Edgar Filing: ENERGY PARTNERS LTD

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-16179

Energy Partners, Ltd.

(Exact name of registrant as specified in its charter)


Delaware		72-1409562
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

201 St. Charles Avenue, Suite 3400 New Orleans, Louisiana		70170
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code:

504-569-1875

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of exchange on which registered
Common Stock, Par Value $0.001 Per Share		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act). Yes ¨ No x

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes x No ¨

The aggregate market value of the common stock held by non-affiliates of the registrant at June 30, 2010 (the registrant’s most recently completed second fiscal quarter) based on the closing stock price as quoted on the New York Stock Exchange on that date was $353,060,074. As of February 25, 2011, there were 40,175,161 shares of the registrant’s common stock, par value $0.001 per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Proxy Statement for the Annual Meeting of Stockholders of Energy Partners, Ltd. expected to be held on May 19, 2011

TABLE OF CONTENTS


		Page
PART I

Item 1.	Business		1

	Cautionary Statement Concerning Forward Looking Statements		20

Item 1A.	Risk Factors		21

Item 1B.	Unresolved Staff Comments		42

Item 2.	Properties		42

Item 3.	Legal Proceedings		42

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		43

Item 6.	Selected Financial Data		45

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		45

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		67

Item 8.	Financial Statements and Supplementary Data		69

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		115

Item 9A.	Controls and Procedures		116

Item 9B.	Other Information		116

PART III

Item 10.	Directors, Executive Officers and Corporate Governance		117

Item 11.	Executive Compensation		117

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		117

Item 13.	Certain Relationships and Related Transactions, and Director Independence		117

Item 14.	Principal Accountant Fees and Services		117

PART IV

Item 15.	Exhibits and Financial Statement Schedules		118

Statements we make in this Annual Report on Form 10-K (“Annual Report”) which express a belief, expectation or intention, as well as those that are not historical fact, may constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Our forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the headings “Cautionary Statement Concerning Forward-Looking Statements” and “Risk Factors” in Items 1 and 1A of Part 1 of this Annual Report.

PART I

Item 1.

Business

Overview

Energy Partners, Ltd. (referred to herein as “we,” “our,” “us” or the “Company”) was incorporated as a Delaware corporation in January 1998 and operates as an independent oil and natural gas exploration and production company based in New Orleans, Louisiana and Houston, Texas. Our current operations are concentrated in the U.S. Gulf of Mexico shelf focusing on state and federal waters offshore Louisiana, which we consider our core area. We have focused on acquiring and developing assets in this region, as it is characterized by established exploitation, development and exploration opportunities in both productive horizons and deeper geologic formations. Our management professionals and technical staff have considerable geological, geophysical and operational experience that is specific to the Gulf of Mexico and Gulf Coast region, and we have acquired and developed geophysical and geological data relating to these areas. We intend to pursue capital-efficient development and exploration activities in our core area, as well as identify acquisition opportunities that leverage our operational strengths. As of December 31, 2010, we had estimated proved reserves of 27.4 million barrels of oil equivalent, or Mmboe, of which 63% were oil and 93% were proved developed. Of these proved developed reserves, 63% were oil reserves.

We produce both oil and natural gas. Throughout this Annual Report, when we refer to “total production,” “total reserves,” “percentage of production,” “percentage of reserves,” or any similar term, we have converted our natural gas reserves or production into barrel equivalents. For this purpose, six thousand cubic feet of natural gas is equal to one barrel of oil, which is based on the relative energy content of natural gas and oil. Natural gas liquids are aggregated with oil in this Annual Report.

For definitions of oil and natural gas terms used frequently in this Annual Report, please refer to the “Glossary of Oil and Natural Gas Terms” following the index of Exhibits in Item 15 of Part IV of this Annual Report.

Recent Events

On February 14, 2011, we acquired an asset package consisting of certain shallow-water Gulf of Mexico shelf oil and natural gas interests surrounding the Mississippi River delta and a related gathering system (the “ASOP Properties”) from Anglo-Suisse Offshore Partners, LLC (“ASOP”) for $200.7 million in cash, subject to customary adjustments to reflect an economic effective date of January 1, 2011 (the “ASOP Acquisition”). As of December 31, 2010, the ASOP Properties had estimated proved reserves of approximately 8.1 Mmboe, of which 84% were oil and 76% were proved developed reserves. Of these proved developed reserves, 88% were oil reserves. The ASOP Acquisition was financed with the proceeds from the sale of $210 million in aggregate principal amount of 8.25% senior notes due 2018 (the “8.25% Notes”) offered to qualified institutional buyers pursuant to Rule 144A promulgated under the Securities Act of 1933, as amended (the “Securities Act”), and to persons outside the United States pursuant to Regulation S promulgated under the Securities Act. After deducting the initial purchasers’ discount and estimated offering expenses, the Company realized net proceeds of approximately $202 million.

Competitive Strengths

High Quality Asset Base with Significant Exploitation and Exploration Potential. We believe our asset base is characterized by lower-risk properties that have predictable well control and production profiles. Our pro forma net proved reserves reflecting the ASOP Acquisition as of December 31, 2010 were 89% proved developed, which provides significant production visibility. Our fields offer significant development and exploration potential, with multiple producing zones and unexplored deeper horizons.

Oil-Weighted Reserves and Production. We believe we are more oil-focused in both our reserves and production as compared to many of our peers. After giving effect to the ASOP Acquisition, our pro forma net proved reserves at December 31, 2010 were approximately 68% oil, and our pro forma net average daily production for the quarter ended December 31, 2010 was 60% oil. Given the current commodity price environment and resulting disparity between oil and natural gas prices on a barrel of oil equivalent basis, we believe our high percentage of oil reserves compared to our overall reserve base provides us an economic advantage. Additionally, the production decline curve of oil is typically lower than a comparable natural gas decline curve, resulting in longer term production from current reserves.

Operating Control. After giving effect to the ASOP acquisition, we operate properties that contain approximately 80% of our proved reserves. As the operator of a property, we are afforded greater control of the optimization of production, the timing and amount of capital expenditures and the operating parameters and costs of our projects. As such, we are able to align capital expenditures with cash flow because we are generally able to adjust drilling plans in response to changes in commodity prices. Additionally, we believe that we are one of the lowest-cost operators in the region and are therefore able to maximize cash flows from our operated reserves.

Geographically Focused Properties in the Gulf of Mexico. We operate geographically focused properties located in the Gulf of Mexico shelf, which gives us the opportunity to minimize logistical costs and reduce staff. Our experience in the Gulf of Mexico, and particularly offshore Louisiana, has led us to focus our efforts in that particular region, where we are familiar with the fields, drilling and production trends and where we have amassed an extensive library of geologic information. We own an extensive high-quality 3-D seismic database that is primarily focused on our core area and currently covers approximately 11,700 square miles. This seismic data assists us in identifying attractive development and exploration drilling opportunities that adhere to our capital-efficient development strategies. We have recently reprocessed the 3-D seismic data covering our East Bay and South Timbalier 26 fields, and our initial evaluation indicates that this data will enable us to better image deeper prospective horizons below existing field pays as well as the shallower producing horizons. Drilling activity in the Gulf of Mexico shelf, as compared to deepwater drilling activities, has not been as severely impacted by the regulatory changes resulting from the explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico in April 2010. Over 26% of our developed net acreage is located in Louisiana state waters, which are not regulated by the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”) and where there have been no delays in the permitting process for drilling.

Experienced Management and Significant Technical Expertise. We have an experienced and technically-adept management team, averaging more than 20 years of industry experience among our top seven executives. We have also built a strong technical staff of geologists and geophysicists, field operations managers and engineers to handle all aspects of our exploitation, exploration, production and decommissioning activities.

Business Strategy

Pursue Capital Efficient Development in Core Areas. Our current producing asset base in the Gulf of Mexico shelf includes a large inventory of low-risk exploitation opportunities, as well as exploration prospects with multiple objectives and follow up opportunities. In 2010, we completed 19 workovers and drilled five sidetracks and five drill wells, with a 76% success rate. Our fiscal year 2011 capital budget is $110 to $125 million (excluding the cost of acquiring the ASOP properties), $80 million of which is allocated to development of our existing Gulf of Mexico shelf asset base primarily in the East Bay and South Timbalier field areas, $20 million of which is allocated to exploration projects and an additional $10 million to $25 million of which is allocated to development projects within the recently acquired ASOP Properties. We also plan to spend approximately $17 million in 2011 on plugging, abandonment and other decommissioning activities. In our pre-acquisition fields, we will continue to focus on low-risk development projects, as well as a small number of high quality, high potential exploration prospects. We believe the ASOP Properties will enhance our exploitation strategy to increase production from legacy fields and will provide us with substantial incremental exploration opportunities within our core area.

Target Acquisition Opportunities to Replace Reserves and Leverage Operational Strengths. We continually review and monitor opportunities to acquire producing properties, leasehold acreage and drilling prospects in and around our core areas of operation so that we can act quickly as acquisition opportunities become available. We intend to focus our acquisition strategy on operated Gulf of Mexico shelf assets that are characterized by production-weighted reserves, seismic coverage and operated positions, while allowing us to maintain a conservative capital structure. We intend to use acquisitions of this type as a key method to replace and grow reserves and production, as we believe this strategy increases production and cash flow visibility while reducing dry hole and exploration risk. We believe our expertise in the Gulf of Mexico shelf and in plugging and abandonment operations allows us to effectively evaluate acquisitions and to operate the properties we eventually acquire.

Maintain Financial Discipline. We are committed to maintaining a conservative financial position, sufficient liquidity and a strong balance sheet. We have $150.0 million available under our new $250 million credit facility we entered into concurrently with the consummation of the ASOP Acquisition on February 14, 2011 (the “new credit facility”). In order to maintain financial flexibility, we generally plan to fund our initial 2011 fiscal year exploration and development capital budget entirely with cash flow from operations. Additionally, our operational control enables us to manage the timing of a substantial portion of our capital investments.

Retain Cost Leadership, with Continued Improvement. We emphasize identifying opportunities to reduce our costs in connection with our efforts to find, develop and produce our oil and natural gas reserves. We are one of the lowest cost operators among our public Gulf of Mexico peers, based on lease operating expense and general and administrative expense per Boe of production. We have reduced these costs per Boe by approximately 35% since 2008 by more efficiently allocating labor and transportation costs, reducing non-technical personnel and continuing our plugging, abandonment and decommissioning program to reduce lease operating expenses.

Capitalize on Competency in Plugging and Abandonment. We have established a proactive, multi-year plan to plug, abandon and decommission depleted wells and associated infrastructure. Gary Hanna, our chief executive officer who joined us in September 2009, has significant experience in conducting these types of operations and has supplemented our staff to accomplish this objective. With our core competency in plugging, abandonment and other decommissioning operations, we expect to reduce our lease operating expense over time by removing idle infrastructure and its associated maintenance costs.

Where You Can Find More Information

We maintain a website at www.eplweb.com that contains information about us, including links to our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all related amendments as soon as reasonably practicable after providing such reports to the Securities and Exchange

Commission (the “SEC”). In addition, our website contains our Corporate Governance Guidelines and the charters for our Audit, Compensation and Nominating and Governance Committees. Copies of this information are also available by writing to our Corporate Secretary at 201 St. Charles Avenue, Suite 3400, New Orleans, Louisiana 70170. Our website and the information contained in it and connected to it shall not be deemed incorporated by reference into this Annual Report or any other filing that we make with the SEC.

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934 (as amended, the “Exchange Act”). The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov.

Properties

As of December 31, 2010, we had working interests in 19 producing fields located in the Gulf of Mexico shelf region, including larger legacy fields and smaller fields as follows:

•

our East Bay producing field on the southern flank of the Mississippi River delta;

•

three producing fields in the vicinity of the Bay Marchand salt dome (the “Greater Bay Marchand area”) and in close proximity to each other; and

•

15 smaller producing fields offshore Louisiana.

Our East Bay field comprised approximately 21% of our production during the year ended December 31, 2010 and 54% of our proved reserves at December 31, 2010. It is comprised of the South Pass 24 and 27 fields and is located 89 miles southeast of New Orleans, near the mouth of the Mississippi River. It contains 230 producing wells located along the coastline and in water depths ranging up to approximately 70 feet. We operate this field and own an average 97% working interest in our acreage position in this area. Our leasehold area covered 40,880 gross acres (39,586 net acres) as of December 31, 2010. During 2011, we plan to concentrate on exploitation opportunities in the East Bay field and to drill below 14,000 feet subsea using newly-reprocessed seismic data.

Our Greater Bay Marchand area comprised approximately 52% of our production during the year ended December 31, 2010 and 35% of our proved reserves at December 31, 2010. Our key assets in this area include the South Timbalier 26 and 41 fields and the Bay Marchand field located approximately 60 to 72 miles south of New Orleans in water depths of 73 feet or less. We own working interests ranging from 13% to 100% in the Greater Bay Marchand area. We operate the South Timbalier 26 and 41 blocks. During 2011, we plan to concentrate on exploitation opportunities in South Timbalier 26 with the benefit of newly-reprocessed seismic data.

The 15 smaller producing fields offshore Louisiana comprised approximately 16% of our production during the year ended December 31, 2010 and 8% of our proved reserves at December 31, 2010. These properties are located in water depths ranging from 18 to 225 feet with working interests ranging from 20% to 100%.

The ASOP Properties acquired on February 14, 2011 comprise three producing complexes located in the Gulf of Mexico shelf region offshore Louisiana surrounding the Mississippi River delta. The West Delta complex, a legacy producing area, comprised approximately 60% of the ASOP Properties’ reserves at December 31, 2010 and is located 62 miles south, southeast of New Orleans. It contains 23 producing wells in water depths ranging from 29 to 87 feet and is comprised of five lease blocks. We operate the West Delta complex and own a working interest of 100% of the acreage position in this area. The South Pass complex

comprised approximately 14% of the ASOP Properties’ reserves at December 31, 2010 and is located 96 miles southeast of New Orleans. It contains four producing wells in water depths of approximately 300 feet and is comprised of one field. The South Pass complex is operated by Energy XXI, and we own working interests ranging from 44% to 70% of the acreage position in this area. The Main Pass complex comprised approximately 26% of the ASOP Properties’ reserves at December 31, 2010 and is located 98 miles southeast of New Orleans. It contains 32 producing wells in water depths of approximately 250 feet and is comprised of two fields. The complex is operated by Apache, and we own a working interest of 33% of the acreage position in this area.

As of December 31, 2010, after giving effect to the ASOP Acquisition, we had an interest in 333 producing wells in 27 producing fields. These producing fields include three legacy operating areas. All of our properties, including the ASOP Properties, are predominantly located in the Gulf of Mexico shelf. This concentration facilitates our ability to manage the operated fields efficiently and provide economies of scale in our core operating area. In addition, the ASOP Properties complement our pre-acquisition reserve profile and increase our proved developed producing reserves, as well as the percentage of oil comprising our proved reserves. We believe there is significant exploitation and exploration potential with respect to the ASOP Properties that we can realize by leveraging our technical and operational expertise.

As of December 31, 2010, we also owned interests in 21 undeveloped blocks and one producing lease in the deepwater Gulf of Mexico area. These deepwater Gulf of Mexico properties comprised approximately 10% of our production during the year ended December 31, 2010 and 3% of our proved reserves at December 31, 2010. Our working interests in our leases in this area ranged from 15% to 33%. Our deepwater assets do not fit with our long-term strategy, and there are no current plans to develop these interests. As such, we may monetize or trade these assets.

Oil and Natural Gas Reserves

In December 2008, the SEC issued a final rule, “Modernization of Oil and Gas Reporting,” which amended its oil and gas reserves estimation and disclosure requirements. The new requirements were codified into the Accounting Standards Codification (“ASC”) Topic 932, “Extractive Activities—Oil and Gas” (“ASC 932”), in January 2010, and had the effect of, among other things, modifying the prices used to estimate reserves for SEC disclosure purposes to an average price based upon the prior twelve month period rather than the year-end price. See Note 20 “Supplementary Oil and Natural Gas Disclosures—(Unaudited)” of the consolidated financial statements in Part II, Item 8 of this Annual Report for additional information regarding changes in reporting related to oil and natural gas reserves as a result of ASC 932. The revised rule was effective January 1, 2010 for reporting December 31, 2009 annual oil and natural gas reserve information. We adopted the provisions of the final rule in connection with the filing of our annual report for the year ended December 31, 2009.

The following table presents our estimated net proved oil and natural gas reserves and the estimated future net revenues and cash flows related to our reserves at December 31, 2010, 2009 and 2008. Our estimates of proved reserves are based on reserve reports prepared as of December 31, 2010 by Netherland, Sewell & Associates, Inc. (“NSAI”) and Ryder Scott Company, LP (“Ryder Scott”), independent petroleum engineers. Neither PV-10 nor the standardized measure of discounted future net cash flows shown in the table is intended to represent the current market value of the estimated oil and natural gas reserves that we own. Note 20 “Supplementary Oil and Natural Gas Disclosures—(Unaudited)” of the consolidated financial statements in Part II, Item 8 of this Annual Report provides important additional information about our proved oil and natural gas reserves.

PV-10 may be considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. Because the

standardized measure is dependent on the unique tax situation of each company, our calculation may not be comparable to those of our competitors. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis.


	As of December 31,
	2010		2009		2008
	(dollars in thousands)
Total estimated net proved reserves (1):
Oil (Mbbls)		17,223		19,923		21,637
Natural gas (Mmcf)		61,251		67,378		90,808
Total (Mboe)		27,431		31,153		36,771
Net proved developed reserves (2):
Oil (Mbbls)		15,974		15,026		17,052
Natural gas (Mmcf)		56,410		57,139		79,413
Total (Mboe)		25,376		24,549		30,288
Net proved undeveloped reserves:
Oil (Mbbls)		1,249		4,897		4,585
Natural gas (Mmcf)		4,841		10,239		11,395
Total (Mboe)		2,055		6,604		6,483
Estimated future net revenues before income taxes (3)	$	565,922	$	534,771	$	557,660
Present value of estimated future net revenues before income taxes (PV-10) (3)(4)(6)	$	413,066	$	395,997	$	425,247
Standardized measure of discounted future net cash flows (5)(6)	$	359,458	$	393,802	$	416,171

(1)

The table does not include reserves associated with the ASOP Properties, which we acquired on February 14, 2011. As of December 31, 2010, the ASOP Properties had estimated proved reserves of approximately 8.1 Mmboe, of which 84% were oil and 76% were proved developed reserves. Of these proved developed reserves, 88% were oil reserves. All estimates of proved reserves with respect to the ASOP Properties contained in this Annual Report are based on reserve reports prepared as of December 31, 2010 by NSAI.

(2)	Net proved developed non-producing reserves as of December 31, 2010 (6,484 Mbbls and 38,334 Mmcf) were 12,873 Mboe, or 47% of our total proved reserves.

(3)

The December 31, 2010 and 2009 amounts were calculated using oil prices of $77.85 and $57.70 per barrel, respectively, and natural gas prices of $4.54 and $3.96 per Mcf, respectively, held constant for the life of the reserves, computed in accordance with ASC 932, based on the unweighted, arithmetic average of the closing price on the first day of each of the twelve months during the fiscal year. The December 31, 2008 amount was calculated using a period-end oil price of $44.77 per barrel and a period-end natural gas price of $6.05 per Mcf, in accordance with the SEC rules in effect at that time.

(4)	The present value of estimated future net revenues attributable to our reserves was prepared using constant prices, determined in the manner described in footnote (3), discounted at a rate of 10% per year on a pre-tax basis.

(5)	The standardized measure of discounted future net cash flows represents the present value of future cash flows after income taxes discounted at 10% per year, as calculated in accordance with SEC guidelines and pricing.

(6)

PV-10 is a non-GAAP financial measure as defined by the SEC. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. Because the standardized measure is dependent on the unique tax situation of each company, our calculation may not be comparable to those of our competitors. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis.

As of December 31, 2009, our proved undeveloped reserves (“PUDs”) totaled 4.9 Mmbbls of oil and 10,239 Mmcf of natural gas, for a total of 6.6 Mmboe. Included in these PUDs are 4.2 Mmboe that have been included in proved undeveloped reserves for longer than five years. Our PUDs at December 31, 2009 were associated with infill exploitation reserves in proven reservoirs which generally are up-dip reserves and/or reserves where the existing wellbore is not mechanically viable, requiring a new or replacement wellbore to enable production. During 2010, we converted 0.3 Mmboe of PUDs to proved developed reserves. As a result of changes in our strategic focus during 2010 and the resulting reallocation of financial resources and technical personnel to higher potential organic and acquisition-related opportunities, including our ASOP Acquisition which closed on February 14, 2011, our plans and expectations have changed with respect to certain of the PUDs existing as of December 31, 2009. As a result, our PUDs as of December 31, 2010 reflect a decrease of approximately 4.3 Mmboe related to PUDs aged greater than five years for which funds were not committed in our 2011 development plan. We expect our remaining PUDs as of December 31, 2010 of 2.1 Mmboe to begin converting from proved undeveloped to proved developed as the planned development projects begin in 2011. Of the seven planned future development projects related to our PUDs, consisting of five sidetracks and two horizontal wells, three sidetracks and both horizontal wells are part of our committed 2011 development plan. The remaining two sidetracks are awaiting depletion of the current producing zone and are projected to occur in 2012. We project future development costs relating to the development of the PUDs remaining at December 31, 2010 to be approximately $21.3 million in 2011, $12.1 million in 2012, $0.5 million in 2013, $4.0 million in 2014, and $2.5 million thereafter.

Our Vice President, Reserves, is the technical person primarily responsible for overseeing the preparation of our reserve estimates and for compliance with our policies. He is a registered petroleum engineer with extensive experience in reservoir analysis and reports directly to our executive management. At the end of each year, our reserve estimates are prepared by outside petroleum engineering firms. As of December 31, 2010, our estimates of proved reserves are based on reserve reports prepared by the independent petroleum engineering firms NSAI and Ryder Scott, both nationally recognized engineering firms.

We have internal controls in place to provide reasonable assurance of compliance with SEC rules in the determination of our reserve estimates. These controls include:

•

corporate policies which require reserve estimates to be in compliance with SEC guidelines;

•

data on new discoveries is reviewed by the Vice President, Reserves, and our outside engineering firms for evaluation and incorporation into our reserve estimates;

•

year-end reserve estimates are reviewed by our Vice President, Reserves, and our chief executive officer and other senior management; and

•

revisions are communicated to our Board of Directors.

The estimates of the oil and natural gas reserves of the ASOP Properties as of December 31, 2010 included in this Annual Report are based on reserve reports prepared by NSAI but were not subject to the internal controls summarized above.

As an operator of domestic oil and gas properties, we have filed Department of Energy Form EIA-23, “Annual Survey of Oil and Gas Reserves,” as required by Public Law 93-275. The differences between the reserves as reported on Form EIA-23 and those reported herein are attributable to the fact that Form EIA-23 requires that an operator report the total reserves attributable to wells that it operates, without regard to percentage ownership and excluding non-operated wells in which it owns an interest.

The table below sets forth production information for each field that contains 15% or more of our total proved reserves as of December 31, 2010.


	Years Ended December 31,
	2010		2009		2008
East Bay:
Oil (Mbbls)		1,031		837		885
Natural gas (Mmcf)		78		295		604
Total (Mboe)		1,044		886		986
South Timbalier 26:
Oil (Mbbls)		362		440		431
Natural gas (Mmcf)		1,167		1,394		815
Total (Mboe)		557		672		567

Costs Incurred in Oil and Natural Gas Activities

The following table sets forth the costs incurred associated with finding, acquiring and developing our proved oil and natural gas reserves.


	Years Ended December 31,
	2010		2009		2008
	(In thousands)
Acquisitions—Proved	$	—	$	—	$	—
Acquisitions—Unproved		623		85		20,925
Exploration		31,463		2,477		56,202
Development (1)		25,643		8,815		127,948

Costs incurred	$	57,729	$	11,377	$	205,075

(1)

Includes asset retirement obligations incurred associated with finding, acquiring and developing our proved oil and natural gas reserves of $0.1 million during the year ended December 31, 2010. Includes asset retirement obligations incurred associated with finding, acquiring and developing our proved oil and natural gas reserves of $13.4 million during the year ended December 31, 2008. No asset retirement obligations were incurred associated with finding, acquiring and developing our proved oil and natural gas reserves during the year ended December 31, 2009.

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2010.


	Total Productive Wells
	Gross		Net
Oil		220		170
Natural gas		54		32

Total		274		202

Productive wells consist of producing wells and wells capable of production, including oil wells awaiting connection to production facilities and natural gas wells awaiting pipeline connections to commence deliveries. Thirty gross oil wells and six gross natural gas wells have dual completions.

In this Annual Report, when referring to wells and acreage, “gross” refers to the total wells or acres in which we have a working interest and “net” refers to gross wells or acres multiplied by our working interest.

Acreage

The following table sets forth information relating to acreage held by us as of December 31, 2010. Developed acreage is assigned to producing wells.


	Gross Acreage		Net Acreage
Developed:
Gulf of Mexico Shelf		114,282		83,706
Deepwater Gulf of Mexico		5,760		1,600
Other		1,085		349

Total		121,127		85,655

Undeveloped:
Gulf of Mexico Shelf		105,681		103,180
Deepwater Gulf of Mexico		115,200		30,303
Other		3,527		456

Total		224,408		133,939

We continually assess our undeveloped lease inventory for exploration opportunities and, where appropriate, develop strategies to maintain our inventory by allocating resources to such leases or arranging for the participation of others, including farm-outs and the use of prospect generation consulting geologists. We currently have no plans to continue developing strategic opportunities for leases covering 69% of the acreage expiring in 2011. As of December 31, 2010, the net book value of the leases expiring in 2011 and 2012 is $0.6 million and $0.4 million, respectively. Leases covering 28% of our undeveloped net acreage expire in 2011 (primarily deepwater and central and western Gulf of Mexico), 12% expire in 2012, 42% expire in 2013, 3% expire in 2014, 7% expire in 2015 and 8% expire thereafter.

Drilling Activity

Drilling activity refers to the number of wells completed at any time during the applicable fiscal years, regardless of when drilling was initiated. The term “completed” refers to the installation of permanent equipment for the production of oil or natural gas. During the year ended December 31, 2010, we completed 19 gross (16.2 net) recompletion operations of which 14 gross (11.2 net) were successful; 9 gross (6.4 net) exploratory drilling operations of which 7 gross (4.9 net) were successful; and 1 (gross and net) development well which was successful. Our 2009 development activities consisted of five gross (3.8 net) successful workovers. We executed one exploration well late in 2009 which was not completed until January 2010. We drilled no development or exploration wells that were completed in 2009. In 2008, we drilled 13 gross (10.6 net) development wells, all of which were productive. Also in 2008, we drilled four gross (0.9 net) exploration wells, of which three gross (0.7 net) were productive and one gross (0.2 net) was non-productive.

Title to Properties

Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements, mechanics’ and materialman’s liens, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with the use of our properties or the operation of our business.

We believe that we have satisfactory title to, or rights in, all of our properties. As is customary in the oil and natural gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties.

We investigate title prior to the consummation of an acquisition of producing properties and before the commencement of drilling operations on undeveloped properties. We have obtained or conducted a thorough title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and natural gas industry.

Regulatory Matters

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Regulation of Natural Gas Gathering. Section 1(b) of the Natural Gas Act of 1938, as amended (the “NGA”), exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”) as a natural gas company under the NGA. We believe that our natural gas pipelines and appurtenant facilities meet the tests the FERC has historically used to establish a facility’s status as a gathering facility not subject to regulation as a natural gas company under the NGA. However, the distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is the subject of on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by the FERC, the courts, or Congress. Natural gas gathering facilities and operations may, at some point in the future, receive greater regulatory scrutiny at both the state and federal levels. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Regulation of Offshore Gathering Facilities. Our gathering systems gather gas and oil on the Outer Continental Shelf (the “OCS”) and in Louisiana. Our gathering systems are subject to the jurisdiction of the applicable state regulatory agencies to the extent that those gathering systems traverse state land and/or waters. State regulation of gathering facilities generally includes a variety of safety, environmental, nondiscriminatory take, and common purchaser requirements, and complaint-based rate regulation.

The gathering systems are also subject to the jurisdiction of the BOEMRE, because they traverse the OCS pursuant to BOEMRE-issued easements. The BOEMRE issued a final rule, effective August 18, 2008, that implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines on the OCS. We cannot predict the ultimate impact of these regulatory changes to our OCS natural gas operations. We do not believe that we would be affected by any such regulatory changes on a materially different basis than other gathering lines operating on the OCS with whom we compete.

Regulation of Onshore Gathering Facilities. Our onshore natural gas gathering operations are subject to ratable take and common purchaser statutes in the states in which we operate. The common purchaser statutes

generally require our gathering pipelines to purchase or take without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Louisiana and Texas have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. The rates we charge for gathering in Texas and Louisiana are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.

Though our natural gas gathering facilities are not subject to regulation by the FERC under the NGA, as the owner and operator of these facilities, we may be subject to certain annual natural gas transaction reporting requirements and daily scheduled flow and capacity posting requirements imposed by FERC depending on the volume of natural gas transactions and flows on our facilities in a given period. See the discussion of “—Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.”

In 2007, Texas enacted new laws regarding rates, competition and confidentiality for natural gas gathering and transmission pipelines (the “Competition Statute”) and new informal complaint procedures for challenging determinations of lost and unaccounted for gas by gas gatherers, processors and transporters (the “LUG Statute”). The Competition Statute gives the Railroad Commission of Texas (the “RRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and intrastate transportation pipelines in formal rate proceedings. This statute also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The Competition Statute also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation, or gathering of natural gas. The LUG Statute modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. Such statute also extends the types of information that can be requested, provides producers with an annual audit right, and provides the RRC with the authority to make determinations and issue orders in specific situations. Both the Competition Statute and the LUG Statute became effective September 1, 2007. We cannot predict what effect, if any, these statutes might have on our future operations in Texas.

Regulation of Sales of Natural Gas and Natural Gas Liquids (“NGLs”). The price at which we buy and sell natural gas and NGLs is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Future Trading Commission (“CFTC”). See below the discussion of “—Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities. In addition, pursuant to Order 704 (as defined below) some of our operations may be required to annually report to the FERC, starting May 1, 2009, information regarding natural gas purchase and sale transactions depending on the volume of natural gas purchased or sold during the prior calendar year. See below the discussion of “—Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.”

Regulation of Availability, Terms and Cost of Pipeline Transportation. Our processing operations and our marketing of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. The price and terms of access to pipeline transportation can be subject to extensive federal and, if a complaint is filed, state regulation. The FERC regularly proposes and implements new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of NGLs. We cannot predict the

ultimate impact of these regulatory changes to our natural gas production operations and our natural gas and NGL marketing operations. We do not believe that we would be affected by any such FERC action in a materially different manner than other natural gas producers and natural gas and NGL marketers with whom we compete.

The ability of our facilities to deliver natural gas into third party natural gas pipeline facilities is directly impacted by the gas quality specifications required by those pipelines. In 2006, the FERC issued a policy statement on provisions governing gas quality and interchangeability in the tariffs of interstate gas pipeline companies and a separate order declining to set generic prescriptive national standards. In its policy statement on gas quality and interchangeability, the FERC encouraged all natural gas pipelines subject to its jurisdiction to use certain interim guidelines issued by a group of industry representatives, headed by the Natural Gas Council (the “NGC+ Work Group”), as the common reference point for resolving gas quality and interchangeability issues. We do not believe that the adoption of gas quality and interchangeability standards that are in line with the NGC+ Work Group’s interim guidelines by a pipeline that either directly or indirectly interconnects with our facilities would materially affect our operations. We cannot predict, however, whether FERC will approve gas quality specifications that materially differ from the NGC+ Work Group’s interim guidelines for such an interconnecting pipeline.

Regulation of Transportation of Oil. Our wholly owned subsidiary, EPL Pipeline, L.L.C. (“EPL Pipeline”), is an interstate common carrier pipeline subject to regulation by the FERC under the Interstate Commerce Act (“ICA”). EPL Pipeline owns an approximately twelve-mile pipeline that runs between South Timbalier 26 and a portion of South Timbalier 41 on the Gulf of Mexico OCS to Bayou Fourchon, Louisiana. The ICA requires that we maintain a tariff on file with the FERC for this pipeline. The tariff sets forth the rate, which was established at a negotiated rate that has not been protested, as well as the rules and regulations governing this service. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits challenges to existing rates and authorizes the FERC to investigate such rates to determine whether they are just and reasonable. If, upon completion of an investigation, the FERC finds that the existing rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation and, in some cases, reparations for the two year period prior to the filing of a complaint.

Other Federal Laws and Regulations Affecting Our Industry

Energy Policy Act of 2005. The Energy Policy Act of 2005 (“EPAct 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. With respect to regulation of natural gas transportation, EPAct 2005 amended the NGA by increasing the criminal penalties available for violations of each Act. EPAct 2005 also added a new section to the NGA that provides the FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce, including our Company. EPAct 2005 also amended the NGA to add an anti-market manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC. In 2006, the FERC issued Order No. 670 (“Order 670”) to implement the anti-market manipulation provision of EPAct 2005. Order 670 makes it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit any statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any entity. Order 670 does not apply to activities that relate only to non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation

subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704 (as defined below) and daily scheduled flows. FERC’s anti-market manipulation rule and enhanced civil penalty authority reflect a significant expansion of its enforcement authority.

FERC Market Transparency Rules. In 2007, the FERC issued a final rule on annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such actions on a materially different basis than other natural gas companies with whom we compete.

Environmental Matters

General. Various federal, state and local laws and regulations governing the protection of the environment, such as the Oil Pollution Act of 1990 (“OPA”), the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (“CERCLA”), the Resource Conservation and Recovery Act, as amended (“RCRA”), the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and the Federal Clean Air Act, as amended (the “Clean Air Act”), affect our operations and costs. In particular, our exploration, development and production operations, our activities in connection with storage and transportation of oil and other hydrocarbons, and our use of facilities for treating, processing or otherwise handling hydrocarbons and related wastes may be subject to regulation under these and similar state laws and regulations. These laws and regulations:

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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, including the management and disposal of drill production water and wastes;

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limit or prohibit drilling and production activities on certain lands lying within wetlands and other protected areas and in ways that affect certain species;

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impose permitting, monitoring, and recordkeeping requirements and other regulatory controls; and

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impose substantial liabilities, including cleanup obligations, for pollution resulting from our operations.

Failure to comply with these laws and regulations may result in the assessment of significant administrative, civil and criminal fines and penalties, the incurrence of capital expenditures, delays in the development of projects, the imposition of remedial or corrective action obligations, or injunctive relief that could include limitations on, or the cessation of, certain of our operations. Changes in environmental laws and regulations occur regularly and the current trend is toward more stringent environmental regulation and legislation. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us, the imposition of additional requirements in the future could materially adversely affect our operations and financial position and the oil and natural gas industry in general.

Oil Pollution Act of 1990. The OPA, and regulations thereunder, impose significant liability on “responsible parties” for removal costs and damages resulting from oil spills into or upon navigable waters, adjoining shorelines, or in the exclusive economic zone of the United States. A “responsible party” includes the owner or

operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. OPA also requires that the lessee or permittee of the offshore area in which a covered offshore facility is located establish and maintain evidence of financial responsibility in the amount of $35.0 million ($10.0 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to an oil spill for which such person is statutorily responsible. The amount of required financial responsibility may be increased above the minimum amounts to an amount not exceeding $150.0 million depending on the risk represented by the quantity or quality of oil that is handled by the facility. We carry insurance coverage to meet these obligations, which we believe is customary for comparable companies in our industry. A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.

As a result of the explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico in April 2010, the U.S. Congress has considered legislation that could increase our obligations and potential liability under the OPA, including by eliminating the current cap on liability for damages and by increasing minimum levels of financial responsibility. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating in offshore waters, although the Secretary of Interior may increase this amount up to $150 million in certain situations. At least one proposed bill would have imposed new requirements on OCS operations, including increasing the minimum level of financial responsibility to $300.0 million. It is uncertain whether, and in what form, any such legislation will ultimately be adopted. We are not aware of the occurrence of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on us.

Superfund. CERCLA, also known as Superfund, and comparable state laws impose liability for response costs associated with releases of “hazardous substances” and damages to natural resources as a result of such releases, without regard to fault or the legality of the original act, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former “owner” or “operator” of a disposal site or a site where a release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances in the environment.

