EL Paso Pipeline Partners (EPB) CORRESP Correspondence with SEC

El Paso Pipeline Partners, L.P.

1001 Louisiana Street, Suite 1000

Houston, Texas 77002

May 15, 2013

VIA EDGAR

United States Securities and Exchange Commission
100 F Street, NE
Washington, D.C. 20549
Attention: Jennifer Thompson     Accounting Branch Chief

Re: El Paso Pipeline Partners, L.P.

Form 10-K for the year ended December 31, 2012

Filed February 26, 2013

Form 10-Q for the quarterly period ended March 31, 2013

Filed May 2, 2013

File No. 001-33825

Ladies and Gentlemen:

In this letter, we set forth our response to the comments contained in the letter from the Staff of the Division of Corporation Finance (the "Staff") of the Securities and Exchange Commission (the "Commission"), dated May 6, 2013, with respect to the above-referenced filings. For your convenience, we have repeated in bold type each comment exactly as set forth in the May 6 comment letter. Our response to each comment is set forth immediately below the text of the applicable comment.

Form 10-K for the year ended December 31, 2012

Item 1 and 2: Business and Properties, page 1

Outlook for 2013, page 1

1. We note your statement that you expect to declare cash dividends of $2.55 per unit for 2013, generate earnings before depreciation and amortization of $1.22 billion and produce excess cash flow of more than $25 million above the distribution target. Please explain to us in detail how your disclosures have complied with Items 10(b) and 10(e) of Regulation S-K. We believe that investor understanding of such projections would be enhanced by disclosure of the key assumptions and factors which in management's opinion are most significant to the projections and the susceptibility of such assumptions to change. If you wish to present similar projections in future filings, please show us your proposed revisions to your disclosures.

United States Securities and Exchange Commission

May 15, 2013

Page 2

Response: We operate interstate natural gas transportation and terminaling facilities characterized by stable, contracted cash flows. Since our base cash flows (cash flows not attributable to acquisitions or expansions) are relatively stable from year to year and are largely supported by firm transportation contracts under which shippers are charged reservation fees irrespective of volumes actually shipped, our forecast assumptions focus on factors affecting our base cash flow from year to year. As illustrated in the table on page 30 in Item 7 of our Form 10-K for the year ended December 31, 2012, 93% of our revenues in 2012 were “Reservation” revenues, meaning they are neither sensitive to the price of natural gas nor the amount of natural gas that moves through the system (2011 reservation revenues also comprised 93% of consolidated revenues). As further disclosed on page 30, the remaining weighted average contract term for our natural gas transportation and LNG contracts was approximately 8 years and 20 years, respectively, as of December 31, 2012.

Further, Kinder Morgan, Inc. (“Kinder Morgan”), our parent company and owner of our general partner, has a long history of operating and formulating annual forecasts for very similar assets. Kinder Morgan management’s experience with operating and forecasting for natural gas pipelines and terminaling facilities coupled with our stable cash flows along with our remaining average contract life provide reasonable basis to support a one year forecast for us.

The financial measures disclosed were determined to be of key importance to master limited partnership, or MLP, investors and are commonly referenced in our industry as such. We believe cash distributions per unit represents the most important financial measure for an investor since it represents actual cash expected to be distributed to each common unit held by an investor. The cash coverage above the distribution target indicates to investors the level of cushion we anticipate we will have to support our quarterly cash distributions. This measure can be used by investors as an indication of the magnitude of our distributable cash flow sensitivity. Earnings before DD&A (“EBDA”) is used as a measure to assess the operating performance of our assets and is useful for our investors because it allows investors to evaluate our operating results without regard to our financing methods or capital structure. Included in our quarterly and annual disclosures are reconciliations of our net income to distributable cash flow as well as EBDA to net income. As such, the readers are familiar with the key elements affecting these non-GAAP measures.

