 2,372 | ||||||||||||||||||
| Depreciation, depletion and amortization | 564 | 557 | 2,261 | 2,209 | ||||||||||||||||||
| General and administrative | 175 | 119 | 673 | 669 | ||||||||||||||||||
| Taxes, other than income taxes | 101 | 97 | 398 | 421 | ||||||||||||||||||
| Loss on impairments and divestitures, net | — | 80 | 13 | 387 | ||||||||||||||||||
| Other income, net | (1 | ) | (1 | ) | (1 | ) | (1 | ) | ||||||||||||||
| 2,820 | 2,455 | 10,161 | 9,486 | |||||||||||||||||||
| Operating income | 812 | 934 | 3,544 | 3,572 | ||||||||||||||||||
| Other income (expense) | ||||||||||||||||||||||
| Earnings from equity investments | 101 | 154 | 578 | 497 | ||||||||||||||||||
| Loss on impairments and divestitures of equity investments, net | (150 | ) | (266 | ) | (150 | ) | (610 | ) | ||||||||||||||
| Amortization of excess cost of equity investments | (16 | ) | (14 | ) | (61 | ) | (59 | ) | ||||||||||||||
| Interest, net | (445 | ) | (422 | ) | (1,832 | ) | (1,806 | ) | ||||||||||||||
| Other, net | 22 | 2 | 82 | 44 | ||||||||||||||||||
| Income before income taxes | 324 | 388 | 2,161 | 1,638 | ||||||||||||||||||
| Income tax expense | (1,316 | ) | (173 | ) | (1,938 | ) | (917 | ) | ||||||||||||||
| Net (loss) income | (992 | ) | 215 | 223 | 721 | |||||||||||||||||
| Net income attributable to noncontrolling interests | (14 | ) | (6 | ) | (40 | ) | (13 | ) | ||||||||||||||
| Net (loss) income attributable to Kinder Morgan, Inc. | (1,006 | ) | 209 | 183 | 708 | |||||||||||||||||
| Preferred stock dividends | (39 | ) | (39 | ) | (156 | ) | (156 | ) | ||||||||||||||
| Net (loss) income available to common stockholders | $ | (1,045 | ) | $ | 170 | $ | 27 | $ | 552 | |||||||||||||
| Class P Shares | ||||||||||||||||||||||
| Basic and diluted (loss) earnings per common share | $ | (0.47 | ) | $ | 0.08 | $ | 0.01 | $ | 0.25 | |||||||||||||
| Basic and diluted weighted average common shares outstanding | 2,229 | 2,230 | 2,230 | 2,230 | ||||||||||||||||||
| Declared dividend per common share | $ | 0.125 | $ | 0.125 | $ | 0.500 | $ | 0.500 | ||||||||||||||
| Adjusted earnings per common share (1) | $ | 0.21 | $ | 0.18 | $ | 0.66 | $ | 0.66 | ||||||||||||||
| Segment EBDA |
% |
% |
||||||||||||||||||||
| Natural Gas Pipelines | $ | 641 | $ | 708 | (9 | )% | $ | 3,487 | $ | 3,211 | 9 | % | ||||||||||
| CO2 | 211 | 219 | (4 | )% | 847 | 827 | 2 | % | ||||||||||||||
| Terminals | 299 | 222 | 35 | % | 1,224 | 1,078 | 14 | % | ||||||||||||||
| Products Pipelines | 318 | 306 | 4 | % | 1,231 | 1,067 | 15 | % | ||||||||||||||
| Kinder Morgan Canada | 50 | 41 | 22 | % | 186 | 181 | 3 | % | ||||||||||||||
| Total Segment EBDA | $ | 1,519 | $ | 1,496 | 2 | % | $ | 6,975 | $ | 6,364 | 10 | % | ||||||||||
|
Note |
|
| (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. |
| Kinder Morgan, Inc. and Subsidiaries | ||||||||||||||||||||||
| Preliminary Earnings Contribution by Business Segment | ||||||||||||||||||||||
| (Unaudited) | ||||||||||||||||||||||
| (In millions, except per share amounts) | ||||||||||||||||||||||
