KMIKinder Morgan

We note your statement that “several of [y]our counterparties defaulted on their obligations” or filed for bankruptcy protection. In future reports, if material, please disclose the number of customers who have defaulted and the amount of revenue management believes is unrecoverable. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We acknowledge the Staff’s comment and in future reports, if material, we will cross-reference to other sections of our filing where applicable quantitative disclosure resides regarding customers who have defaulted on their obligations.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Read in the reply ↗

In future reports, please disclose the percentage of your total revenues that are tied to fee based, take-or-pay and commodity based contracts. In this regard, we note your statement on page 10 that “the overwhelming majority of cash [you] generate is fee-based and therefore is not directly exposed to commodity prices.” However, you also acknowledge commodity price sensitivity in your CO2, Natural Gas Pipelines and

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Products Pipelines segments. Please provide additional detail as to the breakdown of these kinds of contracts in each segment and quantify the amount of revenue and capacity that is impacted.

We acknowledge the Staff’s comment and agree that it is important for the readers of our financial statements to understand the direct commodity price sensitivity of our operations. Our disclosure on page 10 of our 2015 Form 10-K referenced by the Staff is specifically aimed at providing the users of our report a concise and useful tool to gauge the extent to which our distributable cash flows are, or are not, directly exposed to volatility in commodity prices.

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We believe it is more meaningful and useful to the users of our reports to provide an estimated sensitivity of our distributable cash flow (“DCF”) to changes in the relevant commodity prices, rather than providing total revenues that are fee-based, take-or-pay, or commodity-based, which would not allow users to quantify our bottom-line exposure.

In its Guidance Regarding Management's Discussion and Analysis of Financial Condition and Results of Operations (Release No. 33-8350), the Commission stated that “MD&A should be a discussion and analysis of a company’s business as seen through the eyes of those who manage that business.” As discussed in our disclosure and our response No. 5 below, our management, and we believe our investors, evaluate our performance using DCF and want to understand quantitatively how our DCF might be directly impacted by changes in commodity prices. As such, as part of our 2016 Outlook on page 10, we provide our 2016 budget-assumed West Texas Intermediate (WTI) crude price per barrel and Henry Hub natural gas price per MMBtu. We also provide the estimated changes in expected 2016 distributable cash flow that would result from a $1 per barrel change in WTI crude prices ($6.5 million), a $0.10 per MMBtu change in Henry Hub natural gas prices ($2 million), and a 1% change in the ratio of weighted average NGL prices to WTI crude prices ($0.6 million), in each case as compared to our 2016 commodity price assumptions. This sensitivity disclosure, taken together with our $4.9 billion of expected DCF disclosed on page 10 (and subsequently updated and reconciled to net income in our MD&A each reporting period), illustrates the limited nature of our exposure to commodity price volatility.

We monitor our segments’ exposure to commodity prices and, while our commodity price exposure has historically been primarily in our CO2 segment, we enhanced our 2015 disclosure to provide the sensitivity across those segments of ours with any significant direct commodity price sensitivity rather than only for our CO2 segment.

We do not believe providing the requested revenue percentage information or the breakdown of revenue by contract type for each segment would add material information to an analysis of our commodity price sensitivity. We have thousands of contracts with a wide variety of terms, and the usefulness of revenue for gauging commodity price sensitivity would similarly vary widely, due in part to the fact that certain of our costs also vary based on the same commodity price indices. A user presented with our revenue by contract type would not have sufficient information to determine the overall potential impact of commodity price volatility on our performance. Our disclosure allows users of our 2015 Form 10-K to evaluate our guidance based on their own commodity price expectations. We believe our existing sensitivity disclosure achieves the objective of providing users a more complete picture of our commodity price sensitivity, with context that would be absent from percentages of revenue tied to fee-based, take-or-pay and commodity-based contracts.

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In future reports, please discuss the credit ratings of those customers that comprise the majority of your revenues and the amount of revenue those customers represent. In this regard, we note your CEO’s remarks in the 2015 earnings call that your top 25 customers represent about 44% of your revenue and that 80% of those top customers are investment grade rated entities.

The remarks of our CEO referenced above related to supplemental information we prepared as part of a special project conducted to quantify this information in light of the unfavorable commodity price environment and industry conditions that we encountered at that time. We considered whether such information should be included in our 2015 Form 10-K, but, based on the results of this special project, determined such information did not represent a material risk to the company and therefore, including it in our 2015 Form 10-K was not necessary.

