corresp

Goodrich Petroleum Corporation
808 Travis, Suite 1320
Houston, Texas 77002
(713) 780-9494
Fax (713) 780-9254

April 13, 2007

VIA EDGAR AND FAX

Division of Corporation Finance
Securities and Exchange Commission
450 Fifth Street, N.W., Mail Stop 7010
Washington, D.C. 20549


Attn:		Mr. H. Roger Schwall

Re:		Goodrich Petroleum Corporation
		Form 10-K for Fiscal Year Ended December 31, 2005
		Filed March 15, 2006
		Goodrich Petroleum Corporation
		Form 10-K for Fiscal Year Ended December 31, 2006
		Filed March 14, 2007
		File No. 1-12719
		Supplemental Response Filed February 2, 2007

Ladies and Gentlemen:

On behalf of Goodrich Petroleum Corporation (the “Company”), this letter sets forth the Company’s responses to the comments of the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) in its comment letter dated March 29, 2007 (the “Comment Letter”) with respect to the Company’s Annual Report on Form 10-K for the Year Ended December 31, 2005 and the Company’s Annual Report on Form 10-K for the Year Ended December 31, 2006. For your convenience, we have repeated in italics each comment of the Staff exactly as given in the Comment Letter and set forth below each such comment is the Company’s response.

Comment 1:

Form 10-K for the Fiscal Year Ended December 31, 2005

Goodrich Petroleum Corporation and Subsidiaries Notes to Consolidated Financial Statements, p. 52

NOTE N — Oil and Gas Producing Activities (Unaudited), page 66

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April 13, 2007
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Oil and Natural Gas Reserves, page 67

1. The projected production volumes for 2006 from your proved producing properties are significantly larger than the volumes produced in 2005 by the same properties. For these same properties, the projected operating expense in 2006, on a total and on a unit of production basis, is significantly lower than your expense incurred in 2005. Please explain to us the reasons for these differences. Include a spreadsheet comparison of the components of your projected and incurred expenses such as labor, power, non-recurring items, etc.

Response:

We believe the differences between our 2005 actual production volumes and costs and 2006 projected volumes and costs reflected in our reserve report are consistent with, and readily explained by, the results and impact of our expanded drilling and production program in the Cotton Valley Trend Area.

The 2005 Form 10-K showed 2005 net production of 8,685 mmcfe, while the reserve report as of December 31, 2005 showed a net production projection of 10,162 mmcfe for the proved producing reserves for the 2006 calendar year. The primary reason for the large increase in projected production volumes from proved producing reserves for fiscal year 2006 contained in the December 31, 2005 reserve report is that, due to our expanded drilling program, a number of our Cotton Valley trend wells had come on line during 2005 and had not produced for the entire year. During the calendar year of 2005, Goodrich added 50 wells mostly in the Cotton Valley trend area. Of the 50 wells, 68% were added in the last half of 2005. These second half wells significantly added to the production growth and the 2006 production projection.

The primary reason for the difference in costs between our actual 2005 results and our projected 2006 estimates is the expected mix of production volumes being more heavily weighted towards Cotton Valley trend volumes in 2006 versus 2005. For example, in 2005 approximately 55% of our total volumes came from South Louisiana, which is an area known for much higher operating costs than the Cotton Valley trend area of East Texas and Northwest Louisiana. Given that several of our south Louisiana fields are in areas where marshes and shallow inland waters are common, many of our costs in this region are much higher than normal land-based operations. In the year end 2005 reserve report, a greater percentage of 2006 production was expected to come from the Cotton Valley trend, which would have the impact of lowering overall unit costs for the company. In general, we have found it to be not uncommon that south Louisiana operating costs are as much as twice that of Cotton Valley costs (for example, $1.50 per mcfe in South Louisiana versus $0.75 per mcfe in the Cotton Valley trend). Thus, the blend of production alone accounts for the vast majority of the cost reductions, both on an absolute and a per unit of production basis. In addition, the 2006 operating expense forecast included expected cost reductions in the Cotton Valley trend resulting from economies of scale in certain of our fields related to salt water disposal costs and centralization of compression facilities. We had executed contracts in place by year end 2005 which had the impact of reducing a portion of our salt water disposal costs going forward from that time.

