Edgar Filing: ENERGY PARTNERS LTD

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, 2006

¨	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 $0.01 Per Share		New York Stock Exchange
Preferred Share Purchase Rights		New York Stock Exchange

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

None

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

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 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check One)


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨

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

The aggregate market value of the common stock held by non-affiliates of the registrant at June 30, 2006 based on the closing price of such stock as quoted on the New York Stock Exchange on that date was $666,071,844.

As of February 21, 2007 there were 40,216,494 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2007 Annual Meeting of Stockholders have been incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS


		Page
PART I

Items 1 & 2.	Business and Properties	1
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	18
Item 3.	Legal Proceedings	18
Item 4.	Submission of Matters to a Vote of Security Holders	19
Item 4A.	Executive Officers of the Registrant	19

PART II

Item 5.	Market for the Registrant’s Common Stock and Related Stockholder Matters	20
Item 6.	Selected Financial Data	22
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	35
Item 8.	Financial Statements and Supplementary Data	38
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	71
Item 9A.	Controls and Procedures	71
Item 9B.	Other Information	71

PART III

Item 10.	Directors and Executive Officers of the Registrant	72
Item 11.	Executive Compensation	72
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	72
Item 13.	Certain Relationships and Related Transactions	72
Item 14.	Principal Accountant Fees and Services	72

PART IV

Item 15.	Exhibits and Financial Statement Schedules	73
Certificate of Elimination of Series D Exchangeable Convertible Preferred Stock
Subsidiaries of Energy Partners, Ltd.
Consent of KPMG LLP
Consent of Netherland, Sewell & Associates, Inc.
Consent of Ryder Scott Company, L.P.
Rule 13a-14a/15d-14a Certification of Chairman and CEO
Rule 13a-14a/15d-14a Certification of Executive VP and CFO
Section 1350 Certifications
Report of Independent Petroleum Engineers dated February 16, 2007
Report of Independent Petroleum Engineers dated February 14, 2007

FORWARD LOOKING STATEMENTS

All statements other than statements of historical fact contained in this Report on Form 10-K (“Report”) and other periodic reports filed by us under the Securities Exchange Act of 1934 and other written or oral statements made by us or on our behalf, are forward-looking statements. When used herein, the words “anticipates”, “expects”, “believes”, “goals”, “intends”, “plans”, or “projects” and similar expressions are intended to identify forward-looking statements. It is important to note that forward-looking statements are based on a number of assumptions about future events and are subject to various risks, uncertainties and other factors that may cause our actual results to differ materially from the views, beliefs and estimates expressed or implied in such forward-looking statements. We refer you specifically to the section “Risk Factors” in Item 1A of this Report. Although we believe that the assumptions on which any forward-looking statements in this Report and other periodic reports filed by us are reasonable, no assurance can be given that such assumptions will prove correct. All forward-looking statements in this Report are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this Report.

PART I

Items 1 & 2. Business and Properties

We were incorporated 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 Gulf of Mexico Shelf, the deepwater Gulf of Mexico as well as the Gulf Coast onshore region (the “Gulf of Mexico Region”). We concentrate on this core focus area because it provides us with favorable geologic and economic conditions, including multiple reservoir formations, regional economies of scale, extensive infrastructure and comprehensive geologic databases. We believe that this region offers a balanced and expansive array of existing and prospective exploration, exploitation and development opportunities in both established productive horizons and deeper geologic formations. In addition, we intend to evaluate reserve and exploratory acquisition opportunities outside of our core focus area. As of December 31, 2006, we had estimated proved reserves of approximately 170.1 Bcf of natural gas and 29.9 Mmbbls of oil, or an aggregate of approximately 58.3 Mmboe, with a standardized measure of discounted future net cash flows of $893.5 million.

We have a team of geoscientists and management professionals with considerable region-specific geological, geophysical, technical and operational experience. We have grown through a combination of exploration, exploitation and development drilling and multi-year, multi-well drill-to-earn programs, as well as strategic acquisitions of oil and natural gas fields, in the Gulf of Mexico Shelf, deepwater and the Gulf Coast onshore areas. As we have grown, we have strengthened our management team, expanded our property base, reduced our geographic concentration, and moved to a more balanced oil and natural gas reserve profile. We have also expanded our technical knowledge base through the addition of high quality personnel and geophysical and geological data.

Our common stock is traded on the New York Stock Exchange under the symbol “EPL.” We maintain a website at www.eplweb.com which contains information about us, including links to our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all related amendments. In addition, our website contains our Corporate Governance Guidelines and the charters for our Audit, Compensation and Nominating Committees. Copies of such information are also available by writing to the Secretary of the Company 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 Report on Form 10-K.

Exploration and Development Expenditures

Our exploration and development expenditures for 2006 totaled $399.3 million inclusive of a $0.4 million contingent consideration payment to former stockholders of a company acquired in 2002. For 2007, we have

budgeted exploration and development expenditures of approximately $300 million. The drilling portfolio, both onshore and offshore, includes a mixture of lower risk development and exploitation wells, moderate risk, moderate and higher potential exploration opportunities and higher risk, higher potential exploration projects. Our 2007 budget does not include any acquisitions of proved reserves that may occur during the year.

Our Properties

At December 31, 2006, we had interests in 46 producing fields, 6 fields under development and 2 properties on which drilling operations were then being conducted, all of which are located in the Gulf of Mexico Region. These fields fall into five focus areas which we identify as our Eastern, Central, Western and Deepwater offshore and Gulf Coast onshore areas. The Eastern offshore area is comprised of two producing fields, including the East Bay field. The Central offshore area is comprised of six producing fields, four of which are contiguous and cover most of the Bay Marchand salt dome. The Western offshore area, which extends from areas offshore central and western Louisiana to areas offshore Texas, is comprised of 28 producing fields. The Deepwater offshore area is comprised of 24 offshore blocks. Our Gulf Coast onshore area is located in South Louisiana, with 10 producing fields. Over the last several years, we have continued to add to our leasehold acreage position in these areas through federal and state lease sales, acquisitions and trades with industry partners.

Eastern Offshore Area

East Bay is the key asset in our Eastern offshore area and is located 89 miles southeast of New Orleans near the mouth of the Mississippi River. East Bay contains producing wells located onshore along the coastline and in water depths ranging up to approximately 170 feet. East Bay is comprised primarily of the South Pass 24, 26 and 27 fields. Through a number of state and federal lease sales, we have acquired acreage that is contiguous to East Bay in several additional South Pass blocks as well as across the river in West Delta blocks. We own an average 96% interest in our acreage position in this area with our working interest ranging from 18% to 100% and our net revenue interest varying up to a maximum of 86%. Inclusive of all lease acquisitions, our leasehold area covered 35,094 gross acres (33,820 net acres) at the end of 2006. Our Eastern offshore area operations accounted for approximately 15% of our net daily production during 2006.

Central Offshore Area

The core assets of our Central offshore area, the fields located in Greater Bay Marchand, are located approximately 60 miles south of New Orleans in water depths of 181 feet or less. Our key assets in this area include the South Timbalier 26 and 41 and Bay Marchand fields as well as reserves which are currently under development in the South Timbalier 46 field. Our Central offshore area operations accounted for approximately 41% of our net daily production during 2006.

In 2003, we drilled our initial discovery well in South Timbalier 41 field on acreage acquired earlier that year in a federal lease sale. Five follow up exploratory wells and one development well have been drilled in the field and all have been successful. All of these wells have been brought on production. This field, in which additional reserve potential remains to be tested, represents the most significant discovery in our history. We acquired acreage in eight additional leases in the vicinity of this field in the March 2005 federal lease sale.

In addition, we owned a 50% interest in the South Timbalier 26 field at the beginning of 2005. In March 2005, we closed the acquisition of the remaining 50% interest in South Timbalier 26 above approximately 13,000 feet subsea for approximately $19.6 million after closing adjustments. As a result of the acquisition, we now own a 100% interest in the producing horizons in this field. The acquisition expanded our interest in our core Greater Bay Marchand area and gave us additional flexibility in undertaking the future development of the South Timbalier 26 field. We have interests in 14 producing wells in this field.

