Amplify Energy (AMPYW) CORRESP Correspondence with SEC

MEMORIAL PRODUCTION PARTNERS LP
1401 MCKINNEY, SUITE 1025
HOUSTON, TEXAS 77010

September 14, 2011

H. Roger Schwall
Assistant Director
U.S. Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E. Mail Stop 4628
Washington, D.C. 20549-3561

Re: Memorial Production Partners LP
Registration Statement on Form S-1
File No. 333-175090
Filed June 23, 2011

Dear Mr. Schwall:

     Set forth below are the responses of Memorial Production Partners LP, a Delaware limited partnership (“we” or the “Partnership”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the U.S. Securities and Exchange Commission (the “Commission”) by letter dated September 7, 2011 with respect to Amendment No. 1 (“Amendment No. 1”) to the Partnership’s Form S-1 initially filed with the Commission on June 23, 2011, File No. 333-175090 (the “Registration Statement”). Concurrently with the submission of this letter, we are filing through EDGAR Amendment No. 2 to the Registration Statement (“Amendment No. 2”). For your convenience, we have also hand delivered three copies of this letter, Amendment No. 2, and Amendment No. 2 marked to show all changes made since the initial filing of Amendment No. 1.

     Each response is prefaced by the exact text of the Staff’s corresponding comment in bold text. All references to page numbers and captions correspond to Amendment No. 2, unless otherwise indicated.

Amendment No. 1 to Registration Statement on Form S-1

General

1.	We remind you of prior comments 1 through 8, 10, 33, and 46 from our letter to you dated July 22, 2011.
	Response: We have complied or undertake to comply with each such prior comment. Specifically:

H. Roger Schwall
September 14, 2011
Page 2

• with respect to prior comment 3, we have filed Exhibits 3.3, 3.6, 8.1, 10.6, 10.7, 21.1, 23.8 and 23.9 with Amendment No. 2;

• with respect to prior comment 4, we have filed our artwork on the inside front cover of Amendment No. 2;

• with respect to prior comment 5, we undertake to provide updated disclosure with our next amendment;

• with respect to prior comment 10, we undertake to provide the Staff with all road show slides that are expected to be used in connection with our offering;

• with respect to prior comment 33, we have revised pages 106 and 107 of the Registration Statement to disclose the appropriate limitations and intend to file the form of credit agreement with our next amendment; and

• with respect to prior comment 46, we have filed the form of opinion to be included as Exhibit 8.1 with Amendment No. 2.

2.	We note your response to prior comment 17. Please explain the basis for your conclusions (1) you “carry appropriate levels of insurance;” and (2) your insurance policy and indemnification obligations does not pose any related material risks. Provide quantified information as part of your response.
	Response: We believe that the Partnership carries types and amounts of insurance appropriate for a company with its operations. Please see pages 146 and 147 of the Registration Statement, on which we disclose our levels of insurance coverage. Given this coverage, we believe that the only material insurance and indemnification-related risks that the Partnership faces are those that are faced by all operating companies: the risk that even appropriate amounts of insurance may be insufficient under certain circumstances.
3.	With a view towards disclosure, please provide us with a table that indicates what quarterly distributions would have been for the most recent four fiscal quarters, quantifying any shortfalls or explain to us why you are unable to do so. In that regard, we re-issue prior comments 19, 29, and 30.

Response: As a private company, our predecessor was not required to prepare quarterly financial information for all periods and we have not prepared quarterly financial information for all periods. In addition, a significant portion of the Partnership Properties were acquired during 2011 and we have not been provided by the sellers, and thus do not have access to quarter-by-quarter financial information with respect to those assets prior to our acquisition. Accordingly, we cannot and have not used or relied upon quarter-by-quarter financial information to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each quarter during those periods. Rather, we have based our determination whether we would have generated sufficient available cash to pay the minimum quarterly distribution for each quarter during the applicable period on financial information for the entire four quarter period. As a result, we are unable to provide the pro forma distribution amounts on a quarter-by-quarter basis.

H. Roger Schwall
September 14, 2011
Page 3

4.	You indicate in your response to prior comment 18 that you have provided additional information concerning “certain of the chemicals contained in such fluid” on page 144. However, we are unable to locate that disclosure. Please advise or revise.
	Response: We have previously supplementally provided the Staff with additional information concerning the certain chemicals used in the Partnership’s hydraulic fracturing fluid formulation. Please note that on page 145 of the Registration Statement, we disclose that “approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand.”