Consistent with ASC 280-10-50-42, on page 132 of

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our 2015 Form 10-K, in Footnote 16 Reportable Segments, we disclose that we did not have revenues from any single customer that exceeded 10% of our consolidated revenues. Furthermore, in Items 1 and 2, Business and Properties, on page 19 under Major Customers, we provide similar disclosure.

We believe that the size and diversity of our customer base, and the prevalence of large, well capitalized international oil and gas companies and public utilities among our top customers, along with the value delivered to our customers by our services and assets, are significant factors in mitigating our credit risk exposure. During 2015 and through the date of filing of our 2015 Form 10-K, we were aware of only six bankruptcies among our several thousand customers. Our allowance for doubtful accounts, which was disclosed on page 87 of our 2015 Form 10-K, showed a net $81 million increase during the year. On pages 55 and 56 of our 2015 Form 10-K, we describe the components of our bad debt expense totaling $82 million related to certain coal customer bankruptcies, essentially explaining the driver of all of the increase in our allowance for doubtful accounts during the year. The credit exposure related to customer bankruptcies or contract defaults in our other segments was de minimus. Other than exposures to coal customers, which we have disclosed and quantified, we have not experienced significant adverse financial impacts due to credit risk and do not currently expect to in the future.

We continually monitor counterparty credit risk, including as it relates to accounts receivable and specific estimates of future cash flows, using our existing procedures designed to provide the necessary information for management decision-making and to comply with accounting and disclosure requirements. To the extent we have material exposures related to concentrations of credit risk, we will provide relevant disclosure in our future reports.

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We note your indication on page 40 that the remaining average contract life of your natural gas transportation contracts was approximately six years. Given this average, in future filings, please enhance your disclosure to explain the number of contracts, expressed as a percentage of revenue, up for renewal in the next 1-2 years.

We provide the remaining average contract life for our natural gas transportation contracts using a weighted average based on the contracted capacity, as a measure for our users to understand the overall level of demand for our natural gas transportation assets. We further supplement this disclosure, as applicable, with specific disclosure regarding re-contracting activity and risk for specific pipeline assets when it is material.

Our Natural Gas Pipelines segment has thousands of customer contracts. Many customers have more than one contract with one or more of our pipeline assets.

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Contracts come up for renewal every year; however, no single customer contract is material to our overall revenues or earnings in any given year. While we may have many contracts with significant revenues expiring in any given year, the size of our portfolio and the nature of our Natural Gas Pipelines’ assets, most of which are core energy infrastructure assets, mitigate our risk related to contract expirations. As such, the consistent trend with our expiring contracts on most of our pipelines has been that they are renewed or the associated capacity is contracted with another customer. A significant change in that trend would result in a corresponding change in our average contract life, which over the past four years has averaged from 5.5 to 7 years. In light of the facts and circumstances discussed above, we believe that disclosure of the percentage or amount of revenue related to contracts up for renewal in the coming 12 or 24 months could give a potentially misleading impression about the risk to these revenues. We believe our existing approach provides the appropriate level of disclosure, and therefore, we propose in future filings, to continue providing the average remaining Natural Gas Pipeline transportation contract life.

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You state that in December 2015 your board of directors approved a plan pursuant to which you expect to pay quarterly dividends of $0.125 per share to your common shareholders ($0.50 per common share annually), down from your third quarter 2015 dividend of $0.51 per common share, beginning with the fourth quarter 2015 dividend payable to common shareholders on February 16, 2016.

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We further note that you expect the reduced dividend level eliminates your need to access the capital markets to fund your growth projects in 2016. Please note that non-GAAP measures that focus on cash generated are typically presented for yield-generating master limited partnership where available cash is required to be distributed as opposed to a C-Corporation where dividends are solely at the election of the Board of Directors. Given the flexibility of the corporate organization to adjust its dividend policy as well as your stated use of excess cash for the foreseeable future, please tell us in detail why this cash flow metric remains useful and relevant to your current investors and analysts. We may have further substantive comment.