Western Offshore Area

The properties in the Western offshore area are located in water depths ranging from 7 to 371 feet with working interests ranging from 17% to 100%. We owned interests in 31 fields in this area at December 31, 2006, 28 of which were producing fields with another 3 under development. Our Western offshore area operations accounted for approximately 26% of our net daily production during 2006.

Deepwater Offshore Area

We have a 25% working interest in each of our properties in the Deepwater offshore area. We owned interests in 24 blocks in this area at December 31, 2006, one of which was under development and two of which were under evaluation at year end. We have several additional prospects identified on our current deepwater acreage and plan to generate prospects and bid on deepwater leases at future Gulf of Mexico lease sales in order to expand our portfolio of drilling opportunities in the area.

Gulf Coast Onshore Area

In 2005, we closed an acquisition of properties and reserves onshore in south Louisiana for $149.6 million in cash, after adjustments for the exercise of preferential rights by third parties and closing adjustments. The properties acquired included nine fields, four of which were producing at the time of the closing through 14 wells. The properties in the Gulf Coast onshore area are located in south Louisiana with working interests ranging from 8% to 100%. We owned interests in ten producing fields in this area and one property on which operations were being conducted at December 31, 2006 in this area. Our Gulf Coast onshore area operations accounted for approximately 18% of our net daily production during 2006.

Oil and Natural Gas Reserves

The following table presents our estimated net proved oil and natural gas reserves and the present value of our reserves at December 31, 2006, 2005 and 2004. The December 31, 2006, 2005 and 2004 estimates of proved reserves are based on reserve reports prepared by Netherland, Sewell & Associates, Inc. and Ryder Scott Company, L.P., independent petroleum engineers. Neither the present values, discounted at 10% per annum, of estimated future net cash flows before income taxes, or the standardized measure of discounted future net cash flows shown in the table are intended to represent the current market value of the estimated oil and natural gas reserves we own.


	As of December 31,
	2006		2005		2004
Total estimated net proved reserves(1):
Oil (Mbbls)		29,914		31,478		28,770
Natural gas (Mmcf)		170,123		166,949		149,835
Total (Mboe)		58,268		59,303		53,743
Net proved developed reserves(2):
Oil (Mbbls)		24,811		25,656		24,737
Natural gas (Mmcf)		117,392		103,627		102,760
Total (Mboe)		44,376		42,917		41,864
Estimated future net revenues before income taxes (in thousands)(3)	$	1,632,470	$	2,531,166	$	1,271,083
Present value of estimated future net revenues before income taxes (in thousands)(3) (4)	$	1,188,295	$	1,806,185	$	924,135
Standardized measure of discounted future net cash flows (in thousands)(5)	$	893,474	$	1,261,246	$	667,668

(1)	Approximately 68% of our total proved reserves were proved undeveloped and proved developed non-producing at December 31, 2006.

(2)	Net proved developed non-producing reserves as of December 31, 2006 were 14,017 Mbbls and 71,071 Mmcf.

(3)

The December 31, 2006 amount was calculated using a period-end oil price of $58.40 per barrel and a period-end natural gas price of $5.54 per Mcf, while the December 31, 2005 amount was calculated using a period-end oil price of $57.81 per barrel and a period-end natural gas price of $10.31 per Mcf and the December 31, 2004 amount was calculated using a period-end oil price of $41.84 per barrel and a period-end natural gas price of $6.23 per Mcf.

The Company believes estimated future net revenues before income taxes and present value of estimated future net revenues before income taxes to be important measures for evaluating the relative significance of its natural gas and oil properties. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of pre-tax measures provide greater comparability of assets when evaluating companies.

(4)	The present value of estimated future net revenues attributable to our reserves was prepared using constant prices, as of the calculation date, discounted at 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 tax discounted at 10%.

Costs Incurred in Oil and Natural Gas Activities

The following table sets forth certain information regarding the costs incurred that are associated with finding, acquiring, and developing our proved oil and natural gas reserves:


	Years Ended December 31,
	2006		2005		2004
	(In thousands)
Acquisitions	$	16,316	$	198,980	$	8,717
Exploration		224,147		171,859		113,278
Development(1)		167,346		114,814		75,732

Costs incurred	$	407,809	$	485,653	$	197,727

(1)	Includes asset retirement obligations incurred of $8.5 million, $6.9 million and $3.5 million for the years ended December 31, 2006, 2005 and 2004, respectively.

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, 2006:


	Total Productive Wells
	Gross	Net
Oil	269	205
Natural gas	148	71

Total	417	276

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 six gross oil wells and twelve gross natural gas wells have dual completions.

Acreage

The following table sets forth information as of December 31, 2006 relating to acreage held by us. Developed acreage is assigned to producing wells.


	Gross Acreage	Net Acreage
Developed:
Eastern offshore area	30,952	29,678
Central offshore area	33,840	19,206
Western offshore area	142,074	88,645
Deepwater offshore area	5,760	1,440
Gulf Coast onshore area	6,880	2,769

Total	219,506	141,738

Undeveloped:
Eastern offshore area	4,142	4,142
Central offshore area	48,837	45,477
Western offshore area	192,144	151,323
Deepwater offshore area	128,880	32,220
Gulf Coast onshore area	13,935	4,593

Total	387,938	237,755

Leases covering 5% of our undeveloped net acreage will expire in 2007, 9% in 2008, 14% in 2009, 42% in 2010, 29% in 2011 and 1% thereafter.

Well Activity

The following table shows our well activity for the years ended December 31, 2006, 2005 and 2004. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest in these wells.


	Years Ended December 31,
	2006		2005		2004
	Gross	Net	Gross	Net	Gross	Net
Development Wells:
Productive	3.0	1.7	8.0	4.7	5.0	3.2
Non-productive	—	—	3.0	1.1	2.0	2.0

Total	3.0	1.7	11.0	5.8	7.0	5.2

Exploration Wells:
Productive	17.0	8.7	30.0	15.3	19.0	12.3
Non-productive	6.0	2.7	17.0	9.3	5.0	2.2

Total	23.0	11.4	47.0	24.6	24.0	14.5

Well activity refers to the number of wells completed at any time during the fiscal years, regardless of when drilling was initiated. For the purpose of this table, “completed” refers to the installation of permanent equipment for the production of oil or natural gas.

Title to Properties

Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements, mechanics’ and materialman 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 in the operation of our business.

We believe that we have satisfactory title to, or rights in, all of our producing 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

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, as amended (“NGA”), the Natural Gas Policy Act of 1978, as amended (“NGPA”), and regulations promulgated thereunder by the Federal Energy Regulatory Commission (“FERC”) and its predecessors. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of wellhead natural gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, as amended (the “Decontrol Act”). The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. While sales by producers of natural gas can currently be made at unregulated market prices, Congress could reenact price controls in the future.

Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued Order No. 636 and a series of related orders (collectively, “Order No. 636”) to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders (collectively, “Order No. 637”), which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 have been upheld on judicial review, and most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.

The Outer Continental Shelf Lands Act (“OCSLA”) requires that all pipelines operating on or across the outer continental shelf (“OCS”) provide open access, non-discriminatory transportation service. Previously the FERC enforced this provision pursuant to its authority under both the NGA and the OCSLA. One of FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers on the OCS with greater assurance of open access service on pipelines located on the OCS and non-discriminatory rates and conditions of service on such pipelines. In 2003, the courts determined that the

FERC had only limited authority to enforce its open access rules on the OCS and decided, instead, that such authority primarily rested with others, including the Department of the Interior. The U.S. Minerals Management Service (“MMS”), within the Department of the Interior, has jurisdiction under OCSLA to ensure that all shippers seeking service on OCS pipelines transporting oil or gas pursuant to MMS-granted easements or rights-of-way receive open and non-discriminatory access to such transportation. In furtherance of this mandate, MMS has initiated a rulemaking to consider whether to amend its regulations to better ensure such access for OCS shippers.