Our Cash Distribution Policy and Restrictions on Distributions, page 56

5.

We note your response to prior comment 28, which specifies how you calculated the $9.2 million of development costs for the year ended December 31, 2010. Please clarify how the $6.3 million of exploration costs disclosed on page F-65 impacted your calculation of pro forma cash available for distributions. To the extent that the $6.3 million of costs represents cash expenditures, tell us, why you have not reduced Estimated EBITDA when calculating your pro forma cash available for distribution. Please also provide an explanation of how exploration costs impact pro forma cash available for distribution of all other periods presented.

Response: While the $6.3 million of historical exploration and extension well costs set forth on page F-65 of the Registration Statement do represent cash expenditures, those costs do not impact our calculation of pro forma cash available for distributions during the year ended December 31, 2010 because those costs were not maintenance capital expenditures that the Partnership would have incurred.

     For purposes of determining our pro forma cash available for distributions, we start with pro forma net income, then adjust net income as described on pages 60 through 62 of the Registration Statement to determine our pro forma adjusted EBITDA for the period. Because substantially all of the exploration and extension well costs in question were capitalized (under the successful efforts method), those costs were not included in net income. Then, to determine pro forma cash available for distribution, we reduce the pro forma adjusted EBITDA by cash interest expense and the amount of maintenance capital that we estimate we will incur, which is $9.2 million.

     While our predecessor did expend the referenced $6.3 million of exploration costs, our predecessor managed the Partnership Properties under a strategy that included both development and exploratory activities — a different business strategy than we will employ as set forth on page 5 of the Registration Statement to maintain and grow a stable production profile through accretive acquisitions and low-risk development. We do not anticipate the Partnership incurring any material exploration costs, but rather expect to spend approximately $9.2 million per year on average on maintenance capital directed to low-risk exploitation activities

H. Roger Schwall
September 14, 2011
Page 4

expenditures. Accordingly, we believe that historical exploration costs are appropriately excluded from the calculation of pro forma cash available for distribution.

Predecessor Combined Balance Sheets, page F-20

Predecessor Combined Statements of Operations, page F-21

6.

We note your responses to prior comments 53 and 54, which indicate that the net cash proceeds to be paid to Memorial Resource at the time of the offering represent a portion of the consideration to be paid for the contribution of the Partnership Properties. However, we note that pro forma adjustment (c)(2) on page F-8 reflects a $140.5 million cash distribution to Memorial Resources which is appropriately recorded as a reduction to equity. We further note that SAB Topic 1B3 specifies that the presentation is appropriate even though the stated use of proceeds is other than for the payment of dividends. We reissue prior comments 53 and 54.

Response: With respect to prior comment 53, we have included a pro forma balance sheet as of June 30, 2011, the latest balance sheet of our predecessor, on page F-20 of the Registration Statement. Our predecessor’s pro forma balance sheet reflects the $140.5 million distribution to Memorial Resource Development LLC (“Memorial Resource”) accrual and corresponding reduction of equity related to the cash distribution expected to be made to Memorial Resource upon closing of the offering. Please also see page F-41 of the Registration Statement.

     With respect to the Staff’s prior comment 54, we respectfully submit that the pro forma per unit data contemplated within SAB Topic 1.B.3 is not applicable in the contemplated transactions. The predecessor historical combined financial statements are comprised of the following audited and unaudited results of: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), (ii) certain carved-out oil and natural gas properties of Classic Hydrocarbons Holdings, L.P. (“Classic”), and (iii) a 40% undivided interest in the oil and natural gas properties owned by WHT Energy Partners LLC (“WHT”). As a result, there is no historical equity class outstanding of our predecessor.

     Because our predecessor is a combination of the above referenced components, with two of the three components consisting of carve-out financial statements, we are unable to provide any per unit data related to the historical predecessor combined financial statements. Therefore, we do not believe a presentation of pro forma per unit data only giving effect to the number of units, the proceeds of which would be necessary to pay the $140.5 million, would be applicable. We have included disclosure regarding the proposed distribution of $140.5 million throughout the Registration Statement. For example, please see pages F-4, F-8, F-20 and F-41. We believe that a substantial portion of the distribution to Memorial Resource is a return of capital previously provided by Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore

H. Roger Schwall
September 14, 2011
Page 5

Holdings, L.P. that the predecessor utilized to acquire the underlying oil and gas properties and not a return on capital invested from earnings of the underlying properties.

