Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

140K characters. Original on sec.gov · Markdown

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto. We prepared our consolidated financial statements in accordance with GAAP. Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Business Strategy;” (ii) a description of developments during 2017, found in Items 1 and 2 “Business and Properties—(a) General Development of Business—Recent Developments;” and (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors.”

Inasmuch as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements. These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management’s judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in Item 1A “Risk Factors” and at the beginning of this report in “Information Regarding Forward-Looking Statements.”

General

Our business model, through our ownership and operation of energy related assets, is built to support two principal objectives:

•helping customers by providing safe and reliable natural gas, liquids products and bulk commodity transportation, storage and distribution; and
•creating long-term value for our shareholders.

To achieve these objectives, we focus on providing fee-based services to customers from a business portfolio consisting of energy-related pipelines, natural gas storage, processing and treating facilities, and bulk and liquids terminal facilities. We also produce and sell crude oil. Our reportable business segments are based on the way our management organizes our enterprise, and each of our business segments represents a component of our enterprise that engages in a separate business activity and for which discrete financial information is available.

Our reportable business segments are:

•Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG facilities;
•CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium for recovering crude oil from mature oil fields to increase production; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas;
•Terminals—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, chemicals, and ethanol and bulk products, including petroleum coke, steel and coal; and (ii) Jones Act tankers;
•Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, propane, ethane, crude oil and condensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; and
•Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport.

As an energy infrastructure owner and operator in multiple facets of the various U.S. and Canadian energy industries and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future.

With respect to our interstate natural gas pipelines, related storage facilities and LNG terminals, the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended periods of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. These long-term contracts are typically structured with a fixed-fee reserving the right to transport or store natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity. Similarly, the Texas Intrastate Natural Gas Pipeline operations, currently derives approximately 76% of its sales and transport margins from long-term transport and sales contracts. As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As of December 31, 2017, the remaining weighted average contract life of our natural gas transportation contracts (including intrastate pipelines’ terminal sales portfolio) was approximately six years.

Our midstream assets provide gathering and processing services for natural gas and gathering services for crude oil. These assets are mostly fee-based and the revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into their base components, are affected by the volumes of natural gas made available to our systems. Such volumes are impacted by producer rig count and drilling activity. In addition to fee based arrangements, some of which may include minimum volume commitments, we also provide some services based on percent-of-proceeds, percent-of-index and keep-whole contracts. Our service contracts may rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices.

The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2017, had a remaining average contract life of approximately eight years. CO2 sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed. Our recent contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price. On a volume-weighted basis, for third-party contracts making deliveries in 2018, and utilizing the average oil price per barrel contained in our 2018 budget, approximately 97% of our revenue is based on a fixed fee or floor price, and 3% fluctuates with the price of oil. In the long-term, our success in this portion of the CO2 business segment is driven by the demand for CO2. However, short-term changes in the demand for CO2 typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts. In the CO2 business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. In that regard, our production during any period is an important measure. In addition, the revenues we receive from our crude oil, NGL and CO2 sales are affected by the prices we realize from the sale of these products. Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products. In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program, in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil. The realized weighted average crude oil price per barrel, with the hedges allocated to oil, was $58.40 per barrel in 2017, $61.52 per barrel in 2016 and $73.11 per barrel in 2015. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $49.61 per barrel in 2017, $41.36 per barrel in 2016 and $47.56 per barrel in 2015.

The factors impacting our Terminals business segment generally differ between terminals and tankers and depending on whether the terminal is a liquids or bulk terminal, and in the case of a bulk terminal, the type of product being handled or stored. Our liquids terminals business generally has long-term contracts that require the customer to pay regardless of whether they use the capacity. Thus, similar to our natural gas pipeline business, our liquids terminals business is less sensitive to short-term changes in supply and demand. Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of the length of the underlying service contracts (which on average is approximately three years), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time. As with our refined petroleum products pipeline transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored. While we handle and store a large variety of products in our bulk terminals, the primary products are steel, coal and petroleum coke. For the most part, we have contracts for this business that contain minimum volume guarantees and/or service exclusivity arrangements under which customers are required to utilize our terminals for all or a specified percentage of their handling and storage needs. The profitability of our minimum volume contracts is generally unaffected by short-term variation in economic

conditions; however, to the extent we expect volumes above the minimum and/or have contracts which are volume-based we can be sensitive to changing market conditions. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. In addition, weather-related factors such as hurricanes, floods and droughts may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods. In addition to liquid and bulk terminals, we also own Jones Act tankers. As of December 31, 2017, we have sixteen Jones Act qualified tankers that operate in the marine transportation of crude oil, condensate and refined products in the U.S. and are currently operating pursuant to multi-year fixed price charters with major integrated oil companies, major refiners and the U.S. Military Sealift Command.

The profitability of our refined petroleum products pipeline transportation and storage business is generally driven by the volume of refined petroleum products that we transport and the prices we receive for our services. We also have approximately 51 liquids terminals in this business segment that store fuels and offer blending services for ethanol and biofuels. The transportation and storage volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored. Demand for refined petroleum products tends to track in large measure demographic and economic growth, and with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable. Because of that, we seek to own refined petroleum products pipelines located in, or that transport to, stable or growing markets and population centers. The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index.

Our crude and condensate transportation services are primarily provided either pursuant to (i) long-term contracts that normally contain minimum volume commitments or (ii) through terms prescribed by the toll settlements with shippers and approved by regulatory authorities. As a result of these contracts, our settlement volumes are generally not sensitive to changing market conditions in the shorter term, however, in the longer term the revenues and earnings we realize from our crude and condensate pipelines in the U.S. and Canada are affected by the volumes of crude and condensate available to our pipeline systems, which are impacted by the level of oil and gas drilling activity in the respective producing regions that we serve. Our petroleum condensate processing facility splits condensate into its various components, such as light and heavy naphtha, under a long-term fee-based agreement with a major integrated oil company.

KML

The interest in the Canadian business operations that we sold to the public on May 30, 2017 in KML’s IPO represented an interest in all our operating assets in our Kinder Morgan Canada business segment and our operating Canadian assets in our Terminals and Products Pipelines business segments. These Canadian assets include the Trans Mountain pipeline system (including related terminaling assets), the TMEP, the Puget Sound and Jet Fuel pipeline systems, the Canadian portion of the Cochin pipeline system, the Vancouver Wharves Terminal and the North 40 Terminal; as well as three jointly controlled investments: the Edmonton Rail Terminal, the Alberta Crude Terminal and the Base Line Terminal.

Subsequent to the IPO, we retained control of KML, and as a result, it remains consolidated in our consolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in our consolidated statements of stockholders’ equity and consolidated balance sheets. Earnings attributable to the public ownership of KML are presented in “Net income attributable to noncontrolling interests” in our consolidated statements of income for the periods presented after May 30, 2017. KML transacts in and/or uses the Canadian dollar as the functional currency, which affects segment results due to the variability in U.S. - Canadian dollar exchange rates.

Subsequent to its IPO, KML has obtained a credit facility and completed two preferred share offerings. KMI expects KML to be a self-funding entity and does not anticipate making contributions to fund its growth or specifically to fund the TMEP.

TMEP Permitting and Construction Progress

TMEP was approved by Order in Council on December 1, 2016, with 157 conditions. The Province of British Columbia (BC) stated its approval of the TMEP on January 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 the 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 BC, including access to BC 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.

On December 4, 2017, KML announced that, while TMEP had made incremental progress during 2017 on permitting, regulatory condition satisfaction and land access, the scope and pace of the permits and approvals received to date did not allow for significant additional construction to begin at that 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 would 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 would 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. In its January 17, 2018 earnings press release, KML announced a potential unmitigated delay to project completion of one year (to December 2020) primarily due to the time required to file for, process and obtain necessary permits and regulatory approvals. As stated in Trans Mountain's November 14, 2017 motion to the NEB discussed below, "it is critical for Trans Mountain to have certainty that once started, the TMEP can confidently be completed on schedule." The TMEP projected in service date remains subject to change due to risks and uncertainties described in “Information Regarding Forward-Looking Statements,” “Item 1A, Risk Factors,” elsewhere in this Item 7, and in Note 17 to our consolidated financial statements under the heading “TMEP Litigation.” Further, as stated in KML’s January 17, 2018 earnings press release, if TMEP continues to be "faced with unreasonable regulatory risks due to a lack of clear processes to secure necessary permits . . . it may become untenable for Trans Mountain's shareholders . . . to proceed." Trans Mountain continues to proceed in water work at the Westridge Terminal.

On October 26 and November 14, 2017, KML filed motions with the 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 December 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. On January 18, 2018, the NEB issued its reasons for decision on the Burnaby motion and granted in part Trans Mountain’s motion for a backstop process, establishing a generic process to hear any future motions as they relate to provincial and municipal permitting issues.

Hearings were held in October and November 2017 related to two judicial reviews underway in the BC Supreme Court with respect to the environmental certificate granted to TMEP by the province of BC. 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 October 2 to October 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 TMEP. The approvals granted followed many years of engagement and consultation with communities, Aboriginal groups and individuals.

As of the end of the fourth quarter 2017, a cumulative C$930 million has been spent on the TMEP. KML’s estimated total cost for the TMEP is C$7.4 billion (C$6.7 billion excluding capitalized equity financing costs). Construction related delays could result in increases to the estimated total costs; however, because the extent of the delay remains uncertain, KML has not updated its cost estimate at this time.