It should be noted that FERC has pending a rulemaking to consider whether to reformulate its test for defining non-jurisdictional gathering in the shallow waters of the OCS and, if so, what form that new test should take. The stated purpose of this initiative is to devise an objective test that furthers the goals of the NGA by protecting producers from the unregulated market power of third-party transporters of gas, while providing incentives for investment in production, gathering and transportation infrastructure offshore. While we cannot predict whether FERC’s gathering test ultimately will be revised and, if so, what form such revised test will take, any test that refunctionalizes as FERC-jurisdictional transmission facilities currently classified as gathering would impose an increased regulatory burden on the owner of those facilities by subjecting the facilities to NGA certificate and abandonment requirements and rate regulation.

We cannot accurately predict whether FERC’s (or MMS’s) actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts. For example, the Federal Energy Policy Act, signed into law in August 2005, contains various provisions designed to increase the level of competition and transparency in FERC-regulated natural gas markets (e.g. one such provision, recently implemented by FERC in its regulations, makes market-based rate authority generally available to new interstate natural gas storage facilities), those provisions are now in various stages of implementation by FERC. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is materially different from the effect of such regulation on our competitors.

Regulation of Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is materially different from the effect of such regulation on our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Our subsidiary, EPL Pipeline, L.L.C., owns an approximately 12-mile oil pipeline, which transports oil produced from South Timbalier 26 and a portion of South Timbalier 41 on the Gulf of Mexico OCS to Bayou Fourchon, Louisiana. Production transported on this pipeline includes oil produced by us from South Timbalier 26 and by us and our working interest partner in South Timbalier 41. EPL Pipeline, L.L.C. has on file with the Louisiana Public Service Commission and FERC tariffs for this transportation service and offers non-discriminatory transportation for any willing shipper.

Regulation of Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling and plugging and abandonment surety bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and the plugging and abandonment of wells. Many states also have regulations restricting production to the market demand for oil and natural gas. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Some of our offshore operations are conducted on federal leases that are administered by MMS and are required to comply with the regulations and orders promulgated by MMS under OCSLA. Among other things, we are required to obtain prior MMS approval for any exploration plans we pursue and our development and production plans for these leases. MMS regulations also establish construction requirements for production facilities located on our federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Under limited circumstances, MMS could require us to suspend or terminate our operations on a federal lease.

MMS also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and natural gas leases. The basis for royalty payments established by MMS and the state regulatory authorities is generally applicable to all federal and state oil and natural gas lessees. Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.

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.

Environmental Regulations

General. Various federal, state and local laws and regulations governing the protection of the environment, such as the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), 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 legislation. These laws and regulations:

•

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

•

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

•

impose substantial liabilities for pollution resulting from our operations.

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. Changes in environmental laws and regulations occur regularly, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those in the oil and natural gas industry in general. 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, there is no assurance that this trend will continue in the future.

As with the industry generally, compliance with existing regulations increases our overall cost of business. The areas affected include:

•

unit production expenses primarily related to the control and limitation of air emissions and the disposal of produced water;

•

capital costs to drill exploration and development wells primarily related to the management and disposal of drilling fluids and other oil and natural gas exploration wastes; and

•

capital costs to construct, maintain and upgrade equipment and facilities.

Superfund. CERCLA, also known as “Superfund,” imposes liability for response costs and damages to natural resources, without regard to fault or the legality of the original act, on some classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” or “operator” of a disposal site 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 hazardous substances released into the environment. In the course of our ordinary operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance.” We may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed.

We 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 our predecessors have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes 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. In addition, many of these properties have been operated by third parties whose actions with respect to the treatment and disposal or release of hydrocarbons or other wastes were not under our control. These properties and wastes disposed on these properties may be subject to CERCLA and analogous state laws. Under these laws, we could be required:

•

to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators;

•

to clean up contaminated property, including contaminated groundwater; or

•

to perform remedial operations to prevent future contamination.

At this time, we do not believe that we are associated with any Superfund site and we have not been notified of any claim, liability or damages under CERCLA.

Oil Pollution Act of 1990. The Oil Pollution Act of 1990, as amended (the “OPA”) and regulations thereunder impose liability on “responsible parties” for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. Liability under OPA is strict, and under certain circumstances joint and several, and potentially unlimited. 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. The OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to 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. We are not aware 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.

U.S. Environmental Protection Agency. U.S. Environmental Protection Agency regulations address the disposal of oil and natural gas operational wastes under three federal acts more fully discussed in the paragraphs that follow. The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), provides a framework for the safe disposal of discarded materials and the management of solid and hazardous wastes. The direct disposal of operational wastes into offshore waters is also limited under the authority of the Clean Water Act. When injected underground, oil and natural gas wastes are regulated by the Underground Injection Control program under Safe Drinking Water Act. If wastes are classified as hazardous, they must be properly transported, using a uniform hazardous waste manifest, documented, and disposed at an approved hazardous waste facility. We have coverage under the Clean Water Act permitting requirements for discharges associated with exploration and development activities. We take the necessary steps to ensure all offshore discharges associated with a proposed operation, including produced waters, will be conducted in accordance with such requirements.

Resource Conservation Recovery Act. RCRA, is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. 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 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 produced waters and other wastes into navigable 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 developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. 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. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. The Safe Drinking Water Act of 1974, as amended establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. 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. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. 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 abide by 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.

Marine Mammal and Endangered Species. Federal Lease Stipulations Executive Order 13158 (Marine Protected Areas) address the protection of marine areas and the reduction of potential taking of protected marine species (sea turtles, marine mammals, Gulf Sturgen and other listed marine species). MMS permit approvals will be conditioned on collection and removal of debris resulting from activities related to exploration, development and production of offshore leases. MMS has issued Notices to Lessees and Operators (“NTL”) 2003-G06 advising of requirements for posting of signs in prominent places on all vessels and structures and of an observing training program.

Consideration of Environmental Issues in Connection with Governmental Approvals. Our operations frequently require licenses, permits and/or other governmental approvals. Several federal statutes, including OCSLA, the National Environmental Policy Act (“NEPA”), and the Coastal Zone Management Act (“CZMA”) require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. OCSLA, for instance, requires the U.S. Department of Interior (“DOI”) to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment. Similarly, NEPA requires DOI and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement. CZMA, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and natural gas development. In obtaining various approvals from the DOI, we must certify that we will conduct our activities in a manner consistent with an applicable program.

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 might also require us to institute certain administrative and/or engineering controls required by the Occupational Safety and Health Act and MMS to ensure worker safety during paint removal.

Air Pollution Control. The Clean Air Act and state air pollution laws adopted to fulfill its mandates provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. Air emissions associated with offshore activities are projected using a matrix and formula supplied by MMS, which has primacy from the Environmental Protection Agency for regulating such emissions.

Naturally Occurring Radioactive Materials (“NORM”). NORM are materials not covered by the Atomic Energy Act, 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 established by the State of Louisiana or the State of Texas, as applicable.

Abandonment Costs. One of the responsibilities of owning and operating oil and natural gas properties is paying for the cost of abandonment. Companies are required to reflect abandonment costs as a liability on their balance sheets in the period in which it is incurred. We may incur significant abandonment costs in the future which could adversely affect our financial results.

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. The oil production from the East Bay field is sold under a contract with Shell Trading (US) Company (“Shell”). The contract has a 60 day cancellation provision and can be terminated by either party. In the event that the contract is cancelled by us, Shell has the right through 2007 to match any other offers we receive for the purchase of this oil production. Our oil, condensate and natural gas production is sold to a variety of purchasers, which has historically been 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 2006, Louis Dreyfus Energy Services, L.P. accounted for approximately 28%, Shell 19%, Conoco Phillips 12% and Chevron Texaco Exploration & Production Company 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 operation although a temporary disruption in production revenues could occur.

Employees

As of December 31, 2006, we had 179 full-time employees, including 45 geoscientists, engineers and technicians and 73 field personnel. Our employees are not represented by any labor union. We consider relations with our employees to be satisfactory and we have never experienced a work stoppage or strike.

Item 1A. Risk Factors

Risks Relating to the Oil and Natural Gas Industry

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 budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling activity, including the following:

•

pressure or irregularities in geological formations;

•

shortages of or delays in obtaining equipment and qualified personnel;

•

equipment failures or accidents;

•

adverse weather conditions, such as hurricanes and tropical storms;

•

reductions in oil and natural gas prices;

•

title problems;

•

limitations in the market for oil and natural gas; and

•

cost of services to drill wells.