DCF is the primary internal performance measure for our company, and management believes the same is true for external users of our reports. Management utilizes this performance measure in its weekly business reviews in evaluating the performance of our segments and management teams. While historically DCF quantified our measure of adjusted earnings which would primarily be returned to shareholders via dividends, it now quantifies our measure of adjusted earnings available to create value to our common equity holders in other ways.

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This value could come in the form of dividends, share repurchases, debt retirement, acquisitions, or expansion capital projects. DCF is the measure we have used consistently for our entire existence. We believe it is well understood and valued by the users of our reports and is comparable to measures used by those within our industry regardless of corporate structure or dividend payout ratio.

We acknowledge the Staff’s observation that master limited partnerships are required to distribute available cash. We believe it is also important to note that the definition of available cash for master limited partnerships often includes a reduction for certain cash reserves which are generally at management’s discretion. Accordingly, master limited partnerships can have a wide range of distributions as a percentage of DCF. Additionally, the energy infrastructure companies structured as C-corporations to which we compare ourselves utilize DCF or similar Non-GAAP financial measures, such as cash available for dividends.

We have modified our non-GAAP financial measures disclosure regarding our DCF performance measure subsequent to the change in our dividend. We intend to make further enhancements substantially consistent with the language below in our future earnings releases and filings.

Below is our proposed revised explanation of DCF:

DCF is a significant performance measuremetric used by us and by external users of our financial statements to evaluate our performance and to measure and estimate the ability of our assets to generate cash earningsflow, after servicing our debt, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as dividends, stock repurchases, retirement of debt, or expansion capital expenditures. on an ongoing basis. Management uses this measure and believes it provides users of our financial statements with a is important to users of our financial statements because it believes the measure that more accurately reflects our business’ ability to generate cash earnings ongoing cash generation capacity than a comparable GAAP similar measure with the certain items included. We believe the GAAP measure most directly comparable to DCF is net income. A reconciliation of DCF to net income is provided hereinin this release. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends.

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We note that you have separate revenue line items for natural gas sales, services and product sales and other. We further note that you present one line item for cost of sales. Please tell us how you considered separately disclosing cost of tangible goods sold and cost of services to comply with Rule 5-03(b)(2) of Regulation S-X.

Consistent with the provisions of Rule 5-03(b)(2), we present sales of tangible products and revenues from services separately. We also state separately costs of tangible goods sold and cost of services. The costs associated with revenues presented within our “Natural Gas Sales” and “Product Sales and Other” revenue captions are primarily included in our “Cost of Sales” caption on our Consolidated Statement of Income, with the exception of our CO2 segment, where we classify our oil and gas lease operating expenses within the “Operations and Maintenance” caption.

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The costs of services associated with revenues presented within our “Services” caption are primarily included within the “Operations and Maintenance” caption.

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Please describe and quantify the types of regulatory assets and liabilities included in this summary disclosure. Please also affirmatively state whether your regulatory assets are being recovered in rates with a return. Since there is a large gap in the recovery period for your regulatory assets, a weighted recovery period would be more informative than a wide range of years.

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Please revise to provide a more informative disclosure. Finally, to the extent any specific regulatory assets are being recovered without a return, provide the disclosure required by ASC 980-340-50-1.

We acknowledge the Staff’s comment. In future filings we will add further disclosure as to the recovery period of our significant regulatory assets and liabilities and the amount of regulatory assets for which we do not expect to earn a rate of return. Set forth below is the table from our 2015 Form 10-K revised to comply with the Staff’s request as an example of the type of disclosure we expect to include in future filings.

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The changes are marked as compared to our current disclosure.

Regulatory Assets and Liabilities

Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We included the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets. As of December 31, 2015, the recovery period of these regulatory assets was approximately one year to forty-one years.

The following table summarizes our regulatory asset and liability balances as of December 31, 2015 and 2014 (in millions):

December 31,

2015

2014

Current regulatory assets

$

Non-current regulatory assets

378

406

Total regulatory assets (a)

433

487

Current regulatory liabilities

161

189

Non-current regulatory liabilities

166

290

Total regulatory liabilities (b)

327

479

(a)

Regulatory assets as of December 31, 2015, include (1) $197 million of unamortized losses on disposal of assets, (2) $136 million income tax gross up on equity AFUDC and (3) $100 million of other assets including amounts related to fuel tracker arrangements. The weighted average remaining recovery period for these assets is approximately 18 years. Approximately, $222 million of the regulatory assets are recoverable without earning a return, including the income tax gross up on equity AFUDC for which there is an offsetting deferred income tax balance for FERC rate base purposes, and therefore, it does not earn a return.