2017 Tax Reform

While the recently enacted 2017 Tax Reform will ultimately be moderately positive for us, the reduced corporate income tax rate caused certain of our deferred-tax assets to be revalued at 21 percent versus 35 percent at the end of 2017. Although there is no impact to the underlying related deductions, which can continue to be used to offset future taxable income, we took an estimated approximately $1.4 billion non-cash accounting charge in the fourth quarter of 2017. This charge is our initial estimate and may be refined in the future as permitted by recent guidance from the SEC and FASB. The positive impacts of the law include the reduced corporate income tax rate and the fact that several of our U.S. business units (essentially all but our interstate natural gas pipelines) will be able to deduct 100 percent of their capital expenditures through 2022. The net impact results in postponing the date when we become a significant federal cash taxpayer by approximately one year, to beyond 2024.

We continue to assess the impact of the 2017 Tax Reform on our business in order to complete our analysis. Any adjustment to our provisional amount recorded during the year ended December 31, 2017 will be reported in the reporting period in which any such adjustments are determined and may be material in the period in which the adjustments are made. See Note 5 “Income Taxes” to our consolidated financial statements.

Critical Accounting Policies and Estimates

Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of GAAP involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining: (i) revenue recognition and income taxes, (ii) the economic useful lives of our assets and related depletion rates; (iii) the fair values used to (a) assign purchase price from business combinations, (b) determine possible asset and equity investment impairment charges, and (c) calculate the annual goodwill impairment test; (iv) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (v) provisions for uncollectible accounts receivables; and (vi) exposures under contractual indemnifications.

For a summary of our significant accounting policies, see Note 2 “Summary of Significant Accounting Policies” to our consolidated financial statements. We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed as follows.

Acquisition Method of Accounting

For acquired businesses, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition. Determining the fair value of these items requires management’s judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. For more information on our acquisitions and application of the acquisition method, see Note 3 “Acquisitions and Divestitures” to our consolidated financial statements.

Environmental Matters

With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, we do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at fair value, where appropriate, environmental liabilities assumed in a business combination.

Our recording of our environmental accruals often coincides with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations. These adjustments may result in increases in environmental expenses and are primarily related to quarterly reviews of potential environmental issues and resulting environmental liability estimates. In making these liability estimations, we consider the effect of environmental compliance, pending legal actions against us, and potential third party liability claims. For more information on environmental matters, see PART I, Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Environmental Matters.” For more information on our environmental disclosures, see Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.

Legal and Regulatory Matters

Many of our operations are regulated by various U.S. and Canadian regulatory bodies and we are subject to legal and regulatory matters as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify contingent liabilities, we identify a range of possible costs expected to be required to resolve the matter. Generally, if no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on legal proceedings, see Note 17 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.

Intangible Assets

Intangible assets are those assets which provide future economic benefit but have no physical substance. Identifiable intangible assets having indefinite useful economic lives, including goodwill, are not subject to regular periodic amortization, and such assets are not to be amortized until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We evaluate goodwill for impairment on May 31 of each year. At year end and during other interim periods we evaluate our reporting units for events and changes that could indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount.

Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets. These intangible assets have definite lives, are being amortized in a systematic and rational manner over their estimated useful lives, and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets.

Hedging Activities

We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices, foreign currency exposure on Euro denominated debt, and to balance our exposure to fixed and variable interest rates, and we believe that these hedges are generally effective in realizing these objectives. According to the provisions of GAAP, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged, and any ineffective portion of the hedge gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately.

All of our derivative contracts are recorded at estimated fair value. We utilize published prices, broker quotes, and estimates of market prices to estimate the fair value of these contracts; however, actual amounts could vary materially from estimated fair values as a result of changes in market prices. In addition, changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. For more information on our hedging activities, see Note 14 “Risk Management” to our consolidated financial statements.

Employee Benefit Plans

We reflect an asset or liability for our pension and other postretirement benefit plans based on their overfunded or underfunded status. As of December 31, 2017, our pension plans were underfunded by $686 million and our other postretirement benefits plans were underfunded by $90 million. Our pension and other postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. We utilize a full yield curve approach in the estimation of the service and interest cost components of net periodic benefit cost (credit) for our pension and other postretirement benefit plans which applies the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The selection of these assumptions is further discussed in Note 10 “Share-based Compensation and Employee Benefits” to our consolidated financial statements.

Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and other postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants, or over the expected future lives of inactive plan participants. As of December 31, 2017, we had deferred net losses of approximately $547 million in pretax accumulated other comprehensive loss and noncontrolling interests related to our pension and other postretirement benefits.

The following table shows the impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended December 31, 2017:

Pension BenefitsOther Postretirement Benefits
Net benefit cost (income)Change in funded status(a)Net benefit cost (income)Change in funded status(a)
(In millions)
One percent increase in:
Discount rates$(13)$252$(1)$33
Expected return on plan assets(21)—(3)—
Rate of compensation increase4(13)——
Health care cost trends——3(24)
One percent decrease in:
Discount rates15(299)1(38)
Expected return on plan assets21—3—
Rate of compensation increase(3)13——
Health care cost trends——(3)21
(a)Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations.

Income Taxes

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.

Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance for the amount that is more likely than not to not be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached.

In determining the deferred income tax asset and liability balances attributable to our investments, we apply an accounting policy that looks through our investments. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments.

Results of Operations

Overview

Our management evaluates our performance primarily using the measures of Segment EBDA and, as discussed below under “—Non-GAAP Measures,” DCF, and Segment EBDA before certain items. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses, interest expense, net, and income taxes. Our general and administrative expenses include such items as employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

In our discussions of the operating results of individual businesses that follow, we generally identify the important fluctuations between periods that are attributable to acquisitions and dispositions separately from those that are attributable to businesses owned in both periods.

Consolidated Earnings Results

Year Ended December 31,
201720162015
(In millions)
Segment EBDA(a)
Natural Gas Pipelines$3,487$3,211$3,067
CO2847827658
Terminals1,2241,078878
Products Pipelines1,2311,0671,106
Kinder Morgan Canada186181182
Total segment EBDA(b)6,9756,3645,891
DD&A(2,261)(2,209)(2,309)
Amortization of excess cost of equity investments(61)(59)(51)
General and administrative and corporate charges(c)(660)(652)(708)
Interest, net(d)(1,832)(1,806)(2,051)
Income before income taxes2,1611,638772
Income tax expense(e)(1,938)(917)(564)
Net income223721208
Net (income) loss attributable to noncontrolling interests(40)(13)45
Net income attributable to Kinder Morgan, Inc.183708253
Preferred Stock Dividends(156)(156)(26)
Net Income Available to Common Stockholders$27$552$227
(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, other expense (income), net, losses on impairments of goodwill, losses on impairments and divestitures, net and losses on impairments and divestitures of equity investments, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

Certain items affecting Total Segment EBDA (see “—Non-GAAP Measures” below)

(b)2017, 2016 and 2015 amounts include decreases in earnings of $384 million, $1,121 million and $1,748 million, respectively, related to the combined net effect of the certain items impacting Total Segment EBDA. The extent to which these items affect each of our business segments is discussed below in the footnotes to the tables within “—Segment Earnings Results.”
(c)2017, 2016 and 2015 amounts include an increase to expense of $15 million, a decrease to expense of $13 million and an increase to expense of $60 million, respectively, related to the combined net effect of the certain items related to general and administrative and corporate charges disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”
(d)2017, 2016 and 2015 amounts include decreases in expense of $39 million, $193 million and $27 million, respectively, related to the combined net effect of the certain items related to interest expense, net disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”
(e)2017, 2016 and 2015 amounts include increases in expense of $1,085 million and $18 million and a decrease in expense of $340 million, respectively, related to the combined net effect of the certain items related to income tax expense representing the income tax provision on certain items plus discrete income tax items.

Year Ended December 31, 2017 vs. 2016

The certain item totals reflected in footnotes (b), (c) and (d) to the table above accounted for $555 million of the increase in income before income taxes in 2017 as compared to 2016 (representing the difference between decreases of $360 million and $915 million in income before income taxes for 2017 and 2016, respectively). After giving effect to these certain items, which are discussed in more detail in the discussion that follows, the remaining decrease of $32 million (1%) from the prior year in income before income taxes is primarily attributable to decreased performance from our Natural Gas Pipelines business segment, largely associated with our sale of a 50% interest in SNG to The Southern Company (Southern Company) on September 1, 2016, and increased DD&A expense partially offset by decreased general and administrative expense and decreased interest expense.

Year Ended December 31, 2016 vs. 2015

The certain item totals reflected in footnotes (b), (c) and (d) to the table above accounted for $866 million of the increase in income before income taxes in 2016 as compared to 2015 (representing the difference between decreases of $915 million and $1,781 million in income before income taxes for 2016 and 2015, respectively). After giving effect to these certain items, which are discussed in more detail in the discussion that follows, income before income taxes for 2016 when compared to the prior year was flat. Increased results in our Products Pipelines and Terminals business segments and decreased DD&A expense and interest expense, net, were offset by unfavorable commodity prices affecting our CO2 business segment and decreased results on our Natural Gas Pipelines business segment. The decrease in DD&A was primarily driven by lower DD&A in our CO2 business segment and the decrease in interest expense was due to lower weighted average debt balances, partially offset by a slightly higher overall weighted average interest rate on outstanding debt.

Non-GAAP Financial Measures

Our non-GAAP performance measures are DCF, both in the aggregate and per share, and Segment EBDA before certain items. 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 (i) do not have a cash impact (for example, asset impairments), or (ii) 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).