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:

•

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;

•

abnormally pressured formations;

•

mechanical difficulties;

•

fires and explosions;

•

personal injuries and death; and

•

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

Offshore operations are also subject to a variety of operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes, tropical storms or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company. We maintain insurance at levels that we believe are consistent with industry practices and our particular needs, but we are not fully insured against all risks. We may elect not to obtain insurance for certain risks or to limit levels of coverage if we believe that the cost of available insurance is excessive relative to the risks involved. In this regard, the cost of available coverage has increased significantly as a result of losses experienced by third-party insurers in the 2005 hurricane season in the Gulf of Mexico, in particular those resulting from Hurricanes Katrina and Rita. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect our cash flow and net income and could reduce or eliminate the funds available for exploration, exploitation and acquisitions or result in loss of equipment and properties.

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure requirements and financial commitments.

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, cash flow, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, 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. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include:

•

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

•

domestic natural gas supply, demand and inventories;

•

the actions of the Organization of Petroleum Exporting Countries, or OPEC;

•

the price and quantity of foreign imports of oil;

•

the price and availability of liquefied natural gas imports;

•

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

•

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;

•

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

•

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

•

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

•

technological advances affecting energy consumption; and

•

the price and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity, ability to finance planned capital expenditures or ability to pursue acquisitions. Further, oil prices and natural gas prices do not necessarily move together.

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 present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires 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 shown in this Report.

In order to assist in the preparation of our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of these data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates.

It cannot be assumed that the present value of future net revenues from our proved reserves referred to in this Report is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present-value estimate.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could harm our business. We may be required to shut in wells for lack of a market or because of inadequacy or unavailability of oil or natural gas pipeline or gathering system capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver to market.

Risks Relating to Energy Partners, Ltd.

A significant part of the value of our production and reserves is concentrated in two areas. Because of this concentration, any production problems or inaccuracies in reserve estimates related to these areas could impact our business adversely.

During 2006, 41% of our net daily production came from our Greater Bay Marchand area and approximately 42% of our proved reserves were located in the fields that comprise this area. In addition, 15% of our net daily production came from our East Bay field and approximately 30% of our proved reserves were located on this property. If mechanical problems, storms or other events were to curtail a substantial portion of this production, our cash flow could be affected adversely. If the actual reserves associated with these properties are less than our estimated reserves, our business, financial condition or results of operations could be adversely affected.

Relatively short production life for Gulf of Mexico and Gulf Coast onshore region properties 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 production rates generally result in recovery of a relatively higher percentage of reserves from properties during the initial few years of production. All of our operations are presently in the Gulf of Mexico and Gulf Coast onshore regions. Production from reservoirs in the Gulf of Mexico region generally declines more rapidly than from reservoirs in many other producing regions of the world. As of December 31, 2006, our independent petroleum engineers estimate, on average, 67% of our total proved reserves will be produced within 5 years. As a result, our reserve replacement needs from new investments are relatively greater than those of producers who recover lower percentages of their reserves over a similar time period, such as producers who have a portion of their reserves outside the Gulf of Mexico Region. We may not be able to develop, exploit, find or acquire additional reserves to sustain our current production levels or to grow. There can be no assurance that we will be able to grow production at rates we have experienced in the past. Our future oil and natural gas reserves and production, and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.

Rapid growth may place significant demands on our resources.

We have experienced rapid growth in our operations and expect that expansion of our operations will continue. Our rapid growth has placed, and our anticipated future growth will continue to place, a significant demand on our managerial, operational and financial resources due to:

•

the need to manage relationships with various strategic partners and other third parties;

•

difficulties in hiring and retaining skilled personnel necessary to support our business;

•

complexities in integrating acquired businesses and personnel;

•

the need to train and manage our employee base; and

•

pressures for the continued development of our financial and information technology management systems.

If we have not made adequate allowances for the costs and risks associated with these demands or if our systems, procedures or controls are not adequate to support our operations, our business could be harmed.

Properties that we buy may not produce as projected, and we may be unable to fully identify liabilities associated with the properties or obtain protection from sellers against them.

Our strategy includes acquisitions. The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including:

•

the amount of recoverable reserves and the rates at which those reserves will be produced;

•

future oil and natural gas prices;

•

estimates of operating costs;

•

estimates of future development costs;

•

estimates of the costs and timing of plugging and abandonment; and

•

potential environmental and other liabilities.

Our assessments will not reveal all existing or potential problems, nor will they permit us to become familiar enough with the properties to evaluate fully their deficiencies and capabilities. In the course of our due diligence, we may not inspect every well, platform or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline corrosion or groundwater contamination, when an inspection is conducted. We may not be able to 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.

Substantial acquisitions, development programs or other transactions could require significant external capital and could change our risk and property profile.

In order to finance acquisitions of additional producing properties or finance the development of any discoveries made through any expanded exploratory program that might be undertaken, we may need to alter or increase our capitalization substantially through the issuance of additional debt or equity securities, the sale of production payments or other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for any such transactions or to obtain additional external funding on terms acceptable to us.

The unavailability or high cost 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 within our budget.

All of our operations are in the Gulf of Mexico and Gulf Coast onshore regions. Shortages and the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploration and development plans, which could have a material adverse effect on our business, financial condition or results of operations. 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. We cannot offer assurance that costs will not continue to increase again or that necessary equipment and services will be available to us at economical prices.

Our stockholder rights plan and provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

The existence of some provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock. The provisions in our certificate of incorporation and bylaws that could delay or prevent an unsolicited change in control of our company include:

•

the board of directors’ ability to issue shares of preferred stock and determine the terms of the preferred stock without approval of common stockholders; and

•

a prohibition on the right of stockholders to call meetings and a limitation on the right of stockholders to present proposals or make nominations at stockholder meetings.

In addition, we have a stockholder rights plan that may have the effect of discouraging unsolicited takeover proposals. The rights issued under the shareholder rights plan would cause substantial dilution to a person or group which attempts to acquire us on terms not approved in advance by our board of directors.

In addition, Delaware law imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.

No assurances regarding our company’s exploration of strategic alternatives

On October 12, 2006, we announced that our board of directors had directed management, together with our financial advisors, to explore strategic alternatives to maximize stockholder value, including the possible sale of our company. We make no assurances as to whether we will be able to consummate any such alternative. In addition, the exploration of strategic alternatives will involve expense and will require significant time from management that might otherwise have been spent on operating the business.

The loss of key personnel could adversely affect us.

To a large extent, we depend on the services of our chairman and chief executive officer, Richard A. Bachmann, our president and chief operating officer, Phillip A. Gobe, and other senior management personnel. The loss of the services of Messrs. Bachmann or Gobe or other senior management personnel could have an adverse effect on our operations. We do not maintain any insurance against the loss of any of these individuals.

The exploration and production business is highly competitive, and our success will depend largely on our ability to attract and retain experienced geoscientists and other professional staff.

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 and Gulf Coast onshore 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. We cannot make assurances 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 future revenues and growth may be diminished or restricted.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

On August 28, 2006, Woodside Petroleum, Ltd. (“Woodside”) commenced an action against the Company, the Company’s directors, and Stone Energy Corporation (“Stone”) in the Delaware Court of Chancery for New Castle County (the Delaware Court) styled as ATS, Inc. v. Bachmann et al., C.A. No. 2374-N (the Woodside Litigation). As amended on October 20, 2006, the Woodside complaint alleged that the termination fee provisions in the agreement and plan of merger (the “Merger Agreement”) with Stone were invalid under Delaware law and that the fee the Company paid Stone in connection with the termination of the Merger Agreement and Stone’s termination of its merger agreement with Plains Exploration and Production Company (“Plains”) constituted an invalid penalty under Delaware law. Woodside also alleged that the EPL directors breached their fiduciary duties by agreeing to the termination fee provisions in the Merger Agreement and the fees paid to Stone. Woodside asserted that, absent the invalidation of the termination fee payments, the Company’s shareholders will be unable to make a fully informed choice as to whether to accept the Tender Offer. Woodside sought declaratory and injunctive relief.

