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

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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 2016, 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 coal, petroleum coke, fertilizer, steel and ores 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, 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 77% 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, 2016, the remaining weighted average contract life of our natural gas transportation contracts (including intrastate pipelines’ purchase and sales contracts) was approximately six years.

Our midstream assets provide gathering and processing services for natural gas and gathering services for crude oil. These assets are generally 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, we also provide some services based on percent-of-proceeds, percent-of-index and keep-whole contracts some of which may include minimum volume requirements. 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, 2016, had a remaining average contract life of approximately nine 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 2017, and utilizing the average oil price per barrel contained in our 2017 budget, approximately 98% of our revenue is based on a fixed fee or floor price, and 2% 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 $61.52 per barrel in 2016, $73.11 per barrel in 2015, and $88.41 per barrel in 2014. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $41.36 per barrel in 2016, $47.56 per barrel in 2015, and $86.48 per barrel in 2014.

The factors impacting our Terminals business segment generally differ 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 longer-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 four 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, 2016, we have twelve 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 predominately 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 55 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.

A portion of our business portfolio 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. Our Canadian operations are included in three of our business segments: (i) our Kinder Morgan Canada segment, which is comprised of the Trans Mountain pipeline, an oversubscribed common carrier crude oil and refined petroleum pipeline serving western Canada, the Trans Mountain (Puget) pipeline serving Washington state; and the Jet Fuel pipeline serving Vancouver International Airport; (ii) terminal facilities located in western Canada that are included in our Terminals business segment; and (iii) the Canadian portion of our Cochin pipeline, which is included in our Products Pipelines business segment.

In our discussions of the operating results of individual businesses that follow (see “—Results of Operations” below), 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.

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 assign purchase price from business combinations, determine possible asset and equity investment impairment charges, and 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 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, 2016, our pension plans were underfunded by $724 million and our other postretirement benefits plans were underfunded by $141 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, 2016, we had deferred net losses of approximately $613 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, 2016:

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$(10)$236$(1)$37
Expected return on plan assets(21)—(3)—
Rate of compensation increase4(11)——
Health care cost trends——3(31)
One percent decrease in:
Discount rates12(278)—(42)
Expected return on plan assets21—3—
Rate of compensation increase(3)10——
Health care cost trends——(4)27
(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 effective. 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 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,” distributable cash flow, or 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.

Segment results for the years ended December 31, 2015 and 2014 have been retrospectively adjusted to reflect the elimination of the Other segment as a reportable segment. The activities that previously comprised the Other segment are now presented within the Corporate non-segment activities in reconciling to the consolidated totals in the respective segment reporting tables. The Other segment had historically been comprised primarily of legacy operations of acquired businesses not associated with our ongoing operations. These business activities have since been sold or have otherwise ceased. In addition, the Other segment included certain company owned real estate assets which are primarily leased to our operating subsidiaries as well as third party tenants. This activity is now reflected within Corporate activity. In addition, the portions of interest income and income tax expense previously allocated to our business segments are now included in “Interest expense, net” and “Income tax expense” for all periods presented in the following tables.

Consolidated Earnings Results

Year Ended December 31,
201620152014
(In millions)
Segment EBDA(a)
Natural Gas Pipelines$3,211$3,067$4,264
CO28276581,248
Terminals1,078878973
Products Pipelines1,0671,106856
Kinder Morgan Canada181182200
Total segment EBDA(b)6,3645,8917,541
DD&A(2,209)(2,309)(2,040)
Amortization of excess cost of equity investments(59)(51)(45)
General and administrative expenses(c)(669)(690)(610)
Interest expense, net(d)(1,806)(2,051)(1,798)
Corporate(e)17(18)43
Income before income taxes1,6387723,091
Income tax expense(917)(564)(648)
Net income7212082,443
Net (income) loss attributable to noncontrolling interests(13)45(1,417)
Net income attributable to Kinder Morgan, Inc.7082531,026
Preferred Stock Dividends(156)(26)—
Net Income Available to Common Stockholders$552$227$1,026
(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)2016, 2015 and 2014 amounts include decreases in earnings of $1,121 million, $1,748 million and $67 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)2016, 2015 and 2014 amounts include decreases (increase) to expense of $5 million, $(25) million and $28 million, respectively, related to the combined net effect of the certain items related to general and administrative expenses disclosed below in “—General and Administrative, Interest, Corporate and Noncontrolling Interests.”
(d)2016, 2015 and 2014 amounts include decreases in expense of $193 million, $27 million and $3 million, respectively, related to the combined net effect of the certain items related to interest expense, net disclosed below in “—General and Administrative, Interest, Corporate and Noncontrolling Interests.”
(e)2016, 2015 and 2014 amounts include decreases (increase) to expense of $8 million, $(35) million and $22 million, respectively, related to the combined net effect of the certain items related to Corporate activities disclosed below in “—General and Administrative, Interest, Corporate and Noncontrolling Interests.

Year Ended December 31, 2016 vs. 2015

The certain item totals reflected in footnotes (b), (c), (d) and (e) 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.