Our non-GAAP performance measures described below should not be considered alternatives to GAAP net income or other GAAP measures and have important limitations as analytical tools. Our computations of DCF and Segment EBDA before certain items may differ from similarly titled measures used by others. You should not consider these non-GAAP performance 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 performance 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.

DCF

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 external users of our financial statements in evaluating our performance and in measuring and estimating 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 DCF to net income available to common stockholders is provided in the table below. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends.

Segment EBDA Before Certain Items

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 performance 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).

In the tables for each of our business segments under “— Segment Earnings Results” below, Segment EBDA before certain items is calculated by adjusting the Segment EBDA for the applicable certain item amounts, which are totaled in the tables and described in the footnotes to those tables.

Reconciliation of Net Income Available to Common Stockholders to DCF

Year Ended December 31,
201720162015
(In millions)
Net Income Available to Common Stockholders$27$552$227
Add/(Subtract):
Certain items before book tax(a)1419151,781
Book tax certain items(b)(77)18(340)
Impact of 2017 Tax Reform(c)1,381——
Total certain items1,4459331,441
Noncontrolling interest certain items(d)—(8)(63)
Net income available to common stockholders before certain items1,4721,4771,605
Add/(Subtract):
DD&A expense(e)2,6842,6172,683
Total book taxes(f)957993976
Cash taxes(g)(72)(79)(32)
Other items(h)294332
Sustaining capital expenditures(i)(588)(540)(565)
DCF$4,482$4,511$4,699
Weighted average common shares outstanding for dividends(j)2,2402,2382,200
DCF per common share$2.00$2.02$2.14
Declared dividend per common share0.5000.5001.605
(a)Consists of certain items summarized in footnotes (b) through (d) to the “—Results of Operations—Consolidated Earnings Results” table included above, and described in more detail below in the footnotes to tables included in both our management’s discussion and analysis of segment results and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”
(b)Represents income tax provision on certain items plus discrete income tax items. For 2017, discrete income tax items include a $36 million federal return-to-provision tax benefit as a result of the recognition of an enhanced oil recovery credit instead of deduction. For 2016, discrete income tax items include a $276 million increase in tax expense primarily due to the impact of the sale of a 50% interest in SNG discussed in Note 5 “Income Taxes” to our consolidated financial statements.
(c)Amount includes book tax certain items and $219 million pre-tax certain items related to our FERC regulated business. See Note 5 “Income Taxes” to our consolidated financial statements.
(d)Represents noncontrolling interests share of certain items.
(e)Includes DD&A, amortization of excess cost of equity investments and our share of certain equity investee’s DD&A, net of the noncontrolling interests’ portion of KML DD&A and consolidating joint venture partners’ share of DD&A of $362 million, $349 million and $323 million in 2017, 2016 and 2015, respectively.
(f)Excludes book tax certain items of $(1,085) million, $(18) million and $340 million for 2017, 2016 and 2015, respectively. 2017, 2016 and 2015 amounts also include $104 million, $94 million and $72 million, respectively, of our share of taxable equity investee’s book taxes, net of the noncontrolling interests’ portion of KML book taxes.
(g)Includes our share of taxable equity investee’s cash taxes of $(69) million, $(76) million and $(19) million in 2017, 2016 and 2015, respectively.
(h)Amounts include non-cash compensation associated with our restricted stock program. 2017 amount also includes a pension contribution.
(i)Includes our share of (i) certain equity investee’s, (ii) KML’s, and (ii) consolidating subsidiaries’ sustaining capital expenditures of $(107) million, $(90) million and $(70) million in 2017, 2016 and 2015, respectively.
(j)Includes restricted stock awards that participate in common share dividends and, for 2015, the dilutive effect of warrants, which expired on May 25, 2017 without the issuance of Class P common stock.

Segment Earnings Results

Natural Gas Pipelines

Year Ended December 31,
201720162015
(In millions, except operating statistics)
Revenues(a)$8,618$8,005$8,725
Operating expenses(b)(5,457)(4,393)(4,738)
Loss on impairment of goodwill(c)——(1,150)
Loss on impairments and divestitures, net(d)(27)(200)(122)
Other income113
Earnings from equity investments(e)453385351
Loss on impairments of equity investments(f)(150)(606)(26)
Other, net(g)491924
Segment EBDA(a)(b)(c)(d)(e)(f)(g)3,4873,2113,067
Certain items(a)(b)(c)(d)(e)(f)(g)3928251,062
Segment EBDA before certain items$3,879$4,036$4,129
Change from prior periodIncrease/(Decrease)
Revenues before certain items$594$(477)
Segment EBDA before certain items$(157)$(93)
Natural gas transport volumes (BBtu/d)(h)29,10828,09528,196
Natural gas sales volumes (BBtu/d)2,3412,3352,419
Natural gas gathering volumes (BBtu/d)(h)2,6532,9703,540
Crude/condensate gathering volumes (MBbl/d)(h)273292309

Certain items affecting Segment EBDA

(a)2017 and 2015 amounts include increases in revenues of $8 million and $32 million, respectively, and 2016 amount includes a decrease in revenues of $50 million, all related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales. 2016 amount also includes an increase in revenue of $39 million associated with revenue collected on a customer’s early buyout of a long-term natural gas storage contract. 2015 amount also includes an increase in revenues of $200 million associated with amounts collected on the early termination of a long-term natural gas transportation contract on KMLP.
(b)2017 amount includes a decrease in earnings of (i) $166 million related to the impact of the 2017 Tax Reform; (ii) $3 million related to the non-cash impairment loss associated with the Colden storage field; and (iii) $3 million from other certain items. 2016 and 2015 amounts include a decrease in earnings of $3 million and an increase in earnings of $1 million, respectively, from other certain items.
(c)2015 decrease in earnings of $1,150 million relates to goodwill impairments on our non-regulated midstream reporting unit.
(d)2017 amount includes a decrease in earnings of $27 million related to the non-cash impairment loss associated with the Colden storage field. 2016 amount includes (i) a decrease in earnings of $106 million of project write-offs; (ii) an $84 million pre-tax loss on the sale of a 50% interest in our SNG natural gas pipeline system; and (iii) an $11 million decrease in earnings from other certain items. 2015 amount includes (i) $52 million of losses related to divestitures of certain non-regulated midstream assets; (ii) $47 million of losses related to other impairments on our non-regulated midstream assets; and (iii) a $25 million net decrease in earnings related to project write-offs and other certain items.
(e)2017 amount includes (i) a decrease in earnings of $58 million related to 2017 Tax Reform adjustments recorded by equity investees; (ii) an increase in earnings from an equity investment of $22 million on the sale of a claim related to the early termination of a long-term natural gas transportation contract; (iii) an increase in earnings from an equity investment of $12 million related to a customer contract settlement; (iv) a decrease in earnings of $12 million related to early termination of debt at an equity investee; and (v) a decrease in earnings of $10 million related to a non-cash impairment at an equity investee. 2016 amount includes an increase in earnings of $18 million related to the early termination of a customer contract at an equity investee and a decrease in earnings of $12 million related to

other certain items at equity investees. 2015 amount includes an increase in earnings of $5 million related to other certain items at an equity investee.

(f)2017 amount includes a $150 million non-cash impairment loss related to our investment in FEP. 2016 amount includes $606 million of non-cash impairment losses primarily related to our investments in MEP and Ruby. 2015 amount includes $26 million of non-cash impairment losses primarily associated with our investment in Fort Union Gas Gathering L.L.C.
(g)2017 and 2016 amounts include decreases in earnings of $5 million and $10 million, respectively, related to certain litigation matters.

Other

(h)Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included at our ownership share for the entire period, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.

Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2017 and 2016, when compared with the respective prior year:

Year Ended December 31, 2017 versus Year Ended December 31, 2016

Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
SNG$(200)(62)%$(356)(92)%
CIG(50)(18)%(45)(12)%
South Texas Midstream(49)(18)%101%
KinderHawk(20)(23)%(20)(20)%
Oklahoma Midstream(11)(26)%19971%
TGP686%936%
Elba Express4043%4448%
NGPL(a)22183%n/an/a
EPNG184%224%
Texas Intrastate Natural Gas Pipeline Operations133%60523%
Altamont Midstream1027%3232%
All others (including eliminations)2—%101%
Total Natural Gas Pipelines$(157)(4)%$5947%

(a) Equity investment

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2017 and 2016:

•decrease of $200 million (62%) from SNG primarily due to our sale of a 50% interest in SNG to Southern Company on September 1, 2016;
•decrease of $50 million (18%) from CIG primarily due to a decrease in tariff rates effective January 1, 2017 as a result of a rate case settlement entered into in 2016;
•decrease of $49 million (18%) from South Texas Midstream primarily due to lower commodity based service revenues and residue gas sales as a result of lower volumes partially offset by higher NGL sales gross margin primarily due to rising NGL prices;
•decrease of $20 million (23%) from KinderHawk primarily due to lower volumes;
•decrease of $11 million (26%) from Oklahoma Midstream primarily due to lower volumes and unfavorable producer mix. Higher revenues of $199 million and associated increase in costs of goods sold were primarily due to higher commodity prices;
•increase of $68 million (6%) from TGP primarily due to higher firm transportation revenues driven by incremental capacity sales, expansion projects recently placed in service and an increase in operational gas sales, partially offset by an increase in the associated gas cost;
•increase of $40 million (43%) from Elba Express primarily due to an expansion project placed in service in December 2016;
•increase of $22 million (183%) from our equity investment in NGPL primarily due to lower interest expense due to a reduction in interest rates due to debt refinancing and the repayment of bank borrowings in 2017;
•increase of $18 million (4%) from EPNG primarily due to higher transportation revenues driven by incremental Permian capacity sales and an increase in volumes due to the ramp up of existing customer volumes associated with an expansion project partially offset by increased operations and maintenance expense;
•increase of $13 million (3%) from our Texas intrastate natural gas pipeline operations (including the operations of its Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems) primarily due to higher transportation margins as a result of higher volumes and higher park and loan revenues partially offset by lower storage and sales margins. The increases in revenues of $605 million resulted primarily from an increase in sales revenue due primarily to higher commodity prices which was largely offset by a corresponding increase in costs of sales; and
•increase of $10 million (27%) from Altamont Midstream primarily due to higher natural gas and liquids revenues due to higher commodity prices and volumes.

