Risks And Uncertainties	3 Months Ended
Mar. 31, 2012
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 unprecedented 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. Because of the moratoriums and permitting delays, it has taken until the first quarter of 2012 for us to bring to production the three additional wells at the Telemark Hub and the two wells planned for the Gomez Hub have been postponed. The new Telemark wells have taken longer to complete and bring to production than originally planned and one of them has not produced at rates that were previously projected. We are currently recompleting this well in hopes of bringing on a new sand and increasing production; however, this operation which in mid-March had been expected to be completed in the first quarter of 2012 has encountered downhole difficulties and is now expected to be completed in the second quarter of 2012. In addition, we have incurred capital and operating costs higher than we expected primarily due to additional regulations imposed since the Deepwater Horizon incident and the requirement to perform sidetracks on two of the wells. The new wells helped us achieve production growth in 2011, and we forecast overall production and operating cash flow growth in 2012 due to new production from our Clipper property and from projected increases at our Telemark Hub. Production in the first quarter of 2012 is lower than in the fourth quarter of 2011 primarily due to the Telemark well recompletion discussed above which required us to take the well offline and normal production declines. While cash flows were lower than previously projected due to lower than expected production rates, delays in bringing on new production and higher capital costs, we continued our development operations by supplementing our cash flows from operating activities with funds raised through various transactions (see the Consolidated Statement of Cash Flows.) As of March 31, 2012, we had a working capital deficit of $267.9 million. To preserve our development momentum in the negative working capital environment that we experienced throughout 2011, we increased our term loans, issued convertible perpetual preferred stock, granted net profits interests ("NPIs" discussed below) to certain of our vendors, sold NPIs and dollar-denominated overriding royalty interests ("Overrides" discussed below) in our properties to investors, and entered into prepaid swaps against our future production that provided cash proceeds to us at closing. We 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 begin during 2013 with production commencing in 2014. A similar arrangement is in place for the Octabuoy topside equipment, which is being constructed by the same company in China. We have continued this practice of managing capital and seeking financing proceeds in a negative working capital environment during the first quarter of 2012. We increased our term loans, sold NPIs and Overrides in our properties to investors, and entered into prepaid swaps against our future production that provided cash proceeds to us at closing. As operator of all of our projects that require cash commitments within the next twelve months and beyond, 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 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, on a temporary basis, our capital commitments to our available capital resources. Our planned operations for the remainder of 2012 reflect our expectations for production based on actual production history, new production expected to be brought online, the development delays at Telemark and Gomez Hubs 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 new production online, and the higher cost of servicing our additional financing and other obligations. 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, our ability to monetize our properties and future production through asset sales and financial derivatives, 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 effect 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 other financing sources; however, there is no assurance that we will be able to do so in the future if required to meet any short-term liquidity needs. Despite continued production delays, we believe we can continue to meet our obligations for at least the next twelve months through a combination of cash flow from operations, continuing to sell or assign interests in our properties and selling forward our production through the financial derivatives markets, and if necessary, further delaying certain development activities. 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 actual results. A substantial portion of our total proved reserves are undeveloped and recognition of such reserves requires us to expect that capital will be 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, 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 severe 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 material 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. We cannot predict future changes in laws and regulations governing oil and gas operations in the Gulf of Mexico. New regulations issued since the Deepwater Horizon 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. 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 requirements. 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 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 requirements of our debt and other obligations.

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 unprecedented 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. Because of the moratoriums and permitting delays, it has taken until the first quarter of 2012 for us to bring to production the three additional wells at the Telemark Hub and the two wells planned for the Gomez Hub have been postponed. The new Telemark wells have taken longer to complete and bring to production than originally planned and one of them has not produced at rates that were previously projected. We are currently

recompleting this well in hopes of bringing on a new sand and increasing production; however, this operation which in mid-March had been expected to be completed in the first quarter of 2012 has encountered downhole difficulties and is now expected to be completed in the second quarter of 2012. In addition, we have incurred capital and operating costs higher than we expected primarily due to additional regulations imposed since the Deepwater Horizon incident and the requirement to perform sidetracks on two of the wells.

The new wells helped us achieve production growth in 2011, and we forecast overall production and operating cash flow growth in 2012 due to new production from our Clipper property and from projected increases at our Telemark Hub. Production in the first quarter of 2012 is lower than in the fourth quarter of 2011 primarily due to the Telemark well recompletion discussed above which required us to take the well offline and normal production declines. While cash flows were lower than previously projected due to lower than expected production rates, delays in bringing on new production and higher capital costs, we continued our development operations by supplementing our cash flows from operating activities with funds raised through various transactions (see the Consolidated Statement of Cash Flows.)

As of March 31, 2012, we had a working capital deficit of $267.9 million. To preserve our development momentum in the negative working capital environment that we experienced throughout 2011, we increased our term loans, issued convertible perpetual preferred stock, granted net profits interests ("NPIs" discussed below) to certain of our vendors, sold NPIs and dollar-denominated overriding royalty interests ("Overrides" discussed below) in our properties to investors, and entered into prepaid swaps against our future production that provided cash proceeds to us at closing. We 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 begin during 2013 with production commencing in 2014. A similar arrangement is in place for the Octabuoy topside equipment, which is being constructed by the same company in China. We have continued this practice of managing capital and seeking financing proceeds in a negative working capital environment during the first quarter of 2012. We increased our term loans, sold NPIs and Overrides in our properties to investors, and entered into prepaid swaps against our future production that provided cash proceeds to us at closing.

As operator of all of our projects that require cash commitments within the next twelve months and beyond, 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 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, on a temporary basis, our capital commitments to our available capital resources.

Our planned operations for the remainder of 2012 reflect our expectations for production based on actual production history, new production expected to be brought online, the development delays at Telemark and Gomez Hubs 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 new production online, and the higher cost of servicing our additional financing and other obligations.

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, our ability to monetize our properties and future production through asset sales and financial derivatives, 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 effect 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 other financing sources; however, there is no assurance that we will be able to do so in the future if required to meet any short-term liquidity needs. Despite continued production delays, we believe we can continue to meet our obligations for at least the next twelve months through a combination of cash flow from operations, continuing to sell or assign interests in our properties and selling forward our production through the financial derivatives markets, and if necessary, further delaying certain development activities.

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 actual results. A substantial portion of our total proved reserves are undeveloped and recognition of such reserves requires us to expect that capital will be 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, 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 severe 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 material 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. We cannot predict future changes in laws and regulations governing oil and gas operations in the Gulf of Mexico. New regulations issued since the Deepwater Horizon 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. 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 requirements.

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 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 requirements of our debt and other obligations.