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April 13, 2007
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Given that the above items account for the vast majority of the cost differences between the two years, we respectfully submit that a detailed breakdown of our historical and projected costs by category is not necessary in explaining the differences.

Comment 2:

2. Your response to our January 19, 2007 comment 1(c)indicates that a down dip well may have depleted three proved undeveloped locations in a common fault block. Please explain to us the reasons that this well was not included in your analysis at the time of the original booking. Tell us whether these PUD locations’ estimated drainage area was restricted to your leasehold.

Response:

The 2004 reserve report included three undeveloped locations that were in separate fault blocks in Goodrich’s Plumb Bob Field. Goodrich owned the leases or options that covered the areas of these undeveloped locations at the time of the reserve report. Each of these PUD locations was up dip of a previously producing well in the same fault block that had presumably watered out in the target zone. The PUD locations were identified by using a 3D seismic survey that Goodrich had recently acquired and were booked on the assumption that wells within the fault block were principally water driven. The target horizon is typically a water drive reservoir. After the 2004 reserve report was finalized, Goodrich continued to work on many additional projects in the same field. Several months later additional data came to light which suggested that these plugged wells may have experienced primarily pressure drive depletion, with only a weak water drive support. This new information cast some doubt on the type of principal drive mechanism in these wells and therefore the three undeveloped locations were removed from the reserve report the following year.

Comment 3:

Form 10-K for the Fiscal Year Ended December 31, 2006

Goodrich Petroleum Corporation and Subsidiaries Notes to Consolidated Financial Statements, p. 57

NOTE 13 — Oil and Gas Producing Activities (Unaudited), page 76

Oil and Natural Gas Reserves, page 78

3. We note that your 2006 negative proved reserve revisions are 44% of the beginning proved reserves, your 2006 proved reserve additions constitute 68% of the beginning figures and your proved undeveloped reserves increased to 118 BCFE from 105. In the footnotes to your proved reserve disclosures, you state”...the primary cause of the revisions was the significant pricing difference between December 31, 2006 and December 31, 2005, which caused a number of our proved undeveloped locations in the Cotton Valley area to become uneconomic at the lower

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prices...” and “Extensions, discoveries, and other reserve additions were positive on an overall basis in 2006, primarily related to our continued drilling activities on existing and newly acquired properties in the Cotton Valley Trend of East Texas and North Louisiana.” Please clarify to us the basis for Cotton Valley PUD reserves as additions while previously booked Cotton Valley PUD reserves were revised downward. Include specific economic factors, such as well costs, operating expenses, etc., that you consider relevant.

Response:

We respectfully submit that the result of losing booked Cotton Valley PUD reserves as a result of pricing while at the same time adding new PUD reserves is wholly consistent with the results that should be expected from a very active drilling program measured at a point in time when pricing had declined from historical pricing.

At the time of the year-end 2005 reserve report we had drilled and completed approximately 60 wells in the Cotton Valley Trend; proved locations and reserve volumes were estimated using SEC definitions and standard industry practice. When the PUD locations offsetting these original approximately 60 wells were scrutinized at the higher operating costs, higher drilling costs which evolved during 2006, and lower prices existing at December 31, 2006, many of them became uneconomic, thus they were removed from our reserve books. Conversely, by year-end 2006 we had drilled and logged approximately 160 new wells in the Cotton Valley Trend and by that date had proven up additional portions of our acreage as economically viable, even under the lower pricing in effect at December 31, 2006. In conjunction with our independent reserve engineers, Netherland, Sewell and Associates, Inc., we identified approximately 270 PUD locations which were economically viable at December 31, 2006 given the capital costs, operating costs, and pricing in effect at that date and also a subset of our planned drilling program covering our East Texas acreage. Given our sizable acreage position, our high drilling activity in 2006, the relatively small drainage area of most of our Cotton Valley wells and the large change in cost/price outlooks between year-end 2005 and 2006, the removal of numerous PUD locations in one area was offset by the addition of PUD locations in another area which had higher reserves per well and favorable economics. However, there were some areas where performance was below expectation due to higher water production and increased lifting costs resulting in reserve reductions on existing wells. In some instances this resulted in the removal of offset PUD locations in more marginal areas.