(b)

Regulatory liabilities are comprised of customer prepayments to be credited to shippers or other over-collections that are expected to be returned to shippers or netted against under-collections over time. Approximately, $78 million of the $166 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 8 years, while the remaining $88 million is not subject to a defined period.

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Please explain how you adjust goodwill as a result of applying the look-through method of recording deferred taxes on the outside book tax basis differences in your investments without regard to non-tax deductible goodwill.

We apply a look through method of recording deferred income taxes on the outside book-tax basis differences in our investments. As a result, in the context of accounting for a business combination, no deferred income taxes are recorded associated with non-deductible goodwill recorded at the investee level.

To the extent we have material transactions involving the application of this accounting policy, we provide additional disclosure specifying the impact on deferred income taxes as we did in 2014 related to the acquisitions of certain Jones Act tankers which was disclosed on page 94 of our

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2014 Form 10-K. We had no such significant transactions in 2015.

In future filings, we propose to clarify our accounting policy statement within our footnote on acquisitions, with disclosure substantially consistent with the following:

We apply a look through method of recording deferred income taxes on the outside book-tax basis differences in our investments. As a result, no deferred income taxes are recorded associated with non-deductible goodwill recorded at the investee level. we adjust goodwill as a result of applying the look-through method of recording deferred taxes on the outside book tax basis differences in our investments without regard to non-tax deductible goodwill.

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You indicate that you weighted the market and income approaches for Natural Gas Pipelines Regulated and Non-Regulated and your CO2 reporting units. Please tell us the relative weighting for each reporting unit and why you believe values indicated using the income approach are more representative of the value that could be received from a market participant at December 31, 2015.

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Please also tell us which reporting units would be impaired using a 100% market approach and a 50/50 weighting of income and market approaches. We may have further comment.

For our Natural Gas Pipelines - Regulated and Non-Regulated and our CO2 reporting units, we weighted the income approach 75% and the market approach 25%. The Natural Gas Pipelines Regulated and CO2 reporting units did not indicate an impairment at this weighting and neither reporting unit would have indicated an impairment if we had weighted the market approach at 50% or 100%.

While we believe the market approach can provide a good estimate of fair value, we have more precise and detailed levels of information regarding our own cash flow estimates and, therefore, we believe it is appropriate

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to weight these inputs more heavily. Given the triggering events possibly affecting our Natural Gas Pipelines - Regulated and Non-Regulated as well as our CO2 reporting units, we utilized our internal cash flow estimates of these respective reporting units which, in management’s judgment and experience, have a higher level of precision and historical accuracy. In our experience, market participants rely heavily on a target company’s cash flow estimates in valuing transactions, using market multiples primarily as a reasonableness check. For example, we disclosed that giving our CO2 reporting unit a 100% weighting to the market approach would have resulted in a higher reporting unit fair value as compared to the fair value that we determined as a result of our approach of weighting the market approach with the income approach.

For our Natural Gas Pipeline - Non-Regulated reporting unit, we determined the carrying value exceeded the fair value regardless of the weighting. Our weighting was based on management’s judgment with respect to how a market participant would value the reporting unit. We compared the implied enterprise value to the EBITDA multiple resulting from this valuation approach to the peer group market multiple and concluded it was reasonable as our reporting unit fair value of approximately 14x EBITDA was approximately 1.1 times the market indicated EBITDA multiple of 12.7x. This information was disclosed in Note 8. Goodwill on pages 106 and 107 of our 2015 Form 10-K allowing a reader to assess the reasonableness of management’s assumptions.

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Please tell us why the fair value allocation of your Natural Gas Pipeline-Non-Regulated reporting unit assumes such assets would be sold in a taxable transaction. In this regard, explain to us what the tax effects of selling this reporting unit in a taxable transaction would be to you and how this assumption is considered reasonable.

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Finally, tell us what the implied control premium is for your $17.2 billion valuation of this reporting unit and why it is reasonable control premium relative to recent comparable sales transactions.

