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 2015, 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 energy, bulk commodity and liquids products 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—(i) the ownership and/or operation of liquids and bulk terminal facilities located throughout the U.S. and portions of Canada that transload and store refined petroleum products, crude oil, condensate, and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals and (ii) the ownership and operation of our Jones Act tankers;
•Products Pipelines—the ownership and operation of refined petroleum products and crude oil and condensate pipelines that deliver refined petroleum products (gasoline, diesel fuel and jet fuel), NGL, crude oil, condensate and bio-fuels to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;
•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; and
•Other—primarily other miscellaneous assets and liabilities including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with legacy trading activities; and (iii) other miscellaneous assets and liabilities.

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 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 73% 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, 2015, the remaining 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, 2015, 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 2016, and utilizing the average oil price per barrel contained in our 2016 budget, approximately 99% of our revenue is based on a fixed fee or floor price, and 1% 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 all hedges allocated to oil, was $73.11 per barrel in 2015, $88.41 per barrel in 2014, and $92.70 per barrel in 2013. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $47.56 per barrel in 2015, $86.48 per barrel in 2014, and $94.94 per barrel in 2013.

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 coal, petroleum coke, and steel. 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. Our eight Jones Act qualified tankers operate in the marine transportation of crude oil, condensate and refined products in the U.S. and are currently operating pursuant to multi-year 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 (including the Kinder Morgan Canada business segment, the Canadian portion of the Cochin Pipeline, and the bulk and liquids terminal facilities located in Canada) transact in and/or use the Canadian dollar as the functional currency, which affect segment results due to the variability in U.S. - Canadian dollar exchange rates.

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) the economic useful lives of our assets and related depletion rates; (ii) the fair values used to assign purchase price from business combinations, determine possible asset impairment charges, and calculate the annual goodwill impairment test; (iii) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (iv) provisions for uncollectible accounts receivables; (v) exposures under contractual indemnifications; and (vi) unbilled revenues.

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 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.

For more information on our December 31, 2015 goodwill impairment evaluation and amortizable intangibles, see Note 8 “Goodwill” to our consolidated financial statements.

Estimated Net Recoverable Quantities of Oil and Gas

We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted or amortized into income, and the presentation of supplemental information on oil and gas producing activities. The expected future cash flows to be generated by oil and gas producing properties used in testing for impairment of such properties also rely in part on estimates of net recoverable quantities of oil and gas.

Proved reserves are the estimated quantities of oil and gas that geologic and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. For more information on our ownership interests in the net quantities of proved oil and gas reserves and our measures of discounted future net cash flows from oil and gas reserves, please see “Supplemental Information on Oil and Gas Producing Activities (Unaudited)”.

DD&A expense on our proved oil and gas properties is calculated using the unit of production (UOP) method. The reserves that are used to determine the UOP depletion rate for leasehold acquisition and the costs to acquire proved properties is the total of our developed and undeveloped proved reserves which are known as total proved reserves. The UOP depreciation rate for our tangible lease and well equipment costs, including development costs and exploration costs associated with successful drilling projects, is calculated based upon total proved developed reserves. Our estimated future well plugging and abandonment costs along with future expected salvage values are considered in the UOP DD&A expense calculation. For our oil and gas producing properties that have no proved reserves, the UOP depreciation rate is based on each property’s risk-adjusted probable reserves and NYMEX forward curve prices.

The sustained deterioration in the long-term outlook for commodity prices was a triggering event that required us to perform impairment testing of our assets that are sensitive to such commodity prices. During 2015, we performed a two-step impairment testing of certain long-lived assets within our CO2 segment, which resulted in the impairment of certain of our oil and gas producing properties in the amount of $399 million for the year ended December 31, 2015.

As of December 31, 2015, the net book value of productive properties, plant and equipment associated with our oil and gas proved reserves was approximately $932 million, which included 49.5 million barrels of oil equivalent of estimated proved developed reserves, and the DD&A expense recorded on these properties in 2015 was $376 million. If the estimates of proved reserves used in the unit-of-production calculation had been lower by 5%, DD&A expense in 2015 would have increased by approximately $15 million.

Continued lower commodity prices as indicated by forward curve pricing that is used in testing for impairment, estimated total proved and risk-adjusted probable oil and gas reserves, and related expected future cash flows, may result in additional impairments of our oil producing interests and increased DD&A expense in 2016. See Note 4 “Impairments and Disposals” to our consolidated financial statements.

Hedging Activities

We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices 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. We may or may not apply hedge accounting to our derivative contracts depending on the circumstances. All of our derivative contracts are recorded at estimated fair value. 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, 2015, our pension plans were underfunded by $604 million and our other postretirement benefits plans were underfunded by $184 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. For 2015, we selected our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities. The selection of these assumptions is further discussed in Note 10 “Share-based Compensation and Employee Benefits” to our consolidated financial statements. Effective January 1, 2016, we changed our estimate of the service and interest cost components of net periodic benefit cost (credit) for our pension and other postretirement benefit plans. The new estimate utilizes a full yield curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The new estimate provides a more precise measurement of service and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates. The change does not affect the measurement of our pension and postretirement benefit obligations and it is accounted for as a change in accounting estimate, which is applied prospectively. The change in the service and interest costs going forward will not be significant.

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, 2015, we had deferred net losses of approximately $535 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, 2015:

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$219$2$44
Expected return on plan assets(23)—(4)—
Rate of compensation increase3(10)——
Health care cost trends——4(31)
One percent decrease in:
Discount rates11(258)—(51)
Expected return on plan assets23—4—
Rate of compensation increase(3)9——
Health care cost trends——(2)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

We record a valuation allowance to reduce our deferred tax assets to an 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 addition, 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.

In determining the deferred income tax asset and liability balances attributable to our investments, we have applied 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

Non-GAAP Measures

The non-GAAP financial measures, DCF before certain items and segment EBDA before certain items are presented below under “—Distributable Cash Flow” and “—Consolidated Earnings Results,” respectively. Certain items are items that are required by GAAP to be reflected in net income, but typically either do not have a cash impact, or by their nature are separately identifiable from our normal business operations and, in our view, are likely to occur only sporadically.

Our non-GAAP measures described below should not be considered as an alternative to GAAP net income or any other GAAP measure. DCF before certain items and segment EBDA before certain items are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider either of these non-GAAP measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Because DCF before certain items excludes some but not all items that affect net income and because DCF measures are defined differently by different companies in our industry, our DCF before certain items may not be comparable to DCF measures of other companies. Our computation of segment EBDA before certain items has similar limitations. Management compensates for the limitations of these non-GAAP measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.