Under CERCLA, the term “hazardous substance” does not include “petroleum, including crude oil or any fraction thereof,” unless specifically listed or designated and the term does not include natural gas, NGLs, liquefied natural gas, or synthetic gas usable for fuel. While this “petroleum exclusion” lessens the significance of CERCLA to our operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance” in the course of our ordinary operations. We also currently own or lease properties that for many years have been used for the exploration and production of oil and natural gas. Although we and, to our knowledge, our predecessors have used operating and disposal practices that were standard in the industry at the time, “hazardous substances” may have been disposed or released on, under or from the properties owned or leased by us or on, under or from other locations where these wastes have been taken for disposal. At this time, we do not believe that we have any liability associated with any Superfund site, and we have not been notified of any claim, liability or damages under CERCLA.

Resource Conservation and Recovery Act. RCRA and comparable state laws impose detailed requirements relating to the handling, storage, treatment and disposal of hazardous waste. We routinely generate small quantities of hazardous waste in the ordinary course of our business that are subject to these requirements. These wastes are treated, stored and disposed of off-site at facilities that are permitted to manage them. At present, RCRA and many similar state statutes include a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. At various times in the past, proposals

have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the current exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

Clean Water Act. The Clean Water Act imposes restrictions and controls on the discharge of pollutants, including petroleum, produced water and other certain wastes into navigable waters, including coastal waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or, to a lesser degree, developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for significant civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants or unauthorized discharges of pollutants or fill material into wetlands or other waters. These statutes also impose liability for cleanup, restoration and damages on the parties responsible for those discharges for the costs of cleaning up any environmental damage caused by such release, for natural resource damages resulting from the release, and for mitigation or restoration related to the filling of wetlands and other waters. We are subject to the Clean Water Act’s permitting requirements for discharges associated with exploration and development activities. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

Safe Drinking Water Act. The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control Program, authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In Louisiana and Texas, no underground injection may take place except as authorized by permit or rule. We currently own and operate various underground injection wells. Failure to comply with our permits could subject us to civil and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

National Marine Sanctuary Act, Marine Mammal Protection Act, Migratory Bird Treaty Act, and Endangered Species Act. Certain federal laws, including the National Marine Sanctuary Act, the Marine Mammal Protection Act , the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated marine areas and marine species. These laws and their state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected plants and animals, including damage to their habitats. Further, if such species are located in an area in which we conduct operations, our operations could be prohibited, restricted, or delayed, or we could be required to implement expensive mitigation measures.

In addition, Executive Order 13158 (Marine Protected Areas), issued in 2000, directs federal agencies to strengthen existing Marine Protected Areas (“MPAs”), establishes new MPAs, and develops a national system of MPAs. This order could adversely affect our operations by restricting areas in which we may carry out future exploration or production activities and/or cause us to incur increased operating expenses. In addition, BOEMRE permit approvals are conditioned on the collection and removal of debris resulting from activities related to exploration, development and production of offshore leases in order to prevent harm to marine species. The BOEMRE also issues Notices to Lessees and Operators (“NTLs”) that provide guidance on the implementation of and compliance with Outer Continental Shelf Lands Act (“OCSLA”) regulations. The BOEMRE has issued numerous NTLs relating to the prevention of harm to marine species, with which we must comply.

Consideration of Environmental Issues in Connection with Governmental Approvals. Our operations frequently require federal licenses, permits, and/or other governmental approvals. Several federal statutes, including OCSLA, the National Environmental Policy Act, and the Coastal Zone Management Act require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. The environmental review process required under these laws can be costly and time-consuming and could result in the delay or prohibition of our planned activities.

Lead-Based Paints. Various pieces of equipment and structures owned by us have been coated with lead-based paints as was customary in the industry at the time these pieces of equipment were fabricated and constructed. These paints may contain lead at a concentration high enough to be considered a regulated hazardous waste when removed. If we need to remove such paints in connection with maintenance or other activities and they qualify as a regulated hazardous waste, this would increase the cost of disposal. High lead levels in the paint may also require us to institute certain administrative and/or engineering controls required by the Occupational Safety and Health Act and the BOEMRE to ensure worker safety during paint removal.

Clean Air Act. Our operations utilize equipment that emits air pollutants subject to the federal Clean Air Act and state air pollution control laws. These laws limit the emissions of regulated pollutants from such equipment and, in some instances, require the installation and operation of pollution control equipment to achieve these emissions limitations and meet ambient air quality standards. These laws also require us to maintain operating permits for existing equipment and obtain construction permits for new and modified equipment. We could be required to incur costs in the future for additional air pollution control equipment, although we do not believe that such requirements will have a material adverse effect on our operations. We believe that we are in compliance in all material respects with applicable air pollution control laws and requirements.

Climate Change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent compared to 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on our operations cannot be determined with any certainty at this time.

The U.S. Congress has considered legislation to reduce emissions of greenhouse gases; however, it is uncertain at this time whether, and in what form, such legislation will be adopted in the United States. Both President Obama and the Administrator of the EPA have expressed support for legislation to restrict or regulate emissions of greenhouse gases. In addition, several states, either individually or through multi-state regional initiatives, have already passed laws, adopted regulations or undertaken regulatory activity to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap-and-trade programs. Depending on the particular program, we could be required to purchase and surrender allowances for greenhouse gas emissions resulting from our operations, prepare an inventory of greenhouse gas emissions resulting from our operations, or pay a tax on the greenhouse gas emissions resulting from our operations.

Even in the absence of federal legislation, the EPA has begun to regulate greenhouse gas emissions from both mobile and stationary sources. In 2009, the EPA published its finding that greenhouse gases contribute to air pollution that may endanger public health or welfare. Thereafter, the EPA adopted a comprehensive national system for reporting emissions of greenhouse gases for major sources of emissions. On September 22, 2009, the EPA finalized a greenhouse gas reporting rule that requires large sources of greenhouse gas emissions to monitor, maintain records on, and annually report their greenhouse gas emissions. On November 8, 2010, the

EPA also issued greenhouse gas monitoring and reporting regulations for petroleum and natural gas facilities, including offshore petroleum and natural gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year, that went into effect on December 30, 2010. The rule requires reporting of greenhouse gas emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. In 2010, the EPA also issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act. The EPA’s greenhouse gas rules are currently undergoing legal challenges and numerous other petitions are pending at the EPA from states and environmental groups seeking additional regulation of a variety of additional sources of greenhouse gas emissions. It is not possible at this time to predict what legislation or new regulations may be adopted to address greenhouse gas emissions or how the adoption of such legislation or regulations would impact our business. However, any new federal, regional or state restrictions on emissions of greenhouse gases imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on our business and the demand for the oil and natural gas we produce.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. Due to their location, our operations in the Gulf of Mexico are vulnerable to operational and structural damages resulting from hurricanes and other severe weather systems and our insurance may not cover all associated losses. As discussed below in “Plugging, Abandonment and Decommissioning,” we are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.

Naturally Occurring Radioactive Materials (“NORM”). NORM are materials whose radioactivity is enhanced by technological processing such as mineral extraction or processing through exploration and production conducted by the oil and natural gas industry. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM-contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards.

Offshore Leasing and Permitting. The BOEMRE currently regulates offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Gulf of Mexico shelf, and removal of facilities. We believe that our operations are in material compliance with all applicable BOEMRE regulations and orders. On January 19, 2011, the U.S. Department of the Interior announced that it would divide offshore oil and gas responsibilities among three separate agencies, with the reorganization to be completed by October 1, 2011. The Department of Interior will create the Bureau of Ocean Energy Management with responsibility for leasing and environmental studies; the Bureau of Safety and Environmental Enforcement with responsibility for field operations, including inspections, regulatory compliance, and oil spill response; and a third agency for management of revenues. Once the reorganization is completed, the BOEMRE will cease to exist. At this time, we do not know the impact that this reorganization may have on our operations.

Plugging, Abandonment and Decommissioning. We are responsible for plugging and abandoning wellbores and decommissioning associated platforms, pipelines and facilities on our oil and natural gas properties. Some of our offshore operations are conducted on federal leases that are administered by the BOEMRE and are required to comply with the regulations and orders promulgated by the BOEMRE under OCSLA.

The BOEMRE issued an NTL, effective October 15, 2010. The NTL imposes more stringent requirements for decommissioning facilities that pose a hazard to safety or the environment, as well as for facilities that are not useful for lease operations and that are not capable of oil and natural gas production in “paying quantities.” Historically, the BOEMRE granted approval to operators to maintain these structures in order to conduct future activities. However, the NTL significantly restricts this practice. Under the NTL, lessees must submit an application to permanently plug any well that poses a hazard to safety or the environment within 30 days after identifying the hazard. The NTL also imposes new deadlines for removing platforms or other facilities that are no longer useful for operations. Furthermore, the NTL imposes new deadlines for plugging, abandoning or performing downhole zonal isolation on wells that are no longer useful for operations and that are no longer capable of production in paying quantities. In January 2011, we responded to a written request from BOEMRE for information on our “idle iron” issues by submitting a company-wide three-year plan for our wellbore plugging and abandonment and decommissioning activities through 2013. This plan does not include the properties we have acquired from ASOP. In order to permit us to gather the necessary information and perform the necessary analysis with respect to these recently-acquired properties, BOEMRE has granted a 180-day extension for submitting an idle iron plan for these properties.

The effects of Hurricanes Katrina and Rita during the 2005 hurricane season and Hurricanes Ike and Gustav in 2008 significantly impacted oil and gas operations on the Outer Continental Shelf. The effects included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs. The BOEMRE continues to be concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the potential for future damage, the BOEMRE issued guidance, through NTLs, aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not more stringent, design and operational requirements will be issued by the BOEMRE or successor agency, and these new requirements could increase our operating costs. The BOEMRE, its successors, and other regulatory bodies, including those regulating the decommissioning of our pipelines and facilities under the jurisdiction of the state of Louisiana, may change their requirements or enforce requirements in a manner inconsistent with our expectations, which could materially increase the cost of such activities and/or accelerate the timing of cash expenditures and could have a material adverse affect on our financial position, results of operations and cash flows.

The failure to comply with these rules and regulations could result in substantial penalties, including lease termination in the case of federal leases. Under limited circumstances, the BOEMRE could require us to suspend or terminate our operations on a federal lease. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations, although the impact of those requirements may vary significantly based on the nature and location of operations and related pipelines and facilities.

Significant Customers

We market substantially all of the oil and natural gas from properties we operate and from properties others operate where our interest is significant. We sell our natural gas to marketing companies pursuant to a variety of contractual arrangements, generally under contracts with terms no longer than six to twelve months. Pricing on those contracts is based largely on published regional index pricing. We sell our oil under contracts with month-to-month terms to a variety of purchasers. The pricing for oil is based upon the posted prices set by major purchasers in the production area, reporting publications, or upon New York Mercantile Exchange (“NYMEX”) pricing. Oil pricing is adjusted for quality and transportation differentials. Oil and natural gas purchasers are selected on the basis of price, credit quality and service reliability.

Our oil, condensate and natural gas production is sold to a variety of purchasers, historically at market-based prices. We believe that the prices for liquids and natural gas are comparable to market prices in the areas where we have production. Of our total oil and natural gas revenues in 2010, Shell Trading (US) Company accounted for approximately 42%, ConocoPhillips accounted for approximately 26% and Louis Dreyfus Energy Services, L.P. accounted for approximately 11%. Due to the nature of the markets for oil and natural gas, we do not believe that the loss of any one of these customers would have a material adverse effect on our financial condition or results of operations, although a temporary disruption in production revenues could occur.

Employees

As of December 31, 2010, we had 100 full-time employees, including 18 geoscientists, engineers and technicians and 51 field personnel. Our employees are not represented by any labor union or other collective bargaining organization. We consider relations with our employees to be satisfactory and we have never experienced a work stoppage or strike. We regularly use independent consultants and contractors to perform various professional services, particularly in the areas of drilling, completion, field, on-site production operations and certain administrative functions.

Competitors

Our competitors include numerous independent oil and gas companies, individuals and major oil companies. Many of our larger competitors possess and employ financial and personnel resources substantially greater than ours. These competitors are able to pay more for productive oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to replace and expand our reserve base depends on our ability to attract and retain qualified personnel and identify and acquire suitable producing properties and prospects for future drilling. See Part I, Item 1A, “Risk Factors” for additional information about risks related to our competitors, personnel and ability to acquire producing properties and prospects.

Inflation

Prior to the third quarter of 2008, we observed a general rise in the selling prices of our oil and natural gas over the prior three year period due to market factors that include the decline in the value of the U.S. dollar against other currencies, including those from which the U.S. imports oil. During that same period, we also observed increasing prices for drilling services, transportation services and raw materials, such as steel, which have impacted our lease operating expenses and our capital expenditures. The significant decline in commodity prices that occurred in the latter part of 2008, along with a general economic downturn, generally created downward pressure in 2009 on prices for the materials and services that we use in our operations, primarily our exploration, development, plugging, abandonment and other decommissioning activities. The duration and extent of future price changes, declines or increases, is highly uncertain.

Seasonality

Historically, the demand for and price of natural gas generally trends upward during the winter months and downward during the summer months. However, these seasonal fluctuations can be reduced due to summer storage practices where pipeline companies, utilities, distribution companies and industrial users may purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas. These trends are also disrupted by extreme market impacts such as those that occurred in 2008, when oil and natural gas prices reached peak levels in the summer months, then fell during the winter. Tropical storms and hurricanes generally occur in the Gulf of Mexico during late summer and fall, which may require us to evacuate personnel and shut-in production during those periods. The winds and turbulent current conditions that occur in the winter months can impact our ability to safely load, unload and transport personnel and equipment, and perform operations, including plugging, abandonment and other decommissioning activities, which can delay our operations, increase the cost of our operations and/or delay the restoration and maintenance of our oil and natural gas production.

Chapter 11 Reorganization

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Chapter 11 Reorganization” for a description and discussion of our Chapter 11 reorganization in 2009.

Cautionary Statement Concerning Forward Looking Statements

This Annual Report contains forward-looking statements within the meaning of, and we intend that such forward-looking statements be subject to the safe harbor provisions of, the U.S. federal securities laws. Forward-looking statements are, by definition, statements that are not historical in nature and relate to possible future events. They may be, but are not necessarily, identified by words such as “will,” “would,” “should,” “likely,” “estimates,” “thinks,” “strives,” “may,” “anticipates,” “expects,” “believes,” “intends,” “goals,” “plans,” or “projects” and similar expressions.

These forward-looking statements reflect our current views with respect to possible future events, are based on various assumptions and are subject to risks and uncertainties. These forward-looking statements are not guarantees or predictions of our future performance, and our actual results and future developments may differ materially from those projected in, and contemplated by, the forward-looking statements. As a result, you should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements. Among the factors that could cause actual results to differ materially are the risks and uncertainties described under Part I, Item 1A, “Risk Factors,” including the following:

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planned and unplanned capital expenditures;

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adequacy of capital resources and liquidity including, but not limited to, access to additional capacity under our credit facility;

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our substantial level of indebtedness;

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our ability to incur additional indebtedness;

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volatility in oil and natural gas prices;

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volatility in the financial and credit markets;

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changes in general economic conditions;

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uncertainties in reserve and production estimates;

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replacing our oil and natural gas reserves;

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unanticipated recovery or production problems;

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availability, cost and adequacy of insurance coverage;

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hurricane and other weather-related interference with business operations;

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drilling and operating risks;

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production expense estimates;

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the impact of derivative positions;

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our ability to retain and motivate key executives and other necessary personnel;

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availability of drilling and production equipment and field service providers;

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the effects of delays in completion of, or shut-ins of, gas gathering systems, pipelines and processing facilities;

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potential costs associated with complying with new or modified regulations promulgated by the BOEMRE;

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the impact of political and regulatory developments;

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risks and liabilities associated with acquired properties or business, including the ASOP Properties;

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our ability to make and integrate acquisitions, including the ASOP Properties;

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oil and gas prices and competition; and

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our ability to generate sufficient cash flow to meet our debt service and other obligations.

Many of these factors are beyond our ability to control or predict. Any, or a combination, of these factors could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. These forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

For a further list and description of various risks, relevant factors and uncertainties that could cause future results or events to differ materially from those expressed or implied in our forward-looking statements, see “Risk Factors” in Part 1, Item 1A of this Annual Report and elsewhere in this Annual Report; our reports and registration statements filed from time to time with the SEC; and other announcements we make from time to time. Given these risks and uncertainties, you should not place undue reliance on these forward-looking statements.

Although we believe that the assumptions on which any forward-looking statements are based in this Annual Report and other periodic reports filed by us are reasonable when and as made, no assurance can be given that such assumptions will prove correct. All forward-looking statements in this Annual Report are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this Annual Report and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by applicable securities laws and regulations.

Item 1A.

Risk Factors

Risks Related to Our Business

Our business requires substantial capital investment and maintenance expenditures, and our capital resources may not be adequate to provide for all of our cash requirements.

Our operations are capital intensive. Our ability to replace our oil and natural gas production and maintain our production levels and reserves requires extensive capital investment, including substantial capital expenditures for the acquisition, development, production, exploration and abandonment of oil and gas properties. Our business also requires substantial expenditures for routine maintenance. Our capital requirements will depend on numerous factors, and we cannot predict accurately the timing and amount of our capital requirements. Though we have the ability to borrow under our new credit facility, we intend to finance our development and exploration capital expenditures primarily through cash flow from operations. Because our cash flows are subject to a range of economic, competitive and business risks, we may not be able to generate sufficient cash flow from operations to meet our debt payment obligations and to fund these capital requirements. Additionally, the amounts available to us under our new credit facility may not be sufficient for our capital requirements not funded by cash flow from operations, and we may not be able to access additional financing resources for a variety of reasons, including restrictive covenants in our new credit facility. If we are unable to make scheduled payments on our new credit facility, or if our financing requirements are not met by our new credit facility and we are unable to access sources of additional financing on terms we find acceptable, our business, operations, financial condition and cash flows will be negatively impacted.

Without additional capital resources, we may be forced to limit or defer our planned oil and natural gas exploration and development program and this will adversely affect the recoverability and ultimate value of our

oil and natural gas properties, in turn negatively affecting our business, financial condition and results of operations. We may also be unable to obtain sufficient credit capacity with counterparties to finance the hedging of our future crude oil and natural gas production which may limit our ability to manage price risk. As a result, we may lack the capital necessary to complete potential acquisitions, obtain credit necessary to enter into derivative contracts to hedge our future crude oil and natural gas production or to capitalize on other business opportunities.

The borrowing base under our new credit facility is subject to re-determination and could be reduced in the future if commodity prices decline, which will limit our available funding for exploration and development.

Our current borrowing base under our new credit facility is $150 million, and we currently have no amounts outstanding under our new credit facility. Our borrowing base is subject to semi-annual and certain other interim re-determinations by our lenders in their sole discretion. The next re-determination of the borrowing base is scheduled to occur on May 1, 2011. The lenders will re-determine the borrowing base based on an engineering report with respect to our oil and natural gas reserves, which will take into account the prevailing oil and natural gas prices at such time. Any reduction of the borrowing base is subject to approval of lenders holding not less than 66 2/3% of the lending commitments under our new credit facility.

In the future, we may not be able to access adequate funding under our new credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base re-determination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. If oil and natural gas commodity prices deteriorate, we anticipate that the revised borrowing base under our new credit facility may be reduced. As a result, we may be unable to obtain adequate funding under our new credit facility. If funding is not available when needed, it could adversely affect our exploration and development plans as currently anticipated and our ability to make new acquisitions, each of which could have a material adverse effect on our production, revenues and results of operations.

In addition, if there is a decrease in our borrowing base as a result of the outcome of a subsequent borrowing base re-determination and, as a result of such decrease, the outstanding borrowings under our new credit facility exceed the re-determined borrowing base, we will be required to repay such excess within 60 days. We may not have the financial resources in the future to make any mandatory principal prepayments required under our new credit facility.

Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the notes.

We and the guarantors of the 8.25% Notes (the “guarantors”), on a consolidated basis, have outstanding approximately $210.0 million of senior indebtedness, none of which is secured. Our substantial level of indebtedness could have significant effects on our business. For example, our level of indebtedness and the terms of our debt agreements may:

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make it more difficult for us to satisfy our financial obligations under the 8.25% Notes, our other indebtedness and our contractual and commercial commitments and increase the risk that we may default on our debt obligations;

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heighten our vulnerability to downturns in our business, our industry or in the general economy and restrict us from exploiting business opportunities or making acquisitions;

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limit management’s discretion in operating our business;

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require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, and other general corporate purposes;

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place us at a competitive disadvantage compared to our competitors that have less debt;

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limit our ability to borrow additional funds; and

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limit our flexibility in planning for, or reacting to, changes in our business, the industry in which we operate or the general economy.

Each of these factors may have a material and adverse effect on our financial condition and viability. Our ability to make payments with respect to the 8.25% Notes and to satisfy our other debt obligations will depend on our future operating performance, which will be affected by prevailing economic conditions and financial, business and other factors affecting our company and industry, many of which are beyond our control. In addition, the indenture governing the 8.25% Notes (the “Indenture”) and our new credit facility contain financial and other restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our failure to comply with those covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our debts.

Despite existing debt levels, we may still be able to incur substantially more debt, which would increase the risks associated with our leverage.

Even with our existing debt levels, we and our subsidiaries may be able to incur substantial amounts of additional debt in the future, including debt under our new and future credit facilities. As of December 31, 2010, after giving effect to the issuance of the 8.25% Notes and the ASOP Acquisition and entry into our new credit facility, we would have been able to incur approximately $867.0 million of additional indebtedness permitted by the Indenture, including approximately $150.0 million of debt under our new credit facility, and other permitted debt categories or baskets. In addition, the Indenture will allow us to issue additional notes under certain circumstances, which will also be guaranteed by the guarantors. Although the terms of the 8.25% Notes and our new and future credit facilities will limit our ability to incur additional debt, these terms do not and will not prohibit us from incurring substantial amounts of additional debt for specific purposes or under certain circumstances. If new debt is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could intensify and could further exacerbate the risks associated with our leverage.

Our new credit facility and the Indenture impose significant operating and financial restrictions on us and our subsidiaries that may prevent us from pursuing certain business opportunities and restrict our ability to operate our business.

Our new credit facility and the Indenture contain covenants that restrict our and our restricted subsidiaries’ or, in the case of the new credit facility, our and all of our subsidiaries’, ability to take various actions, such as:

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transferring or selling assets;

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paying dividends or distributions, buying subordinated indebtedness or securities, making certain investments or making other restricted payments;

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incurring or guaranteeing additional indebtedness or, in the case of the Indenture and only with respect to our restricted subsidiaries, issuing preferred stock;

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creating or incurring liens;

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incurring dividend or other payment restrictions affecting restricted subsidiaries;

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consummating a merger, consolidation or sale of all or substantially all our assets;

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entering into transactions with affiliates;

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engaging in business other than a business that is the same or similar to our current business or a reasonably related extension thereof;

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making capital expenditures;

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issuing capital stock of certain subsidiaries;

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entering into sale/leaseback transactions;

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making acquisitions or investments; and

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designating subsidiaries as unrestricted subsidiaries.

In addition, our new credit facility restricts us from entering into certain hedging contracts or extending credit. Our new credit facility also requires, and any future credit facilities may additionally require, us to comply with specified financial ratios, including regarding interest coverage, total leverage, current assets to current liabilities or other similar ratios.

We may also be prevented from taking advantage of business opportunities that arise if we fail to meet certain ratios or because of the limitations imposed on us by the restrictive covenants under these agreements. The restrictions contained in our new credit facility and the Indenture may also limit our ability to plan for or react to market conditions, meet capital needs or otherwise restrict our activities or business plans and adversely affect our ability to finance our operations, enter into acquisitions, execute our business strategy, effectively compete with companies that are not similarly restricted or engage in other business activities that would be in our interest. In the future, we may also incur debt obligations that might subject us to additional and different restrictive covenants that could affect our financial and operational flexibility. We cannot assure you that we will be granted waivers or amendments to these agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on acceptable terms or at all should we seek to do so.

Our ability to comply with these covenants will likely be affected by events beyond our control, and we cannot assure you that we will satisfy those requirements. A breach of any of these provisions could result in a default under our new credit facility, the Indenture or any future credit facilities we may enter into, which could allow all amounts outstanding thereunder to be declared immediately due and payable, subject to the terms and conditions of the documents governing such indebtedness. If we were unable to repay the accelerated amounts, our secured lenders could proceed against the collateral granted to them to secure such indebtedness. This would likely in turn trigger cross-acceleration and cross-default rights under any other credit facilities and indentures, if any then exist governing the 8.25% Notes and the terms of our other indebtedness outstanding at such time. If the amounts outstanding under our new credit facility, the 8.25% Notes or any other indebtedness outstanding at such time were to be accelerated or were the subject of foreclosure actions, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

A substantial or extended decline in oil and natural gas prices may have a material adverse effect on our business, financial condition, results of operations, cash flows and our ability to meet our debt obligations, operating cost requirements, capital expenditure requirements and other financial commitments.

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, financial condition, cash flow, access to capital and future rate of growth. Oil and natural gas are commodities and, as a result, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. While oil and natural gas prices have recently recovered from their low levels in 2009, there are different views about the strength of the economic recovery and future demand for oil and natural gas. Consequently, there is no assurance that prices will not fall again. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include:

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changes in the global supply, demand and inventories of oil;

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domestic natural gas supply, demand and inventories;

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the actions of the Organization of Petroleum Exporting Countries;

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the price and quantity of foreign imports of oil;

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the price and availability of liquefied natural gas imports;

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political conditions, including embargoes, in or affecting other oil-producing countries;

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economic and energy infrastructure disruptions caused by actual or threatened acts of war, or terrorist activities, or national security measures deployed to protect the United States from such actual or threatened acts or activities;

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economic stability of major oil and natural gas companies and the interdependence of oil and natural gas and energy trading companies;

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the level of worldwide oil and natural gas exploration and production activity;

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weather conditions, including energy infrastructure disruptions resulting from those conditions;

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technological advances effecting energy consumption; and

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the price and availability of alternative fuels.

Oil and natural gas prices as of the date of this Annual Report permit us to maintain the minimal investment necessary to mitigate the impact of natural reservoir declines on our current production levels. However, if prices fall to their previous low levels, we may not be able to replace our reserves and our production may decline significantly. As a result, we could experience a decline in our revenues and available capital, which would likely substantially decrease our capital expenditures, drilling activities and operations.

Any continuing volatility in the financial and credit markets may affect our ability to obtain funding or to obtain funding on acceptable terms. These factors may hinder or prevent us from meeting our future capital needs and/or continuing to meet our obligations and conduct our business.

The recent credit crisis and related turmoil in the global financial systems have had an impact on our business and our financial condition, and we may face challenges if economic and financial market conditions do not improve. Historically, we have used our cash flow from operations and borrowings under our credit facility to fund our capital expenditures and have relied on the capital markets to provide us with additional capital for large or exceptional transactions. A continuation or recurrence of the economic crisis could further reduce the demand for oil and natural gas and put downward pressure on the prices for oil and natural gas.

In the future, we may not be able to access adequate funding under our new credit facility and any other debt instruments we may enter into as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base re-determination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Declines in commodity prices, or a continuing decline in those prices, could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base.

Because our consolidated financial statements reflect fresh-start accounting adjustments made upon emergence from our Chapter 11 reorganization and because of the effects of the transactions that became effective pursuant to our plan of reorganization, financial information included in this Annual Report for periods prior to September 30, 2009 are not comparable with our financial information for periods on or after September 30, 2009.

In connection with our Chapter 11 reorganization, we adopted fresh-start accounting effective on September 30, 2009 in accordance with ASC Topic 852, “Reorganizations.” Our adoption of fresh-start accounting resulted in our becoming a new entity for financial reporting purposes. As required by fresh-start accounting, our assets and liabilities were adjusted to reflect fair value as of September 30, 2009. In addition to fresh-start accounting, our financial statements reflect the effects of all of the transactions implemented by our plan of reorganization. Accordingly, our financial statements for periods prior to September 30, 2009 are not comparable with our financial statements for periods on or after September 30, 2009. Furthermore, the estimates and assumptions used to implement fresh-start accounting are inherently subject to significant uncertainties and

contingencies beyond our control. Accordingly, we cannot provide assurance that the estimates, assumptions, and values reflected in our valuations will be realized, and our actual results could vary materially.

Our current operations and a significant part of the value of our production and reserves are concentrated in the Gulf of Mexico. Because of this concentration, any production problems or inaccuracies in reserve estimates related to these areas could have a material adverse effect on our business.

Virtually all of our current operations are concentrated in the Gulf of Mexico region. We are more vulnerable to operational, regulatory and other risks associated with the Gulf of Mexico, including the risk of adverse weather conditions, than many of our competitors that are more geographically diversified because all or a substantial portion of our operations could experience the same condition at the same time.

Fifty-two percent of our net daily production came from our South Timbalier and other Greater Bay Marchand area properties for the year ended December 31, 2010 and approximately 35% of our proved reserves at December 31, 2010 were located in the fields that comprise this area. In addition, 21% of our net daily production for the year ended December 31, 2010 came from our East Bay field and approximately 54% of our proved reserves at December 31, 2010 were located in this area. After giving effect to the ASOP Acquisition, 58% of our pro forma net daily production for the year ended December 31, 2010 and 68% of our pro forma proved reserves at December 31, 2010 were attributable to these areas. If the actual reserves associated with these two properties are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows.

During the 2008 hurricane season, our production was reduced by approximately 21%, on an annual basis, as a result of damage to third party pipelines caused by two hurricanes. The hurricane damage limited our ability to sell our production from certain properties for extended periods of time during the third and fourth quarters of 2008. If mechanical problems, storms or other events were to curtail a substantial portion of the production in these areas, such a curtailment could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The relatively steep decline curves generally associated with oil and gas properties located in the Gulf of Mexico region subjects us to higher reserve replacement needs.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. High initial production rates generally result in recovery of a relatively higher percentage of reserves from properties during the initial few years of production, often followed by a rapid decline in the rate of production.

Because substantially all of our operations are concentrated in the Gulf of Mexico, and because production from reservoirs in the Gulf of Mexico region generally declines more rapidly compared to reservoirs in many other producing regions of the world, our reserve replacement needs are relatively greater than those of producers with reserves outside the Gulf of Mexico region.

As of December 31, 2010, our independent petroleum engineers estimate that, on average, 66% of our total proved reserves will be produced within five years. We will have to continue to develop, exploit, find or acquire additional reserves to sustain our current production levels and to grow our production.

We may not be able to keep pace with technological developments in our industry.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other natural gas and oil companies may have greater financial,

technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.

With respect to a portion of our properties, we are not the operator and therefore are not in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on such properties.

As we carry out our planned drilling program, we will not serve as operator of all planned wells. As of December 31, 2010, we operated approximately 86% of our properties, based on proved reserves at December 31, 2010. Following the ASOP Acquisition, we operate approximately 80% of our properties, including the ASOP Properties, based on proved reserves at December 31, 2010. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

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the timing and amount of capital expenditures;

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the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

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the operator’s expertise and financial resources;

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approval of other participants in drilling wells;

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selection of technology; and

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the rate of production of the reserves.

Our operations in the deepwater Gulf of Mexico area present unique operating risks.

The deepwater Gulf of Mexico area has had relatively limited drilling activity due to risks associated with geological complexity, water depth and higher drilling and development costs, which could result in substantial cost overruns and/or uneconomic projects or wells. Because we have operations in the deepwater Gulf of Mexico area, we are exposed to these risks. Our deepwater assets do not fit within our long-term strategy, and there are no current plans to develop these interests. As such, we may monetize or trade these assets. However, there is no assurance that we will be able to divest these interests on terms acceptable to us.

If we place hedges on future production and encounter difficulties meeting that production, we may not realize the originally anticipated cash flows.

Our assets consist of a mix of reserves, with some being developed while others are undeveloped. To the extent that we sell the production of these reserves on a forward-looking basis but do not realize that anticipated level of production, our cash flow may be adversely affected if energy prices rise above the prices for the forward-looking sales. In this case, we would be required to make payments to the purchaser of the forward-looking sale equal to the difference between the current commodity price and that in the sales contract multiplied by the physical volume of the shortfall. There is the risk that production estimates could be inaccurate or that storms or other unanticipated problems could cause the production to be less than the amount anticipated, causing us to make payments to the purchasers pursuant to the terms of the hedging contracts.

Our price risk management activities could result in financial losses or could reduce our income, which may adversely affect our cash flows.

We enter into derivative contracts to reduce the impact of natural gas and oil price volatility on our cash flow from operations. Currently, we use a combination of natural gas and crude oil put and swap arrangements to mitigate the volatility of future natural gas and oil prices received.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our price risk management activities are subject to the following risks:

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a counterparty may not perform its obligation under the applicable derivative instrument;

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there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

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the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.

Loss of key management and failure to attract qualified management could negatively impact our operations.

Successfully implementing our strategies will depend, in part, on our management team. The loss of members of our management team could have an adverse effect on our business. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping qualified personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs, or prevent us from pursuing our strategy as quickly as we would otherwise wish to do.

Our ability to collect payments from our partners depends on the partners’ creditworthiness.

In operating our oil and natural gas properties, we typically incur costs on behalf of our partners in advance of billing and collecting our partners’ share of those costs. Some of our partners are highly leveraged and may become unable to pay us for their share of the operating costs. Further, a significant adverse change in the financial and/or credit position of a partner could require us to assume greater credit risk relating to that partner and could limit our ability to collect joint interest receivables. Failure to receive payments from our partners for their share of costs incurred on our oil and natural gas properties could adversely affect our results of operations, financial condition and cash flows.

Risks Related to Our Acquisition Strategy

Our acquisition strategy involves potential risks that could adversely impact our future financial performance.

A significant component of our business strategy is to acquire oil and gas properties. Acquisitions of producing properties from third parties require us to assess many factors that are inherently inexact and may be inaccurate, including:

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the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

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the risk that financial information relating to the acquired assets may not be accurate;

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inaccurate assumptions about revenues and costs, including synergies;

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significant increases in our indebtedness and working capital requirements;

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an inability to transition and integrate successfully or timely the businesses we acquire;

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the cost of transition and integration of data systems and processes;

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potential environmental problems and costs;

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the assumption of unknown liabilities;

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limitations on rights to indemnity from the seller;

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the diversion of management’s attention from other business concerns;

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increased demands on existing personnel and on our corporate structure;

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increased responsibility for plugging and abandonment costs;

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customer or key employee losses of the acquired businesses; and

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the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, our future acquisition costs may be higher than those we have achieved historically. Any of these factors could adversely impact our future financial performance and ability to pay principal and interest on the notes. Future transactions may prove to stretch our internal resources and infrastructure. As a result, we may need to hire additional personnel and invest in additional resources, which will increase our costs. Any further acquisitions we make over the short term would likely exacerbate these risks.

We may record material impairments to the carrying values of our oil and natural gas properties if oil and gas prices decline from prices we used to estimate the acquisition fair values of acquired oil and gas properties.

We record acquisitions of oil and natural gas properties, including the ASOP Acquisition, using the purchase method of accounting which requires that we record the acquired oil and natural gas properties at their fair values as of the acquisition date. We may be required to recognize material non-cash impairment charges in future reporting periods if market prices for oil or natural gas decline and, as a result, the estimated fair values of the acquired oil and natural gas properties decline from the values estimated as of the acquisition date.

We may be unable to successfully integrate the operations of the properties we acquire.

Integration of the operations of the properties we acquire with our existing business will be a complex, time-consuming and costly process. Failure to successfully integrate the acquired businesses and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of combining the acquired operations include, among other things:

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operating a significantly larger combined organization;

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integrating corporate, technological and administrative functions;

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integrating internal controls and other corporate governance matters;

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diverting management’s attention from other business concerns;

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loss of key vendors from the acquired businesses;

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a significant increase in our indebtedness; and

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potential environmental or regulatory liabilities and title problems.

The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. Our operating performance, revenues and costs could be materially adversely affected if:

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we are not successful in completing the integration of acquired properties into our operations;

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the integration takes longer or is more complex than anticipated; or

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we cannot operate acquired properties as effectively as we anticipate.

We may not realize all of the anticipated benefits from our acquisitions.

We may not realize all of the anticipated benefits from any future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices.

We may not have fully identified liabilities associated with properties or assets we acquire or obtained adequate protection from sellers against liabilities.

Our assessments of potential acquisitions may not reveal all existing or potential problems with the subject properties or permit us to become adequately familiar with the properties in order to evaluate fully their deficiencies and capabilities. In the course of our due diligence, we may not inspect every well, platform or pipeline. Our inspections may not identify structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. As a result, we may not realize all of the anticipated benefits from future acquisitions, such as increased earnings, cost savings and revenue enhancements.

The properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the acquired properties or obtain protection from sellers against such liabilities.