Year Ended December 31, 2015 vs. 2014

The certain item totals reflected in footnotes (b), (c), (d) and (e) to the table above accounted for $1,767 million of the decrease in income before income taxes in 2015 as compared to 2014 (representing the difference between decreases of $1,781 million and $14 million in income before income taxes for 2015 and 2014, respectively). After giving effect to these certain items, which are discussed in more detail in the discussion that follows, the remaining decrease of $552 million (18%) from the prior year in income before income taxes is primarily attributable to increased DD&A expense, general and administrative expense and interest expense, net. As explained further below, our total segment earnings before DD&A did not change significantly when compared to the prior year as unfavorable commodity prices affecting our CO2 business segment were offset by increased results from our Products Pipelines, Terminals and Natural Gas Pipelines business segments.

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 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, hurricane impacts 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.

Distributable Cash Flow

DCF is a significant performance measure used by us and by external users of our financial statements to evaluate our performance and to measure and estimate the ability of our assets to generate cash earnings after servicing our debt and preferred stock dividends, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as common stock dividends, stock repurchases, retirement of debt, or expansion capital expenditures. Management uses this performance measure and believes it provides users of our financial statements a useful performance measure reflective of our business’s ability to generate cash earnings to supplement the comparable GAAP measure. We believe the GAAP measure most directly comparable to DCF is net income available to common stockholders. A reconciliation of DCF to net income available to common stockholders is provided 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,
201620152014
(In millions)
Net Income Available to Common Stockholders$552$227$1,026
Add/(Subtract):
Certain items before book tax(a)9151,78114
Book tax certain items(b)18(340)(117)
Certain items after book tax9331,441(103)
Noncontrolling interest certain items(c)(8)(63)—
Net income available to common stockholders before certain items1,4771,605923
Add/(Subtract):
DD&A expense(d)2,6172,6832,390
Total book taxes(e)993976840
Cash taxes(f)(79)(32)(448)
Other items(g)433217
Sustaining capital expenditures(h)(540)(565)(509)
Net income attributable to noncontrolling interests of our former master limited partnerships——1,405
Declared distributions to noncontrolling interests(i)——(2,000)
DCF$4,511$4,699$2,618
Weighted average common shares outstanding for dividends(j)2,2382,2001,312
DCF per common share$2.02$2.14$2.00
Declared dividend per common share0.5001.6051.740
(a)Consists of certain items summarized in footnotes (b) through (e) 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, Interest, Corporate and Noncontrolling Interests.”
(b)Represents income tax provision on certain items plus discrete income tax items. For 2016, discrete income tax items included 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)Represents noncontrolling interests share of certain items.
(d)Includes DD&A, amortization of excess cost of equity investments and our share of equity investee’s DD&A of $349 million, $323 million and $305 million in 2016, 2015 and 2014, respectively.
(e)Excludes book tax certain items. 2016, 2015 and 2014 amounts also include $94 million, $72 million and $75 million, respectively, of our share of taxable equity investee’s book tax expense.
(f)Includes our share of taxable equity investee’s cash taxes of $(76) million, $(19) million and $(27) million in 2016, 2015 and 2014, respectively.
(g)For 2016 and 2015, consists primarily of non-cash compensation associated with our restricted stock awards program and for 2014 consists primarily of excess coverage from our former master limited partnerships.
(h)Includes our share of equity investee’s sustaining capital expenditures of $(90) million, $(70) million and $(59) million in 2016, 2015 and 2014, respectively.
(i)Represents distributions to KMP and EPB limited partner units formerly owned by the public for the respective period.
(j)Includes restricted stock awards that participate in common share dividends and, for 2015, the dilutive effect of warrants. 2014 amount also includes the common shares issued on November 26, 2014 for the Merger Transactions as if outstanding for the entire fourth quarter which differs from our GAAP presentation on our Consolidated Statement of Income.

Segment Earnings Results

Natural Gas Pipelines

Year Ended December 31,
201620152014
(In millions, except operating statistics)
Revenues(a)$8,005$8,725$10,168
Operating expenses(4,393)(4,738)(6,241)
Loss on impairment of goodwill(b)—(1,150)—
Loss on impairments and divestitures, net(b)(200)(122)(5)
Other income13—
Earnings from equity investments385351318
Loss on impairments of equity investments(b)(606)(26)—
Other, net192424
Segment EBDA(b)(c)3,2113,0674,264
Certain items(b)8251,062(190)
Segment EBDA before certain items(c)$4,036$4,129$4,074
Change from prior periodIncrease/(Decrease)
Revenues before certain items$(477)$(1,479)
Segment EBDA before certain items$(93)$55
Natural gas transport volumes (BBtu/d)(d)28,09528,19626,917
Natural gas sales volumes (BBtu/d)2,3352,4192,334
Natural gas gathering volumes (BBtu/d)(d)2,9703,5403,394
Crude/condensate gathering volumes (MBbl/d)(d)308340298

