Executive Overview

General

ATP Oil & Gas Corporation is engaged in the acquisition, development and production of oil and natural gas properties in the Gulf of Mexico and the North Sea. We seek to acquire and develop properties with proved undeveloped ("PUD") reserves that are economically attractive to us but are not strategic to major or large exploration-oriented independent oil and gas companies. Occasionally we will acquire properties that are already producing or where previous drilling has encountered reservoirs that appear to contain commercially productive quantities of oil and gas even though the reservoirs do not meet the SEC definition of proved reserves. We believe that our strategy provides assets for us to develop and produce without the risk, cost or time of traditional exploration.

We seek to create value and reduce operating risks through the acquisition and subsequent development of properties in areas that have:

• significant undeveloped reserves and reservoirs;

• close proximity to developed markets for oil and natural gas;

• existing infrastructure of oil and natural gas pipelines and production/processing platforms; and

• a relatively stable regulatory environment for offshore oil and natural gas development and production.

Our focus is on acquiring properties that are noncore or nonstrategic to their current owners for a variety of reasons. For example, larger oil companies from time to time adjust their capital spending or shift their focus to exploration prospects which they believe offer greater reserve potential. Some projects may provide lower economic returns to a company due to its cost structure within that company. Also, due to timing or budget constraints, a company may be unwilling or unable to develop a property before the expiration of the lease. With our cost structure and acquisition strategy, it is not unusual for us to have a total acquisition cost for a property that is less than the total costs of the previous owner. This strategy coupled with our expertise in our areas of focus and our ability to develop projects may make the acquired oil and gas properties more financially attractive to us than to the seller. Given our strategy of acquiring properties that contain proved reserves, or where previous drilling indicates to us the presence of recoverable hydrocarbons, our operations typically are lower risk than exploration-focused Gulf of Mexico and North Sea operators.

Since we operate a significant number of the properties in which we acquire a working interest, we are able to significantly influence the plans and timing of a project's development. In addition, practically all of our properties have already defined targeted reservoirs, which eliminates time necessary in typical exploration efforts to locate and determine the extent of oil and gas reservoirs. Without the exploration time constraint, we focus on developing projects in the shortest time possible between initial significant investment and first revenue generated in order to maximize our rate of return. We may initiate new development projects by simultaneously obtaining the various required components such as the pipeline and the production platform or subsea well completion equipment. We believe this strategy, combined with our strong technical abilities to evaluate and implement a project's requirements, allows us to efficiently complete the development project and commence production. To enhance the economics and return on investment of a project, we sometimes develop the project to a value creation point and either sell an interest or bring in partners on a promoted basis during the high capital development phase.

Third quarter 2009 Highlights

• We discovered additional pay sands at the Telemark Hub;

• On November 1, 2009, our new deepwater drilling and production facility, the ATP Titan, sailed out of dry dock and should arrive on location at the Telemark Hub shortly.

• We realized $74.5 million, net of fees and expenses, from monetizing both the oil and natural gas pipelines that service our Gomez Hub;

• We raised, net of fees and expenses, $93.4 million by selling common stock and $135.5 million by selling perpetual convertible preferred stock;

• We amended our Term Loans to improve financial flexibility;

• We have reduced outstanding Term Loans by $112.6 million since June 30, 2009.

On March 6, 2009, along with GE Energy Financial Services ("GE"), we formed ATP-IP to own the ATP Innovator, the floating production facility that currently serves our Mississippi Canyon Block 711 Gomez Hub properties. We contributed the ATP Innovator in exchange for a 49% subordinated limited partner interest and a 2% general partner interest. GE paid $150.0 million to ATP-IP for a 49% Class A limited partner interest. In accordance with our Term Loans, we used $36.4 million of net proceeds from this transaction to reduce the Asset Sale Facility. We remain the operator and continue to hold a 100% working interest in the Gomez field and its oil and gas reserves. The transaction was effective June 1, 2008 and allows us exclusive use of the ATP Innovator during the term of the Platform Use Agreement ("PUA"), which is expected to be the economic life of the Gomez Hub reserves. One director and three officers of ATP also serve as three managers (the equivalent of directors) and the President of the General Partner, ATP IP-GP, LLC. Under certain circumstances there may be conflicts of interest between the general partner and ATP.