On September 12, 2006, Thomas Farrington, a purported stockholder of the Company, filed a putative class action suit against the Company, all of the Company’s directors, EPL Acquisition Corp. LLC, and Stone in the Delaware Court (the Farrington Action). As amended on October 19, 2006, the complaint in the Farrington Action alleges that the Company’s directors breached their fiduciary duties by agreeing to the termination fee provisions in the Merger Agreement, adopting the sixth-month stockholders rights agreement, amending and extending coverage to all full time employees of its change of control severance arrangements, and paying a fee to Stone in connection with the termination of the Merger Agreement. Farrington also alleges that the Company’s directors have failed to adequately disclose material information relevant to the Company stockholders’ decision whether to accept the Tender Offer. Farrington seeks declaratory and injunctive relief as well as unspecified damages.

On October 19, 2006, the Delaware Court denied motions filed by Woodside and Farrington seeking expedited consideration of these claims. The Company and the individual defendants believe the claims are without merit and intend to defend vigorously against those claims.

On October 26, 2006, Woodside dismissed its legal action without prejudice.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 4A. Executive Officers of the Registrant

The following table sets forth certain information regarding our executive officers:


Name	Age	Position
Richard A. Bachmann	62	Chairman and Chief Executive Officer
Phillip A. Gobe	54	Director, President and Chief Operating Officer
Timothy R. Woodall	39	Executive Vice President and Chief Financial Officer
John H. Peper	54	Executive Vice President, General Counsel and Corporate Secretary
T. Rodney Dykes	50	Senior Vice President—Production

Richard A. Bachmann has been chief executive officer and chairman of the board of directors since our incorporation in January 1998 and also served as our president until May 2005. Mr. Bachmann began organizing our company in February 1997. From 1995 to January 1997, he served as director, president and chief operating officer of LL&E, an independent oil and natural gas exploration company. From 1982 to 1995, Mr. Bachmann held various positions with LL&E, including director, executive vice president, chief financial officer and senior vice president of finance and administration. From 1978 to 1981, Mr. Bachmann was treasurer of Itel Corporation. Prior to 1978, Mr. Bachmann served with Exxon International, Esso Central America, Esso InterAmerica and Standard Oil of New Jersey. He also serves as a director of Trico Marine Services, Inc.

Phillip A. Gobe joined us in December 2004 as chief operating officer and was elected president in May 2005 and appointed a director in November 2005. Mr. Gobe has over 30 years of energy industry experience and was with Nuevo Energy Company as chief operating officer from February 2001 until its acquisition by Plains Exploration & Production Company in May 2004. Mr. Gobe’s primary responsibilities were managing Nuevo’s domestic and international exploitation and exploration operations. Prior to his position with Nuevo, Mr. Gobe had been the Senior Vice President of Production for Vastar Resources, Inc. since 1997. From 1976 to 1997, Mr. Gobe worked for Atlantic Richfield Company and its subsidiaries in positions of increasing responsibility, primarily in the Gulf of Mexico and Alaska.

Timothy R. Woodall joined us in August 2006 as executive vice president and chief financial officer. Mr. Woodall was most recently with UBS Investment Bank (“UBS”) from September 2004 to July 2006 serving as an Executive Director within its Global Energy Group. In addition to focusing on international energy companies, he has advised on various mergers and acquisitions (“M&A”) and capital market transactions for a number of U.S. clients including EPL. Immediately prior to his position with UBS, Mr. Woodall had been a Director of Investment Banking for Credit Suisse First Boston since 2001.

John H. Peper joined us in January 2002 as executive vice president, general counsel and corporate secretary. Prior to joining us, Mr. Peper had been senior vice president, general counsel and secretary of Hall Houston Oil Company (“HHOC”) since February 1993. Mr. Peper also served as a director of HHOC from October 1991 until we acquired HHOC in January 2002. For more than five years prior to joining HHOC, Mr. Peper was a partner in the law firm of Jackson Walker, L.L.P., where he continued to serve in an of counsel capacity through 2001.

T. Rodney Dykes joined us in April 2001 as general manager of operations and was elected vice president of operations in July 2001. He served as our vice president of exploitation for the period from March 2002 through July 2003 and was elected senior vice president—production in July 2003. Mr. Dykes has over 25 years experience in the energy industry. Immediately prior to joining us, Mr. Dykes worked as an independent consultant. From 1994 to 1999, Mr. Dykes held various positions with CMS Oil and Gas Company, including divisional operations manager, vice president of operations and vice president of business development. From 1980 to 1994, he held various technical, drilling and production management positions with Maxus Energy. Prior to 1980, Mr. Dykes was a petroleum engineer with Kerr McGee.

PART II

Item 5. Market for Registrant’s Common Stock and Related Stockholder Matters

Our common stock is listed on the New York Stock Exchange 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 New York Stock Exchange.


	High		Low
2005
First Quarter	$	27.97	$	18.38
Second Quarter		28.63		19.06
Third Quarter		32.98		22.20
Fourth Quarter		32.30		21.25
2006
First Quarter		28.68		20.62
Second Quarter		28.85		17.38
Third Quarter		25.75		16.37
Fourth Quarter		25.56		23.70
2007
First Quarter (through February 21, 2007)		24.52		20.80

On February 21, 2007 the last reported sale price of our common stock on the New York Stock Exchange was $22.33 per share.

As of February 21, 2007 there were approximately 128 holders of record of our common stock.

We have not paid any cash dividends in the past on our common stock and do not intend to pay cash dividends on our common stock in the foreseeable future. We intend to retain earnings for the future operation and development of our business. Any future cash dividends to holders of common stock would depend on future earnings, capital requirements, our financial condition and other factors determined by our board of directors.

The graph below matches our cumulative 5-year total shareholder return on common stock with the cumulative total returns of the S & P 500 index, and a customized peer group of eleven companies. The peer group includes: ATP Oil & Gas Corp., Bois d’ Arc Energy Inc, Cabot Oil & Gas Corp., Comstock Resources Inc, Denbury Resources Inc, Houston Exploration Company, Meridian Resources Corp., Newfield Exploration Company, St. Mary Land & Exploration Company, Stone Energy Corp. and W & T Offshore Inc. The graph tracks the performance of a $100 investment in our common stock, in the peer group, and the index (with the reinvestment of all dividends) from 12/31/2001 to 12/31/2006.

LOGO

* $100 invested on 12/31/01 in stock or index-including reinvestment of dividends. Fiscal year ending December 31.

12/01

12/02

12/03

12/04

12/05

12/06

Energy Partners, Ltd.

100.00

141.72

184.11

268.48

288.61

323.44

S & P 500

100.00

77.90

100.24

111.15

116.61

135.03

Peer Group

100.00

101.05

131.48

186.22

273.45

280.25

Item 6. Selected Financial Data

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


	Years Ended December 31,
	2006			2005			2004			2003			2002
	(In thousands, except per share data)
Statement of Operations Data:
Revenue	$	449,550		$	402,947		$	295,447		$	230,187		$	133,788
Income (loss) from operations(1)		(55,343	)		132,027			86,068			58,560			(6,660	)
Net income (loss)(2)		(50,400	)		73,095			46,416			33,250			(8,799	)
Net income (loss) available to common stockholders(3)		(50,400	)		72,151			43,017			29,705			(12,129	)
Basic net income (loss) per common share	$	(1.32	)	$	1.94		$	1.31		$	0.96		$	(0.44	)
Diluted net income (loss) per common share	$	(1.32	)	$	1.79		$	1.20		$	0.93		$	(0.44	)
Cash flows provided by (used in):
Operating activities	$	272,074		$	269,969		$	165,074		$	136,702		$	25,417
Investing activities		(358,780	)		(449,159	)		(176,713	)		(110,057	)		(54,380	)
Financing activities		83,131			92,442			784			77,631			29,079


	As of December 31,
	2006		2005		2004		2003		2002
	(In thousands)
Balance Sheet Data:
Total assets	$	1,003,845	$	931,285	$	647,678	$	544,181	$	384,220
Long-term debt, excluding current maturities		317,000		235,000		150,109		150,317		103,687
Stockholders’ equity		372,269		394,593		315,049		261,485		191,922
Cash dividends per common share		—		—		—		—		—

(1)	The 2006 and 2005 income from operations includes business interruption insurance recoveries of $32.9 million and $20.6 million respectively from deferred production at our covered fields resulting form Hurricanes Katrina and Rita.

