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 2014, 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—(i) the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems; (ii) the ownership and/or operation of associated natural gas and crude oil gathering systems and natural gas processing and treating facilities; and (iii) the ownership and/or operation of NGL fractionation facilities and transportation systems;

•	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 and rail transloading and materials handling 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 includes other miscellaneous assets and liabilities purchased in our 2012 EP acquisition including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with EP’s legacy trading activities; and (iii) other miscellaneous EP 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 and related storage facilities, 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 Group, currently derives approximately 75% of its sales and transport margins from long-term transport and sales contracts that include requirements with minimum volume payment obligations. As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As of December 31, 2014, the remaining average contract life of our natural gas transportation contracts (including intrastate pipelines’ purchase and sales contracts) was approximately six years.

Our midstream group, which is within our Natural Gas Pipelines Segment, provides gathering and processing services primarily through our (i) EP midstream asset operations, which we acquired 50% from KKR effective June 1, 2012, and 50% from the May 25, 2012 EP acquisition, (ii) our Copano operations, which included the remaining 50% ownership interest in Eagle Ford Gathering LLC (Eagle Ford) that we did not already own and which was acquired effective May 1, 2013 and (iii) our KinderHawk operation, which gathers and treats natural gas in the Haynesville and Bossier shale gas formations located in northwest Louisiana. These substantially fee-based gathering, processing and fractionation assets, along with our financial strength and extensive pipeline transportation and storage assets, provide an excellent platform to further grow our midstream group services footprint. 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 also affected by the volumes of natural gas made available to our systems, which are primarily driven by levels of natural gas drilling activity. Our midstream group services are provided pursuant to a variety of arrangements, generally categorized (by the nature of the commodity price risk) as fee-based, percent-of-proceeds, percent-of-index and keep-whole. 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.

In February 2015, we acquired Hiland Partners (Hiland) for a total purchase price of approximately $3 billion (including assumption of debt). Hiland’s assets consist of crude oil gathering and transportation pipelines and gas gathering and processing systems, primarily serving production from the Bakken Formation in North Dakota and Montana. Most of Hiland’s operations will be included in our midstream group within our Natural Gas Pipelines segment.

The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2014, had a remaining average contract life of approximately ten 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 2015, and utilizing the average oil price per barrel contained in our 2015 budget, approximately 86% of our revenue is based on a fixed fee or floor price, and 14% 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 $88.41 per barrel in 2014, $92.70 per barrel in 2013 and $87.72 per barrel in 2012. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $86.48 per barrel in 2014, $94.94 per barrel in 2013 and $89.91 per barrel in 2012.

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. 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 have minimum volume guarantees and are volume based above the minimums. Because these contracts are volume based above the minimums, our profitability from the bulk business can be sensitive to economic conditions. 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. 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 seven 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 business is generally driven by the volume of refined petroleum products that we transport and the prices we receive for our services. Transportation 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 2015 budget, and related announced expectation to declare dividends of $2.00 per share for 2015, assumes an average WTI crude oil price of approximately $70 per barrel and an average natural gas price of $3.80 per MMBtu in 2015. For 2015, we estimate that every $1 change in the average WTI crude oil price per barrel will impact our distributable cash flow by approximately $10 million (approximately $7 million of which is attributable to our CO2 business segment), and each $0.10 per MMBtu change in the average price of natural gas will impact distributable cash flow by approximately $3 million. This assumes we do not add additional hedges during the year which could reduce these sensitivities. These sensitivities compare to total anticipated segment earnings before DD&A in 2015 of approximately $8 billion (adding back our share of joint venture DD&A). Even adjusting for current commodity prices we expect to have significant excess coverage in 2015.

The amount that we are able to increase dividends to our shareholders will, to some extent, be a function of our ability to complete successful acquisitions and expansions. We believe we will continue to have opportunities for expansion of our facilities in many markets, and we have budgeted approximately $4.4 billion for our 2015 capital expansion program (including small acquisitions and investment contributions, but excluding our recent acquisition of Hiland Partners, LP). We consider and enter into discussions regarding potential acquisitions and are currently contemplating potential acquisitions.

Based on our historical record and because there is continued demand for energy infrastructure in the areas we serve, we expect to continue to have such opportunities in the future, although the level of such opportunities is difficult to predict. While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations. Furthermore, our ability to make accretive acquisitions is a function of the availability of suitable acquisition candidates at the right cost, and includes factors over which we have limited or no control. Thus, we have no way to determine the number or size of accretive acquisition candidates in the future, or whether we will complete the acquisition of any such candidates.

Our ability to make accretive acquisitions or expand our assets is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such acquisitions. Our dividend policy is to distribute most of our available cash, and we intend to continue accessing capital markets to fund acquisitions and asset expansions. Historically, we have succeeded in raising necessary capital in order to fund our acquisitions and expansions, and although we cannot predict future changes in the overall equity and debt capital markets (in terms of tightening or loosening of credit), we believe that our stable cash flows, credit ratings, and historical records of successfully accessing both equity and debt funding sources should allow us to continue to execute our current investment, dividend and acquisition strategies, as well as refinance maturing debt when required. For a further discussion of our liquidity, including our and our subsidiaries’ public debt and equity offerings in 2014, please see “—Liquidity and Capital Resources” below.

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.

In addition, 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) use the local Canadian dollar as the functional currency for its Canadian operations and we enter into foreign currency-based transactions, both of which affect segment results due to the inherent variability in U.S. - Canadian dollar exchange rates. To help understand our reported operating results, all of the following references to “foreign currency effects” or similar terms in this section represent our estimates of the changes in financial results, in U.S. dollars, resulting from fluctuations in the relative value of the Canadian dollar to the U.S. dollar. The references are made to facilitate period-to-period comparisons of business performance and may not be comparable to similarly titled measures used by other registrants.

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 16 “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 16 “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 our goodwill for impairment on May 31 of each year. There were no impairment charges resulting from our May 31, 2014 impairment testing, and no event indicating an impairment has occurred subsequent to that date, other than $2 million associated with a pending asset divestiture. Furthermore, our analysis as of that date did not reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units is less than the carrying value of its net assets. For more information on our goodwill, see Notes 2 “Summary of Significant Accounting Policies” and 7 “Goodwill and Other Intangibles” to our consolidated financial statements.

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 amortizable intangibles, see Note 7 “Goodwill and Other Intangibles” 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)”.

The quantities of our proved oil and gas reserves and the measures of discounted future net cash flows from those oil and gas reserves as of December 31, 2014 are based on the 12 month unweighted average of the first day of the month price realized in 2014. Commodity prices fell substantially toward the end of 2014 and therefore, unless commodity prices recover in the next 12 months, the amount of our proved oil and gas reserves and the measures of discounted future net cash flows from those oil and gas reserves could be negatively impacted in 2015. Any resulting reductions in our proved oil and gas reserves due to lower commodity pricing may increase our DD&A expense. Sustained lower commodity prices may also negatively impact forward curve pricing that is used in testing for impairment, estimated total proved and risk-adjusted probable and possible oil and gas reserves, and related expected future cash flows, which may result in impairment of our oil producing interests.

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.

Since it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to unfavorable changes in commodity prices-a perfectly effective hedge-we often enter into hedges that are not completely effective in those instances where we believe to do so would be better than not hedging at all. But because the part of such hedging transactions that is not effective in offsetting undesired changes in commodity prices (the ineffective portion) is required to be recognized currently in earnings, our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For example, when we purchase a commodity at one location and sell it at another, we may be unable to hedge completely our exposure to a differential in the price of the product between these two locations; accordingly, our financial statements may reflect some volatility due to these hedges. For more information on our hedging activities, see Note 13 “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, 2014, our pension plans were underfunded by $427 million and our other postretirement benefits plans were underfunded by $235 million. Our pension and other postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. We select 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 9 “Share-based Compensation and Employee Benefits” to our consolidated financial statements.

Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and other postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of

expected future service of active participants, or over the expected future lives of inactive plan participants. We record these deferred amounts as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations. As of December 31, 2014, we had deferred net losses of approximately $323 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, 2014:

		Pension Benefits								Other Postretirement Benefits
		Net benefit cost (income)				Change in funded status and pretax accumulated other comprehensive income (loss)				Net benefit cost (income)				Change in funded status and pretax accumulated other comprehensive income (loss)
		(In millions)
One percent increase in:
Discount rates		$	10			$	260			$	2			$	55
Expected return on plan assets		(23		)		—				(4		)		—
Rate of compensation increase		2				(13		)		—				—
Health care cost trends		—				—				4				(47		)
One percent decrease in:
Discount rates		(11		)		(312		)		—				(65		)
Expected return on plan assets		23				—				4				—
Rate of compensation increase		(1		)		12				—				—
Health care cost trends		—				—				(2		)		40

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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. For a discussion of our anticipated dividends for 2015, see “—Financial Condition—Cash Flows—KMI Dividends.”

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

	Year Ended December 31,
	2014				2013				2012
	(In millions)
Net Income	$	2,443			$	2,692			$	427
Add/(Subtract):
Certain items before book tax(a)	14				(609		)		1,692
Book tax certain items	(117		)		(39		)		(412		)
Certain items after book tax	(103		)		(648		)		1,280
Net income before certain items	2,340				2,044				1,707
Add/(Subtract):
Net income attributable to third-party noncontrolling interests(b)	(12		)		(5		)		(1		)
Depreciation, depletion and amortization(c)	2,390				2,142				1,678
Book taxes(d)	840				847				584
Cash taxes(d)	(448		)		(552		)		(460		)
Declared distributions to noncontrolling interests(e)	(2,000		)		(2,355		)		(1,797		)
Sustaining capital expenditures(f)	(509		)		(414		)		(393		)
Other, net(g)	17				6				93
Subtotal	278				(331		)		(296		)
DCF before certain items	$	2,618			$	1,713			$	1,411
Weighted Average Shares Outstanding for Dividends(h)	1,312				1,040				908
DCF per share before certain items	$	2.00			$	1.65			$	1.55
Declared dividend per common share	1.74				1.60				1.40

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(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)	Represents net income allocated to third-party ownership interests in consolidated subsidiaries other than our former Master Limited Partnerships.

(c)	Includes DD&A, amortization of excess cost of equity investments and our share of equity method investee’s DD&A of $305 million, $297 million and $236 million in 2014, 2013 and 2012, respectively.

(d)	Includes our share of equity method investee’s book or cash income taxes.

(e)	Represents distributions to KMP and EPB limited partner units formerly owned by the public.

(f)	Includes our share of equity method investee’s sustaining capital expenditures of $(59) million, $(48) million and $(51) million in 2014, 2013 and 2012, respectively.

(g)	Consists primarily of book to cash timing differences related to certain defined benefit plans and other items, and for periods prior to fourth quarter 2014 includes differences between earnings and cash from our former Master Limited Partnerships.

(h)	Includes restricted shares that participate in dividends. 2014 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

With regard to our reportable business segments, we consider segment earnings before all DD&A expenses, and amortization of excess cost of equity investments (defined in the “—Results of Operations” tables below and sometimes referred to in this report as EBDA) to be an important measure of our success in maximizing returns to our shareholders. We also use segment EBDA internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our six reportable business segments. EBDA may not be comparable to measures used by other companies. Additionally, EBDA should be considered in conjunction with net income and other performance measures such as operating income, income from continuing operations or operating cash flows.

Certain items included in EBDA are either not allocated to business segments or are not considered by management in its evaluation of business segment performance. In general, the items not included in segment results are interest expense, general and administrative expenses, DD&A and unallocable income taxes. These items 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 currently evaluate business segment performance primarily based on segment EBDA in relation to the level of capital employed. We consider each period’s EBDA to be an important measure of business segment performance for our segments. We account for intersegment sales at market prices. We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the income statement of the combined entity.

	Year Ended December 31,
	2014				2013				2012
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	4,259			$	4,207			$	2,174
CO2	1,240				1,435				1,322
Terminals	944				836				708
Products Pipelines	856				602				668
Kinder Morgan Canada	182				424				229
Other	13				(5		)		7
Total Segment EBDA(b)	7,494				7,499				5,108
DD&A expense	(2,040		)		(1,806		)		(1,419		)
Amortization of excess cost of equity investments	(45		)		(39		)		(23		)
Other revenues	36				36				35
General and administrative expenses(c)	(610		)		(613		)		(929		)
Interest expense, net of unallocable interest income(d)	(1,807		)		(1,688		)		(1,441		)
Income from continuing operations before unallocable income taxes	3,028				3,389				1,331
Unallocable income tax expense	(585		)		(693		)		(127		)
Income from continuing operations	2,443				2,696				1,204
Loss from discontinued operations, net of tax(e)	—				(4		)		(777		)
Net income	2,443				2,692				427
Net income attributable to noncontrolling interests	(1,417		)		(1,499		)		(112		)
Net income attributable to Kinder Morgan, Inc.	$	1,026			$	1,193			$	315

---

(a)

Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other income (expense). 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, 2014, 2013 and 2012 were $63 million, $49 million and $12 million, respectively.

Certain item footnotes

(b)	2014, 2013 and 2012 amounts include decrease in earnings of $45 million, increase in earnings of $573 million, and decrease in earnings of $295 million, respectively, related to the combined effect from all of the 2014, 2013 and 2012 certain items impacting continuing operations and disclosed below in our management discussion and analysis of segment results.

(c)	2014 and 2013 amounts include decrease to expense of $28 million and $8 million, and 2012 amount includes increase in expense of $366 million, respectively, related to the combined effect from all of the 2014, 2013 and 2012 certain items related to general and administrative expenses disclosed below in “—General and Administrative, Interest, and Noncontrolling Interests.”

(d)	2014 and 2013 amounts include decrease in expense of $3 million and $32 million and 2012 amount includes increase in expense of $87 million, respectively, related to the combined effect from all of the 2014, 2013 and 2012 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. 2012 amount includes a combined $937 million loss from the remeasurement of net assets to fair value and the sale of our disposal group and DD&A expense of $7 million.

Year Ended December 31, 2014 vs. 2013

The certain items described in footnotes (b), (c) and (d) to the tables above accounted for $627 million decrease in income from continuing operations before unallocable income taxes in 2014, when compared to 2013 (combining to decrease total income from continuing operations before unallocable income taxes by $14 million for 2014 and increase total income from continuing operations before unallocable income taxes by $613 million for 2013). The $266 million (10%) period-to-period increase in income from continuing operations before unallocable income taxes remaining, after giving effect to these certain items, reflects better overall performance primarily from our Natural Gas Pipelines, Products Pipelines and Terminals segments in 2014.

Year Ended December 31, 2013 vs. 2012

The certain items described in footnotes (b), (c) and (d) to the tables above accounted for $1,361 million increase in income from continuing operations before unallocable income taxes in 2013, when compared to 2012 (combining to increase total income from continuing operations before unallocable income taxes by $613 million for 2013 and decrease total income from continuing operations before unallocable income taxes by $748 million for 2012). The $697 million (34%) period-to-period increase in income from continuing operations before unallocable income taxes remaining, after giving effect to these certain items, reflects better overall performance from our segments in 2013 driven by our Natural Gas Pipelines segment (primarily due to a full year of contributions from the EP operations).