Note 14 Supplemental Oil and Gas Information, page F-65

Oil and Natural Gas Reserves, page F-66

7.	Please provide, here or elsewhere in your filing, the disclosures required by Item 1203 of Regulation S-K.
	Response: We have revised the Registration Statement accordingly. Please see pages 140 and F-68 of the Registration Statement.

Engineering Comments

8.	Regarding our prior comment 62, you disclosed the number of wells you had drilled and completed as of December 31, 2010 as required by paragraph (a)(1)(2) of Item 1205 of Regulation S-K. However, you have not disclosed the number of wells that were currently drilling as of that date as required by paragraphs (a)(b)(c)(d) of Item 1206 of Regulation S-K. Please revise your document to include this information.
	Response: We have revised the Registration Statement accordingly. Please see page 143 of the Registration Statement.
9.	You state that your production decline rate is approximately 9% for 2011. However, we note that your production actually declined by approximately 11.5% per year in the first six months of 2011. Please revise your document to disclose this.
	Response: Our reserve reports that were prepared or audited by our third party engineers, Netherland, Sewell & Associates, Inc. (“NSAI”) and Miller and Lents, Ltd. (“Miller and Lents”), show a forecasted production decline of 9% for the Partnership’s proved developed producing reserves. The decline rate was calculated by taking our beginning of year 2011 forecasted daily production versus our end of year 2011 forecasted daily production.

H. Roger Schwall
September 14, 2011
Page 6

10.	We note in the reserve report numerous Cotton Valley wells that may have only produced a total of a few hundred barrels of NGLs to date since completion but have forecasts which indicate that they will produce in 2011 alone ten to twelve times the cumulative NGL production even though the gas production may be 70% depleted. We could not find anything in the filing that explains this large increase in NGLs from these wells. Please reconcile this or revise your document and reserves as necessary.
	Response: The cumulative NGL production since completion date referenced in the individual Cotton Valley reserve runs does not accurately reflect all NGL production to date, as we do not have access to the complete production history of NGLs for those assets because the prior owners of such assets have not provided us with such information. We do, however have historical data sufficient to make reasonable projections regarding future production. The reserve projections used, as prepared or audited by NSAI and Miller and Lents, are based on the multi year historical production trends for each well, which is illustrated with the following comparison of historical versus projected NGL volumes for the East Texas assets. On a pro forma basis, the Partnership Properties generated 270 MBbls of NGLs in the year ending 2010 (as set forth on page 140 of the Registration Statement). Of those 270 MBbls, our East Texas assets contributed 213 MBbls, or 79% of such NGL production, from multiple producing reservoirs, including the Cotton Valley. For the year ending 2011, we have projected 185 MBbls of NGLs to be produced from our East Texas assets on a pro forma basis (114.5 MBbls of NGLs were produced from those assets for the six months ended June 30, 2011 on a pro forma basis). Thus, our projected NGL production for the year ending 2011 represents only 87% of our pro forma NGL production for the prior year’s actual East Texas production.
11.	We note that all of your Cotton Valley proved undeveloped locations are operated by third parties. Many of these wells are not scheduled to be drilled for five years. Please provide to us the evidence you have from these third parties that they are planning to drill these wells at the time you have estimated in the reserve report.
	Response: All of our Cotton Valley proved undeveloped drilling locations are operated by Classic or WHT, each of which is a controlled subsidiary of Memorial Resource, and each other proved undeveloped drilling location in our reserve reports is also operated by a controlled subsidiary of Memorial Resource. Memorial Resource, as the sole voting owner of our general partner and a significant limited partner interest owner in the Partnership, intends to drill those wells at the time we have estimated in the reserve reports.
	Our reserve reports were prepared or audited by NSAI and Miller and Lents using generally accepted

H. Roger Schwall
September 14, 2011
Page 7

principles and methods promulgated by the Society of Petroleum Engineers (“SPE”) in the SPE 2007 Standards and as embodied by the petroleum engineering textbooks, as well as in accordance with applicable standards promulgated by the Commission. Our estimates of proved undeveloped reserves as of December 31, 2010 are based on estimates made or audited by our independent engineers, NSAI and Miller and Lents based on drilling and development programs provided by us and Memorial Resource (which is the sole voting owner of our general partner). Based on our current expectations of our cash flows and drilling and development programs, which includes drilling of proved undeveloped locations, we believe that we can fund the drilling of our current inventory of proved undeveloped locations and our expansions and extensions in the next five years from our cash flow from operations, additional equity capital and any credit facility we may enter into.