We believe our disclosure as presented in our Form 10-K for the year ended December 31, 2012 has complied with Items 10(b) and 10(e)of Regulation S-K, in all material respects. We will, however, make certain enhancements to our discussion on a prospective basis. We plan to augment our filings to include a more descriptive summary of what drives changes in our distributable cash flow from the prior year including appropriate commentary regarding the predictability of our distributable cash flows. This approach should provide further investor understanding of our projections and why we focus on the disclosed assumptions. Below is revised disclosure with changes indicated in bold italics substantially consistent with what we plan to include in future filings:

United States Securities and Exchange Commission

May 15, 2013

Page 3

Outlook for 2013

We expect to declare cash distributions of $2.55 per unit for 2013, a 13% increase over our 2012 distributions of $2.25 per unit. Our base cash flows (cash flows not attributable to acquisitions or expansions) are relatively stable from year to year and are largely supported by reservation charges under firm transportation contracts. Therefore, we expect our growth from 2012 to 2013 to be mainly driven by acquisitions and expansion projects.

Our 2013 budget includes the expected acquisition of 50% of Gulf LNG Energy LLC from KMI in the third quarter of 2013, a full year contribution from our 2012 acquisitions from El Paso, and a growth project on the Elba Express Pipeline expected to commence operations during the second quarter of 2013. In 2013, we expect to generate earnings before depreciation and amortization (EBDA) of $1.22 billion (adding back our share of joint venture depreciation and amortization). We expect to produce excess cash flow of more than $25 million above the 2013 distribution target of $2.55 per unit.

Item 6. Selected Financial Data, page 28

2. Please explain to us why the amounts disclosed for "Per unit cash distributions declared during the period" do not agree to the amounts in the "Per unit Cash Distribution Declared" line item presented on your income statements. Consistent with your disclosure on page 93, it appears the selected financial data figures might represent the per unit cash distribution paid during the period. Please revise future filings as necessary.

Response: The amounts disclosed in each table are correct. They may appear to be inconsistent because we use different wording in the two tables to describe the amounts. We acknowledge this could be unnecessarily confusing and will revise future filings to more clearly distinguish between distributions declared for the period and distributions paid in or declared in/during the period. Distributions for each quarter are declared and paid in the subsequent quarter, creating a difference between the amount declared for a particular quarter or year and the amount declared and paid in a particular quarter or year. In future filings we will use “declared” only to refer to distributions “declared for” the period and cease using the phrase “declared during”. We will use “paid in” to refer to the period in which distributions are declared and paid so that the only phrases used to describe the distributions will be “declared for” and “paid in”. We will change the description on the income statement to “Per Unit Cash Distribution Declared For the Period”. In addition, we will revise the table on page 28 to show both the “Per unit cash distributions declared for the period” and the “Per unit cash distributions paid in the period” separately. Please see the changes to the table on page 28 shown below in bold italics:

United States Securities and Exchange Commission

May 15, 2013

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	As of or for the Year Ended December 31,
	2012		2011		2010		2009		2008
	(In Millions, Except Per Unit Amounts)
Operating Results Data:
Revenues	$	1,515	$	1,531	$	1,454	$	1,231	$	1,173
Operating income	863		849		819		656		605
Net income	589		605		666		542		507
Net income attributable to El Paso Pipeline Partners, L.P.	579		512		418		357		333
Net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit-basic and diluted:         Common units	2.15		2.03		1.90		1.64		1.26
Subordinated units(1)	—		—		1.78		1.56		1.12
Per unit cash distributions declared for the period(2)	2.25		1.93		1.63		1.36		1.20
Per unit cash distributions paidin the period (2)	2.14		1.87		1.55		1.33		1.01
Balance Sheet Data (at end of period):
Property, plant and equipment, net	$	5,931	$	6,040	$	6,051	$	5,781	$	5,182
Total assets	6,581		6,679		6,569		6,565		6,034
Long-term debt and other financing obligations, less current maturities	4,246		4,028		3,580		2,732		2,478

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(1) All subordinated units were converted into common units on a one-for-one basis effective January 3, 2011. See Note 8 to our consolidated financial statements included elsewhere in this report for further information.

(2) Distributions for the fourth quarter of each year are declared and paid in the first quarter of the following year.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, page 29

Results of Operations, page 32

3. We note that your Results of Operations narrative prominently discusses your results in terms of Non-GAAP financial measures and does not provide sufficient analysis of the changes in certain line items, such as revenues and operation and maintenance expenses, computed in accordance with GAAP and presented on the face of your financial statements. Please revise your discussion and analysis to provide presentation with equal or greater prominence of financial measures presented in accordance with GAAP. Refer to Item 10(e)(1)(i)(A) of Regulation S-K. In doing so, please also provide a narrative discussion of the extent to which material changes in revenues are attributable to changes in prices or to changes in volumes.