The properties we acquire may not produce as expected, may be in an unexpected condition and we may be subject to increased costs and liabilities, including environmental liabilities. Although we review properties prior to acquisition in a manner consistent with industry practices, such reviews are not capable of identifying all potential adverse conditions. Furthermore, we have not yet been able to subject the preparation of reserve estimates for acquired properties to the same internal controls we have for the preparation of reserve estimates for our existing properties. Generally, it is not feasible to review in depth every individual property involved in each acquisition. We focus our review efforts on the higher-value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties and preparation of reserve reports in accordance with our internal controls may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to fully assess their condition, any deficiencies, and development potential.

If we are unable to execute our acquisition strategy successfully, our business may not continue to grow.

We intend to pursue opportunistic acquisitions that leverage our organizational strengths. However, we may not be able to identify and consummate future acquisitions successfully, and assets that we do acquire may not yield anticipated benefits. Our failure to execute our acquisition strategy successfully in the future could limit our ability to continue to grow our business.

Risks Related to Our Industry

Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and estimated values of our reserves.

The process of estimating oil and natural gas reserves is complex, requiring interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves disclosed in this Annual Report.

Estimates of oil and natural gas reserves are inherently imprecise. The preparation of our reserve estimates requires projections of production rates and timing of development expenditures, analysis of available geological, geophysical, production and engineering data, and assumptions about oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The extent, quality and reliability of this data can vary. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, drilling and operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. If our estimates of the recoverable reserve volumes on a property are revised downward, if development costs exceed previous estimates or if commodity prices decrease, as discussed elsewhere in these risk factors, we may be required to record an impairment to our property and equipment, which could have a material adverse effect on our financial position and results of operations. Once recorded, an impairment of property and equipment may not be reversed at a later date. Our ability to obtain financing in the future may depend in part on our estimate of the proved oil and natural gas reserves for properties that will serve as collateral. If proved reserves on a property are revised downward, our ability to acquire adequate funding may be significantly reduced.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves.

The present value of future net revenues from our proved reserves and the standardized measure of discounted future net cash flows referred to in this Annual Report should not be assumed to represent or approximate the current market value of our estimated proved oil and natural gas reserves.

In accordance with SEC requirements, the estimated discounted future net cash flows from our proved reserves are computed using prices based on the unweighted, arithmetic average of the closing price on the first day of each of the twelve months during the preceding fiscal year and costs as of the date of the estimate held constant for the life of the reserves. However, actual future net cash flows from our natural gas and oil properties will be affected by factors such as:

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the volume, pricing and duration of our natural gas and oil hedging contracts;

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supply of and demand for natural gas and oil;

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actual prices we receive for natural gas and oil;

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our actual operating costs in producing natural gas and oil;

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the amount and timing of our capital expenditures and decommissioning costs;

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the amount and timing of actual production; and

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changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating

discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our estimates of proved reserves and related PV-10 and standardized measure of discounted future net cash flows have been prepared in accordance with new SEC rules, which went into effect for fiscal years ending on or after December 31, 2009, and may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future.

This Annual Report presents estimates of our proved reserves and related PV-10 as of December 31, 2010 and 2009 and standardized measure of discounted future net cash flows as of December 31, 2010 and 2009, all of which have been prepared and presented under new SEC rules. These new rules are effective for fiscal years ending on or after December 31, 2009, and require companies to prepare their reserves estimates using revised reserve definitions and revised pricing based on 12-month unweighted first-day-of the-month average pricing. The previous rules required that reserve estimates be calculated using year-end pricing. As a result of these changes, and because the new rules do not have a retroactive effect to periods that ended prior to December 31, 2009, direct comparisons to our prior period reserves amounts may be more difficult.

Another impact of the new SEC rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our future proved undeveloped reserves if we do not drill and develop those reserves within the required five-year timeframe.

The SEC has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules and may not issue further interpretive guidance on the new rules. Accordingly, the estimates of our proved reserves for any periods ending on or after December 31, 2009 included in this Annual Report could differ materially from any estimates we might prepare applying more specific SEC interpretive guidance. On December 30, 2010, the SEC provided comments on the periodic filings we made with the SEC in 2010. These comments included comments on certain of our reserve disclosures, and we are in the process of responding to these comments. We do not believe that these comments will result in material changes to the reserve disclosures we have previously made.

We may be limited in our ability to book additional proved undeveloped reserves under recent SEC rules.

We have included in this Annual Report certain estimates of our and the ASOP Properties’ proved reserves as of December 31, 2010 prepared in a manner consistent with our and our independent petroleum engineer’s interpretation of the recent SEC rules relating to modernizing reserve estimation and disclosure requirements for oil and natural gas companies. These recent rules were effective for annual reporting periods ended on or after December 31, 2009. Included within these recent SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, we may be required to write-off reserves previously recognized as proved undeveloped. Also, since we have acquired the ASOP Properties very recently, we do not have a development plan for these properties and there cannot be any assurance as to what level of proved undeveloped reserves will be supported by the plan we do develop. As of December 31, 2010, approximately 7% of our total proved reserves were undeveloped, and approximately 47% of our total proved reserves were developed non-producing reserves. As of December 31, 2010, approximately 24% of the ASOP Properties’ total proved reserves were undeveloped, and approximately 15% of the ASOP Properties’ total proved reserves were developed non-producing reserves. There can be no assurance that all of those reserves will ultimately be developed or produced.

If we are unable to replace the reserves that we have produced, our reserves and future revenues will decline.

Our future success depends on our ability to find, develop, acquire and produce oil and natural gas reserves that are economically recoverable. Lower commodity prices and increased costs associated with exploration and production may lower the threshold of economic recoverability. Though our 2011 fiscal year capital budget contemplates the deployment of a significantly larger amount of capital compared to the capital expenditures in 2010, which were at levels significantly lower than our historical average, there can be no assurance that we will be able to grow production through the drill-bit at rates we have experienced in the past. Though we intend to pursue development and acquisition opportunities, there is no assurance that our efforts will yield their intended results. Without continued successful acquisition or exploration activities, our reserves and revenues will decline as a result of our current reserves being depleted by production. We may not be able to find or acquire additional reserves on an economic basis.

Unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.

We may become responsible for unanticipated costs associated with abandoning and reclaiming wells, facilities and pipelines. Abandonment and reclamation of facilities and the costs associated therewith are often referred to as “decommissioning.” Should decommissioning be required that is not presently anticipated, or should the decommissioning be accelerated (such as can happen after a hurricane), these costs may exceed the value of reserves remaining at any particular time. We may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy these decommissioning costs could have a material adverse effect on our financial position and results of operations.

We may not be insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance coverage against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of wells, oil pollution, third party liability, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery, as well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages and losses.

Currently, we have general liability insurance coverage with an annual aggregate limit of $2.0 million and umbrella liability coverage with an aggregate limit of $150.0 million applicable to our working interest. We also have an offshore property physical damage policy that contains a $70.0 million annual aggregate named windstorm limit. Our operational control of well coverage provides limits that vary by well location and depth and range from a combined single limit of $20.0 million to $75.0 million per occurrence. Deepwater wells have a coverage limit of $50.0 million per occurrence. Additionally, we maintain $70.0 million in oil pollution liability coverage. Our control of well and oil pollution liability policy limits are scaled proportionately to our working interests, except for our deepwater control of well coverage, which limit is to our working interest and all of our policies described above are subject to deductibles, sub-limits and/or self-insurance. Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

An operational or hurricane related event may cause damage or liability in excess of our coverage, which might severely impact our financial position. We may be liable for damages from an event relating to a project in which we are a non-operator, but have a working interest in such project. Such an event may also cause a significant interruption to our business, which might also severely impact our financial position. For example, we experienced production interruptions in 2005, 2006 and 2007 from Hurricanes Katrina and Rita and in 2008 and 2009 from Hurricanes Gustav and Ike for which we had no production interruption insurance.

We reevaluate the purchase of insurance, policy limits and terms annually each April. In light of the recent catastrophic accident in the Gulf of Mexico, we may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the Gulf of Mexico, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

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environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

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abnormally pressured formations;

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blow-outs and surface cratering;

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mechanical difficulties and pipe, cement, sub-sea well or pipeline failures;

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fires and explosions;

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personal injuries and death; and

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natural disasters, especially hurricanes and tropical storms in the Gulf of Mexico region.

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses because of costs and/or liability incurred as a result of:

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injury or loss of life;

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severe damage to and destruction of property, natural resources and equipment;

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pollution and other environmental damage;

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clean-up responsibilities;

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regulatory investigations and penalties;

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suspension of our operations; and

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repairs to resume operations.

Exploring for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success will depend on the success of our exploration and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data

obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in planned expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling activity, including the following:

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pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment and qualified personnel;

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equipment failures or accidents;

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adverse weather conditions, such as hurricanes and tropical storms;

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reductions in oil and natural gas prices;

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title problems;

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limitations in the market for oil and natural gas; and

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cost of services to drill wells.

If we are unable to effectively manage the commodity price risk of our production if energy prices fall, we may not realize the anticipated cash flows from our acquisitions.

Compared to some other participants in the oil and gas industry, we are a relatively small company with modest resources. Therefore, there is the possibility that we may be unable to find counterparties willing to enter into derivative arrangements with us or be required to either purchase relatively expensive put options, or commit to deliver future production, to manage the commodity price risk of our future production. To the extent that we commit to deliver future production, we may be forced to make cash deposits available to counterparties as they mark to market these financial hedges. Proposed changes in regulations affecting derivatives may further limit or raise the cost, or increase the credit support required to hedge. This funding requirement may limit the level of commodity price risk management that we are prudently able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves. If we fail to manage the commodity price risk of our production and energy prices fall, we may not be able to realize the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reserves.

Periods of high cost or lack of availability of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute on a timely basis our exploration and development plans.

Substantially all of our current operations are concentrated in the Gulf of Mexico region. Shortages and the high cost of drilling rigs, equipment, supplies or personnel that occur in this region from time to time could delay or adversely affect our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Periodically, as a result of increased drilling activity or a decrease in the supply of equipment, materials and services, we have experienced increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in the Gulf of Mexico and in other offshore areas around the world also decreases the availability of offshore rigs in the Gulf of Mexico. As a result, costs may increase in the future and necessary equipment and services may not be available on terms acceptable to us. Redeployment of drilling rigs to areas other than the Gulf of Mexico in the wake of the Deepwater Horizon incident in April 2010, discussed below, may reduce the availability of offshore rigs, which could increase costs in future years.

Impediments to transporting our products may limit our access to oil and natural gas markets or delay our production.

Our ability to market our oil and natural gas production depends on a number of factors, including the proximity of our reserves to pipelines and terminal facilities, the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties and the availability of satisfactory oil and natural gas transportation arrangements. In deepwater operations, market access depends on the proximity of, and our ability to tie into, existing production platforms owned or operated by third parties and the ability to negotiate commercially satisfactory arrangements with the owners or operators. These facilities and systems may be shut-in due to factors outside of our control. If any of these third party services and arrangements become partially or fully unavailable, or if we are unable to secure such services and arrangements on acceptable terms, or if the gas quality specification for their pipelines or facilities changes so as to restrict our ability to transport gas on these pipelines or facilities, our production could be limited or delayed and our revenues could be adversely affected.

Competition in the oil and natural gas industry is intense, which may adversely affect us.

We operate in a highly competitive environment for acquiring oil and natural gas properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in Gulf of Mexico activities. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. There can be no assurance that we will be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. If we are unable to compete successfully in these areas in the future, our revenues and growth may be diminished or restricted.

The recent explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico and the resulting oil spill may significantly increase our risks, costs and delays.

The recent explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico and the resulting oil spill may significantly impact the risks we face. The Deepwater Horizon incident and resulting legislative, regulatory and enforcement changes, including increased tort liability, could increase our liability that may arise if any incidents occur on our offshore operations. We cannot predict the ultimate impact the Deepwater Horizon incident and resulting changes in regulation of offshore oil and natural gas operations will have on us.

In response to the spill, and during a moratorium on deepwater (below 500 feet) drilling activities implemented between May 30, 2010 and October 12, 2010, the BOEMRE issued a series of NTLs and adopted changes to its regulations to impose a variety of new measures intended to help prevent a similar disaster in the future.

Offshore operators, including those operating in deepwater, outer continental shelf waters and shallow waters, where we have substantial operations, must now comply with strict new safety and operating requirements. For example, before being allowed to resume drilling, outer continental shelf operators must certify compliance with all applicable operating regulations found in 30 C.F.R. Part 250, including those rules recently placed into effect, such as rules relating to well casing and cementing, blowout preventers, safety certification, emergency response, and worker training. Operators of all offshore waters also must demonstrate the availability of adequate spill response and blowout containment resources. Notwithstanding the lifting of the moratorium on October 12, 2010, we cannot predict with certainty when new permits will be granted under the

new requirements. We anticipate that there will continue to be delays in the resumption of drilling-related activities, including delays in the issuance of drilling permits, as these regulatory initiatives are fully implemented.

Legislative and regulatory initiatives relating to offshore operations, which include consideration of increases in the minimum levels of demonstrated financial responsibility required to conduct exploration and production operations on the outer continental shelf and elimination of liability limitations on damages, will, if adopted, likely result in increased costs and additional operating restrictions and could have a material adverse effect on our business.

In addition to the new requirements recently imposed by the BOEMRE, there have been a variety of proposals to change existing laws and regulations that could materially adversely affect our operations and cause us to incur substantial costs, including by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory burdens. Furthermore, such proposed changes could lead to a wide variety of other unforeseeable consequences that make operations in the Gulf of Mexico and other offshore waters more difficult, more time consuming, and more costly. For example, the U.S. Congress recently considered amendments to OPA, in response to the Deepwater Horizon incident. OPA and regulations adopted pursuant to OPA impose liabilities for and requirements related to oil spills into waters of the United States, including the outer continental shelf waters where we have substantial operations. OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from an oil spill, including, but not limited to, the costs of responding to a spill, natural resource damages and economic damages suffered by persons adversely affected by the spill. The U.S. Congress has considered legislation that would eliminate existing liability caps for damages under OPA. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35.0 million for companies operating in offshore waters, although the Secretary of Interior may increase this amount up to $150.0 million in certain situations. Congress considered one proposed bill with regard to OPA that would, if adopted, impose new requirements on OCS operations, including increasing the minimum level of financial responsibility to $300.0 million. If OPA is amended to materially increase the minimum level of financial responsibility beyond current requirements, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. If we are unable to provide the level of financial assurance required by OPA, we may be forced to sell our properties or operations located in offshore waters or enter into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating in offshore waters will be increased.

We do not know how the ongoing reorganization of the BOEMRE will impact potential future regulations or enforcement that may affect our operations.

On May 19, 2010, the U.S. Department of the Interior announced that it would reorganize the Minerals Management Service by dividing its offshore oil and gas responsibilities among three separate agencies. Shortly thereafter, on June 18, 2010, the Minerals Management Service was renamed the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE. The BOEMRE currently regulates offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Gulf of Mexico shelf and removal of facilities. On October 1, 2010, the first phase of reorganization took place when the revenue collection arm of the former Mineral Management Service became the Office of Natural Resources Revenue. On January 19, 2011, the U.S. Department of the Interior announced the structures and responsibilities of the two remaining agencies, with the reorganization of the BOEMRE into these agencies to be completed by October 1, 2011. Interior will create the Bureau of Ocean Energy Management, which will have responsibility for leasing and environmental studies, and the Bureau of

Safety and Environmental Enforcement, which will have responsibility for field operations, including inspections, regulatory compliance, and oil spill response. Once the reorganization is completed, the BOEMRE will cease to exist. At this time, we cannot predict the impact that this reorganization, or future regulations or enforcement actions taken by the new agencies, may have on our operations.

We may need to obtain bonds or other surety in order to maintain compliance with regulations promulgated by the BOEMRE, which, if required, could be costly and reduce borrowings available under our new credit facility or any other credit facilities we may enter into in the future.

The BOEMRE regulations with respect to offshore operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the outer continental shelf of the Gulf of Mexico and removal of facilities. The BOEMRE generally requires that lessees have substantial net worth or post bonds or other acceptable assurances so that the various obligations of lessees on the Gulf of Mexico shelf will be met. While we believe that we are currently exempt from the supplemental bonding requirements of the BOEMRE, the BOEMRE could re-evaluate our plugging obligations and increase them which could cause us to lose our exemption. The cost of these bonds or other surety could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety. Such letters of credit would likely be issued under our new credit facility or another credit facility we may enter into in the future and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. The cost of compliance with these supplemental bonding requirements could materially and adversely affect our financial condition, cash flows and results of operations.

We are subject to extensive governmental laws and regulations, including environmental regulations and permit requirements, that can adversely affect the cost, manner or feasibility of doing business and could result in restrictions on our operations or civil or criminal liability.

Our exploration, development and production operations, our activities in connection with storage and transportation of oil and other hydrocarbons and our use of facilities for treating, processing or otherwise handling hydrocarbons and related wastes are subject to various federal, state and local laws, orders and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties or the imposition of injunctive relief.

The construction and operation of our projects also require numerous permits and approvals from governmental agencies. If we are unable to acquire or renew permits and approvals required for operations, we may be forced to suspend or cease operations altogether. We may not be able to obtain all necessary permits and approvals, and as a result our operations may be adversely affected. In addition, obtaining all necessary permits and approvals may necessitate substantial expenditures and may create a risk of expensive delays or loss of value if a project is unable to proceed as planned due to changing requirements or local opposition.

Future compliance with laws and regulations, including environmental, production, transportation, sales, rate and tax rules and regulations, and any changes to such laws or regulations, may reduce our profitability and have a material adverse effect on our financial position, liquidity and cash flows. Such laws and regulations may require more stringent and costly waste handling, storage, transport, disposal or cleanup requirements. See “Business—Environmental Matters.”

The adoption of pending climate change legislation could result in increased operating costs, create delays in our obtaining air pollution permits for new or modified facilities, and reduce demand for the crude oil and natural gas we produce.

There are state, national and international efforts to regulate the emission of greenhouse gases including, most significantly, carbon dioxide. The U.S. Congress has considered legislation that seeks to control or reduce emissions of greenhouse gases from a variety of sources. In addition, several states have already taken legal

measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories or regional cap-and-trade programs. It is uncertain at this time whether, and in what form, climate change legislation will ultimately be adopted in the United States.

The EPA has started to implement regulations pertaining to greenhouse gas emissions. In 2009, the EPA issued a finding under section 202(a) of the Clean Air Act, concluding that greenhouse gas pollution endangers the public health and welfare of current and future generations and the EPA finalized a greenhouse gas emission standard for mobile sources. On September 22, 2009, the EPA finalized a greenhouse gas reporting rule that requires large sources of greenhouse gas emissions to monitor, maintain records on and annually report their greenhouse gas emissions. On November 8, 2010, the EPA also issued greenhouse gas monitoring and reporting regulations specifically for petroleum and natural gas facilities, including offshore petroleum and natural gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of greenhouse gas emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. The EPA issued a final rule that makes certain stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions, beginning in 2011, under the Clean Air Act. Several of the EPA’s greenhouse gas rules are being challenged in pending court proceedings and, depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Our operations are generally exempt from regulation by the FERC, but FERC regulations still affect our non-FERC jurisdictional businesses and the markets for products derived from these businesses. The FERC issued Order 704, which requires certain participants in the natural gas market, including interstate and intrastate pipelines, natural gas gatherers, natural gas marketers, and natural gas processors that engage in a minimum level of natural gas sales or purchases, to submit annual reports regarding those transactions.

Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company. We believe that our natural gas gathering facilities meet the traditional tests the FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is the subject of on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by the FERC or the courts.

In addition, the courts have determined that certain pipelines that would otherwise be subject to the ICA are exempt from regulation by the FERC under the ICA as proprietary lines. The classification of a line as a proprietary line is a fact-based determination subject to FERC and court review. Accordingly, the classification and regulation of some of our gathering facilities and transportation pipelines may be subject to change based on future determinations by the FERC or the courts.

The BOEMRE has communicated that it will commence more stringent enforcement of requirements to decommission facilities that pose a hazard to safety or the environment or are not useful for lease operations and are not capable of oil and natural gas production in “paying quantities.” Historically, the BOEMRE granted approval to operators to maintain such facilities in order to conduct other future activities. However, we expect that this practice will be more limited in the future. The BOEMRE has stated that these measures are in response to recent hurricane seasons in which idle structures were damaged or destroyed. We recently responded to a BOEMRE written request to review and evaluate our inventory of non-producing wells and facilities to determine the future utility of these structures and the level of threat posed to the environment and human safety in the event of a “catastrophic loss.” As a result, we periodically review our plans with the BOEMRE to perform wellbore plugging and abandonment and decommissioning work on certain facilities and structures in our East Bay field.

The BOEMRE and other regulatory bodies, including those regulating the decommissioning of our pipelines and facilities under the jurisdiction of the state of Louisiana, may change their requirements or enforce requirements in a manner inconsistent with our expectations, which could materially increase the cost of such activities and/or accelerate the timing of cash expenditures and could have a material adverse effect on our financial position, results of operations and cash flows.

The failure to comply with these rules and regulations can result in substantial penalties, including lease termination in the case of federal leases. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations, though the impact of those requirements may vary significantly based on the nature and location of operations and related pipelines and facilities.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the EPAct of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. While our systems have traditionally not been subject to full FERC regulation, the FERC’s civil penalty authority may apply to a broad range of market participants that have not historically been subject to its regulations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to annual reporting requirements. Additional rules and regulations that impact our facilities and operations may be considered or adopted by the FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Our sales of oil and natural gas, and any hedging activities related to such energy commodities, expose us to potential regulatory risks.

The FERC, the Federal Trade Commission and the CFTC, hold statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil and natural gas, and any hedging activities related to these energy commodities, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority.

Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition or results of operations.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

The U.S. Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material effect on our financial condition and our results of operations.

The proposed U.S. federal budget for fiscal year 2011 includes certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

On February 1, 2010, the Obama administration released its proposed federal budget for fiscal year 2011. The proposed budget would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and impose new taxes. The provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; increases in the taxation of foreign source income; levy of an excise tax on Gulf of Mexico oil and gas production; repeal of the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing leases located on federal lands.

To date, none of these proposals has been enacted. However, should any of these proposals be enacted, our taxes may increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities. Since none of these proposals has yet been voted on or become law, we do not know the ultimate impact any of these proposals may have on our business.

Terrorist attacks aimed at our facilities could adversely affect our business.

Since the September 11, 2001 terrorist attacks, the U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, or those of our customers, could have a material adverse affect on our financial condition and operations.

Item 1B.

Unresolved Staff Comments

None.

Item 2.

Properties

The information contained in Part I, Item 1, “Business” of this Annual Report is incorporated by reference.

Item 3.

Legal Proceedings

For information regarding legal proceedings, see the information in Note 16, “Commitments and Contingencies” in the consolidated financial statements in Part II, Item 8 of this Annual Report.

PART II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Since September 23, 2009, the common stock of the reorganized Company (the “Successor Company”) has been listed on the New York Stock Exchange (the “NYSE”) under the symbol “EPL.” During the period from March 30, 2009 through September 21, 2009, our common stock was quoted for public trading on the Pink Sheets quotations system, an over-the-counter market, under the symbol “ERPLQ.PK.” Prior to March 30, 2009, the common stock of the pre-reorganized Company (the “Predecessor Company”) was listed on the NYSE under the symbol “EPL.” The following table sets forth, for the periods indicated, the range of the high and low sales prices of our common stock as reported by the NYSE (through the First Quarter 2009 and subsequent to September 22, 2009) and the Pink Sheets quotations system (subsequent to First Quarter 2009 through September 21, 2009).


	High		Low
	($)		($)
Predecessor Company
2009
First Quarter		2.34		0.08
Second Quarter		0.45		0.05
Third Quarter (through September 21, 2009)		0.47		0.27


Successor Company

2009
Third Quarter (from September 23 to September 30, 2009)		11.73		6.81
Fourth Quarter		9.39		7.25

2010
First Quarter		12.35		8.28
Second Quarter		14.62		11.36
Third Quarter		13.22		9.61
Fourth Quarter		15.00		10.75

2011
First Quarter (through February 25, 2011)		16.38		13.95

On February 25, 2011, the last reported sales price of our common stock on the NYSE was $16.38 per share.

As of February 25, 2011, there were approximately 151 holders of record of our common stock.

We have not paid any cash dividends in the past on our common stock. The covenants in certain debt instruments to which we are a party, including our new credit facility and the Indenture related to our 8.25% Notes, place certain restrictions and conditions on our ability to pay dividends. Any future cash dividends would depend on contractual limitations, future earnings, capital requirements, our financial condition and other factors determined by our board of directors.

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of December 31, 2010 with respect to compensation plans under which our equity securities are authorized for issuance.


	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights (1)		Weighted Average Exercise Price of Outstanding Options Warrants and Rights (2)		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by stockholders		—		—		—
Equity compensation plans not approved by stockholders (3)		509,986	$	10.49		630,737

Total		509,986	$	10.49		630,737

(1)	Comprised of 488,616 shares subject to issuance upon the exercise of options and 21,370 shares which will vest upon the lapsing of restrictions associated with restricted share awards.

(2)	Restricted share awards do not have an exercise price; therefore, this only reflects the weighted-average exercise price of options.

(3)	The form of the 2009 Long Term Incentive Plan was filed with the Plan Supplement and approved by the Bankruptcy Court prior to our emergence from Chapter 11 reorganization. Accordingly, no stockholder approval was required, and none was sought or obtained.

See Note 15 “Employee Benefit Plans” of the consolidated financial statements in Part II, Item 8 of this Annual Report for further information regarding the significant features of the above plan.

Item 6.

Selected Financial Data

The following table shows selected financial data derived from our consolidated financial statements, which are set forth in Part II, Item 8, “Financial Statements and Supplementary Data” of this Annual Report. The data should be read in conjunction with Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report.


	Successor Company						Predecessor Company (1)
	Year Ended December 31, 2010			Period from October 1, 2009 through December 31, 2009			Period from January 1, 2009 through September 30, 2009			Years Ended December 31,
	Year Ended December 31, 2010			Period from October 1, 2009 through December 31, 2009			Period from January 1, 2009 through September 30, 2009			2008			2007 (2)			2006
	(In thousands, except per share data)
Statement of Operations Data:
Revenue	$	239,909		$	56,750		$	134,885		$	356,252		$	454,649		$	449,550
Income (loss) from operations (3)		7,309			(4,523	)		(51,323	)		(25,531	)		(56,013	)		(55,343	)
Net loss		(8,468	)		(21,012	)		(36,114	)		(52,212	)		(79,955	)		(50,400	)
Basic and diluted loss per common share	$	(0.21	)	$	(0.53	)	$	(1.12	)	$	(1.63	)	$	(2.32	)	$	(1.32	)


	Successor Company As of				Predecessor Company (1) As of December 31,
	December 31, 2010		December 31, 2009		2008		2007 (2)		2006
	(In thousands)
Balance Sheet Data:
Total assets	$	626,906	$	709,228	$	766,766	$	814,856	$	1,003,845
Long-term debt, excluding current maturities (4)		—		58,590		—		484,501		317,000
Stockholders’ equity		473,116		480,087		57,119		101,970		372,269
Cash dividends per common share		—		—		—		—		—

(1)

In connection with our emergence from Chapter 11 reorganization, we adopted fresh-start accounting as of September 30, 2009. Fresh-start accounting is required upon a substantive change in control and requires that the reporting entity allocate the reorganization value of the Company to its assets and liabilities in relation to their fair values. Under the provisions of fresh-start accounting, a new entity has been deemed created for financial reporting purposes.

(2)	Amounts in 2007 reflect the sale of substantially all of our onshore South Louisiana assets in June 2007.

(3)	The loss from operations in 2008, 2007 and 2006 includes business interruption insurance recoveries of $4.2 million, $9.1 million and $32.9 million, respectively, from deferred production at our covered fields resulting from Hurricanes Gustav and Ike in 2008 and Katrina and Rita in 2005.

(4)

Long-term debt classified as current was $18.8 million and $497.5 million at December 31, 2009 and 2008, respectively. At December 31, 2007 and 2006, none of our debt was classified as current. At December 31, 2010, we had no borrowings outstanding. On February 14, 2011, we issued $210.0 million in aggregate principal amount of our 8.25% Notes due 2018.

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

We were incorporated as a Delaware corporation in January 1998 and operate in a single segment as an independent oil and natural gas exploration and production company. Our current operations are concentrated in the U.S. Gulf of Mexico shelf focusing on state and federal waters offshore Louisiana, which we consider our core area. We have focused on acquiring and developing assets in this region, as it offers a balanced and

expansive array of existing and prospective exploration, exploitation and development opportunities in both established productive horizons and deeper geologic formations. As of December 31, 2010, we had estimated proved reserves of 27.4 million barrels of oil equivalent, or Mmboe, of which 63% were oil and 93% were proved developed. Of these proved developed reserves, 63% were oil reserves.

Recent Developments

The ASOP Acquisition and Notes Offering. On February 14, 2011, we acquired an asset package consisting of certain shallow-water Gulf of Mexico shelf oil and natural gas interests surrounding the Mississippi River delta and a related gathering system (the “ASOP Properties”) from Anglo-Suisse Offshore Partners, LLC (“ASOP”) for $200.7 million in cash, subject to customary adjustments to reflect an economic effective date of January 1, 2011 (the “ASOP Acquisition”). As of December 31, 2010, the ASOP Properties had estimated proved reserves of approximately 8.1 Mmboe, of which 84% were oil and 76% were proved developed reserves. Of these proved developed reserves, 88% were oil reserves. The ASOP Properties:

•

include 59 producing wells in three complexes;

•

had average daily production of approximately 3,344 Boe per day for the three months ended December 31, 2010;

•

include 48,106 gross and 37,402 net acres; and

•

include related gathering lines.

The ASOP Acquisition was financed with the proceeds from the sale of $210 million in aggregate principal amount of 8.25% senior notes due 2018 (the “8.25% Notes”) offered to qualified institutional buyers pursuant to Rule 144A promulgated under the Securities Act of 1933, as amended (the “Securities Act”), and to persons outside the United States pursuant to Regulation S promulgated under the Securities Act. After deducting the initial purchasers’ discount and estimated offering expenses, we realized net proceeds of approximately $202 million. On February 14, 2011, we also entered into an agreement for a new credit facility. See “—Financial Condition, Liquidity and Capital Resources” for more information regarding the 8.25% Notes and the new credit facility.

The ASOP Acquisition provides an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus on oil-weighted assets in our core area of expertise in the Gulf of Mexico shelf. The ASOP Acquisition also provides us with access to infrastructure and extensive acreage, with significant exploitation and development potential. We intend to pursue exploitation of the ASOP Properties, including recompletions, well reactivations and development drilling, while we analyze the potential for higher-impact exploration prospects. We operate properties containing approximately 60% of the proved reserves attributable to the ASOP Properties. We have begun to implement a three-year commodity price hedging program weighted towards oil in conjunction with the ASOP Acquisition to manage commodity price risks associated with future oil production.

Overview and Outlook

Our reorganization under Chapter 11 in 2009 substantially reduced our indebtedness and restructured our balance sheet. Throughout the course of our Chapter 11 reorganization, we continued to operate in the ordinary course of business without the sale of any assets and continued to meet our business obligations to our vendors and joint interest owners. We emerged from our Chapter 11 reorganization with an improved capital structure and enhanced financial flexibility. In 2010, we continued to improve our financial strength by repaying all of our high yield PIK Notes (defined below) and entering into the Amended Prior Credit Facility (defined below). See “—Chapter 11 Reorganization—Emergence from Chapter 11 Reorganization.”

During 2009, including the period following our emergence from Chapter 11 reorganization, we undertook meaningful cost reductions in general and administrative (“G&A”) expenses and lease operating expenses

(“LOE”). These cost reductions included significant reductions both in our workforce and office space in our New Orleans and Houston offices, reductions in the use of third party contractors and consultants, lower marine transportation and liftboat costs and lower corporate governance costs. During 2010 we also continued to focus on (1) achieving meaningful cost reductions in G&A expenses and LOE; (2) converting non-producing reserves to cash flow; and (3) developing a core competency in plugging, abandonment and decommissioning operations. We allocate capital in a rigorous and disciplined manner intended to achieve an overall lower risk capital expenditure profile that focuses on maximizing rate of return and requires projects to compete on that basis.

Our development efforts during 2010 focused on our oil-rich East Bay field where average daily production increased 18% for the year ended December 31, 2010, as compared to the year ended December 31, 2009. As a result, our 2010 average oil production levels exceeded our 2009 levels. Prior to 2010, we established an initial low-risk capital budget oriented towards stabilizing production at the levels experienced in the quarter ended December 31, 2009 and have since continued to develop additional production enhancing opportunities, some of which were approved in excess of our initial capital budget. As of the date of this Annual Report, our fiscal year 2011 capital budget is $110 to $125 million (excluding the cost of acquiring the ASOP properties), $80 million of which is allocated to development of our existing Gulf of Mexico shelf asset base primarily in the East Bay and South Timbalier field areas, $20 million of which is allocated to exploration projects and an additional $10 million to $25 million of which is allocated to development projects within the recently acquired ASOP Properties. We also plan to spend approximately $17 million in 2011 on plugging, abandonment and other decommissioning activities. Our key areas of operations and our plans for future exploration and development activities do not include any deepwater areas.

We continually review and monitor opportunities to acquire producing properties, leasehold acreage and drilling prospects so that we can act quickly as acquisition opportunities become available. We intend to focus our acquisition strategy on Gulf of Mexico shelf assets that are characterized by production-weighted reserves, seismic coverage and operated positions. We intend to use acquisitions of this type as a key method to replace and grow reserves and production, because we believe this strategy increases production and cash flow visibility while reducing dry hole and exploration risk. We believe our expertise in the Gulf of Mexico shelf and in plugging and abandonment operations allows us to effectively evaluate acquisitions and to operate any properties we eventually acquire.

We continue to generate prospects, strive to maintain an extensive inventory of drillable prospects in-house and maintain exposure to new opportunities through relationships with industry partners. Generally, we fund any exploration and development expenditures with internally generated cash flows.

Our longer term operating strategy is to increase our oil and natural gas reserves and production while focusing on reducing exploration and development costs and operating costs to remain competitive with our offshore Gulf of Mexico industry peers.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as oil and natural gas prices, tropical weather, economic, political and regulatory developments and availability of other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil and natural gas could materially adversely affect our financial position, our results of operations, our cash flows, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. See “Risk Factors” for a more detailed discussion of these risks.

We are also focused on the development of a core competency in plugging, abandonment and decommissioning operations in an attempt to reduce our overall costs in that area of operations, which will enable us to achieve our objectives of prudently removing idle infrastructure throughout the remaining productive lives of our fields and, over time, to reduce ongoing LOE associated with maintaining idle infrastructure.

Basis of Presentation

On May 1, 2009, we and certain of our subsidiaries filed voluntary petitions (In re: Energy Partners, Ltd., et. al., Case No. 09-32957) for reorganization under Chapter 11 of Title 11 of the United States Code, 11 U.S.C. §§ 101 et seq., as amended (“Chapter 11”), in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). On September 17, 2009, the Bankruptcy Court entered an order confirming the plan of reorganization we had filed with the Bankruptcy Court (the “Plan of Reorganization”). On September 21, 2009 (the “Exit Date”), we emerged from Chapter 11 reorganization pursuant to the Plan of Reorganization. In accordance with ASC Topic 852, “Reorganizations” (“ASC 852”), we adopted fresh-start accounting as of September 30, 2009. Fresh-start accounting is required upon a substantive change in control and requires that the reporting entity allocate the reorganization value of the Company to its assets and liabilities in relation to their fair values. Under the provisions of fresh-start accounting, a new entity has been deemed created for financial reporting purposes. In this Annual Report, references to the “Predecessor Company” refer to reporting dates of the Company through September 30, 2009, including the effect of the provisions of the Plan of Reorganization and the application of fresh-start accounting; activity of the Company subsequent to September 30, 2009 is referred to as that of the “Successor Company.” For more information on our reorganization, see “—Chapter 11 Reorganization.”

As a result of our reorganization under Chapter 11 and the application of fresh-start accounting in accordance with ASC 852, our financial statements for periods prior to September 30, 2009 are not comparable to our financial statements for periods on or after September 30, 2009. The presentation of combined financial information for the year ended December 31, 2009 is not in accordance with accounting principles generally accepted in the United States (“GAAP”). However, our Chapter 11 reorganization did not result in the disposition of any of our oil and natural gas properties. As a result, the comparability of certain components of our operating results and key operating performance measures, specifically those related to production, average oil and natural gas selling prices, revenues and lease operating expenses, was not significantly impacted by the reorganization. Therefore, we believe that for purposes of discussion and analysis, those combined financial results are useful for management and investors when analyzing our operational performance and by helping to facilitate a year-to-year discussion. In the following discussion, references to combined results for the year ended December 31, 2009 combine the period from January 1, 2009 through September 30, 2009 (reflecting the operations of the Predecessor Company) with the period from October 1, 2009 through December 31, 2009 (reflecting the operations of the Successor Company).