Natural Gas Pipelines

	Year Ended December 31,
	2014				2013				2012
	(In millions, except operating statistics)
Revenues(a)(c)	$	10,168			$	8,617			$	5,230
Operating expenses	(6,241		)		(5,235		)		(3,111		)
Other income (expense)	(5		)		24				(14		)
Earnings from equity investments	318				232				52
Interest income and Other, net	25				578				22
Income tax expense	(6		)		(9		)		(5		)
EBDA from continuing operations(b)	4,259				4,207				2,174
Discontinued operations(c)	—				(4		)		(770		)
Certain items(a)(b)(c)	(190		)		(486		)		1,139
EBDA before certain items	$	4,069			$	3,717			$	2,543
Change from prior period	Increase/(Decrease)
Revenues before certain items(a)	$	1,339			$	3,176
EBDA before certain items	$	352			$	1,174
Natural gas transport volumes (BBtu/d)(d)	32,627				30,647				31,650
Natural gas sales volumes (BBtu/d)(e)	2,334				2,458				2,402
Natural gas gathering volumes (BBtu/d)(f)	3,080				2,959				2,996

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Certain item footnotes

(a)

2014 amount includes a $198 million increase in revenue and earnings associated with the early termination charge of a long-term natural gas transportation contract from a certain customer on our Kinder Morgan Louisiana pipeline system. 2014 and 2013 amounts include $2 million and $16 million decreases, respectively, related to derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales.

(b)

2014 and 2013 amounts include $190 million and $490 million increases in earnings and 2012 amount includes a $202 million decrease in earnings, respectively, related to the combined effect from certain items. 2014 amount consists of (i) $198 million increase in earnings related to the early termination of a natural gas transportation contact, as described in footnote (a); (ii) $3 million loss related to sale of certain Gulf Coast offshore and onshore TGP supply facilities; and (iii) a combined $5 million decrease in earnings from other certain items. 2013 amount consists of (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 $16 million decrease in earnings related to derivative contracts, as described in footnote (a); and (iv) a combined $23 million decrease in earnings from other certain items. 2013 and 2012 amounts include $65 million and $200 million, respectively, non-cash equity investment impairment charges related to our 20% ownership interest in NGPL Holdco LLC. 2012 amount also consists of a combined $2 million decrease in earnings from other certain items.

(c)

Represents EBDA attributable to the FTC Natural Gas Pipelines disposal group. 2013 amount represents a loss from the sale of net assets. 2012 amount includes (i) a combined loss of $937 million from the remeasurement of net assets to fair value and the sale of net assets; (ii) $167 million of EBDA (which included revenues of $227 million); and (iii) $7 million of DD&A expense from discontinued operations.

Other footnotes

(d)

Includes pipeline volumes for TransColorado Gas Transmission Company LLC, MEP, Kinder Morgan Louisiana Pipeline LLC, FEP, TGP, EPNG, Copano South Texas, the Texas intrastate natural gas pipeline group, CIG, WIC, CPG, SNG, Elba Express, NGPL, Citrus and Ruby Pipeline, L.L.C. Volumes for acquired pipelines are included for all periods. 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 group.

(f)	Includes Copano operations, EP midstream assets operations, KinderHawk, Endeavor, Bighorn Gas Gathering L.L.C., Webb Duval Gatherers, Fort Union Gas Gathering L.L.C., EagleHawk, and Red Cedar Gathering Company throughput volumes. Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included for all periods.

Following is information, including discontinued operations, related to the increases and decreases in both EBDA and revenues before certain items in 2014 and 2013, when compared with the respective prior year:

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)	$	163			n/a		$	998			n/a
TGP	121				15%		151				14%
EPNG	37				10%		59				11%
Ruby(b)	18				199%		n/a				n/a
Citrus(b)	13				15%		n/a				n/a
Texas Intrastate Natural Gas Pipeline Group	11				3%		432				12%
WIC	(24		)		(17)%		(26		)		(15)%
SNG	(17		)		(4)%		(25		)		(4)%
All others (including eliminations)	30				3%		(250		)		(24)%
Total Natural Gas Pipelines	$	352			9%		$	1,339			16%

---

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 Group (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.

Year Ended December 31, 2013 versus Year Ended December 31, 2012
	EBDA increase/(decrease)						Revenues increase/(decrease)
	(In millions, except percentages)
TGP	$	358			81%		$	440			73%
Copano operations (including Eagle Ford)(a)	289				n/a		1,538				n/a
EPNG	151				68%		217				72%
SNG	129				40%		239				67%
CIG	129				78%		165				71%
SLNG	66				82%		65				62%
WIC	54				61%		53				43%
EP midstream asset operations	46				118%		81				89%
Elba Express	43				122%		43				111%
CPG	35				75%		40				65%
Citrus(b)	32				62%		n/a				n/a
All others (including eliminations)	9				1%		522				350%
Total Natural Gas Pipelines - continuing operations	1,341				56%		3,403				65%
Discontinued operations(c)	(167		)		(100)%		(227		)		(100)%
Total Natural Gas Pipelines - including discontinued operations	$	1,174			46%		$	3,176			58%

---

n/a – not applicable

(a)

On May 1, 2013, as part of our 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.

(c)	Represents amounts attributable to the FTC Natural Gas Pipelines disposal group.

The significant changes in the Natural Gas Pipelines business segment’s EBDA before certain items in the comparable years of 2013 and 2012 included the following:

•	incremental earnings of $1,043 million associated with full-year contributions from assets acquired from EP, which was acquired effective May 25, 2012, including earnings from TGP, EPNG, SNG, CIG, SLNG, WIC, EP midstream asset operations, Elba Express, CPG and Citrus; and

•	incremental earnings of $289 million from the Copano operations, which we acquired effective May 1, 2013.

The period-to-period decreases in EBDA from discontinued operations were due to the sale of the FTC Natural Gas Pipelines disposal group effective November 1, 2012. For further information about this sale, see Note 3 “Acquisitions and Divestitures—Divestitures—FTC Natural Gas Pipelines Disposal Group—Discontinued Operations” to our consolidated financial statements.

CO2

	Year Ended December 31,
	2014				2013				2012
	(In millions, except operating statistics)
Revenues(a)	$	1,960			$	1,857			$	1,677
Operating expenses	(494		)		(439		)		(381		)
Other (loss) income	(243		)		—				7
Earnings from equity investments	25				24				25
Interest income and Other, net	—				—				(1		)
Income tax expense	(8		)		(7		)		(5		)
EBDA(b)	1,240				1,435				1,322
Certain items(a)(b)	218				(3		)		4
EBDA before certain items	$	1,458			$	1,432			$	1,326
Change from prior period	Increase/(Decrease)
Revenues before certain items(a)	$	81			$	166
EBDA before certain items	$	26			$	106
Southwest Colorado CO2 production (gross) (Bcf/d)(c)	1.3				1.2				1.2
Southwest Colorado CO2 production (net) (Bcf/d)(c)	0.5				0.5				0.5
SACROC oil production (gross)(MBbl/d)(d)	33.2				30.7				29.0
SACROC oil production (net)(MBbl/d)(e)	27.6				25.5				24.1
Yates oil production (gross)(MBbl/d)(d)	19.5				20.4				20.8
Yates oil production (net)(MBbl/d)(e)	8.8				9.0				9.3
Katz oil production (gross)(MBbl/d)(d)	3.6				2.7				1.7
Katz oil production (net)(MBbl/d)(e)	3.0				2.2				1.4
Goldsmith Landreth oil production (gross)(MBbl/d)(d)	1.3				0.7				—
Goldsmith Landreth oil production (net)(MBbl/d)(e)	1.1				0.6				—
NGL sales volumes (net)(MBbl/d)(e)	10.1				9.9				9.5
Realized weighted-average oil price per Bbl(f)	$	88.41			$	92.70			$	87.72
Realized weighted-average NGL price per Bbl(g)	$	41.87			$	46.43			$	50.95

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Certain item footnotes

(a)	2014 and 2013 amounts include unrealized gains of $25 million and $3 million, and 2012 amount includes unrealized losses of $11 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil sales.