Distributable Cash Flow

DCF before certain items is an overall performance metric we use to estimate the ability of our assets to generate cash flows on an ongoing basis and as a measure of cash available to pay dividends. We believe the primary measure of company performance used by us, investors and industry analysts is cash generation performance. Therefore, we believe DCF before certain items is an important measure to evaluate our operating and financial performance and to compare it with the performance of other publicly traded companies within the industry.

The table below details the reconciliation of Net Income to DCF before certain items:

Year Ended December 31,
201520142013
(In millions)
Net Income$208$2,443$2,692
Add/(Subtract):
Certain items before book tax(a)(b)1,78114(609)
Book tax certain items(b)(c)(340)(117)(39)
Certain items after book tax1,441(103)(648)
Net income before certain items1,6492,3402,044
Add/(Subtract):
Net income attributable to third-party noncontrolling interests(d)(18)(12)(5)
DD&A expense(e)2,6832,3902,142
Book taxes(f)976840847
Cash taxes(g)(32)(448)(552)
Other items(h)32176
Sustaining capital expenditures(i)(565)(509)(414)
Declared distributions to noncontrolling interests(j)—(2,000)(2,355)
Subtotal3,076278(331)
DCF before certain items available to equity4,7252,6181,713
Preferred stock dividends(26)——
DCF before certain items available to common stockholders$4,699$2,618$1,713
Weighted average common shares outstanding for dividends(k)2,2001,3121,040
DCF per common share before certain items$2.14$2.00$1.65
Declared dividend per common share1.6051.7401.600
(a)Consists of certain items summarized in footnotes (b) through (e) to the “—Consolidated Earnings Results” table included below, 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, and Noncontrolling Interests.”
(b)2015 amount includes a $175 million non-cash pre-tax impairment ($84 million net after-tax impact to common stockholders) of a terminal facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer, which occurred after the issuance of our 2015 fourth quarter earnings release containing our preliminary financial results ($175 million in certain items before book tax and $(48) million in book tax certain items).
(c)Represents income tax provision on certain items plus discrete income tax items.
(d)Represents net income allocated to third-party ownership interests in consolidated subsidiaries other than our former master limited partnerships. 2015 amount excludes losses attributable to noncontrolling interests of $63 million related to impairments included as certain items, which includes a $43 million loss attributable to noncontrolling interests associated with the impairment discussed in footnote (b) above.
(e)Includes DD&A, amortization of excess cost of equity investments and our share of equity investee’s DD&A of $323 million, $305 million and $297 million in 2015, 2014 and 2013, respectively.
(f)Excludes book tax certain items and includes income tax allocated to the segments. 2015, 2014 and 2013 amounts also include $72 million, $75 million and $66 million, respectively, of our share of taxable equity investee’s book tax expense.
(g)Includes our share of taxable equity investee’s cash taxes of $(19) million, $(27) million and $(30) million in 2015, 2014 and 2013, respectively.
(h)For 2015, consists primarily of non-cash compensation associated with our restricted stock awards program and for 2014 and 2013 consists primarily of excess coverage from our former master limited partnerships.
(i)Includes our share of equity investee’s sustaining capital expenditures of $(70) million, $(59) million and $(48) million in 2015, 2014 and 2013, respectively.
(j)Represents distributions to KMP and EPB limited partner units formerly owned by the public for the respective period.
(k)Includes restricted stock awards that participate in dividends and, for 2015, the dilutive effect of warrants. 2014 amount also includes the 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.

Consolidated Earnings Results

In the Results of Operations table below and in the business segment tables that follow, segment EBDA before certain items is calculated by adjusting the segment earnings before DD&A for the applicable certain item amounts in the footnotes to those tables.

In general, interest expense, general and administrative expenses, DD&A, unallocable interest income and income taxes and net income attributable to noncontrolling interests are not controllable by our business segment operating managers and therefore are not included when we measure business segment operating performance. 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.

We evaluate business segment performance primarily based on segment EBDA before certain items in relation to the level of capital allocated and consider this to be an important measure of our business segment performance. We account for intersegment sales at market prices, which are eliminated in consolidation.

Year Ended December 31,
201520142013
(In millions)
Segment earnings before DD&A(a)
Natural Gas Pipelines$3,063$4,259$4,207
CO26571,2401,435
Terminals849944836
Products Pipelines1,100856602
Kinder Morgan Canada163182424
Other(53)13(5)
Total segment earnings before DD&A(b)5,7797,4947,499
DD&A expense(2,309)(2,040)(1,806)
Amortization of excess cost of equity investments(51)(45)(39)
Other revenues373636
General and administrative expenses(c)(690)(610)(613)
Interest expense, net of unallocable interest income(d)(2,055)(1,807)(1,688)
Income from continuing operations before unallocable income taxes7113,0283,389
Unallocable income tax expense(503)(585)(693)
Income from continuing operations2082,4432,696
Loss from discontinued operations, net of tax(e)——(4)
Net income2082,4432,692
Net loss (income) attributable to noncontrolling interests45(1,417)(1,499)
Net income attributable to Kinder Morgan, Inc.2531,0261,193
Preferred Stock Dividends(26)——
Net Income Available to Common Stockholders$227$1,026$1,193
(a)Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, other expense (income), net, losses on impairments of goodwill and losses on impairments and disposals of long-lived assets, net and equity investments. Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes. Allocable income tax expenses included in segment earnings for the years ended December 31, 2015, 2014 and 2013 were $61 million, $63 million and $49 million, respectively.

Certain item footnotes

(b)2015, 2014 and 2013 amounts include decreases (increase) in earnings of $1,783 million, $45 million and $(573) million, respectively, related to the combined effect of the certain items impacting segment earnings before DD&A from continuing operations and disclosed below in our management discussion and analysis of segment results.
(c)2015, 2014 and 2013 amounts include (increase) decreases to expense of $(25) million, $28 million and $8 million, respectively, related to the combined effect of the certain items related to general and administrative expenses disclosed below in “—General and Administrative, Interest, and Noncontrolling Interests.”
(d)2015, 2014 and 2013 amounts include decreases in expense of $27 million, $3 million and $32 million, respectively, related to the combined effect of the certain items related to interest expense, net of unallocable interest income disclosed below in “—General and Administrative, Interest, and Noncontrolling Interests.”
(e)2013 amount represents an incremental loss related to the sale of our FTC Natural Gas Pipelines disposal group effective November 1, 2012.