Year Ended December 31, 2016 versus Year Ended December 31, 2015

Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
SNG$(109)(25)%$(188)(33)%
South Texas Midstream(62)(18)%(229)(18)%
KinderHawk(48)(36)%(51)(33)%
KMLP(31)(135)%(34)(100)%
CIG(27)(9)%(31)(8)%
CPGPL(22)(37)%(23)(29)%
TransColorado(15)(48)%(16)(42)%
TGP17118%20517%
Hiland Midstream5942%15238%
Texas Intrastate Natural Gas Pipeline Operations72%(278)(9)%
All others (including eliminations)(16)(1)%161%
Total Natural Gas Pipelines$(93)(2)%$(477)(6)%

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:

•decrease of $109 million (25%) from SNG primarily due to our sale of a 50% interest in SNG to Southern Company on September 1, 2016;
•decrease of $62 million (18%) from South Texas Midstream primarily due to lower volumes and price. Revenue decreased approximately $229 million partially offset by a decrease in costs of sales;
•decrease of $48 million (36%) from KinderHawk due to lower volumes;
•decrease of $31 million (135%) from KMLP as a result of a customer contract buyout in the fourth quarter of 2015;
•decrease of $27 million (9%) from CIG primarily due to a recent rate case settlement and lower firm reservation revenues due to contract expirations and contract renewals at lower rates;
•decrease of $22 million (37%) from CPGPL primarily due to lower transport revenues as a result of contract expirations;
•decrease of $15 million (48%) from TransColorado primarily due to lower transport revenues as a result of contract expirations;
•increase of $171 million (18%) from TGP primarily due to a full year of earnings from expansion projects placed in service during 2015 and favorable 2016 firm transport revenues;
•increase of $59 million (42%) from Hiland Midstream primarily due to favorable margins on renegotiated contracts, along with results of a full year from our February 2015 Hiland acquisition; and
•increase of $7 million (2%) from our Texas intrastate natural gas pipeline operations (including the operations of its Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems) primarily due to higher storage margins partially offset by lower sales and transportation margins as a result of lower volumes. The decrease in revenues of $278 million resulted primarily from a decrease in sales revenue due to lower commodity prices which was largely offset by a corresponding decrease in costs of sales.

CO2

Year Ended December 31,
201720162015
(In millions, except operating statistics)
Revenues(a)$1,196$1,221$1,699
Operating expenses(394)(399)(432)
Gain (loss) on impairments and divestitures, net(b)1(19)(606)
Earnings from equity investments(c)4424(3)
Segment EBDA(a)(b)(c)847827658
Certain items(a)(b)(c)4092484
Segment EBDA before certain items$887$919$1,142
Change from prior periodIncrease/(Decrease)
Revenues before certain items$(43)$(267)
Segment EBDA before certain items$(32)$(223)
Southwest Colorado CO2 production (gross) (Bcf/d)(d)1.31.21.2
Southwest Colorado CO2 production (net) (Bcf/d)(d)0.60.60.6
SACROC oil production (gross)(MBbl/d)(e)27.929.333.8
SACROC oil production (net)(MBbl/d)(f)23.224.428.1
Yates oil production (gross)(MBbl/d)(e)17.318.419.0
Yates oil production (net)(MBbl/d)(f)7.78.28.5
Katz, Goldsmith, and Tall Cotton Oil Production - Gross (MBbl/d)(e)8.17.05.7
Katz, Goldsmith, and Tall Cotton Oil Production - Net (MBbl/d)(f)6.95.94.8
NGL sales volumes (net)(MBbl/d)(f)9.910.310.4
Realized weighted-average oil price per Bbl(g)$58.40$61.52$73.11
Realized weighted-average NGL price per Bbl(h)$25.15$17.91$18.35

Certain items affecting Segment EBDA

(a)2017, 2016 and 2015 amounts include unrealized losses of $54 million and $63 million, and an unrealized gain of $138 million, respectively, related to non-cash mark to market derivative contracts used to hedge forecasted commodity sales. 2017 amount also includes an increase in revenues of $9 million related to the settlement of a CO2 customer sales contract and 2015 amount also includes a favorable adjustment of $10 million related to carried working interest at McElmo Dome.
(b)2017, 2016 and 2015 amounts include a decrease in expense of $1 million and increases in expense of $20 million and $207 million, respectively, related to source and transportation project write-offs. 2015 amount also includes oil and gas property impairments of $399 million.
(c)2017, 2016 and 2015 amounts include an increase in equity earnings of $4 million and decreases in equity earnings of $9 million and $26 million, respectively, for our share of a project write-off recorded by an equity investee.

Other

(d)Includes McElmo Dome and Doe Canyon sales volumes.
(e)Represents 100% of the production from the field. We own an approximately 97% working interest in the SACROC unit, an approximately 50% working interest in the Yates unit, an approximately 99% working interest in the Katz unit and a 99% working interest in the Goldsmith Landreth unit and a 100% working interest in the Tall Cotton field.
(f)Net after royalties and outside working interests.
(g)Includes all crude oil production properties.
(h)Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.

Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2017 and 2016, when compared with the respective prior year:

Year Ended December 31, 2017 versus Year Ended December 31, 2016
Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
Source and Transportation Activities$21%$(9)(3)%
Oil and Gas Producing Activities(34)(6)%(33)(3)%
Intrasegment eliminations——%(1)(3)%
Total CO2$(32)(3)%$(43)(3)%

The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2017 and 2016:

•increase of $2 million (1%) from our Source and Transportation activities primarily due to increased earnings from an equity investee of $6 million and lower operating expenses of $5 million partially offset by lower revenues of $9 million driven by lower contract sales prices of $7 million and decreased volumes of $2 million; and
•decrease of $34 million (6%) from our Oil and Gas Producing activities primarily due to decreased revenues of $33 million driven by lower volumes of $22 million and lower commodity prices of $11 million, and higher operating expenses of $1 million.
Year Ended December 31, 2016 versus Year Ended December 31, 2015
Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
Source and Transportation Activities$(27)(8)%$(36)(9)%
Oil and Gas Producing Activities(196)(24)%(241)(20)%
Intrasegment Eliminations——%1021%
Total CO2$(223)(20)%$(267)(17)%

The changes in Segment EBDA for our CO2 business segment are further explained by the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015 which factors include lower revenues of $205 million from lower commodity prices and $72 million due to decreased volumes, partially offset by (i) $27 million in reduced operating costs; (ii) $15 million of lower severance and ad valorem tax expenses; and (iii) $11 million primarily related to increased earnings from an equity investee.

Terminals

Year Ended December 31,
201720162015
(In millions, except operating statistics)
Revenues(a)$1,966$1,922$1,879
Operating expenses(b)(788)(768)(836)
Gain (loss) on impairments and divestitures, net(c)14(99)(191)
Other income——1
Earnings from equity investments(d)243521
Loss on impairments and divestitures of equity investments, net(e)—(16)(4)
Other, net848
Segment EBDA(a)(b)(c)(d)(e)1,2241,078878
Certain items, net(a)(b)(c)(d)(e)(10)91206
Segment EBDA before certain items$1,214$1,169$1,084
Change from prior periodIncrease/(Decrease)
Revenues before certain items$68$38
Segment EBDA before certain items$45$85
Bulk transload tonnage (MMtons)59.554.855.6
Ethanol (MMBbl)68.166.763.1
Liquids leaseable capacity (MMBbl)87.984.778.6
Liquids utilization %(f)93.6%94.7%94.6%

Certain items affecting Segment EBDA

(a)2017, 2016 and 2015 amounts include increases in revenues of $9 million, $28 million and $23 million, respectively, from the amortization of a fair value adjustment (associated with the below market contracts assumed upon acquisition) from our Jones Act tankers. 2017 amount also includes a decrease in revenues of $5 million related to other certain items.
(b)2017 amount includes (i) an increase in expense of $21 million related to hurricane repairs; (ii) a decrease in expense of $10 million related to accrued dredging costs; and (iii) a decrease in expense of $2 million related to other certain items. 2016 amount includes an increase in expense of $3 million related to other certain items. 2015 amount includes a $34 million increase in bad debt expense due to certain coal customers bankruptcies related to revenues recognized in prior years but not yet collected and an increase in expense of $2 million related to other certain items.
(c)2017 amount includes a gain of $23 million primarily related to the sale of a 40% membership interest in the Deeprock Development joint venture in July 2017 and losses of $8 million related to other impairments and divestitures, net. 2016 amount includes an expense of $109 million related to various losses on impairments and divestitures, net. 2015 amount includes a $175 million non-cash pre-tax impairment of a terminal facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer and $14 million related to other losses on impairments and divestitures, net.
(d)2016 amount includes an increase in earnings of $9 million related to our share of the settlement of a certain litigation matter at an equity investee. 2015 amount includes a decrease in earnings of $4 million related to a non-cash impairment at an equity investee.
(e)2016 amount includes $16 million related to various losses on impairments and divestitures of equity investments, net.