(b)

2014 amount includes certain items of a $218 million decrease in earnings (consists of impairment charge of $235 million related primarily to the Katz Strawn unit, an exploration charge of $8 million related to our Wolfcamp operation and a $25 million gain discussed in footnote (a) above). 2013 amount includes a $3 million increase in earnings discussed in footnote (a) above. 2012 amount includes $4 million decrease in earnings (consists of $11 million loss discussed in footnote (a) above and $7 million gain from the sale of our ownership interest in the Claytonville oil field unit), respectively.

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.

(g)	Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.

The CO2 business segment’s primary businesses involve the production, marketing and transportation of both CO2 and crude oil, and the production and marketing of natural gas and NGL. We refer to the segment’s two primary businesses as its Oil and Gas Producing Activities and its Source and Transportation Activities for each of these two primary businesses, following is information related to the increases and decreases in both EBDA and revenues before certain items in 2014 and 2013, when compared with the respective prior year:

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	$	56			14%		$	59			13%
Oil and Gas Producing Activities	(30		)		(3)%		26				2%
Intrasegment eliminations	—				—%		(4		)		5%
Total CO2	$	26			2%		$	81			4%

---

The primary increases in the source and transportation activities’ EBDA and revenues before certain items in the comparable years of 2014 and 2013 included the following:

•	EBDA increase of $56 million (14%) driven primarily by higher revenues (described following), partly offset by higher labor costs, power costs, property taxes and severance taxes; and

•

a revenue increase of $59 million (13%) driven primarily by an increase of 8% in average CO2 contract prices. The increase in contract prices were due primarily to two factors: (i) a change in the mix of contracts resulting in more CO2 being delivered under higher price contracts and (ii) heavier weighting of new CO2 contract prices to the price of crude oil. CO2 volumes were also higher by 7% when compared to the period in 2013, primarily due to expansion projects at our Doe Canyon field placed in service in the fourth quarter of 2013.

The primary changes in the oil and gas producing activities’ EBDA and revenues before certain items in the comparable years of 2014 and 2013 included the following:

•

EBDA decrease of $30 million (3%) driven by higher operating expenses as a result of (i) incremental well work costs at our recently acquired Goldsmith Landreth unit; (ii) increased power costs; and (iii) higher property and severance tax expenses related to higher revenues (described following). Also contributing to lower EBDA for the comparable period was lower crude oil and NGL prices, which were offset by improved net crude oil production of 8%; and

•

a $26 million (2%) increase in revenues, driven primarily by an 8% increase in crude oil sales volumes. The increase in sales volumes was due primarily to higher production at the Katz unit, incremental production from the Goldsmith Landreth unit (acquired effective June 1, 2013), and higher production at the SACROC unit (volumes presented in the results of operations table above). The increase in revenues was offset in part by a 5% decrease in the realized weighted average price per barrel of crude oil and a 10% decrease in NGL prices.

Year Ended December 31, 2013 versus Year Ended December 31, 2012
	EBDA increase/(decrease)						Revenues increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing Activities	$	74			8%		$	144			11%
Source and Transportation Activities	32				9%		40				10%
Intrasegment Eliminations	—				—		(18		)		(23)%
Total CO2	$	106			8%		$	166			10%

---

The primary increases in the oil and gas producing activities’ EBDA and revenues before certain items in the comparable years of 2013 and 2012 included the following:

•

EBDA increase of $74 million (8%) was driven by (i) a $144 million (11%) increase in crude oil sales revenues, due primarily to higher average realized sales prices for U.S. crude oil and partly due to higher oil sales volumes. Our realized weighted average price per barrel of crude oil increased 6% in 2013 versus 2012. The overall increase in oil sales revenues were also favorably impacted by a 7% increase in crude oil sales volumes, due primarily to both higher

production from the Katz and SACROC field units, and to incremental production from the Goldsmith Landreth unit, which we acquired effective June 1, 2013 (volumes presented in the results of operations table above); (ii) a $65 million (20%) increase in operating expenses resulting primarily from higher fuel and power expenses, and higher maintenance and well workover expenses, all related to both increased drilling activity in 2013 and incremental expenses associated with the Goldsmith Landreth field unit; and (iii) a $9 million decrease in natural gas plant products sales due to a 9% decrease in our realized weighted average price per barrel of NGL, partially offset by a 4% increase in sales volumes.

The primary increases in the source and transportation activities’ EBDA and revenues before certain items in the comparable years of 2013 and 2012 included the following:

•

EBDA increase of $32 million (9%) and revenue increase of $40 million (10%) were primarily driven by (i) higher CO2 sales revenues, due to an almost 10% increase in average sales prices; (ii) higher reimbursable project revenues, largely related to the completion of prior expansion projects on the Central Basin pipeline system; and (iii) higher third party storage revenues at the Yates field unit.

Terminals

	Year Ended December 31,
	2014				2013				2012
	(In millions, except operating statistics)
Revenues(a)	$	1,718			$	1,410			$	1,359
Operating expenses	(746		)		(657		)		(685		)
Other (expense) income	(29		)		74				14
Earnings from equity investments	18				22				21
Interest income and Other, net	12				1				2
Income tax expense	(29		)		(14		)		(3		)
EBDA(a)	944				836				708
Certain items, net(a)	35				(38		)		44
EBDA before certain items	$	979			$	798			$	752
Change from prior period	Increase/(Decrease)
Revenues before certain items(a)	$	298			$	43
EBDA before certain items	$	181			$	46
Bulk transload tonnage (MMtons)(b)	88.0				89.9				97.5
Ethanol (MMBbl)	71.8				65.0				65.3
Liquids leaseable capacity (MMBbl)	78.0				68.0				60.4
Liquids utilization %(c)	95.3		%		94.6		%		92.8		%

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Certain item footnotes

(a)

2014 amount includes (i) an $18 million increase in revenues from the amortization of deferred credits (associated with below market contracts assumed upon acquisition) from our Jones Act tankers acquired effective January 17, 2014 (APT acquisition); (ii) a $29 million write-down associated with a pending sale of certain terminals to a third-party; (iii) a $12 million increase in expenses due to hurricane clean-up and repair activities at our New York Harbor and Mid-Atlantic terminals; and (iv) a $12 million increase in expense associated with a liability adjustment related to a certain litigation matter. 2013 amount 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 $12 million decrease of earnings from other certain items (which includes a $8 million increase in revenues related to hurricane reimbursements). 2012 amount includes a $51 million increase in expense related to hurricanes Sandy and Isaac clean-up and repair activities and the associated write-off of damaged assets, a $12 million casualty indemnification gain related to a 2010 casualty at the Myrtle Grove, Louisiana, International Marine Terminal facility and a combined $5 million decrease of earnings from other certain items.

Other footnotes

(b)	Volumes for acquired terminals are included for all periods and include our proportionate share of joint venture tonnage.

(c)	The ratio of our actual leased capacity to its estimated potential capacity.

The Terminals business segment includes the transportation, transloading and storing of petroleum products, crude oil, condensate (other than those included in the Products Pipelines segment), and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals. The bulk and liquids terminal operations are grouped into regions based on geographic location and/or primary operating function. This structure allows the management to organize and evaluate segment performance and to help make operating decisions and allocate resources.