Certain items affecting Segment EBDA

(a)2016 and 2014 amounts include decreases in revenues of $50 million and $2 million, respectively, and 2015 amount includes an increase in revenues of $32 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 and 2014 amounts also include increases in revenues of $200 million and $198 million, respectively, associated with amounts collected on the early termination of long-term natural gas transportation contracts on KMLP.
(b)In addition to the revenue certain items described in footnote (a) above, 2016 amount also includes (i) $613 million related to equity investment impairments primarily related to our investments in MEP and Ruby; (ii) a decrease in earnings of $106 million of project write-offs; (iii) an $84 million pre-tax loss on the sale of a 50% interest in our SNG natural gas pipeline system; (iv) an increase in earnings of $18 million related to the early termination of a customer contract at an equity investee; and (v) a decrease in earnings of $29 million from other certain items. 2015 amount also includes (i) $1,150 million of losses related to goodwill impairments on our non-regulated midstream reporting unit; (ii) $52 million of losses related to divestitures of our non-regulated midstream assets; (iii) $47 million of losses related to other impairments on our non-regulated midstream assets; (iv) $26 million of impairments on equity investments; and (v) a $19 million net decrease in earnings related to project write-offs and other certain items. 2014 amount also includes a $6 million decrease in earnings from other certain items.

Other

(c)Income tax expense and interest income that were allocated to and presented in Segment EBDA in prior periods are presented herein in income tax expense and interest expense, net, respectively, to conform to our current presentation as discussed above in “—Overview.” The amounts for 2016, 2015 and 2014 were $7 million, $4 million and $6 million, respectively, in income tax expense and for 2014, $1 million in interest income.
(d)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 2016 and 2015, when compared with the respective prior year:

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)%
CPG(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 The Southern Company (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 CPG 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.

Year Ended December 31, 2015 versus Year Ended December 31, 2014

Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
Hiland Midstream$140n/a$404n/a
TGP364%484%
EPNG359%5610%
EagleHawk(a)31443%n/an/a
Texas Intrastate Natural Gas Pipeline Operations154%(1,231)(30)%
KinderHawk(67)(34)%(69)(31)%
Oklahoma Midstream(38)(57)%(247)(47)%
KMLP(33)(59)%(34)(50)%
CPG(24)(29)%(24)(24)%
Altamont Midstream(21)(35)%(60)(37)%
South Texas Midstream(9)(3)%(417)(25)%
All others (including eliminations)(10)(1)%957%
Total Natural Gas Pipelines$551%$(1,479)(15)%

n/a - not applicable

(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 2015 and 2014:

•increase of $140 million from our February 2015 acquisition of the Hiland Midstream asset;
•increase of $36 million (4%) from TGP primarily due to higher revenues from firm transportation and storage services due largely to expansion projects placed in service in the fourth quarter 2014 and during 2015. Partially offsetting this was an increase in the provision for revenue sharing during 2015, lower transportation usage revenues and natural gas park and loan revenues due to milder winter weather in 2015 and higher ad valorem taxes;
•increase of $35 million (9%) from EPNG due largely to additional firm transport revenues due, in part, to additional demand from Mexico;
•increase of $31 million (443%) from EagleHawk driven by higher volumes and lower pipeline integrity costs;
•increase of $15 million (4%) 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) due largely to higher transportation and natural gas sales margins as a result of new customer contracts, partially offset by lower processing margins due to the non-renewal of a customer contract in the second quarter of 2014 and lower storage margins. The decrease in revenues of $1,231 million and associated decrease in costs of goods sold were caused by lower natural gas prices;
•decrease of $67 million (34%) from KinderHawk primarily due to the expiration of a minimum volume contract;
•decrease of $38 million (57%) from Oklahoma Midstream primarily due to lower commodity prices and lower volumes. Lower revenues of $247 million and associated decrease in costs of goods sold were also due to lower commodity prices;
•decrease of $33 million (59%) from KMLP as a result of a customer contract buyout in the third quarter of 2014;
•decrease of $24 million (29%) from CPG due primarily to lower transport revenues as a result of contract expirations;
•decrease of $21 million (35%) from Altamont Midstream primarily due to lower commodity prices partially offset by higher volumes; and
•decrease of $9 million (3%) from South Texas Midstream primarily due to lower commodity prices, partially offset by higher gathering and processing volumes. Lower revenues of $417 million and associated decrease in costs of goods sold were due to lower commodity prices.

CO2

Year Ended December 31,
201620152014
(In millions, except operating statistics)
Revenues(a)$1,221$1,699$1,960
Operating expenses(399)(432)(494)
Loss on impairments and divestitures, net(b)(19)(606)(243)
Earnings from equity investments(b)24(3)25
Segment EBDA(b)(c)8276581,248
Certain items(b)92484218
Segment EBDA before certain items(c)$919$1,142$1,466
Change from prior periodIncrease/(Decrease)
Revenues before certain items$(267)$(384)
Segment EBDA before certain items$(223)$(324)
Southwest Colorado CO2 production (gross) (Bcf/d)(d)1.21.21.3
Southwest Colorado CO2 production (net) (Bcf/d)(d)0.60.60.5
SACROC oil production (gross)(MBbl/d)(e)29.333.833.2
SACROC oil production (net)(MBbl/d)(f)24.428.127.6
Yates oil production (gross)(MBbl/d)(e)18.419.019.5
Yates oil production (net)(MBbl/d)(f)8.28.58.8
Katz, Goldsmith, and Tall Cotton Oil Production - Gross (MBbl/d)(e)7.05.74.9
Katz, Goldsmith, and Tall Cotton Oil Production - Net (MBbl/d)(f)5.94.84.1
NGL sales volumes (net)(MBbl/d)(f)10.310.410.1
Realized weighted-average oil price per Bbl(g)$61.52$73.11$88.41
Realized weighted-average NGL price per Bbl(h)$17.91$18.35$41.87