Response: We acknowledge the requirement in Regulation S-K Item 10(e)(1)(i)(A) that our presentation of non-GAAP financial measures must include a presentation, with equal or greater prominence, of the most directly comparable financial measure or measures calculated and presented in accordance with GAAP. We believe our disclosure as presented in our Form 10-K for the year ended December 31, 2012 complies with this requirement, in all material respects, as well as the requirements of Regulation S-K Item 303. We will, however, make

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May 15, 2013

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certain enhancements in future filings to our discussion and analysis to further increase the prominence of the GAAP measures presented on the face of our financial statements and clarify the relationship of such GAAP measures to the non-GAAP measures that we believe are integral to our investors’ understanding of our business and financial position. We propose to provide this enhanced disclosure on a prospective basis in future filings.

Basis for Current Presentation

Our objective is to provide information that in our judgment is appropriate to provide the reader an understanding of the results of our operations on the same basis as used by our management. Based on the nature of our energy infrastructure fee-based operations and limited partnership structure, we believe it is most useful to our readers to describe the results of our operations using a net non-GAAP measure that also includes a prominent discussion of the related GAAP measure in such a manner that the reader is able to discern the corresponding changes in the GAAP measures.

Pursuant to our limited partnership agreement, we are required to distribute 100% of our available cash to our partners. As such, the most important performance metric is distributable cash flow and EBDA. Our approach is to discuss our results of operations in the context of these measures, while at the same time providing the variances in terms of GAAP measures. This allows the reader to understand the fluctuations in the Non-GAAP measures while at the same time understanding how the corresponding GAAP measure was affected.

Current Presentation with Enhanced Disclosure

The following language contains excerpts from our existing discussion and analysis illustrating how we give prominence to the variations in our GAAP measures from period to period, provided within the context of our discussion of the impact on our net earnings and cash flow. This presentation provides the reader with a transparent understanding of our results of operations both in terms of our GAAP and non-GAAP measures, without unnecessary repetition. We believe the reader is provided a more detailed and better understanding of our results of operations using this approach, as compared to if we focused solely on material changes in our GAAP measures.

We would propose to include in future filings language substantially consistent with the following to increase the prominence and clarify the relationship of the GAAP measures presented on the face of our financial statements to the non-GAAP measures that we believe are integral to our investors’ understanding of our business and financial position. The bold italicized language indicates areas of enhanced future disclosure which we believe will provide further clarity with respect to relevant GAAP measures.

Earnings Results

We previously reported earnings before interest expense and income taxes as our segment performance measure. As a result of KMI’s acquisition of El Paso, management now assesses our segment performance based on EBDA, which excludes depreciation and amortization, general and administrative expenses and interest expense, net. Certain general and administrative expenses have been

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May 15, 2013

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excluded from EBDA such as employee benefits, legal, information technology and other costs that are not controllable by operating management and thus are not included in the measure of performance for which they are accountable. Our management uses EBDA as a measure to assess the operating results and effectiveness of our assets, which consists of both consolidated operations and earnings from equity method investments. We believe providing EBDA to our investors is useful because it is the same measure used by management to evaluate our segment performance and allows investors to evaluate our operating results without regard to our financing methods or capital structure. 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 or operating cash flows.

Below are the components of EBDA for the annual periods presented (in millions):

	2012			2011			2010
Revenues	$	1,515		$	1,531		$	1,454
Operating Expenses
Operation and maintenance	(389		)	(419		)	(398		)
General and administrative expenses	139			132			128
Operation and maintenance, excluding general and administrative expenses	(250		)	(287		)	(270		)
Taxes, other than income taxes	(82		)	(83		)	(72		)
Operating Expenses	(332		)	(370		)	(342		)
Earnings from equity investments	14			15			16
Other income, net	5			8			32
EBDA	$	1,202		$	1,184		$	1,160

United States Securities and Exchange Commission

May 15, 2013

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Below is a reconciliation of our EBDA to net income attributable to EPB, our throughput volumes and an analysis and discussion of our operating results for the annual periods presented (in millions, except operating statistics):