Other

(f)The ratio of our actual leased capacity to our estimated capacity.

Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2017 and 2016, when compared with the respective prior year:

Year Ended December 31, 2017 versus Year Ended December 31, 2016
Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
Marine Operations$4227%$7231%
Gulf Liquids208%3811%
Alberta, Canada86%75%
Midwest711%1511%
Held for sale operations(19)(100)%(55)(90)%
Gulf Central(17)(16)%(11)(8)%
All others (including intrasegment eliminations)41%2—%
Total Terminals$454%$684%

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2017 and 2016:

•increase of $42 million (27%) from our Marine Operations related to the incremental earnings from the May 2016, July 2016, September 2016, December 2016, March 2017, June 2017, July 2017 and December 2017 deliveries of the Jones Act tankers, the Magnolia State, Garden State, Bay State, American Endurance, American Freedom, Palmetto State, American Liberty and American Pride, respectively, partially offset by decreased charter rates on the Golden State, Pelican State, Sunshine State, Empire State and Pennsylvania Jones Act tankers;
•increase of $20 million (8%) from our Gulf Liquids terminals primarily related to higher volumes as a result of various expansion projects, including the recently commissioned Kinder Morgan Export Terminal and North Docks terminal, partially offset by lost revenue associated with Hurricane Harvey-related operational disruptions;
•increase of $8 million (6%) from our Alberta, Canada terminals primarily due to escalations in predominantly fixed, take-or-pay terminaling contracts and a true-up in terminal fees in connection with a favorable arbitration ruling;
•increase of $7 million (11%) from our Midwest terminals primarily driven by increased ethanol throughput revenues in 2017 and a new bulk storage and handling contract entered into fourth quarter 2016;
•decrease of $19 million (100%) from our sale of certain bulk terminal facilities to an affiliate of Watco Companies, LLC in December 2016 and early 2017; and
•decrease of $17 million (16%) from our Gulf Central terminals primarily related to the sale of a 40% membership interest in the Deeprock Development joint venture in July 2017 and the subsequent change in accounting treatment of our retained 11% membership interest as well as lost revenue associated with Hurricane Harvey-related operational disruptions.
Year Ended December 31, 2016 versus Year Ended December 31, 2015
Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
Marine Operations$5251%$7346%
Alberta, Canada1412%1914%
Gulf Liquids146%185%
Northeast1110%1910%
Lower River47%(12)(9)%
Gulf Bulk(13)(17)%(50)(29)%
Held for sale operations(2)(67)%(18)(100)%
All others (including intrasegment eliminations)51%(11)(2)%
Total Terminals$858%$382%

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:

•increase of $52 million (51%) from our Marine Operations related to the incremental earnings from the December 2015, May 2016, July 2016, September 2016 and December 2016 in-service of the Jones Act tankers the Lone Star State, Magnolia State, Garden State, Bay State,and American Endurance, respectively, and increased charter rates on the Empire State Jones Act tanker;
•increase of $14 million (12%) from our Alberta, Canada terminals, driven by a full year of earnings from our Edmonton South rail terminal joint venture expansion, which began operations in second quarter 2015;
•increase of $14 million (6%) from our Gulf Liquids terminals, primarily related to higher volumes as a result of various expansion projects, including marine infrastructure improvements at our Galena Park and North Docks terminals, as well as higher rates and ancillary service activities on existing business;
•increase of $11 million (10%) from our Northeast terminals, primarily due to contributions from two terminals acquired as part of the BP Products North America Inc. acquisition which was completed in February 2016;
•increase of $4 million (7%) from our Lower River terminals, due to a $15 million write-off of certain coal customers accounts receivable which occurred in 2015 and favorable results from certain Lower River terminals, partially offset by decreased revenues and earnings of $18 million due to certain coal customer bankruptcies;
•decrease of $13 million (17%) from our Gulf Bulk terminals, driven by decreased revenues and earnings of $41 million due to certain coal customer bankruptcies offset by a $28 million write-off of a certain coal customer’s accounts receivable which occurred in the fourth quarter of 2015;
•decrease of $2 million (67%) from our sale of certain bulk and transload terminal facilities to Watco Companies, LLC in early 2015; and
•included in “All others” is a decrease in revenues and earnings of $11 million due to certain coal customer bankruptcies as compared to a $4 million write-off of certain coal customers accounts receivable which occurred in 2015.

Products Pipelines

Year Ended December 31,
201720162015
(In millions, except operating statistics)
Revenues$1,661$1,649$1,831
Operating expenses(a)(487)(573)(772)
Loss on impairments and divestitures, net(b)—(76)—
Other (expense) income——(2)
Earnings from equity investments(c)585345
Gain on divestiture of equity investment(d)—12—
Other, net(1)24
Segment EBDA(a)(b)(c)(d)1,2311,0671,106
Certain items(a)(b)(c)(d)(38)113(4)
Segment EBDA before certain items$1,193$1,180$1,102
Change from prior periodIncrease/(Decrease)
Revenues before certain items$12$(182)
Segment EBDA before certain items$13$78
Gasoline (MBbl/d) (e)1,0381,0251,011
Diesel fuel (MBbl/d)351342354
Jet fuel (MBbl/d)297288282
Total refined product volumes (MBbl/d)(f)1,6861,6551,647
NGL (MBbl/d)(f)112109106
Condensate (MBbl/d)(f)327324273
Total delivery volumes (MBbl/d)2,1252,0882,026
Ethanol (MBbl/d)(g)117115113

Certain items affecting Segment EBDA

(a)2017 amount includes a decrease in expense of $34 million related to a right-of-way settlement and an increase in expense of $1 million related to hurricane repairs. 2016 amount includes increases in expense of $31 million of rate case liability estimate adjustments associated with prior periods and $20 million related to a legal settlement. 2015 amount includes a $4 million decrease in expense associated with a certain Pacific operations litigation matter.
(b)2016 amount includes increases in expense of $65 million related to the Palmetto project write-off and $9 million of non-cash impairment charges related to the sale of a Transmix facility.
(c)2017 amount includes an increase in equity earnings of $5 million related to the impact of the 2017 Tax Reform at an equity investee.
(d)2016 amount includes a $12 million gain related to the sale of an equity investment.

Other

(e)Volumes include ethanol pipeline volumes.
(f)Joint Venture throughput is reported at our ownership share.
(g)Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.

Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2017 and 2016, when compared with the respective prior year:

Year Ended December 31, 2017 versus Year Ended December 31, 2016
Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
Pacific operations$51%$112%
South East Terminals45%65%
Calnev36%23%
Double Eagle330%240%
Transmix13%(14)(6)%
Parkway(3)(100)%(1)(100)%
All others (including eliminations)——%61%
Total Products Pipelines$131%$121%

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2017 and 2016:

•increase of $5 million (1%) from Pacific operations primarily due to higher service revenues driven by an increase in volumes partially offset by a volume driven increase in power costs and an increase in right-of-way expense;
•increase of $4 million (5%) from our South East Terminals primarily due to higher revenues driven by higher volumes as a result of capital expansion projects being placed in service during 2017;
•increase of $3 million (6%) from Calnev primarily due to higher service revenues driven by higher volumes and a decrease in expense related to the reduction of a rate reserve;
•increase of $3 million (30%) from Double Eagle primarily due to higher revenues driven by higher volumes and price;
•increase of $1 million (3%) from our Transmix processing operations. The decrease in revenues of $14 million and associated decrease in costs of goods sold were driven by lower sales volumes primarily due to the sale of our Indianola plant in August 2016 and lower brokered sales at the Dorsey plant due to an expired contract in May 2017; and
•decrease of $3 million (100%) from Parkway pipeline due to our sale of our 50% interest in Parkway pipeline on July 1, 2016.
Year Ended December 31, 2016 versus Year Ended December 31, 2015
Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
Crude & Condensate Pipeline$3720%$3618%
KMCC - Splitter2053%3071%
Double H pipeline1534%2239%
Plantation Pipe Line917%15%
Transmix826%(286)(57)%
Cochin(13)(11)%32%
All others (including eliminations)2—%121%
Total Products Pipelines$787%$(182)(10)%

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:

•increase of $37 million (20%) from Kinder Morgan Crude & Condensate Pipeline driven primarily by an increase in pipeline throughput volumes from existing customers and additional volumes associated with expansion projects;
•increase of $20 million (53%) from our KMCC - Splitter due to first and second phases being in full operation for 2016. Start up of first phase was in March 2015 and second phase was in July 2015;
•increase of $15 million (34%) due to full year of results from our Double H pipeline, which began operations in March 2015;
•increase of $9 million (17%) from our equity investment in Plantation Pipe Line primarily due to lower operating costs;
•increase of $8 million (26%) from our Transmix processing operations largely due to unfavorable market price impacts during the fourth quarter of 2015. The decrease in revenues of $286 million and associated decrease in costs of goods sold were driven by lower sales volumes primarily due to the sale of our Indianola plant in August 2016; and
•decrease of $13 million (11%) from Cochin primarily due to higher pipeline integrity costs.