Certain items affecting Segment EBDA

(a)2016, 2015 and 2014 amounts include an unrealized loss of $63 million, and unrealized gains of $138 million and $25 million, respectively, all relating to derivative contracts used to hedge forecasted commodity sales. 2015 amount also includes a favorable adjustment of $10 million related to carried working interest at McElmo Dome.
(b)In addition to the revenue certain items described in footnote (a) above: 2016 amount also includes a decrease of $9 million in equity earnings for our share of a project write-off recorded by an equity investee and a $20 million increase in expense related to source and transportation project write-offs. 2015 amount also includes (i) oil and gas property impairments of $399 million; (ii) project write-offs of $207 million; and (iii) a $26 million decrease in equity earnings for our share of a project write-off. 2014 amount also includes oil and gas property impairments of $243 million.

Other

(c)Income tax expense that was allocated to and presented in Segment EBDA in prior periods is presented herein in income tax expense to conform to our current presentation as discussed above in “—Overview.” The amounts for 2016, 2015 and 2014 were $2 million, $1 million and $8 million, respectively, in income tax expense.
(d)Includes McElmo Dome and Doe Canyon sales volumes.
(e)Represents 100% of the production from the field. We own 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 2016 and 2015, when compared with the respective prior year:

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.

Year Ended December 31, 2015 versus Year Ended December 31, 2014
Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
Source and Transportation Activities$(122)(27)%$(116)(23)%
Oil and Gas Producing Activities(202)(20)%(303)(20)%
Intrasegment Eliminations——%3542%
Total CO2$(324)(22)%$(384)(20)%

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 2015 and 2014 which factors include lower revenues of $405 million from lower commodity prices partially offset by $62 million of increased volumes and $27 million in reduced operating expenses.

Terminals

Year Ended December 31,
201620152014
(In millions, except operating statistics)
Revenues(a)$1,922$1,879$1,718
Operating expenses(768)(836)(746)
Loss on impairments and divestitures, net(b)(99)(191)(29)
Other income—1—
Earnings from equity investments352118
Loss on impairments and divestitures of equity investments, net(b)(16)(4)—
Other, net4812
Segment EBDA(b)(c)1,078878973
Certain items, net(b)9120635
Segment EBDA before certain items(c)$1,169$1,084$1,008
Change from prior periodIncrease/(Decrease)
Revenues before certain items$38$156
Segment EBDA before certain items$85$76
Bulk transload tonnage (MMtons)(d)61.863.279.8
Ethanol (MMBbl)66.763.166.5
Liquids leaseable capacity (MMBbl)87.881.577.8
Liquids utilization %(e)94.8%93.6%95.3%

Certain items affecting Segment EBDA

(a)2016, 2015 and 2014 amounts include increases in revenues of $28 million, $23 million and $18 million, respectively, from the amortization of a fair value adjustment (associated with the below market contracts assumed upon acquisition) from our Jones Act tankers.
(b)In addition to the revenue certain items described in footnote (a) above: 2016 amount also includes increases in expense of $103 million related to losses on impairments and divestitures, net and $16 million related to losses on impairments and divestitures of equity investments, net. 2015 amount also includes (i) 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; (ii) 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 (iii) $20 million primarily related to other impairment charges. 2014 amount also includes a $29 million write-down associated with a sale of certain terminals to a third-party and $24 million of increased expense from other certain items.

Other

(c)Income tax expense that was allocated to and presented in Segment EBDA in prior periods is presented herein in income tax expense to conform to our current presentation as discussed above in “—Overview.” The amounts for 2016, 2015 and 2014 were $42 million, $29 million and $29 million, respectively, in income tax expense.
(d)Includes our proportionate share of joint venture tonnage.
(e)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 2016 and 2015, when compared with the respective prior year:

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.
Year Ended December 31, 2015 versus Year Ended December 31, 2014
Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
Alberta, Canada$5276%$67102%
Marine Operations44n/a57n/a
Gulf Liquids2411%4114%
Gulf Central2352%3051%
Held for sale operations(17)(77)%(57)(67)%
Gulf Bulk(16)(18)%2215%
Mid Atlantic(21)(29)%(25)(18)%
All others (including intrasegment eliminations)(13)(3)%213%
Total Terminals$768%$1569%

n/a – not applicable

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 2015 and 2014:

