November 18, 2010
Securities and Exchange Commission
Division of Corporation Finance
Mail Stop 7010
100 F Street, N.E.
Washington, D.C. 20549-7010
| Re: | ATP Oil & Gas Corporation |
Comment Letter Dated November 5, 2010
Registration Statement on Form S-4; File Number 333-169880, filed October 12, 2010
(the “Registration Statement”)
Ladies and Gentlemen,
Set forth below are the responses of ATP Oil & Gas Corporation (“we,” “ATP” 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 November 5, 2010. For your convenience, the comments provided by the Staff have been included before the response in the order presented in the comment letter.
General
| 1. | We will not accelerate the effectiveness of your registration statement until you resolve all comments on your Exchange Act filings. |
Response: We do not anticipate requesting acceleration until your comments to our Exchange Act filings have been resolved.
| 2. | In light of recent events involving the Gulf of Mexico, please review your disclosure to ensure that you have disclosed all material information regarding your potential liability in the event that one of the rigs operating on your property is involved in an explosion or similar event in any of your offshore locations. For example, and without limitation, please address the following: |
| • | Disclose the applicable policy limits related to your insurance coverage; |
| • | Disclose your related indemnification obligations and those of your rig operators, if applicable; |
| • | Disclose whether your existing insurance would cover any claims made against you by or on behalf of individuals who are not your employees in the event of personal injury or death, and whether the rig operator would be obligated to indemnify you against any such claims; |
| • | Clarify your insurance coverage with respect to any liability related to any resulting negative environmental effects; and |
ATP Oil & Gas Corporation | 4600 Post Oak Place | Suite 200 | Houston, TX 77027 | www.atpog.com |
Securities and Exchange Commission
Response to Comment Letter Dated November 5, 2010
| • | Provide further detail on the risks for which you are insured for your offshore operations. |
Response: We maintain insurance to protect the Company and its subsidiaries against losses arising out of our oil and gas operations. Our insurance includes coverage for physical damage to our offshore properties, general (third party) liability, workers compensation and employers liability, seepage and pollution and other risks. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. Additionally, our insurance is subject to the terms, conditions and exclusions of such policies. For losses emanating from offshore operations, ATP has up to an aggregate of $2.1 billion of various insurance coverages with individual policy limits ranging from $1.0 million to over $500 million each. While we maintain insurance levels, deductibles and retentions that we believe are prudent and responsible, there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.
In general, our current insurance policies cover physical damage to our oil and gas assets. The coverage is designed to repair or replace assets damaged by insurable events.
Our excess liability policies generally provide coverage (dependent on the asset) for bodily injury and property damage, including coverage for negative environmental effects such as seepage and pollution. This liability coverage would cover claims for bodily injury or death brought against the company by or on behalf of individuals who are not employees of the company. The liability limits scale to either our operating interest or the total insured interest including nonoperating partners.
Our energy insurance package includes coverage for operator’s extra expense, which provides coverage for control of well, re-drill and pollution arising from a covered event. We maintain a $150 million Oil Spill Financial Responsibility policy in order to provide a Certificate of Financial Responsibility to The Bureau of Ocean Energy Management, Regulation, and Enforcement (“BOEM”) under the requirements of the Oil Pollution Act of 1990. Additionally, as noted above, our excess liability policies provide coverage (dependent on the asset) for bodily injury and property damage, including coverage for negative environmental effects such as seepage and pollution.
The indemnification obligations between ATP and its drilling contractors are negotiated as part of an overall drilling contact, and as such each contract is unique. However, generally, the drilling contractors agree to indemnify ATP against claims arising from injury to or death of their employees or the employees of their subcontractors. Similarly, ATP generally agrees to indemnify the drilling contractor against claims made by employees of ATP and its other contractors. Additionally, each party generally is responsible for damage to its own property.
We will add a section to the Form S-4 prospectus entitled “Additional Information About the Company” and it will include the foregoing disclosure and, in future periodic filings, we intend to provide disclosure consistent with the foregoing.
| 3. | In this regard, discuss what remediation plans or procedures you have in place to deal with the environmental impact that would occur in the event of an oil spill or leak from your offshore operations. |
Response: ATP has in place for its Gulf of Mexico (“GOM”) operations a Regional Oil Spill Response Plan (“Response Plan”) that covers the uncontrolled release of any
ATP Oil & Gas Corporation | 4600 Post Oak Place | Suite 200 | Houston, TX 77027 | www.atpog.com |
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Securities and Exchange Commission
Response to Comment Letter Dated November 5, 2010
hazardous material. The Response Plan details procedures for the rapid and effective response and remediation to spill events that may occur as a result of ATP’s operations. The Response Plan is supplemented and updated as needed.
The ATP spill management team consists of an integrated organization of key personnel from ATP and a third party spill management group, O’Brien’s Oil Pollution Service, Inc. This team utilizes the National Incident Management System (“NIMS”), which is a nationwide template, or organizational structure, which enables federal, state, and local governments, as well as non-governmental organizations, to work together to prepare for, prevent, if necessary respond to, and mitigate the effects of an incident.
Within the NIMS template is the Incident Command System (“ICS”), which establishes the functional organizational structure of the team (“Response Team”). The ICS represents a best-practices emergency response management structure for meeting the demands of any emergency situation. All members of the Response Team, at a minimum, receive training and are tested through annual spill drills. The Response Team is headed by an Incident Commander who has overall responsibility during the incident mitigation.
ATP is a member of Clean Gulf Associates (“CGA”), which is a not-for-profit association of producing and pipeline companies operating in the GOM. CGA, coupled with the Marine Spill Response Corporation, manage the response personnel and equipment which are on call 24 hours a day, seven days a week. All of these personnel and the associated equipment are managed by the Incident Commander through the ICS.