Year Ended December 31, 2015 vs. 2014

The certain item totals reflected in footnotes (b), (c) and (d) to the tables above accounted for $1,767 million of the decrease in income from continuing operations before unallocable income taxes in 2015 as compared to 2014 (representing the difference between decreases of $1,781 million and $14 million in total income from continuing operations before unallocable income taxes for 2015 and 2014, respectively). After giving effect to these certain items, the remaining decrease of $550 million (18%) from the prior year in income from continuing operations before unallocable income taxes is primarily attributable to increased DD&A expense, general and administrative expense and interest expense, net of unallocable interest income. 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.

Year Ended December 31, 2014 vs. 2013

The certain item totals reflected in footnotes (b), (c) and (d) to the tables above accounted for $627 million of the decrease in income from continuing operations before unallocable income taxes in 2014, when compared to 2013 (combining a decrease of $14 million and an increase of $613 million in total income from continuing operations before unallocable income taxes for 2014 and 2013, respectively). After giving effect to these certain items, the remaining increase of $266 million (10%) from the prior year in income from continuing operations before unallocable income taxes relates to better overall performance primarily from our Natural Gas Pipelines, Products Pipelines and Terminals segments in 2014.

Natural Gas Pipelines

Year Ended December 31,
201520142013
(In millions, except operating statistics)
Revenues(a)$8,725$10,168$8,617
Operating expenses(4,738)(6,241)(5,235)
Loss on impairment of goodwill(b)(1,150)——
Loss on impairments and disposals of long-lived assets and equity investments, net(b)(148)(5)(37)
Other income (expense)3—(4)
Earnings from equity investments351318297
Interest income and Other, net2425578
Income tax expense(4)(6)(9)
Segment earnings before DD&A from continuing operations(b)3,0634,2594,207
Discontinued operations(c)——(4)
Certain items(b)(c)1,062(190)(486)
EBDA before certain items$4,125$4,069$3,717
Change from prior periodIncrease/(Decrease)
Revenues before certain items$(1,479)$1,339
EBDA before certain items$56$352
Natural gas transport volumes (BBtu/d)(d)28,39827,06425,144
Natural gas sales volumes (BBtu/d)(e)2,4192,3342,458
Natural gas gathering volumes (BBtu/d)(f)3,5403,3942,959
Crude/condensate gathering volumes (MBbl/d)(g)340298225

Certain item footnotes

(a)2015 amount includes increase in revenues of $32 million and 2014 and 2013 amounts include decreases in revenues of $2 million and $16 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales. 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: 2015 amount also includes (i) $1,150 million of losses related to goodwill impairments on our non-regulated midstream assets; (ii) $52 million of losses related to disposals of our non-regulated midstream assets; (iii) $47 million of losses related to impairments on our non-regulated midstream assets; and (iv) $45 million net decrease in earnings related to project write-offs and other certain items. 2014 amount also includes $6 million decrease in earnings from other certain items. 2013 amount also includes (i) a $558 million gain from the remeasurement of a previously held 50% equity interest in Eagle Ford to fair value; (ii) a $36 million gain from the sale of certain Gulf Coast offshore and onshore TGP supply facilities; (iii) a $65 million non-cash equity investment impairment charge related to our ownership interest in NGPL Holdco LLC; and (iv) a combined $23 million decrease in earnings from other certain items.
(c)Represents a loss from the sale of our FTC Natural Gas Pipelines disposal group.

Other footnotes

(d)Includes pipeline volumes for Kinder Morgan North Texas Pipeline LLC, Monterrey, TransColorado Gas Transmission Company LLC,

MEP, KMLP, FEP, TGP, EPNG, South Texas Midstream, the Texas Intrastate Natural Gas Pipeline operations, CIG, WIC, CPG, SNG, Elba Express, Sierrita Gas Pipeline LLC, NGPL, Citrus and Ruby Pipeline, L.L.C. 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.

(e)Represents volumes for the Texas Intrastate Natural Gas Pipeline operations and Kinder Morgan North Texas Pipeline LLC.
(f)Includes Oklahoma Midstream, South Texas Midstream, Eagle Ford, North Texas Midstream, Camino Real Gathering Company, L.L.C. (Camino Real), Kinder Morgan Altamont LLC, KinderHawk, Endeavor, Bighorn Gas Gathering L.L.C., Webb Duval Gatherers, Fort Union Gas Gathering L.L.C., EagleHawk, Red Cedar Gathering Company and Hiland Midstream throughput volumes. Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included at our ownership share for the entire period.
(g)Includes Hiland Midstream, EagleHawk and Camino Real. Joint Venture throughput is reported at our ownership share. Volumes for

acquired pipelines are included at our ownership share for the entire period.

Following is information, including discontinued operations, related to the increases and decreases in both EBDA and revenues before certain items in 2015 and 2014, when compared with the respective prior year:

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

EBDA increase/(decrease)Revenues increase/(decrease)
(In millions, except percentages)
Hiland Midstream$140n/a$404n/a
TGP364%484%
EPNG348%5610%
EagleHawk(a)31443%n/an/a
Texas Intrastate Natural Gas Pipeline Operations175%(1,231)(30)%
KinderHawk(67)(34)%(69)(31)%
Oklahoma Midstream(b)(38)(57)%(247)(47)%
KMLP(34)(61)%(34)(50)%
CPG(24)(29)%(24)(24)%
Altamont Midstream(21)(35)%(60)(37)%
South Texas Midstream(b)(9)(3)%(417)(25)%
All others (including eliminations)(b)(9)(1)%957%
Total Natural Gas Pipelines$5614%$(1,479)(15)%

n/a - not applicable

(a)Equity investment.
(b)Includes amounts previously presented as part of “Copano operations.”

The significant changes in our Natural Gas Pipelines business segment’s EBDA before certain items in the comparable years of 2015 and 2014 included the following:

•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 $34 million (8%) 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 $17 million (5%) 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 $34 million (61%) 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.

Year Ended December 31, 2014 versus Year Ended December 31, 2013

EBDA increase/(decrease)Revenues increase/(decrease)
(In millions, except percentages)
Copano operations (including Eagle Ford)(a)$163n/a$998n/a
TGP12115%15114%
EPNG3710%5911%
Ruby(b)18199%n/an/a
Citrus(b)1315%n/an/a
Texas Intrastate Natural Gas Pipeline Operations113%43212%
WIC(24)(17)%(26)(15)%
SNG(17)(4)%(25)(4)%
All others (including eliminations)303%(250)(24)%
Total Natural Gas Pipelines$3529%$1,33916%

n/a – not applicable

(a)On May 1, 2013, as part of Copano acquisition, we acquired the remaining 50% interest of Eagle Ford. Prior to that date, we recorded earnings from Eagle Ford under the equity method of accounting, but we received distributions in amounts essentially equal to equity earnings plus our share of depreciation and amortization expenses less our share of sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput).
(b)Equity investment.

