Eagle Rock Energy Partners L P CORRESP Correspondence with SEC

Via EDGAR

February 25, 2014

Brad Skinner

Senior Assistant Chief Accountant

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549-3561

Re:	Eagle Rock Energy Partners, L.P.
	Form 10-K for Fiscal Year Ended
	December 31, 2012
	Filed March 1, 2013
	File No. 001-33016

Ladies and Gentlemen:

Set forth below are the supplemental responses of Eagle Rock Energy Partners, L.P. (the “Partnership”) in response to a telephonic conversation with the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) on February 21, 2014, with respect to the Staff’s additional comments to the Partnership’s Annual Report on Form 10-K for Fiscal Year Ended December 31, 2012, File No. 001-33016, filed with the Commission on March 1, 2013 (the “2012 10-K”).

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Form 10-K for Fiscal Year Ended December 31, 2012

Reconciliation of Adjusted EBITDA to net cash flows from operating activities and net income (loss), page 61

1. We note your response to prior comment number 5 from our letter dated December 20, 2013. Provide us, as supplemental information, an analysis which compares your original and alternative methods of accounting for commodity hedge costs and which clearly explains why there is a difference in reported net income (loss) under the two methods. As part of your response, provide a complete set of example journal entries and account balances (T accounts) under each method.

SUPPLEMENTAL RESPONSE:

As presented in our prior responses dated January 10, 2014 and February 18, 2014, we believe that the Partnership’s accounting for its commodity hedge costs appropriately matched the revenues and expenses related to the transactions in the relevant periods, and that the differences between our accounting methodology and the alternative treatment to amortize the costs as part of marking the position to market were not material. We elected to change public accounting firms in 2011, and therefore contacted Deloitte & Touche LLP (“Deloitte”), our independent registered public accounting firm for the years ended December 31, 2009 and 2010 periods, regarding this matter. Deloitte indicated that it would not be able to respond as to materiality in a timely manner.

We note that Deloitte agreed with the original accounting methodology at the time the hedge costs were incurred and recorded. We further reiterate our previous arguments, both quantitative and qualitative, below in support of our belief that the differences are not material.

Accordingly, we respectfully propose that no change be made to the presentation of commodity hedge costs for the years ended December 31, 2009 and 2010 (the only years presented in which the Partnership incurred such costs) in the Selected Financial Data within our Annual Report on Form 10-K for the year ended December 31, 2013 (our “2013 10-K”).

Quantitative Support:

($ in thousands)	Net Income (Loss) Original			Net Income (Loss) Alternative			Difference
2008	$	87,520		$	81,619		$	(5,901	)
2009	$	(171,258	)	$	(160,231	)	$	11,027
2010	$	(5,349	)	$	(1,392	)	$	3,957

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Qualitative Support:

1. Changes in earnings or trends were not masked. For two of the periods presented, the net loss we reported was actually greater.

2. The alternate methodology would not have moved the Partnership from a net income to a net loss position or vice versa.

3. While the reported net income / (loss) is different between the two methods, there would be no change to several of the Partnership’s key non-GAAP financial measures, including Adjusted EBITDA, distributable cash flow and distribution coverage ratio, as the differences result from non-cash items which are excluded as part of these calculations.

4. The Partnership’s compliance with its loan covenants or other contractual requirements was not impacted.

5. The amount of hedge cost amortization does not impact any of the goals by which management’s compensation is determined.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves, page F-50

2. We have read your response to prior comment 10 in the letter dated December 20, 2013 and do not concur with your conclusion that the determination of the estimates of your oil and gas reserve quantities and associated future net cash flows should give effect to the revenue derived by the sale of sulfur extracted to make your gas saleable. Sulfur is not a hydrocarbon and therefore does not represent a “saleable hydrocarbon” as defined in Rule 4-10(a)(16) of Regulation S-X. The cost to remove the sulfur is part of the cost of producing the oil and gas and must be included; however, the revenue derived from the sale of non-hydrocarbons should not be included in the determination of economic producibility per Rule 4-10(a)(10) of Regulation S-X or in the computation of future cash flows which relates specifically to the future cash flows from the entity’s proved oil and gas reserves per FASB ASC paragraph 932-235-50-31. We re-issue our prior comment 10.

SUPPLEMENTAL RESPONSE:

As a supplement to our response provided to the Staff on February 18, 2013, we offer the following additional information:

In order to determine the impact of removing sulfur revenues on our reported proved reserves as of January 1, 2011, December 31, 2011 and December 31, 2012, we used the archived versions of our reserve databases for those periods. We changed the assumed sulfur price and sulfur price deductions to zero and re-ran the databases with all other parameters

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unchanged. After excluding the sulfur revenues, certain cases reached the end of their economic life sooner than they did in the original runs, and their reserves were accordingly reduced. The reserves of all other cases in the databases were unchanged. The changes in our total reserve balances from removing sulfur revenues are as follows:

