Risks And Uncertainties	9 Months Ended
Sep. 30, 2011
Risks And Uncertainties [Abstract]
Risks And Uncertainties	Note 3 — Risks and Uncertainties Since May 2010 when the federal government imposed the first of a series of moratoriums on drilling in the Gulf of Mexico, we have faced unparalleled difficulties in obtaining permits to continue our development programs. Prior to the moratoriums, we anticipated developing and bringing to production three additional wells at our Telemark Hub and two additional wells at our Gomez Hub by the end of 2010. As of September 30, 2011, we have been able to bring to production two additional wells at the Telemark Hub and the third well has been drilled to total depth. First production of the third well has now been deferred until January of 2012 as we modify completion plans to accommodate additional pay sands discovered during drilling. During the third quarter, the two wells planned for the Gomez Hub were postponed to late 2012/early 2013 as permits have not yet been received for these two wells. We have also drilled two wells at Clipper—one has been completed, and the second is scheduled to be completed by the end of 2011—with pipeline construction and first production expected in the second half of 2012. The new wells that have been placed on production have taken longer to complete and bring to production than originally planned and have not produced at rates that were previously projected. In addition, we have incurred capital and operating costs higher than we expected primarily due to additional regulations imposed since the deepwater Macondo incident and the requirement to sidetrack two of the wells. The new wells have helped us achieve production growth in 2011, and we forecast production and operating cash flow growth during the remainder of 2011 and 2012 as activity continues. While cash flows were lower than previously projected due to lower than expected production rates, the delays in bringing on new production and higher costs, we continued our development operations by supplementing our cash flows from operating activities with funds raised through various financing transactions (see the Consolidated Statement of Cash Flows.) Our projections for the fourth quarter of 2011 and calendar 2012 reflect our expectations for production based on actual production history, the development delays at Telemark and Gomez discussed above, the deferral of certain capital expenditures, the continuation of commodity prices near current levels, the higher anticipated costs associated with maintaining existing production and bringing additional production on-line, and the higher cost of servicing our additional financing and other obligations. As of September 30, 2011, we had a working capital deficit of $260 million. To preserve our development momentum in the negative working capital environment that we have experienced throughout 2011, we have increased our First Lien Term Loans, issued convertible perpetual preferred stock, granted net profits interests (NPI's) and dollar-denominated overriding royalty interests (ORRI's) to certain of our vendors, and we have entered into prepaid swaps against our future production that provided cash proceeds to us at closing. We have negotiated with the constructor of the hull of the Octabuoy in China to defer the majority of our payments until the hull is ready to be moved to the North Sea, currently scheduled to be mid- to late-2012. A similar arrangement is in place for the topsides for the Octabuoy being constructed by the same company in China. While we believe we can continue to meet our obligations for at least the next twelve months, our cash flow projections are highly dependent upon numerous assumptions including the timing and rates of production from our new wells, the sales prices we realize for our oil and natural gas, the cost to develop and produce our reserves, and a number of other factors, some of which are beyond our control. Our inability to increase near-term production levels and generate sufficient liquidity through the actions noted above could result in our inability to meet our obligations as they come due which would have a material adverse affect on us. In the event we do not achieve the projected production and cash flow increases, we will attempt to fund any short-term liquidity needs through more of these type transactions; however, there is no assurance that we will be able to repeat these types of transactions in the future if they are required to meet any short-term liquidity needs. As operator of all of our projects that require cash commitments within the next twelve months, we retain significant control over the development concept and its timing. We consider the control and flexibility afforded by operating our properties under development to be instrumental to our business plan and strategy. To manage our liquidity, we have recently delayed certain capital commitments, and within certain constraints, we can continue to conserve capital by further delaying or eliminating future capital commitments. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility is one method by which we can match our capital commitments to our available capital resources. Despite our anticipated production growth, we remain highly leveraged. Servicing our debt and other long-term obligations will continue to place significant constraints on us and makes us vulnerable to adverse economic and industry conditions. Specifically, certain of our financing and derivative transactions require us to make payments in future periods from the proceeds (or net profits) from the sale of production. While these financing transactions have enabled us to continue the development of our properties and meet current operating needs, they will significantly burden the future net cash flows from our production until these obligations are satisfied. (See Note 7, "Other Long-term Obligations," and Note 12, "Derivative Instruments and Risk Management Activities" for further details.) 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. The estimation process requires significant 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, and may differ materially from our estimates. A substantial portion of our total proved reserves are undeveloped and recognition of such reserves as proved requires our ability to demonstrate sufficient capital is available to fund their development. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and we intend to continue to develop these reserves through the end of the year and beyond, but there is no assurance we will be successful. 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, cash flows, the quantity of proved reserves that we report, and our ability to meet the requirements of our financing obligations. A substantial portion of our current production is concentrated among relatively few wells located offshore in the Gulf of Mexico and in the North Sea, which are characterized by production declines more rapid than those of conventional onshore properties. As a result, we are particularly vulnerable to a near-term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and bad weather. Any unanticipated significant disruption to, or decline in, our current production levels or prolonged negative changes in commodity prices or operating cost levels could have a materially adverse effect on our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet our commitments as they come due. Oil and natural gas development and production in the Gulf of Mexico are regulated by the Bureau of Ocean Energy Management ("BOEM") and the Bureau of Safety and Environmental Enforcement ("BSEE") of the Department of the Interior, collectively, formerly known as the Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE"). Our near-term operating and development plans in the Gulf of Mexico, as well as our longer-term business plan, are dependent upon receiving regulatory approvals for deepwater drilling and other permits required by the BSEE. Delays in the permitting process directly impact the timing of our development and production activities, and can materially affect our financial position, results of operations, cash flows, and the quantity of proved reserves that we report. We cannot predict future changes in laws and regulations governing oil and gas operations in the Gulf of Mexico. New regulations issued since the Macondo incident in 2010 have changed the way we conduct our business and increased our costs of developing and commissioning new assets. We incurred additional costs in 2010 from the deepwater drilling moratoriums, subsequent drilling permit delays and additional inspection and commissioning costs. Some of these additional costs have continued into 2011 and are expected to continue. Should there be additional significant future regulations or additional statutory limitations, they could require further changes in the way we conduct our business, further increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. Additionally, we cannot influence or predict if or how the governments of other countries in which we operate may modify their regulatory regimes from time to time. As an independent oil and gas producer, our revenue, profitability, cash flows, proved reserves 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. Any extended decline in oil or gas prices could have a materially 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 requirements of our debt and other obligations.