Kinder Morgan Canada

Year Ended December 31,
201720162015
(In millions, except operating statistics)
Revenues$256$253$260
Operating expenses(95)(87)(87)
Other income——1
Other, net25158
Segment EBDA$186$181$182
Change from prior periodIncrease/(Decrease)
Revenues$3$(7)
Segment EBDA$5$(1)
Transport volumes (MBbl/d)(a)308316316
(a)Represents Trans Mountain pipeline system volumes.

For the comparable years of 2017 and 2016, the Kinder Morgan Canada business segment had an increase in Segment EBDA of $5 million (3%) and an increase in revenues of $3 million (1%) primarily due to (i) higher capitalized equity financing costs due to spending on the TMEP; (ii) currency translation gains due to the strengthening of the Canadian dollar; and (iii) higher incentive revenues partly offset by lower state of Washington volumes and operating expense timing changes.

For the comparable years of 2016 and 2015, the Kinder Morgan Canada business segment had a decrease in Segment EBDA of $1 million (1%) and a decrease in revenues of $7 million (3%).

General and Administrative, Interest, Corporate and Noncontrolling Interests

Year Ended December 31,
201720162015
(In millions)
General and administrative and corporate charges(a)$660$652$708
Certain items(a)(15)13(60)
General and administrative and corporate charges before certain items$645$665$648
Interest, net(b)$1,832$1,806$2,051
Certain items(b)3919327
Interest, net, before certain items$1,871$1,999$2,078
Net income (loss) attributable to noncontrolling interests(c)$40$13$(45)
Noncontrolling interests associated with certain items(c)—863
Net income attributable to noncontrolling interests before certain items$40$21$18

Certain items

(a)2017 amount includes (i) an increase in expense of $10 million for acquisition and divestiture related costs; (ii) an increase in expense of $4 million related to certain corporate litigation matters; (iii) an increase in expense of $5 million related to a pension settlement; and (iv) decrease in expense of $4 million related to other certain items. 2016 amount includes increases in expense of (i) $14 million related to severance costs; and (ii) $12 million related to acquisition and divestiture costs; offset by decreases in expense of (i) $34 million related to certain corporate litigation matters; and (ii) $5 million related to other certain items. 2015 amount includes increases in expense of (i) $71 million related to certain corporate legal matters; (ii) $15 million related to costs associated with acquisitions; and (iii) $9 million associated with other certain items; offset by a decrease in expense of $35 million related to pension credit income.
(b)2017, 2016 and 2015 amounts include (i) decreases in interest expense of $44 million, $115 million and $71 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) decreases of $3 million and $44 million and an increase of $23 million, respectively, in interest expense primarily related to non-cash true-ups of our estimates of swap ineffectiveness. 2017 amount also includes an $8 million increase in interest expense related to other certain items. 2016 and 2015 amounts also include a $34 million decrease and a $21 million increase, respectively, in interest expense related to certain litigation matters.
(c)Amounts reflect the noncontrolling interest portion of certain items including (i) a $49 million loss for 2015 associated with Terminals segment certain items and disclosed above in “—Terminals” and (ii) an $8 million loss for 2016 and a $14 million loss for 2015 associated with Natural Gas Pipelines segment certain items and disclosed above in “—Natural Gas Pipelines.”

General and administrative expenses and corporate charges before certain items decreased $20 million in 2017 and increased $17 million in 2016 when compared with the respective prior year. The decrease in 2017 as compared to 2016 was primarily driven by the sale of a 50% interest in our SNG natural gas pipeline system (effective September 1, 2016), higher capitalized costs, lower state franchise taxes, legal and insurance costs, partially offset by higher labor accruals and pension costs. The increase in 2016 as compared to 2015 was primarily driven by higher benefit costs, higher corporate charges and lower capitalized costs partially offset by lower labor, outside services and insurance costs.

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense net of interest income before certain items, decreased $128 million in 2017 and $79 million in 2016, respectively, when compared with the respective prior year. The decrease in interest expense in 2017 as compared to 2016 was primarily due to lower weighted average debt balances as proceeds from the May 2017 KML IPO and our September 2016 sale of a 50% interest in SNG were used to pay down debt, partially offset by a slightly higher overall weighted average interest rate on our outstanding debt. The decrease in interest expense in 2016 as compared to 2015 was primarily due to lower weighted average debt balances, partially offset by a slightly higher overall weighted average interest rate on our outstanding debt.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of both December 31, 2017 and 2016, approximately 28% of our debt balances (excluding debt fair value adjustments) were subject to variable interest rates-either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see Note 14 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Net income attributable to noncontrolling interests, represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not held by us. Net income attributable to noncontrolling interests before certain items for 2017 as compared to 2016 increased $19 million (90%) due to the May 30, 2017 sale of approximately 30% of our Canadian business operations to the public in the KML IPO. The portion of our Canadian business operations net income attributable to the public is now reflected in “Net income attributable to noncontrolling interests.” Net income attributable to noncontrolling interests before certain items for 2016 as compared to 2015 increased $3 million (17%).

Income Taxes

Year Ended December 31, 2017 versus Year Ended December 31, 2016

Our tax expense for the year ended December 31, 2017 is approximately $1,938 million, as compared with 2016 tax expense of $917 million. The $1,021 million increase in tax expense is primarily due to (i) an increase in year-over-year earnings as a result of fewer asset impairments and project write-offs in 2017 and (ii) higher tax expense as a result of the 2017 Tax Reform. These increases are partially offset by (i) the 2016 impact of our Regulated Natural Gas Pipeline segment’s $817 million non-tax-deductible goodwill as a result of the sale of a 50% interest in SNG; and (ii) the recognition of enhanced oil recovery credits.

Year Ended December 31, 2016 versus Year Ended December 31, 2015

Our tax expense for the year ended December 31, 2016 is approximately $917 million, as compared with 2015 tax expense of $564 million. The $353 million increase in tax expense is primarily due to (i) an increase in our earnings as a result of lower impairments in 2016; (ii) the year over year increase in the deferred state tax expense as a result of our sale of a 50% interest in SNG in 2016 and the Hiland acquisition in 2015; and (iii) valuation allowances recorded in 2016 for foreign tax credits and capital loss carryforwards for which we do not expect to recognize any future tax benefits. These increases are partially offset by adjustments to our income tax reserve for uncertain tax positions.

Liquidity and Capital Resources

General

As of December 31, 2017, we had $264 million of “Cash and cash equivalents,” a decrease of $420 million (61%) from December 31, 2016. We believe our cash position, remaining borrowing capacity on our credit facility (discussed below in “—Short-term Liquidity”), and our cash flows from operating activities are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

We have consistently generated substantial cash flow from operations, providing a source of funds of $4,601 million and $4,795 million in 2017 and 2016, respectively. The year-to-year decrease is discussed below in “Cash Flows—Operating Activities.” We have primarily relied on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments, and during the last two years, our growth capital expenditures.

We expect KML to fund the TMEP’s capital expenditures and its other capital expenditures through (i) additional borrowings on KML’s Credit Facility; (ii) the additional issuance of KML preferred shares; (iii) the issuance of additional KML restricted voting stock; (iv) the issuance of KML long-term notes payable; and (v) KML’s retained cash flow from operations or a combination of the above. KML established a dividend policy on its restricted voting shares pursuant to which it will pay its quarterly dividend in an amount based on a portion of its DCF discussed below in “—Noncontrolling interests—KML Restricted Voting Share Dividends.”

On June 16, 2017, KML’s indirect subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the TMEP; (ii) a C$1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional TMEP costs (and, subject to the need to fund such additional costs and regulatory approval, meeting the Canadian NEB-mandated liquidity requirements); and (iii) a C$500 million revolving working capital facility, to be used for working capital and other general corporate purposes (collectively, the “KML Credit Facility”). On January 23, 2018, KML entered into an agreement amending certain terms of its Credit Facility to, among other things, provide additional funding certainty with respect to each tranche of its Credit Facility. The KML Credit Facility has a five-year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. As of December 31, 2017, KML had no amounts outstanding under the KML Credit Facility and C$53 million (U.S.$42 million) in letters of credit. In addition,

KML received C$537 million (U.S.$420 million) of net proceeds from the issuance of Series 1 Preferred Shares in August 2017 and Series 3 Preferred Shares in December 2017.

Generally, we expect that our short-term liquidity needs will be met primarily through retained cash from operations, short-term borrowings or by issuing new long-term debt to refinance certain of our maturing long-term debt obligations. We also expect that KMI’s current common stock dividend level will allow us to use retained cash to fund our growth projects and the previously mentioned share repurchase program in 2018. Moreover, as a result of KMI’s current common stock dividend policy and by continuing to focus on allocating capital to high return opportunities, we do not expect the need to access the equity capital markets to fund our other growth projects for the foreseeable future.

Credit Ratings and Capital Market Liquidity

We believe that our capital structure will continue to allow us to achieve our business objectives. We expect that our short-term liquidity needs will be met primarily through retained cash from operations or short-term borrowings. Generally, we anticipate re-financing maturing long term debt obligations in the debt capital markets and are therefore subject to certain market conditions which could result in higher costs or negatively affect our and/or our subsidiaries’ credit ratings.

As of December 31, 2017, our short-term corporate debt ratings were A-3, Prime-3 and F3 at Standard and Poor’s, Moody’s Investor Services and Fitch Ratings, Inc., respectively.

The following table represents KMI’s and KMP’s senior unsecured debt ratings as of December 31, 2017.