The significant changes in our Natural Gas Pipelines business segment’s EBDA before certain items in the comparable years of 2014 and 2013 included the following:

•increase of $163 million from full year ownership of our Copano operations, which we acquired effective May 1, 2013, including benefits from higher gathering volumes from the Eagle Ford Shale;
•increase of $121 million (15%) from TGP primarily due to higher revenues from (i) firm transportation and storage services due largely to new expansion projects placed in service in the latter part of 2013 and during 2014 and (ii) usage and interruptible transportation services due to weather-related demand relative to 2013. Partially offsetting the increase in 2014 revenues were higher operating and franchise tax expenses in 2014, and a favorable operational sales margin in 2013;
•increase of $37 million (10%) from EPNG, primarily driven by higher transportation revenues and throughput due to increased deliveries to California for storage refill and increased demand in Mexico. The increase in revenues was partially offset by higher field operation and maintenance expenses;
•increase of $18 million (199%) from Ruby due largely to higher contracted firm transportation revenues and lower interest expense;
•increase of $13 million (15%) from Citrus assets, primarily due to higher transportation revenues and reduction in property taxes;
•increase of $11 million (3%) from 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 natural gas sales and transportation margins driven by higher volumes, additional customer contracts and colder weather in the first quarter of 2014, which were offset by lower processing margin due to non-renewal of a certain contract;
•decrease of $24 million (17%) from WIC, primarily due to lower reservation revenue as a result of rate reductions pursuant to its FERC Section 5 rate settlement effective November 1, 2013 and lower rates on contract renewals; and
•decrease of $17 million (4%) from SNG, driven by lower reservation and usage revenues due to rate reductions pursuant to its rate case settlement effective September 1, 2013; partially offset by incremental revenues from increased firm transportation services and revenue related to an expansion project that was placed in service in late 2013.

CO2

Year Ended December 31,
201520142013
(In millions, except operating statistics)
Revenues(a)$1,699$1,960$1,857
Operating expenses(432)(494)(439)
Loss on impairments and disposals of long-lived assets, net(b)(606)(243)—
Earnings from equity investments(b)(3)2524
Income tax expense(1)(8)(7)
Segment earnings before DD&A(b)6571,2401,435
Certain items(b)484218(3)
EBDA before certain items$1,141$1,458$1,432
Change from prior periodIncrease/(Decrease)
Revenues before certain items$(384)$81
EBDA before certain items$(317)$26
Southwest Colorado CO2 production (gross) (Bcf/d)(c)1.21.31.2
Southwest Colorado CO2 production (net) (Bcf/d)(c)0.60.50.5
SACROC oil production (gross)(MBbl/d)(d)33.833.230.7
SACROC oil production (net)(MBbl/d)(e)28.127.625.5
Yates oil production (gross)(MBbl/d)(d)19.019.520.4
Yates oil production (net)(MBbl/d)(e)8.58.89.0
Katz, Goldsmith, and Tall Cotton Oil Production - Gross (MBbl/d)(d)5.74.93.4
Katz, Goldsmith, and Tall Cotton Oil Production - Net (MBbl/d)(e)4.84.12.8
NGL sales volumes (net)(MBbl/d)(e)10.410.19.9
Realized weighted-average oil price per Bbl(f)$73.11$88.41$92.70
Realized weighted-average NGL price per Bbl(g)$18.35$41.87$46.43

Certain item footnotes

(a)2015, 2014 and 2013 amounts include unrealized gains of $138 million, $25 million and $3 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil 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: 2015 amount 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 footnotes

(c)Includes McElmo Dome and Doe Canyon sales volumes.
(d)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.
(e)Net after royalties and outside working interests.
(f)Includes all crude oil production properties. Hedge gains/losses for Oil and NGL are included with Crude Oil.
(g)Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements. Hedge gains/losses for Oil and NGL are included with Crude Oil.

Following is information related to the increases and decreases in both EBDA and revenues before certain items in 2015 and 2014, when compared with the respective prior year:

Year Ended December 31, 2015 versus Year Ended December 31, 2014
EBDA increase/(decrease)Revenues increase/(decrease)
(In millions, except percentages)
Source and Transportation Activities$(115)(26)%$(116)(23)%
Oil and Gas Producing Activities(202)(20)%(303)(20)%
Intrasegment eliminations——%3542%
Total CO2$(317)(22)%$(384)(20)%

The primary changes in our CO2 business segment’s EBDA before certain items in the comparable years of 2015 and 2014 was primarily driven by $405 million from lower commodity prices partially offset by $62 million of increased volumes and $27 million in reduced operating expenses.

Year Ended December 31, 2014 versus Year Ended December 31, 2013
EBDA increase/(decrease)Revenues increase/(decrease)
(In millions, except percentages)
Source and Transportation Activities$5614%$5913%
Oil and Gas Producing Activities(30)(3)%262%
Intrasegment Eliminations——%(4)5%
Total CO2$262%$814%

The primary changes in our CO2 business segment’s EBDA before certain items in the comparable years of 2014 and 2013 included the following:

•increase of $56 million (14%) from source and transportation activities primarily due to higher revenues driven by an increase of average CO2 contract prices and higher CO2 volumes partly offset by higher labor costs, power costs, property taxes and severance taxes.; and
•decrease of $30 million (3%) from oil and gas producing activities primarily driven by higher operating expenses as a result of (i) incremental well work costs; (ii) increased power costs; and (iii) higher property and severance tax expenses related to higher revenues. Also contributing to the decrease was lower crude oil and NGL prices, which were offset by improved net crude oil production.

Terminals

Year Ended December 31,
201520142013
(In millions, except operating statistics)
Revenues(a)$1,879$1,718$1,410
Operating expenses(836)(746)(657)
Loss on impairments and disposals of long-lived assets and equity investments, net(b)(c)(195)(29)73
Other income1—1
Earnings from equity investments211822
Interest income and Other, net8121
Income tax expense(29)(29)(14)
Segment earnings before DD&A(b)(c)849944836
Certain items, net(b)(c)20635(38)
EBDA before certain items$1,055$979$798
Change from prior periodIncrease/(Decrease)
Revenues before certain items$156$298
EBDA before certain items$76$181
Bulk transload tonnage (MMtons)(d)63.279.882.1
Ethanol (MMBbl)63.166.561.2
Liquids leaseable capacity (MMBbl)81.377.868.0
Liquids utilization %(e)93.3%95.3%94.7%

Certain item footnotes

(a)2015 and 2014 amounts include increases in revenues of $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. 2013 amount includes an $8 million increase in revenues related to hurricane reimbursements.
(b)In addition to the revenue certain items described in footnote (a) above: 2015 amount includes a $34 million increase in bad debt expense due to certain coal customers bankruptcies related to revenues recognized in prior years but not yet collected and $20 million primarily related to 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. 2013 amount also includes (i) a $109 million increase in earnings from casualty indemnification gains; (ii) a $59 million increase in clean-up and repair expense, all related to 2012 hurricane activity at the New York Harbor and Mid-Atlantic terminals; and (iii) a combined $20 million decrease of earnings from other certain items.
(c)An additional $175 million non-cash pre-tax impairment ($84 million net after-tax impact to common stockholders) of a terminal facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer, which occurred after the issuance of our 2015 fourth quarter earnings release containing our preliminary financial results.