We will add a section to the Form S-4 prospectus entitled “Additional Information About the Company” and it will include the foregoing and, in future periodic filings, we intend to provide disclosure consistent with the foregoing.
| 4. | Please tell us about your plans to resume drilling in the Gulf of Mexico and the status of your compliance with NTL No. 2010-N05 and NTL No. 2010-N06. |
Response: BOEM issued Notice to Lessees No. 2010-N05 (“NTL-05”) on June 8, 2010 and Notice to Lessees No. 2010-N06 (“NTL-06”) on June 18, 2010. As of the date of this letter, we have two applications for drilling permits under BOEM review and plan to submit additional permit applications over the next few weeks. Both of ATP’s permit applications comply with the requirements of NTL-05 and NTL-06. Upon approval of each permit by the BOEM, ATP will resume drilling in the Gulf of Mexico.
With regard to NTL-05, ATP filed the certifications and information that were required to be filed by certain specified dates under NTL-05. We note that on October 19, 2010, the United States District Court for the Eastern District of Louisiana set aside NTL-05 in the Ensco Offshore Co. v. Salazar litigation. On October 12, 2010, the Department of Interior (“DOI”) issued an order lifting the July 12, 2010 drilling moratorium and requiring OCS lessees and operators to comply with BOEM’s Interim Final Rule entitled “Increased Safety Measures for Energy Development on the Outer Continental Shelf” (the “Safety Interim Final Rule”) before recommencing deepwater operations. The Safety Interim Final Rule, which was published on October 14, 2010, generally incorporates the terms of NTL-05. In connection with our plans and our permit applications, we have supplemented and continue to supplement those plans and permit applications with the actions and information necessary for ATP to remain in compliance with the Safety Interim Final Rule and NTL-06 as well as NTL-05 as such provisions may apply.
ATP Oil & Gas Corporation | 4600 Post Oak Place | Suite 200 | Houston, TX 77027 | www.atpog.com |
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Securities and Exchange Commission
Response to Comment Letter Dated November 5, 2010
Business, page 7
Marketing and Delivery Commitments, page 9
| 5. | Please provide the disclosure regarding delivery commitments required by Item 1207 of Regulation S-K. |
Response: We will add a section to the Form S-4 prospectus entitled “Additional Information About the Company” and it will include the following disclosure and, in future periodic filings, we intend to provide similar disclosure. The last three (underlined) sentences below are additions to the previous disclosure provided in our annual report on Form 10-K for the year ended December 31, 2009 under the caption “Marketing and Delivery Commitments.”
We sell crude oil and natural gas production under price sensitive or market price contracts. Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. The price received by us for such production can fluctuate widely. Changes in the prices of oil and natural gas will affect our proved reserves as well as our revenues, profitability and cash flow. Additionally, involuntary curtailment of our natural gas or oil production, market, economic and regulatory factors may in the future materially affect our ability to sell our natural gas or oil production.Occasionally, we sell a limited portion of our production utilizing fixed-price forward sales contracts, which require us to deliver a fixed and determinable quantity of oil or gas to a predetermined Gulf of Mexico or North Sea market delivery point. At inception of these contracts, we expect to have sufficient production from each local market to satisfy the commitments. Volume information by geographic area at December 31, 2009 regarding our fixed-price forward sales contracts is included in footnote 15 to our Consolidated Financial Statements incorporated herein by reference.
Risk Factors, page 14
| 6. | We note your disclosure at page 16 that under the second amendment to the Term Loans with Credit Suisse, the calculation of the trailing-twelve-months EBITDAX was expanded to include gains from certain property transactions that did not qualify for gain accounting treatment. Tell us how the gains were determined and explain why they were not being reported as gains under U.S. GAAP. |
Response: From March 2009 through January 2010, we completed four transactions which were asset sale/transfer transactions under applicable state law; however, these transactions were required to be treated as financing transactions under U.S. GAAP. The Term Loans to which this EBITDAX covenant applied were repaid in full in April 2010 and this covenant does not apply to our new loans.
Under the provisions of our Term Loans, we were required to use a portion of the proceeds from each transaction to pay down amounts outstanding. Since the loan documents did not contemplate sales transactions that would not be recognized as sales transactions by U.S. GAAP, the lenders agreed to an accommodation for covenant purposes only that allowed hypothetical gain amounts from each transaction to be included in the EBITDAX calculation under the loan covenants. The calculation and ultimate amount of the hypothetical gain was a negotiated concession by the lenders and was derived by subtracting the net book value of the transaction assets from the transaction proceeds, net of fees and expenses.
ATP Oil & Gas Corporation | 4600 Post Oak Place | Suite 200 | Houston, TX 77027 | www.atpog.com |
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Securities and Exchange Commission
Response to Comment Letter Dated November 5, 2010
In the first transaction, an asset was transferred from ATP to a controlled limited partnership. Because ATP maintained control, the partnership remained consolidated in ATP’s financial statements and the associated assets were transferred at their carryover historical cost basis with no gain or loss recognized for GAAP purposes. The proceeds associated with the third party investment in the partnership were reflected under the caption “Temporary equity—redeemable noncontrolling interest.” The second transaction involved the sale of a pipeline to a third party. In conjunction with that sale, we entered into agreements with the third party to transport oil and natural gas production for the remaining productive life of one of our fields for a per-unit fee and we agreed to retain the abandonment obligations related to the pipeline. This transaction was accounted for as a failed sale-leaseback and the proceeds were treated as a financing obligation. The final two transactions were conveyances of limited-term overriding royalty interests repayable in cash. These interests revert to ATP after satisfaction of the dollar-denominated obligations, which were carved from proved producing reserves where future repayment was deemed “reasonably assured.” The proceeds from these transactions were also treated as financing obligations.