Following is information related to the increases and decreases in both EBDA and revenues before certain items in 2014 and 2013, when compared with the respective prior year:

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	$	66			n/a		$	109			n/a
West	32				45%		49				38%
Gulf Central	30				213%		51				663%
Gulf Liquids	20				10%		22				8%
Gulf Bulk	19				25%		26				19%
All others (including intrasegment eliminations and unallocated income tax expenses)	14				3%		41				5%
Total Terminals	$	181			23%		$	298			21%

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 West region 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% owned Battleground Oil Specialty Terminal Company LLC (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 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 out 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.

Year Ended December 31, 2013 versus Year Ended December 31, 20
	EBDA increase/(decrease)						Revenues increase/(decrease)
	(In millions, except percentages)
Gulf Liquids	$	21			11%		$	34			14%
Rivers	15				24%		7				5%
Midwest	9				18%		14				11%
All others (including intrasegment eliminations and unallocated income tax expenses)	1				—%		(12		)		1%
Total Terminals	$	46			6%		$	43			3%

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The primary changes in the Terminals business segment’s EBDA before certain items in the comparable years of 2013 and 2012 included the following:

•

increase of $21 million (11%) from our Gulf Liquids terminals, primarily due to higher liquids 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. For all terminals included in the Terminals business segment, total liquids leaseable capacity increased to 68.0 MMBbl at year-end 2013, up 12.6% from a capacity of 60.4 MMBbl at the end of 2012. The increase in capacity was mainly due to the acquisition of Norfolk and Chesapeake, Virginia facilities from Allied Terminals in June 2013 (incremental contributions from these two terminals are included within the “All others” line in the table above), and the partial in-service of BOSTCO and Edmonton Tank expansion projects. At the same time, Terminals’ overall liquids utilization rate increased 1.8% since the end of 2012;

•	increase of $15 million (24%) from our Rivers region terminals due to the IMT Phase I and II expansion projects at International Marine Terminal (located at Myrtle Grove, Louisiana, near the mouth of the Mississippi River) being placed in service in March 2013. The region also benefited from lower operating and maintenance costs; and

•	increase of $9 million (18%) from our Midwest region terminals, primarily driven by the opening of the BP Whiting terminal (Whiting Indiana) in August 2013. Salt and ethanol volumes increases also contributed to the overall improvement.

Products Pipelines

	Year Ended December 31,
	2014				2013				2012
	(In millions, except operating statistics)
Revenues	$	2,068			$	1,853			$	1,370
Operating expenses	(1,258		)		(1,295		)		(759		)
Other income (expense)	3				(6		)		5
Earnings from equity investments	44				45				39
Interest income and Other, net	1				3				11
Income tax (expense) benefit	(2		)		2				2
EBDA(a)	856				602				668
Certain items, net(a)	4				182				35
EBDA before certain items	$	860			$	784			$	703
Change from prior period	Increase/(Decrease)
Revenues	$	215			$	483
EBDA before certain items	$	76			$	81
Gasoline (MMBbl) (b)	451.8				423.4				395.3
Diesel fuel (MMBbl)	151.5				142.4				141.5
Jet fuel (MMBbl)	113.3				110.6				110.6
Total refined product volumes (MMBbl)(c)	716.6				676.4				647.4
NGL (MMBbl)(d)	35.2				37.3				31.7
Condensate (MMBbl)(e)	36.8				12.6				1.4
Total delivery volumes (MMBbl)	788.6				726.3				680.5
Ethanol (MMBbl)(f)	41.6				38.7				33.1

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Certain item footnote

(a)

2014 amount includes a $4 million increase in expense 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. 2012 amount includes a $32 million increase in expense associated with environmental liability and environmental recoverable receivable adjustments and a combined $3 million decrease in earnings from other certain items.

Other footnotes

(b)	Volumes include ethanol pipeline volumes.

(c)	Includes Pacific, Plantation Pipe Line Company, Calnev, Central Florida and Parkway pipeline volumes.

(d)	Includes Cochin and Cypress pipeline volumes.

(e)	Includes Kinder Morgan Crude & Condensate and Double Eagle Pipeline LLC pipeline volumes.

(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 2014 and 2013, when compared with the respective prior year:

Year Ended December 31, 2014 versus Year Ended December 31, 2013
	EBDA increase/(decrease)						Revenues increase/(decrease)
	(In millions, except percentages)
Crude & Condensate Pipeline	$	67			320%		$	89			402%
Pacific operations	36				13%		25				6%
Transmix operations	(19		)		(44)%		92				10%
All others (including eliminations)	(8		)		(2)%		9				2%
Total Products Pipelines	$	76			10%		$	215			12%

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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.

Year Ended December 31, 2013 versus Year Ended December 31, 2012
	EBDA increase/(decrease)						Revenues increase/(decrease)
	(In millions, except percentages)
Transmix operations	$	27			174%		$	406			82%
Cochin Pipeline	25				34%		33				42%
Crude & Condensate Pipeline	14				n/a		19				n/a
All others (including eliminations)	15				2%		25				3%
Total Products Pipelines	$	81			12%		$	483			35%

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n/a - not applicable

The primary changes in the Products Pipelines business segment’s EBDA before certain items in 2013 compared to 2012 were attributable to the following:

•

a $27 million (174%) increase from our transmix processing operations due to higher margins on processing volumes, incremental earnings from third-party sales of excess renewable identification numbers (RINS) (generated through its ethanol blending operations), and the recognition of unfavorable net carrying value adjustments to product inventory recognized in 2012. The period-to-period increases in revenues were mainly due to the expiration of certain transmix fee-based processing agreements since the end of the third quarter of 2012. Due to the expiration of these contracts, we now directly purchase incremental transmix volumes and sell incremental volumes of refined products, resulting in both higher revenues and higher costs of sales expenses;

•	a $25 million (34%) increase from Cochin Pipeline primarily due to higher transportation revenues, driven by an overall 33% increase in pipeline throughput volumes, partly attributable to incremental ethane/propane volumes as a result of pipeline modification projects completed in June 2012;

•	incremental earnings of $14 million from Kinder Morgan Crude & Condensate Pipeline, which began transporting crude oil and condensate volumes from the Eagle Ford shale gas formation to multiple terminaling facilities along the Texas Gulf Coast in October 2012; and

•	a $15 million (2%) increase from all other represents a number of small increases at various locations.

Kinder Morgan Canada

	Year Ended December 31,
	2014				2013				2012
	(In millions, except operating statistics)
Revenues	$	291			$	302			$	311
Operating expenses	(106		)		(110		)		(103		)
Earnings from equity investments	—				4				5
Interest income and Other, net	15				249				17
Income tax expense	(18		)		(21		)		(1		)
EBDA(a)	182				424				229
Certain items, net(a)	—				(224		)		—
EBDA before certain items	$	182			$	200			$	229
Change from prior period	Increase/(Decrease)
Revenues	$	(11	)		$	(9	)
EBDA before certain items	$	(18	)		$	(29	)
Transport volumes (MMBbl)(b)	106.8				101.1				106.1

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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.

The Kinder Morgan Canada business segment includes the operations of the Trans Mountain and Jet Fuel pipeline systems and until March 14, 2013, the effective date of sale, our one-third ownership interest in the Express crude oil pipeline system.

Following is information related to increases and decreases in both EBDA and revenues before certain items in 2014 and 2013, when compared with the respective prior year:

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/a				n/a
Trans Mountain Pipeline	(12		)		(6)%		$	(11	)		(4)%
Total Kinder Morgan Canada	$	(18	)		(9)%		$	(11	)		(4)%

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n/a - not applicable

(a)	Amount consists of unrealized foreign currency gains/losses, 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 translation. 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.