Other footnotes

(d)Includes our proportionate share of joint venture tonnage.
(e)The ratio of our actual leased capacity to our estimated potential capacity.

Following is information related to the increases and decreases in both EBDA and revenues before certain items in 2015 and 2014, when compared with the respective prior year:

Year Ended December 31, 2015 versus Year Ended December 31, 2014
EBDA increase/(decrease)Revenues increase/(decrease)
(In millions, except percentages)
Alberta, Canada$4570%$67102%
Marine Operations44n/a57n/a
Gulf Liquids2411%4114%
Gulf Central2352%3051%
Watco(17)(77)%(57)(67)%
Gulf Bulk(16)(18)%2215%
Mid Atlantic(14)(21)%(25)(18)%
All others (including intrasegment eliminations and unallocated income tax expenses)(13)(3)%213%
Total Terminals$768%$1569%

n/a – not applicable

The primary changes in the Terminals business segment’s EBDA before certain items in the comparable years of 2015 and 2014 included the following:

•increase of $45 million (70%) from our Alberta, Cananda terminals, driven by our recent 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 small 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 $14 million (21%) 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.
Year Ended December 31, 2014 versus Year Ended December 31, 2013
EBDA increase/(decrease)Revenues increase/(decrease)
(In millions, except percentages)
Acquired assets and businesses$66n/a$109n/a
Alberta, Canada3245%4938%
Gulf Central30213%51663%
Gulf Liquids2010%228%
Gulf Bulk1925%2619%
All others (including intrasegment eliminations and unallocated income tax expenses)143%415%
Total Terminals$18123%$29821%

n/a – not applicable

The primary changes in the Terminals business segment’s EBDA before certain items in the comparable years of 2014 and 2013 included the following:

•increase of $66 million from acquired assets and businesses, primarily the acquisition of the Jones Act tankers;
•increase of $32 million (45%) from our Alberta, Canada terminals, driven by the completion of Edmonton expansion projects;
•increase of $30 million (213%) from our Gulf Central terminals, driven by higher earnings from our 55% interest in BOSTCO oil terminal joint venture, which is located on the Houston Ship Channel and began operations in October 2013;
•increase of $20 million (10%) from our Gulf Liquids terminals, due to higher liquids warehousing revenues from our Pasadena and Galena Park liquids facilities located along the Houston Ship Channel. The facilities benefited from high gasoline export demand, increased rail services and new and incremental customer agreements at higher rates, due in part to new tankage from completed expansion projects;
•increase of $19 million (25%) from our Gulf Bulk terminals, driven by increased shortfall revenue from take-or-pay coal contracts and higher petcoke period-to-period volumes in 2014, due largely to refinery and coker shutdowns in 2013 as a result of turnarounds taken; and
•increase of $14 million (3%) from the rest of the terminal operations was driven primarily by increased shortfall revenue recognized on take-or-pay contracts at our International Marine Terminal in Myrtle Grove, Louisiana and earnings from the BP Whiting terminal in Whiting, Indiana which was placed in service in the third quarter of 2013.

Products Pipelines

Year Ended December 31,
201520142013
(In millions, except operating statistics)
Revenues$1,831$2,068$1,853
Operating expenses(772)(1,258)(1,295)
Other (expense) income(2)3(6)
Earnings from equity investments454445
Interest income and Other, net613
Income tax (expense) benefit(8)(2)2
Segment earnings before DD&A(a)1,100856602
Certain items(a)(4)4182
EBDA before certain items$1,096$860$784
Change from prior periodIncrease/(Decrease)
Revenues$(237)$215
EBDA before certain items$236$76
Gasoline (MMBbl) (b)377.7364.7350.3
Diesel fuel (MMBbl)131.8129.1125.1
Jet fuel (MMBbl)103.1100.598.6
Total refined product volumes (MMBbl)(c)612.6594.3574.0
NGL (MMBbl)(d)38.625.327.7
Condensate (MMBbl)(e)99.733.210.7
Total delivery volumes (MMBbl)750.9652.8612.4
Ethanol (MMBbl)(f)41.441.638.7

Certain item footnote

(a)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. 2013 amount includes (i) a $162 million increase in expense associated with rate case liability adjustments; (ii) a $15 million increase in expense associated with a legal liability adjustment related to a certain West Coast terminal environmental matter; and (iii) $5 million loss from the write-off of assets at our Los Angeles Harbor West Coast terminal.

Other footnotes

(b)Volumes include ethanol pipeline volumes.
(c)Includes Pacific, Plantation Pipe Line Company, Calnev, Central Florida and Parkway pipeline volumes. Joint

Venture throughput is reported at our ownership share.

(d)Includes Cochin and Cypress pipeline volumes. Joint Venture throughput is reported at our ownership share.
(e)Includes Kinder Morgan Crude & Condensate, Double Eagle Pipeline LLC and Double H pipeline volumes. Joint Venture throughput is

reported at our ownership share.

(f)Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.