Rating agencySenior debt ratingDate of last changeOutlook
Standard and Poor’sBBB-November 20, 2014Stable
Moody’s Investor ServicesBaa3November 21, 2014Stable
Fitch Ratings, Inc.BBB-November 20, 2014Stable

Short-term Liquidity

As of December 31, 2017, our principal sources of short-term liquidity are (i) our $5.0 billion revolving credit facility and associated $4.0 billion commercial paper program; (ii) the KML Credit Facility (for the purposes described above); and (iii) cash from operations. The loan commitments under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program and letters of credit reduce borrowings allowed under ours and KML’s respective credit facilities. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, we have consistently generated strong cash flows from operations.

As of December 31, 2017, our $2,828 million of short-term debt consisted primarily of (i) $125 million outstanding borrowings under the KMI $5.0 billion revolving credit facility; (ii) $240 million outstanding under our $4.0 billion commercial paper program; and (iii) $2,284 million of senior notes that mature in the next year. We intend to refinance our short-term debt through credit facility borrowings, commercial paper borrowings, or by issuing new long-term debt or paying down short-term debt using cash retained from operations. Our short-term debt balance as of December 31, 2016 was $2,696 million.

We had working capital (defined as current assets less current liabilities) deficits of $3,466 million and $2,695 million as of December 31, 2017 and 2016, respectively. Our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall $771 million (29%) unfavorable change from year-end 2016 was primarily due to a decrease in cash and restricted deposits, and a net increase in our current portion of long-term debt and accounts payable. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities (discussed below in “—Long-term Financing” and “— Capital Expenditures”).

We employ a centralized cash management program for our U.S.-based bank accounts that concentrates the cash assets of our wholly owned subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. These programs provide that funds in excess of the daily needs of our wholly owned subsidiaries are concentrated,

consolidated or otherwise made available for use by other entities within the consolidated group. We place no material restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to KMI other than restrictions that may be contained in agreements governing the indebtedness of those entities.

Certain of our wholly owned subsidiaries are subject to FERC-enacted reporting requirements for oil and natural gas pipeline companies that participate in cash management programs. FERC-regulated entities subject to these rules must, among other things, place their cash management agreements in writing, maintain current copies of the documents authorizing and supporting their cash management agreements, and file documentation establishing the cash management program with the FERC.

Long-term Financing

Our equity consists of Class P common stock and mandatory convertible preferred stock each with a par value of $0.01 per share. We have in place an equity distribution agreement which allows us to issue and sell through or to our sales agents and/or principals shares of our Class P common stock. However, with the exception of the issuance of KML preferred equity and/or common equity to partially finance the TMEP or other KML capital expenditures, we do not expect the need to access the equity capital markets to fund our growth projects for the foreseeable future. Furthermore, we began repurchasing shares of our Class P common stock under a $2 billion share buy-back program in December 2017 that we intend to fund through retained cash. For more information on our equity buy-back program and our equity distribution agreement, see Note 11 “Stockholders’ Equity” to our consolidated financial statements.

From time to time, we issue long-term debt securities, often referred to as senior notes. All of our senior notes issued to date, other than those issued by certain of our subsidiaries, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date, and, in most cases, plus a make-whole premium. In addition, from time to time our subsidiaries, have issued long-term debt securities. Furthermore, we and almost all of our direct and indirect wholly owned domestic subsidiaries are parties to a cross guaranty wherein we each guarantee the debt of each other. See Note 19 “Guarantee of Securities of Subsidiaries” to our consolidated financial statements. As of December 31, 2017 and 2016, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $34,088 million and $36,205 million, respectively. For more information regarding our debt-related transactions in 2017, see Note 9 “Debt” to our consolidated financial statements.

We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping the fixed rate interest payments for variable rate interest payments and through the issuance of commercial paper or credit facility borrowings.

For additional information about our debt-related transactions in 2017, see Note 9 “Debt” to our consolidated financial statements. For information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

Capital Expenditures

We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as discretionary capital expenditures). Expansion capital expenditures are those expenditures which increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF (see “Results of Operations—DCF”). With respect to our oil and gas producing activities, we classify a capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e. production capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements. Maintenance capital expenditures are those which maintain throughput or capacity. The distinction between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.

Budgeting of maintenance capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally

expect to receive sufficient returns to justify the expenditures. Generally, the determination of whether a capital expenditure is classified as maintenance/sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are. See “—Common Dividends” and “—Preferred Dividends.”

Our capital expenditures for the year ended December 31, 2017, and the amount we expect to spend for 2018 to sustain and grow our business are as follows (in millions):

2017Expected 2018
Sustaining capital expenditures(a)(c)$588$664
KMI Discretionary capital investments(b)(c)(d)(e)$2,982$2,215
KML Discretionary capital investments post-IPO(c)$384$1,500
(a)2017 and Expected 2018 amounts include $107 million and $112 million, respectively, for our share of (i) certain equity investee’s, (ii) KML’s, and (ii) consolidating subsidiaries’ sustaining capital expenditures.
(b)2017 is net of $216 million of contributions from certain partners for capital investments at non-wholly owned consolidated subsidiaries offset by $629 million of our contributions to certain unconsolidated joint ventures for capital investments.
(c)2017 includes $246 million of net changes from accrued capital expenditures, contractor retainage, and other.
(d)2017 includes $107 million of capital expenditures spent on Canadian projects prior to KML’s May 25, 2017 IPO and excludes KML capital expenditures thereafter as it has the capacity to draw on its construction credit facility to fund its capital expenditures.
(e)Expected 2018 amount includes our estimated contributions to certain unconsolidated joint ventures, net of contributions estimated from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

Off Balance Sheet Arrangements

We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 13 “Commitments and Contingent Liabilities” to our consolidated financial statements. Additional information regarding the nature and business purpose of our investments is included in Note 7 “Investments” to our consolidated financial statements.

Contractual Obligations and Commercial Commitments

Payments due by period
TotalLess than 1 year2-3 years4-5 yearsMore than 5 years
(In millions)
Contractual obligations:
Debt borrowings-principal payments(a)$36,916$2,828$5,024$4,980$24,084
Interest payments(b)24,5551,8973,4622,97416,222
Leases and rights-of-way obligations(c)722118187117300
Pension and postretirement welfare plans(d)975483245850
Transportation, volume and storage agreements(e)1,043159308258318
Other obligations(f)27964823895
Total$64,490$5,114$9,095$8,412$41,869
Other commercial commitments:
Standby letters of credit(g)$224$125$99$—$—
Capital expenditures(h)$845$845$—$—$—
(a)Less than 1 year amount primarily includes $2,717 million of current maturities on senior notes and $111 million associated with our Trust I Preferred Securities that are classified as current obligations because these securities have rights to convert into cash and/or KMI common stock. See Note 9 “Debt” to our consolidated financial statements.
(b)Interest payment obligations exclude adjustments for interest rate swap agreements and assume no change in variable interest rates from those in effect at December 31, 2017.
(c)Represents commitments pursuant to the terms of operating lease agreements and liabilities for rights-of-way.
(d)Represents the amount by which the benefit obligations exceeded the fair value of plan assets at year-end for pension and other postretirement benefit plans whose accumulated postretirement benefit obligations exceeded the fair value of plan assets. The payments by period include expected contributions to funded plans in 2018 and estimated benefit payments for unfunded plans in all years.
(e)Primarily represents transportation agreements of $425 million, volume agreements of $377 million and storage agreements for capacity on third party and an affiliate pipeline systems of $203 million.
(f)Primarily includes environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we will perform remediation activities. These liabilities are included within “Accrued contingencies” and “Other long-term liabilities and deferred credits” in our consolidated balance sheets.
(g)The $224 million in letters of credit outstanding as of December 31, 2017 consisted of the following (i) $47 million under eleven letters of credit for insurance purposes; (ii) a $42 million letter of credit supporting our pipeline and terminal operations in Canada; (iii) letters of credit totaling $46 million supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (iv) a $25 million letter of credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (v) a $24 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; (vi) a $9 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; and (vii) a combined $31 million in twenty-four letters of credit supporting environmental and other obligations of us and our subsidiaries.
(h)Represents commitments for the purchase of plant, property and equipment as of December 31, 2017.

Cash Flows

Operating Activities

The net decrease of $194 million (4%) in cash provided by operating activities in 2017 compared to 2016 was primarily attributable to:

•a $348 million decrease in operating cash flow resulting from the combined effects of adjusting the $498 million decrease in net income for the period-to-period net increase in non-cash items primarily consisting of the following: (i) net losses on impairments and divestitures of assets and equity investments (see discussion above in “—Results of Operations”); (ii) change in fair market value of derivative contracts; (iii) DD&A expense (including amortization of excess cost of equity investments); (iv) deferred income taxes, which includes a $1,162 million adjustment associated with the 2017 Tax Reform; (v) earnings from equity investments; and (vi) loss (gain) on early extinguishment of debt; and
•a $154 million increase in cash associated with net changes in working capital items and other non-current assets and liabilities. The increase was driven, among other things, primarily by a $144 million income tax refund received in 2017.

Investing Activities

The $1,657 million net increase in cash used in investing activities in 2017 compared to 2016 was primarily attributable to:

•a $1,401 million increase in cash used due to proceeds received in the 2016 period from the sale of a 50% equity interest in SNG;
•a $306 million increase in capital expenditures primarily due to higher expenditures related to natural gas, CO2 and Trans Mountain expansion projects, offset in part by lower expenditures in the Terminals segment;
•a $276 million increase in cash used for contributions to equity investments primarily due to the contributions we made in 2017 to Utopia Holding LLC, FEP and SNG; and
•$212 million lower cash proceeds from sales of property, plant and equipment and other net assets, primarily driven by the higher proceeds we received in 2016 from sales of other long-lived assets; partially offset by
•a $329 million decrease in expenditures for acquisitions of assets and investments, primarily driven by the $324 million portion of the purchase price we paid in the 2016 period for the BP terminals acquisition;
•a $143 million increase in cash for distributions received from equity investments in excess of cumulative earnings, primarily driven by the higher distributions from MEP, SNG and Ruby; and
•a $66 million increase in Other, net primarily due to favorable changes in restricted deposits associated with our hedging activities, offset partially by increases in loans with an equity investee.