Proved Undeveloped Reserves, page 25
| 7. | Please tell us whether you have proved undeveloped reserves that are older than five years. |
Response: At December 31, 2009, ATP did not have any proved undeveloped reserves older than five years.
| 8. | We note that as of December 31, 2009, your PUDs totaled 70.1 MMBbls of crude oil and 286.0 Bcf of natural gas, for a total of 117.8 MMBoe. We further note that during 2009 you only converted 2.6 MMBoe PUDs into proved developed reserves. Please tell us whether your PUDs will be converted within 5 years and explain the basis for such conclusion. |
Response: Our PUD conversion rate during 2009 is not indicative of the conversion rate we expect in future years. Deepwater development is a multi-year process. For example, our Gomez development began in 2003 and was placed on production in 2006. In 2009, the majority of our capital was spent toward the design, construction and installation or modification of our deepwater infrastructure in the GOM and North Sea. While such capital expenditures are important and part of the project development, there are no PUD reserves converted during the infrastructure development phase. This conversion only occurs during the drilling and completion phase of the development. In 2010, we completed the infrastructure development phase at our Telemark Hub and entered the drilling and completion phase, resulting in much greater conversion of PUD reserves to a proved developed reserve category than during the prior year. As of December 31, 2009, our development plan reflected conversion of 75% of our December 31, 2009 PUD inventory to a proved developed reserve category by December 31, 2012, and conversion of 98% of the December 31, 2009 PUD inventory to a proved developed reserve category by December 31, 2014. The remaining 2% of the PUD inventory relates to a gas-cap blowdown that occurs after the five-year period.
Exhibit 23.5
| 9. | Please obtain and file a revised version of this exhibit that includes the disclosure required by Items 1202(a)(8)(iv, v, and viii). |
ATP Oil & Gas Corporation | 4600 Post Oak Place | Suite 200 | Houston, TX 77027 | www.atpog.com |
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Securities and Exchange Commission
Response to Comment Letter Dated November 5, 2010
Response: The revised exhibit is attached and the disclosure requested has been added beginning in the third paragraph on page two of the attachment. We intend to file an amendment to our Form 10-K for the year ended December 31, 2009 to file this exhibit upon resolution of your comments to our Exchange Act filings.
Exhibit 23.6
| 10. | The closing paragraph states in part that the “report was prepared for the exclusive use and sole benefit of ATP Oil & Gas Corporation and may not be put to other use without our prior written consent for such use.” As Item 1202(a)(8) of Regulation S-K requires the report, please obtain and file a revised version which retains no language that could suggest either a limited audience or a limit on potential investor reliance. |
Response: The revised exhibits 23.6 and 23.7 are attached and the statement you noted has been deleted. We intend to file an amendment to our Form 10-K for the year ended December 31, 2009 to file these exhibits upon resolution of your comments to our Exchange Act filings.
Definitive Proxy Statement on Schedule 14A Filed April 29, 2010
Compensation Discussion and Analysis, page 23
| 11. | We note that you have not included any disclosure in response to Item 402(s) of Regulation S-K. Please advise us of the basis for your conclusion that disclosure is not necessary and describe the process you undertook to reach that conclusion. |
Response: Regulation S-K Item 402(s) requires disclosure of compensation policies and practices that are “reasonably likely to have a material adverse effect on the registrant.” In this regard, prior to filing our 2010 proxy statement, ATP’s senior management considered this disclosure item in light of the compensation components utilized by ATP, which are base salary, bonus and, from time to time, grants of options and restricted stock. ATP does not have any individual business units or segments with special or different compensation practices. Cash bonuses and equity award compensation (options and restricted stock) are awarded based on past performance of the company and the individual. Our current compensation practices do not include the award of incentive compensation for the accomplishment of pre-defined goals or targets. Considering the foregoing, management determined that ATP’s compensation practices do not include incentives that lead to inappropriate risk taking by employees or create the likelihood of a material adverse effect on ATP. Our Chief Executive Officer presented this determination to the Board at their meeting on March 3, 2010.
ATP Discretionary Bonus Policy, page 27
| 12. | We note your disclosure at the bottom of page 27 that each of Messrs. Bulmahn, Tate, Reese and Godwin were awarded bonuses under the Discretionary Bonus Policy in connection with the corporate achievements described at page 26. With respect to Mr. Bulmahn and Mr. Tate, please describe in greater detail “each individual’s instrumental role in those achievements,” as considered by your compensation committee, and with respect to Mr. Reese and Mr. Godwin, please describe in greater detail the “key contributions” which the committee recognized. |
Response: The Compensation Committee awarded Mr. Bulmahn’s and Mr. Tate’s bonuses for 2009 performance under the Discretionary Bonus Policy because they both provided the vision, leadership and drive necessary to enable ATP to achieve the accomplishments noted on page 26 of both our preliminary and definitive 2010 proxy statements. With their guidance, the company achieved these results despite challenges caused by negative financial market conditions.
ATP Oil & Gas Corporation | 4600 Post Oak Place | Suite 200 | Houston, TX 77027 | www.atpog.com |
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Securities and Exchange Commission
Response to Comment Letter Dated November 5, 2010
The bonuses awarded to Mr. Reese and Mr. Godwin under the Discretionary Bonus Policy were determined by the Chief Executive Officer, as noted on page 23 of our 2010 proxy statement under “Role of Management in the Executive Compensation Process.” Mr. Reese, ATP’s Chief Financial Officer, led ATP’s efforts to monetize its deepwater offshore infrastructure in 2009, completing two strategic transactions, the first of this type for ATP. His dedication and leadership resulted in the timely completion of these two key transactions. Mr. Reese was also instrumental in developing the transaction structures for the net profits interests noted on page 26 of the 2010 proxy statement, which were also the first transactions of this type for ATP. Mr. Reese’s expertise, determination, and guidance directly impacted ATP’s ability to complete these transactions.