The carrying value of our Natural Gas Pipeline Non-Regulated reporting unit includes an allocation of deferred income tax assets. In performing the Step 2 hypothetical fair value allocation, we did not allocate value to the net deferred income tax asset as we assumed it would not have any value to a market participant because we assumed the hypothetical sale of the reporting unit would be effected in a series of one or more taxable transactions.

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We assumed a taxable transaction for the following reasons: (i) a market participant would expect a step-up in basis for tax purposes (necessitating a taxable transaction); (ii) a market participant would be motivated to effect a taxable transaction to avoid using its stock as currency given the dilution that would be caused by depressed equity valuations; and/or(iii) the seller would be motivated to effect a taxable transaction in order to receive cash consideration. We further noted, based on a review of recent transactions in which we were involved as well as a review of other observable market transactions, that taxable transactions are very common in our industry. Based on our experience, market participants, in valuing transactions assume a full step up in tax basis because of the benefit to the tax paying C-corporation market participant or the benefit to the limited partners of a pass-through entity market participant. If there is no step up in tax basis, in our experience, the value of the transaction can be affected.

With respect to the Staff’s question on the control premium implied by the $17.2 billion valuation of our Natural Gas Pipeline - Non-Regulated reporting unit, this valuation reflected an implied EBITDA to enterprise value multiple of approximately 14x as compared to the market multiple of 12.7x, or 1.1 times greater than the market multiple. We did not use a control premium in deriving our estimate of fair values of our reporting units, but instead calculated estimates of enterprise value using the methodology described in our response to Question 9. We do not believe the 1.1 times ratio at the individual reporting unit valuation level should be compared to the control premium of 34%, which we disclosed in regards to our total equity value of our reporting units as compared to our market capitalization. We generally view the control premiums to be most relevant in the overall market capitalization reconciliation as these are equity values and not enterprise values.

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Please tell us where and how you have disclosed, for each class of assets and liabilities measured at fair value, a description of the valuation techniques and inputs used in making recurring and nonrecurring fair value measurements categorized within Level 2 and Level 3 of the fair value hierarchy. Refer to ASC 820-10-50-2bbb.

We disclose fair value measurement information related to Level 2 and 3 throughout the financial statement footnotes generally within the footnote which discusses the related asset or liability. Depending on the relative significance of the related asset or liability, we provide more or less detailed fair value disclosures.

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The following is a summary of the significant recurring and non-recurring fair value measures for which we made disclosures consistent with ASC 820-10-50-2bbb.

Derivative Financial Instruments and Debt - Recurring Fair Value Measures

Footnote 15, Fair Value on pages 129-131 of our 2015 Form 10-K provides disclosure of our fair value hierarchies and valuation techniques and inputs for our derivative financial instruments, including commodity, currency, and interest rate derivatives, as well as debt. These instruments are described more fully in our debt and risk management footnotes. We disclose the nature of the instruments which comprise the Level 2 and 3 asset and liability amounts, stating that the Level 2 instruments include debt and over-the-counter WTI swaps and options. We disclose that the Level 3 instrument is comprised of power derivative contracts. We disclose in a separate table on page 131 that our debt fair value disclosure is derived using Level 2 inputs. We further disclose on page 131 that, “the derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures.” While this disclosure is a high level summary, considering that the Level 2 and Level 3 assets and liabilities, other than debt, resulting from these recurring fair value measures comprise approximately 1% or less of our total assets and liabilities, we concluded this level of disclosure was appropriate. With respect to the debt fair value disclosure, we believe the standard industry methodologies and key inputs for valuing debt are well understood, and with the significant level of detailed disclosure in our debt footnote regarding our various debt instruments, a reader is able to understand the techniques and inputs used to generate this disclosure. The key unobservable inputs to our debt fair value, credit risk and market interest rates, are well understood and therefore, we did not believe was material to our disclosure. As facts and circumstances change and to the extent these measures become quantitatively or qualitatively more significant, we will consider revising our disclosure as appropriate.

Goodwill and Other Long-lived Assets - Nonrecurring Fair Value Measures

Footnote 4, Impairments and Disposals (pages 97-98) and Footnote 8, Goodwill (pages 105-107), describe in detail the valuation techniques and significant inputs to the fair value estimates made for purposes of the various impairment tests that were conducted. Both of these footnotes describe the fair value estimates as being based on Level 3 inputs. Because of the level of significance these measures had on our financial statements, we provided a significant level of disclosure regarding our key assumptions and inputs, including warning language describing conditions that could trigger additional future impairments.