Risks And Uncertainties

9 Months Ended

Sep. 30, 2011

Note 3 — Risks and Uncertainties

Since May 2010 when the federal government imposed the first of a series of moratoriums on drilling in the Gulf of Mexico, we have faced unparalleled difficulties in obtaining permits to continue our development programs. Prior to the moratoriums, we anticipated developing and bringing to production three additional wells at our Telemark Hub and two additional wells at our Gomez Hub by the end of 2010. As of September 30, 2011, we have been able to bring to production two additional wells at the Telemark Hub and the third well has been drilled to total depth. First production of the third well has now been deferred until January of 2012 as we modify completion plans to accommodate additional pay sands discovered during drilling. During the third quarter, the two wells planned for the Gomez Hub were postponed to late 2012/early 2013 as permits have not yet been received for these two wells. We have also drilled two wells at Clipper—one has been completed, and the second is scheduled to be completed by the end of 2011—with pipeline construction and first production expected in the second half of 2012.

The new wells that have been placed on production have taken longer to complete and bring to production than originally planned and have not produced at rates that were previously projected. In addition, we have incurred capital and operating costs higher than we expected primarily due to additional regulations imposed since the deepwater Macondo incident and the requirement to sidetrack two of the wells. The new wells have helped us achieve production growth in 2011, and we forecast production and operating cash flow growth during the remainder of 2011 and 2012 as activity continues. While cash flows were lower than previously projected due to lower than expected production rates, the delays in bringing on new production and higher costs, we continued our development operations by supplementing our cash flows from operating activities with funds raised through various financing transactions (see the Consolidated Statement of Cash Flows.) Our projections for the fourth quarter of 2011 and calendar 2012 reflect our expectations for production based on actual production history, the development delays at Telemark and Gomez discussed above, the deferral of certain capital expenditures, the continuation of commodity prices near current levels, the higher anticipated costs associated with maintaining existing production and bringing additional production on-line, and the higher cost of servicing our additional financing and other obligations.