Mr. Godwin, ATP’s Chief Accounting Officer, was also awarded a bonus under the Discretionary Bonus Policy for 2009 performance. The number and complexity of the unique transactions that ATP completed in 2009, as described on page 26 of the 2010 proxy statement, required extraordinary and unprecedented efforts to successfully implement in a timely manner from a financial accounting standpoint. As mentioned above, these transactions were the first of their type for ATP. Mr. Godwin’s leadership and expertise in guiding the company’s efforts in this regard were invaluable.
ATP intends to include in future filings a level of detail similar to the foregoing regarding discretionary bonuses when they are awarded. While our 2010 preliminary and definitive proxy statements do not set forth all of the foregoing details, ATP does not believe those documents omit any required disclosure.
Potential Payments upon Termination of Change in Control, page 34
| 13. | We note your disclosure regarding the payments your named executive officers would receive if there were a change in control of the company. Please elaborate on the compensation committee’s rationale for selecting these particular events as triggers for the specified payments. Also explain why Mr. Bulmahn would be awarded a cash payment upon a change of control, regardless of whether a termination event occurs, whereas the other executive officers have double-trigger provisions. Refer to Item 402(b)(2)(xi) of Regulation K. |
Response: The triggers for the potential payments upon terminationor change in control identified in the table on page 34 of our 2010 proxy statement are:
| • | Termination by the Executive for Good Reason |
| • | Involuntary Termination without Cause |
| • | Change in Control and No Termination |
| • | Change in Control and Termination within 12 months |
The first two triggers are without regard to a change in control. The other two triggers pertain to a change in control event. These triggers are fairly standard triggers in executive employment agreements and were included by the Compensation Committee in the employment agreements for the Named Executive Officers to ensure that the agreements would be competitive in our industry. As noted, our Chief Executive Officer, Mr. Bulmahn, is entitled to a payment upon a change in control without regard to
ATP Oil & Gas Corporation | 4600 Post Oak Place | Suite 200 | Houston, TX 77027 | www.atpog.com |
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Securities and Exchange Commission
Response to Comment Letter Dated November 5, 2010
termination. The other Named Executive Officers are entitled to a payment upon change in control only if they are terminated within 12 months following the change. The potential payment to Mr. Bulmahn was structured differently because the compensation committee took into account his role as the founder of ATP.
ATP intends to include in future filings setting forth compensation discussion and analysis a level of detail similar to the foregoing regarding these triggers for payments.
Form 10-Q for Fiscal Period Ended June 30, 2010
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 24
Liquidity and Capital Resources, page 35
| 14. | We note your statement that “[w]e anticipate our 2010 cash capital expenditures (including abandonment) will be between $450 and $500 million, which is the level that we expect can be funded with cash on hand and cash flows from operations.” We further note your statement in Exhibit 99.1 to your Form 8-K filed on August 6, 2010 that “ATP incurred CAPEX costs of $513.3 million during the first six months of 2010.” We also note that you provide substantial information in this earnings release regarding capital expenditures, such as guidance on your projected capital expenditures for the remainder of the year, that is not included in your Form 10-Q. Please ensure that you include all material information regarding your liquidity and capital resources in future periodic reports. |
Response: We will include all material information regarding our liquidity and capital resources in our future periodic reports.
In responding to the comments received from the Staff by letter dated November 5, 2010, ATP acknowledges that: (i) ATP is responsible for the adequacy and accuracy of the disclosure in its Exchange Act filings; (ii) Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to ATP’s Exchange Act filings; and (iii) 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.
We trust that our responses noted above adequately address the Staff’s comments on this filing. 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 |
Attachments
ATP Oil & Gas Corporation | 4600 Post Oak Place | Suite 200 | Houston, TX 77027 | www.atpog.com |
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 | Collarini Associates | |
11111 Richmond Avenue, Suite 126 Houston, Texas 77082 Tel. (832) 251-0160 Fax (832) 251-0157 www.collarini.com |
February 15, 2010
Mr. Jerry Kennedy
ATP Oil & Gas Corporation
4600 Post Oak Place, Suite 200
Houston, Texas 77027-9726
Dear Mr. Kennedy:
In accordance with your request and to enable ATP Oil & Gas Corporation (ATP) to satisfy the requirements of ATP’s annual reporting, we have estimated the proved reserves and future revenue, as of January 1, 2010, to the interest of ATP in and related to certain oil and gas properties, located in the Gulf of Mexico and in the North Sea. The estimate of proved reserves and the future revenue therefrom conform to all standards and definitions promulgated in Section 210.4-10 of Regulation S-X issued by the Securities and Exchange Commission in November 1988 and amended in December 2008. It is estimated these volumes represent 98% of ATP’s total proved reserves.