From an operational standpoint, during the term of the PUA, we are obligated to pay to ATP-IP a per unit fee for all hydrocarbons processed by the ATP Innovator, subject to a minimum throughput fee of $53,000 per day. Such minimum fees, if applicable, can be recovered by us in future periods whenever fees owed during a month exceed the minimum due. We may also be subject to a minimum fee of $53,000 per day for up to 180 days under certain circumstances, including if we fail to provide the minimum notification period before the Gomez field ceases production. We made no other performance guarantees to GE and the ultimate fees earned by ATP-IP beyond the minimum fees will be determined by the volumes of hydrocarbons processed through the facility. During the term of the PUA, we are responsible for all of the operating costs and periodic maintenance of the ATP Innovator. ATP-IP will pay us a monthly fee for certain administrative services we will provide to the partnership. Additionally, we will share in partnership net income and regular minimum quarterly cash distributions in accordance with the provisions of the ATP-IP partnership agreement. Partnership cash in excess of monthly distributions and operating needs is transferred to an escrow account which is classified as restricted cash on the consolidated balance sheet.

For financial reporting purposes, because we are the general partner of the partnership we consolidate ATP-IP, along with three wholly owned limited liability companies (the "LLCs") we created to own our interests in ATP-IP. The contribution of the ATP Innovator was accounted for as a transfer of assets between entities under common control. Accordingly, ATP-IP recorded the ATP Innovator at its carryover cost basis and no accounting gain or loss was recognized. We have historically subjected the ATP Innovator costs to units-of-production depletion over the proved reserves attributable to our Gomez Hub. ATP-IP owns no reserves and, therefore, now recognizes depreciation expense for the ATP Innovator on a straight-line basis over an estimated useful life of 25 years, given the partnership's ability to enter into subsequent throughput agreements and to relocate the ATP Innovator to a new producing location at the end of the existing PUA. We incurred costs associated with the formation of the partnership of approximately $3.4 million which were charged to general and administrative expense. All items of intercompany revenue and expense, investment and capital are eliminated in consolidation. Additionally, because the partnership agreement provides certain redemption rights to the Class A limited partner interests in the event a change of control occurs at ATP, the Class A interests are reflected as a redeemable noncontrolling interest within equity on our consolidated balance sheet, and we segregate net income and comprehensive income attributable to such interests (also see Note 14, "Commitments and Contingencies" to Financial Statements in Item 1).

During June 2009, we issued 8.75 million shares of common stock ($8.25 per share before underwriters' discounts and commissions and offering expenses). During September and October of 2009, we issued 5.8 million shares of common stock ($18.50 per share before underwriters' discounts and commissions and offering expenses). During September 2009, we issued 1.4 million shares of convertible preferred stock with a per share liquidation preference of $100 and a cumulative dividend rate of 8%. We received total net proceeds of $305.8 million for these transactions. In accordance with our Term Loans, $76.5 million of the Asset Sale Facility was repaid. Of that amount, $17.0 million was repaid prior to September 30, 2009.

In the third quarter of 2009, we executed an asset purchase and sale agreement for net proceeds of $74.5 million with a third party for both the oil and natural gas pipelines that service the Gomez Hub at Mississippi Canyon Block
711. In conjunction with the sale, we entered into agreements with the third party to transport oil and gas production for the remaining production life of the fields serviced by the ATP Innovator for a per unit fee that is subject to a minimum monthly payment through December 31, 2016. Such minimum fees, if applicable, can be recovered by us in future periods within the same calendar year whenever fees owed during a month exceed the minimum due. As a result of the retained asset retirement obligation and the purchaser's option to convey the pipeline back to ATP at the end of the life of the fields in the Gomez Hub, the transaction has been accounted for as a financing obligation equal to the net proceeds received. We remain the operator of the pipeline and are responsible for all of the related operating costs. In accordance with our Term Loans, we used $42.2 million of net proceeds to reduce the Asset Sale Facility.