Our depreciation, depletion and amortization (“DD&A”) was affected by our reorganization and application of fresh-start accounting. Thus, changes in DD&A and DD&A rates are not comparable for the periods presented. Generally, because oil prices were higher as of September 30, 2009, the date at which we applied fresh-start accounting, as compared to oil prices as of December 31, 2008, a date at which we recorded significant impairments of certain of our oil and natural gas properties, estimated reorganization values allocated to our longer-lived oil properties were higher on a per Boe basis than values allocated to our shorter-lived natural gas properties. As a result, our overall DD&A rate per Boe declined for the 2010 period.

Our reported asset retirement obligations (i.e., relating to decommissioning) were impacted by our reorganization and application of fresh-start accounting. We estimate our asset retirement obligations based on factors described in “—Discussion of Critical Accounting Policies.” The accretion of liability for asset retirement obligations is significantly affected by the credit-adjusted risk-free discount rate applied to our estimated future costs to plug, abandon and perform other decommissioning activities on our oil and natural gas properties. As a result of our reorganization, the credit adjusted risk-free rate we used as of September 30, 2009 was significantly higher than the rates used to record asset retirement obligations in prior periods. As a result, we expect the amount of future accretion of the liability for asset retirement obligations to be significantly higher than amounts reported in prior years.

We use the successful efforts method of accounting for our investment in oil and natural gas properties. Under this method, we capitalize lease acquisition costs, costs to drill and complete exploration wells in which

proven reserves are discovered and costs to drill and complete development wells. Exploratory drilling costs are charged to expense if and when the well is determined not to have found reserves in commercial quantities. Seismic, geological and geophysical, and delay rental expenditures are expensed as incurred. We conduct many of our exploration and development activities jointly with others and, accordingly, recorded amounts for our oil and natural gas properties reflect only our proportionate interest in such activities.

Chapter 11 Reorganization

Background to Chapter 11 Reorganization. Our filing for reorganization under Chapter 11 was preceded by a number of events and economic conditions that negatively impacted our business and liquidity, including the following:

•

hurricanes in August and September of 2008 damaged third party production pipelines, causing us to shut-in a significant amount of our production from September 2008 and continuing into early 2009;

•

oil and natural gas prices declined in the fourth quarter of 2008 and remained at relatively low levels during 2009 relative to the levels in 2008; and

•

the worldwide credit and capital markets collapsed in 2008 and the availability of debt and equity financing became significantly more scarce, thus reducing financial flexibility for most companies, including us.

These factors negatively impacted our business, and led to several circumstances that significantly affected our liquidity and led to our filing for Chapter 11 reorganization, including:

•

in the third quarter of 2008, the Minerals Management Service (the “MMS”) (now the BOEMRE) rejected our request for a waiver of supplemental bonding requirements for the decommissioning of certain of our federal offshore properties, resulting in the requirement for us to provide cash or other financial support totaling $47.3 million. As a result, the MMS issued an order to us on March 23, 2009 (the “MMS Order”) that resulted in the shut-in of the federal portion of our East Bay field;

•

in March 2009, we received a notice of redetermination from Bank of America, N.A., the Administrative Agent under the Predecessor Company’s Credit Agreement dated as of April 23, 2007 (the “Pre-Reorganization Credit Agreement”), that our borrowing base under the Pre-Reorganization Credit Agreement had been reduced from $150.0 million to $45.0 million, resulting in a borrowing base deficiency of $38.0 million that was required to be repaid by April 3, 2009 (which date was ultimately extended to May 1, 2009); and

•

on April 15, 2009, we were required to make scheduled interest payments of approximately $17 million on the Predecessor Company’s 9.75% Senior Unsecured Notes due 2014 and its Senior Floating Notes due 2013.

Our inability to satisfy these obligations in a timely manner ultimately led to our filing for reorganization under Chapter 11.

Emergence from Chapter 11 Reorganization. On the Exit Date, we consummated certain transactions contemplated by the Plan of Reorganization, including entering into a senior secured credit facility consisting of a $125.0 million revolving credit facility with an initial borrowing base of $45.0 million (the “Prior Revolver”) and a $25.0 million one-year amortizing term loan facility (together with the Prior Revolver, the “Prior Credit Facility”). On the Exit Date, we drew $25 million under the Prior Revolver. We also issued 20% Senior Subordinated Secured PIK Notes due 2014 in an aggregate original principal amount of $61.1 million (the “PIK Notes”). The PIK Notes were issued with original issue discount, and the net proceeds after this discount were $55.0 million. The proceeds from the Prior Credit Facility and the PIK Notes were used to repay amounts outstanding of $83.0 million under the Pre-Reorganization Credit Agreement and to provide working capital for the Company.

During 2010, a key focus of management was to reduce our cost of capital. In June 2010, we reached an agreement to amend our Prior Credit Facility (the “Amended Prior Credit Facility”), which enabled us to redeem our PIK Notes. On June 28, 2010, we paid a total of $70.9 million of principal and accrued interest in connection with the redemption of the PIK Notes. We used cash on hand and a portion of the proceeds of a new $25.0 million term loan under the Amended Prior Credit Facility to fund the redemption. The Amended Prior Credit Facility established a $70.0 million borrowing base consisting of the new $25.0 million term loan and a revolving credit facility with a three-year term that could be used for revolving credit loans and letters of credit up to an initial maximum principal amount of $45.0 million.

On the Exit Date, we also converted the Predecessor Company’s 9.75% Senior Unsecured Notes due 2014, its Senior Floating Rate Notes due 2013 and its 8.75% Senior Notes due 2010, in an aggregate principal amount of approximately $454.5 million (collectively the “Predecessor Company Notes”) and all outstanding shares of the Predecessor Company’s common stock into shares of the Successor Company’s common stock. In accordance with the terms of the Plan of Reorganization, the Predecessor Company Notes and related indentures were cancelled and each existing holder of the Predecessor Company Notes received, in exchange for such holder’s claim (including principal and accrued interest), such holder’s pro rata portion of approximately 95% of the Successor Company’s common stock. Each holder of shares of the Predecessor Company’s common stock received, in full satisfaction of and in exchange for such holder’s interest in the common stock of the Predecessor Company, such holder’s pro rata portion of approximately 5% of the Successor Company’s common stock.

Shortly following our emergence from Chapter 11 reorganization, we provided the MMS, now known as the BOEMRE, with surety bonds in support of decommissioning obligations on certain federal leases in the Gulf of Mexico, and we resumed production from the federal portion of the East Bay field. During April 2010, we regained supplemental waiver status, and we are no longer required to post these surety bonds.

On the Exit Date, the MMS Order was rescinded. We subsequently delivered to the MMS the financial support related to abandonment obligations on certain federal leases in the Gulf of Mexico and we resumed production from the federal portion of the East Bay field.

We emerged from our Chapter 11 reorganization with a five-member board of directors whose members were appointed by operation of the Plan of Reorganization with the approval of the Bankruptcy Court. The Board includes members with significant experience in the oil and gas exploration and production industry. On the Exit Date, the Board appointed a new chief executive officer to lead our executive management team. See Part III of this Annual Report for more information on our board of directors and chief executive officer.

Our Chapter 11 reorganization and related matters are also addressed in Note 4, “Reorganization and Fresh-Start Accounting” to our consolidated financial statements contained in Part II, Item 8, “Financial Statements and Supplementary Data.”

Results of Operations

The following table presents information about our oil and natural gas operations. Our Chapter 11 reorganization did not result in the disposition of any of our oil and natural gas properties. As a result, the comparability of certain components of our operating results and key operating performance measures, specifically those related to production, average oil and natural gas selling prices, revenues and lease operating expenses, was not significantly impacted by the reorganization.


	Successor Company Year Ended December 31, 2010			Successor Company Period from October 1, 2009 through December 31, 2009			Predecessor Company Period from January 1, 2009 through September 30, 2009		Non-GAAP Combined Results for the Year Ended December 31, 2009			Predecessor Company Year Ended December 31, 2008
Net production (per day):
Oil (Bbls)		6,401			6,091			5,127		5,370			5,608
Natural gas (Mcf)		42,488			45,726			61,029		57,172			45,070
Total (Boe)		13,482			13,712			15,299		14,899			13,120
Average sales prices:
Oil (per Bbl)	$	72.80		$	68.03		$	49.88	$	55.07		$	97.42
Natural gas (per Mcf)		4.49			4.42			3.89		3.99			9.46
Total (per Boe)	$	48.72		$	44.95		$	32.22	$	35.18		$	74.15
Oil & natural gas revenues (in thousands):
Oil	$	170,079		$	38,121		$	69,812	$	107,933		$	199,948
Natural gas		69,691			18,587			64,771		83,358			156,074

Total	$	239,770		$	56,708		$	134,583	$	191,291		$	356,022
Impact of derivatives settled during the period (1):
Oil (per Bbl)	$	(3.62	)	$	(1.73	)	$	1.82	$	0.80		$	(7.85	)
Natural gas (per Mcf)	$	0.01		$	—		$	0.01	$	0.01		$	0.02
Average costs (per Boe):
LOE	$	10.64		$	10.63		$	11.09	$	10.98		$	14.98
Taxes, other than on earnings	$	2.06		$	1.65		$	1.43	$	1.48		$	2.34
G&A expenses	$	3.67		$	3.60		$	4.67	$	4.42		$	7.77
Increase (decrease) in oil and natural gas revenue due to:
Change in prices of oil	$	34,751							$	(87,203	)
Change in production volumes of oil		27,395								(4,812	)

Total increase (decrease) in oil sales		62,146								(92,015	)
Change in prices of natural gas		10,461								(90,428	)
Change in production volumes of natural gas		(24,128	)							17,712

Total decrease in natural gas sales		(13,667	)							(72,716	)

(1)	See “—Other Income and Expense” section for further discussion of the impact of derivative instruments.

(2)	The table does not include any information about oil and gas operations associated with the ASOP Properties, which we acquired on February 14, 2011.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Overview

During the year ended December 31, 2010, we completed nineteen (19) recompletion operations, fourteen (14) of which were successful; nine (9) exploratory drilling operations, seven (7) of which were successful; and one (1) development well which was successful.

Our operating results for the year ended December 31, 2010, compared to the year ended December 31, 2009, reflect higher average selling prices for both our oil and natural gas and declines in LOE and G&A expenses. The decline in LOE and G&A expenses is primarily due to the impact of our cost reduction efforts in the 2010 period.

For the year ended December 31, 2010, our revenues increased 25% as compared to the year ended December 31, 2009 due primarily to higher average selling prices for our oil production and the increase in oil production. Our overall production volumes declined by 10%, on a barrel equivalent basis, for the year ended December 31, 2010 when compared to the year ended December 31, 2009. Additionally, our product mix reflects an increase in oil production and a decrease in natural gas production for the year ended December 31, 2010 as compared to the year ended December 31, 2009.

Our Gulf of Mexico shelf production declined 8% in the year ended December 31, 2010, as compared to the year ended December 31, 2009, due primarily to natural reservoir declines in the second half of 2009 and continuing throughout 2010, offset in part by an overall increase in oil production primarily from our East Bay field. Our deepwater production, primarily natural gas, declined 18% for the year ended December 31, 2010, as compared to the year ended December 31, 2009, which was due primarily to natural reservoir decline from our deepwater well. We expect that our deepwater production will continue to decline in the future.

In June 2010, we paid a total of $70.9 million of principal and accrued interest in connection with the redemption of the PIK Notes. We redeemed all of the PIK Notes at 100% of the outstanding aggregate principal amount, plus accrued and unpaid interest. As a result, during the year ended December 31, 2010, we recorded a loss on extinguishment of debt totaling $5.6 million which represents the total of the unamortized original issue discount and unamortized deferred financing costs associated with the PIK Notes.

Our effective income tax rate for the year ended December 31, 2010 was 34.2%. The income tax benefit recorded on the net loss for the year ended December 31, 2010 was reduced due to our applying the change in our estimated effective income tax rate for the full 2010 year, from 36.0% to 37.6%, to our net deferred tax liabilities. The change in our estimated effective income tax rate for 2010 is primarily related to state income taxes. Our effective income tax rate for the quarter ended December 31, 2009 was an approximately 35% benefit on the loss before income taxes for the quarter as a result of the change in our deferred tax position due to the reorganization. Our effective income tax rate for the nine months ended September 30, 2009 was zero because we provided a valuation allowance against the net deferred tax assets generated during the nine months ended September 30, 2009. The impact of the reorganization on our deferred tax position is more fully addressed in Note 14, “Income Taxes,” of the consolidated financial statements in Part II, Item 8 of this Annual Report. Our future income taxes may be materially impacted by our reorganization.

Revenues


	Successor Company Year Ended December 31, 2010		Successor Company Period from October 1 through December 31, 2009		Predecessor Company Period from January 1 through September 30, 2009		Non-GAAP Combined Year Ended December 31, 2009
	(in thousands)
Oil and natural gas revenues	$	239,770	$	56,708	$	134,583	$	191,291

Our oil and natural gas revenues increased primarily due to a 32% increase in average selling prices for our oil and a 19% increase in oil production in the year ended December 31, 2010 as compared to the year ended December 31, 2009, offset in part by a 26% decline in natural gas production in the year ended December 31, 2010 as compared to the year ended December 31, 2009. The percentage of production represented by oil has increased for us. Oil represented 47% of total production for the year ended December 31, 2010, as compared to 36% of total production for the year ended December 31, 2009.

Operating Expenses

Our operating expenses primarily consist of the following:


	Successor Company Year Ended December 31, 2010		Successor Company Period from October 1 through December 31, 2009		Predecessor Company Period from January 1 through September 30, 2009		Non-GAAP Combined Year Ended December 31, 2009
	(in thousands)
LOE	$	52,365	$	13,410	$	46,296	$	59,706
Exploration expenditures and dry hole costs		6,441		453		1,650		2,103
Impairments		26,142		8,514		8,082		16,596
DD&A, including accretion expense (1)		117,406		31,472		101,480		NM
G&A expenses		18,078		4,537		19,493		24,030
Taxes, other than on earnings		10,133		2,083		5,987		8,070

NM – Not meaningful.

(1)	DD&A, including accretion expense, is not comparable for the periods presented due to the application of fresh-start accounting.

We completed drilling two exploratory dry holes and recorded approximately $5.1 million of dry hole costs in the year ended December 31, 2010. In addition, the expense in the year ended December 31, 2010 includes $1.3 million of seismic expenditures and delay rentals. Our exploratory expenditures and dry hole costs will vary significantly depending on the amount of our capital expenditures dedicated to exploration activities and the level of success we achieve in exploratory drilling activities.

Impairment expense for the year ended December 31, 2010 was primarily related to the decline in our estimate of future natural gas prices as of September 30, 2010 as compared to June 30, 2010 affecting two producing fields, including our deepwater producing well, and to reservoir performance of one of these fields and one additional producing field. These producing fields were determined to have future net cash flows less than their carrying values resulting in the write down of these properties to their estimated fair values during the year ended December 31, 2010. Impairment expense recorded by the Successor Company in the quarter ended December 31, 2009 was primarily related to two wells in our Gulf of Mexico shelf area, one of which was unsuccessfully recompleted in 2010; the other was determined to be mechanically unable to produce a behind-pipe reservoir. Impairment expense recorded by the Predecessor Company in the period from January 1, 2009 through September 30, 2009 was primarily due to amounts recorded in the quarter ended March 31, 2009 related to two producing fields which were determined to have future net cash flows less than their carrying values due to commodity price declines and reservoir performance. We periodically assess our oil and natural gas assets for impairment based on factors described in “—Discussion of Critical Accounting Policies.” The factors that can result in impairment include declines in the estimated future selling prices of oil and natural gas. Due to our reorganization and application of fresh-start accounting, we recorded our oil and natural gas properties in the consolidated balance sheet of the Successor Company at their estimated fair market values, based on assumptions including the estimates of future oil and natural gas prices as of September 30, 2009. As a result, our capitalized oil and natural gas property costs may be more sensitive to future material impairments than those of other companies in our industry.

G&A expenses, which include cash and non-cash stock based compensation of $1.3 million and $4.3 million in the years ended December 31, 2010 and 2009, respectively, decreased in the year ended December 31, 2010, as compared to the year ended December 31, 2009, primarily as a result of the impact of cost reduction efforts on the 2010 period, offset in part by litigation costs and costs incurred in our acquisition efforts in the 2010 period.

Taxes, other than on earnings, increased in the year ended December 31, 2010 as compared to the year ended December 31, 2009, due primarily to production taxes resulting from higher average sales prices for oil (which is taxed based on value) and higher estimated franchise taxes in the 2010 period.

Other Income and Expense

Our interest expense was impacted by our Chapter 11 reorganization and is not comparable for the periods presented. Interest expense in the year ended December 31, 2010 consists primarily of interest expense on our PIK Notes and our Prior Credit Facility. We redeemed all of our outstanding PIK Notes on June 28, 2010. Interest expense in the nine months ended September 30, 2009 consists primarily of interest expense on the Predecessor Company Notes. However, as described above, we had discontinued accruing interest on the Predecessor Company Notes as of May 1, 2009, the date we filed for reorganization under Chapter 11, and the Predecessor Company Notes were discharged in the reorganization.

Other income (expense) in the year ended December 31, 2010 includes a net loss of $4.9 million consisting of an unrealized gain of $3.5 million due to the change in fair market value of derivative instruments and a loss of $8.4 million on derivative instruments settled during the period primarily from the impact of our oil fixed-price swaps. Prior to or shortly following our filing for reorganization during 2009, the Predecessor Company settled all outstanding derivative instruments, realizing a gain on those instruments due to the low price environment existing at the time of settlement. In connection with entering into the Prior Credit Facility on the Exit Date, we entered into derivative instruments, primarily oil swaps, pursuant to the terms set forth in the Prior Credit Facility. Due to an increase in market prices for oil during the quarter ended December 31, 2009, the Successor Company recorded unrealized losses on derivative instruments of $21.7 million and losses on settlements of $1.0 in the quarter ended December 31, 2009.

As described above, during the year ended December 31, 2010, we redeemed all of the PIK Notes at 100% of the outstanding aggregate principal amount, plus accrued and unpaid interest. As a result, we recorded a loss on extinguishment of debt totaling $5.6 million.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Overview

During the year ended December 31, 2009, we performed five workover operations, four of which were performed in our core fields during the second half of 2009. We completed drilling operations on one exploration well in the Gulf of Mexico shelf offshore area in early January 2010. We significantly curtailed our drilling operations beginning in the fourth quarter of 2008 and remained at significantly curtailed drilling activity levels during 2009 due to the factors impacting our liquidity addressed under “—Chapter 11 Reorganization—Background to Chapter 11 Reorganization”

Our operating results for the year ended December 31, 2009, compared to the year ended December 31, 2008, reflect significantly lower average selling prices for our oil and natural gas.

For the year ended December 31, 2009, our revenues declined 46% as compared to the year ended December 31, 2008 due primarily to significantly lower average selling prices for our production. Our overall production volumes increased by 14% for the year ended December 31, 2009 when compared to the year ended December 31, 2008 primarily due to new deepwater production, which averaged 1,694 Boe per day in the year ended December 31, 2009, along with the impact of the hurricanes curtailing our production in the latter half of 2008.

We performed four successful workovers in the second half of 2009 which, along with our production enhancement efforts focused primarily on oil producing wells, partially offset a decline in natural gas production from our Gulf of Mexico shelf area for the quarter ended December 31, 2009 as compared to the quarter ended September 30, 2009.

Our effective tax rate for the nine months ended September 30, 2009 was zero because we provided a valuation allowance against the net deferred tax assets generated during the period. Our effective tax rate for the quarter ended December 31, 2009 was an approximately 35% benefit on the loss before income taxes for the quarter as a result of the change in our net deferred tax position due to the reorganization. The impact of the reorganization on our deferred tax position is more fully addressed in Note 14, “Income Taxes,” of the consolidated financial statements contained in Item 8, “Financial Statements and Supplementary Data.” Our future income taxes may be materially impacted by our reorganization.

As more fully addressed in Notes 1, 2 and 4 of the consolidated financial statements contained in Item 8, “Financial Statements and Supplementary Data,” due to our reorganization, amounts reported in our balance sheet as of December 31, 2009 have changed materially from amounts reported as of December 31, 2008. The reorganization and application of ASC 852 adjustments included conversion of the principal and accrued interest on the Predecessor Company Notes into shares of the Successor Company’s common stock. We discontinued accruing interest on Predecessor Company Notes as of May 1, 2009, the date we filed for reorganization. Additionally, along with all of our assets and liabilities, our property and equipment assets and our asset retirement obligations were adjusted to reflect fair values as of September 30, 2009. As a result, our interest expense, accretion of liability for asset retirement obligations and depreciation, depletion and amortization following the reorganization are not comparable to those amounts recorded prior to the reorganization.

Our reported operating expenses for the year ended December 31, 2009, and most notably our G&A expenses, were materially impacted by the presentation of the reorganization items separately from operating income as required by ASC 852. Our reorganization items are disclosed in Note 5 of the consolidated financial statements contained in Item 8, “Financial Statements and Supplementary Data.” Additionally, our net loss for the year ended December 31, 2009 was materially impacted by the adjustments resulting from the reorganization and application of ASC 852 to reflect the loss on discharge of debt and the fresh-start adjustments.

Revenues


	Successor Company Period from October 1 through December 31, 2009		Predecessor Company Period from January 1 through September 30, 2009		Non-GAAP Combined Year Ended December 31, 2009		Predecessor Company Year Ended December 31, 2008
	(in thousands)
Oil and natural gas revenues	$	56,708	$	134,583	$	191,291	$	356,022

Our oil and natural gas revenues declined primarily as a result of the 53% decline in average selling prices for our oil and natural gas in the year ended December 31, 2009, as compared to the year ended December 31, 2008. Production increased by 14% in the year ended December 31, 2009 as compared to the year ended December 31, 2008, due primarily to new deepwater production, which averaged 1,694 Boe per day in the year ended December 31, 2009, along with the impact of the hurricanes curtailing our production in the latter half of 2008 which reduced our 2008 production by approximately 2,800 Boe per day.

Operating Expenses

Our operating expenses primarily consist of the following:


	Successor Company Period from October 1 through December 31, 2009		Predecessor Company Period from January 1 through September 30, 2009		Non-GAAP Combined Year Ended December 31, 2009		Predecessor Company Year Ended December 31, 2008
	(in thousands)
LOE	$	13,410	$	46,296	$	59,706	$	71,931
Exploration expenditures and dry hole costs		453		1,650		2,103		30,199
Impairments		8,514		8,082		16,596		110,403
DD&A, including accretion expense (1)		31,472		101,480		NM		107,688
G&A expenses		4,537		19,493		24,030		37,308
Taxes, other than on earnings		2,083		5,987		8,070		11,245

NM—Not meaningful.

(1)	DD&A, including accretion expense, is not comparable for the periods presented due to the application of fresh-start accounting.

LOE decreased in the year ended December 31, 2009, as compared to the year ended December 31, 2008, primarily due to fewer workovers in 2009 and ongoing efforts to reduce LOE costs during 2009.

Exploration expenditures and dry hole costs decreased in the year ended December 31, 2009, as compared to the year ended December 31, 2008, reflecting a significant decline in drilling activity in 2009.

Impairment expense recorded by the Predecessor Company in the period from January 1, 2009 through September 30, 2009 was primarily due to amounts recorded in the quarter ended March 31, 2009 related to two producing fields which were determined to have future net cash flows less than their carrying values due to commodity price declines and reservoir performance. Impairment expense recorded by the Successor Company in the quarter ended December 31, 2009 was primarily related to two wells in our Gulf of Mexico shelf area, one of which was unsuccessfully recompleted in 2010; the other was determined to be mechanically unable to produce a behind-pipe reservoir.

G&A expenses, which includes cash and non-cash stock based compensation of $4.3 million and $7.4 million in the year ended December 31, 2009 and 2008, respectively, decreased in the year ended December 31, 2009 from the year ended December 31, 2008, primarily as a result of a decrease in personnel and consulting costs, offset, in part, by an increase in insurance costs.

Taxes, other than on earnings, decreased in the year ended December 31, 2009 as compared to the year ended December 31, 2008, due primarily to lower average sales prices for oil (which is taxed based on value), offset, in part, by an increase in local property tax assessments. These taxes may fluctuate from period to period depending on our production volumes from non-federal leases and commodity prices received.

We recorded a loss on abandonment activities in the year ended December 31, 2009 primarily resulted from mechanical issues related to well and platform abandonments on two fields in our Gulf of Mexico shelf area.

We recorded a gain in the year ended December 31, 2008 related to the March 2008 sale of two Gulf of Mexico Shelf properties.

Other Income and Expense

Our interest expense was impacted by our reorganization and is not comparable for the periods presented. Interest expense decreased in the year ended December 31, 2009, as compared to the year ended December 31, 2008, primarily because we discontinued accruing interest on the Predecessor Company Notes as of the date we filed for reorganization under Chapter 11 and discharged the Predecessor Company Notes in the Chapter 11 reorganization.

The Predecessor Company settled all outstanding derivative instruments prior to or shortly following our filing for reorganization, realizing a gain on those instruments due to the low price environment existing at the time of settlement. In connection with entering into the Prior Credit Facility on the Exit Date, we entered into derivative instruments, primarily oil swaps, pursuant to terms set forth in the Prior Credit Facility. Due to an increase in the market prices for oil during the fourth quarter of 2009, the Successor Company recorded net unrealized losses on derivative instruments of $21.7 million and losses on settlements of $1.0 million in the fourth quarter of 2009. Other income (expense) in the year ended December 31, 2008 includes an unrealized gain of $19.1 million due to the change in fair market value of derivative instruments which were to be settled in the future and a loss of $17.0 million in derivative instruments settled during 2008 for a total net gain of $2.1 million.

Reorganization Items, Loss on Discharge of Debt and Fresh-Start Adjustments

Under ASC 852, certain costs and income items resulting from the reorganization and related to the Chapter 11 proceedings are reported separately as reorganization items classified as non-operating expenses. For the year ended December 31, 2009, our reorganization items totaled approximately $25.1 million, consisting primarily of $15.2 million in professional fees related to our financial and legal advisors and $6.8 million from the write-off of deferred financing costs associated with the Predecessor Company’s Pre-Reorganization Credit Agreement.

The restructuring of the Company’s capital and resulting discharge of the Predecessor Company Notes and related accrued interest resulted in a loss on discharge of debt of $2.7 million during 2009.

In order to reflect the adoption of fresh-start reporting pursuant to ASC 852, we adjusted the book values of the Predecessor Company’s assets and liabilities to reflect the estimated fair values of the Successor Company’s assets and liabilities, on a net basis. These fresh-start adjustments decreased our net loss by $57.1 million during 2009.

Financial Condition, Liquidity and Capital Resources

A key focus of management in 2010 was to reduce our cost of capital. In June 2010, we reached an agreement (described below) to amend our Prior Credit Facility with General Electric Capital Corporation, which enabled us to redeem our PIK Notes. On June 28, 2010, we paid a total of $70.9 million of principal and accrued interest in connection with the redemption of the PIK Notes. We redeemed all of the PIK Notes at 100% of the outstanding aggregate principal amount, plus accrued and unpaid interest. As a result, during the quarter ended June 30, 2010, we recorded a loss on extinguishment of debt totaling $5.6 million which represents the total of the unamortized original issue discount and unamortized deferred financing costs associated with the PIK Notes. We used cash on hand and a portion of the proceeds of the new term loan under our Amended Prior Credit Facility to fund the redemption.

ASOP Acquisition and Notes Offering. On February 14, 2011, we issued $210 million in aggregate principal amount of the 8.25% Notes. We used the net proceeds from the offering of the 8.25% Notes of $202 million, after deducting the initial purchasers’ discount and estimated offering expenses payable by us, to acquire the ASOP Properties for a purchase price of $200.7 million and for general corporate purposes. The 8.25% Notes bear interest from the date of their issuance at an annual rate of 8.25% with interest on outstanding notes payable semi-annually, in arrears, on February 15 and August 15 of each year, commencing on August 15, 2011. The

8.25% Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries). The 8.25% Notes will mature on February 15, 2018. For more information on our 8.25% Notes, see Note 9, “Indebtedness,” of our consolidated financial statements contained in Part II, Item 8 of this Annual Report.

New Senior Credit Facility. On February 14, 2011, we entered into our new credit facility with BMO Capital Markets, as lead arranger, Bank of Montreal, as administrative agent and a lender. Under the terms of the credit agreement, our new credit facility established a revolving credit facility with a four-year term that may be used for revolving credit loans and letters of credit up to an aggregate principal amount of $250.0 million, subject to an initial borrowing base of $150.0 million. The new credit facility is secured by substantially all of our assets, including mortgages on at least 85% of our oil and gas properties and the stock of certain wholly-owned subsidiaries. The borrowing base under the new credit facility has been determined at the discretion of the lenders, based on the collateral value of our proved reserves, and is subject to potential special and regular semi-annual redeterminations. Borrowings under our new credit facility bear interest ranging from a base rate plus a margin of 1.00% to 2.00% on base rate borrowings and LIBOR plus a margin of 2.00% to 3.00% on LIBOR borrowings. Our new credit facility was undrawn at closing and currently remains undrawn.

Sources and Uses of Capital. As of December 31, 2010, we had cash and cash equivalents of $33.6 million and no borrowings outstanding under the revolver or term loan components of our Amended Prior Credit Facility. As of that date, the undrawn commitment under our Amended Prior Credit Facility was $45.0 million. See”—Terminated Credit Facility” below for more details on our Amended Prior Credit Facility. At the closing of our 8.25% Notes offering on February 14, 2011, the Amended Prior Credit Facility was replaced with our new credit facility, which has an initial borrowing base of $150.0 million. There is no term loan component in our new credit facility.

We entered 2010 with a capital budget of approximately $57 million, of which approximately $45 million was allocated for exploration and development expenditures and $12 million for plugging, abandonment and other decommissioning expenditures. Our fiscal year 2011 capital budget is $110 to $125 million (excluding the cost of acquiring the ASOP properties), $80 million of which is allocated to development of our existing Gulf of Mexico shelf asset base primarily in the East Bay and South Timbalier field areas, $20 million of which is allocated to exploration projects and an additional $10 million to $25 million of which is allocated to development projects within the recently acquired ASOP Properties. We also plan to spend approximately $17 million in 2011 on plugging, abandonment and other decommissioning activities. Our key areas of operations and our plans for future exploration and development activities do not include any deepwater areas.

Terminated Credit Facility. We terminated the then existing Amended Prior Credit Facility in connection with entering into our new credit facility described above. On June 16, 2010, we entered into an amendment (the “First Amendment”) to our Prior Credit Facility with General Electric Capital Corporation, as administrative agent (the “Agent”), and the lender parties thereto (the “Lenders”). Upon its effectiveness on June 28, 2010, our Amended Prior Credit Facility established a $70.0 million borrowing base consisting of (a) a new $25.0 million term loan payable, with interest, in six equal monthly installments of principal from July 28, 2010 to December 28, 2010 and (b) a revolving credit facility with a three-year term that may be used for revolving credit

loans and letters of credit up to an initial maximum principal amount of $45.0 million. The interest rate spread on loans and letters of credit under our Amended Prior Credit Facility was based on the level of utilization and ranges from 3.75% to 4.25% for base rate borrowings and 4.75% to 5.25% for LIBOR borrowings. The First Amendment contained the Lenders’ consent for us to redeem all outstanding principal and pay all accrued interest on our PIK Notes, which redemption occurred on June 28, 2010 and was a condition to the effectiveness of the First Amendment.

The First Amendment did not make any material changes to the covenants, default provisions or collateral requirements under the Prior Credit Facility. Our obligations under our Amended Prior Credit Facility and under derivative contracts were guaranteed by our material subsidiaries and secured by our real property assets and the oil and natural gas properties to which 90% of the present value of our proved reserves is attributable. The borrowing base under the Amended Prior Credit Facility was $45.0 million at December 31, 2010. The maximum amount of letters of credit that could be outstanding at any one time was $20.0 million, and the amount available under the revolving credit facility was limited by the borrowing base. The borrowing base was subject to semi-annual redeterminations based on the proved reserves of the oil and natural gas properties that served as collateral for our Amended Prior Credit Facility. Monthly scheduled repayments of principal on the term loan, each in the amount of $4.2 million, reduced the borrowing base by the amount of such repayments. The term loan was repaid in full on December 28, 2010.

The documentation for our Amended Prior Credit Facility provided security for our obligations arising from derivative contracts with lenders under the Prior Credit Facility. On October 29, 2010, we entered into a novation agreement under which, effective October 1, 2010, we novated certain of our derivative contracts. The novation agreement effectively transferred all the rights, liabilities, duties and obligations of a certain derivative counterparty under those contracts to a new counterparty.

We have experienced, and may experience in the future, substantial working capital deficits. Our working capital deficits have historically resulted from increased accounts payable and accrued expenses related to ongoing exploration and development costs, which may be capitalized as noncurrent assets. At December 31, 2010, our working capital deficit was $12.7 million, compared to $16.9 million at December 31, 2009.

We maintain restricted escrow funds in a trust for future plugging, abandonment and other decommissioning costs at our East Bay field. The trust was originally funded with $15.0 million and, with accumulated interest, had increased to $16.7 million at December 31, 2008. We have made draws to date through December 2010 of $9.5 million, with $6.1 million drawn in 2010. We may draw from the trust upon the authorization, and subsequent completion, of qualifying abandonment activities at our East Bay field. As of the date of this Annual Report, we had $7.2 million remaining in restricted escrow funds for decommissioning work in our East Bay field, $1.2 million of which will be available for draw upon authorization, and subsequent completion, of additional qualifying decommissioning activities as that work progresses. The remaining $6.0 million will remain restricted until substantially all required decommissioning in the East Bay field is complete. Amounts on deposit in the trust account are reflected in Restricted cash on our condensed consolidated balance sheets.

Shortly following our emergence from Chapter 11 reorganization, we provided the BOEMRE with surety bonds in support of decommissioning obligations on certain federal leases in the Gulf of Mexico, and we resumed production from the federal portion of the East Bay field. During April 2010, we regained supplemental waiver status, and we are no longer required to post these surety bonds. Restricted cash totaling $8.9 million held as collateral for these surety bonds and other surety bonding obligations was released to us during the second quarter of 2010. We expect the cancellation of these surety bonds will reduce our surety bonding costs.

activities and/or accelerate the timing of cash expenditures and could have a material adverse effect on our financial position, results of operations and cash flows. For important additional information regarding risks related to our regulatory environment, see Part I, Item 1A, “Risk Factors.”

Analysis of Cash Flows for the Year Ended December 31, 2010

The following table sets forth our cash flows:


	Successor Company Year Ended December 31, 2010			Successor Company Period from October 1 through December 31, 2009			Predecessor Company Period from January 1 through September 30, 2009
	(in thousands)
Net cash provided by operating activities	$	127,380		$	16,868		$	14,366
Net cash used in investing activities	$	(45,903	)	$	(2,808	)	$	(29,751	)
Net cash provided by (used in) financing activities	$	(74,669	)	$	(31,250	)	$	57,329

The increase in our 2010 cash flows from operations primarily reflects the impact of the increase in oil and natural gas sales prices realized during the year ended December 31, 2010 as compared to the year ended December 31, 2009. Operating cash flows for the year ended December 31, 2010 also include cash payments totaling $15.8 million related to the redemption of our PIK Notes on June 28, 2010, which amount includes $9.7 million of interest for the period from September 21, 2009 through the redemption date and $6.1 million of original issue discount.

Net cash used in investing activities in the year ended December 31, 2010 reflects an increase in exploration and development expenditures as compared to the year ended December 31, 2009, offset by a decrease in restricted cash. Our investing cash flows for the year ended December 31, 2009 reflect, in part, that a higher level of capital expenditure activities occurred in the fourth quarter of 2008 compared to the fourth quarter of 2009, which resulted in cash payments for prior quarter work during the quarter ended March 31, 2009 that were higher than those in the quarter ended March 31, 2010.

Net cash used in financing activities during the year ended December 31, 2010 reflects the redemption of the PIK Notes and payments on the term loan component of our Prior Credit Facility and our Amended Prior Credit Facility, partially offset by proceeds from the term loan component of our Amended Prior Credit Facility. Net cash provided by financing activities during the year ended December 31, 2009 reflects increased utilization of the Predecessor Company’s credit facility to fund working capital shortfalls caused by the decline in production and the precipitous decline in oil and natural gas sales prices in 2009.