As presented in the accompanying detailed projections by reservoir and by reserve category, we estimate the net reserves and future net income to the ATP Oil & Gas Corporation interest, as of January 1, 2010, in the Gulf of Mexico, to be:
| Net Remaining Reserves | Future Net Income (M$) | |||||||||||||||
Reserve Category | Oil (MBO) | Gas (MMCF) | Undiscounted | Present Worth at 10% | ||||||||||||
Proved | ||||||||||||||||
Producing | 6,214 | 23,528 | 467,087 | 377,333 | ||||||||||||
Shut-In | 24 | 11,624 | 40,535 | 35,092 | ||||||||||||
Behind Pipe | 808 | 900 | 44,980 | 22,617 | ||||||||||||
Undeveloped | 44,431 | 187,873 | 1,976,101 | 1,215,600 | ||||||||||||
P&A | 0 | 0 | -116,586 | -50,978 | ||||||||||||
Total Proved | 51,477 | 223,926 | 2,412,115 | 1,599,665 | ||||||||||||
ATP Oil & Gas Corporation
February 15, 2010
Page Two
As presented in the accompanying detailed projections by reservoir and by reserve category, we estimate the net reserves and future net income to the ATP Oil & Gas Corporation interest, as of January 1, 2010, in the North Sea, to be:
| Net Remaining Reserves | Future Net Income (M$) | |||||||||||||||
Reserve Category | Oil (MBO) | Gas (MMCF) | Undiscounted | Present Worth at 10% | ||||||||||||
Proved | ||||||||||||||||
Producing | 4 | 12,085 | 45,924 | 38,610 | ||||||||||||
Undeveloped | 25,498 | 97,497 | 1,018,088 | 338,649 | ||||||||||||
P&A | 0 | 0 | -30,156 | -11,189 | ||||||||||||
Total Proved | 25,501 | 109,582 | 1,033,856 | 366,071 | ||||||||||||
Oil volumes are generally expressed in thousands of stock tank barrels (MBO), where one barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of standard cubic feet (MMCF) at 60 degrees Fahrenheit and the contract pressure base.
Net sales, as defined in this report, are before deducting production taxes. Net income is after deducting these taxes, and after deducting future capital costs and operating expenses, but before consideration of federal income taxes. The future net income has also been shown discounted at ten percent to determine its present worth as required by Regulation S-X. This present worth is included to indicate a standard measure and is not intended to represent the market value of the property. Our estimates of future cash flows include estimates of all costs required to recover reserves.
Reserves in this report were estimated using all applicable engineering and geological data available such as, but not limited to, historic production volumes, initial flow test information, flowing tubing pressures, shut-in tubing pressures, bottom hole pressures, repeat formation test data, pressure- volume- temperature fluid analysis, geological well logs, sidewall core analysis, and whole core analysis at the time the report was conducted.
The reserve volumes and their respective classifications and categorizations were estimated by performance methods, volumetric methods, analogy, or combination of methods. Performance methods generally included decline curve analysis and material balance analysis where representative data was available. Volumetric estimates generally included a combination of geological and engineering interpretations, while analogy methods included reserve estimates from historical performance of similar wells and reservoirs in the field or nearby fields.
Proved reserve classifications were determined based on the “reasonable certainty” of recovering the estimated volumes or more. The proved reserve categorizations were based on the stage of maturity and development of the respective proved reserves.
Based on gross oil equivalent barrels, approximately 65 percent of ATP’s proved reserves are located in the North America, United States, Gulf of Mexico and 35 percent are located in the United Kingdom sector of the North Sea. ATP’s proved reserves are approximately 15 percent developed and 85 percent undeveloped in total and in each geographic region.
ATP Oil & Gas Corporation
February 15, 2010
Page Three
ATP’s Gulf of Mexico proved developed reserves are approximately 70 percent proved producing and 30 percent proved non- producing. Approximately 92 percent of the Gulf of Mexico’s proved producing reserves were estimated by performance methods while 100 percent of the proved non- producing reserves and 98% of the proved undeveloped reserves were estimated by volumetric methods. These estimates are based on gross oil equivalent barrels that ATP holds an interest in.
ATP’s North Sea proved developed reserves are 100 percent proved producing. Approximately 73 percent of the North Sea’s proved producing reserves were estimated by performance and 27 percent were estimated by volumetric methods. Approximately 34 percent of the proved undeveloped reserves in the North Sea were estimated by performance methods, 34 percent were estimated by volumetric methods and 11 percent were estimated by analog methods. These estimates are based on gross oil equivalent barrels that ATP holds an interest in.
A detail description of methodology used in estimating reserves for each well and reservoir in each field is tabulated in the respective field section under “Reserve Summary” included in the detailed report.
Hydrocarbon prices used in this report are based on SEC price parameters using the average prices received on the first of each month during the 12-month period prior to the ending date of the period covered in this report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. The product prices used to determine future gross revenue for each field were determined by applying benchmark pricing as describe above then adjusted by “differentials” only to the extent provided by SEC guidelines. These “differentials” generally adjust the benchmark prices on a field by field basis to account for product quality, transportation, and marketing. The “differentials” were provided to Collarini Associates in detail from ATP. Collarini accepted the “differentials” as factual data and did not confirm the accuracy of these adjustments. The following table summarizes by major geographic region the “average benchmark prices” and the “average realized price” after the appropriate “differentials” were applied.
| Price | Avg Benchmark | Avg Realized | ||||||||||||
Geographic Region | Product | Reference | Price | Price | ||||||||||
North America | ||||||||||||||
United States | ||||||||||||||
Gulf of Mexico | Oil/ Condensate | WTI Cushing | $61.18/Bbl | $58.29/Bbl | ||||||||||
| Gas | Henry Hub | $3.87/MMBtu | $4.22/MCF | |||||||||||
United Kingdom | ||||||||||||||
North Sea | Oil/ Condensate | Brent Oil | $59.73/Bbl | $56.73/Bbl | ||||||||||
| Gas | Heren Index (BNBP) | $4.95/MMBtu | $4.69/MCF | |||||||||||
ATP Oil & Gas Corporation
February 15, 2010
Page Four
Future development costs included in this report were provided to Collarini Associates by ATP and accepted as factual data. Collarini Associates reviewed, for reasonableness, the estimated future development cost, plug and abandonment cost and their respective timing for each well, reservoir, and field. Collarini did not, however, confirm the accuracy of these expenditures. These costs are tabulated in the respective field section under “Forecast of Expenditures” included in the detailed report. These costs are held constant and not escalated. It should be noted, as provided by ATP, the value of the ATP Innovator floating platform, located at Mississippi Canyon 711, and its associated infrastructure, is $225.676 million as of December 31, 2009. The value is depreciated using a straight-line depreciation method over its estimated useful life. The depreciated book value is reflected in the appropriate proved category.