During this period we also financed significant portions of our development program with transactions entered into with our vendors and their affiliates. We have conveyed to certain vendors net profits interests in our Telemark Hub and Clipper oil and gas properties in exchange for development services. We have also negotiated with certain other vendors involved in the development of the Telemark Hub and Clipper to partially defer payments until after production has begun. Development of our interest in the Cheviot field in the U.K. North Sea continues and we have arranged with the fabricator of the floating production and drilling facility to defer $99 million of payments until construction is complete. Consequently, we have terminated the related letter of credit and unencumbered the $19.0 million balance of our revolving credit facility which secured it.

On November 2, 2009, we entered into an amendment (the "Amendment") to the Term Loans to provide additional flexibility during the period from October 1, 2009 through December 31, 2010 (the "Amendment Period"). Among other provisions, the Amendment loosens the Net Debt to EBITDAX ratio from 3.0 to 4.0, the EBITDAX to Interest ratio from 2.5 times to 2.0 times and the current ratio from 1.0 to 0.8 for the duration of the Amendment Period. The interest rate on the Tranche B-1 balance will increase to a minimum 11.25% during the Amendment Period, at the end of which it will decrease to a minimum 9.5% for the remainder of the term. Beginning this past July 1, 2009, the minimum rate on the Asset Sale Facility increased by 0.5% and such increases will continue each January 1 and July 1 until it is repaid in full. This Amendment will further increase the rate on the Asset Sale Facility balance outstanding as of October 1, 2009 by 2.75% to a minimum 11.75%. Effective January 1, 2011, the minimum rate on any balance that remains outstanding at that date will decrease by 1.25% to 11.5%.

We paid an initial fee of 0.5% to each of the lender group and the administrative agent of the outstanding balance of the Term Loans at closing plus related expenses for a total of $12.6 million for the Amendment. Additionally, a one-time fee of up to 1.0% may be due on the aggregate unpaid balance outstanding at June 30, 2010; specifically, 0.5% of the aggregate unpaid balance outstanding will be due if any portion of the Asset Sale Facility remains unpaid at that date and an additional 0.5% will be due if the Tranche B-1 balance outstanding exceeds $800 million.

Additional discussion of our expectations for 2009 can be found in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our 2008 Annual Report on Form 10-K.

Risks and Uncertainties

As an independent oil and gas producer, our revenue, profitability, cash flows, and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Prices for oil and gas declined materially in early 2009 compared to 2008. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual obligations required under our June 2008 senior secured term loan facility, as amended ("Term Loans").

In addition, our estimates of proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, which could materially impact the quantities of oil and natural gas that we ultimately produce. As of September 30, 2009, approximately 84% of our total proved reserves are undeveloped. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations and cash flows.

We are also vulnerable to certain concentrations that could expose our revenues, profitability, cash flows and access to capital to the risk of a near-term severe impact. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and a substantial portion of our current production is contributed from relatively few wells located offshore in the Gulf of Mexico and in the North Sea. In 2008 and 2009, a significant amount of time and money has been spent by us on our Telemark Hub development. Our 2010 results of operations, financial position and cash flows will be significantly impacted by the timing and success at this development. In addition to the numerous risks associated with offshore operations, some of which may not be covered by insurance, these properties are also characterized by rapid production declines, which require us to incur significant capital expenditures to replace declining production. Complications in the development of any single material well or infrastructure installation, including lack of sufficient capital, or if we were to experience operational problems, uninsured events, or prolonged adverse commodity prices resulting in the curtailment of production in any of these wells, our current and future production levels would be adversely affected, which may materially affect our financial condition, results of operations and cash flows.