•increase of $52 million (76%) from our Alberta, Canada terminals, driven by our Edmonton-area expansion projects, including storage and connectivity additions at our Edmonton South and North 40 terminals as well as the commissioning of two joint venture rail terminals;
•increase of $44 million from our Marine Operations related primarily to the incremental earnings from the Jones Act tankers we acquired in the first and fourth quarters of 2014 as well as the December 2015 delivery from the NASSCO shipyard of the first new build tanker, the Lone Star State;
•increase of $24 million (11%) from our Gulf Liquids terminals, related to the Vopak terminal acquisition completed in first quarter 2015 and the addition of nine new tanks at Galena Park placed into service during fourth quarter 2014 and first quarter 2015;
•increase of $23 million (52%) from our Gulf Central terminals, driven by higher earnings from our expansion projects at our joint venture terminals, Battleground Oil Specialty Terminal Company LLC (BOSTCO) and Deeprock Development LLC;
•decrease of $17 million (77%) from our sale of certain bulk and transload terminal facilities to Watco Companies, LLC in early 2015;
•decrease of $16 million (18%) from our Gulf Bulk terminals, primarily from reduced coal earnings due to certain coal customers bankruptcies of $27 million partially offset by increased shortfall revenue from take-or-pay coal contracts;
•decrease of $21 million (29%) from our Mid Atlantic terminals, driven by lower revenues as a result of lower tonnage partially offset by higher shortfall revenue from take-or-pay coal contracts; and
•decrease of $21 million primarily from reduced coal earnings due to certain coal customers bankruptcies, which impacted our International Marine Terminals and Mid River terminals included in “All others” and the Mid Atlantic terminals noted above by $16 million, $3 million and $2 million, respectively.

Products Pipelines

Year Ended December 31,
201620152014
(In millions, except operating statistics)
Revenues$1,649$1,831$2,068
Operating expenses(573)(772)(1,258)
Loss on impairments and divestitures, net(a)(76)——
Other (expense) income—(2)3
Earnings from equity investments534544
Gain on divestiture of equity investment(a)12——
Other, net24(1)
Segment EBDA(a)(b)1,0671,106856
Certain items(a)113(4)4
Segment EBDA before certain items(b)$1,180$1,102$860
Change from prior periodIncrease/(Decrease)
Revenues$(182)$(237)
Segment EBDA before certain items$78$242
Gasoline (MMBbl) (c)374.3368.9359.2
Diesel fuel (MMBbl)124.9129.1126.9
Jet fuel (MMBbl)105.2103.1100.5
Total refined product volumes (MMBbl)(d)604.4601.1586.6
NGL (MMBbl)(d)39.738.625.3
Condensate (MMBbl)(d)118.399.733.2
Total delivery volumes (MMBbl)762.4739.4645.1
Ethanol (MMBbl)(e)41.341.441.6

Certain items affecting Segment EBDA

(a)2016 amount includes increases in expense of (i) $65 million related to the Palmetto project write-off; (ii) $31 million of rate case liability estimate adjustments associated with prior periods; (iii) $20 million related to a legal settlement; and (iv) $9 million of non-cash impairment charges related to the sale of a Transmix facility; offset by a $12 million gain related to the sale of an equity investment. 2015 and 2014 amounts include a $4 million decrease in expense and a $4 million increase in expense, respectively, associated with a certain Pacific operations litigation matter.

Other

(b)Income tax expense and interest income that were allocated to and presented in Segment EBDA in prior periods are presented herein in income tax expense and interest expense, net, respectively, to conform to our current presentation as discussed above in “—Overview.”

The amounts for 2016, 2015 and 2014 were $(5) million, $8 million and $2 million, respectively, in income tax (benefit) expense and for 2015 and 2014, $2 million and $(2) million, respectively in interest income (expense).

(c)Volumes include ethanol pipeline volumes.
(d)Joint Venture throughput is reported at our ownership share.
(e)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 2016 and 2015, when compared with the respective prior year:

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.
Year Ended December 31, 2015 versus Year Ended December 31, 2014
Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
Crude & Condensate Pipeline$102124%$9081%
KMCC - Splitter33n/a43n/a
Double H pipeline44n/a56n/a
Cochin3540%5450%
Pacific operations237%276%
Transmix operations833%(490)(49)%
All others (including eliminations)(3)(1)%(17)(4)%
Total Products Pipelines$24228%$(237)(12)%

n/a - not applicable

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 2015 and 2014:

•increase of $102 million (124%) from Kinder Morgan Crude & Condensate Pipeline driven primarily by an increase of pipeline throughput volumes due to the ramp up of existing customer volumes and additional volumes from new customers;
•increase of $33 million from our KMCC - Splitter due to the startup of the first and second phases in March 2015 and July 2015;
•increase of $44 million from our Double H pipeline which was acquired in February 2015 as part of the Hiland acquisition;
•increase of $35 million (40%) from Cochin driven by higher service revenues due to the completion of the Cochin Reversal project in the third quarter of 2014;
•increase of $23 million (7%) from our Pacific operations due to higher service revenues, resulting from higher volumes and margins; and
•increase of $8 million (33%) from our Transmix processing operations primarily due to favorable inventory adjustments impacting margins. The decrease in revenues of $490 million and associated decrease in costs of goods sold were caused by lower commodity prices.

Kinder Morgan Canada

Year Ended December 31,
201620152014
(In millions, except operating statistics)
Revenues$253$260$291
Operating expenses(87)(87)(106)
Other income—1—
Other, net15815
Segment EBDA(a)$181$182$200
Change from prior periodIncrease/(Decrease)
Revenues$(7)$(31)
Segment EBDA$(1)$(18)
Transport volumes (MMBbl)(b)115.2115.4106.8
(a)Income tax expense that was allocated to and presented in Segment EBDA in prior periods is presented herein in income tax expense to conform to our current presentation as discussed above in “—Overview.” The amounts for 2016, 2015 and 2014 were $20 million, $19 million and $18 million, respectively, in income tax expense.
(b)Represents Trans Mountain pipeline system volumes.