Comment 4:

Website

4. Page 19 of your presentation, “March 15^th 2007 Bear Stearns Global Oil & Gas Conference Management Presentation” claims “YE2006 Proved Reserves at Current Prices” of 227 BCFE while you disclose 206 BCFE as your year-end proved reserves on page 78 of your current Form 10-K. Please amend the appropriate document(s) to eliminate this inconsistency.

Securities and Exchange Commission
April 13, 2007
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Response:

Consistent with Staff policy, we have not included any reserve estimates in any SEC filings other than proved reserves determined under FAS 69 and the SEC proved reserve definition. Our management, however, continues to believe that it is informative, if not material to, investors that the impact of pricing on proved reserve estimates be understood. The management presentation references “YE2006 Proved Reserves at Current Prices” because we believed it informative to investors to provide information about the impact of price changes on the Company’s proved reserves calculated at a price more in accordance with current market expectations, as opposed to the one day price required by FAS 69. The referenced quantity, 227 BCFE, was extracted from a supplemental year end reserve report run at a price of approximately $8.00 per mmbtu constant price case, a price more in line with more recent market expectations based upon the NYMEX twelve month average strip pricing. We respectfully submit that such alternative pricing scenarios have been, and will be, presented in a manner so that they are not to be confused with proved reserve volumes calculated at year end under FAS 69 and SEC defined principles. In this regard please note that, while we have, consistent with our policy, discontinued the publication of the referenced management presentation, future presentations and furnished disclosures of the Company containing any such alternative pricing presentations, will be made with a clarifying note substantially similar to the following:

“We have provided alternative proved reserve estimates in this report assuming natural gas prices other than those in effect on December 31, 2006 solely for illustrative purposes to demonstrate hypothetically the effect that year end economic conditions had on our proved reserve estimates. The natural gas prices used in these alternative presentations were selected by management based upon a review of the NYMEX forward pricing for natural gas contracts. Our ultimate recovery will be dependent upon numerous factors including actual geological conditions, the impact of future oil and gas pricing and exploration costs, and our future drilling decisions and budgets based upon our future evaluation of risks and returns and the availability of capital. The United States Securities and Exchange Commission (SEC) has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under economic and operating conditions existing at the date of the report. Accordingly, the SEC guidelines may prohibit us from including these alternatively priced proved reserve estimates in filings with the SEC.”

Closing Comments

Please respond to these comments within 10 business days or tell us when you will provide us with a response. Please furnish a letter with your amendment that keys your responses to our comments and provides any requested information. Detailed letters greatly facilitate our review. Please understand that we may have additional comments after reviewing your amendment and responses to our comments.

In connection with responding to our comments, please provide, in writing, a statement from the company acknowledging that:

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	•		the company 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

	•		the company 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.

In addition, please be advised that the Division of Enforcement has access to all information you provide to the staff of the Division of Corporation Finance in our review of your filing or in response to our comments on your filing.

Response:

In connection with the Staff comments and our responses, we confirm that (i) the Company is responsible for the adequacy and accuracy of the disclosure in the filing, and (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. We also acknowledge the Staff’s position that the Company 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.


	Very truly yours,

	/s/ David R. Looney

	David R. Looney Executive Vice President and Chief Financial Officer


CC:		James M. Prince
		Vinson & Elkins L.L.P.