(2)	The 2003 net income includes a cumulative effect of change in accounting principle resulting from the adoption of Statement 143, which increased net income $2.3 million, net of deferred income taxes of $1.3 million.

(3)	Net income (loss) available to common stockholders is computed by subtracting preferred stock dividends and accretion of discount of $0.9 million, $3.4 million, $3.5 million and $3.3 million from net income (loss) for the years ended December 31, 2005, 2004, 2003 and 2002, respectively.

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

Overview

While the impacts of Hurricanes Katrina, Rita, Cindy, Dennis and Emily (the “Tropical Weather”) were significant in 2005 and continued to affect us in 2006, we continued to make progress toward implementing our long-term growth strategy to increase our oil and natural gas reserves and production while keeping our finding

and development costs and operating costs competitive with our industry peers. We will implement this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve or resource potential and by making acquisitions, including acquisitions in our core focus area which includes the Gulf of Mexico and onshore Gulf Coast regions. We also evaluate acquisition opportunities outside of our core focus area as a complement to the drilling and development activities we have budgeted for that area. Our drilling program will contain some higher risk, higher reserve potential opportunities, moderate risk, moderate and higher reserve potential opportunities, as well as some lower risk, lower reserve potential opportunities, in order to achieve a balanced program of reserve and production growth.

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.

On June 22, 2006, we entered into the Merger Agreement with Stone, pursuant to which EPL Acquisition Corp. LLC, a wholly-owned subsidiary, would acquire all of the shares of Stone for a combination of cash and stock valued at approximately $2.1 billion. Prior to entering into the Merger Agreement, Stone terminated its then existing merger agreement with Plains on the same day. Under the terms of the terminated merger agreement between Stone and Plains, Plains was entitled to a termination fee of $43.5 million, which was advanced by us to Plains and was included in other assets in the Consolidated Balance Sheet at June 30, 2006. On August 28, 2006, Woodside announced its intention to commence a tender offer, through its U.S. subsidiary ATS Inc., for all of our outstanding shares of common stock for $23.00 per share in cash subject to, among other conditions, our stockholders voting down the proposed Stone acquisition. The tender offer was commenced on August 31, 2006 and was effective until September 28, 2006. On September 14, 2006, we announced that, on September 13, 2006, our board of directors (the “Board”) rejected as inadequate the unsolicited conditional offer by Woodside and recommended that our stockholders not tender their shares. Woodside extended its offer three times and announced on October 26, 2006 that it was extending its offer for the final time until November 17, 2006. On October 12, 2006 we announced that we had terminated the Merger Agreement with Stone and that the Board had directed us, assisted by our financial advisors, to explore strategic alternatives to maximize stockholder value, including the possible sale of our Company. In conjunction with the termination of the Merger Agreement, we paid $8.0 million to Stone, which was included in general and administrative expenses in the fourth quarter of 2006. In addition, the $43.5 million termination fee that was advanced to Plains in June 2006 on behalf of Stone was also expensed in 2006 along with other merger and strategic alternative related costs of $15.0 million. We continue to incur legal and financial advisor fees in 2007 related to the shareholder litigation as well as our exploration of strategic alternatives.

On June 2, 2006 we amended and extended to May 31, 2011 our bank credit facility and increased our borrowing base. Modifications to the bank credit facility included, among other things, the expansion of the revolving credit facility to $300 million from $200 million (subject to borrowing base limitations) and improved grid pricing for interest rate margins and commitment fees. At December 31, 2006 we had $167 million outstanding under our bank credit facility. The borrowing base, which was increased to $250 million on November 1, 2006, remains subject to redetermination based on the proved reserves of the oil and natural gas properties that serve as collateral for the bank credit facility.

On August 29, 2005 Hurricane Katrina made landfall south of New Orleans causing catastrophic damage throughout portions of the Gulf of Mexico and to portions of Alabama, Louisiana and Mississippi, including New Orleans. As a result of the devastating effects of the storm on New Orleans and surrounding areas, we announced on August 30 that we had elected to establish temporary headquarters at our Houston, Texas office.

A satellite office was also established in Baton Rouge, Louisiana. On September 24, 2005 Hurricane Rita made landfall in the United States on the Texas/Louisiana border between Sabine Pass, Texas and Johnson’s Bayou, Louisiana. This hurricane caused extensive damage throughout portions of the region, particularly to third party infrastructure such as pipelines and processing plants.

As a result of these two major hurricanes and other Tropical Weather, nearly all of our production was shut in at one time or another during the third quarter of 2005. During 2005 we maintained business interruption insurance on our significant properties, including our East Bay field. Recovery of lost revenue for our East Bay field and three other fields began accruing at various dates in 2005 as a result of the Tropical Weather and by the end of October 2006 had ceased accruing on all fields. Through December 31, 2006 we had recorded $53.5 million for business interruption recoveries of which $32.9 million and $20.6 million were recorded in the statement of operations in 2006 and fourth quarter of 2005, respectively.

On March 8, 2005, we closed the acquisition of the remaining 50% gross working interest in South Timbalier 26 above approximately 13,000 feet subsea that we did not already own for approximately $19.6 million after closing adjustments. As a result of the acquisition, we now own a 100% gross working interest in the producing horizons in this field. The acquisition expands our interest in our core Greater Bay Marchand area and has given us additional flexibility in undertaking the future development of the South Timbalier 26 field.

On January 20, 2005, we closed an acquisition of properties and reserves in south Louisiana for $149.6 million in cash, after adjustments for the exercise of preferential rights by third parties and closing adjustments. The entire purchase price was allocated to property and equipment. The terms of the acquisition did not contain any contingent consideration, options or future commitments. The acquisition was composed of nine fields, four of which were producing at the time of the closing through 14 wells. The transaction expanded the exploration opportunities in our expanded focus area and further reduced the concentration of our reserves and production. Upon the signing of the purchase agreement, we paid a $5.0 million deposit in 2004 toward the purchase price which was recorded as other assets in the year-end 2004 consolidated balance sheet. The proved reserves are in the southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.

We have included the results of operations from the acquisitions discussed above from their respective closing dates. We had experienced substantial revenue and production growth as a result of these acquisitions through the period prior to the tropical weather discussed above. For the foregoing reasons these acquisitions will affect the comparability of our historical results of operations with future periods.

On July 16, 2004, we filed a universal shelf registration statement (the “Registration Statement”) which allows us to issue an aggregate of $300 million in common stock, preferred stock, senior debt and subordinated debt in one or more separate offerings with the size, price and terms to be determined at the time of the sale. On November 10, 2004 we sold approximately 3.5 million shares of our common stock to the public pursuant to the Registration Statement. Concurrent with this offering, we entered into a stock purchase agreement with Energy Income Fund (“EIF”), an early investor in us, pursuant to which we purchased an equal number of shares of common stock owned by EIF at a price per share equal to the proceeds per share received in the offering, before expenses. We did not retain any of the proceeds from the offering and the shares are now held as treasury shares, at cost. We restored the Registration Statement to $300 million in May 2005.

In connection with the acquisition of a company in January 2002, its former preferred stockholders have the right to receive contingent consideration based upon a percentage of the amount by which the before tax net present value of proved reserves related, in general, to exploratory prospect acreage held by the acquired company as of the closing date exceeds a net present value discounted at 30%. The contingent consideration may be paid in our common stock or cash at our option (with a minimum of 20% paid in cash for each payment) and in no event will exceed a value of $50 million. Due to the uncertainty inherent in estimating the value of the contingent consideration, total final consideration will not be determined until March 1, 2007. The Company does not expect to make a contingent consideration payment in 2007. The contingent consideration paid, if any, will be capitalized as additional purchase price.

Our revenue, profitability and future growth rate depend on a number of factors beyond our control, such as tropical weather, economic, political and regulatory developments and competition from 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 and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. See “Risk Factors” in Item 1A for a more detailed discussion of these risks.