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%).

Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2015, when compared with 2014:

Year Ended December 31, 2015 versus Year Ended December 31, 2014
Segment EBDA before certain items increase/(decrease)Revenues before certain items increase/(decrease)
(In millions, except percentages)
Trans Mountain Pipeline$(12)(7)%$(30)(11)%
Express Pipeline(a)(6)(100)%n/an/a
Jet Fuel Pipeline——%(1)(17)%
Total Kinder Morgan Canada$(18)(9)%$(31)(11)%

n/a - not applicable

(a)Amount consists of unrealized foreign currency gains, net of book tax, on outstanding, short-term intercompany borrowings that were repaid in December 2014. We sold our debt and equity investments in Express Pipeline on March 14, 2013.

The changes in Segment EBDA for our Kinder Morgan Canada business segment are further explained by the significant factors driving Segment EBDA before certain items which factors include an unfavorable impact from foreign currency exchange rates, and repayment of the Express note as discussed in footnote (a) above.

General and Administrative, Interest, Corporate and Noncontrolling Interests

Year Ended December 31,
201620152014
(In millions)
General and administrative expense(a)(e)$669$690$610
Certain items(a)5(25)28
Management fee reimbursement(e)(34)(37)(36)
General and administrative expense before certain items$640$628$602
Interest expense, net(b)$1,806$2,051$1,798
Certain items(b)193273
Interest expense, net, before certain items$1,999$2,078$1,801
Corporate(c)(e)$(17)$18$(43)
Certain items(c)8(35)22
Management fee revenue(e)343736
Corporate before certain items$25$20$15
Net income (loss) attributable to noncontrolling interests$13$(45)$1,417
Noncontrolling interests associated with certain items(d)863—
Net income attributable to noncontrolling interests before certain items$21$18$1,417

Certain items

(a)2016 amount includes increases in expense of (i) $14 million related to severance costs; and (ii) $12 million related to acquisition costs; offset by a decrease in expense of $31 million related to certain corporate litigation matters. 2015 and 2014 amounts include decreases in expense of $35 million and $39 million related to pension credit income. 2015 amount also includes increases in expense of $45 million related to certain corporate legal matters and $15 million related to costs associated with acquisitions. 2014 amount also includes a net increase of $11 million in expense for various other certain items.
(b)2016, 2015 and 2014 amounts include (i) decreases in interest expense of $115 million, $71 million and $65 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions; (ii) a $34 million decrease, a $21 million increase and a $15 million increase, respectively, in interest expense related to certain litigation matters; and (iii) a $44 million decrease, a $23 million increase and

a $1 million decrease, respectively, in interest expense primarily related to non-cash true-ups of our estimates of swap ineffectiveness. 2014 amount also includes (i) increases in expense of $9 million of amortization of capitalized financing fees; (ii) $12 million of interest expense on margin for marketing contracts associated with legacy operations; and (iii) $27 million of interest expense related to the Merger Transactions.

(c)2015 amount is primarily related to a litigation matter and 2014 amount is primarily related to our foreign operations.
(d)2015 amount reflects the noncontrolling interest portion of certain items including (i) a $43 million impairment and a $6 million loss associated with Terminals segment certain items and disclosed above in “—Terminals” and (ii) a $14 million loss associated with a Natural Gas Pipelines segment impairment certain item and disclosed above in “—Natural Gas Pipelines.”

Other

(e)2016, 2015 and 2014 amounts include certain equity investee management fee revenue of $34 million, $37 million and $36 million, respectively. These amounts are recorded to the “Product sales and other” caption with the offsetting expenses primarily included in the “General and administrative” expense caption in our accompanying consolidated statements of income.

General and administrative expenses before certain items increased $12 million in 2016 and $26 million in 2015 when compared with the respective prior year. The increase in 2016 as compared to 2015 was primarily driven by higher benefit costs and lower capitalized costs partially offset by lower labor, outside services and insurance costs. The increase in 2015 as compared to 2014 was primarily driven by the acquisition of Hiland (effective February 13, 2015), lower capitalized costs and higher labor expenses partially offset by lower benefit 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 $79 million in 2016 and increased $277 million in 2015, respectively, when compared with the respective prior year. 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. The increase in 2015 as compared to 2014 was primarily due to higher weighted average debt balances as a result of capital expenditures, joint venture contributions and acquisitions that were made during 2014 and 2015, and incremental debt borrowings to fund the $3.9 billion cash portion of the Merger Transactions in November 2014.

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 December 31, 2016 and 2015, approximately 28% and 27%, respectively, 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.

After taking into effect the certain items, the Corporate expense for 2016 and 2015 increased by $5 million for each respective period when compared with the respective prior year.

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 2016 as compared to 2015 increased $3 million (17%). The $1,399 million decrease (99%) for 2015 as compared to 2014 was primarily due to our purchase of the KMP and EPB limited partner units and KMR shares formerly owned by the public in the fourth quarter of 2014 as part of the Merger Transactions.

Income Taxes

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.