Acquisitions and Divestitures - Nonrecurring Fair Value Measures

Footnote 3, Acquisitions and Divestitures (pages 94-96) provides disclosure regarding the allocation of our purchase price of various business combinations completed during the periods presented. Footnote 2, Summary of Significant Accounting Policies on page 90 provides a summary of how we determine the value of separately identifiable intangibles acquired in business combinations.

We did not provide more detailed disclosure of the valuation techniques and key inputs related to these acquisitions because we did not believe the information was material given the straightforward nature of these transactions and the acquired assets and liabilities. In future filings, to the extent we conclude the transactions involve valuation techniques that are not commonly used or understood or where a range of acceptable inputs is possible, we will augment this disclosure.

Employee Benefits - Recurring Fair Value Measures

Footnote 10, Share-based Compensation and Employee Benefits (pages 111-119) provides disclosure regarding the fair value estimates associated with assets of our pension and other postretirement benefit plans. We provide Level 2 and 3 tabular disclosure as well as explanations of our valuation techniques and key valuation inputs. The Level 3 assets are inconsequential. With respect to the Level 2 assets, we concluded the extent of our disclosure on valuation techniques and key inputs was sufficient as the valuation methodologies and key inputs are generally available and understood and there is not a wide range of alternatives that could yield a materially different result.

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We note the Compensation Committee exercised its discretion to award incentive compensation despite the company missing its financial performance objective target level. Please tell us why these amounts were reported as Non-Equity Incentive Plan Compensation pursuant to Item 402(c)(2)(vii), and not as Bonus compensation pursuant to Item 402(c)(2)(iv), as this compensation does not seem to be contingent upon the

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satisfaction of the performance target. In this regard, we note that the performance target was set at $2.00 per share in cash dividends but the company only distributed $1.605 per share. Please see Regulation S-K Compliance and Disclosure Interpretation 119.02 available on our website.

We acknowledge the Staff’s Regulation S-K Compliance and Disclosure Interpretation 119.02. We propose to include the amounts paid to the named executive officers for 2015 performance pursuant to the Annual Incentive Plan in the Bonus column in future Summary Compensation Tables and will apply this guidance in the future, as applicable.

Further, we acknowledge that:

•

Kinder Morgan, Inc.

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is responsible for the adequacy and accuracy of the disclosure in the filing;

Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

Kinder Morgan, Inc. may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

If any member of the Staff has any questions regarding the foregoing, or desires further information or clarification in connection therewith, please contact the undersigned at (713) 369-9470.

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We note your response to comment 4. In future reports, please include the analysis provided in your response regarding contract terms and the potential impact contract expirations may have on your results of operations, as we believe this provides investors with valuable insight into whether reported financial information is indicative of future operating results.

We acknowledge the Staff’s comment and, in future annual reports, we will include the additional analysis regarding our weighted average remaining contract life and the potential impact contract expirations may have on our results of operations. Read in the reply ↗

You discuss your results of operations primarily on a non-GAAP basis in MD&A and your earnings releases, which may be inconsistent with the updated Compliance and Disclosure Interpretations on Non-GAAP Financial Measures issued on May 17, 2016. Please review this guidance in its entirety when preparing your next earnings release.

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In addition, your revised disclosure suggests you view DCF as a performance measure but your discussion also suggests that it has value as a liquidity measure. Please supplementally clarify whether you view DCF as solely a performance measure and the reason(s) for your view.

We acknowledge the Staff’s comment and believe our most recent disclosures are consistent with the updated Compliance and Disclosure Interpretations issued on May 17, 2016 (“2016 C&DI”). Upon reviewing the 2016 C&DI, we made certain enhancements to our disclosures as reflected in our second quarter 2016 earnings release and in the MD&A in our June 30, 2016 Form 10Q.

In our second quarter 2016 earnings release, we preceded our presentation of non-GAAP measures with the most comparable GAAP measure, and in our discussion of the results for the respective periods, we provided explanations of

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the factors impacting both measures in a continuous discussion. The financial tables included in our earnings release present the GAAP measures before the non-GAAP measures. We believe we have provided equal or greater explanation of our GAAP measures as compared to our non-GAAP measures because, as further discussed below with respect to MD&A, we provide discussion of certain items affecting the GAAP measures followed by further explanation of the core operating drivers of our results that is equally relevant to both the GAAP and non-GAAP measures.