We currently have an extensive inventory of drillable prospects in-house, we are generating more internally and we are being exposed to new opportunities through relationships with industry partners. Our policy is to fund our exploration and development expenditures with internally generated cash flow, which allows us to preserve our balance sheet to finance acquisitions and other capital projects. However, from time to time, we may use our bank credit facility to fund working capital needs. We believe that the near term may provide us with further opportunities to acquire targeted properties, including those within our focus area. During 2006, we drew on our bank credit facility to fund costs associated with the termination of the merger agreement between Stone and Plains, the termination of the Merger Agreement and financial advisory and legal fees associated with the Merger Agreement and the Woodside offer and the pursuit of strategic alternatives as well as repair costs relating to the Tropical Weather pending their reimbursement under applicable insurance coverage.

Results of Operations

The following table presents information about our oil and natural gas operations.


	Years Ended December 31,
	2006			2005			2004
Net production (per day):
Oil (Bbls)		8,238			7,984			8,663
Natural gas (Mcf)		106,042			88,430			82,098
Total (Boe)		25,912			22,722			22,346
Oil & natural gas revenues (in thousands):
Oil	$	179,752		$	135,359		$	111,006
Natural gas		269,434			266,646			183,525
Total		449,186			402,005			294,531
Average sales prices, net of hedging:
Oil (per Bbl)	$	59.78		$	46.45		$	35.01
Natural gas (per Mcf)		6.96			8.26			6.11
Total (per Boe)		47.49			48.47			36.01
Impact of hedging:
Oil (per Bbl)	$	—		$	(3.15	)	$	(4.40	)
Natural gas (per Mcf)		(0.02	)		(0.24	)		(0.04	)
Average costs (per Boe):
Lease operating expense	$	6.22		$	6.08		$	4.93
Taxes, other than on earnings		1.44			1.25			1.13
Depreciation, depletion and amortization		20.95			12.00			10.86
Accretion expense		0.48			0.50			0.43
Increase in oil and natural gas revenue (net of hedging) due to:
Change in prices of oil	$	38,850		$	35,863
Change in production volumes of oil		5,543			(11,510	)
Total increase in oil sales		44,393			24,353
Change in prices of natural gas	$	(42,043	)	$	64,006
Change in production volumes of natural gas		44,831			19,115
Total increase in natural gas sales		2,788			83,121


	As of December 31,
	2006		2005		2004
Total estimated net proved reserves:
Oil (Mbbls)		29,914		31,478		28,770
Natural gas (Mmcf)		170,123		166,949		149,835
Total (Mboe)		58,268		59,303		53,743
Standardized measure of discounted future net cash flows (in thousands)	$	893,474	$	1,261,246	$	667,668

Revenues and Net Income

Our oil and natural gas revenues increased to $449.2 million in 2006 from $402.0 million in 2005. The increase in revenue for this period is primarily due to production levels restored from Tropical Weather related damage which adversely affected 2005 production., combined with increased oil prices as well as the commencement of production from new fields and additional wells in our South Timbalier 41 field. These increases were partially offset by natural reservoir declines as well as a decline in natural gas prices. Also included in 2006 income from operations was $32.9 million of business interruption insurance recoveries from deferred production at one of our fields resulting from Hurricane Katrina.

Our oil and natural gas revenues increased to $402.0 million in 2005 from $294.5 million in 2004. The increase in revenue for this period is in large part the result of sharply increased natural gas and oil prices which were driven even higher in the aftermath of Hurricanes Katrina and Rita. The increase was also attributable to increased production, despite the storms, resulting primarily from the commencement of production from 26 new wells brought on production since year end 2004, 23 of which were natural gas. In addition, our acquisitions in the first quarter of 2005 of the south Louisiana properties and the additional interest in South Timbalier 26 added incremental production compared to 2004. However, the foregoing increases were adversely impacted by an estimated 5,490 Boe per day of deferred production for the full year of 2005 from production shut-ins resulting from the Tropical Weather compared to deferred production of 597 Boe per day in 2004 from Hurricane Ivan and Tropical Storm Matthew. Also included in 2005 income from operations was $20.6 million of accrued business interruption insurance recoveries from deferred production at four of our fields resulting from Hurricanes Katrina and Rita.

We recognized a net loss of $50.4 million in 2006 compared to net income of $73.1 million in 2005. The decrease was due to impairments of $84.7 million combined with substantially higher general and administrative expenses due to the expensing of costs resulting from the termination of the merger agreement between Stone and Plains, the termination of the Merger Agreement as well as the additional legal and financial advisory costs associated with the unsolicited tender offer by Woodside to acquire all of our outstanding common stock and costs associated with our process of exploring strategic alternatives. We recognized net income of $73.1 million in 2005 compared to net income of $46.4 million in 2004. The increase was primarily a result of the increase in oil and natural gas revenue and business interruption recovery previously discussed, which was offset by our increased operating costs, as discussed below.

Operating Expenses

Operating expenses were impacted by the following:

•

Lease operating expense increased $8.4 million to $58.8 million in 2006. The increase is primarily a result of a general increase in production from new wells coming on stream in new fields, the continued increase in the cost of oilfield industry services combined with workover costs and uninsured repairs made during 2006.

Lease operating expense increased $10.1 million to $50.4 million in 2005. The increase is a result of the uninsured portion of repairs due to the Tropical Weather of $2.7 million, and was also affected by new wells coming on stream in new fields, acquisitions during the first quarter of 2005 and workovers, as well as a general increase in the cost of oilfield industry services.

•

Taxes, other than on earnings, increased $3.2 million to $13.6 million in 2006. This increase was due to the increase in oil prices during the year as well as an increase in the rate charged in 2006 compared to 2005. Taxes, other than on earnings, increased $1.1 million to $10.4 million in 2005. This increase was due to the increase in commodity prices and for the full year, production from the acreage acquired in the south Louisiana property acquisition. These taxes are expected to fluctuate from period to period depending on our production volumes from non-federal leases and the commodity prices received.

•

Exploration expenditures and dry hole costs decreased $13.2 million to $51.7 million in 2006. The decrease is primarily due to our increased success rate and the dollars expended on each exploratory well. The expense in 2006 is comprised of $37.5 million of costs for exploratory wells or portions thereof which were found to be not commercially productive and $14.2 million of seismic expenditures and delay rentals.

Exploration expenditures and dry hole costs increased $35.9 million to $64.9 million in 2005. The increase is primarily due to the increase in our exploratory drilling program from 25 exploratory wells drilled in 2004, to 45 exploratory wells drilled in 2005. The expense in 2005 is comprised of $52.0 million of costs for exploratory wells or portions thereof which were found to be not commercially productive and $12.9 million of seismic expenditures and delay rentals.

Our exploration expenditures, including dry hole charges, will vary depending on the amount of our capital budget dedicated to exploration activities and the level of success we achieve in exploratory drilling activities.

•

Impairments of properties of $84.7 million were taken during 2006. Substantially all of the expense was taken in eight fields, four of which were onshore assets acquired during an acquisition in January of 2005. Three of these onshore fields along with three offshore fields experienced downward revisions of recoverable reserves at December 31, 2006. These revisions along with decreased oil and natural gas prices resulted in impairments of $52.1 million on these assets. The Company elected to release the lease on the remaining onshore field and one other offshore field experienced mechanical difficulties; it was determined that significant capital would be needed to extend its economic life and that this capital would be better deployed to projects with more potential. The net book value of these assets of $27.0 million was therefore written off during 2006.

Impairment of properties increased $11.0 million to $17.9 million in 2005. The increase is due to impairments taken at six fields which would need significant capital to extend their economic lives. We decided to deploy the capital to projects with more potential, therefore impairing the assets. We also had two fields with partial impairments due to insufficient cash flow from reserves.

•

Depreciation, depletion and amortization increased $98.7 million to $198.2 million in 2006. The increase was primarily due to increased production volumes, a shift in the production contribution from our various fields as well as reserve revisions taken in several of our onshore properties at the end of 2005 that increased the depreciation burden from those fields on a total expense and Boe basis. Some fields carry a higher depreciation burden than others and fields in which more recent exploration and development activity has taken place reflect the effect of rising costs of oilfield industry services and capital goods; therefore, changes in the sources of our production will directly impact this expense.

Depreciation, depletion and amortization increased $10.7 million to $99.5 million in 2005. The increase was in part a result of higher production in 2005. In addition, the shift in the production contribution amongst our various fields increased our total expense as well as our expense per Boe. Some fields carry a higher depreciation burden than others, therefore, changes in the mix of our production among the various fields will directly impact this expense.