We have not paid any cash dividends in the past on our common stock. The covenants in certain debt instruments to which we are a party, including our new credit facility and the Indenture governing the 8.25% Notes, place certain restrictions and conditions on our ability to pay dividends. Any future cash dividends would depend on contractual limitations, future earnings, capital requirements, our financial condition and other factors determined by our board of directors. Our new senior credit facility will contain similar covenants that restrict the payment of dividends.

Analysis of Cash Flows for Year Ended December 31, 2009


	Successor Company Period from October 1 through December 31, 2009			Predecessor Company Period from January 1 through September 30, 2009			Predecessor Company Year Ended December 31, 2008
	(in thousands)
Net cash provided by operating activities	$	16,868		$	14,366		$	184,610
Net cash used in investing activities	$	(2,808	)	$	(29,751	)	$	(205,230	)
Net cash provided by (used in) financing activities	$	(31,250	)	$	57,329		$	13,747

The decrease in our 2009 cash flows from operations primarily reflects the impact of the precipitous decline in oil and natural gas sales prices realized during the year ended December 31, 2009 as compared to the year ended December 31, 2008.

Net cash used in investing activities declined in the year ended December 31, 2009 as compared to the year ended December 31, 2008 as a result of curtailed capital expenditures in response to declining oil and natural gas sales prices, contraction in the credit markets and reduced liquidity.

Net cash provided by financing activities increased during the year ended December 31, 2009 as compared to the year ended December 31, 2008, as a result of new borrowings arranged pursuant to the Plan of Reorganization.

Disclosures about Contractual Obligations and Commercial Commitments

The following table aggregates the contractual commitments and commercial obligations which affect our financial condition and liquidity position as of December 31, 2010.


	Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		Thereafter
	(in thousands)
Operating leases	$	3,534	$	622	$	1,262	$	1,133	$	517
Asset retirement obligations including accretion (1)		211,844		16,902		37,595		27,227		130,120

Total contractual obligations (2)	$	215,378	$	17,524	$	38,857	$	28,360	$	130,637

(1)	Includes discretionary amounts that we expect to spend on asset retirement activities of approximately $12.7 million, $15.7 million and $7.4 million in the less than one year period, one to three year period and three to five year period, respectively.

(2)

This table does not reflect any changes in our contractual commitments and commercial obligations occurring subsequent to December 31, 2010. Contractual commitments and commercial obligations assumed pursuant to the issuance of the 8.25% Notes and the closing of the ASOP Acquisition are not reflected in the table. The 8.25% Notes bear interest semi-annually and mature on February 15, 2018. Management has not yet had the opportunity to complete its assessment of the fair values of the liabilities assumed in the ASOP Acquisition. We currently estimate that the asset retirement obligations, including accretion, assumed in the ASOP Acquisition, total approximately $44 million, all of which is expected to be due beyond five years from December 31, 2010.

Off-Balance Sheet Transactions

We do not maintain any off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources other than those disclosed above.

Derivative Instruments

Note 2 “Summary of Significant Accounting Policies” and Note 12 “Derivative Transactions,” respectively, of our consolidated financial statements contained in Part II, Item 8 of this Annual Report describe our commodity price risks and the instruments we use to manage them.

We enter into derivative instruments to reduce our exposure to fluctuations in the market prices of oil and natural gas. Hedging transactions can expose us to risk of financial loss if, among other things, production is less than expected, the counterparty to the contract defaults on its obligations, or there is a change in the expected differential between the underlying price in the derivative instrument and actual price received. Derivative instruments may limit the benefit we would have otherwise received from increases in the sales prices of our oil and natural gas. Conversely, if we were not to engage in hedging transactions, we may be more adversely affected by declines in oil and natural gas prices than our competitors who do engage in hedging transactions.

Our revenues, profitability and future growth are highly dependent on prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our new credit facility is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell all of our oil and natural gas production under price sensitive or market price contracts.

Discussion of Critical Accounting Policies

In preparing our financial statements in accordance with accounting principles generally accepted in the United States, management must make estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Application of certain of our accounting policies requires a significant number of estimates. These accounting policies are described below.

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Reorganization and Fresh-Start Accounting—The financial statements for the period in which we were in reorganization under Chapter 11 were prepared in accordance with ASC Topic 852, “Reorganizations,” (originally issued as the American Institute of Certified Public Accountant’s Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”). Under ASC 852, we were required to, among other things, (1) identify transactions that were directly associated with the reorganization from those events that occurred during the normal course of business, (2) identify pre-petition liabilities subject to compromise from those that were not subject to compromise or were post petition liabilities and (3) apply “fresh-start” accounting rules upon emergence from Chapter 11 reorganization.

Based on financial projections that we and our advisors developed, the allocation of the reorganization value was determined using various valuation methods, including (i) comparable company analysis, which estimates the value of the Company based on the implied valuations of other similar companies; (ii) comparable asset transaction analysis, which estimates the value of a company based upon publicly announced transactions of

assets with similar characteristics; (iii) comparable merger transaction analysis, which, much like comparable asset transaction analysis, estimates the value of a company based upon publicly announced transactions with similar characteristics, except that merger analysis analyzes public to public merger transactions rather than solely asset transactions; and (iv) discounted cash flow analysis, which estimates the value of the Company by determining the present value of estimated future cash flows. The reorganization value is based on subjective estimates and assumptions, which are inherently subject to significant uncertainties and contingencies which are beyond our control. The fair value allocated to our property and equipment should not be viewed as representative of the current value of our oil and natural gas reserves or the current value of the Company. The reorganization value of the Company was estimated to be approximately $603 million.

In order to reflect the reorganization and application of ASC 852, we adjusted the book values of the Predecessor Company’s assets and liabilities to reflect the estimated fair values of the Successor Company’s assets and liabilities, on a net basis. These adjustments reduced our net loss by $57.1 million in the period from January 1, 2009 through September 30, 2009. The restructuring of the Company’s capital and resulting discharge of the Predecessor Company Notes and related accrued interest resulted in a loss of $2.7 million in the period from January 1, 2009 through September 30, 2009. The adjustments for the revaluation of the assets and liabilities and the loss on the discharge of pre-petition debt were recorded in “Fresh-start adjustments” and “Loss on discharge of debt,” respectively, in the consolidated statement of operations for the period from January 1, 2009 through September 30, 2009.

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Successful-Efforts Method of Accounting—Oil and natural gas exploration and production companies choose from two acceptable methods of accounting for oil and gas properties, the “successful efforts” method, which is the method we use, and the “full cost” method. The most significant difference between the two methods relates to the accounting treatment of drilling costs incurred on unsuccessful exploratory wells (dry holes) and exploration costs. Under the successful efforts method of accounting for oil and natural gas producing activities, costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. We may capitalize exploratory well costs beyond one year if (a) we found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project; otherwise, these costs are expensed. Geological and geophysical costs are charged to expense as incurred. We allocate the capitalized cost of producing oil and gas properties to earnings through DD&A on a field-by-field basis as production occurs. Entities that follow the full cost method capitalize drilling and exploratory costs, including dry hole costs, into one or more large pools of oil and natural gas property costs. Under the full cost method, the capitalized costs for each pool are allocated to earnings through DD&A based on the production of each pool. Additionally, under the successful efforts method, we measure impairments of our oil and natural gas properties based on the estimated fair value of oil and natural gas properties on a field-by-field basis based on the requirements of ASC Topic 360, “Property, Plant and Equipment” (“ASC 360”). In estimating fair value, we make assumptions about factors that have a high degree of uncertainty, including expected future sales prices for oil and natural gas, expected future costs of production, development and abandonment, and the appropriate rate at which we discount future cash flows. Under the full cost method, impairments are measured based on criteria determined by the SEC, which differs from the application of ASC 360.

We believe that companies with active exploratory drilling programs typically incur dry hole costs. To the extent that we incur significant amounts of exploratory drilling costs in the future, we expect to continue to incur dry hole costs in the future. We expect our dry hole costs will vary depending on our success rate in finding productive oil and natural gas reserves as well as the amount of our capital expenditures that are dedicated to exploration activities.

•

Proved Reserve Estimates—We use our oil and natural gas proved reserve estimates to calculate our DD&A. We allocate the capitalized cost of our producing oil and natural gas properties to earnings

through DD&A based on Boe units produced during the period as a percentage of total estimated Boe reserves. We also use reserve estimates, which may include (on a risk adjusted basis) reserves that are not proved reserves, to assess our productive oil and natural gas properties for impairment. Proved reserves are the estimated quantities of crude oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, estimated prices and costs as of the date the reserve estimates are made are held constant for the life of the reserves.

Independent reserve engineers prepare our oil and natural gas reserve estimates using guidelines established by the SEC and U.S. generally accepted accounting principles (“GAAP”). In December 2008, the SEC issued a final rule, “Modernization of Oil and Gas Reporting,” which amended its oil and gas reserves estimation and disclosure requirements. The new requirements were codified into ASC 932 in January 2010 and had the effect of, among other things: permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; modifying the prices used to estimate reserves for SEC disclosure purposes to an unweighted, arithmetic average price based upon the prior twelve month period rather than the year-end price; and allowing the optional disclosure of “probable” and “possible” reserves to investors. The revised rule was effective January 1, 2010 for reporting December 31, 2009 annual oil and natural gas reserve information. We adopted the provisions of the final rule in connection with the preparation of our 2009 Annual Report. The quality and quantity of data, the interpretation of data, the accuracy of economic assumptions, and judgments and estimates regarding uncertain events and circumstances by us and our independent reserve engineers affect the accuracy of reserve estimates. We may materially revise our reserve estimates in subsequent periods due to drilling or production results or other data obtained after the date of the estimate.

As of December 31, 2010, we had estimated proved reserves of 27.4 Mmboe, of which 46% were proved developed producing reserves while 47% of our proved reserves were classified as proved developed non-producing reserves. Most of our proved developed non-producing reserves are classified as “behind pipe” and will be produced after depletion of another productive zone in the same well. Approximately 7% of total proved reserves are categorized as proved undeveloped reserves.

The present value of the future net cash flow disclosed in this Annual Report is not intended to reflect the market value of the oil and natural gas reserves. In accordance with ASC 932, we use prices based on the unweighted, arithmetic average of the closing price on the first day of each of the twelve months during the fiscal year, and costs determined on the date of the estimate held constant for the life of the reserves and a 10% discount rate to determine the present value of future net cash flow. Actual costs incurred and prices received in the future may vary significantly and the discount rate may not accurately reflect economic conditions.

As of December 31, 2010, the computation of the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves used an oil price based on the NYMEX WTI of $77.85 per barrel and a natural gas priced based on the NYMEX Henry Hub of $4.54 per Mcf, computed by applying the use of physical pricing based on the unweighted, arithmetic average of the closing price on the first day of each of the twelve months during the fiscal year (as required by ASC 932), applying historical adjustments, including transportation, quality differentials, and purchaser bonuses, on an individual property basis, to the year end quantities of estimated proved reserves. The historical adjustments applied to the computed prices are determined by comparing our historical realized price experience with the comparable historical market, or posted, price. These adjustments can vary significantly over time both in amount and as a percentage of the posted price, especially related to our oil prices during periods when the market price for oil varies widely. The price adjustments reflected in our computed reserve prices may not represent the amount of price adjustments we may actually obtain in the future when we sell our production. We estimated the costs based primarily on our actual historical costs incurred for appropriate periods of time for individual properties. Where a particular property does not have production during the year, we apply pricing adjustments based on the most similar property.

•

Depletion, Depreciation and Amortization of Oil and Natural Gas Properties—We calculate DD&A using the estimates of proved oil and natural gas reserves previously discussed in these critical

accounting policies. We segregate the capitalized costs and record DD&A for capitalized property costs separately using the units-of-production method. The units-of- production method is based on the ratio of (1) actual volumes produced to (2) total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods), or total proved reserves in the case of leasehold costs (the DD&A rate). Each period, this ratio is applied to the applicable capitalized asset cost category, resulting in allocation of the cost of our oil and natural gas properties over the periods during which they produce revenues. As previously discussed, material revisions to proved reserves may occur as a result of unforeseen factors and may materially impact the DD&A rate.

In 2010, we had negative revisions of 4.3 Mmboe related to PUDs aged greater than five years for which funds were not committed in our 2011 development plan, representing 14% of our total proved reserves of 31.2 Mmboe as of December 31, 2009. In 2009, we had negative revisions of 0.6 Mmboe, representing 2% of our total proved reserves of 36.8 Mmboe as of December 31, 2008. In 2008, we had negative revisions of 5.5 Mmboe, representing 12% or our total proved reserves of 45.3 Mmboe as of December 31, 2007. The negative revisions in 2008 resulted from a combination of price decreases in both oil and natural gas (3.5 Mmboe) and performance (2.0 Mmboe). Our past revisions have had minimal impact on our DD&A rates because they have been relatively low as a percentage of our reserve base and/or related to fields with little cumulative production. Historical revisions are not necessarily indicative of potential future revisions.

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Impairment of Oil and Natural Gas Properties—We evaluate our capitalized oil and natural gas property costs for potential impairment when circumstances indicate that the carrying value may not be recoverable. Because we accumulate capitalized costs separately, property by property (generally analogous to a field or a lease), for our proved oil and natural gas properties under the successful efforts method of accounting, we perform impairment assessments on a property by property basis. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or natural gas, unfavorable adjustments to reserve volumes, or other changes to contracts or environmental regulations. In general, we do not view temporarily low oil or natural gas prices as a triggering event for conducting impairment tests. Historically, our sales price for oil and natural gas has varied significantly. Although our sales prices may rise and fall quickly over short periods of time, we believe sales prices over the long-term are primarily based on supply and demand factors. Accordingly, our impairment tests make use of long-term sales price assumptions for oil and natural gas. A significant amount of judgment and uncertainty is involved in performing impairment evaluations because major inputs to the computation are based on our estimates of future events, including projections of future oil and natural gas sales prices, amounts of recoverable oil and natural gas reserves, timing of future production, future costs to develop and produce our oil and natural gas and discount factors.

Our assessment of possible impairment of proved oil and natural gas properties is based on our best estimate of future prices, costs and expected net future cash flows by property. An impairment loss is indicated if undiscounted net future cash flows are less than the carrying value of a property. The impairment expense is measured as the shortfall between the net book value of the property and its estimated fair value measured based on the discounted net future cash flows from the property. Actual prices, costs, and net future cash flows may vary from our estimates. Our discount rate may not accurately reflect economic conditions. We recognized impairment expense of $26.1 million, $8.5 million, $8.1 and $110.4 million in the year ended December 31, 2010, in the period from October 1, 2009 through December 31, 2009, in the period from January 1, 2009 through September 30, 2009 and the year ended December 31, 2008, respectively.

For individual unevaluated properties (those with no corresponding proved reserves) with capitalized cost below a threshold amount, we allocate capitalized costs to earnings generally over the primary lease terms. We believe this method provides a reasonable estimate of the amount of capitalized costs of unevaluated properties which will prove unproductive over the primary lease terms. Properties that are subject to amortization and those

with capitalized costs greater than the threshold amount are assessed for impairment periodically. If we find oil and natural gas reserves sufficient to justify development of the property, we transfer the net capitalized cost of the unproved property to proved properties and DD&A is recorded on the units-of-production basis described above. If our efforts do not result in proved oil and natural gas reserves, the related net capitalized costs are charged to earnings as impairment expense.

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Asset Retirement Obligations (“AROs”)—We have material obligations to plug and abandon oil and natural gas wells and to decommission related platforms, pipelines and equipment as well as to dismantle and abandon facilities when they are no longer being used for the production of oil and natural gas. We record a liability for the estimated fair value of a material ARO in the period when we identify or incur the obligation. When the liability is initially recorded, we capitalize the cost by increasing the carrying amount of the related asset, which is allocated to expense through DD&A on the units-of-production basis. Accretion increases the ARO liability over time, using the effective interest method.

Numerous estimates, assumptions and judgments are inherent in the calculation of ARO including ultimate settlement amounts, timing of settlements, technological changes, future inflation rates, the credit adjusted risk-free rate of interest, and changes in legal, regulatory, environmental and political environments. We revise our estimates of the fair value of ARO as information about material changes to the liability become known. Revisions are recorded as an adjustment to existing ARO liabilities and to the carrying amount of the related assets. Revisions occurring at or near the end of an asset’s useful life may result in a material positive or negative impact on earnings.

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Derivative Instruments and Hedging Activities—We enter into hedging transactions for our oil and natural gas production to reduce our exposure to fluctuations in the price of oil and natural gas. Historically, our hedging instruments consisted primarily of financially-settled puts, swaps and collars. We record our hedging instruments at fair market value as either assets or liabilities in our consolidated balance sheet. We estimate the fair value of hedging instruments based on estimated future commodity prices. The fair market value may differ from actual settlements if market prices change, the other party to the contract defaults on its obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

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Share-Based Compensation—We measure compensation expense for all share-based payment awards based on their grant-date fair values. We use the Black-Scholes option pricing model to estimate fair values of share-based awards. Option pricing models, including the Black-Scholes model, require the use of input estimates and assumptions, including expected volatility, expected life, expected dividend rate, and expected risk-free rate of return. The assumptions for expected volatility and expected life most significantly affect the grant-date fair value. Our estimate of the forfeiture rate of our stock-based awards also impacts the amount of expense recorded over the expected life of the award. See Note 15, “Employee Benefit Plans,” in Part II, Item 8 of this Annual Report for a description of methods used to determine our assumptions. If we determined that another method used to estimate expected volatility or expected life was more reasonable than our current methods, or if another method for calculating these input assumptions was prescribed by authoritative guidance, the fair value calculated for share-based awards could change significantly. Higher volatility and longer expected lives result in increases to share-based compensation determined at the date of grant.

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Deferred Tax Asset Valuation Allowance—We are required to assess whether it is more likely than not that we will be able to realize some or all of our deferred tax assets. If we cannot determine that deferred tax assets are more likely than not recoverable, we are required to provide a valuation allowance against those assets. This assessment takes into account factors including: (a) the nature, frequency, and severity of current and cumulative financial reporting losses; (b) sources of estimated future taxable income; and (c) tax planning strategies. A pattern of recent financial reporting losses is heavily weighted as a source of negative evidence when determining the realizability of deferred tax assets. Projections of estimated future taxable income exclusive of reversing temporary differences are

a source of positive evidence only when the projections are combined with a history of recent profitable operations and can be reasonably estimated. Otherwise, projections are considered inherently subjective and generally will not be sufficient to overcome negative evidence that includes cumulative losses in recent years. If necessary and available, tax planning strategies would be implemented to accelerate taxable amounts to utilize expiring carryforwards. These strategies would be a source of additional positive evidence supporting the realizability of deferred tax assets.

See Note 14 “Income Taxes” in Part II, Item 8 of this Annual Report for more information regarding our deferred taxes.

Changes in estimates and assumptions described in these critical accounting policies may result in material changes to our net income or loss from period to period.

New Accounting Pronouncements

For information regarding new accounting pronouncements, see the information in Note 18 “New Accounting Pronouncements” in the consolidated financial statements in Part II, Item 8 of this Annual Report.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view our ongoing market-risk exposure.

Interest Rate Risk

We are exposed to changes in interest rates which affect the interest earned on our interest-bearing deposits and the interest paid on borrowings under our new credit facility. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. On December 28, 2010, we repaid in full all outstanding borrowings under the term loan component of our Amended Prior Credit Facility and had no borrowings outstanding on the revolver component. On February 14, 2011, our Amended Prior Credit Facility was replaced with our new credit facility, which bears interest at a floating rate, and we issued our fixed-rate 8.25% Notes. See “Financial Condition, Liquidity and Capital Resources” for information on our new credit facility and 8.25% Notes.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our new credit facility is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may reduce the amount of oil and natural gas that we can economically produce. We currently sell all of our oil and natural gas production under price sensitive or market price contracts.

Historically, we have used commodity derivative instruments to manage commodity price risks associated with future oil and natural gas production. As of December 31, 2010, the following derivative instruments were outstanding:

Oil Contracts


	Fixed-Price Swaps									Puts
Remaining Contract Term	Daily Average Volume (Bbls)		Volume (Bbls)		Average Swap Price ($/Bbl)		Fair Value (In thousands)			Daily Average Volume (Bbls)		Volume (Bbls)		Floor Price ($/ Bbl)		Fair Value (In thousands)
January 2011—July 2011		2,261		479,250	$	71.13	$	(10,409	)		502		106,500	$	60.00	$	16
August 2011—November 2011		502		61,200	$	72.18	$	(1,306	)		1,301		158,700	$	60.00	$	128
December 2011		948		29,400	$	72.64	$	(605	)		1,302		40,350	$	60.00	$	42

During January 2011, we entered into the following derivative instruments:

Oil Contracts


	Fixed-Price Swaps
Remaining Contract Term	Daily Average Volume (Bbls)		Volume (Bbls)		Average Swap Price ($/Bbl)
February 2011—July 2011		436		79,000	$	95.19
August 2011—November 2011		82		10,000	$	94.88
December 2011		161		5,000	$	94.70
January 2012—July 2012		2,028		432,000	$	95.22
August 2012—November 2012		459		56,000	$	94.87
December 2012		903		28,000	$	94.70
January 2013—July 2013		1,698		360,000	$	94.27
August 2013—November 2013		393		48,000	$	93.88
December 2013		774		24,000	$	93.83

Item 8.

Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Energy Partners, Ltd.:

In our opinion, the accompanying consolidated balance sheet as of December 31, 2010 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the year then ended present fairly, in all material respects, the financial position of Energy Partners, Ltd. and its subsidiaries at December 31, 2010, and the results of their operations and their cash flows for the year ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

New Orleans, Louisiana

March 3, 2011

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Energy Partners, Ltd.:

We have audited the accompanying consolidated balance sheet of Energy Partners, Ltd. and subsidiaries as of December 31, 2009, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the period from October 1, 2009 through December 31, 2009 (Successor Company), for the period from January 1, 2009 through September 30, 2009 (Predecessor Company), and the year ended December 31, 2008 (Predecessor Company). These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Partners, Ltd. and subsidiaries as of December 31, 2009, and the results of their operations and their cash flows for the period from October 1, 2009 through December 31, 2009 (Successor Company), for the period from January 1, 2009 through September 30, 2009 (Predecessor Company), and for the year ended December 31, 2008 (Predecessor Company), in conformity with U.S. generally accepted accounting principles.

As discussed in note 1 and note 4 to the consolidated financial statements, the Company filed a petition for reorganization under Chapter 11 of the United States Bankruptcy Code on May 1, 2009. The Company’s plan of reorganization became effective, and the Company emerged from bankruptcy protection on September 21, 2009. In connection with its emergence from bankruptcy, the Successor Company Energy Partners, Ltd. and subsidiaries adopted fresh-start reporting in conformity with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 852 (ASC 852), Reorganizations. Accordingly, the Successor Company’s consolidated financial statements prior to September 30, 2009 are not comparable to its consolidated financial statements for periods on or after September 30, 2009.

/s/ KPMG LLP

New Orleans, Louisiana

March 10, 2010, except for the supplemental condensed consolidating balance sheet as of December 31, 2009, and related supplemental condensed consolidating statement of operations and cash flows for the period from October 1, 2009 through December 31, 2009 (Successor Company), and for the period from January 1, 2009 through September 30, 2009 (Predecessor Company) as presented in note 19, which is as of March 2, 2011

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2010 and 2009

(In thousands, except share data)


	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	33,553		$	26,745
Trade accounts receivable—net		21,443			27,958
Receivables from insurance		2,088			5,464
Fair value of commodity derivative instruments		186			914
Deferred tax assets		2,693			5,768
Prepaid expenses		3,303			2,940

Total current assets		63,266			69,789
Property and equipment, under the successful efforts method of accounting for oil and natural gas properties		719,147			648,517
Less accumulated depreciation, depletion and amortization		(168,055	)		(37,535	)

Net property and equipment		551,092			610,982
Restricted cash		8,489			22,147
Other assets		1,814			3,647
Deferred financing costs—net of accumulated amortization of $1,656 and $325 at December 31, 2010 and 2009, respectively		2,245			2,663

	$	626,906		$	709,228

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	18,358		$	14,047
Accrued expenses		28,394			32,822
Asset retirement obligations		16,902			10,830
Current portion of long-term debt		—			18,750
Fair value of commodity derivative instruments		12,320			10,256

Total current liabilities		75,974			86,705
Long-term debt		—			58,590
Asset retirement obligations		54,681			59,150
Deferred tax liabilities		22,469			16,953
Fair value of commodity derivative instruments		—			7,519
Other		666			224

		153,790			229,141
Commitments and contingencies (Note 16)
Stockholders’ equity:
Preferred stock, par value $0.001 per share; authorized 1,000,000 shares; no shares issued and outstanding at December 31, 2010 and 2009		—			—
Common stock, par value $0.001 per share; authorized 75,000,000 shares; issued and outstanding: 40,091,664 and 40,021,770 shares at December 31, 2010 and 2009, respectively		40			40
Additional paid-in capital		502,556			501,059
Accumulated deficit		(29,480	)		(21,012	)

Total stockholders’ equity		473,116			480,087

	$	626,906		$	709,228

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

For the Year Ended December 31, 2010, the Period from October 1, 2009 through December 31, 2009,

the Period from January 1, 2009 through September 30, 2009 and the Year Ended December 31, 2008

(In thousands, except per share data)


	SUCCESSOR COMPANY						PREDECESSOR COMPANY
	Year Ended December 31, 2010			Period from October 1, 2009 through December 31, 2009			Period from January 1, 2009 through September 30, 2009			Year Ended December 31, 2008
Revenue:
Oil and natural gas	$	239,770		$	56,708		$	134,583		$	356,022
Other		139			42			302			230

		239,909			56,750			134,885			356,252
Costs and expenses:
Lease operating		52,365			13,410			46,296			71,931
Transportation		1,306			315			699			1,089
Exploration expenditures and dry hole costs		6,441			453			1,650			30,199
Impairments		26,142			8,514			8,082			110,403
Depreciation, depletion and amortization		104,561			28,448			95,944			103,318
Accretion of liability for asset retirement obligations		12,845			3,024			5,536			4,370
General and administrative		18,078			4,537			19,493			37,308
Taxes, other than on earnings		10,133			2,083			5,987			11,245
Gain on sale of assets		—			—			—			(5,527	)
Loss (gain) on abandonment activities		(90	)		493			3,732			21,695
Other		819			(4	)		(26	)		—

Total costs and expenses		232,600			61,273			187,393			386,031
Business interruption recovery		—			—			1,185			4,248

Income (loss) from operations		7,309			(4,523	)		(51,323	)		(25,531	)
Other income (expense):
Interest income		113			3			47			784
Interest expense (contractual interest of $34,076 for the period from January 1, 2009 through September 30, 2009)		(9,807	)		(4,322	)		(17,813	)		(46,533	)
Gain (loss) on derivative instruments		(4,865	)		(22,705	)		2,728			2,053
Loss on early extinguishment of debt		(5,627	)		—			—			—

		(20,186	)		(27,024	)		(15,038	)		(43,696	)
Loss before reorganization items, loss on discharge of debt, fresh-start adjustments and income taxes		(12,877	)		(31,547	)		(66,361	)		(69,227	)
Reorganization items (Note 5)		—			(865	)		(24,198	)		—
Loss on discharge of debt (Note 4)		—			—			(2,666	)		—
Fresh-start adjustments (Note 4)		—			—			57,111			—

Loss before income taxes		(12,877	)		(32,412	)		(36,114	)		(69,227	)
Income tax benefit		4,409			11,400			—			17,015

Net loss		(8,468	)		(21,012	)		(36,114	)		(52,212	)

Basic and diluted loss per share	$	(0.21	)	$	(0.53	)	$	(1.12	)	$	(1.63	)
Weighted average common shares used in computing earnings per share:
Basic and diluted		40,064			40,020			32,200			31,988

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

For the Year Ended December 31, 2010, the Period from October 1, 2009 through December 31, 2009,

the Period from January 1, 2009 through September 30, 2009 and the Year Ended December 31, 2008

(In thousands)


	Treasury Stock Shares			Treasury Stock			Predecessor Company Common Stock Shares			Predecessor Company Common Stock			Successor Company Common Stock Shares		Successor Company Common Stock		Additional Paid In Capital			Retained Earnings (Deficit)			Total
Balance, December 31, 2007—Predecessor Company		12,240		$	(258,356	)		43,981		$	441			—		—	$	374,874		$	(14,989	)	$	101,970

Stock purchase, compensation and incentive plans, net		—			—			116			1			—		—		4,789			—			4,790
Exercise of common stock options		—			—			79			1			—		—		749			—			750
Comprehensive loss:
Net loss		—			—			—			—			—		—		—			(52,212	)		(52,212	)

Comprehensive loss																								(52,212	)

Other		—			—			147			1					—		1,820			—			1,821

Balance, December 31, 2008—Predecessor Company		12,240		$	(258,356	)		44,323		$	444			—		—	$	382,232		$	(67,201	)	$	57,119

Stock purchase, compensation and incentive plans, net		—			—			297			2			—		—		3,420			—			3,422
Comprehensive loss:
Net loss		—			—			—			—			—		—		—			(36,114	)		(36,114	)

Comprehensive loss																								(36,114	)

Other		—			—			54			1					—		616			—			617
Reorganization Adjustments		(12,240	)		258,356			(44,674	)		(447	)		40,000		40		114,566			103,315			475,830
Stock issued to Directors pursuant to 2009 LTIP		—			—			—			—			18		—		—			—

Balance, September 30, 2009—Successor Company		—		$	—			—		$	—			40,018	$	40	$	500,834		$	—		$	500,874

Stock compensation and incentive plan awards pursuant to 2009 LTIP		—			—			—			—			—		—		243			—			243
Comprehensive loss:
Net loss		—			—			—			—			—		—		—			(21,012	)		(21,012	)

Comprehensive loss																								(21,012	)

Other		—			—			—			—			4		—		(18	)		—			(18	)

Balance, December 31, 2009—Successor Company		—		$	—			—		$	—			40,022	$	40	$	501,059		$	(21,012	)	$	480,087

Stock compensation and incentive plan awards pursuant to 2009 LTIP		—			—			—			—			69		—		1,429			—			1,429
Comprehensive loss:
Net loss		—			—			—			—			—		—		—			(8,468	)		(8,468	)

Comprehensive loss																								(8,468	)

Other		—			—			—			—			1		—		68			—			68

Balance, December 31, 2010—Successor Company		—		$	—			—		$	—			40,092	$	40	$	502,556		$	(29,480	)	$	473,116

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Year Ended December 31, 2010, the Period from October 1, 2009 through December 31, 2009,

the Period from January 1, 2009 through September 30, 2009 and the Year Ended December 31, 2008

(In thousands)


	SUCCESSOR COMPANY						PREDECESSOR COMPANY
	Year Ended December 31, 2010			Period from October 1, 2009 through December 31, 2009			Period from January 1, 2009 through September 30, 2009			Year Ended December 31, 2008
Cash flows from operating activities:
Net loss	$	(8,468	)	$	(21,012	)	$	(36,114	)	$	(52,212	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		104,561			28,448			95,944			103,318
Accretion of liability for asset retirement obligations		12,845			3,024			5,536			4,370
Loss on discharge of debt		—			—			2,666			—
Fresh-start adjustments		—			—			(57,111	)		—
Unrealized (gain) loss on derivative contracts		(3,500	)		21,739			—			(19,508	)
Non cash compensation		1,255			417			3,689			6,108
In-kind interest on PIK Notes		(3,395	)		3,395			—			—
Deferred income taxes		(4,409	)		(11,400	)		—			(17,015	)
Gain on disposal of assets and other		—			—			—			(5,827	)
Exploration expenditures		5,103			163			126			21,796
Impairments		26,142			8,514			8,082			110,403
Amortization of deferred financing costs and discount on debt		1,130			524			8,356			1,834
Loss on abandonment activities		(90	)		493			3,732			21,695
Other		—			—			3			879
Changes in operating assets and liabilities:
Trade accounts receivable		6,515			(3,501	)		4,807			21,655
Other receivables		3,376			(1,428	)		194			(4,249	)
Prepaid expenses		(363	)		1,505			677			2,276
Other assets		618			(1,570	)		(641	)		(5,819	)
Accounts payable and accrued expenses		2,361			(10,806	)		(2,414	)		22,045
Asset retirement obligations		(16,130	)		(1,637	)		(22,374	)		(26,915	)
Other liabilities		(171	)		—			(792	)		(674	)

Net cash provided by operating activities		127,380			16,868			14,366			184,610

Cash flows used in investing activities:
Decrease in restricted cash		13,658			—			—			—
Property acquisitions		(623	)		(54	)		(31	)		(20,925	)
Exploration and development expenditures		(58,183	)		(2,731	)		(29,723	)		(199,157	)
Other property and equipment additions		(755	)		(23	)		(147	)		(724	)
Proceeds from sale of oil and gas assets		—			—			150			15,576

Net cash used in investing activities		(45,903	)		(2,808	)		(29,751	)		(205,230	)

Cash flows provided by (used in) financing activities:
Deferred financing costs		(181	)		—			(798	)		(5	)
Repayments of indebtedness, excluding repayment of PIK Notes issued to pay interest of $3,395		(94,882	)		(31,250	)		(55,001	)		(120,000	)
Proceeds from indebtedness		20,394			—			113,128			133,000
Exercise of stock options and warrants		—			—			—			752

Net cash provided by (used in) financing		(74,669	)		(31,250	)		57,329			13,747

Net increase (decrease) in cash and cash equivalents		6,808			(17,190	)		41,944			(6,873	)
Cash and cash equivalents at beginning of period		26,745			43,935			1,991			8,864

Cash and cash equivalents at end of year	$	33,553		$	26,745		$	43,935		$	1,991

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Non-cash financing information:
Discharge of Senior Unsecured Notes, including accrued interest of $18,663	$	—		$	—		$	473,164		$	—
Issuance of equity in Successor Company		—			—			500,874			—
Debt incurred to repay secured bank credit facility, including accrued interest of $1,085		—			—			29,084			—
Debt incurred to pay deferred financing costs and surety bond premium		737			—			2,790			—
Debt incurred to pay interest on PIK Notes		—			3,395			—			—
Cash paid during the period for:
Interest		8,307			552			5,614			46,875
Income taxes		—			—			—			—

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Organization

Energy Partners, Ltd. (“we,” “our,” “us,” or “the Company”) was incorporated as a Delaware corporation on January 29, 1998. We are an independent oil and natural gas exploration and production company. Our current operations are concentrated in the U.S. Gulf of Mexico shelf focusing on state and federal waters offshore Louisiana.

Recent Events – Acquisition, Notes Offering and New Credit Facility. On February 14, 2011, we acquired an asset package consisting of certain shallow-water Gulf of Mexico shelf oil and natural gas interests surrounding the Mississippi River delta and a related gathering system (the “ASOP Properties”) from Anglo-Suisse Offshore Partners, LLC (“ASOP”) for $200.7 million in cash, subject to customary adjustments to reflect an economic effective date of January 1, 2011 (the “ASOP Acquisition”). In connection with the ASOP Acquisition, on February 14, 2011, we issued $210.0 million in aggregate principal amount of 8.25% senior notes due 2018 (the “8.25% Notes’). Also on February 14, 2011, we entered into a new credit facility which establishes a revolving credit facility with a four-year term that may be used for revolving credit loans and letters of credit up to an aggregate principal amount of $250.0 million, subject to an initial borrowing base of $150.0 million. See Note 3, “Acquisitions” and Note 9, “Indebtedness” for more information regarding these subsequent events.

2009 Reorganization. On May 1, 2009 (the “Petition Date”), we and certain of our subsidiaries filed voluntary petitions (In re: Energy Partners, Ltd., et. al., Case No. 09-32957) for reorganization under Chapter 11 of Title 11 of the United States Code, 11 U.S.C. §§ 101 et seq., as amended (“Chapter 11”), in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). We continued to manage our properties and operate our business as “debtors-in-possession” while under the jurisdiction of the Bankruptcy Court. On September 21, 2009, we emerged from Chapter 11 reorganization (the “Exit Date”) pursuant to the plan of reorganization confirmed by the Bankruptcy Court (the “Plan of Reorganization”). The Chapter 11 filings and related matters are addressed in Note 4, “Reorganization and Fresh-Start Accounting.”