Year Ended December 31, 2013 versus Year Ended December 31, 2012
	EBDA increase/(decrease)						Revenues increase/(decrease)
	(In millions, except percentages)
Trans Mountain Pipeline	$	(24	)		(11)%		$	(9	)		(3)%
Express Pipeline(a)	(5		)		(28)%		n/a				n/a
Total Kinder Morgan Canada	$	(29	)		(13)%		$	(9	)		(3)%

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n/a - not applicable

(a)	We sold our debt and equity investments in Express Pipeline on March 14, 2013. Prior to the sale, the earnings from Express Pipeline were recorded under the equity method of accounting.

The period-to-period decreases in EBDA from Express were primarily due to both lower equity earnings and lower interest income resulting from the sale of our equity and debt investments in Express effective March 14, 2013.

The decreases in Trans Mountain’s earnings were driven by (i) higher income tax expenses (due largely to general increases in British Columbia’s income tax rates since the end of the third quarter of 2012); (ii) unfavorable impacts from foreign currency translation (due to the weakening of the Canadian dollar since the end of 2012, we translated Canadian denominated income and expense amounts into less U.S. dollars in 2013); and (iii) lower management incentive fees earned from the operation of the Express pipeline system (due to its sale in March 2013). The period-to-period decreases in Trans Mountain’s earnings were partially offset by incremental non-operating income from allowances for funds used during construction (representing an estimate of the cost of capital funded by equity contributions).

Other

Our other segment results are driven by activities from other miscellaneous assets and liabilities purchased in our 2012 EP acquisition that were not allocated to the above segments. This segment contributed earnings of $13 million, a loss of $5 million and earnings of $7 million for the years ended 2014, 2013 and 2012, respectively. However, 2014 and 2012 earnings include a certain item of $22 million increase in earnings and $10 million decrease in earnings, respectively, primarily related to our foreign operations. After taking into effect the certain item, the earnings for 2014 and 2013 decreased by $4 million and $22 million, respectively, when compared with the respective prior year.

General and Administrative, Interest, and Noncontrolling Interests

	Year Ended December 31,
	2014				2013				2012
	(In millions)
General and administrative expense(a)(c)	$	610			$	613			$	929
Certain items(a)	28				8				(366		)
Management fee reimbursement(c)	(36		)		(36		)		(35		)
General and administrative expense before certain items	$	602			$	585			$	528
Unallocable interest expense net of interest income and other, net(b)	$	1,807			$	1,688			$	1,441
Certain items(b)	3				32				(87		)
Unallocable interest expense net of interest income and other, net, before certain items	$	1,810			$	1,720			$	1,354
Net income attributable to noncontrolling interests	$	1,417			$	1,499			$	112

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Certain item footnotes

(a)

2014 amount includes a decrease in expense of $39 million related to pension credit income and a net increase of $11 million in expense for various other certain items. 2013 amount includes a decrease in expense of $59 million related to EP post-merger pension credits, partially offset by increases in expense of (i) $41 million related to asset and business acquisition costs and unallocated legal expenses and (ii) combined $10 million from other certain items primarily related to the EP acquisition. 2012 amount includes $366 million increase of pre-tax expense associated with the EP acquisition and EP Energy sale, which includes (i) $160 million in employee severance, retention and bonus costs; (ii) $87 million of accelerated EP stock based compensation allocated to the post-combination period under applicable GAAP rules; (iii) $37 million in advisory fees; (iv) $68 million for legal fees and reserves, net of recoveries;

(v) $29 million of other EP acquisition expenses; and (vi) a combined $14 million increase in expense from other certain items; partially offset by a $29 million benefit associated with pension income.

(b)

2014, 2013 and 2012 amounts include $9 million, $21 million and $108 million of amortization of capitalized financing fees, almost all of which was associated with the EP acquisition financing. 2012 also includes amounts written-off due to debt repayment. 2014, 2013 and 2012 amounts include (i) $12 million, $14 million and $9 million, respectively, of interest expense on margin for marketing contracts and (ii) $65 million, $67 million and $29 million, respectively, of decreased interest expense related to debt fair value adjustments associated with the EP and Copano acquisitions. 2014 amount includes (i) $27 million of interest expense related to the Merger Transactions; and (ii) an increase in interest expense of $15 million associated with a certain Pacific operations litigation matter. 2014 and 2012 also include $1 million and $1 million decreases in expense, respectively, related to the combined effect from other certain items.

Other footnote

(c)

2014, 2013 and 2012 amounts include NGPL Holdco LLC general and administrative reimbursements of $36 million, $36 million and $35 million, respectively. These amounts were recorded to the “Product sales and other” caption in our accompanying consolidated statements of income with the offsetting expenses primarily included in the “General and administrative” expense caption in our accompanying consolidated statements of income.

Items not attributable to any segment include general and administrative expenses, unallocable interest income and income tax expense, interest expense, and net income attributable to noncontrolling interests. Our general and administrative expenses include such items as unallocated salaries and employee-related expenses, employee benefits, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services. These expenses are generally not controllable by our business segment operating managers and therefore are not included when we measure business segment operating performance. For this reason, we do not specifically allocate our general and administrative expenses to the business segments. As discussed previously, we use segment EBDA internally as a measure of profit and loss to evaluate segment performance, and each of our segment’s EBDA includes all costs directly incurred by that segment.

The increase in general and administrative expenses before certain items of $17 million and $57 million in 2014 and 2013 when compared with the respective prior year was primarily driven by the acquisition of Copano (effective May 1, 2013) and EP (effective May 25, 2012). Additional drivers were higher benefit costs, payroll taxes and segment 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 $90 million and $366 million in 2014 and 2013, respectively, when compared with the respective prior year. 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 issuing $6 billion of debt primarily related to 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.

The increase in interest expense in 2013 as compared to respective prior year was primarily due to interest expense incurred from EP acquisition debt, debt assumed in the EP acquisition, and other business acquisitions, see Notes 3 “Acquisition and Divestitures” and Note 8 “Debt” to our consolidated financial statements. Also contributed to the increase in 2013 as compared to 2012 were higher effective interest rates and higher average borrowings which were largely due to the capital expenditures and joint venture contributions. For more information on the capital expenditures and capital contributions see “—Liquidity and Capital Resources.”

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, 2014, approximately 26% 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. As of December 31, 2013, approximately 25% of our debt balances (excluding debt fair value adjustments) were subject to variable interest rates. For more information on our interest rate swaps, see Note 13 “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 $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 on our Kinder Morgan Louisiana pipeline system 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. The $1,387 million (1,238%) increase for 2013 as compared to 2012 was primarily due to our noncontrolling interests’ portion of (i) our 2013 $558 million gain from the remeasurement of our previously held 50% equity interest in Eagle Ford to fair value; (ii) our 2013 $140 million after-tax gain on the sale of our investments in the Express pipeline system; (iii) additional income from EP assets acquired in 2012; (iv) additional income from our 2013 acquisition of Copano; and (v) the 2012 non-cash loss of $937 million net of tax loss from both costs to sell and the remeasurement of FTC Natural Gas Pipeline disposal group net assets to fair value.

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, 2014 versus Year Ended December 31, 2013

Our tax expense for income 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 tax expense is due primarily to (i) the tax impact of significantly lower pretax earnings in 2014 associated with our investment in KMP (primarily as a result of KMP’s 2014 recognition of a $235 million impairment of its CO2 assets compared to gains it recognized in 2013 of $558 million on remeasurement to fair value of its initial 50% interest in the Eagle Ford joint venture and $224 million on the sale of its 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.