Item 303 of Regulation S-K requires disclosure of information relevant to assessing our results of operations to enable readers of our reports to see our company through the eyes of management. We believe our disclosure accomplishes this objective and is compliant with the related requirements. Importantly, we believe the content and format of our MD&A provide readers a thorough analysis of our results through the eyes of management, including a discussion of the effect of certain items on earnings for the period, as well as the primary drivers affecting our core operating results by segment.

Our approach to MD&A is to provide an integrated discussion of our results of operations incorporating both our GAAP and non-GAAP measures, thereby minimizing duplicative disclosure. In our June 30, 2016 Form 10-Q, we present our MD&A using a discussion that integrates our

GAAP and non-GAAP measures beginning with our Consolidated Earnings Results presented in accordance with GAAP. Under the heading Consolidated Earnings Results, we present segment EBDA, as disclosed in our reportable segment footnote in our consolidated financial statements, in a tabular format with corresponding numerical and percentage changes from period to period. The discussion of our consolidated earnings results is an overview of our results of operations, providing a summary of certain items that affected the GAAP results for segment operations and non-operational corporate items, for the respective periods, as well as the primary factors driving the remaining changes affecting our core operating results on a consolidated basis. A more detailed discussion of operating results is presented for each segment using segment EBDA and segment EBDA before certain items, to provide an integrated and iterative discussion of our results of operations.

For each segment, we explain certain items applicable only to segment EBDA and further discuss the remaining drivers affecting both segment EBDA and segment EBDA before certain items. By discussing the effect of certain items on segment EBDA, management is bringing to the readers’ attention matters that, in management’s judgment, are separable from the segment’s core operations in the period affected. We further discuss what, in management’s view, represents the core operating results, which are primarily driven by volumes, pricing, and contributions from newly placed-in-service assets, disposed of or acquired assets, and the related business activity for the segment. The significant changes from period to period for the respective GAAP line items are explained by a combination of the footnotes that follow the heading Certain items affecting Segment EBDA after each segment’s operating results table, as applicable, in combination with the subsequent tables presenting the remaining change driven by each specific operating asset. These tables are followed by additional narrative discussion explaining the business drivers of the reported changes, other than the certain items previously discussed. The entire discussion under each segment heading explains both the GAAP and non-GAAP measures in a manner that first explains certain items which affected the GAAP results, and then a further discussion of the factors driving both the GAAP and non-GAAP results. We believe this approach provides the reader full transparency in an integrated manner that is consistent with the way in which management evaluates the segments’ results. We take a similar approach with our expenses for general and administrative, interest, and noncontrolling interests.

We further acknowledge the Staff’s comment that our disclosure suggests that we view DCF as a performance measure, and confirm that our management team uses DCF solely as a measure of our performance in creating value for our common stockholders. We do not use DCF as a measure of the overall liquidity of the enterprise for the reasons explained below. In our weekly management review meetings, we measure the performance of our portfolio of assets by reviewing weekly updates to our forecast of DCF. It is a critical component of our management review process as a profitability and performance measure of our operating assets.

We believe DCF has historically been an accurate and useful measure of the profitability of our operating assets and is, therefore, our primary performance measure. We believe the most comparable GAAP measure to DCF is net income available to common stockholders (“net income”).

Typically, the largest recurring differences between our net income and our DCF are (1) net income is reduced by depreciation, depletion and amortization (“DD&A”), while DCF is, instead, reduced by sustaining capital expenditures and (2) net income is reduced by a provision for income taxes, while DCF is, instead, reduced by cash income taxes. In addition, we make adjustments to present the results of our equity method investments on this same basis and to adjust for certain items that, in management’s judgment, are separable from the core operations of our business. We replace DD&A with sustaining capital expenditures because we believe sustaining capital expenditures are more representative of the annual cash capital costs necessary to improve or extend the life of our existing assets than DD&A. We also believe that deducting cash income taxes for the period, rather than the provision for income taxes, is more representative of the net cash earnings for our company. DCF is readily reconcilable to net income and we believe is useful as a non-GAAP measure of profitability available our common stockholders. We believe DCF measures the profitability that is available our common stockholders which, at the discretion of our board of directors, could be returned to common stockholders in the form of dividends or share repurchases, or reinvested in the enterprise through acquisitions or expansion capital projects.