	2012			2011			2010
EBDA(1)(2)(3)(4)	$	1,202		$	1,184		$	1,160
Depreciation and amortization (5)	(181		)	(180		)	(165		)
General and administrative expenses(6)	(139		)	(132		)	(128		)
Interest and debt expense, net (7)	(293		)	(267		)	(199		)
Income tax expense	—			—			(2		)
Net income	589			605			666
Net income attributable to noncontrolling interests	(10		)	(93		)	(248		)
Net income attributable to EPB	$	579		$	512		$	418
Throughput volumes (BBtu/d)(8)	7,864			7,364			7,694

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(1) 2012 includes a $27 million increase in EBDA for certain items as follows:

• $34 million of pre-acquisition EBDA related to CPG,

• $11 million charge to operating expenses attributable to a canceled software implementation project,

• $6 million non-cash adjustmentreducing operating expenses for environmental liabilities associated with certain CIG environmental projects, and

• $2 million of additional operating expenses for the amortization of regulatory assets associated with the SNG offshore asset sale.

(2) 2011 includes a $99 million increase in EBDA for certain items as follows:

• $85 million of pre-acquisition EBDA related to CPG,

• $17 million of revenue resulting from BG LNG’s cancellation of its commitment to Phase B of SLNG’s Elba III Expansion, and

• $3 million charge to operating expenses for the write-off of project development costs incurred in conjunction with the aforementioned Elba Express expansion project.

(3) 2010 includes a $72 million increase in EBDA for certain items as follows:

• $93 million of pre-acquisition EBDA related to CPG, and

• $21 million non-cash write down to operating expensesresulting from a FERC order related to the 2009 sale of the CIG Natural Buttes facilities (compressor station and gas processing plant).

(4) 2012, 2011 and 2010 includes within Other income, net $3 million, $7 million and $28 million, respectively, of an allowance for equity funds used during construction.

(5) Includes pre-acquisition depreciation and amortization expense for CPG of $5 million in 2012 and $12 million for each of 2011 and 2010.

(6) Includes certain items as follows:

• pre-acquisition general and administrative expenses for CPG of $3 million in 2012 and $8 million for each of 2011 and 2010, and

• non-cash severance costs of $34 million in 2012 allocated to us from El Paso as a result of KMI’s acquisition of El Paso; however, we do not have any obligation nor did we pay any amounts related to this expense.

(7) Includes pre-acquisition interest and debt expense, net for CPG of $4 million, $11 million and $12 million in 2012, 2011 and 2010, respectively.

(8) Throughput volumes are presented for WIC, CIG, SNG and CPG and exclude intrasegment volumes. The average daily volumes transported on Elba Express during 2012, 2011 and 2010 were not material.

United States Securities and Exchange Commission

May 15, 2013

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Combined, the certain items described in footnotes (1) through (3) to the table above decreased our EBDA by $72 million in 2012, and increased our EBDA by $27 million in 2011, when compared with the respective prior year. In addition, the certain items described in footnotes (1) through (3) to the table above accounted for an $84 million decrease in revenues in 2012 versus 2011, and $13 million of higher revenues in 2011 versus 2010, respectively. Following is information related to the remaining (i) $90 million increase and $3 million decrease in EBDA and (ii) $68 million and $64 million increase in revenues in 2012 and 2011, when compared with the respective prior year.

Year Ended December 31, 2012 versus Year Ended December 31, 2011

	EBDA		Revenues
	increase/(decrease) (in millions)
CPG	$	51	$	62
SNG	26		21
Other	13		(15)
Total EPB	$	90	$	68

• The CPG acquisition contributed $51 million of incremental EBDA for the year ended December 31, 2012 (reflecting CPG’s EBDA results for the May 25 to December 31, 2012 post-acquisition period). See Note 3 to our consolidated financial statements included elsewhere in this report for additional information regarding the acquisition of CPG;

• SNG contributed higher EBDA of $26 million primarily due to the completion of Phases II and III of the South System III expansion project in June 2011 and June 2012;

• CIG, included in Other, contributed additional EBDA of $6 million in 2012 as compared to 2011 largely due to favorable property tax adjustments of $4 million during 2012, lower pipeline maintenance, payroll and contractor costs of $10 million, which impacted operating expenses, and increased reservation revenue of $7 million related to an expansion project placed in service in October 2011. Partially offsetting these favorable impacts were lower transportation revenues of $15 million primarily resulting from the non renewal of expiring contracts, the restructuring of certain contracts at lower volumes or discounted rates and lower usage and interruptible revenues due to milder weather; and

• WIC, included in Other, contributed additional EBDA of $4 million in 2012 as compared to 2011 primarily due to higher operating expenses related to compressor station repairs performed in 2011.