Our Term Loans impose restrictions on us that increase our vulnerability in the current adverse economic and industry climate, and may limit our ability to obtain financing. Even though we have recently obtained an amendment to our credit facility, as discussed above, to provide us more latitude in our covenants for the period from October 1, 2009 until December 31, 2010, our ability to meet these covenants is primarily dependent on the adequacy of cash flows from operations, oil and natural gas reserve levels and cash inflows from other financing transactions. Our inability to satisfy the covenants or other contractual requirements contained in our Term Loans would constitute an event of default. An uncured default could result in our outstanding debt becoming immediately due and payable. If this were to occur, we might not be able to obtain waivers or secure alternative financing to satisfy our obligations either of which would have a material adverse impact on our business. We are currently in negotiations to execute transactions that will provide additional funds to us to support our capital expenditure program and reduce our outstanding indebtedness. Given current market conditions, our ability to access the capital markets or consummate asset monetizations or other financings may be restricted at a time when we need to raise additional capital. Further, the current economic conditions could also impact our lenders, customers and hedging counterparties and cause them to fail to meet their obligations to us with little or no warning.

Although we believe that we will have adequate liquidity to meet our future capital requirements and to remain compliant with the covenants under our Term Loans, the factors described above create uncertainty. We have also recently conveyed to certain vendors limited-term net profits interests in our Telemark Hub and Clipper oil and gas properties in exchange for development services and equipment to be provided. We have also negotiated with certain other vendors involved in the development of the Telemark Hub to partially defer payments until after production has begun. We intend to fund our near-term development projects utilizing cash on hand, cash flows from operations and other asset financings. To the extent we are also successful in monetizing selected assets, we may use the proceeds in excess of our required debt repayments to fund additional development opportunities, to further reduce our debt or for added liquidity. We consider the control and flexibility afforded by operating our properties under development to be key to our business plan and strategy. By operating our properties, we retain significant control over the development plans and their timing. Within certain constraints, we can conserve capital by delaying or

eliminating capital expenditures. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility allows us to match our capital commitments to our available capital resources.

Results of Operations

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

For the three months ended September 30, 2009 and 2008 we reported net income
(loss) attributable to common shareholders of ($9.1) million and $36.5 million, or ($0.20) and $1.02 per diluted share, respectively.

Oil and Gas Production Revenues

Revenues presented in the table and the discussion below represent revenues from sales of oil and natural gas production volumes. The table below includes oil and natural gas production revenues from amortization of deferred revenue related to the second quarter 2008 sale of the limited-term overriding royalty interest. We do not reflect any production associated with those revenues.

                                                 Three Months Ended        % Change
                                                   September 30,           from 2008
                                                  2009        2008          to 2009
  Production:
  Natural gas (MMcf)                                3,689       7,267            (49 )%
  Oil and condensate (MBbl)                           792         821             (4 )%
  Total (MMcfe)                                     8,438      12,190            (31 )%
  Gulf of Mexico (MMcfe)                            7,672       8,693            (12 )%
  North Sea (MMcfe)                                   766       3,497            (78 )%
  Revenues from production (in thousands):
  Natural gas                                  $   13,479   $  53,429            (75 )%
  Effects of cash flow hedges                         904        (230 )
  Amortization of deferred revenue                  1,789       2,434

  Total                                        $   16,172   $  55,633            (71 )%

  Oil and condensate                           $   50,907   $  53,510             (5 )%
  Effects of cash flow hedges                          -         (957 )
  Amortization of deferred revenue                  7,931      10,161

  Total                                        $   58,838   $  62,714             (6 )%

  Natural gas, oil and condensate              $   64,386   $ 106,939            (40 )%
  Effects of cash flow hedges                         904      (1,187 )
  Amortization of deferred revenue                  9,720      12,595

  Total                                        $   75,010   $ 118,347            (37 )%