| Three Months Ended | Year Ended | |||||||||||||||||||||
| December 31, | December 31, | |||||||||||||||||||||
| 2017 | 2016 |
% |
2017 | 2016 |
% |
|||||||||||||||||
| Segment EBDA before certain items (1) | ||||||||||||||||||||||
| Natural Gas Pipelines | $ | 1,027 | $ | 986 | 4 | % | $ | 3,879 | $ | 4,036 | (4 | )% | ||||||||||
| CO2 | 228 | 238 | (4 | )% | 887 | 919 | (3 | )% | ||||||||||||||
| Terminals | 317 | 305 | 4 | % | 1,214 | 1,169 | 4 | % | ||||||||||||||
| Product Pipelines | 314 | 307 | 2 | % | 1,193 | 1,180 | 1 | % | ||||||||||||||
| Kinder Morgan Canada | 50 | 41 | 22 | % | 186 | 181 | 3 | % | ||||||||||||||
| Subtotal | 1,936 | 1,877 | 3 | % | 7,359 | 7,485 | (2 | )% | ||||||||||||||
| DD&A and amortization of excess investments | (580 | ) | (571 | ) | (2,322 | ) | (2,268 | ) | ||||||||||||||
| General and administrative and corporate charges (1) (2) | (163 | ) | (152 | ) | (645 | ) | (665 | ) | ||||||||||||||
| Interest, net (1) | (463 | ) | (475 | ) | (1,871 | ) | (1,999 | ) | ||||||||||||||
| Subtotal | 730 | 679 | 2,521 | 2,553 | ||||||||||||||||||
| Book taxes (1) | (207 | ) | (225 | ) | (853 | ) | (899 | ) | ||||||||||||||
| Certain items | ||||||||||||||||||||||
| Acquisition and divestiture related costs | (1 | ) | (1 | ) | (8 | ) | (13 | ) | ||||||||||||||
| Fair value amortization | 11 | 37 | 53 | 143 | ||||||||||||||||||
| Contract and debt early termination (3) | — | — | 19 | 53 | ||||||||||||||||||
| Legal and environmental reserves (4) | (6 | ) | 71 | 37 | 16 | |||||||||||||||||
| Change in fair market value of derivative contracts (5) | (13 | ) | (52 | ) | (40 | ) | (75 | ) | ||||||||||||||
| Losses on impairments and divestitures, net | (157 | ) | (343 | ) | (170 | ) | (848 | ) | ||||||||||||||
| Project write-offs (6) | — | (1 | ) | — | (171 | ) | ||||||||||||||||
| Hurricane damage | (18 | ) | — | (27 | ) | — | ||||||||||||||||
| Other | (3 | ) | (2 | ) | (5 | ) | (20 | ) | ||||||||||||||
| Subtotal certain items before tax | (187 | ) | (291 | ) | (141 | ) | (915 | ) | ||||||||||||||
| Book tax certain items (7) | 53 | 52 | 77 | (18 | ) | |||||||||||||||||
| Impact of 2017 Tax Cuts and Jobs Act | (1,381 | ) | — | (1,381 | ) | — | ||||||||||||||||
| Total certain items | (1,515 | ) | (239 | ) | (1,445 | ) | (933 | ) | ||||||||||||||
| Net (loss) income | (992 | ) | 215 | 223 | 721 | |||||||||||||||||
| Net income attributable to noncontrolling interests | (14 | ) | (6 | ) | (40 | ) | (13 | ) | ||||||||||||||
| Preferred stock dividends | (39 | ) | (39 | ) | (156 | ) | (156 | ) | ||||||||||||||
| Net (loss) income available to common stockholders | $ | (1,045 | ) | $ | 170 | $ | 27 | $ | 552 | |||||||||||||
| Net (loss) income available to common stockholders | $ | (1,045 | ) | $ | 170 | $ | 27 | $ | 552 | |||||||||||||
| Total certain items | 1,515 | 239 | 1,445 | 933 | ||||||||||||||||||
| Noncontrolling interests certain item (8) | (1 | ) | 1 | — | (8 | ) | ||||||||||||||||
| Adjusted earnings | 469 | 410 | 1,472 | 1,477 | ||||||||||||||||||