United States Securities and Exchange Commission

May 15, 2013

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Year Ended December 31, 2011 versus Year Ended December 31, 2010

	EBDA			Revenues
	increase/(decrease) (in millions)
SNG	$	3		$	15
WIC	(5		)	12
SLNG	7			25
Other	(8		)	12
Total EPB	$	(3	)	$	64

• SNG contributed higher EBDA of $3 million. Our EBDA was favorably impacted by $23 million due to the completion of Phases I and II of the South System III expansion project in January and June 2011. Partially offsetting this favorable impact were lower transportation revenues of $14 million primarily resulting from the restructuring of certain contracts at lower volumes or discounted rates and lower usage and interruptible revenues due to milder weather. EBDA was further burdened by $6 million due to higher operating expenses during 2011 as compared to 2010 primarily due to an unfavorable gas balance revaluation resulting from lower prices and higher retained volumes and the elimination of their fuel sharing mechanism;

• CIG's EBDA, included in Other, decreased by $8 million in 2011 as compared to 2010. Our transportation revenue was $9 million lower due to nonrenewal of expiring contracts, restructuring of certain contracts at lower volumes or discounted rates and lower usage and interruptible revenues due to milder weather. Our EBDA was further burdened by $8 million of higher operating expensesfor pipeline maintenance, contractor costs and property taxes. Partially offsetting these unfavorable EBDA impacts were $9 million of expansion projects placed in service in 2010;

• WIC's EBDA decreased by $5 million in 2011 as compared to 2010. Our EBDA was unfavorably impacted by $9 million due to nonrenewal of expiring contracts, higher third party capacity commitments and unfavorable gas balance revaluations. Additionally, our EBDA was lower by $3 million primarily due to higher contractor costs for maintenance and equipment repairs. Partially offsetting these unfavorable EBDA impacts were $8 millionof expansion projects placed in service in 2010; and

• SLNG contributed higher EBDA of $7 million. Our EBDA was favorably impacted by $11 million due to the completion of the Elba III Phase A Expansion project in 2010, partially offset by $4 million of higher operating expenses for contractor costs due to maintenance and repairs.

United States Securities and Exchange Commission

May 15, 2013

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Further, we note in your comment a suggestion for us to include a narrative discussion of the extent to which material changes in revenue are attributable to changes in prices or to changes in volume. As discussed above in our response to comment number 1, our revenues are largely supported by firm transportation contracts under which shippers are charged reservation fees irrespective of volumes actually shipped. These reservation revenues are neither sensitive to the price of natural gas nor the amount of natural gas transported through our pipeline systems. Given the substantial relevance of our reservation fee-based contracts to our results of operations, we believe the most significant drivers to changes in our revenues is our ability to expand our system infrastructure (adding incremental net margin through acquisitions or expansion projects) and renew expiring long-term contracts. Where applicable, we have disclosed the impact of these matters in our Results of Operations discussion.

Consolidated Statements of Income, page 67

4. Please explain to us your basis in GAAP for excluding the $34 million severance charge from your Limited Partners' Net Income per Unit computations. In doing so, tell us further information about the nature of the charge, including how the allocated amount was derived.

Response: The severance expense relates to cash severance payments made by Kinder Morgan to certain former El Paso employees following Kinder Morgan’s acquisition of El Paso in May 2012. Kinder Morgan accounted for these payments as a one-time termination benefit based on the guidance in ASC 420-10. Amounts paid under this one-time termination benefit arrangement were determined using a formula based on length of service and salary.