Proved Reserves	Oil (MBbls)		Gas (MMcf)		Natural Gas Liquids (MBbls)
January 1, 2011
As Reported	8,696		38,382		6,176
Excluding Sulfur Revenues	8,695		38,161		6,136
Difference	0.0	%	(0.6	)%	(0.6	)%
December 31, 2011
As Reported	11,522		234,022		11,347
Excluding Sulfur Revenues	11,184		232,498		11,167
Difference	(2.9	)%	(0.7	)%	(1.6	)%
December 31, 2012
As Reported	12,984		194,429		12,866
Excluding Sulfur Revenues	12,767		191,443		12,733
Difference	(1.7	)%	(1.5	)%	(1.0	)%

We consider the differences in the prior year reserve amounts to be insignificant and propose to present the 2011 and 2012 reserves in the 2013 Form 10-K as unchanged from the balances as reported in the 2012 Form 10-K. As discussed in our previous responses, we will update the 2013 year-end reserve balances to reflect the impact of removing sulfur revenues. Per your request, we have discussed this matter with our current independent registered public accounting firm and as this information is unaudited and does not impact the audited financial statements, they did not object to the presentation.

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We plan to present the Standardized Measure for all periods shown in the 2013 Form 10-K excluding the impact of sulfur revenues, with additional commentary and quantitative disclosure to explain the change in presentation from prior years. Annex A to this letter presents our proposed Standardized Measure disclosure for the 2013 Form 10-K in its entirety.

* * * * *

In connection with the Staff’s comments and our responses, we confirm that (i) the Partnership is responsible for the adequacy and accuracy of the disclosure in the filing, (ii) the 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 (iii) the Partnership 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.

Please direct any questions that you have with respect to the foregoing and any request for additional supplemental information to Douglas E. McWilliams of Vinson & Elkins L.L.P. at (713) 758-3613.

	Very truly yours,

	EAGLE ROCK ENERGY PARTNERS, L.P.

	By: Eagle Rock Energy GP, L.P., its general partner

	By: Eagle Rock Energy G&P, LLC, its general partner


	By:	/s/ Jeffrey P. Wood
	Name:	Jeffrey P. Wood
	Title:	Senior Vice President and Chief Financial Officer

Enclosures

cc: Jennifer O’Brien (Securities and Exchange Commission)

John Hodgin (Securities and Exchange Commission)

Charles C. Boettcher (Eagle Rock Energy Partners, L.P.)

Douglas E. McWilliams (Vinson & Elkins L.L.P.)

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Annex A: Proposed Standardized Measure Disclosure for 2013 Form 10-K

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following information has been developed utilizing authoritative guidance procedures and is based on oil and natural gas reserves estimated by the Partnership’s independent reserves engineer. It can be used for some comparisons, but should not be the only method used to evaluate the Partnership or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Partnership.

The Partnership believes that the following factors should be taken into account when reviewing the following information:

· future costs and selling prices will probably differ from those required to be used in these calculations;

· due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and

· a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues.

Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes were computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows were reduced to present value amounts by applying a 10% discount factor.

The Partnership’s hydrocarbon reserves in Alabama and East Texas contain hydrogen sulfide that must be removed from the natural gas stream before the hydrocarbons are sold. As part of the process to remove the hydrogen sulfide, the Partnership produces and sells elemental sulfur. The Partnership generated revenue from the sale of sulfur of $8.1 million, $14.0 million and $17.8 million in 2013, 2012 and 2011, respectively. The cost of removing the sulfur is included in the future production costs in the Standardized Measure table below. In prior years, the Partnership included the expected revenues from the sale of sulfur as part of the Standardized Measure computation. The Partnership changed that practice in 2013 and now includes only the

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sale of hydrocarbons in the computation. The Standardized Measure presented as of December 31, 2012 and 2011 in the following table has been adjusted to reflect this change in methodology. No reserve volumes have been booked for sulfur, and the impact of sulfur revenues on the economic limit of reserves in prior years is considered immaterial.

The Standardized Measure is as follows as of December 31, 2013, 2012 and 2011:

($ in thousands)	As of December 31, 2013			As of December 31, 2012			As of December 31, 2011
				As Adjusted			As Adjusted
Future cash inflows	$	2,423,350		$	2,279,735		$	2,516,812
Future production costs	(737,468		)	(767,004		)	(845,530		)
Future development costs	(318,778		)	(354,690		)	(315,019		)
Future net cash flows before income taxes	1,367,104			1,158,041			1,356,263
Future income tax (expense) benefit	(1,212		)	(1,086		)	(1,831		)
Future net cash flows before 10% discount	1,365,892			1,156,955			1,354,432
10% annual discount for estimated timing of cash flows	(715,386		)	(621,826		)	(711,846		)
Total standardized measure of discounted future net cash flows	$	650,506		$	535,129		$	642,586

The tables below present the Partnership’s previously-disclosed SMOG values, the revised values (which exclude sulfur revenues), and the differences between them for years ending December 31, 2012 and 2011. The differences between the two sets of values are most pronounced in the future cash inflows and future production costs. The change in future cash inflows is due to a shortening of the economic life of certain properties when sulfur revenues are excluded. The change in future production costs is the result of the exclusion of sulfur revenues, which were historically shown as an offset to the cost to transport and market the sulfur. In some prior years, the cost to transport and market the sulfur exceeded the total sulfur revenues, resulting in a net cost. In other prior years, sulfur revenues exceeded the cost to transport and market the sulfur, resulting in net positive cash flows. In order to maintain consistency across periods and to show only hydrocarbon revenues as future cash inflows, the Partnership reported the net impact from the sale of sulfur in all periods within future production costs.