     None of our proved undeveloped reserves at December 31, 2010 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped.

12.	We note that you include 19 proved undeveloped horizontal wells in the Cotton Valley, and that you have reserve estimates of approximately 4 BCF of gas, 250,000 barrels of NGLs, and 30,000 barrels of oil. Please provide to us the basis of these estimates.
	Response: The reserve estimates, as prepared or audited by our third party engineers NSAI and Miller and Lents, for the proposed horizontal wells were supported by the review of 38 offset well locations from five separate operators that resulted in multiple offsets within several miles of each of the horizontal proved undeveloped wells. The more relative offset well projections (a total of 16 wells) were used to generate a type curve that projected an average estimated ultimate recovery, or EUR, of approximately 5 BCF. The type curve utilized was curtailed to a generally more conservative approximate 4 BCF EUR utilized under the scheduled horizontal proved undeveloped wells. Oil and NGL reserve projections were tied to the historical performance of the offsetting proved developed producing locations.
13.	We note that the well life of these 19 proved undeveloped wells in the Cotton Valley is approximately 55 years. We do not agree that the fact that the economic software program indicates that economic production will or can go on for fifty plus years means that it is reasonably certain it will do so. We believe, in relatively new developments or where new technology is being utilized, where no analogy exists for the estimated life of the producing wells, proved reserves should be limited to well lives that are more reasonably certain until such time the evidence for longer well lives is more compelling.
	Therefore, please revise your document to limit the proved reserves from the Haynesville Shale horizontal wells to well lives that are more reasonably certain based on what has been demonstrated historically. As these wells exhibit strong hyperbolic declines early in their production history, a shorter more reasonable well

H. Roger Schwall
September 14, 2011
Page 8

life will not necessarily reduce the reserves in the same proportion as the reduction in well life. Please revise your reserves and document accordingly.

Response: We acknowledge the Staff’s comment. The referenced 19 proved undeveloped wells are scheduled as horizontals in the Cotton Valley formation and are not relative to the Haynesville Shale. The Cotton Valley is a shallower formation located above the Haynesville Shale and has been in production in the Carthage Field since 1968. The Cotton Valley production is sourced from “conventional” hydrocarbon saturated sandstones, rather than “unconventional” shale like the Haynesville. The Cotton Valley formation consists of an array of widely developed and fairly homogeneous sands that typically have moderate porosity and low permeability and have therefore historically generated hyperbolic production trends with long economic lives. The exploitation of the Cotton Valley has expanded over recent decades with the advancement of horizontal drilling and fracture stimulation methods. These technologies have proven to deliver the same long life hyperbolic production trends, but with a multiple increase to the historical vertical well initial production rates, thereby generating multiples to the vertical well EURs as well. Much of this expanded development in the Cotton Valley was initiated during the product pricing increases of the late 1970’s and early 1980’s, and therefore, many of the currently producing Cotton Valley wells in this area have been active in excess of 25 years, with decades of economic life remaining.

H. Roger Schwall
September 14, 2011
Signature Page

     If you have any questions or comments concerning these responses, please call John A. Weinzierl, our President and Chief Executive Officer, at (713) 579-5710 or John Goodgame at Akin Gump Strauss Hauer & Feld LLP at (713) 220-8144.

Sincerely,
Memorial Production Partners LP
By:	Memorial Production Partners GP LLC, its general partner
By:	/s/  John A. Weinzierl
	John A. Weinzierl
	President and Chief Executive Officer

cc: John Goodgame, Akin Gump Strauss Hauer & Feld LLP
Douglas E. McWilliams, Vinson & Elkins L.L.P.
Christopher Ray, Natural Gas Partners