As disclosed in our filings, we have no employees and consequently were not party to the one-time termination benefit arrangement described above. Nor were we obligated to reimburse our general partner for payments made under the arrangement. However, many of our general partner’s employees provide services to us or for our benefit. Consequently, we concluded that it was appropriate to reflect a portion of the related severance expense in our financial statements based on an analogy to ASC 718-10-15-4 and the guidance in SAB Topic 5T. On this basis, we recognized severance expense in our statement of operations with an offsetting increase to our general partner’s capital account. The amount of severance cost allocated to us was determined based on a combination of specific identification (those terminated employees who devoted all or substantially all of their time to EPB) and by using of the same allocation model that our general partner and its parent, El Paso Corporation, used to allocate normal compensation-related costs prior to the merger with Kinder Morgan.

We next evaluated how the expense of this one-time termination benefit should be allocated for purposes of calculating earnings per unit. We concluded the full amount of severance expense should be allocated to the general partner, who also holds our incentive distribution rights. As discussed above, our general partner entered into the severance agreement with its employees; we (EPB) were not party to the arrangement and were under no obligation to (and did not) reimburse our general partner. As a result, our general partner bore the entire economic cost of this arrangement and therefore was allocated the entire amount of the expense.

United States Securities and Exchange Commission

May 15, 2013

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Finally, we considered how a cost incurred by a non common equity interest holder and recognized in a subsidiary’s separate financial statements pursuant to SAB Topic 5T should be treated for purposes of calculating common equity earnings per share – or in our case limited partner earnings per unit. We believe GAAP does not address this specific fact pattern, and as a result requires the use of judgment. Because our general partner interest and our incentive distribution rights are considered participating securities, we considered the guidance in ASC 260 and concluded that allocation of the severance expense to the general partner was appropriate. Specifically, our general partner had the contractual obligation to absorb one hundred percent of the severance costs without reimbursement from EPB and our limited partners. In addition, the payment of severance costs put us and our general partner in the same economic position had we paid the costs ourselves and our general partner agreed to receive a correspondingly lower distribution – which in turn would have resulted in the same amount of earnings allocated to the limited partners under the ASC 260 guidance.

Note 6. Debt, page 83

5. We note your statement in the last risk factor on page 14 that applicable law and contractual restrictions, including restrictions in certain of your subsidiaries' credit facilities and the rights of certain creditors of your subsidiaries that would often be superior to your interests, may negatively impact your ability to obtain distributions from your subsidiaries. Please explain to us how you considered the guidance in Item 4-08(e) of Regulation S-X and the need to provide Schedule I as discussed in Rule 5-04(c) of Regulation S-X. In your response, please describe the contractual restrictions and tell us the percentage of consolidated net assets that are restricted.

Response: We considered the guidance in Item 4-08(e) of Regulation S-X and the need to provide Schedule I as discussed in Rule 5-04(c) of Regulation S-X and determined our disclosure is appropriate and sufficient. Our restricted assets, which are comprised solely of our equity in the undistributed earnings of our unconsolidated equity investments, represent less than 1% of our consolidated net assets as of December 31, 2012. We routinely receive distributions of available cash from our consolidated subsidiaries and equity method investees. We disclosed on page 85 in our debt footnote, “…there are no significant restrictions on EPPOC’s or EPB’s ability to access the net assets or cash flows related to its controlling interests in the operating companies either through dividend or loan.” We have also disclosed the most restrictive covenants of EPPOC and each subsidiary on that page.

The EPPOC credit agreement, of which WIC is also a borrower, does have a restricted payment clause preventing cash distributions in certain events. However, the restricted payment clause includes an exception for cash payments among EPB, EPPOC and its subsidiaries. Therefore, this provision does not provide for restrictions on distributions between EPB, EPPOC, and our subsidiaries even in the event the restricted payment clause of the credit agreement is triggered.

Senior notes at CIG and SNG contain provisions which would potentially restrict cash distributions resulting from a sale of all or substantially all of their assets. Since we control the ability to sell or retain these assets, our creditors do not have any effective rights under this provision. Other than that clause, there are no provisions which could restrict distributions to EPPOC under the CIG or SNG indentures.