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The following summarizes the revisions to the Standardized Measure for fiscal years 2012 and 2011 resulting from the removal of sulfur revenues:

	As of December 31, 2012
($ in thousands)	As Reported			Revisions			As Adjusted

Future cash inflows	$	2,315,266		$	(35,531	)	$	2,279,735
Future production costs	(669,896		)	(97,108		)	(767,004		)
Future development costs	(359,154		)	4,464			(354,690		)
Future net cash flows before income taxes	1,286,216			(128,175		)	1,158,041
Future income tax (expense) benefit	(1,321		)	235			(1,086		)
Future net cash flows before 10% discount	1,284,895			(127,940		)	1,156,955
10% annual discount for estimated timing of cash flows	(680,855		)	59,029			(621,826		)
Total standardized measure of discounted future net cash flows	$	604,040		$	(68,911	)	$	535,129

	As of December 31, 2011
($ in thousands)	As Reported			Revisions			As Adjusted

Future cash inflows	$	2,562,650		$	(45,838	)	$	2,516,812
Future production costs	(742,749		)	(102,781		)	(845,530		)
Future development costs	(317,405		)	2,386			(315,019		)
Future net cash flows before income taxes	1,502,496			(146,233		)	1,356,263
Future income tax (expense) benefit	(2,379		)	548			(1,831		)
Future net cash flows before 10% discount	1,500,117			(145,685		)	1,354,432
10% annual discount for estimated timing of cash flows	(778,520		)	66,674			(711,846		)
Total standardized measure of discounted future net cash flows	$	721,597		$	(79,011	)	$	642,586

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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership’s proved oil and natural gas reserves for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
($ in thousands)	2013			2012			2011
				As Adjusted			As Adjusted
Beginning of year	$	535,129		$	642,586		$	284,687
Sale of oil and gas produced, net of production costs	(150,457		)	(132,451		)	(138,860		)
Net changes in prices and production costs	2,720			(78,247		)	143,023
Extensions, discoveries and improved recovery, less related costs	136,464			66,460			40,832
Previously estimated development costs incurred during the period	21,470			53,111			90,418
Net changes in future development costs	107,951			36,914			(119,121		)
Revisions of previous quantity estimates	(103,351		)	(76,434		)	(34,497		)
Purchases of property	—			2,811			324,652
Sales of property	—			(5,063		)	—
Accretion of discount	49,233			60,734			26,225
Net changes in income taxes	(36		)	317			(519		)
Other	51,383			(35,609		)	25,746
End of year	$	650,506		$	535,129		$	642,586

The following summarizes the revisions to the changes in the Standardized Measure for fiscal years 2012 and 2011 resulting from the Partnership’s decision to remove sulfur revenues from the Standardized Measure computation:

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	Year Ended December 31, 2012
($ in thousands)	As Reported			Revisions			As Adjusted

Beginning of year	$	721,597		$	(79,011	)	$	642,586
Sale of oil and gas produced, net of production costs	(132,451		)	—			(132,451		)
Net changes in prices and production costs	(76,759		)	(1,488		)	(78,247		)
Extensions, discoveries and improved recovery, less related costs	66,460			—			66,460
Previously estimated development costs incurred during the period	53,111			—			53,111
Net changes in future development costs	36,503			411			36,914
Revisions of previous quantity estimates	(85,176		)	8,742			(76,434		)
Purchases of property	2,811			—			2,811
Sales of property	(5,063		)	—			(5,063		)
Accretion of discount	67,956			(7,222		)	60,734
Net changes in income taxes	564			(247		)	317
Other	(45,513		)	9,904			(35,609		)
End of year	$	604,040		$	(68,911	)	$	535,129

	Year Ended December 31, 2011
($ in thousands)	As Reported			Revisions			As Adjusted

Beginning of year	$	333,993		$	(49,306	)	$	284,687
Sale of oil and gas produced, net of production costs	(138,860		)	—			(138,860		)
Net changes in prices and production costs	170,917			(27,894		)	143,023
Extensions, discoveries and improved recovery, less related costs	40,832			—			40,832
Previously estimated development costs incurred during the period	90,418			—			90,418
Net changes in future development costs	(117,783		)	(1,338		)	(119,121		)
Revisions of previous quantity estimates	(26,447		)	(8,050		)	(34,497		)
Purchases of property	324,652			—			324,652
Accretion of discount	30,728			(4,503		)	26,225
Net changes in income taxes	(621		)	102			(519		)
Other	13,768			11,978			25,746
End of year	$	721,597		$	(79,011	)	$	642,586

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Eagle Rock Energy Partners L P (EROC) Inactive CORRESPCorrespondence with SEC