Following is information related to the increases and decreases in both EBDA and revenues before certain items in 2015 and 2014, when compared with the respective prior year:

Year Ended December 31, 2015 versus Year Ended December 31, 2014
EBDA increase/(decrease)Revenues increase/(decrease)
(In millions, except percentages)
Crude & Condensate Pipeline$102124%$9081%
KMCC - Splitter33n/a43n/a
Double H pipeline44n/a56n/a
Cochin2934%5450%
Pacific operations237%276%
Transmix operations833%(490)(49)%
All others (including eliminations)(3)(1)%(17)(4)%
Total Products Pipelines$23627%$(237)(12)%

n/a - not applicable

The primary changes in the Products Pipelines business segment’s EBDA before certain items in the comparable years of 2015 and 2014 included the following:

•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 $29 million (34%) 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.
Year Ended December 31, 2014 versus Year Ended December 31, 2013
EBDA increase/(decrease)Revenues increase/(decrease)
(In millions, except percentages)
Crude & Condensate Pipeline$67320%$89402%
Pacific operations3613%256%
Transmix operations(19)(44)%9210%
All others (including eliminations)(8)(2)%92%
Total Products Pipelines$7610%$21512%

The primary changes in the Products Pipelines business segment’s EBDA before certain items in the comparable years of 2014 and 2013 included the following:

•increase of $67 million (320%) from Kinder Morgan Crude & Condensate Pipeline, driven primarily by an increase of pipeline throughput volumes to 81.0 MBbl/d as compared to 24.1 MBbl/d in 2013 (236%);
•increase of $36 million (13%) from our Pacific operations, due to higher service revenues driven by higher volumes and margins and lower operating expenses primarily due to lower rights-of-way expenses; and
•decrease of $19 million (44%) from our transmix processing operations, primarily driven by unfavorable inventory pricing. The increase in revenues of $92 million and associated increase in costs of goods sold were caused by higher product sales volumes.

Kinder Morgan Canada

Year Ended December 31,
201520142013
(In millions, except operating statistics)
Revenues$260$291$302
Operating expenses(87)(106)(110)
Other income1——
Earnings from equity investments——4
Interest income and Other, net815249
Income tax expense(19)(18)(21)
Segment earnings before DD&A(a)163182424
Certain items, net(a)——(224)
EBDA before certain items$163$182$200
Change from prior periodIncrease/(Decrease)
Revenues$(31)$(11)
EBDA before certain items$(19)$(18)
Transport volumes (MMBbl)(b)115.4106.8101.1

Certain item footnote

(a)2013 amount includes a $224 million pre-tax gain from the sale of our equity and debt investments in the Express pipeline system.

Other footnote

(b)Represents Trans Mountain pipeline system volumes.

Following is information related to increases and decreases in both EBDA and revenues before certain items in 2015 and 2014, when compared with the respective prior year:

Year Ended December 31, 2015 versus Year Ended December 31, 2014
EBDA increase/(decrease)Revenues increase/(decrease)
(In millions, except percentages)
Trans Mountain Pipeline$(12)(7)%$(30)(11)%
Express Pipeline(a)(7)(100)%n/an/a
Jet Fuel Pipeline——%(1)(17)%
Total Kinder Morgan Canada$(19)(10)%$(31)(11)%

n/a - not applicable

(a)Amount consists of unrealized foreign currency gains, net of book tax, on 2014 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.

For the comparable years of 2015 and 2014, the Kinder Morgan Canada business segment had a decrease in earnings of $19 million (10%) which was driven primarily by an unfavorable impact from foreign currency exchange rates, and repayment of the Express note as discussed in footnote (a) above.

Year Ended December 31, 2014 versus Year Ended December 31, 2013
EBDA increase/(decrease)Revenues increase/(decrease)
(In millions, except percentages)
Express Pipeline(a)$(6)(44)%n/an/a
Trans Mountain Pipeline(12)(6)%$(11)(4)%
Total Kinder Morgan Canada$(18)(9)%$(11)(4)%

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.

For the comparable years of 2014 and 2013, the Trans Mountain Pipeline had a decrease in earnings of $12 million (6%) which was driven primarily by an unfavorable impact from foreign currency exchange rates. Due to the weakening of the Canadian dollar since the end of the third quarter of 2013, we translated Canadian denominated income and expense amounts into fewer U.S. dollars in 2014.

Other

This segment contributed a loss of $53 million, earnings of $13 million and a loss of $5 million for the years ended 2015, 2014 and 2013, respectively. However, 2015 and 2014 earnings include certain items of a $35 million decrease in earnings and a $22 million increase in earnings, respectively. The 2015 certain items related primarily to a litigation matter and the 2014 certain items were primarily related to our foreign operations. After taking into effect the certain items, the earnings for 2015 and 2014, decreased by $9 million and $4 million, respectively, when compared with the respective prior year.

General and Administrative, Interest, and Noncontrolling Interests

Year Ended December 31,
201520142013
(In millions)
General and administrative expense(a)(d)$690$610$613
Certain items(a)(25)288
Management fee reimbursement(d)(37)(36)(36)
General and administrative expense before certain items$628$602$585
Unallocable interest expense net of interest income and other, net(b)$2,055$1,807$1,688
Certain items(b)27332
Unallocable interest expense net of interest income and other, net, before certain items$2,082$1,810$1,720
Net (loss) income attributable to noncontrolling interests$(45)$1,417$1,499
Noncontrolling interests associated with certain items(c)63——
Net income attributable to noncontrolling interests before certain items$18$1,417$1,499

Certain item footnotes

(a)2015, 2014 and 2013 amounts include decreases in expense of $35 million, $39 million and $59 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. 2013 amount also includes increases in expense of $41 million related to asset and business acquisition costs and unallocated legal expenses and a combined $10 million from other certain items primarily related to the acquisition of EP.
(b)2015, 2014 and 2013 amounts include decreases in interest expense of $71 million, $65 million and $67 million, respectively, related to debt fair value adjustments associated with acquisitions. 2015 and 2014 amounts also include (i) a $23 million increase and $1 million decrease, respectively, in interest expense primarily related to a non-cash true-up of our estimate of swap ineffectiveness; and (ii) a $13 million decrease and $15 million increase, respectively, in interest expense associated with a certain Pacific operations litigation matter.

2015 amount also includes a $34 million increase in interest expense for a non-cash adjustment related to a litigation matter. 2014 and 2013 amounts also include increases in expense of $9 million and $21 million, respectively, of amortization of capitalized financing fees and $12 million and $14 million, respectively, of interest expense on margin for marketing contracts. 2014 amount also includes $27 million of interest expense related to the Merger Transactions.

(c)2015 amount includes (i) a $43 million impairment recognized after the issuance of our 2015 fourth quarter earnings release containing our preliminary financial results 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 footnote

(d)2015, 2014 and 2013 amounts include NGPL Holdco LLC general and administrative reimbursements of $37 million, $36 million and $36 million, respectively. These amounts were 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.

The increase in general and administrative expenses before certain items of $26 million and $17 million in 2015 and 2014 when compared with the respective prior year was primarily driven by the acquisition of Hiland (effective February 13, 2015) and Copano (effective May 1, 2013). Additional drivers for the increase between 2015 and 2014 were lower capitalized costs and higher labor expenses partially offset by lower benefit and insurance costs while the increase between 2014 and 2013 was impacted by higher benefit costs, payroll taxes and labor expenses partially offset by lower costs on our corporate headquarters building and insurance costs.