United States Securities and Exchange Commission

May 15, 2013

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SLNG’s senior notes have restricted payment provisions which, under certain circumstances, could lead to a restriction of payments to EPPOC. These triggering events include: (i) the occurrence and continuation of certain customary events of default, including SLNG’s failure to make payments under the senior notes when due, SLNG becoming insolvent, and SLNG defaulting in the payment of other material indebtedness, (ii) termination of the Phase IIIA Terminal Service Agreement, (iii) a force majeure event which occurs and lasts for at least 30 days and results in a reduction of payments to SLNG, and (iv) if SLNG demands or receives payment from established credit support due to a breach under certain specified terminal service agreements. SLNG is in compliance with its covenants and has not experienced any of the above circumstances since these senior notes were originally sold in 2009. Accordingly, at the time of EPB’s 10-K filing, SLNG was not subject to distribution restrictions.

Our equity method investments include WYCO Development LLC, which is 50% owned by our wholly owned subsidiary CIG, and Bear Creek Storage Company, L.L.C., which is 50% owned by our wholly owned subsidiary SNG. As of December 31, 2012, our proportionate share of undistributed earnings in these equity investees was approximately $5 million, representing our sole restricted asset amount. Our equity investees generally distribute to us in cash our proportionate share of their net income before depreciation and amortization, less sustaining capital expenditures within the subsequent quarter. Therefore, our proportionate share of undistributed earnings is the result of timing differences.

In summary, at the time of EPB’s 10-K filing, there were no significant restrictions on EPPOC’s or EPB’s ability to access the net assets or cash flows related to its controlling interests in the operating companies or related to its equity method investees either through dividend or loan. The disclosure requirements in Item 4-08(e) of Regulation S-X and the Schedule I requirements contemplated by Rule 5-04(c) of Regulation S-X are not required since the percentage of our restricted assets to consolidated net assets as of December 31, 2012 was substantially less than the 25% threshold specified in Regulation S-X. In future filings we will make reference in our risk factor disclosure to the debt footnote in our financial statements, which contains further disclosure as to the nature of potential restrictions.

United States Securities and Exchange Commission

May 15, 2013

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Form 10-Q for the quarterly period ended March 31, 2013

Notes to Consolidated Financial Statements, page 9

Note 8. Litigation, Environmental and Other Contingencies, page 13

Other Commitments, page 15

6. We note your disclosure that you formed ELC to develop and own a natural gas liquefaction plant. You disclose that you own 51% of the membership interest and that you account for this investment by the equity method. Please explain to us in more detail why you account for this investment using the equity method despite your 51% ownership interest.

Response: In connection with the January 2013 formation of ELC in which we and Shell have ownership interests of 51% and 49%, respectively, the parties entered into an LLC agreement (the “LLC Agreement”) and several related transaction agreements. Based on these agreements and the guidance in ASC 810, we believe that our 51% ownership interest does not constitute a controlling financial interest in ELC due to certain key decisions requiring joint approval by the members which preclude us from exercising control over the entity despite our 51% ownership interest. The rights of the minority interest holder include substantive participating rights granted to the minority interest holder per the LLC Agreement, including, but not limited to, the right to joint control over (a) the selection and termination of the officers of ELC that are responsible for the implementation of its policies and procedures, and (b) the establishment of the operating and capital decisions of ELC, including approval of annual operating and capital budgets, that are made in the ordinary course of its business. The minority interest holder’s rights are generally exercised through equal board representation and supermajority voting rights such that we could not impose our decisions on significant matters without Shell’s consent. Further, the related transaction agreements do not contain any substantive provisions that would otherwise give us the power to control ELC’s significant economic activities. Accordingly, we concluded that we should not consolidate ELC but instead should account for our investment in ELC using the equity method based on our ability to exert significant influence over, but not control of, ELC.

Further, we acknowledge that:

• El Paso Pipeline Partners, L.P. is responsible for the adequacy and accuracy of the disclosure in the filings;

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

• El Paso Pipeline Partners, L.P. 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.

United States Securities and Exchange Commission

May 15, 2013

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If any member of the Commission's Staff has any questions regarding the foregoing, or desires further information or clarification in connection therewith, please contact the undersigned at (713) 369-9895.

Very truly yours,El Paso Pipeline Partners, L.P.

By:    El Paso Pipeline GP Company, L.L.C.

its general partner

By:    /s/ David P. Michels            David P. Michels    Chief Financial Officer