| DD&A and amortization of excess investments (9) | 666 | 656 | 2,684 | 2,617 | ||||||||||||||||||
| Total book taxes (10) | 232 | 248 | 957 | 993 | ||||||||||||||||||
| Cash taxes (11) | (18 | ) | (18 | ) | (72 | ) | (79 | ) | ||||||||||||||
| Other items (12) | 13 | 12 | 29 | 43 | ||||||||||||||||||
| Sustaining capital expenditures (13) | (172 | ) | (161 | ) | (588 | ) | (540 | ) | ||||||||||||||
| DCF | $ | 1,190 | $ | 1,147 | $ | 4,482 | $ | 4,511 | ||||||||||||||
| Weighted average common shares outstanding for dividends (14) | 2,239 | 2,239 | 2,240 | 2,238 | ||||||||||||||||||
| DCF per common share | $ | 0.53 | $ | 0.51 | $ | 2.00 | $ | 2.02 | ||||||||||||||
| Declared dividend per common share | $ | 0.125 | $ | 0.125 | $ | 0.500 | $ | 0.500 | ||||||||||||||
| Adjusted EBITDA (15) | $ | 1,896 | $ | 1,829 | $ | 7,198 | $ | 7,242 | ||||||||||||||
|
Notes ($ million) |
|
| (1) | Excludes certain items: |
| 4Q 2017 - Natural Gas Pipelines $(386), CO2 $(17), Terminals $(18), Products Pipelines $4, general and administrative and corporate charges $(7), interest expense $18, book tax $(1,109). | |
| 4Q 2016 - Natural Gas Pipelines $(278), CO2 $(19), Terminals $(83), Products Pipelines $(1), general and administrative and corporate charges $37, interest expense $53, book tax $52. | |
| YTD 2017 - Natural Gas Pipelines $(392), CO2 $(40), Terminals $10, Products Pipelines $38, general and administrative and corporate charges $(15), interest expense $39, book tax $(1,085). | |
| YTD 2016 - Natural Gas Pipelines $(825), CO2 $(92), Terminals $(91), Products Pipelines $(113), general and administrative and corporate charges $13, interest expense $193, book tax $(18). | |
| (2) | Includes corporate charges: |
| 4Q 2017 - $4 | |
| 4Q 2016 - $5 | |
| YTD 2017 - $22 | |
| YTD 2016 - $17 | |
| General and administrative expense is also net of management fee revenues from an equity investee: | |
| 4Q 2017 - $(9) | |
| 4Q 2016 - $(9) | |
| YTD 2017 - $(35) | |
| YTD 2016 - $(34) | |
| (3) | Comprised of earnings recognized related to the early termination of customer contracts, including earnings from the sale of a contract termination claim related to a customer bankruptcy, partially offset by an equity investee loss on early termination of debt. |
| (4) | Legal reserve adjustments related to certain litigation and environmental matters. |
| (5) | Gains or losses are reflected in our DCF when realized. |
| (6) | YTD 2016 includes $106 million of project write-offs associated with our Northeast Energy Direct Market project and $65 million of write-offs associated with our Palmetto project. |
| (7) | YTD 2017 includes a $36 million federal return-to-provision tax benefit as a result of the recognition of an enhanced oil recovery credit instead of deduction. YTD 2016 includes 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. |
| (8) | Represents noncontrolling interest share of certain items. |
| (9) | Includes KMI's share of certain equity investees' DD&A, net of the noncontrolling interests' portion of KML DD&A and consolidating joint venture partners' share of DD&A: |