In the table above, we report our interest expense as “net,” meaning that we have subtracted unallocated interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense net of interest income and other, net before certain items, increased $272 million and $90 million in 2015 and 2014, respectively, when compared with the respective prior year. The increase in interest expense in 2015 as compared to 2014 was primarily due to higher 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.

The increase in interest expense in 2014 as compared to 2013 was primarily due to higher average debt balances as a result of capital expenditures, joint venture contributions and acquisitions that were made during 2014 and incremental debt borrowings to fund the $3.9 billion cash portion of the Merger Transactions in November 2014. In addition, the increase was impacted by the refinancing of the short-term KMI credit facility debt with a $1.5 billion long-term debt issuance in November 2013, which had a higher interest rate. This increase in interest expense was partially offset by (i) lower average balances outstanding on our EP acquisition term loan as a result of its termination in November 2014 and (ii) lower interest rates on our credit facility and EP acquisition term loan as a result of the refinancing of these facilities in 2014.

We use interest rate swap agreements to transform 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, 2015 and December 31, 2014, approximately 27% and 26%, 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.

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. 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. The $82 million decrease (5%) for 2014 as compared to 2013 was primarily due to our noncontrolling interests’ portion of (i) our 2013 $558 million pre-tax gain from the remeasurement of our previously held 50% equity interest in Eagle Ford to fair value; and (ii) our 2013 $140 million after-tax gain on the sale of our investments in the Express pipeline system; which was partially offset by our noncontrolling interests’ portion of our 2014 $198 million pre-tax increase associated with the early termination of a long-term natural gas transportation contract by a certain customer of KMLP and an increase in income allocated to noncontolling interests during the fourth quarter 2014 due to the elimination of the incentive distribution rights as a result of the Merger Transactions.

Subsequent to the Merger Transactions, net income attributable to noncontrolling interests represents net income allocated to third-party ownership interests in consolidated subsidiaries. Prior to the Merger Transactions it also included net income allocated to KMP and EPB limited partner units formerly owned by the public.

Income Taxes—Continuing Operations

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

Our income tax expense from continuing operations for the year ended December 31, 2015 was $564 million, as compared with 2014 income tax expense of $648 million. The $84 million decrease in income 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.

Year Ended December 31, 2014 versus Year Ended December 31, 2013

Our income tax expense from continuing operations for the year ended December 31, 2014 was $648 million, as compared with 2013 income tax expense of $742 million. The $94 million decrease in income tax expense is due primarily to (i) the tax impact of lower pretax earnings in 2014 associated with our investment in KMP primarily related to KMP’s 2014 recognition of a $235 million impairment of CO2 assets compared to gains recognized in 2013 of $558 million on remeasurement to fair value of the initial 50% interest in the Eagle Ford joint venture and $224 million on the sale of the one-third interest in the Express pipeline system; (ii) a 2014 worthless stock deduction related to our Brazil operations; and (iii) a 2013 decrease in our share of non-tax-deductible goodwill associated with our investment in KMP (as a result of our change in ownership primarily due to KMP’s acquisition of Copano). These decreases are partially offset by (i) the tax benefit in 2013 of a decrease in the deferred state tax rate as a result of the drop-down of our 50% ownership interest in EPNG and midstream assets and KMP’s acquisition of Copano; (ii) 2013 adjustments to our income tax reserve for uncertain tax positions as a result of the settlement of legacy EP Internal Revenue Service audits; and (iii) the 2014 recording of a valuation allowance related to our investment in NGPL.

Liquidity and Capital Resources

General

As of December 31, 2015, we had $229 million of “Cash and cash equivalents,” on our consolidated balance sheet, a decrease of $86 million (27%) from December 31, 2014. 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 strong cash flow from operations, providing a source of funds of $5,303 million and $4,467 million in 2015 and 2014, respectively (the year-to-year increase of 19% is discussed below in “Cash Flows—Operating Activities”). During 2015, we have relied on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, and dividend payments.

Historically, we have relied on cash from our equity and debt issuances to fund, in large part, expansion capital expenditures, acquisitions and to refinance debt maturities. However, due to the recent unfavorable capital market conditions, the resulting increased cost of equity and debt issuances have made it less economical to do so. As a result, on December 8, 2015, we announced that our board of directors approved a plan pursuant to which we expect to pay quarterly dividends of $0.125 per share to our common shareholders ($0.50 per common share annually), down from our third quarter 2015 dividend of $0.51 per common share, beginning with the fourth quarter 2015 dividend payable to common shareholders on February 16, 2016. We expect the reduced dividend level eliminates our need to access the capital markets to fund our growth projects in 2016.

Additionally, on January 26, 2016, we announced the issuance of a new $1 billion term loan facility and the expansion of our revolving credit facility from $4 billion to $5 billion. The proceeds of the three-year unsecured term loan were used to refinance maturing long-term debt.

Credit Ratings and Capital Market Liquidity

Based on our recent decision to retain a larger portion of our internally generated cash to fund our growth projects, 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 further utilize 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.

Our short-term corporate debt rating is 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, 2015.

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, 2015 our principal sources of short-term liquidity are (i) our $4.0 billion revolving credit facility (which capacity was increased to $5.0 billion on January 26, 2016) 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 flow from operations.

Our short-term debt as of December 31, 2015 was $821 million, comprised entirely of the current portion of our long-term debt excluding $1.0 billion of debt that matured in January and February 2016 that was refinanced using proceeds from the $1.0 billion term loan issued in January 2016, and therefore included within “Long-term debt” on our consolidated balance sheet at December 31, 2015. We intend to refinance our short-term debt through additional credit facility borrowings, commercial paper borrowings, or with issuing new long-term debt or paying down short-term debt using cash retained from operations. Our combined balance of short-term debt as of December 31, 2014 was $2,717 million.

We had working capital (defined as current assets less current liabilities) deficits of $1,241 million and $2,610 million as of December 31, 2015 and 2014, respectively. Our current liabilities include short-term borrowings used to finance our expansion capital expenditures which periodically we may replace with long-term financing and/or partially pay down using retained cash from operations. The overall $1,369 million (52%) favorable change from year-end 2014 was primarily due to a net decrease in our credit facility borrowings, commercial paper borrowings and current portion of long-term debt (largely refinanced with the new long-term issuances); offset partially by (i) lower other current assets driven by the 2015 receipt of a federal tax refund; and (ii) lower cash balances. 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 subsidiaries, their operating partnerships and their 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 subsidiaries, their operating partnerships and their 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 parent companies other than restrictions that may be contained in agreements governing the indebtedness of those entities.

Certain of our operating 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, 2015 and 2014, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $40,732 million and $38,312 million, respectively.