As of September 30, 2011, we had a working capital deficit of $260 million. To preserve our development momentum in the negative working capital environment that we have experienced throughout 2011, we have increased our First Lien Term Loans, issued convertible perpetual preferred stock, granted net profits interests (NPI's) and dollar-denominated overriding royalty interests (ORRI's) to certain of our vendors, and we have entered into prepaid swaps against our future production that provided cash proceeds to us at closing. We have negotiated with the constructor of the hull of the Octabuoy in China to defer the majority of our payments until the hull is ready to be moved to the North Sea, currently scheduled to be mid- to late-2012. A similar arrangement is in place for the topsides for the Octabuoy being constructed by the same company in China.

While we believe we can continue to meet our obligations for at least the next twelve months, our cash flow projections are highly dependent upon numerous assumptions including the timing and rates of production from our new wells, the sales prices we realize for our oil and natural gas, the cost to develop and produce our reserves, and a number of other factors, some of which are beyond our control. Our inability to increase near-term production levels and generate sufficient liquidity through the actions noted above could result in our inability to meet our obligations as they come due which would have a material adverse affect on us. In the event we do not achieve the projected production and cash flow increases, we will attempt to fund any short-term liquidity needs through more of these type transactions; however, there is no assurance that we will be able to repeat these types of transactions in the future if they are required to meet any short-term liquidity needs.

As operator of all of our projects that require cash commitments within the next twelve months, we retain significant control over the development concept and its timing. We consider the control and flexibility afforded by operating our properties under development to be instrumental to our business plan and strategy. To manage our liquidity, we have recently delayed certain capital commitments, and within certain constraints, we can continue to conserve capital by further delaying or eliminating future capital commitments. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility is one method by which we can match our capital commitments to our available capital resources.

Despite our anticipated production growth, we remain highly leveraged. Servicing our debt and other long-term obligations will continue to place significant constraints on us and makes us vulnerable to adverse economic and industry conditions. Specifically, certain of our financing and derivative transactions require us to make payments in future periods from the proceeds (or net profits) from the sale of production. While these financing transactions have enabled us to continue the development of our properties and meet current operating needs, they will significantly burden the future net cash flows from our production until these obligations are satisfied. (See Note 7, "Other Long-term Obligations," and Note 12, "Derivative Instruments and Risk Management Activities" for further details.)

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. The estimation process requires significant 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, and may differ materially from our estimates. A substantial portion of our total proved reserves are undeveloped and recognition of such reserves as proved requires our ability to demonstrate sufficient capital is available to fund their development. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and we intend to continue to develop these reserves through the end of the year and beyond, but there is no assurance we will be successful. 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, cash flows, the quantity of proved reserves that we report, and our ability to meet the requirements of our financing obligations.

A substantial portion of our current production is concentrated among relatively few wells located offshore in the Gulf of Mexico and in the North Sea, which are characterized by production declines more rapid than those of conventional onshore properties. As a result, we are particularly vulnerable to a near-term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and bad weather. Any unanticipated significant disruption to, or decline in, our current production levels or prolonged negative changes in commodity prices or operating cost levels could have a materially adverse effect on our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet our commitments as they come due.

Oil and natural gas development and production in the Gulf of Mexico are regulated by the Bureau of Ocean Energy Management ("BOEM") and the Bureau of Safety and Environmental Enforcement ("BSEE") of the Department of the Interior, collectively, formerly known as the Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE"). Our near-term operating and development plans in the Gulf of Mexico, as well as our longer-term business plan, are dependent upon receiving regulatory approvals for deepwater drilling and other permits required by the BSEE. Delays in the permitting process directly impact the timing of our development and production activities, and can materially affect our financial position, results of operations, cash flows, and the quantity of proved reserves that we report.

We cannot predict future changes in laws and regulations governing oil and gas operations in the Gulf of Mexico. New regulations issued since the Macondo incident in 2010 have changed the way we conduct our business and increased our costs of developing and commissioning new assets. We incurred additional costs in 2010 from the deepwater drilling moratoriums, subsequent drilling permit delays and additional inspection and commissioning costs. Some of these additional costs have continued into 2011 and are expected to continue. Should there be additional significant future regulations or additional statutory limitations, they could require further changes in the way we conduct our business, further increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico. Additionally, we cannot influence or predict if or how the governments of other countries in which we operate may modify their regulatory regimes from time to time.

As an independent oil and gas producer, our revenue, profitability, cash flows, proved reserves 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. Any extended decline in oil or gas prices could have a materially 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 requirements of our debt and other obligations.