(2) Summary of Significant Accounting Policies

(a) Basis of Presentation

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of Energy Partners, Ltd. and our wholly-owned subsidiaries. All significant intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

The financial statements for the period in which the Company was in reorganization under Chapter 11 were prepared in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852 (“ASC 852”), “Reorganizations,” (originally issued as the American Institute of Certified Public Accountant’s Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”). Under ASC 852, we must, among other things, (1) identify transactions that are directly associated with the reorganization from those events that occur during the normal course of business, (2) identify pre-petition liabilities subject to compromise from those that are not subject to compromise or are post petition liabilities and (3) apply fresh-start accounting rules upon emergence from Chapter 11 reorganization (see Note 4). In accordance with the Plan of Reorganization, only the Company’s 9.75% Senior Unsecured Notes due 2014 (the “Fixed Rate Notes”), its Senior Floating Rate Notes due 2013 (the “Floating Rate Notes” and together with the Fixed Rate Notes, the “Senior Unsecured Notes”) and its 8.75% Senior Notes due 2010 (collectively with the Senior Unsecured Notes, the “Predecessor Company Notes”) and the related accrued interest were discharged in the reorganization. As a result, we discontinued accruing interest on the Predecessor Company Notes as of the Petition Date.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In accordance with ASC 852, we adopted fresh-start accounting as of September 30, 2009. Fresh-start accounting is required upon a substantive change in control and requires that the reporting entity allocate the reorganization value of the Company to its assets and liabilities in relation to their fair values. Under the provisions of fresh-start accounting, a new entity has been deemed created for financial reporting purposes. References to the “Predecessor Company” refer to reporting dates of the Company through September 30, 2009, including the effect of the reorganization and application of fresh-start accounting; subsequent thereto, the Company is referred to as the “Successor Company” in the consolidated financial statements and the notes thereto. The financial statements for the year ended December 31, 2008 do not reflect the effect of any changes in the Company’s capital structure or changes in fair values of assets and liabilities as a result of fresh-start accounting. For further information on fresh-start accounting, see Note 4.

(b) Property and Equipment

We use the successful efforts method of accounting for oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. We may capitalize exploratory well costs beyond one year if (a) we found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project; otherwise, these costs are expensed. Geological and geophysical costs are charged to expense as incurred.

Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold costs are transferred to proved properties. For individual unevaluated properties with capitalized cost below a threshold amount, we allocate capitalized costs to earnings generally over the primary lease terms. Properties that are subject to amortization and those with capitalized costs greater than the threshold amount are assessed for impairment periodically. Capitalized costs of producing oil and natural gas properties are depreciated and depleted by the units-of-production method.

We evaluate our capitalized costs of proved oil and natural gas properties for potential impairment when circumstances indicate that the carrying values may not be recoverable. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or natural gas, unfavorable adjustments to reserve volumes, or other changes to contracts, environmental regulations or tax laws. The calculation is performed on a field-by-field basis, utilizing our current estimates of future revenues and operating expenses. In the event net undiscounted cash flow is less than the carrying value, an impairment loss is recorded based on the present value of expected future net cash flows over the economic lives of the reserves.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion, depreciation and amortization are eliminated from the property accounts, along with the related asset retirement obligations, unless retained by us, and the resulting gain or loss is recognized in earnings.

(c) Asset Retirement Obligations

We record our obligations associated with the retirement of tangible long-lived assets at their fair values in the period incurred. The fair value of the obligation is also recorded to the related asset’s carrying amount. Accretion of the liability is recognized as an operating expense and the capitalized cost is amortized using the units-of-production method. Our asset retirement obligations relate primarily to the plugging and abandonment of our oil and natural gas wellbores and to decommissioning related pipelines, facilities and structures.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(d) Income Taxes

We account for income taxes under the asset and liability method, which requires that we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis amounts. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. We recognize the effect on deferred tax assets and liabilities of a change in the tax rates in income in the period that includes the enactment date.

We follow the provisions of ASC Topic 740, “Income Taxes,” which apply to the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. These provisions also contain guidance on de-recognition, classification, interest and penalties. Interest, if any, is classified as a component of interest expense, and statutory penalties, if any, are classified as a component of general and administrative expense.

(e) Deferred Financing Costs

We defer costs incurred to obtain debt financing and then amortize such costs as additional interest expense over the maturity period of the related debt.

(f) Earnings Per Share

Basic earnings per share is computed by dividing income or loss available to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings per share includes the effect, if dilutive, of potential common shares associated with stock option and restricted share awards outstanding during each period.

(g) Revenue Recognition

We record revenues from the sales of oil and natural gas when the product is delivered at a determinable price, title has transferred and collectability is reasonably assured. When we have an interest with other producers in properties from which natural gas is produced, we use the entitlement method for recording natural gas sales revenue. Under this method of accounting, revenue is recorded based on our net revenue interest in production. Deliveries of natural gas in excess of our revenue interest are recorded as liabilities and under-deliveries are recorded as receivables. We had natural gas imbalance liabilities of $1.6 million and $2.5 million at December 31, 2010 and 2009, respectively.

(h) Cash and Cash Equivalents

We include in cash and cash equivalents our highly-liquid investments with original maturities of three months or less. At December 31, 2010 and 2009, cash and cash equivalents includes investments in overnight interest-bearing deposits of $35.8 million and $27.2 million, respectively. These amounts are reduced by overdraft balances on other operating accounts with legal right of offset in the same banking institution to arrive at the cash and cash equivalent balances reported in our consolidated balance sheets.

(i) Derivative Activities

Derivative instruments, including certain derivative instruments embedded in other contracts, are recorded at fair market value and included as either assets or liabilities in the balance sheet. The accounting for changes in fair value depends on the intended use of the derivative and the resulting designation, which is established at the

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

inception of the derivative. We do not elect to designate derivative instruments as hedges. Unrealized gains and losses resulting from changes in the fair value of derivative instruments are recorded in other income (expense). Realized gains and losses related to contract settlements are also recorded in other income (expense).

(j) Stock-Based Compensation

We recognize stock-based compensation expense based on the estimated grant-date fair value of all stock-based awards, net of an estimated forfeiture rate, over the requisite service period of the awards, which is generally equivalent to the vesting term. We record stock-based compensation expense only for those awards expected to vest. We periodically revise our estimated forfeiture rate if actual forfeitures differ from our estimates.

We are required to report excess tax benefits from the exercise of stock options as financing cash flows. No stock options were exercised during 2010 and 2009. For the year ended December 31, 2008, no excess tax benefits were reported in the statement of cash flows as we were in a net operating loss carryforward position. See Note 15 for additional disclosures.

(k) Allowance for Doubtful Accounts

We routinely assess the recoverability of all material trade and other receivables to determine their collectability. Our crude oil and natural gas revenue receivables are typically collected within two months. We may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest receivables on properties where we are the operator. When we believe collection of the full amount of our accounts receivable is in doubt, we record an allowance to reflect accounts receivable at the net realizable value, which may be reflected in earnings or as an increase to the net book value of our oil and natural gas properties depending on the nature of the transaction that created the receivable. The nature of the transaction resulting in the receivable balance determines whether the allowance, when recorded, impacts our earnings (ordinarily through LOE) or our property and equipment balances. As of December 31, 2010 our allowance for doubtful accounts was $2.3 million, $0.3 million of which was recorded as a reduction in earnings in 2010. As of December 31, 2009, our allowance for doubtful accounts was $2.0 million, of which $0.1 million and $0.8 million was recorded as a reduction in earnings in the periods from October 1, 2009 through December 31, 2009 and January 1, 2009 through September 31, 2009, respectively.

(l) Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We use historical experience and various other assumptions that are believed to be reasonable under the circumstances to form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Our actual results may differ from these estimates and assumptions used in preparation of our financial statements. Significant estimates with regard to these financial statements and related unaudited disclosures include the estimated fair values of assets and liabilities used in the application of fresh-start accounting as described in Note 4 and the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows therefrom disclosed in Note 20.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(m) Reclassifications

Certain reclassifications have been made to the prior period financial statements in order to conform to the classification adopted for the most recent reporting period.

(3) Acquisitions

On February 14, 2011, we acquired the ASOP Properties for $200.7 million in cash, subject to customary adjustments to reflect an economic effective date of January 1, 2011. As of December 31, 2010, the ASOP Properties had estimated proved reserves of approximately 8.1 Mmboe, of which 84% were oil and 76% were proved developed reserves. The primary factors considered by management in acquiring the ASOP Properties include the belief that the ASOP Acquisition provides an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus on oil-weighted assets in our core area of expertise in the Gulf of Mexico shelf and that it also provides us with access to infrastructure and extensive acreage, with significant exploitation and development potential.

The ASOP Acquisition was financed with the proceeds from the sale of $210 million in aggregate principal amount of our 8.25% Notes, which were offered in a private placement only to qualified institutional buyers under Rule 144A promulgated under the Securities Act of 1933, as amended (the “Securities Act”), or to persons outside of the United States in compliance with Regulation S promulgated under the Securities Act. After deducting the initial purchasers’ discount and estimated offering expenses, the Company realized net proceeds of approximately $202 million. See Note 9, “Indebtedness” for more information regarding our 8.25% Notes.

The ASOP Acquisition will be accounted for using the purchase method of accounting for business combinations. The following allocation of the purchase price as of February 14, 2011 is preliminary and includes significant use of estimates. This preliminary allocation is based on information that was available to management at the time these consolidated financial statements were prepared and takes into account current market conditions and estimated market prices for oil and natural gas. Management has not yet had the opportunity to complete its assessment of the fair values of the assets acquired and liabilities assumed. Accordingly, the allocation will change as additional information becomes available and is assessed by management, and the impact of such changes may be material.

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects management’s estimate of customary adjustments of $7.8 million to reflect an economic effective date of January 1, 2011.


(In thousands)	February 14, 2011
Oil and natural gas properties	$	210,383
Asset retirement obligations		(17,469	)

Net assets acquired	$	192,914

Pro forma results of operations are not provided for the year ended December 31, 2010 because the historical results of the ASOP Properties were not available at the time these consolidated financial statements were prepared.

(4) Reorganization and Fresh-Start Accounting

On the Exit Date, we consummated certain transactions contemplated by the Plan of Reorganization, including entering into a senior secured credit facility consisting of a $125 million revolving credit facility with an initial borrowing base of $45 million (the “Prior Revolver”) and a $25 million one-year amortizing term loan

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

facility (together with the Revolver, the “Prior Credit Facility”). We also issued 20% Senior Subordinated Secured PIK Notes due 2014 in an aggregate principal amount of $61.1 million (the “PIK Notes”). The PIK Notes were issued with original issue discount, and the note proceeds after this discount were $55.0 million. As of September 28, 2009, we had satisfied the hedging requirements under the Prior Credit Facility and had delivered to the Minerals Management Service (the “MMS”) the financial support related to abandonment obligations on certain federal leases in the Gulf of Mexico.

We reflected the reorganization and application of ASC 852 as of September 30, 2009. Fresh-start accounting is required upon a substantive change in control and requires that the reporting entity allocate the reorganization value of the Successor Company to its assets and liabilities in relation to their fair values. Based on financial projections that we and our advisors developed, the allocation of the reorganization value was determined using various valuation methods, including (i) comparable company analysis, which estimates the value of the Company based on the implied valuations of other similar companies; (ii) comparable asset transaction analysis, which estimates the value of a company based upon publicly announced transactions of assets with similar characteristics; (iii) comparable merger transaction analysis, which, much like comparable asset transaction analysis, estimates the value of a company based upon publicly announced transactions with similar characteristics, except that merger analysis analyzes public to public merger transactions rather than solely asset transactions; and (iv) discounted cash flow analysis, which estimates the value of the Company by determining the present value of estimated future cash flows. The reorganization value is based on subjective estimates and assumptions, which are inherently subject to significant uncertainties and contingencies which are beyond our control. The fair value allocated to our property and equipment should not be viewed as representative of the current value of our oil and natural gas reserves or the current value of the Company. The reorganization value of the Company was estimated to be approximately $603 million.

In order to reflect the reorganization and application of ASC 852, we adjusted the book values of the Predecessor Company’s assets and liabilities to reflect the estimated fair values of the Successor Company’s assets and liabilities, on a net basis. These adjustments increased net income by $57.1 million in the period from January 1, 2009 through September 30, 2009. The restructuring of the Company’s capital (see Note 6) and resulting discharge of the Predecessor Company Notes and related accrued interest resulted in a loss of $2.7 million in the period from January 1, 2009 through September 30, 2009. The adjustments for the revaluation of the assets and liabilities and the loss on the discharge of pre-petition debt are recorded in “Fresh-start adjustments” and “Loss on discharge of debt,” respectively, in the condensed consolidated statement of operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table reflects the reorganization and application of ASC 852 on our condensed consolidated balance sheet as of September 30, 2009:


(In thousands)	Predecessor Company as of September 30, 2009			Reorganization Adjustments (1)			Fresh-Start Adjustments (2)			Successor Company as of September 30, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	43,935		$	—		$	—		$	43,935
Trade accounts receivable		24,457			—			—			24,457
Receivables from insurance		4,036			—			—			4,036
Fair value of commodity derivative instruments		—			2,379			—			2,379
Prepaid expenses		4,445			—			—			4,445

Total current assets		76,873			2,379			—			79,252
Property and equipment		1,645,651			—			(1,026,377	)		619,274
Less accumulated depreciation, depletion and amortization		(1,057,701	)		—			1,057,701			—

Net property and equipment		587,950			—			31,324			619,274
Restricted cash		22,148			—			—			22,148
Other assets		1,712			2,863			—			4,575
Deferred financing costs		—			2,988			—			2,988

	$	688,683		$	8,230		$	31,324		$	728,237

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	23,487		$	(6,320	)	$	—		$	17,167
Accrued expenses		43,739			(6,366	)		—			37,373
Accrued interest on indebtedness		1,516			(1,085	)		—			431
Asset retirement obligations		9,308			—			—			9,308
Secured bank credit facility		83,000			(83,000	)		—			—
Secured bank credit facility term loan		—			25,000			—			25,000

Total current liabilities		161,050			(71,771	)		—			89,279
Liabilities subject to compromise:
Senior unsecured debt		454,501			(454,501	)		—			—
Accrued interest on senior unsecured debt		18,663			(18,663	)		—			—
Long-term debt		—			80,001			—			80,001
Asset retirement obligations		83,679			—			(25,787	)		57,892
Other liabilities		191			—			—			191

		718,084			(464,934	)		(25,787	)		227,363
Stockholders’ equity:
Preferred stock		—			—			—			—
Common stock		447			(407	)		—			40
Additional paid-in capital		386,268			114,566			—			500,834
Accumulated deficit		(157,760	)		100,649			57,111			—
Treasury stock		(258,356	)		258,356			—			—

Total stockholders’ equity		(29,401	)		473,164			57,111			500,874

	$	688,683		$	8,230		$	31,324		$	728,237

(1)	To record the discharge of liabilities subject to compromise, the conversion of the Predecessor Company’s common stock into new common stock of the Successor Company and to reduce the Predecessor Company’s accumulated deficit to zero. This column also reflects the following:

•

payment of pre-petition vendor claims totaling $6.3 million;

•

premiums of $5.2 million associated with hedging requirements under the Prior Credit Facility;

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

•

payment of Predecessor Company secured bank credit facility and related accrued interest;

•

payments totaling approximately $9.4 million for financing costs and certain reorganization items; and

•

loss on discharge of debt of $2.7 million reflected in accumulated deficit.

(2)	To adjust assets and liabilities to fair values.

The fair value assigned to our proved oil and natural gas properties as of September 30, 2009 was estimated by adjusting the pre-tax future cash flows from our proved reserves as set forth in our reserve reports prepared by our independent reservoir engineers as of December 31, 2008 to reflect the production for the period from December 31, 2008 through September 30, 2009 and to reflect other revisions of reserve quantities identified during 2009, which revisions were not significant. We used the NYMEX forward price curve of oil and natural gas as of September 30, 2009 to estimate the future selling price of our reserves, which we escalated at a 2.5% inflation rate for periods beyond the limits of the NYMEX forward price curve. The weighted average prices of oil and natural gas reflected in our estimate of the fair value of proved reserves were $83.88 per barrel of oil and $6.98 per mcf of natural gas. Proved reserve volumes were risk-adjusted by reference to the Society of Petroleum Engineers 28^th Annual Survey of Economic Parameters (June 2009) (“SPEE Survey”) based on the reserve category as follows: (i) proved developed producing—100%; (ii) proved non-producing—80%; (iii) proved behind pipe—80%; (iv) proved undeveloped—65%. Probable and possible reserves were risk-adjusted at 35% and 10%, respectively, by reference to the SPEE Survey. Estimated income taxes were deducted from future cash flows at a rate of 8.6%, which reflects the estimated rate of payment of cash taxes with reference to comparable companies. Net estimated future cash flows after estimated operating costs were discounted at 14.4% per year by reference to the SPEE Survey.

Our asset retirement obligations changed as a result of the application of ASC 852 because the discount rate and inflation rate applied to the estimated future abandonment costs in order to determine the fair value as of September 30, 2009 differed from the discount rates and inflation rates used to establish asset retirement obligations in prior periods under ASC Topic 410, “Asset Retirement and Environmental Obligations.”

(5) Reorganization Items

Under ASC 852, certain costs and income items resulting from the reorganization and restructuring of the business were reported separately as reorganization items classified as non-operating expenses. Our reorganization items were as follows:


(In thousands)	Successor Company Period from October 1, 2009 through December 31, 2009		Predecessor Company Period from January 1, 2009 through September 30, 2009
Amortization of deferred financing costs	$	—	$	6,838
Professional fees		785		14,462
Directors and officers insurance premium		—		1,573
Provision for rejected/renegotiated contracts		80		1,300
Employee agreements		—		25

Total reorganization items	$	865	$	24,198

Deferred financing costs as of the Petition Date associated with the Predecessor Company Notes were written off in accordance with the provisions of ASC 852. We also wrote off the remaining balance of deferred financing costs associated with the Predecessor Company’s bank credit facility which was repaid in connection with our emergence from Chapter 11 reorganization.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We retained advisors to assist in our reorganization under Chapter 11 and incurred significant costs associated with the restructuring. Professional fees primarily relate to fees paid to our financial and legal advisors, the advisors to our creditors that we were obligated to pay under certain agreements and the advisors to the official committees appointed during our Chapter 11 proceedings. During the period from January 1 to September 30, 2009, we made cash payments for these professional fees, including retainers, totaling approximately $9.0 million which were included in our cash flows from operating activities for the period. In addition to monthly fees, as of September 30, 2009, we had accrued a success fee of $3.4 million that we were obligated to pay to our financial advisor under our agreement with that firm, which is included in professional fees in the table above. This fee was paid during the period from October 1, 2009 through December 31, 2009.

Prior to our filing for reorganization under Chapter 11, we purchased a six-year extension to our directors and officers insurance coverage (commonly referred to as a “tail policy”). The premium amount of $1.6 million was recorded and paid in cash during the period from January 1 to September 30, 2009.

During September, 2009, with the approval of the Bankruptcy Court, we renegotiated the lease for our corporate office in Louisiana and rejected the lease for our office in Texas and recorded $1.4 million in associated costs, $0.9 million of which was paid during the period from October 1, 2009 through December 31, 2009. Approximately $0.5 million was paid in 2010, representing the final payment due on our lease renegotiations.

In June 2009, we executed retention agreements with all of our non-officer, non-field employees, which called for payments of one-half of the retention amounts upon execution of the agreements and the remaining one-half upon exit from our Chapter 11 reorganization. Our field employees also received payments under this program. We also executed agreements with all of our officers (except for two executive officers who had individual change of control severance agreements with the Company) that called for payments of the entire retention amount upon exit from our Chapter 11 reorganization. During the period from January 1, 2009 through September 30, 2009, we recorded approximately $2.0 million for cash payments under these agreements. In addition, the remaining two executive officers terminated their written change of control severance agreements with the Company in exchange for receiving an unsecured claim for rejection damages in the Chapter 11 reorganization. In connection with these retention agreements, non-field employees and officers were required to waive and release the Company from any and all potential claims with respect to certain incentive and retention plans and agreements as provided for in the retention agreements. During the period from January 1, 2009 through September 30, 2009, we reduced previously established accruals totaling approximately $2.0 million for the various incentive and retention plans and agreements that were waived and released.

(6) Common Stock

In connection with our emergence from Chapter 11 reorganization, we converted the Predecessor Company Notes and outstanding Predecessor Company common stock into shares of our new common stock as of the Exit Date. In accordance with the terms of the Plan of Reorganization, the Predecessor Company Notes and related indentures, as well as the Predecessor Company’s outstanding common shares, were cancelled. Each holder of these notes received, in exchange for such holder’s respective claim (including principal and accrued interest), such holder’s pro rata portion of approximately 95% of the common stock in the Successor Company, or 38 million shares. Each holder of the Predecessor Company’s common stock received, in full satisfaction of and in exchange for such holder’s respective common stock interests, such holder’s pro rata portion of approximately 5% of the common stock in the Successor Company, or approximately 2 million shares. The shares of treasury stock held by the Predecessor Company were not allocated any portion of the newly issued common stock. In each case, the common stock of the Successor Company issued pursuant to the Plan of Reorganization is subject

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

to dilution by the issuance of shares of common stock issuable under the Successor Company’s 2009 Long-Term Incentive Plan. We reserved up to 1,237,000 shares of common stock for the issuance of restricted shares and option shares under the 2009 Long-Term Incentive Plan, with 630,737 shares remaining for issuance as of December 31, 2010. See Note 15, “Employee Benefit Plans” for information regarding the 2009 Long-Term Incentive Plan.

Covenants in certain debt instruments to which we are a party, including our new credit facility and the indenture related to our 8.25% Notes, place certain restrictions and conditions on our ability to pay dividends on our common stock.

(7) Property and Equipment

The following table summarizes our property and equipment at December 31, 2010 and 2009.


	2010		2009
	(In thousands)
Proved oil and natural gas properties	$	687,759	$	618,508
Unproved oil and natural gas properties		29,230		28,606
Other		2,158		1,403

	$	719,147	$	648,517

Substantially all of our oil and natural gas properties served as collateral under our credit facility existing at December 31, 2010 and serve as collateral under our new credit facility.

We recognized impairment expense of $26.1 million, $8.5 million, $8.1 million and $110.4 million in the year ended December 31, 2010, the period from October 1, 2009 through December 31, 2009, the period from January 1, 2009 through September 30, 2009 and the year ended December 31, 2008, respectively.

Impairment expense recorded by the Successor Company in the quarter ended December 31, 2009 was primarily related to two wells in our Gulf of Mexico shelf area, one of which was unsuccessfully recompleted in 2010; the other was determined to be mechanically unable to produce a behind-pipe reservoir. Impairment expense of the Predecessor Company for the period from January 1, 2009 through September 30, 2009 was primarily related to two producing fields which were determined to have future net cash flows less than their carrying values due to commodity price declines and reservoir performance.

During 2008, we recorded impairments of oil and natural gas properties totaling $110.4 million. The impairment expense was primarily related to certain deepwater prospects ($47.5 million), producing fields (primarily five) which were determined to have future net cash flows less than their carrying values due primarily to commodity price declines and reservoir performance resulting in the write down of these properties to their estimated fair values as of December 31, 2008 ($39.3 million) and certain undeveloped properties ($20.8 million).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

At December 31, 2010 and 2009, we did not have any projects that were suspended for a period greater than one year.

(8) Asset Retirement Obligations

We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, along with a corresponding increase in the carrying amount of the related long-lived asset. The following table reconciles the beginning and ending aggregate recorded amount of our asset retirement obligations.


	Successor Company Year Ended December 31, 2010			Successor Company Period from October 1, 2009 through December 31, 2009			Predecessor Company Period from January 1, 2009 through September 30, 2009
	(in thousands)
Beginning of period total	$	69,980		$	67,200		$	105,687
Accretion expense		12,845			3,024			5,536
Revisions		4,766			1,384			3,765
Liabilities incurred		128			—			—
Liabilities settled		(16,136	)		(1,628	)		(22,001	)

End of period total		71,583			69,980			92,987
Less: End of period current portion		(16,902	)		(10,830	)		(9,308	)

End of the period noncurrent portion	$	54,681		$	59,150		$	83,679

As a result of the application of ASC 852, our asset retirement obligations were reduced by approximately $25.8 million because the discount rate and inflation rate applied to the estimated future abandonment costs in order to determine the fair value as of September 30, 2009 differed from the discount rates and inflation rates used to establish asset retirement obligations in prior periods.

(9) Indebtedness

The following table sets forth our indebtedness.


(In thousands)	SUCCESSOR COMPANY December 31, 2010		SUCCESSOR COMPANY December 31, 2009
Term loan component of Prior Credit Facility, interest rate of 6.5% on December 31, 2009 based on base rate plus a floating spread, payable September 21, 2010	$	—	$	18,750
Revolving credit component of Amended Prior Credit Facility, interest rate of 6.5% on December 31, 2009, based on LIBOR plus a floating spread, payable September 21, 2012		—		—
PIK Notes, face amount of $61.1 million, interest rate of 20%, payable September 21, 2014 (net of $5.9 million of unamortized original issue discount)		—		55,195
In-kind interest on PIK Notes (new notes issued January 1, 2010), face amount of $3.4 million, interest rate of 20%, payable September 21, 2014		—		3,395

Total indebtedness		—		77,340
Current portion of indebtedness		—		18,750

Noncurrent portion of indebtedness	$	—	$	58,590

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On February 14, 2011, our credit facility existing at December 31, 2010 was replaced with a new credit facility, and, in connection with the ASOP Acquisition (see Note 3), we issued $210.0 million in aggregate principal amount of our 8.25% Notes due 2018. See Subsequent Events below for more information on these transactions.

Credit Facility at December 31, 2010

On June 16, 2010, we entered into an amendment (the “First Amendment”) to our Prior Credit Facility dated as of September 21, 2009, (together with the First Amendment, the “Amended Prior Credit Facility”) with General Electric Capital Corporation, as administrative agent (the “Agent”), and the lender parties thereto (the “Lenders”). Upon its effectiveness on June 28, 2010, the Amended Prior Credit Facility established a $70 million borrowing base consisting of (a) a new $25 million term loan payable, with interest, in six equal monthly installments of principal from July 28, 2010 to December 28, 2010 and (b) a revolving credit facility with a three-year term that could be used for revolving credit loans and letters of credit up to an initial maximum principal amount of $45 million. The interest rate spread on loans and letters of credit under the Amended Prior Credit Facility was based on the level of utilization and ranged from 3.75% to 4.25% for base rate borrowings and 4.75% to 5.25% for LIBOR borrowings. The First Amendment contained the Lenders’ consent for us to redeem all outstanding principal and pay all accrued interest on PIK Notes, which redemption occurred on June 28, 2010 and was a condition to the effectiveness of the First Amendment. On December 28, 2010, we repaid in full all outstanding borrowings under the term loan component of our Amended Prior Credit Facility and had no borrowings outstanding on the revolver component.

The First Amendment did not make any material changes to the covenants, default provisions or collateral requirements under the Prior Credit Facility. Our obligations under the Amended Prior Credit Facility and under derivative contracts were guaranteed by our material subsidiaries and secured by our real property assets and the oil and natural gas properties to which 90% of the present value of our proved reserves was attributable.

At December 31, 2010, our borrowing base was $45.0 million under the Amended Prior Credit Facility. The maximum amount of letters of credit that could be outstanding at any one time was $20 million, and the amount available under the revolving credit facility was limited by the borrowing base. The borrowing base was subject to semi-annual redeterminations based on the proved reserves of the oil and natural gas properties that served as collateral for the Amended Prior Credit Facility. In January 2011, our borrowing base had been reaffirmed at $45 million.

On September 21, 2009, we entered into the Prior Credit Facility with the Agent and the Lender. The Prior Credit Facility provided for senior secured borrowings consisting of (a) a one-year, $25 million term loan and (b) a three-year revolving credit facility that could be used for revolving credit loans and letters of credit from time to time up to a maximum principal amount of $125 million, including the $25 million term loan, subject to limitations described below in this paragraph. The maximum amount of letters of credit that could be outstanding at any one time was $20 million and the amount available under the revolving credit facility was limited by the borrowing base. The initial borrowing base at closing was $70 million, including the $25 million term loan. At December 31, 2009, the borrowing base was $63.8 million, including the $18.8 million remaining balance on the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

term loan. The borrowing base was subject to semi-annual redeterminations based on the proved reserves of the oil and gas properties that served as collateral for the Prior Credit Facility. We were subject to our first borrowing base redetermination beginning in December 2009, and our borrowing base had been reaffirmed at $45 million plus the remaining balance on the term loan. Monthly scheduled repayments of the $25 million term loan, each in the amount of $2.1 million, reduced the borrowing base by the principal amount of each such repayment. Our obligations under the Prior Credit Facility and under derivative contracts with the Lenders were guaranteed by our material subsidiaries and secured by our real property assets and the oil and gas properties to which 90% of the present value of our proved reserves was attributable (the “Collateral”).

The Prior Credit Facility permitted both base rate based borrowings and LIBOR borrowings, in each case plus a floating spread. The spread would float up or down based on our utilization under the credit facilities (the “Utilization Level”). The spread could range from 3.00% to 3.50% for base rate borrowings and 4.00% to 4.50% for LIBOR borrowings. The credit agreement included a LIBOR floor of 2.00%. We incurred a commitment fee on the unused portion of the borrowing base at a rate ranging from 0.75% to 1.00% based upon the Utilization Level.

The term loan required repayment in twelve installments of approximately $2.1 million each month beginning October 21, 2009, with any remaining principal balance due on September 21, 2010. The original maturity of the revolving credit facility was September 21, 2012. However, the Prior Credit Facility was amended on June 16, 2010 as described above.

The Prior Credit Facility contained customary negative covenants and customary events of default. As described in the Prior Credit Facility, we were required to maintain, for each period for which a covenant certification was required, (a) a current ratio (as defined in the credit facility) of 1.0 to 1.0, (b) an interest coverage ratio of not less than 2.50 to 1.0, (c) a leverage ratio less than or equal to 1.50 to 1.0, and (d) a coverage ratio, as defined in the credit agreement, with respect to plugging and abandonment obligations. We were also required to maintain a commodities hedging program that was in compliance with the requirements set forth in the Prior Credit Facility. The determination of our borrowing base under the Prior Credit Facility was based on our proved reserves using the Lenders’ pricing assumptions, and included the impact of our commodity derivative instruments. The Prior Credit Facility also placed restrictions on the maximum estimated future production volumes that could be subject to commodity derivative instruments. In order to meet our objectives in establishing the Prior Credit Facility borrowing base and to conform to the Prior Credit Facility terms, we entered into certain commodity derivative instruments upon our emergence from Chapter 11 reorganization in connection with executing the Prior Credit Facility. See Note 12, “Derivative Transactions,” for more information regarding outstanding commodity derivative instruments.

PIK Notes

On September 21, 2009, we issued the PIK Notes due 2014 in an aggregate principal amount of $61.1 million pursuant to an indenture dated September 21, 2009. The PIK Notes were issued with original issue discount, and the note proceeds after this discount were $55.0 million. The PIK Notes allowed, or required, as specified in the indenture, for payment of interest “in-kind” in the form of newly issued notes having the same terms as the PIK Notes. Interest on the PIK Notes and newly issued PIK Notes issued for payment of periodic interest was payable in additional PIK Notes or in cash subject to the limitations described below and in the indenture.

On June 28, 2010, we redeemed all outstanding principal and paid all accrued interest on the PIK Notes. The redemption price of the PIK Notes was 100% of the outstanding aggregate principal amount. In connection with

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

the redemption, we paid a total of $70.9 million of principal and accrued interest. We recorded a loss on the redemption of $5.6 million representing the total of the unamortized original issue discount and unamortized deferred financing costs associated with the PIK Notes.

Until the first interest payment date that would occur 91 days after the repayment in full of all amounts outstanding under the Prior Credit Facility and the termination of the Lenders’ commitments under the Prior Credit Facility (such date being, the “Credit Facility Termination Date”), interest on the PIK Notes was payable in-kind, semi-annually in arrears on January 1 and July 1 of each year, beginning on January 1, 2010. At December 31, 2009, our total indebtedness related to the PIK Notes included $3.4 million of accrued interest “in-kind” for which new notes were issued on January 1, 2010. After the Credit Facility Termination Date, interest on the original PIK Notes and any additional PIK Notes issued for in-kind interest payments, would be payable quarterly in cash in arrears on January 1, April 1, July 1 and October 1 of each year. All of the PIK Notes would have matured on September 21, 2014 along with all accrued but unpaid interest and the outstanding PIK Note principal balances.

The PIK Notes were (a) subordinated in right of payment to the Prior Credit Facility, (b) guaranteed by our material subsidiaries and (c) (i) prior to the Credit Facility Termination Date, secured by the Collateral or (ii) after the Credit Facility Termination Date, secured by the Collateral plus certain additional real property collateral as may be required under the indenture. The security interests granted for the benefit of the holders of the PIK Notes were subordinated to those granted in favor of the Lenders.

The indenture related to the PIK Notes imposed customary negative covenants, which were based on such covenants contained in the Prior Credit Facility, and contained customary events of default, except that there were no financial performance covenants contained in the indenture.

Predecessor Indebtedness

In April 2007, the Predecessor Company refinanced an existing bank credit facility with a credit agreement, which had availability and a borrowing base of $200 million and was secured by substantially all of our assets (the “Pre-Reorganization Credit Agreement”). The borrowing base under the Pre-Reorganization Credit Agreement was subject to redetermination based on the proved reserves of the oil and natural gas properties that served as collateral as set out in the reserve report delivered to the banks in April and October each year. In November 2008, the Pre-Reorganization Credit Agreement was redetermined with a borrowing base of $150 million. At December 31, 2008, we had $43 million outstanding under the Pre-Reorganization Credit Agreement. In March 2009, the Pre-Reorganization Credit Agreement was redetermined with a new borrowing base of $45 million. The Predecessor Company had $83 million outstanding under the Pre-Reorganization Credit Agreement, resulting in a deficiency of $38 million and a demand for repayment of the borrowing base deficiency.

While we were not in default under our Pre-Reorganization Credit Agreement as of December 31, 2008, we subsequently failed to timely satisfy a number of Pre-Reorganization Credit Agreement covenants, including those requiring the delivery of our December 31, 2008 debt compliance certificate in April 2009 and providing our December 31, 2008 financial results at that time. On September 21, 2009, outstanding borrowings under the Pre-Reorganization Credit Agreement of $83 million were repaid using proceeds from the Prior Credit Facility and the PIK Notes.

As described in Note 4, “Reorganization and Fresh-Start Accounting,” the Predecessor Company Notes and the related indentures were cancelled in connection with the reorganization, resulting in a loss on debt discharge of $2.7 million during the period from January 1, 2009 through September 30, 2009. In addition, the outstanding borrowings under the Pre-Reorganization Credit Agreement and related accrued interest were repaid.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Subsequent Events

Senior Notes Offering

On February 14, 2011, we issued the $210.0 million in aggregate principal amount of our 8.25% Notes under an Indenture, dated as of February 14, 2011 (the “Indenture”). As described in Note 3, “Acquisitions,” we used the net proceeds from the offering of the 8.25% Notes of $202.0 million, after deducting the initial purchasers’ discount and estimated offering expenses payable by us, to acquire the ASOP Properties for a purchase price of $200.7 million and for general corporate purposes. The 8.25% Notes bear interest from the date of their issuance at an annual rate of 8.25% with interest on outstanding notes payable semi-annually, in arrears, on February 15 and August 15 of each year, commencing on August 15, 2011. The 8.25% Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries). The 8.25% Notes will mature on February 15, 2018. In connection with the execution of the Indenture, we also entered into a registration rights agreement, dated as of February 14, 2011 (the “Registration Rights Agreement”).

On or after February 15, 2015, we may on any one or more occasions redeem all or a part of the 8.25% Notes upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest and special interest, if any, on the 8.25% Notes redeemed, to the applicable redemption date, if redeemed during the twelve-month period beginning on February 15^th of the years indicated below, subject to the rights of holders of Notes on the relevant record date to receive interest on the relevant interest payment date:


Year	Percentage
2015		104.125	%
2016		102.063	%
2017 and thereafter		100.000	%

Any such redemption and notice may, in our discretion, be subject to the satisfaction of one or more conditions precedent, including but not limited to, the occurrence of a change of control. Unless we default in the payment of the redemption price, interest will cease to accrue on the 8.25% Notes or portions thereof called for redemption on the applicable redemption date.

At any time prior to February 15, 2014, we may, at our option, on any one or more occasions redeem up to 35% of the aggregate principal amount of outstanding 8.25% Notes (which amount includes additional notes issued under the Indenture), upon not less than 30 nor more than 60 days’ prior notice, at a redemption price equal to 108.250% of the principal amount of the notes redeemed, plus accrued and unpaid interest and special interest, if any, to the redemption date, with the net cash proceeds of certain equity offerings, provided that: (1) at least 65% of the aggregate principal amount of 8.25% Notes issued under the Indenture (which amount includes additional notes issued under the Indenture) remains outstanding immediately after the occurrence of such redemption; and (2) the redemption occurs within 90 days of the date of the closing of such equity offering. In addition, we may, at our option, on any one or more occasions redeem all or a part of the 8.25% Notes prior to February 15, 2015 at a redemption price equal to 100% of the principal amount of the 8.25% Notes redeemed plus a “make-whole” premium as of, and accrued and unpaid interest and special interest, if any, to the redemption date.