As the Staff is aware, liquidity measures quantify an enterprise’s ability to meet its financial obligations as they come due. Generally, liquidity measures are focused on short-term financial obligations. Commonly used liquidity measures include working capital/current ratio, quick ratio, cash ratio and various other working capital ratios. Solvency or leverage measures, such as debt/EBITDA and debt to total capital, quantify an enterprise’s ability to repay long-term debt. On the other hand, net income and EPS, which are focused on the common equity holders, are used in measuring corporate profitability and performance as well as investment valuation. Because our calculation of DCF, similar to net income, has been reduced by our non-discretionary obligations including interest, income taxes, as well as sustaining capital requirements, we do not believe DCF is a useful measure of our enterprise’s liquidity. Furthermore, because DCF is used by us and the investment community to evaluate the performance to the common equity holders as well as to measure the value of the common equity, it is more closely aligned with other corporate performance and investment valuation measures. A GAAP liquidity measure such as cash flow from operations is not closely comparable to DCF, and would involve significantly more reconciling items than are required to reconcile to net income. Such additional reconciling items would include changes in working capital, changes in certain other assets and liabilities, and other reconciling items.

We believe our current disclosures appropriately characterize our use of DCF as a performance measure and that our reconciliation to net income as the most comparable GAAP measure is appropriate. We propose, in future quarterly and annual reports, to further enhance the disclosure in our non-GAAP definitions in a manner substantially consistent with the following, providing readers with additional clarification regarding management’s view on the use of DCF.

Non-GAAP Measures

Our non-GAAP financial measures are DCF and Segment EBDA before certain items. 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 alternatives to GAAP net income available to common stockholders or any other GAAP measure. DCF 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 a substitute for an analysis of our results as reported under GAAP. Because DCF excludes some but not all items that affect net income available to common stockholders and because DCF measures are defined differently by different companies in our industry, our DCF 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 is a significant performance measure used by us and by external users of our financial statements to evaluate our performance and to measure and estimate the ability of our assets to generate cash earnings after servicing our debt and preferred stock dividends, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes, such as common stock dividends, stock repurchases, retirement of debt or expansion capital expenditures. Management uses this measure and believes it provides users of our financial statements a measure that more accurately reflects our business’ ability to generate cash earnings than a comparable GAAP measure. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. For a discussion of our anticipated dividends for 2016, see “Liquidity and Capital Resources-Common Dividends.”

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We note your response to comment 6 that costs of services are classified within “operating and maintenance” expense. Please tell us if these are the only costs captured within “operating and maintenance” expense.

Rest of the question

If not, please tell us the amount of these costs and explain to us in more detail why you believe that this presentation meets the requirement of Rule 5-03(b)(2) of Regulation S-X to separately disclose costs of services. Please also enhance your accounting policies footnote to clarify for investors where these costs are classified in your Statements of Income.

We acknowledge the Staff’s comment and confirm that all of the $2,337 million of costs within “Operations and maintenance” are costs of services, with the exception of approximately

$342 million of oil, gas, and carbon dioxide production costs associated with our CO2 segment for the year-ended December 31, 2015. Consistent with industry practice, oil and gas producers generally do not characterize the costs of oil and gas producing activities as cost of sales or cost of services, as the primary costs are DD&A and production costs.

Rest of the answer

In future annual reports, we propose to include disclosure in our accounting policies footnote substantially consistent with the following:

Cost of Sales

Cost of sales primarily includes the cost of energy commodities sold, including natural gas, NGL and other refined petroleum products, adjusted for the effects of our energy commodity derivative activities, as applicable, other than production from our CO2 segment.

Operations and Maintenance

Operations and maintenance include cost of services and is primarily comprised of (i) operational labor costs, and (ii) operations, maintenance and asset integrity, regulatory and environmental compliance costs, in addition to costs associated with our oil, gas and carbon dioxide producing activities of [________], for the years ended December 31, 20xx, 20xx, and 20xx, respectively.

If any member of the Staff has any questions regarding the foregoing, or desires further information or clarification in connection therewith, please contact the undersigned at (713) 369-9470.

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