  Average realized sales price:
  Natural gas (per Mcf)                        $     3.67   $    7.35            (50 )%
  Effects of cash flow hedges (per Mcf)              0.25                     (0.03)

  Average realized price (per Mcf)             $     3.92   $    7.32            (46 )%

  Oil and condensate (per Bbl)                 $    64.28   $   65.18             (1 )%
  Effects of cash flow hedges (per Bbl)                -                      (1.17)

  Average realized price (per Bbl)             $    64.28   $   64.01             -  %

  Natural gas, oil and condensate (per Mcfe)   $     7.64   $    8.77            (13 )%
  Effects of cash flow hedges (per Mcfe)             0.11                     (0.10)

  Average realized price (per Mcfe)            $     7.75   $    8.67            (11 )%

Revenues from production decreased in third quarter 2009 compared to third quarter 2008 due to a 31% decrease in overall production and an 11% decrease in average realized sales price (21% price decrease in Gulf of Mexico partially offset by a 8% price increase in North Sea). The lower production in the Gulf of Mexico is primarily the result of natural production declines at the Gomez Hub. The lower production in the North Sea is primarily due to the sale of 80% of our working interest in Tors and Wenlock in the fourth quarter of 2008 and due to voluntary production curtailment as a result of low natural gas prices. The lower average realized sales price is due to decreased commodity market prices.

Lease Operating

Lease operating expenses include costs incurred to operate and maintain wells
and related equipment and facilities. These costs include, among others,
workover expenses, operator fees, processing fees, insurance and transportation.
Lease operating expense was as follows:




                                            Three Months Ended     % Change
                                              September 30,        from 2008
                                             2009         2008      to 2009
         Lease operating (in thousands)   $    22,891   $ 24,723          (7 %)
         Per Mcfe                                2.71       2.03          33 %
         Gulf of Mexico                          2.80       2.20          27 %
         North Sea                               1.85       1.61          15 %

Lease operating expense for third quarter 2009 decreased compared to third quarter 2008 primarily due to the sale of 80% of our working interest in Tors and Wenlock in fourth quarter 2008 and due to reduced fuel and chemicals costs in the Gulf of Mexico partially offset by increases related to a platform workover at our Gomez Hub. The per unit cost has increased primarily due to this platform workover and due to the effect of fixed costs on lower production volumes.

General and Administrative

General and administrative expenses are overhead-related expenses, including
employee compensation, legal and accounting fees, insurance, and investor
relations expenses. General and administrative expense was as follows:




                                                 Three Months Ended     % Change
                                                   September 30,        from 2008
                                                  2009         2008      to 2009
   General and administrative (in thousands)   $    6,945    $  9,212         (25 %)
   Per Mcfe                                          0.82        0.76           8 %

The general and administrative expense decreased for third quarter 2009 compared to the third quarter 2008 primarily as a result of decreased stock-based compensation costs.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization ("DD&A") expense was as follows:




                                      Three Months Ended     % Change
                                        September 30,        from 2008
                                       2009         2008      to 2009
              DD&A (in thousands)   $    37,460   $ 52,825         (29 %)
              Per Mcfe                     4.44       4.33           3 %

DD&A expense for the third quarter 2009 decreased compared to third quarter 2008 primarily due to decreased production described above. The per unit increase is primarily a result of higher costs incurred on our new developments relative to some of our older properties. The increased rate was partially offset by expense decreases related to the change from units-of-production depletion to straight-line depreciation for the ATP Innovator upon contribution to ATP-IP.

Accretion of Asset Retirement Obligation

Accretion expense in third quarter 2009 decreased to $3.0 million compared to $4.2 million in third quarter 2008 primarily due to the North Sea property sale noted above and changes in estimates of future abandonment obligations.

Loss on Abandonment

Loss on abandonment was $1.9 million and $0.9 million in third quarter 2009 and 2008, respectively. These amounts are primarily the result of actual abandonment . . .