Year Ended December 31, 2013 versus Year Ended December 31, 2012

Our tax expense for income from continuing operations for the year ended December 31, 2013 was $742 million, as compared with 2012 income tax expense of $139 million. The $603 million increase in tax expense is due primarily to (i) higher income in 2013 attributable to our investments in KMP and EPB as compared to 2012 and (ii) tax expense as a result of KMP’s 2013 sale of its one-third interest in the Express pipeline system. These increases are partially offset by a decrease in the deferred state tax rate as a result of the March 2013 drop-down transaction and KMP’s Copano acquisition.

Liquidity and Capital Resources

General

As of December 31, 2014, we had a combined $315 million of “Cash and cash equivalents,” on our consolidated balance sheet, a decrease of $283 million (47%) from December 31, 2013. We believe our cash position and remaining borrowing capacity (discussed below in “—Short-term Liquidity”), and our access to financial resources are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

Our primary cash requirements, in addition to normal operating expenses, are for debt service, sustaining capital expenditures, expansion capital expenditures and quarterly dividends to our common shareholders.

In general, we expect to fund:

•	cash dividends and sustaining capital expenditures with existing cash and cash flows from operating activities;

•	expansion capital expenditures and working capital deficits with retained cash, proceeds from divestitures, additional borrowings (including commercial paper issuances), and the issuance of additional common stock;

•	interest payments with cash flows from operating activities; and

•	debt principal payments, as such debt principal payments become due, with proceeds from divestitures, additional borrowings or by the issuance of additional common stock.

In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.” Cash provided from our operations is fairly stable across periods since a majority of our cash generated is fee based from a diversified portfolio of assets and is not sensitive to commodity prices. However, in our CO2 business segment, while we hedge the majority of our oil production, we do have exposure to unhedged volumes, a significant portion of which are NGL.

Historically, our distributions to noncontrolling interests were primarily comprised of distributions made by KMP and EPB on their common units that were not owned by us. With the closing of the Merger Transactions, all the previously held equity securities of KMP, EPB and KMR are now owned by us. As partial consideration for the KMP, EPB and KMR equity securities that we did not already own as of the Merger Transactions date, we issued approximately 1,097 million KMI Class P common shares. We expect that dividends on KMI’s Class P common stock will be $2.00 per share for 2015. Also, see “—KMI Dividends.”

Credit Ratings and Capital Market Liquidity

Based on our historical record, 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 short-term borrowings. We are subject, however, to conditions in the equity and debt markets 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 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, 2014.

Rating agency		Senior debt rating		Date of last change		Outlook
Standard and Poor’s		BBB-		November 20, 2014		Stable
Moody’s Investor Services		Baa3		November 21, 2014		Stable
Fitch Ratings, Inc.		BBB-		November 20, 2014		Stable

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Short-term Liquidity

As of December 31, 2014 our principal sources of short-term liquidity are (i) our $4.0 billion revolving credit facility and associated $4.0 billion commercial paper program (discussed following); and (ii) cash from operations. The loan commitments under our revolving credit facility can be used to fund borrowings for working capital and other general corporate purposes and also serve as a backup for our commercial paper program. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and have consistently generated strong cash flow from operations, providing a source of funds of $4,467 million and $4,122 million in 2014 and 2013, respectively (the year-to-year increase is discussed below in “Cash Flows—Operating Activities”).

Effective upon the closing of the Merger Transactions on November 26, 2014, we replaced the prior KMI credit agreement, the KMP credit agreement and the EPB credit agreement with a 5-year, $4 billion revolving credit facility with a syndicate of lenders, which can be increased to $5 billion if certain circumstances are met. On November 26, 2014, we entered into a $4.0 billion commercial paper program. Borrowings under our commercial paper program and letters of credit reduce borrowings allowed under our credit facility. For additional information on our credit facility and commercial paper program, see Note 8 “Debt” to our consolidated financial statements.

In connection with the Hiland acquisition, we entered into and made borrowings of $1,641 million under a new six-month bridge credit facility with UBS AG, Stamford Branch. The credit facility bears interest at the same rate as our $4.0 billion

revolving credit facility and the borrowing capacity is reduced by any payments made. As of the date of this filing, we had $1,516 million outstanding under this credit facility.

Our short-term debt as of December 31, 2014 was $2,717 million, primarily consisting of (i) $1,236 million combined outstanding borrowings under our $4 billion credit facility and $4 billion commercial paper program; (ii) $375 million in principal amount of 4.10% senior notes that mature November 15, 2015; (iii) $340 million in principal amount of 6.80% senior notes that mature November 15, 2015; (iv) $300 million in principal amount of 5.625% senior notes that mature February 15, 2015; and (v) $250 million in principal amount of 5.15% senior notes that mature March 1, 2015. We intend to refinance our short-term debt through additional credit facility borrowings, commercial paper borrowings, issuing new long-term debt, or with proceeds from asset sales. Our combined balance of short-term debt as of December 31, 2013 was $2,306 million.

We had working capital (defined as current assets less current liabilities) deficits of $2,610 million and $2,207 million as of December 31, 2014 and 2013, respectively. Our current liabilities include short-term borrowings used to finance our expansion capital expenditures which are periodically replaced with long-term financing. The overall $403 million (18%) unfavorable change from year-end 2013 was primarily due to (i) a net increase in KMI’s credit facility and commercial paper borrowings; (ii) lower cash balances (described above); and (iii) an increase in the current portion of long-term debt. The overall increase in our working capital deficit was partially offset by the repayment of KMP’s commercial paper borrowings and the subsequent termination of the program. 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 combined cash and cash equivalent balances as a result of our equity issuances and our or our subsidiaries’ debt issuances (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

In addition to our principal sources of short-term liquidity listed above, we could meet our cash requirements through the issuance of long-term securities or additional common shares. Our equity offerings consist of the issuance of additional Class P common stock with a par value of $0.01 per share. Through an equity distribution agreement, we can issue and sell through or to our sales agents and/or principals shares of our Class P common stock from time to time up to an aggregate offering price of $5 billion. For more information on our equity issuances during 2014 and our equity distribution agreement, see Note 10, “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. As of December 31, 2014 and 2013, the aggregate principal amount outstanding of the various series of KMI’s senior notes (excluding our subsidiaries’ senior borrowings discussed below) was $11,438 million (including $6 billion issued in 2014 to fund the cash portion of consideration of the Merger Transactions), and $5,645 million, respectively.

In addition, from time to time our subsidiaries, including KMP, TGP, EPNG, CIG, SNG and Copano, have issued long-term debt securities, often referred to as their senior notes. Most of the debt of our subsidiaries is unsecured; however a modest amount of secured debt has been incurred by our subsidiaries. As of December 31, 2014 and 2013, the total liability balance due on the various borrowings of our subsidiaries (including senior notes issued by KMP, TGP, EPNG, CIG, SNG and Copano) was $28,355 million and $25,889 million, respectively.

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 18 “Guarantee of Securities of Subsidiaries” to our consolidated financial statements.

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 2014, see Note 8 “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 Structure

We finance our expansion capital expenditures and acquisitions with a combination of equity and debt in order to maintain an approximate net debt to EBITDA ratio between 5.0 and 5.5. In the short-term, we may fund these expenditures from borrowings under our credit facility until the amount borrowed is of a sufficient size to cost effectively offer either debt, equity, or both.

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.

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 “—KMI Dividends.”

Our capital expenditures for the year ended December 31, 2014, and the amount we expect to spend for 2015 to sustain and grow our business are as follows (in millions):

	2014				Expected 2015
Sustaining capital expenditures(a)	$	509			$	586
Discretionary capital expenditures(b)(c)	$	3,580			$	4,381

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(a)	2014 and Expected 2015 amounts include $57 million and $82 million, respectively, for our proportionate share of sustaining capital expenditures of certain unconsolidated joint ventures.

