January 12, 2007

Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549-7010

Re: Comment Letter Dated December 13, 2006

Form 10-K for Fiscal Year Ended December 31, 2005, Filed March 15, 2006

File No. 1-32647

Ladies and Gentlemen,

Set forth below are the responses of ATP Oil & Gas Corporation (“we,” or the “Company”) to the comments of the staff of the Securities and Exchange Commission (the “Staff”) in the comment letter of the Staff dated December 13, 2006. For your convenience, the comments provided by the Staff have been included before the response in the order presented in the comment letter. We do not believe that these items, individually or in the aggregate, are sufficiently material in substance to warrant filing an amendment to our Annual Report on Form 10-K for the year ended December 31, 2005 (as amended, “2005 Form 10-K”). Therefore, with your approval, we propose incorporating these changes and clarifications in our Annual Report on Form 10-K for the year ended December 31, 2006 (“2006 Form 10-K”), the due date for which is March 1, 2007, and future filings. In several of our responses below, we describe where we will address the comments in our 2006 Form 10-K by referring to the corresponding portions of our 2005 Form 10-K.

General

1. Please correct the Commission File Number indicated on the cover of your annual report to be 001-32647 which took effect with your filing of the Form 8-A12B on October 14, 2005.

Response: On January 25, 2001, we registered on Form 8-A under the Securities Exchange Act of 1934 (the "Exchange Act") our class of common stock pursuant to Section 12(g) and were assigned on that date Commission File Number 000-32261. Since that date, we have affixed that file number to every filing we have made pursuant to the Exchange Act. On October 14, 2005, we were assigned Commission File Number 001-32647 when we registered on Form 8-A under the Exchange Act our class of common stock purchase rights pursuant to Section 12(b), which attached to our outstanding shares of common stock but expire, at the latest, on October 17, 2015. It is our understanding that the file number assigned to the October 14, 2005 Form 8-A relates only to the common stock purchase rights and, thus, would expire at the same time as our common stock purchase rights. We will use the file number you have directed in all future filings if, after your review of this response, you continue to believe the use of the file number associated with the registration of our common stock is incorrect.

Engineering Comments

Business

Securities and Exchange Commission

January 12, 2007

General, page 6

2. Please disclose the percentage of your proved reserves that are classified as developed producing, developed non-producing and undeveloped.

Response: We supplementally advise that of our total proved reserves at December 31, 2005, 46.3 MMcfe (9%) were producing, 82.1 MMcfe (15%) were developed and not producing and 399.1 MMcfe (76%) were undeveloped. We will include comparable disclosures in our 2006 Form 10-K. All of the foregoing amounts and percentages, except those for the split between developed producing and developed non-producing, are either set forth or are calculable from the data included in the “Supplemental Information About Oil and Gas Producing Activities” in our 2005 Form 10-K.

Risk Factors, page 12

3. Please include a risk factor that cites the percent of total reserves that are classified as undeveloped reserves. Explain how this fact may impact your future results if the reserves are not developed, or not developed in a timely manner. Also address the risks that future prices of oil and gas decline materially, and that future production from your properties turns out to be materially different from the reserve estimates you disclose.

Response: The first risk factor of our 2005 Form 10-K states: “Our actual development results are likely to differ from our estimates of our proved reserves. We may experience production that is less than estimated and development costs that are greater than estimated in our reserve reports. Such differences may be material.” We propose to add to that risk factor in our 2006 Form 10-K the following:

“Additionally, approximately [    ]% of our total proved reserves are undeveloped. Development of these reserves may not yield the expected results, or the development may be delayed or the development costs may exceed our estimates, any of which may materially affect our financial position and results of operations.”

We supplementally advise that at December 31, 2005, the blank in the first sentence above was 76%, which amount is determinable from the “Supplemental Information About Oil and Gas Producing Activities” in our 2005 Form 10-K. We will include comparable disclosures in our 2006 Form 10-K.

We note that you requested risk factors addressing the risk of future oil and gas price declines and addressing the risk of future production that is materially different from our reserve estimates. We believe that our risk factor entitled, “Oil and natural gas prices are volatile, and low prices have had in the past and could have in the future a material adverse impact on our business” on page 15, and our first risk factor, entitled “Our actual development results are likely to differ from our estimates of our proved reserves. We may experience production that is less than estimated and development costs that are greater than estimated in our reserve reports. Such differences may be material,” on page 12, as modified above, address the specific risks to which you referred.