| 4Q 2017 - $86 | |
| 4Q 2016 - $85 | |
| YTD 2017 - $362 | |
| YTD 2016 - $349 | |
| (10) | Excludes book tax certain items. Also, includes KMI's share of taxable equity investees' book taxes, net of the noncontrolling interests' portion of KML book taxes: |
| 4Q 2017 - $25 | |
| 4Q 2016 - $23 | |
| YTD 2017 - $104 | |
| YTD 2016 - $94 | |
| (11) | Includes KMI's share of taxable equity investees' cash taxes: |
| 4Q 2017 - $(15) | |
| 4Q 2016 - $(17) | |
| YTD 2017 - $(69) | |
| YTD 2016 - $(76) | |
| (12) | All periods include non-cash compensation associated with our restricted stock program. 2017 also includes a pension contribution. |
| (13) | Includes KMI's share of certain equity investees' sustaining capital expenditures (the same equity investees for which DD&A is added back): |
| 4Q 2017 - $(33) | |
| 4Q 2016 - $(24) | |
| YTD 2017 - $(107) | |
| YTD 2016 - $(90) | |
| (14) | Includes restricted stock awards that participate in common share dividends. |
| (15) | Net (loss) income is reconciled to Adjusted EBITDA as follows, with any difference due to rounding: |
| Three Months Ended | Year Ended | ||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||||||
| Net (loss) income | $ | (992 | ) | $ | 215 | $ | 223 | $ | 721 | ||||||||||
| Total certain items | 1,515 | 239 | 1,445 | 933 | |||||||||||||||
| Net income attributable to noncontrolling interests before certain items (16) | (1 | ) | (5 | ) | (12 | ) | (21 | ) | |||||||||||
| DD&A and amortization of excess investments (9) (17) | 674 | 657 | 2,704 | 2,617 | |||||||||||||||
| Book taxes (10) (17) | 237 | 248 | 967 | 993 | |||||||||||||||
| Interest, net (1) | 463 | 475 | 1,871 | 1,999 | |||||||||||||||
| Adjusted EBITDA | $ | 1,896 | $ | 1,829 | $ | 7,198 | $ | 7,242 | |||||||||||
| (16) | Excludes KML noncontrolling interests: | ||||||||||||||||||
| 4Q 2017 - $13 | |||||||||||||||||||
| YTD 2017 - $27 | |||||||||||||||||||
| (17) | Includes the noncontrolling interests' portion of KML: | ||||||||||||||||||
| 4Q 2017 - DD&A $8; Book taxes $5 | |||||||||||||||||||
| YTD 2017 - DD&A $20; Book taxes $10 | |||||||||||||||||||
| Volume Highlights | ||||||||||||||||
| (historical pro forma for acquired and divested assets) | ||||||||||||||||
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| Natural Gas Pipelines | ||||||||||||||||
| Transport Volumes (BBtu/d) (1) | 30,033 | 27,897 | 29,108 | 28,095 | ||||||||||||
| Sales Volumes (BBtu/d) (2) | 2,375 | 2,288 | 2,341 | 2,335 | ||||||||||||
| Gas Gathering Volumes (BBtu/d) (3) | 2,704 | 2,749 | 2,653 | 2,970 | ||||||||||||
| Crude/Condensate Gathering Volumes (MBbl/d) (4) | 286 | 265 | 273 | 292 | ||||||||||||
| CO2 | ||||||||||||||||
| Southwest Colorado Production - Gross (Bcf/d) (5) | 1.28 | 1.27 | 1.29 | 1.20 | ||||||||||||
| Southwest Colorado Production - Net (Bcf/d) (5) | 0.59 | 0.65 | 0.61 | 0.61 | ||||||||||||
| Sacroc Oil Production - Gross (MBbl/d) (6) | 28.35 | 28.13 | 27.88 | 29.32 | ||||||||||||