Financing Activities

The net decrease of $956 million in cash used by financing activities in 2017 compared to 2016 was primarily attributable to:

•a $1,560 million increase in cash due to contributions from noncontrolling interests, primarily reflecting $1,245 million in net proceeds received from the May 2017 KML IPO and $420 million net proceeds received from the KML preferred share issuances in 2017, compared to the 2016 period which includes $84 million of contributions received from BP for its 25% share of a newly formed joint venture; and
•a $485 million increase in cash resulting from contributions received in the 2017 period from EIG, consisting of $386 million for the sale of a 49% partnership interest in ELC and $99 million as additional contributions for 2017 capital expenditures; partially offset by
•an $816 million net increase in cash used related to debt activities as a result of higher net debt payments in the 2017 period compared to the 2016 period. See Note 9 “Debt” to our consolidated financial statements for further information regarding our debt activity; and
•a $250 million increase in cash used for share repurchases under the share buy-back program that commenced in December 2017.

Dividends and Stock Buyback Program

KMI Common Stock Dividends

The table below reflects the payment of cash dividends of $0.50 per common share for 2017.

Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
March 31, 2017$0.125April 19, 2017May 1, 2017May 15, 2017
June 30, 20170.125July 19, 2017July 31, 2017August 15, 2017
September 30, 20170.125October 18, 2017October 31, 2017November 15, 2017
December 31, 20170.125January 17, 2018January 31, 2018February 15, 2018

As previously announced, as a result of substantial balance sheet improvement achieved since the end of 2015, we have taken multiple steps to return significant value to our shareholders. First, we expect to declare an annual dividend of $0.80 per common share for 2018, a 60% increase from the 2017 dividend per common share. The first 2018 increase is expected to be the dividend declared for the first quarter of 2018. Additionally, we plan to increase our dividend to $1.00 per common share in 2019 and $1.25 per common share in 2020, a growth rate of 25% annually.

The actual amount of common dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” All of these matters will be taken into consideration by our board of directors in declaring dividends.

Our common stock dividends are not cumulative. Consequently, if dividends on our common stock are not paid at the intended levels, our common stockholders are not entitled to receive those payments in the future. Our common stock dividends generally will be paid on or about the 15th day of each February, May, August and November.

KMI Preferred Stock Dividends

Dividends on our mandatory convertible preferred stock are payable on a cumulative basis when, as and if declared by our board of directors (or an authorized committee thereof) at an annual rate of 9.750% of the liquidation preference of $1,000 per share on January 26, April 26, July 26 and October 26 of each year, commencing on January 26, 2016 to, and including, October 26, 2018. We may pay dividends in cash or, subject to certain limitations, in shares of common stock or any combination of cash and shares of common stock. The terms of the mandatory convertible preferred stock provide that, unless full cumulative dividends have been paid or set aside for payment on all outstanding mandatory convertible preferred stock for all prior dividend periods, no dividends may be declared or paid on common stock.

PeriodTotal dividend per share for the periodDate of declarationDate of recordDate of dividend
January 26, 2017 through April 25, 2017$24.375January 18, 2017April 11, 2017April 26, 2017
April 26, 2017 through July 25, 201724.375April 19, 2017July 11, 2017July 26, 2017
July 26, 2017 through October 25, 201724.375July 19, 2017October 11, 2017October 26, 2017
October 26, 2017 through January 25, 201824.375October 18, 2017January 11, 2018January 26, 2018

The cash dividend of $24.375 per share of our mandatory convertible preferred stock is equivalent to $1.21875 per depository share.

Stock Buyback Program

On July 19, 2017, our board of directors approved a $2 billion common share buyback program that began in December 2017. During the year ended December 31, 2017, we repurchased approximately 14 million of our Class P shares for approximately $250 million. Subsequent to December 31, 2017 and through February 8, 2018, we repurchased approximately 13 million of our Class P shares for approximately $250 million.

Noncontrolling Interests

Contributions

KML Restricted Voting Shares

As discussed in Note 3 “Acquisitions and Divestitures” to our consolidated financial statements, on May 30, 2017 our indirect subsidiary, KML, issued 102,942,000 restricted voting shares in a public offering. The public ownership of the KML restricted voting shares represents an approximate 30% interest in the voting shares of our Canadian operations and is reflected within “Noncontrolling interests” in our consolidated financial statements as of and for the periods presented after May 30, 2017.

KML Preferred Share Offerings

On August 15, 2017, KML completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 1 Preferred Share for total gross proceeds of C$300 million (U.S.$235 million). On December 15, 2017, KML completed an offering of 10,000,000 cumulative redeemable minimum rate reset preferred shares, Series 3 (Series 3 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 3 Preferred Share for total gross proceeds of C$250 million (U.S.$195 million). The net proceeds from the Series 1 and Series 3 Preferred Share offerings of C$293 million (U.S.$230 million) and C$243 million (U.S.$189 million), respectively, were used by KML to indirectly subscribe for preferred units in Kinder Morgan Canada Limited Partnership (KMC LP), which in turn were used by KMC LP to repay KML Credit Facility indebtedness recently incurred to, directly or indirectly, finance the development, construction and completion of the TMEP and Base Line Terminal project, and for general corporate purposes.

KML Distributions

KML established a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its DCF. The payment of dividends is not guaranteed and the amount and timing of any dividends payable will be at the discretion of KML’s board of directors. The actual amount of cash dividends paid to KML’s shareholders, if any, will depend on numerous factors including: (i) KML’s results of operations; (ii) KML’s financial requirements, including the funding of its current and future growth projects; (iii) the amount of distributions paid indirectly by KMC LP to KML through Kinder Morgan Canada GP Inc. (KMC GP), including any contributions from the completion of its growth projects; (iv) the satisfaction by KML and KMC GP of certain liquidity and solvency tests; (v) any agreements relating to KML’s indebtedness or the limited partnership; and (vi) the cost and timely completion of current and future growth projects. KML intends to pay quarterly dividends, if any, on or about the 45th day (or next business day) following the end of each calendar quarter to holders of its restricted voting shares of record as of the close of business on or about the last business day of the month following the end of each calendar quarter.

KML also established a Dividend Reinvestment Plan (DRIP) which allows holders (excluding holders not resident in Canada) of restricted voting shares to elect to have any or all cash dividends payable to such shareholder automatically reinvested in additional restricted voting shares at a price per share calculated by reference to the volume-weighted average of the closing price of the restricted voting shares on the stock exchange on which the restricted voting shares are then listed for the five trading days immediately preceding the relevant dividend payment date, less a discount of between 0% and 5% (as determined from time to time by KML’s board of directors, in its sole discretion).

For 2018, KML announced that it expects to pay an annual dividend of C$0.65 per restricted voting share.

Dividends on the Series 1 Preferred Shares are fixed, cumulative, preferential and C$1.3125 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding November 15, 2022.

Dividends on the Series 3 Preferred Shares are fixed, cumulative, preferential and C$1.3000 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding February 15, 2023.

The following table provides information regarding distributions to our noncontrolling interests (in millions except per share and share distribution amounts):

Year Ended December 31, 2017
SharesU.S.$C$
KML Restricted Voting Shares(a)
Per restricted voting share declared for the period(b)$0.3821
Per restricted voting share paid in the period$0.17390.2196
Total value of distributions paid in the period1823
Cash distributions paid in the period to the public1316
Share distributions paid in the period to the public under KML’s DRIP418,989
KML Series 1 Preferred Shares(c)
Per Series 1 Preferred Share paid in the period$0.2624$0.3308
Cash distributions paid in the period to the public34
(a)Represents dividends subsequent to KML’s May 30, 2017 IPO.
(b)The U.S.$ equivalent of the dividends declared is calculated based on the exchange rate on the dividend payment date, therefore, the U.S.$ equivalent of the dividend declared for the fourth quarter of 2017 will be calculated using the exchange rate on February 15, 2018.

The combined U.S.$ equivalent of the dividends declared for the second and third quarters of 2017 was $0.1739.

(c)Represents dividends subsequent to the issuance of KML’s Series 1 Preferred Shares.

On January 17, 2018, KML’s board of directors declared a cash dividend of C$0.328125 per share of its Series 1 Preferred Shares for the period from and including November 15, 2017 through and including February 14, 2018, which is payable on February 15, 2018 to Series 1 Preferred Shareholders of record as of the close of business on January 31, 2018.

On January 17, 2018, KML’s board of directors declared a cash dividend of C$0.22082 per share of its Series 3 Preferred Shares for the period from and including December 15, 2017 through and including February 14, 2018, which is payable on February 15, 2018 to Series 3 Preferred Shareholders of record as of the close of business on January 31, 2018.

Recent Accounting Pronouncements

Please refer to Note 18 “Recent Accounting Pronouncements” to our consolidated financial statements for information concerning recent accounting pronouncements.

Previous: Item 6. Selected Financial Data. · Next: Item 7A. Quantitative and Qualitative Disclosures About Market Risk.