If we experience a change of control (as defined in the Indenture), each holder of the 8.25% Notes will have the right to require us to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of the 8.25% Notes at a price in cash equal to 101% of the aggregate principal amount of the

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

8.25% Notes repurchased, plus accrued and unpaid interest and special interest, if any, to the date of repurchase. If we engage in certain asset sales, within 360 days of such sale, we generally must use the net cash proceeds from such sales to repay outstanding senior secured debt (other than intercompany debt or any debt owed to an affiliate), to acquire all or substantially all of the assets, properties or capital stock of one or more companies in our industry, to make capital expenditures or to invest in our business. When any such net proceeds that are not so applied or invested exceed $20.0 million, we must make an offer to purchase the 8.25% Notes and other pari passu debt that is subject to similar asset sale provisions in an aggregate principal amount equal to the excess net cash proceeds. The purchase price of each 8.25% Note (or other pari passu debt) so purchased will be 100% of its principal amount, plus accrued and unpaid interest and special interest, if any, to the repurchase date, and will be payable in cash.

The Indenture, among other things, limits our ability to: (i) declare or pay dividends, redeem subordinated debt or make other restricted payments; (ii) incur or guarantee additional debt or issue preferred stock; (iii) create or incur liens; (iv) incur dividend or other payment restrictions affecting restricted subsidiaries; (v) consummate a merger, consolidation or sale of all or substantially all of our assets; (vi) enter into sale-leaseback transactions, (vii) enter into transactions with affiliates; (viii) transfer or sell assets; (ix) engage in business other than our current business and reasonably related extensions thereof; or (x) issue or sell capital stock of certain subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the Indenture.

Under the Registration Rights Agreement, we and our guarantor subsidiaries (the “Guarantors”) agreed to file a registration statement with the Securities and Exchange Commission (the “SEC”) offering to exchange a new series of freely tradable notes having substantially identical terms as the 8.25% Notes (“exchange notes”) for the 8.25% Notes. We and the Guarantors have agreed to (i) file a registration statement for the exchange notes with the SEC within 150 days after the closing of the 8.25% Notes offering; (ii) use commercially reasonable efforts to cause the registration statement to be declared effective as soon as practicable, but in any event within 210 days after the closing of the 8.25% Notes offering; and (iii) use commercially reasonable efforts to close the exchange offer 30 business days after the registration statement is declared effective. In certain circumstances, we may be required to file a shelf registration statement to cover resales of the 8.25% Notes. The use of the shelf registration statement will be subject to certain customary suspension periods. If we and the Guarantors do not meet these deadlines, we will be required to pay special interest to holders of 8.25% Notes under certain circumstances.

New Senior Credit Facility

On February 14, 2011, we entered into our new credit facility with BMO Capital Markets, as lead arranger, and Bank of Montreal, as administrative agent and a lender. The terms of our new credit facility establish a revolving credit facility with a four-year term that may be used for revolving credit loans and letters of credit up to an aggregate principal amount of $250.0 million, subject to an initial borrowing base of $150.0 million. The maximum amount of letters of credit that may be outstanding at any one time is $20.0 million, and the amount available under the revolving credit facility is limited by the borrowing base. With the consent of the agent, we also have the ability to increase the aggregate commitments under the new credit facility by up to $100.0 million to the extent that existing and/or future lenders provide additional commitments. Upon the closing of our new credit facility, our existing credit facility was terminated. We had no amounts drawn under our new credit facility at the time of closing.

The interest rate spread on loans and letters of credit under our new credit facility will be based on the level of utilization and will range from a base rate plus a margin of 1.00% to 2.00% for base rate borrowings and

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

LIBOR plus a margin of 2.00% to 3.00% for LIBOR borrowings. A commitment fee of 0.5% is payable on the unused portion of the borrowing base. Interest on our base rate borrowings will be payable quarterly, in arrears, and interest on our LIBOR borrowings will be payable on the last day of each relevant interest period, except that in the case of any interest period that is longer than three months, interest will be payable on each successive date three months after the first day of such interest period.

Our new credit facility contains customary covenants, default provisions and collateral requirements. As described in the agreement underlying our new credit facility, we must maintain, for each period for which a covenant certification is required, (a) a minimum current ratio (as defined in the agreement for our new credit facility) of 1.0 to 1.0, (b) a minimum EBITDAX to interest expense coverage ratio of 2.5 to 1.0 and (c) a maximum total debt to EBITDAX ratio of 3.5 to 1.0. We will also be required to maintain a commodities hedging program that is in compliance with the requirements set forth in our new credit facility. The determination of our borrowing base under our new credit facility will be based on our proved reserves, at the sole discretion of the lenders. The initial borrowing base is $150.0 million until May 1, 2011, and scheduled borrowing base redeterminations will be made on a semi-annual basis on May 1^st and November 1^st of each year. Our new credit facility also places restrictions on the maximum estimated future production volumes that can be subject to commodity derivative instruments.

Our obligations under our new credit facility, as well as any hedging contracts and treasury management agreements with the lenders or affiliates of lenders, are guaranteed by our material domestic subsidiaries and secured by a pledge of 100% of the stock of each material domestic subsidiary and 66²/3% of each of their foreign material subsidiaries and a first priority lien on substantially all of our and our material subsidiaries’ assets, including our real property assets and the oil and gas properties to which 85% of the present value of our proved reserves is attributable.

(10) Significant Customers

We had oil and natural gas sales to three customers accounting for 42%, 26% and 11%, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2010. We had oil and natural gas sales to three customers accounting for 36%, 19% and 14%, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the period from October 1, 2009 through December 31, 2009. We had oil and natural gas sales to three customers accounting for 30%, 27% and 21%, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the period from January 1, 2009 through September 30, 2009. We had oil and natural gas sales to three customers accounting for 38%, 24% and 23%, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2008.

(11) Tropical Weather

During the periods from October 1, 2009 through December 31, 2009 and from January 1, 2009 through September 30, 2009, we recorded reductions to lease operating expenses for property damage claims totaling approximately $4.1 million and $1.4 million, respectively, all of which was recorded in receivables from insurance at December 31, 2009. In order to mitigate the higher cost of insurance coverages in 2009, we negotiated higher deductibles for property damage due to named windstorms (such as hurricanes) and significantly lower aggregates for property damage due to named windstorms. Currently, we have an offshore property physical damage policy with a deductible of $20 million per occurrence and an aggregate annual named windstorm limit of $70 million. Due to limited availability of insurance coverage at commercially acceptable rates, we no longer maintain business interruption insurance.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In late August and early September 2008 Hurricanes Gustav and Ike traversed the Gulf of Mexico and adjacent land areas. As a result of these two hurricanes, nearly all of our production was shut-in at one time or another during the third and fourth quarters of 2008. For these occurrences, we previously maintained business interruption insurance on a portion of our lost revenue on our South Timbalier 41, 42 and 46 properties. Recovery of lost revenue from these properties began accruing during the fourth quarter of 2008 when the “no claim period” provided for under the policy elapsed. Through December 31, 2008, the total business interruption claim on these fields was $4.2 million, all of which was collected in 2009.

(12) Derivative Transactions

We enter into derivative transactions to reduce exposure to fluctuations in the price of oil and natural gas for a portion of our production. Our put contracts limit our exposure to declines in the sales price of oil for a limited amount of our production. Our fixed-price swaps fix the sales price for a limited amount of our production and, for the contracted volumes, eliminate our ability to benefit from increases in the sales price of the production. Derivative contracts are carried at their fair value on the consolidated balance sheets as Fair value of commodity derivative instruments and all unrealized and realized gains and losses are recorded in Gain (loss) on derivative instruments in Other income (expense) in the consolidated statements of operations. See Note 13 for information regarding fair values of our derivative instruments.

The following table sets forth our derivative contracts outstanding as of December 31, 2010.

Oil Contracts


	Fixed-Price Swaps						Puts
Remaining Contract Term	Daily Average Volume (Bbls)		Volumes (Bbls)		Average Swap Price ($/Bbl)		Daily Average Volume (Bbls)		Volume (Bbls)		Floor Price ($/Bbl)
January 2011—July 2011		2,261		479,250	$	71.13		502		106,500	$	60.00
August 2011—November 2011		502		61,200	$	72.18		1,301		158,700	$	60.00
December 2011		948		29,400	$	72.64		1,302		40,350	$	60.00

During the period from January 1, 2009 through September 30, 2009, we had agreed to termination of our derivative contracts as requested by our lenders or as required by the terms of our agreements with them. The following table presents information about the components of gain (loss) on derivative instruments.


(In thousands)	Successor Company Year Ended December 31, 2010			Successor Company Period from October 1, 2009 through December 31, 2009			Predecessor Company Period from January 1, 2009 through September 30, 2009		Predecessor Company Year Ended December 31, 2008
Derivative contracts:
Unrealized gain (loss) due to change in fair market value	$	3,500		$	(21,739	)	$	—	$	19,057
Realized gain (loss) on settlement		(8,365	)		(966	)		2,728		(17,004	)

Total gain (loss) on derivative instruments	$	(4,865	)	$	(22,705	)	$	2,728	$	2,053

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(13) Fair Value Measurements

ASC Topic 820, “Fair Value Measurements and Disclosures,” establishes a fair value hierarchy with three levels based on the reliability of the inputs used to determine fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets and liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

As of December 31, 2010 and 2009, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, primarily our commodity derivative instruments. At December 31, 2010 and 2009, the fair values of derivative instruments were measured using price inputs published by NYMEX. These price inputs are quoted prices for assets and liabilities similar to those held by us and meet the definition of Level 2 inputs within the fair value hierarchy. At December 31, 2010, the carrying amounts and fair values of our derivative instruments are reported as assets totaling $0.2 million and liabilities totaling $12.3 million. At December 31, 2009, the carrying amounts and fair values of our derivative instruments are reported as assets totaling $2.1 million and liabilities totaling $17.8 million.

We evaluate our capitalized costs of proved oil and natural gas properties for potential impairment when circumstances indicate that the carrying values may not be recoverable. Our assessment of possible impairment of proved oil and natural gas properties is based on our best estimate of future prices, costs and expected net future cash flows by property (generally analogous to a field or a lease). An impairment loss is indicated if undiscounted net future cash flows are less than the carrying value of a property. The impairment expense is measured as the shortfall between the net book value of the property and its estimated fair value measured based on the discounted net future cash flows from the property. The inputs used to estimate the fair value of our oil and natural gas properties meet the definition of Level 3 inputs within the fair value hierarchy. Impairment expense for the year ended December 31, 2010 was primarily related to the decline in our estimate of future natural gas prices as of September 30, 2010 as compared to June 30, 2010 affecting two producing fields, including our deepwater producing well, and to reservoir performance of one of these fields and one additional producing field. These producing fields were determined to have future net cash flows less than their carrying values resulting in the write down of these properties to their estimated fair values during the year ended December 31, 2010.

As addressed in Note 4, “Reorganization and Fresh-Start Accounting,” we applied fair value concepts in allocating the reorganization value of the Company to our assets and liabilities as a result of the reorganization and application of ASC 852. The inputs to the fair values of our more significant assets and liabilities are addressed in Note 4.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(14) Income Taxes

The following table sets forth the components of our income tax benefit.


	Successor Company Year Ended December 31, 2010		Successor Company October 1, 2009 through December 31, 2009		Predecessor Company January 1, 2009 through September 30, 2009		Predecessor Company Year Ended December 31, 2008
	(In thousands)
Current:
Federal	$	—	$	—	$	—	$	—
State		—		—		—		—

	$	—	$	—	$	—	$	—

Deferred:
Federal	$	4,248	$	11,076	$	—	$	16,542
State		161		324		—		473

	$	4,409	$	11,400	$	—	$	17,015

Total:
Federal	$	4,248	$	11,076	$	—	$	16,542
State		161		324		—		473

	$	4,409	$	11,400	$	—	$	17,015

The following table reconciles the expected statutory federal income tax rate to our effective income tax rate.


	Percentage of Pretax Earnings
	Successor Company Year Ended December 31, 2010			Successor Company October 1, 2009 through December 31, 2009			Predecessor Company January 1, 2009 through September 30, 2009			Predecessor Company Year Ended December 31, 2008
Expected statutory federal income tax rate		35.0	%		35.0	%		35.0	%		35.0	%
State taxes		2.6			1.0			1.0			1.0
Valuation allowance		—			—			(41.0	)		(10.8	)
State tax rate changes		(3.6	)		—			—			—
Statutory depletion		3.4			—			—			—
Other		(3.2	)		(0.8	)		5.0			(0.6	)

		34.2	%		35.2	%		0	%		24.6	%

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table sets forth the tax effects of temporary differences that give rise to significant portions of the current tax asset and net deferred tax liability at December 31, 2010 and 2009.


	2010			2009
	(In thousands)
Current deferred tax assets (liabilities):
Fair value of commodity derivative instruments	$	70		$	3,363
Other		2,623			2,405

Net current deferred tax asset	$	2,693		$	5,768

Non-current deferred tax assets:
Restricted stock awards and options	$	558		$	—
Federal and state net operating loss carryforwards		47,706			47,952
Fair market value of commodity derivative instruments		—			2,265
Other		9,529			4,048

Non-current deferred tax asset		57,793			54,265
Non-current deferred tax liabilities:
Property, plant and equipment, principally due to differences in depreciation		(79,583	)		(71,219	)
Other		(679	)		—

Non-current deferred tax liability		(80,262	)		(71,219	)

Net non-current deferred tax liability	$	(22,469	)	$	(16,954	)

As a result of our reorganization under Chapter 11 in 2009 as described in Note 4, “Reorganization and Fresh-Start Accounting,” the income from the discharge of indebtedness, represented for tax purposes as the excess of the principal and accrued interest on the debt discharged over the fair value of the stock of the reorganized company received in exchange for the discharged obligations, as defined by Internal Revenue Code (the “IRC”) Section 108 (“IRC 108”), reduced our net operating loss carryforwards (“NOLs”) by $97 million (“Tax Attribute Reduction”). Our remaining NOLs as of December 31, 2009 were approximately $125 million. As of December 31, 2010, our remaining NOLs were estimated to be $126 million.

Ownership changes, as defined in IRC Section 382, limit the amount of NOLs that can be utilized annually to offset future taxable income and reduce the tax liability (“Section 382 Limitation”). In 2009, as part of our Chapter 11 reorganization, we had an ownership change which resulted in a Section 382 Limitation on the amount of utilization of each NOL. The limitation is approximately $21 million annually.

We believe that we will be able to utilize all of the NOLs prior to their expiration. The ability to elect the amount of intangible drilling costs to be expensed each year is a major factor generating the NOLs. Prior to December 31, 2009, our net deferred tax position had changed from a net deferred tax liability position to a net deferred tax asset position, before consideration of the valuation allowance. We were not able to conclude that it was more likely than not that our net deferred tax assets would be realized through future earnings and reversal of taxable temporary differences, primarily due to the existence of cumulative book losses for the three year period ended December 31, 2008. As a result, we had previously provided a valuation allowance of $7.5 million as of December 31, 2008, which reduced our net deferred tax asset to zero. The Tax Attribute Reduction changed our net deferred tax position, before consideration of the valuation allowance, from a net deferred tax asset to a net deferred tax liability, which eliminated the need for the valuation allowance; thus, we reversed all of the previously established valuation allowance as of December 31, 2009.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Our federal NOLs of $127 million as of December 31, 2010 are available to reduce future federal taxable income subject to the limitations and estimates described above and the application of the tax rules and regulations. The NOLs begin expiring in the years 2025 through 2030. We believe that we have net unrealized built-in gains that will be recognized under IRC 382 that would sufficiently add to the Section 382 Limitation, making it more likely than not that a valuation allowance is not needed against the NOLs and other tax attributes.

As of January 1, 2011, our 2007-2009 income tax years remain subject to examination by the Internal Revenue Service. In addition, our 2006-2009 state income/franchise tax years remain subject to examination by the States of Louisiana and Texas. As of the date of these financial statements, our 2010 U.S. federal and state income tax returns have not been filed, although management expects to file such returns in a timely manner during 2011. We have no material uncertain tax positions as of December 31, 2010.

(15) Employee Benefit Plans

Stock-Based Compensation Plans

In September 2009 the Board of Directors of the Successor Company adopted the Energy Partners, Ltd. 2009 Long Term Incentive Plan (the “2009 LTIP”). The purpose of the 2009 LTIP is to provide a means to enhance our profitable growth by attracting and retaining directors, officers and other key employees through affording such individuals a means to acquire and maintain stock ownership or awards the value of which is tied to the performance of our common stock. All directors, officers and other key employees providing services to the Company are potentially eligible to participate in the 2009 LTIP. The 2009 LTIP provides for grants of (i) incentive stock options qualified as such under income tax rules and regulations, (ii) stock options that do not qualify as incentive stock options, (iii) restricted stock awards, (iv) restricted stock units, (v) stock appreciation rights, (vi) bonus stock and awards in lieu of Company obligations, (vii) dividend equivalents in connection with other awards, (viii) deferred shares, (ix) performance units or shares, or (x) any combination of such awards (collectively referred to as “Awards”). The 2009 LTIP is administered by a committee of our Board of Directors.

The maximum aggregate number of shares of our common stock that may be issued pursuant to any and all Awards under the 2009 LTIP is limited to 1,237,000 shares, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or the expiration of Awards, as provided under the 2009 LTIP. As of December 31, 2010, 630,737 shares remained available for future grants.

Without stockholder or participant approval, the Board of Directors may amend, alter, suspend, discontinue or terminate the 2009 LTIP or the Committee’s authority to grant Awards under the 2009 LTIP, except that any amendment or alteration of the 2009 LTIP, including any increase in any share limitation, shall be subject to the approval of the stockholders not later than the next annual meeting if stockholder approval is required by any state or federal law or regulation or the rules of any stock exchange or automated quotation system on which the common stock may then be listed or quoted.

The 2009 LTIP provides for the grant of stock options for which the exercise price, set at the time of the grant, will not be less than the fair market value per share at the date of grant. Our outstanding stock options generally have a term of 10 years and vest ratably on an annual basis over a three-year period from the date of grant, other than the stock option grant to our chief executive officer described in the following paragraph.

Pursuant to an employment agreement and the 2009 LTIP, on September 30, 2009, our new chief executive officer was granted an option to purchase 68,116 shares of Successor Company common stock, which was memorialized in an option award agreement dated as of October 1, 2009 (the “Option Agreement”). The terms of the Option Agreement provide for an exercise price equal to $10.00 per share. The closing price of our common

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

stock on the NYSE on September 30, 2009 was $7.46 per share. The option vests ratably on a monthly basis over a 36-month period from the date of grant; provided, however, that the vesting for the first six months of the vesting period (the “Initial Period”) is deferred until the end of the Initial Period and any remaining unvested portion vests ratably on a monthly basis over the remainder of the 36-month vesting period, subject to the executive remaining continuously employed. Vested stock options under the Option Agreement expire 30 months following the applicable vesting date of such stock options. Upon a change in control as defined in the 2009 LTIP, all remaining unvested stock options under the Option Agreement automatically vest and remain exercisable for a period of not less than 30 months following the change in control.

Pursuant to the 2009 LTIP, on the date of the 2010 Annual Meeting of Stockholders, the five members of the Board of Directors were awarded, in the aggregate, a total of 42,735 shares of restricted stock, of which one-half vested immediately and one-half will vest on the day immediately preceding the date of the 2011 Annual Meeting of Stockholders. In connection with the appointment of the five members of the Board of Directors of the Successor Company and pursuant to the 2009 LTIP, the five directors were awarded, in the aggregate, a total of 43,460 shares of restricted stock, of which one-half vested immediately and one-half vested on the day immediately preceding the date of the 2010 Annual Meeting of Stockholders. Pursuant to elections applicable to the 2010 award made by two directors and applicable to the 2009 award made by one director, the receipt of such stock awards are deferred until such directors cease to serve on our Board of Directors.

Prior to the reorganization, the Predecessor Company had two stock-based compensation plans, which are more fully described below. Pursuant to the Plan of Reorganization, all stock option or other equity awards outstanding under these plans became fully vested and were deemed exercised or were cancelled. The number of shares of Predecessor Company common stock that were issued as a result of accelerated vesting of prior restricted stock grants totaled 147,372 shares, which shares were converted into 9,103 shares of Successor Company common stock upon emergence from Chapter 11 reorganization. All Predecessor Company stock and incentive plans for employees were deemed cancelled under the Plan of Reorganization.

The 2006 Long Term Stock Incentive Plan provided for the grant of stock options for which the exercise price, set at the time of the grant, was not less than the fair market value per share at the date of grant. The outstanding options had a term of 10 years and generally vested over three years with grants to a limited group of people that cliff vested at the end of five years.

The Amended and Restated 2000 Stock Incentive Plan for Non-Employee Directors (the Director Plan) was adopted by the Board of Directors in March 2005 and approved by our stockholders in May 2005. The Director Plan permitted the use of restricted share units in addition to stock options to provide flexibility to adjust grants to maintain a competitive equity component for non-employee directors. The option exercise price for an option granted under the Director Plan was the fair market value of the shares covered by the option at the time the option was granted. Options became fully exercisable on the first anniversary of the date of the grant. Prior to the one-year anniversary, the options were exercisable as to a number of shares covered by the option determined by pro-rating the number of shares covered by the option based on the number of days elapsed since the date of the grant. Any portion of an option that had not become exercisable prior to the cessation of the optionee’s service as a director for any reason would not thereafter become exercisable. Each option was to expire on the earlier of (1) 10 years from the date of the granting thereof, or (2) 36 months after the date the optionee ceased to be a director of the Company for any reason. Each restricted share unit represented the right to receive one share of common stock upon the earlier to occur of: (1) the cessation of the eligible director’s service as a director of the Company for any reason, or (2) the occurrence of a change of control of the Company. An eligible director became 100% vested in a grant of restricted share units on the first anniversary of the date of grant.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table sets forth our stock option activity for the year ended December 31, 2010.


	Options			Weighted- Average Exercise Price Per Share		Weighted- Average Remaining Contractual Terms		Aggregate Intrinsic Value
						(in years)		(in thousands)
Outstanding on December 31, 2009		68,116		$	10.00
Granted		438,000			10.50
Forfeited/Cancelled		(17,500	)		8.90

Outstanding on December 31, 2010		488,616		$	10.49		8.5	$	2,135
Exercisable on December 31, 2010		26,490		$	10.00		4.3	$	129

The fair value of each stock option award was estimated on the date of grant using the Black-Scholes option valuation model using the weighted average assumptions in the table below for the year ended December 31, 2010, for the period from January 1, 2009 through September 30, 2009 and the year ended December 31, 2008. No stock option awards were granted during the period from October 1, 2009 through December 31, 2009.


	Year Ended December 31, 2010			January 1, 2009 through September 30, 2009			Year Ended December 31, 2008
Black-Scholes option pricing model assumptions:
Risk free interest rate		2.9	%		1.9	%		4.5	%
Expected life (years)		6.0			4.0			4.95
Expected volatility		50	%		52	%		38	%
Dividend yield		—			—			—

Expected volatility is generally based on the historical volatility of our stock over the period of time equivalent to the expected term of the options granted. As a result of our reorganization for purposes of determining expected volatility in 2010 and 2009, we included consideration of the historical volatility of the share prices of our peers over the relevant time periods in addition to our historical volatility before, during and after our reorganization. We disregarded our share price for the periods during which our stock price was impacted by factors leading up to the Chapter 11 filing and during the period of the Chapter 11 reorganization proceedings because we do not expect these events to reoccur during the expected term of the options. The expected term of options granted is generally derived from historical exercise patterns over a period of time, with consideration of expected term of unvested options. However, because the Successor Company does not have sufficient historical stock option exercise experience upon which to base an estimate of expected term, we used the simplified method for estimating expected term in 2010. In 2009, due to the unique vesting schedule of the option award to our new chief executive officer during 2009, we based the expected term assumption for that option award on the weighted average contractual term of the option shares, taking into account the vesting schedule and other factors, including expected exercise and post-vesting employment termination behavior. The risk-free interest rate is based on the interest rate on constant maturity bonds published by the Federal Reserve with a maturity commensurate with the expected term of the options granted.

The weighted-average grant-date fair value of stock options granted during the year ended December 31, 2010, the period from January 1, 2009 through September 30, 2009 and the year ended December 31, 2008 was $5.32, $2.48 and $4.53, respectively. No stock options were exercised during the year ended December 31, 2010, the period from October 1, 2009 through December 31, 2009 or the period from January 1, 2009 through

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September 30, 2009. The aggregate intrinsic value (the amount by which the market price of the stock on the date of exercise exceeded the market price of the stock on the date of grant) of stock options exercised during the year ended December 31, 2008 was $0.4 million.

The following table sets forth the activity related to our non-vested share awards for the year ended December 31, 2010.


	Shares			Weighted- Average Grant- Date Fair Value
Non-vested share awards outstanding at December 31, 2009		21,730		$	7.67
Granted		42,735			11.70
Vested		(43,095	)		9.67

Non-vested share awards outstanding at December 31, 2010		21,370		$	11.70

The fair value of non-vested share awards equals the market value of the underlying stock on the date of grant. The weighted-average grant-date fair value of the non-vested share awards granted during the year ended December 31, 2010, the period from October 1, 2009 through December 31, 2009 and the year ended December 31, 2008 was $11.70, $7.67 and $12.50 per share, respectively. No non-vested share awards were granted during the period from January 1, 2009 through September 30, 2009. The total fair value of non-vested share awards that vested during year ended December 31, 2010, the period from October 1, 2009 through December 31, 2009, the period from January 1, 2009 through September 30, 2009 and the year ended December 31, 2008 was $0.5 million, $0.2 million, $0.1 million and $2.4 million, respectively.

The following table sets forth stock-based compensation expense and related recognized tax benefits.


	Successor Company Year ended December 31, 2010		Successor Company October 1, 2009 through December 31, 2009		Predecessor Company January 1, 2009 through September 30, 2009		Predecessor Company Year Ended December 31, 2008
	(in thousands)
Compensation Expense (Benefit):
Stock options	$	673	$	14	$	1,001	$	2,127
Non-vested share awards		500		229		2,688		4,274
Employee bonus share awards		82		174		—		—
Performance share awards		—		—		—		(293	)
Deferred Income Tax Benefit		429		150		1,328		2,199

As of December 31, 2010, $1.7 million of total unrecognized compensation expense related to outstanding stock options was expected to be recognized over a weighted-average period of 2.1 years. As of December 31, 2010, $0.1 million of total unrecognized compensation expense related to non-vested share awards was expected to be recognized over a weighted-average period of approximately five months.

We also have a 401(K) Plan that covers all employees. We match 100% of each individual participant’s contribution not to exceed 6% of the participant’s compensation. Our matching contributions were made in the Company’s common stock until 2009. During 2009, our 401(K) Plan was amended to require matching contributions to be made in cash. During the year ended December 31, 2010, the period from October 1, 2009

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

through December 31, 2009 and the period from January 1, 2009 through September 30, 2009, we made matching contributions in cash to the 401(K) Plan of approximately $0.6 million, $0.2 million and $0.5 million, respectively. During 2008, we made matching contributions to the 401(K) Plan of 266,365 shares of common stock valued at approximately $0.9 million.

Employee Retention Plans

In June 2009, we executed retention agreements with all of our non-officer, non-field employees, which called for payments of one-half of the retention amounts upon execution of the agreements and the remaining one-half upon exit from our Chapter 11 reorganization. Our field employees also received payments under this program. We also executed agreements with all of our officers (except for two executive officers who had individual change of control severance agreements with the Company) that called for payments of the entire retention amount upon exit from our Chapter 11 reorganization. During the period from January 1, 2009 through September 30, 2009, we recorded approximately $2.0 million for cash payments under these agreements. In addition, the remaining two executive officers terminated their written change of control severance agreements with the Company in exchange for receiving an unsecured claim for rejection damages in the Chapter 11 reorganization. In connection with these retention agreements, non-field employees and officers were required to waive and release the Company from any and all potential claims with respect to certain incentive and retention plans and agreements as provided for in the retention agreements. During the period from January 1 through September 30, 2009, we reduced previously established accruals totaling approximately $2.0 million for the various incentive and retention plans and agreements that were waived and released.

The Company has two plans under which, in the event of termination of employment in connection with a change of control of our company, our officers and employees are entitled to receive a multiple of their salaries and bonuses (typically up to one or two-and-one-half times such amount) and certain other benefits in a lump sum cash payment. Additionally, all options, restricted stock, restricted share units and other similar awards would become fully vested.

Other

In November 2008, we discontinued a plan that was designed to fund post-employment benefits to a limited group of key non-executive employees through whole life insurance policies, while providing life insurance coverage for the participants during the participation period. The cash surrender value of the cancelled whole life insurance policies distributed to the participants in January 2009 was $0.2 million.

(16) Commitments and Contingencies

We have operating leases for office space and equipment, which expire on various dates through 2016. Future minimum commitments as of December 31, 2010 under these operating obligations are as follows (in thousands):


2011	$	622
2012		629
2013		633
2014		616
2015		517
Thereafter		517

	$	3,534

100

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Expense relating to operating obligations for the year ended December 31, 2010, the period from October 1, 2009 through December 31, 2009, the period from January 1, 2009 through September 30, 2009 and the year ended December 31, 2008 was $1.5 million, $0.7 million, $1.9 million and $5.4 million, respectively.

We maintain restricted escrow funds in a trust for future abandonment costs at our East Bay property. The trust was originally funded with $15 million and, with accumulated interest, increased to $16.7 million at December 31, 2008. We may draw from the trust upon completion of qualifying abandonment activities at our East Bay field. At December 31, 2010, we had $8.5 million remaining in restricted escrow funds for decommissioning work in our East Bay field, $1.3 million of which was released in January 2011 and $1.2 million of which will be available for draw currently upon completion of certain decommissioning activities as that work progresses; the remaining $6.0 million will remain restricted until substantially all required decommissioning in the East Bay field is complete. Amounts on deposit in the trust account are reflected in Restricted cash on our consolidated balance sheets.

We record liabilities when we deliver production that is in excess of our interest in certain properties. In addition to these imbalances, we may, from time to time, be allocated cash sales proceeds in excess of amounts that we estimate are due to us for our interest in production. These allocations may be subject to further review, may require more information to resolve or may be in dispute. In July 2010, we were notified by a purchaser of oil production from one of our non-operated fields that we were allocated, and received sales proceeds from, more oil production than we actually sold to that purchaser. These third party misallocations may date back to 2006. The oil purchaser’s initial estimate of the oil volumes misallocated to us was approximately 74,000 barrels, which may be valued at up to $6.9 million based on information provided by the oil purchaser. We have previously recorded an amount that we believe may be payable related to a potential reallocation, which amount is reflected in Accrued expenses in the accompanying condensed consolidated balance sheets as of December 31, 2010 and 2009.

We and our oil and gas joint interest owners are subject to periodic audits of the joint interest accounts for leases in which we participate and/or operate. As a result of these joint interest audits, amounts payable or receivable by us for costs incurred or revenue distributed by the operator or by us on a lease may be adjusted, resulting in adjustments, increases or decreases, to our net costs or revenues and the related cash flows. Such adjustments may be material. When they occur, these adjustments are recorded in the current period, which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account.

As described in Notes 1 and 4, on May 1, 2009, we and certain of our subsidiaries filed for reorganization under Chapter 11.

In the ordinary course of business, we are a defendant in various other legal proceedings. We do not expect our exposure in these other proceedings, individually or in the aggregate, to have a material adverse effect on our financial position, results of operations or liquidity.

101

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(17) Interim Financial Information (Unaudited)

The following tables summarize our consolidated unaudited interim financial information for the years ended December 31, 2010 and 2009.


	Successor Company Three Months Ended
	March 31		June 30			September 30			December 31
	(In thousands, except per share data)
2010
Revenues	$	70,719	$	58,197		$	56,271		$	54,722
Costs and expenses		56,608		62,874			63,457			49,661

Income (loss) from operations		14,111		(4,677	)		(7,186	)		5,061
Net income (loss) (1)		5,116		(4,610	)		(7,846	)		(1,128	)
Earnings (loss) per share:
Basic	$	0.13	$	(0.12	)	$	(0.20	)	$	(0.03	)
Diluted		0.13		(0.12	)		(0.20	)		(0.03	)

(1)	Included in net income (loss) for the three months ended June 30 is the loss on extinguishment of debt of $5.6 million resulting from the redemption of the PIK Notes.


	Predecessor Company Three Months Ended									Successor Company Three Months Ended
	March 31 (1)			June 30			September 30			December 31
	(In thousands, except per share data)
2009
Revenues	$	42,700		$	46,076		$	46,109		$	56,750
Costs and expenses		66,804			62,625			57,964			61,273
Business interruption recovery		1,185			—			—			—

Loss from operations		(22,919	)		(16,549	)		(11,855	)		(4,523	)
Net income (loss) (2)		(31,871	)		(33,661	)		29,418			(21,012	)
Earnings (loss) per share:
Basic	$	(0.99	)	$	(1.05	)	$	0.91		$	(0.53	)
Diluted		(0.99	)		(1.05	)		0.91			(0.53	)

(1)	Costs and expenses and loss from operations exclude reorganization items totaling $0.9 million which were reclassified due to the application of ASC 852 as a result of our filing for reorganization under Chapter 11. See Note 5 for additional information regarding reorganization items.

(2)	Included in net income (loss) for the three months ended March 31, June 30, September 30 and December 31 are reorganization items totaling $0.9 million, $11.7 million, $11.6 million and $0.9 million, respectively.

(18) New Accounting Pronouncements

In December 2010, the FASB issued Accounting Standards Update No. 2010-29 (“ASU 2010-29), “Disclosure of Supplementary Pro Forma Information for Business Combinations,” to address diversity in practice about the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. ASU 2010-29 specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

during the current year had occurred as of the beginning of the comparable prior annual reporting period only. It also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments in ASU 2010-29 are effective for us prospectively for business combinations for which the acquisition date is on or after January 1, 2011.

(19) Supplemental Condensed Consolidating Financial Information

In connection with the 8.25% Notes offering described in Note 9, all of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries) (the “Guarantor Subsidiaries”) jointly, severally and unconditionally guaranteed the payment obligations under the 8.25% Notes. The following supplemental financial information sets forth, on a consolidating basis, the balance sheet, statement of operations and cash flow information for Energy Partners, Ltd. (Parent Company Only) and for the Guarantor Subsidiaries. We have not presented separate financial statements and other disclosures concerning the Guarantor Subsidiaries because management has determined that such information is not material to investors.

The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. Certain reclassifications were made to conform all of the financial information to the financial presentation on a consolidated basis. The principal eliminating entries eliminate investments in subsidiaries, intercompany balances and intercompany revenues and expenses.