| Sacroc Oil Production - Net (MBbl/d) (7) | 23.61 | 23.43 | 23.22 | 24.43 | ||||||||||||
| Yates Oil Production - Gross (MBbl/d) (6) | 17.00 | 17.91 | 17.34 | 18.37 | ||||||||||||
| Yates Oil Production - Net (MBbl/d) (7) | 7.44 | 7.96 | 7.67 | 8.17 | ||||||||||||
| Katz, Goldsmith, and Tall Cotton Oil Production - Gross (MBbl/d) (6) | 8.76 | 7.45 | 8.10 | 7.01 | ||||||||||||
| Katz, Goldsmith, and Tall Cotton Oil Production - Net (MBbl/d) (7) | 7.43 | 6.27 | 6.86 | 5.90 | ||||||||||||
| NGL Sales Volumes (MBbl/d) (8) | 10.12 | 10.46 | 9.94 | 10.31 | ||||||||||||
| Realized Weighted Average Oil Price per Bbl (9) | $ | 59.32 | $ | 62.30 | $ | 58.40 | $ | 61.52 | ||||||||
| Realized Weighted Average NGL Price per Bbl | $ | 28.81 | $ | 22.25 | $ | 25.15 | $ | 17.91 | ||||||||
| Terminals | ||||||||||||||||
| Liquids Leasable Capacity (MMBbl) | 87.9 | 84.7 | 87.9 | 84.7 | ||||||||||||
| Liquids Utilization % | 93.6 | % | 94.7 | % | 93.6 | % | 94.7 | % | ||||||||
| Bulk Transload Tonnage (MMtons) (10) | 15.0 | 13.7 | 59.5 | 54.8 | ||||||||||||
| Ethanol (MMBbl) | 16.8 | 17.8 | 68.1 | 66.7 | ||||||||||||
| Products Pipelines | ||||||||||||||||
| Pacific, Calnev, and CFPL (MBbl/d) | ||||||||||||||||
| Gasoline (11) | 807 | 781 | 811 | 795 | ||||||||||||
| Diesel | 308 | 280 | 298 | 292 | ||||||||||||
| Jet Fuel | 263 | 251 | 264 | 255 | ||||||||||||
| Sub-Total Refined Product Volumes - excl. Plantation | 1,378 | 1,312 | 1,374 | 1,342 | ||||||||||||
| Plantation (MBbl/d) (12) | ||||||||||||||||
| Gasoline | 221 | 234 | 227 | 230 | ||||||||||||
| Diesel | 56 | 48 | 53 | 50 | ||||||||||||
| Jet Fuel | 33 | 34 | 33 | 34 | ||||||||||||
| Sub-Total Refined Product Volumes - Plantation | 310 | 315 | 312 | 313 | ||||||||||||
| Total (MBbl/d) | ||||||||||||||||
| Gasoline (11) | 1,028 | 1,015 | 1,038 | 1,025 | ||||||||||||
| Diesel | 364 | 328 | 351 | 342 | ||||||||||||
| Jet Fuel | 296 | 284 | 297 | 288 | ||||||||||||
| Total Refined Product Volumes | 1,689 | 1,627 | 1,686 | 1,655 | ||||||||||||
| NGLs (MBbl/d) (13) | 113 | 117 | 112 | 109 | ||||||||||||
| Crude and Condensate (MBbl/d) (14) | 339 | 333 | 327 | 324 | ||||||||||||
| Total Delivery Volumes (MBbl/d) | 2,141 | 2,078 | 2,125 | 2,088 | ||||||||||||
| Ethanol (MBbl/d) (15) | 119 | 113 | 117 | 115 | ||||||||||||
| Trans Mountain (MMBbl/d - mainline throughput) | 303 | 295 | 308 | 316 | ||||||||||||
|
Notes |
|
| (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) | Includes Texas Intrastates and KMNTP. |
| (3) | 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. |
| (4) | Includes Hiland Midstream, EagleHawk, and Camino Real. Joint Venture throughput reported at KMI share. |
| (5) | Includes McElmo Dome and Doe Canyon sales volumes. |
| (6) | Represents 100% production from the field. |
| (7) | Represents KMI's net share of the production from the field. |
| (8) | Net to KMI. |
| (9) | Includes all KMI crude oil properties. |
| (10) | Includes KMI's share of Joint Venture tonnage. |
| (11) | Gasoline volumes include ethanol pipeline volumes. |