Operating costs are based on actual expenses, as provided by ATP Oil & Gas Corporation. Collarini did not confirm the accuracy of these expenses. These current expenses are held constant through the life of the property. These costs include processing fees where applicable. Estimated lease fuel-gas usage has been included as a reduction to produced volume in the cash flow forecast.
Collarini Associates utilized all data, appropriate methods and procedures deemed necessary to conduct and finalize this report to conform to all standards and definitions promulgated in Section 210.4-10 of regulation S – X issued by the Securities and Exchange Commission in November 1988 and amended in December 2008.
The reserves presented in this report are estimates only and should not be construed as being exact quantities. They may or may not be recovered, and if recovered, the revenues, costs, and expenses therefrom may be more or less than the estimated amounts. Because of governmental policies, uncertainties of supply and demand, and international politics, the actual sales rates and the prices actually received for the reserves, as well as the costs of recovery, may vary from those assumptions included in this report. Also, estimates of reserves may increase or decrease as a result of future operational decisions, mechanical problems, and the price of oil and gas.
All reserve estimates have been performed in accordance with sound engineering principles and generally accepted industry practice. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data, and all conclusions represent only informed professional judgments.
The titles to the properties have not been examined by Collarini Associates, nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from ATP Oil & Gas Corporation and from sources which provide publicly accessible data and are considered accurate.
ATP Oil & Gas Corporation
February 15, 2010
Page Five
A detailed environmental and mechanical inspection of the properties was not made by Collarini Associates. A visual inspection of the properties themselves was not considered necessary for the purpose of this report. No assessment of compliance with environmental regulations or future liability for site remediation was made. We are independent consultants; we do not own any interest in this property and are not employed contingent upon the value of this property. All engineering calculations and basic data used in the analysis are maintained on file in our office and are available for review.
Very truly yours,
COLLARINI ASSOCIATES
Mitch Reece, P.E.
President
MCR/tlk
Collarini Engineering Inc.
Texas Board of Professional Engineers Registration F-5660
ATP OIL & GAS CORPORATION
Estimated
Future Reserves and Income
Attributable to Certain
Leasehold and Royalty Interests
SEC Parameters
As of
December 31, 2009
|
| |||
| Eric T. Nelson, P.E. | John E. Hamlin, P.E. | |||
| TBPE License No. 102286 | TBPE License No. 65319 | |||
| Senior Petroleum Engineer | Managing Senior Vice President |
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
February 3, 2010
ATP Oil & Gas Corporation
4600 Post Oak Place, Suite 200
Houston, TX 77027
Gentlemen:
At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of ATP Oil & Gas Corporation (ATP) as of December 31, 2009. The subject properties are located in the federal waters offshore Louisiana and Texas and in the state waters offshore Louisiana. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 3, 2010 and presented herein, was prepared for public disclosure by ATP in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.
The properties evaluated by Ryder Scott account for a portion of ATP’s total net proved reserves as of December 31, 2009. Based on information provided by ATP, the third party estimate conducted by Ryder Scott addresses 10 percent of the total proved developed net liquid hydrocarbon reserves and 15 percent of the total proved developed net gas reserves or 13 percent of the total proved developed net reserves on a standard cubic foot of gas equivalent, SCFE basis and less than one percent of the total proved undeveloped net liquid hydrocarbon and gas reserves or less than one percent of the total proved undeveloped net reserves on a standard cubic foot of gas equivalent, SCFE basis of 6.0 MCF per barrel.
The estimated reserves and future net income amounts presented in this report, as of December 31, 2009, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.
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February 3, 2010
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SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
ATP Oil & Gas Corporation
As of December 31, 2009
| Proved | ||||||||||||||||
| Developed | Undeveloped | Total Proved | ||||||||||||||
| Producing | Non-Producing | |||||||||||||||
Net Remaining Reserves | ||||||||||||||||
Oil/Condensate – Barrels | 492,107 | 287,006 | 183,271 | 962,384 | ||||||||||||
Gas-MMCF | 5,391 | 3,073 | 649 | 9,113 | ||||||||||||
Income Data | ||||||||||||||||
Future Gross Revenue | $ | 49,755,933 | $ | 30,219,956 | $ | 13,802,836 | $ | 93,778,725 | ||||||||
Deductions | 35,689,462 | 27,924,316 | 11,188,315 | 74,802,093 | ||||||||||||
Future Net Income (FNI) | $ | 14,066,471 | $ | 2,295,640 | $ | 2,614,521 | $ | 18,976,632 | ||||||||
Discounted FNI @ 10% | $ | 18,033,673 | $ | 2,119,005 | $ | 1,706,000 | $ | 21,858,678 | ||||||||
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. The program was used solely at the request of ATP. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.
The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. Certain gas, oil and condensate processing and handling fees, including compression fees where applicable, are included as “other” costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 62 percent and gas reserves account for the remaining 38 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.
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February 3, 2010
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| Discounted Future Net Income As of December 31, 2009 | ||||
Discount Rate Percent | Total Proved | |||
5 | $ | 20,714,678 | ||
15 | $ | 22,575,565 | ||
20 | $ | 22,983,516 | ||
30 | $ | 23,186,992 | ||
The results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the behind pipe category.
No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.
Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At ATP’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.
Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”
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February 3, 2010
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Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
ATP’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which ATP owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
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February 3, 2010
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Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, or a combination of methods. Approximately 51 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, and/or material balance, which utilized extrapolations of historical production and pressure data available through October 2009 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by ATP or obtained from public data sources and were considered sufficient for the purpose thereof. Approximately 20 percent of the proved producing reserves were estimated by the volumetric method, and 29 percent of the proved producing reserves were estimated by a combination of performance and volumetric methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.
Approximately one percent of the proved non-producing reserves included herein were estimated by performance methods. Approximately 97 percent of the non-producing reserves were estimated by the volumetric method and approximately two percent of the non-producing reserves were estimated by a combination of performance and volumetric methods. One hundred percent of the undeveloped reserves were estimated by the volumetric method. The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by ATP or which we have obtained from public data sources that were available through October 2009. The data utilized from the analogues as well as well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.
To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
ATP has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by ATP with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product
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February 3, 2010
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prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by ATP. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by ATP. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.
ATP furnished us with the above mentioned average prices in effect on December 31, 2009. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.
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February 3, 2010
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The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by ATP. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by ATP to determine these differentials.
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.
| Geographic Area | Product | Price Reference | Average Benchmark Prices | Average Realized Prices | ||||||||
North America United States | Oil/Condensate | WTI Cushing | $ | 61.18/Bbl | $ | 60.63/Bbl | ||||||
| Gas | Henry Hub | $ | 3.87/MMBTU | $ | 3.89/MCF | |||||||
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
Costs
Operating costs for the leases and wells in this report are based on the operating expense reports of ATP and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. Certain gas, oil and condensate processing and handling fees including compression fees where applicable are included as “other” costs. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by ATP. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
Development costs were furnished to us by ATP and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by AP were accepted without independent verification.
The proved non-producing and undeveloped reserves in this report have been incorporated herein in accordance with ATP’s plans to develop these reserves as of December 31, 2009. The implementation of ATP’s development plans as presented to us and incorporated herein is subject to the approval process adopted by ATP’s management. As the result of our inquires during the course of
ATP Oil & Gas Corporation
February 3, 2010
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preparing this report, ATP has informed us that the development activities included herein have been subjected to and received the internal approvals required by ATP’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to ATP. Additionally, ATP has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans
Current costs used by ATP were held constant throughout the life of the properties.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to ATP. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by ATP.
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February 3, 2010
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ATP Oil & Gas Corporation (“ATP”) makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, ATP has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements of ATP on Form S-3 (Registration Statement Number 333-162574) filed with the Securities and Exchange Commission (“SEC”) on October 19, 2009, and Form S-8 (Registration Statement Number 333-60762) filed with the SEC on May 11, 2001, of the references to our name as well as to the references to our third party report for ATP, which appears in the December 31, 2009 annual report on Form 10-K of ATP. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by ATP.
We have provided ATP with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by ATP and the original signed report letter, the original signed report letter shall control and supersede the digital version.
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
| Very truly yours, | ||
RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580 | ||
| Eric T. Nelson, P.E. | ||
| TBPE License No. 102286 | ||
| Senior Petroleum Engineer | ||
| John E. Hamlin, P.E. | ||
| TBPE License No. 65319 | ||
| JEH/sm | Managing Senior Vice President | |
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. John E. Hamlin was the primary technical person responsible for overseeing the estimate of the reserves, future production, and income presented herein.
Mr. Hamlin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1979, is a Managing Senior Vice President and also serves as an Engineering Group Supervisor responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Hamlin served in a number of engineering positions with Phillips Petroleum Corporation. For more information regarding Mr. Hamlin’s geographic and job specific experience, please refer to the Ryder Scott Company website athttp://www.ryderscott.com.
Mr. Hamlin earned a Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin in 1975 and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Hamlin fulfills. As part of his 2009 continuing education hours, Mr. Hamlin attended an internally presented 9 hours of formalized training as well as a day long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Hamlin attended an additional 24 hours of formalized in-house training as well as an additional 4 hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.
Based on his educational background, professional training and more than 33 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Hamlin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC Regulations”. The SEC Regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein).
Reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
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PETROLEUM RESERVES DEFINITIONS
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Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
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(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
PROVED RESERVES (SEC DEFINITIONS) CONTINUED
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE),
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 2
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
Shut-In
Shut-in Reserves are expected to be recovered from;
| (1) | completion intervals which are open at the time of the estimate but which have not yet started producing; |
| (2) | wells which were shut-in for market conditions or pipeline connections; or |
| (3) | wells not capable of production for mechanical reasons. |
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
ATP OIL & GAS (NETHERLANDS) B.V.
Estimated
Future Reserves and Income
Attributable to Certain
Leasehold Interests
Block L-6D
Offshore the Netherlands
SEC Parameters
As of
December 31, 2009
|
| |||
Eric T. Nelson, P.E. TBPE License No. 102286 | John E. Hamlin, P.E. TBPE License No. 65319 | |||
| Senior Petroleum Engineer | Managing Senior Vice President |
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
February 3, 2010
ATP Oil & Gas (Netherlands) B.V.
4600 Post Oak Place, Suite 200
Houston, TX 77027
Gentlemen:
At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of ATP Oil & Gas (Netherlands) B.V. (ATP) as of December 31, 2009. The subject property is a single producing well located offshore the Netherlands in Block L-6D. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 3, 2010 and presented herein, was prepared for public disclosure by ATP in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.
The properties evaluated by Ryder Scott account for a portion of ATP’s total net proved reserves as of December 31, 2009. Based on information provided by ATP, the third party estimate conducted by Ryder Scott addresses less than 1 percent of the total proved developed net liquid hydrocarbon reserves and 1 percent of the total proved developed net gas reserves or less than 1 percent of the total proved developed net reserves on a standard cubic foot of gas equivalent, SCFE basis of 6.0 MCF per barrel.