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Securities and Exchange Commission

January 12, 2007

Properties, page 19

4. Please comply with Instruction 3 to Item 102 of Regulation S-K, requiring disclosure of material information about your properties, including net production, reserves, development, nature of your interest, and other material information on your individual oil and gas properties or fields.

Response: We supplementally advise you of the following additional information on our most significant properties as of December 31, 2005:

Field	Development Location	Net Total Proved Reserves MMcfe	2005 Net Production MMcfe	Average WI%	Expected First Production
Mississippi Canyon 711	GOM	93,070	0	100.0	2006
Tors	N. Sea	72,871	0	85.0	2006
Cheviot	N. Sea	182,282	0	100.0	2009
King’s Peak	GOM	55,713	1,438	55.0	Producing
Wenlock	N. Sea	26,322	0	100.0	2007

We will include a comparable table in our 2006 Form 10-K and future filings.

Oil and Gas Reserves, page 21

5. It would be helpful to include the definition of proved reserves, as found in Rule 4-10(a) of Regulation S-X, to provide context for your discussions of reserve estimates.

Response: We will add to our 2006 Form 10-K as the first sentence in this section the following reference to the definitions section of the report:

“References below to various classifications of oil and natural gas reserves have the meaning set forth under the caption ‘Certain Definitions’ at the front of this report.”

Acreage, page 23

6. Please identify alongside your table the amount of undeveloped acreage that is expiring in each of the next three years, if material.

Response: We supplementally advise you of the following proposed introductory language and table, which enhances disclosure in the current table summarizing our acreage holdings as of December 31, 2005:

The terms of leases on undeveloped acreage are scheduled to expire as shown in the table below. The term of a lease may be extended by drilling and production operations.

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Securities and Exchange Commission

January 12, 2007

Year Ended December 31:	Gulf of Mexico		North Sea		Total
	Gross	Net	Gross	Net	Gross	Net
2006	5,000	3,350	—	—	5,000	3,350
2007	3,488	3,488	48,436	45,115	51,924	48,603
2008	22,088	22,088	—	—	22,088	22,088
2009 & Beyond	67,487	64,045	43,622	42,841	111,109	106,886
Total	98,063	92,971	92,058	87,956	190,121	180,927

We will include comparable disclosures in our 2006 Form 10-K and future filings.

Management’s Discussion and Analysis, page 28

Results of Operations, page 32

7. We note that you report average oil prices of $41.92 per barrel in 2005. Please reconcile for us this price with the average price for WTI in 2005 of approximately $56.47.

Response: During 2005, we sold 474 MBbls or 75% of our oil and condensate production under fixed forward contracts. Most of those contracts (383 MBbls) were entered into during 2004 when average oil prices were much lower than 2005. The fixed price sales reduced our overall realization on total oil and condensate volumes produced relative to the prevailing market prices by an average of $9.95 per barrel (before subtracting for pricing adjustments, including basis and quality differentials that are discussed below). Almost all of our unhedged oil and condensate sales contracts are based on the Koch Equal Daily Quantity (EDQ) WTI Crude Oil posting, adjusted for Platt’s P+ (a published common pricing adjustment). All of our oil and condensate sales were adjusted further for basis differentials (proximity to sales points), quality (presence of sulphur and other contaminants) and any applicable handling charges.

The impact of the pricing adjustments mentioned above resulted in a net decrease in our oil realizations of $1.20 per barrel. Our relatively lower gas plant liquids sales prices (net of processing costs) tended to reduce our overall realization by an additional $0.94 per barrel. We have removed that impact in the analysis below, because the liquids are priced differently from crude oil.

The reconciliation that follows sets forth the production-weighted price realization, excluding the effects of gas plant liquids, hedging and price adjustments discussed above:

Reported net average realized sale price	$	41.92
Remove the effect of gas plant liquids		0.94
Net average realized oil and condensate sale price		42.86
Add back net effects of fixed forward contracts (1)		9.95
Add back net impact of pricing adjustments, including basis differentials and quality adjustments		1.20
Net realized market price excluding the effects of liquids, hedging and price adjustments	$	54.01

(1) Fixed forward sales qualify for the normal purchase and sale exemption under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and are therefore reported in oil and condensate revenues before the effects of cash flow hedges.