(b)	2014 amount (i) includes $533 million of discretionary capital expenditures of unconsolidated joint ventures and acquisitions and (ii) excludes a combined $118 million net change from accrued capital expenditures, contractor retainage and amounts primarily related to contributions from noncontrolling interests to fund a portion of certain capital projects

(c)	Expected 2015 includes our contributions to certain unconsolidated joint ventures and small acquisitions, 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 12 “Commitments and Contingent Liabilities” to our consolidated financial statements. Additional information regarding the nature and business purpose of our investments is included in Note 6 “Investments” to our consolidated financial statements.

Contractual Obligations and Commercial Commitments

	Payments due by period
	Total				Less than 1 year				2-3 years				4-5 years				More than 5 years
	(In millions)
Contractual obligations:
Debt borrowings-principal payments	$	41,029			$	2,717			$	4,743			$	5,147			$	28,422
Interest payments(a)	29,438				2,203				4,077				3,512				19,646
Leases and rights-of-way obligations(b)	678				97				160				132				289
Pension and postretirement welfare plans(c)	862				75				47				48				692
Transportation, volume and storage agreements(d)	1,189				162				277				249				501
Other obligations(e)	402				153				112				25				112
Total	$	73,598			$	5,407			$	9,416			$	9,113			$	49,662
Other commercial commitments:
Standby letters of credit(f)	$	381			$	350			$	31			$	—			$	—
Capital expenditures(g)	$	1,026			$	1,026			$	—			$	—			$	—

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(a)	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, 2014.

(b)	Represents commitments pursuant to the terms of operating lease agreements and liabilities for rights-of-way.

(c)	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 2015 and estimated benefit payments for unfunded plans in all years.

(d)	Primarily represents transportation agreements of $305 million, volume agreements of $498 million and storage agreements for capacity on third party and an affiliate pipeline systems of $257 million.

(e)	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.

(f)

The $381 million in letters of credit outstanding as of December 31, 2014 consisted of the following (i) $20 million under four letters of credit related to power and marketing purposes; (ii) $86 million under fourteen letters of credit for insurance purposes; (iii) a $100 million letter of credit that supports certain proceedings with the CPUC involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (iv) 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; (v) a $34 million letter of credit supporting our pipeline and terminal operations in Canada; (vi) a $25 million letter of credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (vii) a $24 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; (viii) a $13 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; and (ix) a combined $33 million in twenty-four letters of credit supporting environmental and other obligations of us and our subsidiaries.

(g)	Represents commitments for the purchase of plant, property and equipment as of December 31, 2014.

Cash Flows

Operating Activities

The net increase of $345 (8%) million in cash provided by operating activities in 2014 compared to 2013 was primarily attributable to:

•

a $984 million increase in cash from overall higher net income after adjusting our period-to-period $249 million decrease in net income for non-cash items primarily consisting of the following: (i) 2013 gain on the remeasurement of our previous 50% equity investment in Eagle Ford; (ii) 2013 gain on sale of our investments in the Express pipeline system (see the discussion of these investments in Note 3 “Acquisitions and Divestitures” to our consolidated financial statements); (iii) 2014 loss on impairments on both our CO2 and terminal long-lived assets; (iv) DD&A expenses (including amortization of excess cost of equity investments); (v) deferred income tax expenses; (vi) gains from the sale or casualty of property, plant and equipment (see discussion above in “—Results of Operations”); (vii) the net activity of our equity method investees; and (viii) adjustments to accrued transportation rate case and legal liabilities;

•	a $315 million decrease in cash associated with rate case reserve payments primarily driven by the 2014 CPUC settlement and refund payments;

•

a $228 million decrease in cash associated with net changes in working capital items and non-current assets and liabilities. The decrease was primarily driven by a $195 million use of cash for income tax payments made during the first three quarters of 2014 (due to discrete events in the fourth quarter, we received a refund for these payments in the first quarter of 2015); lower cash flows from both natural gas storage and pipeline transportation system balancing, and lower net dock premiums and toll collections received from our Trans Mountain pipeline system customers. These decreases were partially offset by, among other things, higher cash inflows from favorable changes in the collection and payment of trade and related party receivables and payables (due primarily to the timing of invoices received from customers and paid to vendors and suppliers), and favorable changes in previously deferred reimbursable costs; and

•	a $96 million decrease in cash from interest rate swap termination payments received. In 2013, we terminated, in three separate transactions, three existing fixed-to-variable interest rate swap agreements prior to their contractual maturity dates.

Investing Activities

The $2,088 million net increase in cash used in investing activities in 2014 compared to 2013 was primarily attributable to:

•	a $1,096 million decrease in cash due to higher expenditures for acquisitions. The increase in acquisition expenditures was primarily related to the $1,231 million we paid in 2014 for our APT and Crowley tanker acquisitions, versus the $280 million we paid in 2013 to acquire the Goldsmith Landreth San Andres oil field unit (both discussed in Note 3 “Acquisitions and Divestitures”);

•	a combined $490 million decrease in cash due to proceeds received in 2013 from divestitures, primarily consisting of our sale of the investments in the Express pipeline system;

•	a $248 million decrease in cash due to higher capital expenditures in 2014 primarily reflecting higher investment undertaken to expand and improve our Products Pipelines and CO2 business segments; and

•	a $172 million decrease in cash due to higher capital contributions, driven by a $175 million contribution we made in 2014 to MEP, our 50%-owned joint venture, to fund our share of the joint venture’s repayment of $350 million of senior notes that matured on September 15, 2014.

Financing Activities

The net increase of $1,566 million in cash from financing activities in 2014 compared to 2013 was primarily attributable to:

•

a $5,533 million net increase in cash from overall debt financing activities. The increase was driven by, among other things, a $5,259 million increase in cash due to the issuance of our senior notes, including proceeds of $5,987 million received in 2014 from the series of senior notes we issued to fund our Merger Transactions, and a net increase of $583 million in cash from both our commercial paper and revolving credit facilities programs (reflecting an increase in issuances of $5,733 million, partially offset by an increase in payments of $5,150 million). Further information regarding the debt related to our Merger Transactions is discussed in Note 8 “Debt” to our consolidated financial statements;

•	a $445 million increase in cash due to lower combined repurchases of shares and warrants;

•	a $3,937 million decrease in cash resulting from the cash portion of consideration for the Merger Transactions;

•	a $321 million decrease in cash associated with distributions to noncontrolling interests, primarily reflecting increased distributions to common unit owners of KMP and EPB prior to the Merger Transactions offset by no distribution being paid for the fourth quarter of 2014 since the closing date of the Merger Transactions occurred prior to KMP or EPB declaring any additional distributions; and

•	a $138 million decrease in cash due to higher dividend payments.

KMI Dividends

The table below reflects the payment of cash dividends of $1.74 per common share for 2014, a 9% increase over our 2013 dividends of $1.60 per common share.

Three months ended		Total quarterly dividend per share for the period					Date of declaration		Date of record		Date of dividend
March 31, 2014		$	0.42				April 16, 2014		April 30, 2014		May 16, 2014
June 30, 2014		$	0.43				July 16, 2014		July 31, 2014		August 15, 2014
September 30, 2014		$	0.44				October 15, 2014		October 31, 2014		November 17, 2014
December 31, 2014		$	0.45				January 21, 2015		February 2, 2015		February 17, 2015

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As disclosed elsewhere in this report, we expect to pay cash dividends totaling $2.00 per share on our common stock for 2015. There is nothing in our governing documents or credit agreements that prohibits us from borrowing to pay dividends. The actual amount of 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 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 dividends generally will be paid on or about the 16th day of each February, May, August and November.

Recent Accounting Pronouncements

Please refer to Note 17 “Recent Accounting Pronouncements” to our consolidated financial statements for information concerning recent accounting pronouncements.