The estimated reserves and future net income amounts presented in this report, as of December 31, 2009, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.
ATP Oil & Gas (Netherlands) B.V.
February 3, 2010
Page 2
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold Interests of
ATP Oil & Gas (Netherlands) B.V.
As of December 31, 2009
| Total Proved Developed Producing | ||||
Net Remaining Reserves | ||||
Oil/Condensate – Barrels | 464 | |||
Gas-MMCF | 660 | |||
Income Data | ||||
Future Gross Revenue | $ | 5,484,960 | ||
Deductions | 4,434,236 | |||
Future Net Income (FNI) | $ | 1,050,724 | ||
Discounted FNI @ 10% | $ | 1,541,473 | ||
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. The program was used solely at the request of ATP. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.
The deductions incorporate the normal direct costs of operating the wells, recompletion costs, development costs, and certain abandonment costs net of salvage. Certain gas, oil and condensate processing and handling fees, including compression fees where applicable, are included as “other” costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Gas reserves account for approximately 100 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.
ATP Oil & Gas (Netherlands) B.V.
February 3, 2010
Page 3
| Discounted Future Net income As of December 31, 2009 | ||||
Discount Rate Percent | Total Proved | |||
5 | $ | 1,319,645 | ||
15 | $ | 1,723,343 | ||
20 | $ | 1,871,320 | ||
30 | $ | 2,085,456 | ||
The results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report.
No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.
Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At ATP’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.
Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of
ATP Oil & Gas (Netherlands) B.V.
February 3, 2010
Page 4
regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
ATP’s operations may be subject to various levels of government controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time and time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which ATP owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operation practices.
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
ATP Oil & Gas (Netherlands) B.V.
February 3, 2010
Page 5
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
100 percent of the proved producing reserves attributable to the producing well and/or reservoir were estimated by the performance method, which utilized extrapolations of historical production and pressure data available through October 2009 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by ATP and were considered sufficient for the purpose thereof.
To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
ATP has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by ATP with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by ATP. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves.
ATP Oil & Gas (Netherlands) B.V.
February 3, 2010
Page 6
The future production rates from wells currently on production may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.
ATP furnished us with the above mentioned average prices in effect on December 31, 2009. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.
The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by ATP. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by ATP to determine these differentials.
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.
Geographic Area | Product | Price Reference | Average Benchmark Prices | Average Realized Prices | ||||
Europe | Oil/Condensate | HSL | $50.35/Bbl | $50.35/Bbl | ||||
The Netherlands | Gas | Contract (NIP) | $8.108/MMBTU | $8.27/MCF |
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
Costs
Operating costs for the leases and wells in this report are based on the operating expense reports of ATP and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs include an appropriate level of corporate general administrative and overhead costs. Certain gas, oil and condensate processing and handling fees including compression fees where applicable are included as “other” costs. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an
ATP Oil & Gas (Netherlands) B.V.
February 3, 2010
Page 7
independent verification of the operating cost data used by ATP. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
Development costs were furnished to us by ATP and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by AP were accepted without independent verification.
Current costs used by ATP were held constant throughout the life of the properties.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to ATP. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.
ATP Oil & Gas (Netherlands) B.V.
February 3, 2010
Page 8
Terms of Usage
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by ATP.
ATP Oil & Gas Corporation (“ATP”) makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, ATP has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements of ATP on Form S-3 (Registration Statement Number 333-162574) filed with the Securities and Exchange Commission (“SEC”) on October 19, 2009, and Form S-8 (Registration Statement Number 333-60762) filed with the SEC on May 11, 2001, of the references to our name as well as to the references to our third party report for ATP, which appears in the December 31, 2009 annual report on Form 10-K of ATP. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by ATP.
We have provided ATP with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by ATP and the original signed report letter, the original signed report letter shall control and supersede the digital version.
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
| Very truly yours, |
| RYDER SCOTT COMPANY, LP. |
| TBPE Firm Registration No. F-1580 |
Eric T. Nelson, P.E. TBPE License No. 102286 |
| Senior Petroleum Engineer |
| John E. Hamlin, P.E. |
| TBPE License No. 65319 |
| Managing Senior Vice President |
JEH/pl
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. John E. Hamlin was the primary technical person responsible for overseeing the estimate of the reserves, future production, and income presented herein.
Mr. Hamlin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1979, is a Managing Senior Vice President and also serves as an Engineering Group Supervisor responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Hamlin served in a number of engineering positions with Phillips Petroleum Corporation. For more information regarding Mr. Hamlin’s geographic and job specific experience, please refer to the Ryder Scott Company website athttp://www.ryderscott.com.
Mr. Hamlin earned a Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin in 1975 and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Hamlin fulfills. As part of his 2009 continuing education hours, Mr. Hamlin attended an internally presented 9 hours of formalized training as well as a day long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Hamlin attended an additional 24 hours of formalized in-house training as well as an additional 4 hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.
Based on his educational background, professional training and more than 33 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Hamlin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC Regulations”. The SEC Regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein).
Reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
Page 2
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
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PETROLEUM RESERVES DEFINITIONS
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(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
PROVED RESERVES (SEC DEFINITIONS) CONTINUED
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
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RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE),
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
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RESERVES STATUS DEFINITIONS AND GUIDELINES
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Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
| (1) | completion intervals which are open at the time of the estimate but which have not yet started producing; |
| (2) | wells which were shut-in for market conditions or pipeline connections; or |
| (3) | wells not capable of production for mechanical reasons. |
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
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