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 and our subsidiaries’ 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 2015, 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 cash available to pay dividends 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, 2015, and the amount we expect to spend for 2016 to sustain and grow our business are as follows (in millions):

2015Expected 2016
Sustaining capital expenditures(a)$565$574
Discretionary capital expenditures(b)(c)$3,532$3,281
(a)2015 and Expected 2016 amounts include $70 million and $90 million, respectively, for our proportionate share of sustaining capital expenditures of certain unconsolidated joint ventures.
(b)2015 amount includes an increase of $483 million of discretionary capital expenditures of unconsolidated joint ventures and small acquisitions (i.e. excludes Hiland acquisition) and divestitures and a decrease of a combined $352 million of net changes from accrued capital expenditures and contractor retainage.
(c)Expected 2016 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)$41,553$821$5,389$6,772$28,571
Interest payments(b)29,3112,2674,1093,61019,325
Leases and rights-of-way obligations(c)829103173147406
Pension and postretirement welfare plans(d)932243435839
Transportation, volume and storage agreements(e)1,172160294256462
Other obligations(f)30291952987
Total$74,099$3,466$10,094$10,849$49,690
Other commercial commitments:
Standby letters of credit(g)$243$205$38$—$—
Capital expenditures(h)$1,229$845$384$—$—
(a)Less than 1 year amount primarily includes $667 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 consideration consistent with the EP merger, and excludes $1,000 million of current maturities on long-term debt that were refinanced with proceeds from the issuance of a January 2016 three-year term loan. 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, 2015.
(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 2016 and estimated benefit payments for unfunded plans in all years.
(e)Primarily represents transportation agreements of $526 million, volume agreements of $454 million and storage agreements for capacity on third party and an affiliate pipeline systems of $135 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 $243 million in letters of credit outstanding as of December 31, 2015 consisted of the following (i) $73 million under fourteen letters of credit for insurance purposes; (ii) 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; (iii) a $29 million letter of credit supporting our pipeline and terminal operations in Canada; (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) an $11 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; and (vii) a combined $35 million in twenty-six 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, 2015 and obligations for the definitive construction agreement with Philly Tankers LLC for 2016 and 2017.

Cash Flows

Operating Activities

The net increase of $836 million (19%) in cash provided by operating activities in 2015 compared to 2014 was primarily attributable to:

•a $726 million increase in cash associated with net changes in working capital items and non-current assets and liabilities. The increase was driven, among other things, primarily by $347 million of federal and state income tax refunds we received in 2015 of which $195 million was previously reported as an income tax receivable as of December 31, 2014, and higher cash flows due to favorable changes in the collection of trade and exchange gas receivables. These increases were offset by lower cash flow due to the timing of payments from our trade payables;
•a $243 million increase in cash due to the higher payments in 2014 for rate case reserve payments primarily driven by the 2014 CPUC settlement and refund payments; and
•a $133 million decrease in cash from overall net income after adjusting our period-to-period $2,235 million decrease in net income for non-cash items primarily consisting of the following: (i) loss on impairment of goodwill (see discussion above in “—Results of Operations”); (ii) net losses on impairments and disposals of long-lived assets and equity investments (see discussion above in “—Results of Operations”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred income taxes; (v) a net increase in legal reserves (see discussion above in “—Results of Operations”); (vi) an increase in net unrealized gains relating to derivative contracts used to hedge forecasted natural gas, NGL, and crude oil sales (see discussion above in “—Results of Operations”); and (vii) an increase in equity earnings from our equity investments.

Investing Activities

The $496 million net increase in cash used in investing activities in 2015 compared to 2014 was primarily attributable to:

•a $691 million decrease in cash due to higher expenditures for acquisitions and investments. The overall increase in acquisitions was primarily related to the $1,706 million (net of cash acquired and debt assumed) and $158 million we paid for the Hiland and Vopak acquisitions, respectively, in the 2015 period, versus the $1,231 million we paid for the APT and Crowley tankers in 2014. In 2015 we also paid $134 million in cash for our additional 30% interest in NGPL Holdings LLC. See Note 3 “Acquisitions and Divestitures” for further information regarding these acquisitions;
•a $279 million decrease in cash due to higher capital expenditures;
•a $293 million increase in cash due to lower capital contributions to our equity investments, primarily due to a $175 million contribution we made in the third quarter of 2014 to our 50%-owned Midcontinent Express Pipeline LLC to fund our share of its repayment of $350 million in senior notes that matured on September 15, 2014; and
•a $135 million increase in cash in Other, net, primarily due to favorable changes in restricted deposit accounts associated with our hedging activities.

Financing Activities

The net decrease of $144 million in cash provided by financing activities in 2015 compared to 2014 was primarily attributable to:

•a $7,507 million net decrease in cash from overall debt financing activities. See Note 9 “Debt” for further information regarding our debt activity;
•a $2,464 million decrease in cash due to higher total dividend payments;
•a $1,756 million decrease in contributions provided by noncontrolling interests, primarily reflecting the proceeds received from the issuance of KMP’s and EPB’s common units to the public in the 2014 period and no proceeds in the 2015 period due to the Merger Transactions;
•a $4,009 million increase in cash resulting from the cash portion of consideration for the Merger Transactions and related transaction costs in 2014;
•a $3,870 million increase in cash from the issuances of our Class P shares under our equity distribution agreement;
•a $1,979 million increase in cash due to lower distributions to noncontrolling interests, primarily resulting from our acquisition of the noncontrolling interests associated with KMP and EPB in the Merger Transactions in November 2014;
•a $1,541 million increase in cash from the issuance of our mandatory convertible preferred stock in 2015; and
•a $180 million increase in cash due to the reduction of payments made to repurchase shares and warrants in 2015 compared to the 2014 period.

Common Dividends

The table below reflects the payment of cash dividends of $1.605 per common share for 2015.

Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
March 31, 2015$0.48April 15, 2015April 30, 2015May 15, 2015
June 30, 2015$0.49July 15, 2015July 31, 2015August 14, 2015
September 30, 2015$0.51October 21, 2015November 2, 2015November 13, 2015
December 31, 2015$0.125January 20, 2016February 1, 2016February 16, 2016

As disclosed elsewhere in this report, we expect to pay cash dividends totaling $0.50 per share on our common stock for 2016. 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 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 dividends generally will be paid on or about the 16th 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.

On November 17, 2015, our board of directors declared a cash dividend of $23.291667 per share of our mandatory convertible preferred stock (equivalent of $1.164583 per depository share) for the period from and including October 30, 2015 through and including January 25, 2016, was paid on January 26, 2016 to mandatory convertible preferred shareholders of record as of January 11, 2016.

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.