Year Ended December 31, 2015 versus Year Ended December 31, 2014

Our tax expense for the year ended December 31, 2015 was $564 million, as compared with 2014 tax expense of $648 million. The $84 million decrease in tax expense is due primarily to (i) the tax impact of lower pretax earnings in 2015 primarily due to our recognition of $929 million of impairments on long-lived assets and investments and $1,150 million

goodwill impairment of natural gas pipelines non-regulated midstream assets, of which $882 million is not tax deductible; (ii) the tax benefit of an increase in the deferred state tax rate as a result of the Hiland acquisition; (iii) the 2014 recording of a valuation allowance related to our investment in NGPL; and (iv) the elimination, as a result of the Merger Transactions, of the amortization of the deferred charge recorded as a result of the drop-downs of TGP, EPNG, and the midstream assets. These decreases are partially offset by the 2014 benefit of a worthless stock deduction related to our Brazil operations.

Liquidity and Capital Resources

General

As of December 31, 2016, we had $684 million of “Cash and cash equivalents,” an increase of $455 million (199%) from December 31, 2015. 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 $4,787 million and $5,303 million in 2016 and 2015, respectively. The year-to-year decrease is discussed below in “Cash Flows—Operating Activities.” We have relied on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, and dividend payments, and during 2016, to fund our expansion capital expenditures.

On September 1, 2016, we completed the sale of a 50% interest in our SNG natural gas pipeline system to Southern Company, receiving proceeds of approximately $1.4 billion. We used the proceeds from this transaction to reduce outstanding debt. In addition to repaying outstanding commercial paper and credit facility borrowings, proceeds from the sale were also used on September 30, 2016 to repay the $332 million principal amount of Copano’s 7.125% notes due 2021, and on October 1, 2016, to repay the $749 million principal amount of Hiland’s 7.25% senior notes due 2020 (see Note 9 “Debt”). As of September 1, 2016, SNG had $1,211 million of debt outstanding (including a current portion of $500 million) which is no longer consolidated on our balance sheet.

On August 16, 2016, CIG completed a private offering of $375 million in principal amount of 4.15% senior notes due August 15, 2026. We received net proceeds of $372 million from the offering and used the proceeds from the sale of the notes to reduce debt incurred as the result of the repayment of CIG’s senior notes that matured in 2015 and for general corporate purposes.

On January 26, 2016, we announced the issuance of a new $1.0 billion term loan facility and the expansion of our revolving credit facility from $4.0 billion to $5.0 billion. The proceeds of the three-year unsecured term loan facility were used to refinance maturing long-term debt.

In general, 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 our current common stock dividend level will allow us to use retained cash to fund our growth projects in 2017. Moreover, as a result of our current common stock dividend policy and by continuing to focus on high-grading our growth project backlog to allocate capital to the highest return opportunities, we do not expect to need to access the equity capital markets to fund our 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. However, over the long term, we are subject to uncertain capital market conditions and there can be no assurance we will be able or willing to access the public or private markets for equity and/or long-term senior notes in the future. If we were unable or unwilling to access the capital markets, we would be required to either continue utilizing internally generated cash, restrict expansion capital expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involve higher costs or negatively affect our and/or our subsidiaries’ credit ratings.

As of December 31, 2016, 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, 2016.

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, 2016, our principal sources of short-term liquidity are (i) our $5.0 billion revolving credit facility and associated $4.0 billion commercial paper program; and (ii) 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 our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, have consistently generated strong cash flows from operations.

As of December 31, 2016, our $2,696 million of short-term debt consisted primarily of senior notes that mature in 2017. 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 or received from asset sales. Our short-term debt balance as of December 31, 2015 was $821 million.

We had working capital (defined as current assets less current liabilities) deficits of $2,695 million and $1,241 million as of December 31, 2016 and 2015, 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 partially pay down using retained cash from operations. The overall $1,454 million (117%) unfavorable change from year-end 2015 was primarily due to a net increase in our current portion of long-term debt, offset partially by a favorable change in cash. 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. In 2015, through an equity distribution agreement, we issued and sold through or to our sales agents and/or principals shares of our Class P common stock. For more information on our equity issuances during 2015 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, 2016 and 2015, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $36,205 million and $40,732 million, respectively. For more information regarding our debt-related transactions in 2016, 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.

To date, our debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt-related transactions in 2016, 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—Distributable Cash Flow”). 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, 2016, and the amount we expect to spend for 2017 to sustain and grow our business are as follows (in millions):