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Securities and Exchange Commission

January 12, 2007

The WTI price for 2005 of $56.47 referenced in your question appears to be a simple average NYMEX price for the year. This will not correlate with our realized price excluding the effects of gas plant liquids, hedging and price adjustments. The Koch EDQ posting is a daily average, where the NYMEX price of $56.47 is an average price based on a single day from the end of each month in 2005. Due to timing and market conditions, the Koch EDQ and the NYMEX can vary significantly in any given month. Additionally, our unhedged production subject to prevailing market conditions occurred in the early part of the year when the market prices were lower, resulting in unhedged realizations that were lower than the calendar average. Due to the shut-ins associated with the hurricanes late in 2005, we had no unhedged production in the fourth quarter which would have allowed us to seize upon the higher prices experienced after the storms in 2005. These timing differences explain the remaining variance between our average net realized market price (excluding the effects of liquids, hedging and price adjustments) and the referenced average NYMEX price of $56.47.

Financial Statements

Supplemental Information About Oil and Gas Producing Activities, page F-29

8. You indicate that in 2005 you spent $69.2 million on the acquisition of proved properties. You also indicate that in 2005 you purchased 17,775 MBO and 78,502 MMcf of reserves. As this calculates to $2.25 per BOE, please provide us with the technical justification for classifying these reserve estimates as proved.

Response: The reserve quantities you referenced in your question referred to the effects of extensions and discoveries, not to purchases of proved reserves. Proved property acquisition costs during 2005 were $69.2 million, and the reserves acquired during 2005 totaled 107,220 MMcfe (104,598 MMcf plus 437 MBbl) for an average acquisition cost of $0.65 per Mcfe.

A significant portion of the reserves we acquired were proved undeveloped, and as such require significant future development expenditures. We expect to incur approximately $143.5 million in development costs, and ultimately approximately $41.3 million in abandonment costs, bringing the aggregate cost of these acquired reserves to approximately $254.0 million, or roughly $2.37 per Mcfe ($14.22 per equivalent barrel). Our independent reservoir engineers have attributed proved reserves to these acquired properties because they each meet the SEC definition of proved reserves due to the presence of current production or a conclusive formation test. We believe, with reasonable certainty, that these reserves will be recoverable in future years under economic and operating conditions existing as of December 31, 2005, and we intended to develop these reserves as of that date.

9. We note that in presenting details of the Standardized Measure on page F-30, you indicate future operating costs to be $1.00 per Mcfe. Please reconcile this with the operating costs that you report for 2005 on page 33 of $1.19 per Mcfe.

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Securities and Exchange Commission

January 12, 2007

Response: The most significant factor affecting our future operating cost per unit of production is our anticipated increase in production relative to our anticipated increase in operating costs. The growth in our producing reserve base should allow us to produce at a lower cost on a per-unit basis as a result of the fixed vs. variable cost components. The anticipated impact on our average operating cost per unit of production is summarized in the table below:

	U.S.		N. Sea		Total
2005 Actual
Operating costs - $000	21,624		2,005		23,629
Production – MMcfe	18,659		1,255		19,914
Per unit – $/Mcfe	1.16		1.60		1.19
Future Years
Operating costs - $000 (1)	218,912		326,468		545,380
Production (reserves) – MMcfe	232,031		295,467		527,498
Per unit - $/Mcfe	0.94		1.10		1.03
Increase (Decrease)
Operating costs - $000	197,288		324,463		521,751
Production – MMcfe	213,372		294,212		507,584
Per unit - $/Mcfe	(0.22	)	(0.50	)	(0.16	)

(1) Future operating costs are estimated based on current actual operating costs and operating conditions as of December 31, 2005.

As you requested, we acknowledge:

• The management of ATP Oil and Gas Corporation is responsible for the adequacy and accuracy of the disclosures in its public filings;

• Staff comments or changes to disclosures in response to staff comments do not foreclose the Commission from taking any action with respect to a filing;

• ATP may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

If you have any questions or comments, please call me at 713-403-5514.

Sincerely,

ATP Oil & Gas Corporation

/s/ Albert L. Reese, Jr.

Albert L. Reese, Jr.

Chief Financial Officer

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