103

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Supplemental Condensed Consolidating Balance Sheet

As of December 31, 2010


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	33,553		$	—		$	—		$	33,553
Accounts receivable		73,040			259			(49,768	)		23,531
Other current assets		4,508			1,674			—			6,182

Total current assets		111,101			1,933			(49,768	)		63,266
Property and equipment		512,569			206,578			—			719,147
Less accumulated depreciation, depletion and amortization		(137,284	)		(30,771	)		—			(168,055	)

Net property and equipment		375,285			175,807			—			551,092
Investment in affiliates		76,236			—			(76,236	)		—
Notes receivable, long-term		—			69,000			(69,000	)		—
Other assets		12,548			—			—			12,548

		575,170			246,740			(195,004	)		626,906

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	50,756		$	62,666		$	(49,768	)	$	63,654
Fair value of commodity derivative instruments		12,320			—			—			12,320

Total current liabilities		63,076			62,666			(49,768	)		75,974
Long-term debt		—			69,000			(69,000	)		—
Other liabilities		38,978			38,838			—			77,816

		102,054			170,504			(118,768	)		153,790
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		40			98			(98	)		40
Additional paid-in capital		502,556			84,900			(84,900	)		502,556
Retained earnings		(29,480	)		(8,765	)		8,765			(29,480	)

Total stockholders’ equity		473,116			76,236			(76,236	)		473,116

		575,170			246,740			(195,004	)		626,906

104

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Supplemental Condensed Consolidating Balance Sheet

As of December 31, 2009


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	26,745		$	—		$	—		$	26,745
Accounts receivable		48,438			—			(15,016	)		33,422
Other current assets		8,335			1,287			—			9,622

Total current assets		83,518			1,287			(15,016	)		69,789
Property and equipment		503,293			145,224			—			648,517
Less accumulated depreciation, depletion and amortization		(28,313	)		(9,222	)		—			(37,535	)

Net property and equipment		474,980			136,002			—			610,982
Investment in affiliates		80,082			—			(80,082	)		—
Notes receivable, long-term		—			69,000			(69,000	)		—
Other assets		28,457			—			—			28,457

	$	667,037		$	206,289		$	(164,098	)	$	709,228

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	47,541		$	25,174		$	(15,016	)	$	57,699
Fair value of commodity derivative instruments		10,256			—			—			10,256
Current maturities of long-term debt		18,750			—			—			18,750

Total current liabilities		76,547			25,174			(15,016	)		86,705
Long-term debt		58,590			69,000			(69,000	)		58,590
Other liabilities		51,813			32,033			—			83,846

		186,950			126,207			(84,016	)		229,141
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		40			98			(98	)		40
Additional paid-in capital		501,059			84,900			(84,900	)		501,059
Retained earnings		(21,012	)		(4,919	)		4,919			(21,012	)

Total stockholders’ equity		480,087			80,082			(80,082	)		480,087

	$	667,037		$	206,289		$	(164,098	)	$	709,228

105

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Supplemental Condensed Consolidating Statement of Operations

Year Ended December 31, 2010


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	171,176		$	68,594		$	—		$	239,770
Other		15,008			131			(15,000	)		139

		186,184			68,725			(15,000	)		239,909
Costs and expenses:
Lease operating expenses		34,004			18,361			—			52,365
Taxes, other than on earnings		681			9,452			—			10,133
Exploration expenditures, dry hole cost and impairments		28,715			3,868			—			32,583
Depreciation, depletion, amortization and accretion		89,690			27,716			—			117,406
General and administrative		17,737			15,341			(15,000	)		18,078
Other expenses		2,203			(168	)		—			2,035

Total costs and expenses		173,030			74,570			(15,000	)		232,600

Income (loss) from operations		13,154			(5,845	)		—			7,309

Other income (expense):
Interest expense, net		(9,694	)		—			—			(9,694	)
Gain (loss) on derivative instruments		(4,865	)		—			—			(4,865	)
Loss on extinguishment of debt		(5,627	)		—			—			(5,627	)
Loss from equity investments		(3,846	)		—			3,846			—

Loss before income taxes		(10,878	)		(5,845	)		3,846			(12,877	)
Income taxes		2,410			1,999			—			4,409

Net loss	$	(8,468	)	$	(3,846	)	$	3,846		$	(8,468	)

106

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Supplemental Condensed Consolidating Statement of Operations

Period From October 1, 2009 through December 31, 2009


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	42,054		$	14,654		$	—		$	56,708
Other		3,754			38			(3,750	)		42

		45,808			14,692			(3,750	)		56,750
Costs and expenses:
Lease operating expenses		7,803			5,607			—			13,410
Taxes, other than on earnings		197			1,886			—			2,083
Exploration expenditures, dry hole cost and impairments		3,574			5,393			—			8,967
Depreciation, depletion, amortization and accretion		25,947			5,525			—			31,472
General and administrative		4,415			3,872			(3,750	)		4,537
Other expenses		804			—			—			804

Total costs and expenses		42,740			22,283			(3,750	)		61,273

Income (loss) from operations		3,068			(7,591	)		—			(4,523	)

Other income (expense):
Interest expense, net		(4,319	)		—			—			(4,319	)
Gain (loss) on derivative instruments		(22,705	)		—			—			(22,705	)
Loss from equity investments		(4,919	)		—			4,919			—

Income (loss) before income taxes and reorganization items		(28,875	)		(7,591	)		4,919			(31,547	)
Reorganization items		(865	)		—			—			(865	)

Income (loss) before income taxes		(29,740	)		(7,591	)		4,919			(32,412	)
Income taxes		8,728			2,672			—			11,400

Net income (loss)	$	(21,012	)	$	(4,919	)	$	4,919		$	(21,012	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Supplemental Condensed Consolidating Statement of Operations

Period From January 1, 2009 through September 30, 2009


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	98,897		$	35,686		$	—		$	134,583
Other		11,432			120			(11,250	)		302

		110,329			35,806			(11,250	)		134,885
Costs and expenses:
Lease operating expenses		31,335			14,961			—			46,296
Taxes, other than on earnings		41			5,946			—			5,987
Exploration expenditures, dry hole cost and impairments		9,685			47			—			9,732
Depreciation, depletion, amortization and accretion		87,984			13,496			—			101,480
General and administrative		18,684			12,059			(11,250	)		19,493
Other expenses		4,403			2			—			4,405

Total costs and expenses		152,132			46,511			(11,250	)		187,393

Business interruption recovery		1,185			—			—			(1,185	)
Income (loss) from operations		(40,618	)		(10,705	)		—			(51,323	)

Other income (expense):
Interest expense, net		(17,766	)		—			—			(17,766	)
Gain (loss) on derivative instruments		2,728			—			—			2,728
Income from equity investments		315			—			(315	)		—

Income (loss) before income taxes and reorganization items		(55,341	)		(10,705	)		(315	)		(66,361	)
Reorganization items		(24,198	)		—			—			(24,198	)
Loss on discharge of debt		(2,666	)		—			—			(2,666	)
Fresh-start adjustments		46,091			11,020			—			57,111

Income (loss) before income taxes		(36,114	)		315			(315	)		(36,114	)
Income taxes		—			—			—			—

Net income (loss)	$	(36,114	)	$	315		$	(315	)	$	(36,114	)

108

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Supplemental Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2010


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	84,613		$	42,767		$	—	$	127,380
Cash flows provided by (used in) investing activities:
Property acquisitions		(623	)		—			—		(623	)
Exploration and development expenditures		(15,416	)		(42,767	)		—		(58,183	)
Other property and equipment additions		(755	)		—			—		(755	)
Decrease in restricted cash		13,658			—			—		13,658

Net cash used in investing activities		(3,136	)		(42,767	)		—		(45,903	)
Cash flows provided by (used in) financing activities:
Deferred financing costs		(181	)		—			—		(181	)
Repayments of long-term debt		(94,882	)		—			—		(94,882	)
Proceeds from long-term debt		20,394			—			—		20,394

Net cash used in financing activities		(74,669	)		—			—		(74,669	)

Net increase in cash and cash equivalents		6,808			—			—		6,808
Cash and cash equivalents at the beginning of the period		26,745			—			—		26,745

Cash and cash equivalents at the end of the period	$	33,553		$	—		$	—	$	33,553

Supplemental Condensed Consolidating Statement of Cash Flows

Period From October 1, 2009 through December 31, 2009


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	14,074		$	2,794		$	—	$	16,868
Cash flows used in investing activities:
Property acquisitions		(54	)		—			—		(54	)
Exploration and development expenditures		63			(2,794	)		—		(2,731	)
Other property and equipment additions		(23	)		—			—		(23	)

Net cash used in investing activities		(14	)		(2,794	)		—		(2,808	)

Cash flows provided by (used in) financing activities:
Repayments of long-term debt		(31,250	)		—			—		(31,250	)

Net cash used in financing activities		(31,250	)		—			—		(31,250	)

Net decrease in cash and cash equivalents		(17,190	)		—			—		(17,190	)
Cash and cash equivalents at the beginning of the period		43,935			—			—		43,935

Cash and cash equivalents at the end of the period	$	26,745		$	—		$	—	$	26,745

109

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Supplemental Condensed Consolidating Statement of Cash Flows

Period From January 1, 2009 through September 30, 2009


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	12,178		$	2,188		$	—	$	14,366
Cash flows used in investing activities:
Property acquisitions		(31	)		—			—		(31	)
Exploration and development expenditures		(27,535	)		(2,188	)		—		(29,723	)
Other property and equipment additions		(147	)		—			—		(147	)
Proceeds from the sale of oil and natural gas assets		150			—			—		150

Net cash used in investing activities		(27,563	)		(2,188	)		—		(29,751	)
Cash flows provided by (used in) financing activities:
Deferred financing costs		(798	)		—			—		(798	)
Repayments of long-term debt		(55,001	)		—			—		(55,001	)
Proceeds from long-term debt		113,128			—			—		113,128

Net cash provided by financing activities		57,329			—			—		57,329

Net decrease in cash and cash equivalents		41,944			—			—		41,944
Cash and cash equivalents at the beginning of the period		1,991			—			—		1,991

Cash and cash equivalents at the end of the period	$	43,935		$	—		$	—	$	43,935

(20) Supplementary Oil and Natural Gas Disclosures—(Unaudited)

In December 2008, the SEC issued a final rule, “Modernization of Oil and Gas Reporting,” which amended its oil and gas reserves estimation and disclosure requirements. The new requirements were codified as part of ASC 932 in January 2010, and had the effect of, among other things: permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; modifying the prices used to estimate reserves for SEC disclosure purposes to an average price based upon the prior twelve month period rather than the year-end price; allowing the optional disclosure of “probable” and “possible” reserves to investors; allowing reserves to be classified as “proved undeveloped” if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years (unless the specific circumstances justify a longer time); requiring disclosure regarding the qualifications of the chief technical person who oversees the reserves estimation process; requiring a general discussion of our internal controls used to ensure the objectivity of the reserves estimation process; and requiring that, if a third party is primarily responsible for preparing or auditing the reserve estimates, the company make disclosures relating to the independence and qualifications of the third party, including filing as an exhibit any report received from the third party. The revised rule was effective January 1, 2010 for reporting December 31, 2009 annual oil and natural gas reserve information. We adopted the provisions of the final rule in connection with the filing of our 2009 Annual Report.

Our estimates of proved reserves are based on reserve reports prepared as of December 31, 2010 by independent petroleum engineering firms Netherland, Sewell & Associates, Inc. and Ryder Scott Company, L.P. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to,

110

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

The following table sets forth our estimated net proved reserves, changes in our estimated net proved reserves and our proved developed reserves.


	Crude Oil (Mbbls)			Natural Gas (Mmcf)			Barrels of Oil Equivalent (Mboe)
Estimated Proved Reserves:
December 31, 2007		28,123			103,118			45,309
Sales of reserves in place		(265	)		(1,819	)		(568	)
Extensions, discoveries and other additions (a)		956			8,482			2,370
Revisions (b)		(5,125	)		(2,477	)		(5,538	)
Production		(2,052	)		(16,496	)		(4,802	)

December 31, 2008		21,637			90,808			36,771
Extensions, discoveries and other additions		70			2,203			437
Revisions		176			(4,765	)		(617	)
Production		(1,960	)		(20,868	)		(5,438	)

December 31, 2009		19,923			67,378			31,153
Extensions, discoveries and other additions		652			489			733
Revisions (c)		(1,016	)		8,892			466
Production		(2,336	)		(15,508	)		(4,921	)

December 31, 2010		17,223			61,251			27,431

Proved developed reserves:
December 31, 2008		17,052			79,413			30,288
December 31, 2009		15,026			57,139			24,549
December 31, 2010		15,974			56,410			25,376

(a)	Includes approximately 1.2 Mmboe associated with discoveries in Greater Bay Marchand and approximately 0.4 Mmboe associated with discoveries at our East Bay field.

(b)	Comprised of approximately 3.5 Mmboe of negative revisions associated with price decreases in both oil and natural gas and approximately 2.0 Mmboe of negative revisions associated with underperformance of wells.

(c)

Crude oil revisions and natural gas revisions include decreases of approximately 3,093 Mbbls and 7,360 Mmcf, respectively, related to PUDs aged greater than five years for which funds were not committed in our 2011 development plan. Crude oil revisions also include a net increase of approximately 2,077 Mbbls primarily related to the crude oil price increase. Natural gas revisions also include positive revisions of 26,163 Mmcf related to the inclusion of estimated fuel gas in our natural gas reserves in the December 31, 2010 reserve volumes. This change in methodology reflects fuel gas as a production cost rather than negative natural gas reserves and does not impact future net cash flows after income taxes or standardized measure of discounted future net cash flows. The positive revisions related to the one-time change in the fuel gas methodology were partially offset by decreases of 7,813 Mmcf associated with underperformance of certain wells.

111

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Capitalized costs for oil and natural gas producing activities consist of the following:


	2010			2009
	(In thousands)
Proved properties	$	687,759		$	618,508
Unproved properties		29,230			28,606
Accumulated depreciation, depletion and amortization		(167,417	)		(37,419	)

Net capitalized costs	$	549,572		$	609,695

The following table sets forth the costs incurred associated with finding, acquiring and developing our proved oil and natural gas reserves.


	Years Ended December 31,
	2010		2009		2008
	(In thousands)
Acquisitions—Proved	$	—	$	—	$	—
Acquisitions—Unproved		623		85		20,925
Exploration		31,463		2,477		56,202
Development (1)		25,643		8,815		127,948

Costs incurred	$	57,729	$	11,377	$	205,075

(1)

Expenditures incurred for exploratory dry holes are excluded from operating cash flows and included in investing activities in the consolidated statements of cash flows.

Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves

The following information has been developed utilizing procedures prescribed by ASC 932. It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating our performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of our oil and natural gas reserves or the current value of the Company.

We believe that the following factors should be taken into account in reviewing the following information: (1) future costs and sales prices are likely to differ materially from those required to be used in these calculations; (2) due to future market conditions, governmental regulations and other factors, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) the use of a 10% discount rate, while mandated under ASC 932, is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.

112

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Standardized Measure of Discounted Future Net Cash Flows uses future cash inflows estimated using oil and natural gas prices computed by applying the use of physical pricing based on the simple average of the closing price on the first day of each of the twelve months during the fiscal year (as required by ASC 932) and by applying historical adjustments, including transportation, quality differentials, and purchaser bonuses, on an individual property basis, to the year end quantities of estimated proved reserves. The historical adjustments applied to the computed prices are determined by comparing our historical realized price experience with the comparable historical market, or posted, price. These adjustments can vary significantly over time both in amount and as a percentage of the posted price, especially related to our oil prices during periods when the market price for oil varies widely. The price adjustments reflected in our computed reserve prices may not represent the amount of price adjustments we may actually obtain in the future when we sell our production. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs with the assumption of the continuation of existing economic conditions in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying period-end statutory tax rates to aggregate future net cash flows, reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% annual discount rate in computing Standardized Measure of Discounted Future Net Cash Flows is required by ASC 932.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:


	2010			2009
	(In thousands)
Future cash inflows	$	1,559,274		$	1,416,474
Future production costs(a)		(663,918	)		(543,328	)
Future development costs		(329,434	)		(338,375	)
Future income taxes		(73,446	)		(2,964	)

Future net cash flows after income taxes		492,476			531,807
10% annual discount for estimated timing of cash flows		(133,018	)		(138,005	)

Standardized measure of discounted future net cash flows	$	359,458		$	393,802

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the years ended December 31, 2010 and 2009 is as follows:


	2010			2009
	(In thousands)
Beginning of the period	$	393,802		$	416,171
Sales and transfers of oil and natural gas produced, net of production costs		(179,168	)		(133,096	)
Net changes in prices and production costs (a)		120,892			82,280
Extensions, discoveries and improved recoveries, net of future production costs		16,014			9,045
Revision of quantity estimates		11,305			(13,246	)
Previously estimated development costs incurred during the period		20,759			18,425
Changes in estimated future development costs		(7,221	)		(6,622	)
Changes in production rates (timing) and other		(5,112	)		(28,561	)
Accretion of discount		39,600			42,525
Net change in income taxes (b)		(51,413	)		6,881

Net decrease		(34,344	)		(22,369	)

End of period	$	359,458		$	393,802

113

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(a)

Our estimated future production costs reflect an increase related to the previously described one-time change in the fuel gas methodology to reflect fuel gas as a production cost rather than negative natural gas reserves in addition to an increase related to estimated reserve life due primarily to the crude oil price increase.

(b)	Our estimated future income taxes were impacted by our reorganization which resulted in a reduction in our NOLs (See Note 14, “Income Taxes”).

At December 31, 2010 and 2009, the computation of the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves was based on the following computed prices:


	2010		2009
per barrel for oil	$	77.85	$	57.70
per Mcf for natural gas	$	4.54	$	3.96

114

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

As previously reported in our Current Report on Form 8-K filed on July 1, 2010, on June 28, 2010, the Company dismissed KPMG LLP (“KPMG”) as its independent registered public accounting firm and engaged PricewaterhouseCoopers LLP as the Company’s independent registered public accounting firm. The Company’s Audit Committee recommended and approved the decision to change the Company’s independent registered public accounting firm.

None of KPMG’s reports on the Company’s consolidated financial statements for the Company’s fiscal years ended December 31, 2009 and December 31, 2008 contained any adverse opinion or disclaimer of opinion, or were qualified or modified as to uncertainty, audit scope or accounting principles, except for KPMG’s report on the Company’s consolidated financial statements as of December 31, 2008, and for the year then ended, which was modified as to uncertainty because of substantial doubt about the Company’s ability to continue as a going concern.

During the fiscal years ended December 31, 2009 and December 31, 2008 and through the date hereof, there were no disagreements between the Company and KPMG on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to KPMG’s satisfaction, would have caused KPMG to make a reference to the matter in its reports on the Company’s financial statements for such years.

During the fiscal years ended December 31, 2009 and December 31, 2008 and through the date hereof, there were no “reportable events” (as defined by Item 304(a)(1)(v) of Regulation S-K), except that, as disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, the Company identified the following material weaknesses in the Company’s internal control over financial reporting as of December 31, 2008:

•

Control Environment over Financial Reporting. The Company lacked sufficient resources and accounting expertise to perform effective supervisory reviews and monitoring activities over financial reporting matters and controls related to matters involving judgments and estimates.

•

Complex or Non-Routine Accounting Matters. The Company lacked sufficient expertise and resources within the organization to effectively identify and evaluate the financial reporting implications of complex or non-routine accounting matters, such as application of SFAS No. 143, “Accounting for Asset Retirement Obligations.”

•

Period-End Financial Reporting Process. The Company also lacked sufficient expertise and resources within the organization to ensure journal entries, both recurring and non-recurring, were accompanied by sufficient supporting documentation and were adequately reviewed and approved prior to being recorded.

As a result of the above material weaknesses, there were material errors in the Company’s asset retirement obligations and impairments, and those errors were corrected prior to the issuance of the Company’s financial statements. The Company reported no material weaknesses in its internal control over financial reporting as of December 31, 2009 in its Annual Report on Form 10-K for the year ended December 31, 2009.

KPMG furnished the Company with a letter addressed to the SEC stating that it agrees with the above statements, which letter we filed as Exhibit 16.1 to our Current Report on Form 8-K filed on July 1, 2010.

As described above, on June 28, 2010, the Company engaged PricewaterhouseCoopers LLP to serve as its independent registered public accounting firm for the fiscal year ended December 31, 2010 and to perform procedures related to the financial statements included in our Quarterly Reports of Form 10-Q, which commenced with and included the quarter ended June 30, 2010.

During the Company’s fiscal years ended December 31, 2009 and 2008 and during any subsequent interim period prior to the date of engagement of PricewaterhouseCoopers as our independent registered public accounting firm, the Company has not consulted PricewaterhouseCoopers LLP regarding any of the matters set forth in Item 304(a)(2)(i) or (ii) of Regulation S-K.

115

Item 9A.

Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are designed to ensure that information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. This information is also accumulated and communicated to management, including our principal executive officer and our principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, under the supervision and with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the most recent fiscal quarter reported on herein. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2010.

Because of their inherent limitations, disclosure controls and procedures may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that such controls and procedures may become inadequate because of changes in conditions, or that the degree of compliance with the controls or procedures may deteriorate. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives.

(b) Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with GAAP. In connection with our annual evaluation of internal control over financial reporting, our management, under the supervision and with the participation of our principal executive officer and principal financial officer, assessed the effectiveness as of December 31, 2010, of our internal control over financial reporting based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on that evaluation, our management, including our principal executive officer and principal financial officer, concluded that our internal controls over financial reporting were effective as of December 31, 2010.

Because of their inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2010. See “Report of Independent Registered Public Accounting Firm” in Part II, Item 8 of this Annual Report.

(c) Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the three months ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.

Other Information

None.

116

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

Except as set forth below, for information required by Item 10 regarding our directors and executive officers, see the definitive Proxy Statement of Energy Partners, Ltd. for the Annual Meeting of Stockholders to be held on May 19, 2011, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

Code of Ethics

We have adopted a Corporate Code of Business Conduct and Ethics that applies to all directors and employees, including our chief executive officer, chief financial officer and controller. A copy of the code is available on our website at www.eplweb.com. A copy of the code is also available, at no cost, by writing to our Corporate Secretary at 201 St. Charles Avenue, Suite 3400, New Orleans, Louisiana, 70170. We will post on our website any waiver of the code granted to any of our directors or executive officers promptly following the date of the amendment or waiver. No such waiver has ever been sought or granted.

Item 11.

Executive Compensation

For information required by Item 11, see the definitive Proxy Statement of Energy Partners, Ltd. for the Annual Meeting of Stockholders to be held on May 19, 2011, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Except as set forth below, for information required by Item 12, see the definitive Proxy Statement of Energy Partners, Ltd. for the Annual Meeting of Stockholders to be held on May 19, 2011, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

Securities Authorized for Issuance under Equity Compensation Plans

The information contained in Part II, Item 5, “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” of this Annual Report is incorporated by reference.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

For information required by Item 13, see the definitive Proxy Statement of Energy Partners, Ltd. for the Annual Meeting of Stockholders to be held on May 19, 2011, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

Item 14.

Principal Accountant Fees and Services

For information required by Item 14, see the definitive Proxy Statement of Energy Partners, Ltd. for the Annual Meeting of Stockholders to be held on May 19, 2011, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

117

PART IV

Item 15.

Exhibits and Financial Statement Schedules

(a) Documents to be filed as part of this Annual Report

1. Financial Statements

The following items are included in Part II, Item 8 this Annual Report:

•

Independent Registered Public Accounting Firms’ Reports

•

Consolidated Balance Sheets as of December 31, 2010 and 2009

•

Consolidated Statements of Operations for the year ended December 31, 2010, the period from October 1, 2009 through December 31, 2009, the period from January 1, 2009 through September 30, 2009 and the year ended December 31, 2008

•

Consolidated Statements of Changes in Stockholders’ Equity for the year ended December 31, 2010, the period from October 1, 2009 through December 31, 2009, the period from January 1, 2009 through September 30, 2009 and the year ended December 31, 2008

•

Consolidated Statements of Cash Flows for the year ended December 31, 2010, the period from October 1, 2009 through December 31, 2009, the period from January 1, 2009 through September 30, 2009 and the year ended December 31, 2008

•

Notes to the Consolidated Financial Statements

2. Financial Statement Schedules

All schedules have been omitted because the information is not required or not in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements and notes thereto.

3. Exhibits

118

EXHIBITS

The exhibits marked with the cross symbol (†) are management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

Exhibit

Number

Exhibit Description

Incorporated by
Reference

SEC File
Number

Exhibit

Filing Date

Filed/
Furnished
Herewith

Form

2.0

Second Amended Joint Plan of Reorganization of Energy Partners, Ltd. and certain of its Subsidiaries Under Chapter 11 of the Bankruptcy Code, as Modified as of July 31, 2009

8-K

001-16179

99.1

08/04/2009

3.1

Amended and Restated Certificate of Incorporation of Energy Partners, Ltd. dated as of September 21, 2009

8-A/A

001-16179

3.1

09/21/2009

3.2

Second Amended and Restated Bylaws of Energy Partners, Ltd.

8-A/A

001-16179

3.2

09/21/2009

4.1

Indenture by and among Energy Partners, Ltd., as Issuer, the Guarantors named therein and U.S. Bank National Association, as Trustee dated February 14, 2011

8-K

001-16179

4.1

02/15/2011

10.1

Registration Rights Agreement by and among Energy Partners, Ltd., the Guarantors named therein and the initial purchasers named therein dated February 14, 2011

8-K

001-16179

10.1

02/15/2011

10.2

Credit Agreement by and among Energy Partners, Ltd., as Borrower, Bank of Montreal, as Administrative Agent, and certain financial institutions, as Lenders, dated February 14, 2011

8-K

001-16179

10.2

02/15/2011

10.3

Exchange Agreement between Energy Partners, Ltd. and Mellon Investor Services LLC (operating with the service name BNY Mellon Shareowner Services), as Agent dated September 15, 2009

8-K

001-16179

10.4

09/25/2009

10.4†

Change of Control Severance Plan effective as of March 24, 2005

8-K

001-16179

10.2

03/30/2005

10.5†

First Amendment to Change of Control Severance Plan effective as of September 13, 2006

8-K

001-16179

10.3

09/14/2006

10.6†

Second Amendment to Change of Control Severance Plan effective as of April 16, 2008

8-K

001-16179

10.3

05/08/2008

10.7†

Third Amendment to Change of Control Severance Plan dated November 13, 2008

8-K

001-16179

10.2

11/14/2008

10.8†

Fourth Amendment to Change of Control Severance Plan dated November 13, 2008

10-K

001-16179

10.8

03/11/2010

119

Exhibit

Number

Exhibit Description

Incorporated by
Reference

SEC File
Number

Exhibit

Filing Date

Filed/
Furnished
Herewith

Form

10.9†

Fifth Amendment to Change of Control Severance Plan

10-Q

001-16179

10.2

08/05/2010

10.10

Term sheet with the United States Department of the Interior, Minerals Management Service dated April 30, 2009

10-K

001-16179

10.6

08/05/2009

10.11†

Employment Agreement dated as of October 1, 2009 between Energy Partners, Ltd. and Gary Hanna

8-K

001-16179

10.1

10/06/2009

10.12†

First Amendment to Employment Agreement dated as of April 12, 2010 between Energy Partners, Ltd. and Gary Hanna

10-Q

001-16179

10.3

08/05/2010

10.13†

Option Award Agreement dated as of September 30, 2009 between Energy Partners, Ltd. and Gary Hanna

8-K

001-16179

10.2

10/06/2009

10.14†

Settlement Agreement dated as of June 23, 2009 by and between Energy Partners, Ltd. and John H. Peper

10-K

001-16179

10.51

08/05/2009

10.15†

Energy Partners, Ltd. 2009 Long Term Incentive Plan

S-8

333-162185

4.5

09/29/2009

10.16†

Form of 2009 Long Term Incentive Plan Option Award Agreement

8-K

001-16179

10.5

09/25/2009

10.17†

Form of 2009 Long Term Incentive Plan Restricted Stock Agreement

8-K

001-16179

10.6

09/25/2009

10.18†

Form of Indemnification Agreement for Directors

8-K

001-16179

10.1

11/24/2009

10.19†

Form of Indemnification Agreement for Officers

8-K

001-16179

10.2

11/24/2009

10.20†

Energy Partners, Ltd. Board Compensation Program

8-K

001-16179

10.1

11/12/2009

10.21†

Second Amended and Restated Stock and Deferral Plan for Non-Employee Directors, dated as of November 6, 2009

8-K

001-16179

10.2

11/12/2009

10.22†

Form of Director Deferred Share Agreement

8-K

001-16179

10.3

11/12/2009

16.1

Letter from KPMG LLP dated July 1, 2010, addressed to the Securities and Exchange Commission

8-K

001-16179

16.1

07/01/2010

21.1

Subsidiaries of Energy Partners, Ltd.

23.1

Consent of PricewaterhouseCoopers LLP.

23.2

Consent of KPMG LLP.

23.3

Consent of Netherland, Sewell & Associates, Inc.

120

Exhibit

Number

Exhibit Description

Incorporated by
Reference

SEC File
Number

Exhibit

Filing Date

Filed/
Furnished
Herewith

Form

23.4

Consent of Ryder Scott Company, L.P.

31.1

Certification of Principal Executive Officer of Energy Partners, Ltd. pursuant to Section 302 of the Sarbanes Oxley Act of 2002.

31.2

Certification of Principal Financial Officer of Energy Partners, Ltd. pursuant to Section 302 of the Sarbanes Oxley Act of 2002.

32.1

Section 1350 Certification of Principal Executive Officer of Energy Partners, Ltd. pursuant to Section 906 of the Sarbanes Oxley Act of 2002.

32.2

Section 1350 Certification of Principal Financial Officer of Energy Partners, Ltd. pursuant to Section 906 of the Sarbanes Oxley Act of 2002.

99.1

Report of Independent Petroleum Engineers (Netherland, Sewell & Associates, Inc.) dated as of January 26, 2011

99.2

Report of Independent Petroleum Engineers (Ryder Scott Company, L.P.) dated as of January 25, 2011

99.3

Report of Independent Petroleum Engineers (Netherland, Sewell & Associates, Inc.) dated as of January 26, 2011

121

GLOSSARY OF OIL AND NATURAL GAS TERMS

“Bbl” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to oil and other liquid hydrocarbons.

“Boe” means barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

“Bcf” means one billion cubic feet.

“Bcfe” means one billion cubic feet equivalent, with one barrel of oil being equivalent to six thousand cubic feet of natural gas.

“completion” means the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“LOE” means lease operating expenditures.

“Mbbls” means one thousand barrels of oil or other liquid hydrocarbons.

“Mboe” means one thousand barrels of oil equivalent. For this purpose, six thousand cubic feet of natural gas is equal to one barrel of oil, which is based on the relative energy content of natural gas and oil.

“Mcf” means one thousand cubic feet of natural gas.

“Mmbbls” means one million barrels of oil or other liquid hydrocarbons.

“Mmboe” means one million barrels of oil equivalent.

“Mmbtu” means one million British Thermal Units.

“Mmcf” means one million cubic feet of natural gas.

“plugging and abandonment” means the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Federal regulations and regulations of many states require plugging of abandoned wells.

“proved undeveloped reserves” means proved reserves 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.

“reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“working interest” means the interest in an oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

“PV-10” means the present value of estimated future net revenues computed by applying constant prices, computed in accordance with ASC 932, based on the unweighted, arithmetic average of the closing commodity price on the first day of each of the twelve months during the fiscal year, discounted at a rate of 10% per year on a pre-tax basis.

“standardized measure” means the present value of estimated future net revenues computed by applying constant prices, computed in accordance with ASC 932, based on the unweighted, arithmetic average of the closing commodity price on the first day of each of the twelve months during the fiscal year, discounted at a rate of 10% per year on a post-tax basis.

“sidetrack” refers to directional drilling from an existing wellbore to relocate, without having to drill to the depth at which the directional drilling commences, the bottom of the well in a different productive zone that is horizontally removed from the original well.

122

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/S/ GARY C. HANNA Gary C. Hanna	Chief Executive Officer and Director	March 3, 2011

/S/ TIFFANY J. THOM Tiffany J. Thom	Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)	March 3, 2011

/S/ DAVID P. CEDRO David P. Cedro	Senior Vice President, Controller and Chief Accounting Officer (Principal Accounting Officer)	March 3, 2011

/S/ CHARLES O. BUCKNER Charles O. Buckner	Director	March 3, 2011

/S/ SCOTT A. GRIFFITHS Scott A. Griffiths	Director	March 3, 2011

/S/ MARC MCCARTHY Marc McCarthy	Director	March 3, 2011

/S/ STEVEN J. PULLY Steven J. Pully	Director	March 3, 2011

/S/ JOHN F. SCHWARZ John F. Schwarz	Director	March 3, 2011

123

INDEX TO EXHIBITS

The exhibits marked with the cross symbol (†) are management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

Exhibit

Number

Exhibit Description

Incorporated by
Reference

SEC File
Number

Exhibit

Filing Date

Filed/
Furnished
Herewith

Form

2.0

Second Amended Joint Plan of Reorganization of Energy Partners, Ltd. and certain of its Subsidiaries Under Chapter 11 of the Bankruptcy Code, as Modified as of July 31, 2009

8-K

001-16179

99.1

08/04/2009

3.1

Amended and Restated Certificate of Incorporation of Energy Partners, Ltd. dated as of September 21, 2009

8-A/A

001-16179

3.1

09/21/2009

3.2

Second Amended and Restated Bylaws of Energy Partners, Ltd.

8-A/A

001-16179

3.2

09/21/2009

4.1

Indenture by and among Energy Partners, Ltd., as Issuer, the Guarantors named therein and U.S. Bank National Association, as Trustee dated February 14, 2011

8-K

001-16179

4.1

02/15/2011

10.1

Registration Rights Agreement by and among Energy Partners, Ltd., the Guarantors named therein and the initial purchasers named therein dated February 14, 2011

8-K

001-16179

10.1

02/15/2011

10.2

Credit Agreement by and among Energy Partners, Ltd., as Borrower, Bank of Montreal, as Administrative Agent, and certain financial institutions, as Lenders, dated February 14, 2011

8-K

001-16179

10.2

02/15/2011

10.3

Exchange Agreement between Energy Partners, Ltd. and Mellon Investor Services LLC (operating with the service name BNY Mellon Shareowner Services), as Agent dated September 15, 2009

8-K

001-16179

10.4

09/25/2009

10.4†

Change of Control Severance Plan effective as of March 24, 2005

8-K

001-16179

10.2

03/30/2005

10.5†

First Amendment to Change of Control Severance Plan effective as of September 13, 2006

8-K

001-16179

10.3

09/14/2006

10.6†

Second Amendment to Change of Control Severance Plan effective as of April 16, 2008

8-K

001-16179

10.3

05/08/2008

124

Exhibit

Number

Exhibit Description

Incorporated by
Reference

SEC File
Number

Exhibit

Filing Date

Filed/
Furnished
Herewith

Form

10.7†

Third Amendment to Change of Control Severance Plan dated November 13, 2008

8-K

001-16179

10.2

11/14/2008

10.8†

Fourth Amendment to Change of Control Severance Plan dated November 13, 2008

10-K

001-16179

10.8

03/11/2010

10.9†

Fifth Amendment to Change of Control Severance Plan

10-Q

001-16179

10.2

08/05/2010

10.10

Term sheet with the United States Department of the Interior, Minerals Management Service dated April 30, 2009

10-K

001-16179

10.6

08/05/2009

10.11†

Employment Agreement dated as of October 1, 2009 between Energy Partners, Ltd. and Gary Hanna

8-K

001-16179

10.1

10/06/2009

10.12†

First Amendment to Employment Agreement dated as of April 12, 2010 between Energy Partners, Ltd. and Gary Hanna

10-Q

001-16179

10.3

08/05/2010

10.13†

Option Award Agreement dated as of September 30, 2009 between Energy Partners, Ltd. and Gary Hanna

8-K

001-16179

10.2

10/06/2009

10.14†

Settlement Agreement dated as of June 23, 2009 by and between Energy Partners, Ltd. and John H. Peper

10-K

001-16179

10.51

08/05/2009

10.15†

Energy Partners, Ltd. 2009 Long Term Incentive Plan

S-8

333-162185

4.5

09/29/2009

10.16†

Form of 2009 Long Term Incentive Plan Option Award Agreement

8-K

001-16179

10.5

09/25/2009

10.17†

Form of 2009 Long Term Incentive Plan Restricted Stock Agreement

8-K

001-16179

10.6

09/25/2009

10.18†

Form of Indemnification Agreement for Directors

8-K

001-16179

10.1

11/24/2009

10.19†

Form of Indemnification Agreement for Officers

8-K

001-16179

10.2

11/24/2009

10.20†

Energy Partners, Ltd. Board Compensation Program

8-K

001-16179

10.1

11/12/2009

10.21†

Second Amended and Restated Stock and Deferral Plan for Non-Employee Directors, dated as of November 6, 2009

8-K

001-16179

10.2

11/12/2009

125

Exhibit

Number

Exhibit Description

Incorporated by
Reference

SEC File
Number

Exhibit

Filing Date

Filed/
Furnished
Herewith

Form

10.22†

Form of Director Deferred Share Agreement

8-K

001-16179

10.3

11/12/2009

16.1

Letter from KPMG LLP dated July 1, 2010, addressed to the Securities and Exchange Commission

8-K

001-16179

16.1

07/01/2010

21.1

Subsidiaries of Energy Partners, Ltd.

23.1

Consent of PricewaterhouseCoopers LLP.

23.2

Consent of KPMG LLP.

23.3

Consent of Netherland, Sewell & Associates, Inc.

23.4

Consent of Ryder Scott Company, L.P.

31.1

Certification of Principal Executive Officer of Energy Partners, Ltd. pursuant to Section 302 of the Sarbanes Oxley Act of 2002.

31.2

Certification of Principal Financial Officer of Energy Partners, Ltd. pursuant to Section 302 of the Sarbanes Oxley Act of 2002.

32.1

Section 1350 Certification of Principal Executive Officer of Energy Partners, Ltd. pursuant to Section 906 of the Sarbanes Oxley Act of 2002.

32.2

Section 1350 Certification of Principal Financial Officer of Energy Partners, Ltd. pursuant to Section 906 of the Sarbanes Oxley Act of 2002.

99.1

Report of Independent Petroleum Engineers (Netherland, Sewell & Associates, Inc.) dated as of January 26, 2011

99.2

Report of Independent Petroleum Engineers (Ryder Scott Company, L.P.) dated as of January 25, 2011

99.3

Report of Independent Petroleum Engineers (Netherland, Sewell & Associates, Inc.) dated as of January 26, 2011

126