2016Expected 2017
Sustaining capital expenditures(a)$540$630
Discretionary capital expenditures(b)(c)$2,807$3,240
(a)2016 and Expected 2017 amounts include $90 million and $112 million, respectively, for our proportionate share of sustaining capital expenditures of certain unconsolidated joint ventures.
(b)2016 amount includes $574 million of discretionary capital expenditures of unconsolidated joint ventures and small acquisitions (i.e. excludes Hiland acquisition) and divestitures and excludes a combined $199 million of net changes from accrued capital expenditures and contractor retainage.
(c)Expected 2017 amount includes our contributions to certain unconsolidated joint ventures and small acquisitions and divestitures, net of contributions estimated from unaffiliated joint venture partners for consolidated 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)$38,901$2,696$6,148$4,626$25,431
Interest payments(b)26,4412,0263,6443,15417,617
Leases and rights-of-way obligations(c)764106180136342
Pension and postretirement welfare plans(d)970383435863
Transportation, volume and storage agreements(e)1,106169302261374
Other obligations(f)307709442101
Total$68,489$5,105$10,402$8,254$44,728
Other commercial commitments:
Standby letters of credit(g)$219$199$20$—$—
Capital expenditures(h)$1,112$1,112$—$—$—
(a)Less than 1 year amount primarily includes $2,541 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, KMI common stock and/or warrants. 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, 2016.
(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 fund assets for pension and other postretirement benefit plans at year-end. The payments by period include expected contributions to funded plans in 2017 and estimated benefit payments for unfunded plans in all years.
(e)Primarily represents transportation agreements of $469 million, volume agreements of $434 million and storage agreements for capacity on third party and an affiliate pipeline systems of $147 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 “Other long-term liabilities and deferred credits” in our consolidated balance sheets.
(g)The $219 million in letters of credit outstanding as of December 31, 2016 consisted of the following (i) $50 million under twelve letters of credit for insurance purposes; (ii) a $32 million letter of credit supporting our pipeline and terminal operations in Canada; (iii) our $30 million guarantee under 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 $10 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; and (vii) a combined $32 million in twenty-four letters of credit supporting environmental, power and marketing purposes, and other obligations of us and our subsidiaries.
(h)Represents commitments for the purchase of plant, property and equipment as of December 31, 2016 and obligations for the definitive construction agreement with Philly Tankers LLC for 2017.

Cash Flows

Operating Activities

The net decrease of $516 million (10%) in cash provided by operating activities in 2016 compared to 2015 was primarily attributable to:

•a $414 million decrease in cash from overall net income after adjusting our period-to-period $513 million increase in net income for non-cash items primarily consisting of the following: (i) loss on impairment of goodwill; (ii) net losses on impairments and divestitures; (iii) losses on impairment and divestitures of equity investments; (iv) gains on early extinguishment of debt; (See discussion above in “—Results of Operations” for further information regarding these items); (v) DD&A expenses (including amortization of excess cost of equity investments); (vi) deferred income taxes; and (vii) equity earnings from our equity investments; and
•a $102 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities. The decrease was driven, among other things, primarily by a $195 million income tax refund received in 2015, and lower cash flow due to unfavorable changes in the collection of trade and exchange gas receivables. These decreases were offset partially by higher cash flows associated with the timing of payments from our trade payables.

Investing Activities

The $4,001 million net decrease in cash used in investing activities in 2016 compared to 2015 was primarily attributable to:

•a $1,746 million decrease in expenditures for acquisitions and investments in 2016 compared to the respective 2015 period. The overall decrease in acquisitions was primarily related to the $324 million portion of the purchase price we paid in 2016 for the BP terminals acquisition, versus the $1,706 million (net of cash assumed) and $158 million we paid for the Hiland and Vopak acquisitions, respectively, and the $134 million we paid to increase our ownership in NGPL Holdings LLC to 50% in the 2015 period;
•a $1,401 million net increase in cash due to proceeds from the sale of a 50% equity interest in SNG;
•a $1,014 million reduction in capital expenditures; and
•a $291 million increase in cash due to an increase in proceeds from sales of other long-lived assets; partially offset by,
•a $312 million increase in contributions to equity investments in 2016 compared to 2015, primarily due to a $312 million contribution to our 50% investment in NGPL Holdings LLC in 2016; and
•a $142 million decrease in Other, net primarily due to unfavorable changes in restricted deposits associated with our hedging activities.

Financing Activities

The net decrease of $2,956 million in cash provided by financing activities in 2016 compared to 2015 was primarily attributable to:

•a $3,870 million decrease in financing activities resulting from the issuances of our Class P shares under our equity distribution agreement in 2015 with no Class P Share issuance activity in 2016;
•a $1,541 million decrease in financing activities due to the issuance of our mandatory convertible preferred stock in 2015;
•a $626 million decrease in net debt proceeds. See Note 9 “Debt” for further information regarding our debt activity; and
•a $154 million increase in dividends paid to our mandatory convertible preferred shareholders in 2016;

partially offset by,

•a $3,106 million reduction in dividend payments paid to our common shareholders; and
•a $106 million increase in contributions provided by noncontrolling interests, primarily reflecting the contributions received from BP for its 25% share of a newly formed joint venture.

Common Dividends

The table below reflects the payment of cash dividends of $0.50 per common share for 2016.

Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
March 31, 2016$0.125April 20, 2016May 2, 2016May 16, 2016
June 30, 2016$0.125July 20, 2016August 1, 2016August 15, 2016
September 30, 2016$0.125October 19, 2016November 1, 2016November 15, 2016
December 31, 2016$0.125January 18, 2017February 1, 2017February 15, 2017

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.

Preferred 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, 2016 through April 25, 2016$24.375January 20, 2016April 11, 2016April 26, 2016
April 26, 2016 through July 25, 2016$24.375April 20, 2016July 11, 2016July 26, 2016
July 26, 2016 through October 25, 2016$24.375July 20, 2016October 11, 2016October 26, 2016
October 26, 2016 through January 25, 2017$24.375October 19, 2016January 11, 2017January 26, 2017

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

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.