| (12) | Plantation reported at KMI share. |
| (13) | Includes Cochin and Cypress (KMI share). |
| (14) | Includes KMCC, Double Eagle (KMI share), and Double H. |
| (15) | Total ethanol handled including pipeline volumes included in gasoline volumes above. |
| Kinder Morgan, Inc. and Subsidiaries | ||||||||
| Preliminary Consolidated Balance Sheets | ||||||||
| (Unaudited) | ||||||||
| (In millions) | ||||||||
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| ASSETS | ||||||||
| Cash and cash equivalents | $ | 264 | $ | 684 | ||||
| Other current assets | 2,451 | 2,545 | ||||||
| Property, plant and equipment, net | 40,155 | 38,705 | ||||||
| Investments | 7,298 | 7,027 | ||||||
| Goodwill | 22,162 | 22,152 | ||||||
| Deferred charges and other assets | 6,725 | 9,192 | ||||||
| TOTAL ASSETS | $ | 79,055 | $ | 80,305 | ||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
| Liabilities | ||||||||
| Short-term debt | $ | 2,828 | $ | 2,696 | ||||
| Other current liabilities | 3,353 | 3,228 | ||||||
| Long-term debt | 33,988 | 36,105 | ||||||
| Preferred interest in general partner of KMP | 100 | 100 | ||||||
| Debt fair value adjustments | 927 | 1,149 | ||||||
| Other | 2,735 | 2,225 | ||||||
| Total liabilities | 43,931 | 45,503 | ||||||
| Shareholders’ Equity | ||||||||
| KMI equity | 33,636 | 34,431 | ||||||
| Noncontrolling interests | 1,488 | 371 | ||||||
| Total shareholders' equity | 35,124 | 34,802 | ||||||
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 79,055 | $ | 80,305 | ||||
| Net Debt (1) | $ | 36,409 | $ | 38,160 | ||||
| Net Debt including 50% of KML preferred shares (2) | 36,624 | 38,160 | ||||||
| Adjusted EBITDA | ||||||||
| Twelve Months Ended | ||||||||
| December 31, | ||||||||
| Reconciliation of Net Income to Adjusted EBITDA | 2017 | 2016 | ||||||
| Net income | $ | 223 | $ | 721 | ||||
| Total certain items | 1,445 | 933 | ||||||
| Net income attributable to noncontrolling interests before certain items (3) | (12 | ) | (21 | ) | ||||
| DD&A and amortization of excess investments (4) | 2,704 | 2,617 | ||||||
| Income tax expense before certain items (5) | 967 | 993 | ||||||
| Interest, net before certain items | 1,871 | 1,999 | ||||||
| Adjusted EBITDA | $ | 7,198 | $ | 7,242 | ||||
| Net Debt including 50% of KML preferred shares to Adjusted EBITDA | 5.1 | 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 $143 million and $(43) million as of December 31, 2017 and 2016, respectively, as we have entered into swaps to convert that debt to U.S.$. | |
| (2) | December 31, 2017 amount includes $215 million representing 50% of KML preferred shares which is included in noncontrolling interests. | |
| (3) | 2017 excludes KML noncontrolling interests of $27 million. | |
| (4) | 2017 and 2016 include KMI's share of certain equity investees' DD&A of $382 million and $349 million, respectively. | |
| (5) | 2017 and 2016 include KMI's share of taxable equity investees' book taxes of $114 million and $94 million, respectively. | |