•

Other general and administrative expenses increased $76.9 million to $120.1 million in 2006. This increase was attributable to $43.5 million related to the fee advanced by us to Plains on behalf of Stone to terminate their merger agreement as well as $8.0 million we paid to Stone to terminate our Merger Agreement. Also contributing to the increase were legal and financial advisory costs of $15.0 million associated with the Merger Agreement and its subsequent termination, the unsolicited Woodside offer and the ongoing strategic alternatives process. In addition, included in this expense is stock based compensation of $10.7 million and $6.8 million in the years ended December 31, 2006 and 2005, respectively. Stock based compensation expense increased due to the adoption of the fair-value recognition provisions of Statement of Financial Standards No. 123 (R), “Share Based Payment” (“Statement 123(R”)) during 2006.

Other general and administrative expenses increased $12.2 million to $43.2 million in 2005. Included in this expense is stock based compensation of $6.8 million and $3.1 million in the years ended December 31, 2005 and 2004, respectively. The increase was due to the provision for a contractual dispute of $3.4 million as well as the costs associated with temporarily relocating our personnel and headquarters to Houston and opening a Baton Rouge office in the wake of Hurricane Katrina. Costs incurred of approximately $1.6 million included employee relocation allowances and housing, temporary office space and furniture rental as well as the purchase of computer equipment. In addition, the increase was due to increased personnel costs resulting from our overall increased level of activity and expanded asset base as well as increased cost of insurance.

Other Income and Expense

Interest expense increased $6.5 million to $24.6 million in 2006. The increase was a result of and increase in the interest rate as well as the average borrowings under our bank credit facility in the year ended December 31, 2006 compared to the same period of 2005.

Interest expense increased $3.7 million to $18.1 million in 2005. The increase was a result of interest expense on borrowings under our bank credit facility to finance acquisitions and for short-term fluctuations in working capital.

Financial Condition, Liquidity and Capital Resources

The trend of increased revenues we have experienced in 2006 has continued to provide strong cash flows from operations, which totaled $272.1 million in 2006 inclusive of merger and acquisition related costs. We intend to fund our exploration and development expenditures from internally generated cash flows, which we define as cash flows from operations before consideration of changes in working capital plus total exploration expenditures. Our cash on hand at December 31, 2006 was $3.2 million. Our future internally generated cash flows will depend on our ability to maintain and increase production through our exploration and development program, as well as the prices of oil and natural gas. We may from time to time use the availability of our bank credit facility to balance working capital needs.

Our bank credit facility, as amended on June 2, 2006, consists of a revolving line of credit with a group of banks available through May 31, 2011 (the “bank credit facility”). The borrowing base under the bank credit facility was increased in connection with this amendment and further increased November 1, 2006 to $250 million subject to redetermination based on the proved reserves of the oil and natural gas properties that serve as collateral for the bank credit facility as set out in the reserve report delivered to the banks each April 1 and October 1. The bank credit facility permits both prime rate borrowings and London interbank offered rate (“LIBOR”) borrowings plus a floating spread. The spread will float up or down based on our utilization of the bank credit facility. The spread can range from 1.00% to 1.75% above LIBOR and 0% to 0.50% above prime. The borrowing base under the bank credit facility is secured by substantially all of our assets. At February 23, 2007, we had $195 million outstanding and $55 million of credit capacity available under the bank credit facility. In addition, we pay an annual fee on the unused portion of the bank credit facility ranging between 0.30% to 0.5% based on utilization. The bank credit facility contains customary events of default and various financial covenants, which require us to: (i) maintain a minimum current ratio, as defined by our bank credit facility, of 1.0x and (ii) maintain a minimum EBITDAX to interest ratio, as defined by our bank credit facility, of 3.5x. We were in compliance with these covenants as of December 31, 2006.

On August 5, 2003, we issued $150 million of 8.75% senior notes due 2010 which were exchanged in October 2003 for registered 8.75% senior notes due 2010 (the “Registered Senior Notes”) with substantially the same terms. The Registered Senior Notes bear interest at a rate of 8.75% per annum with interest payable semi-annually on February 1 and August 1, beginning February 1, 2004. We may redeem the Senior Notes at our option, in whole or in part, at any time on or after August 1, 2007 at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium which decreases yearly from 4.375% in 2007 to 0% in 2009 and

thereafter. The notes are unsecured obligations and rank equal in right of payment to all existing and future senior debt, including the bank credit facility, and will rank senior or equal in right of payment to all existing and future subordinated indebtedness. The indenture relating to the Registered Senior Notes contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets and consolidate or merge substantially all of our assets. The Registered Senior Notes are not subject to any sinking fund requirements.

Net cash of $358.8 million used in investing activities in 2006 primarily included $341.9 million of oil and natural gas property capital and exploration expenditures and $15.9 million of lease acquisitions. Exploration expenditures incurred are excluded from operating cash flows and included in investing activities. During 2006, we completed 28 drilling projects and 35 recompletion/workover projects, 49 of which were successful and two of which are under evaluation. During 2005, we completed 56 drilling projects and 32 recompletion/workover projects, 60 of which were successful.

Our 2007 capital exploration and development budget is focused on exploration, exploitation and development activities on our proved properties combined with moderate and higher risk exploratory activities on undeveloped leases and does not include acquisitions. We continue to manage our portfolio in order to maintain an appropriate risk balance between low risk development and exploitation activities, moderate risk, moderate and higher potential exploration opportunities and higher risk, higher potential exploration opportunities. Our exploration and development budget for 2007 is currently $300 million. We do not budget for acquisitions. During 2006, capital and exploration expenditures were approximately $408.0 million inclusive of a $0.4 million contingent consideration payment resulting from an acquisition completed during 2002 and $8.5 million in asset retirement obligations. The level of our budget is based on many factors, including results of our drilling program, oil and natural gas prices, industry conditions, participation by other working interest owners and the costs of drilling rigs and other oilfield goods and services. Should actual conditions differ materially from expectations, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2007 capital expenditures.

We have experienced and expect to continue to experience substantial working capital requirements, primarily due to our active exploration and development program and merger and acquisition related fees. We believe that internally generated cash flows will be sufficient to meet our budgeted capital requirements for at least the next twelve months. Availability under the bank facility will be used to balance short-term fluctuations in working capital requirements. However, additional financing may be required in the future to fund our growth.

Disclosures about Contractual Obligations and Commercial Commitments

The following table aggregates the contractual commitments and commercial obligations that affect our financial condition and liquidity position as of December 31, 2006:


	Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		Thereafter
	Total		Less Than 1 Year		1-3 Years		3-5 Years		Thereafter
	(In thousands)
Long-term debt	$	317,000	$	—	$	—	$	317,000	$	—
Interest attributable to all long-term debt(2)		97,241		24,732		49,463		23,046		—
Operating leases		14,885		2,186		3,712		2,568		6,419
Unconditional purchase obligations(1)		90,242		89,152		1,090		—		—
Other long-term liabilities		1,453		—		—		—		1,453

Total contractual obligations	$	520,821	$	116,070	$	54,265	$	342,614	$	7,872

(1)	Consists of commitments to purchase seismic related services and drilling rig commitments as well as committed financial advisory costs associated with our strategic alternatives process.

(2)	The interest attributable to the bank credit facility was calculated using its December 31, 2006 outstanding balance and its weighted average interest rate on that date.

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.

Hedging Activities

We enter into hedging transactions with major financial institutions to reduce exposure to fluctuations in the price of oil and natural gas. We also distribute our hedging transactions to a variety of financial institutions to reduce our exposure to counterparty credit risk. Our hedging program uses financially-settled crude oil and natural gas swaps and zero-cost collars to provide floor prices with varying upside price participation. Our hedges are benchmarked to the New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude oil contracts and Henry Hub natural gas contracts. With a financially-settled swap, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price of the collar. In some hedges, we may modify our collar to provide full upside participation after a limited non-participation range. We had no crude oil positions and the following natural gas contracts as of December 31, 2006:


Natural Gas Positions
		Strike Price		Volume (Mmbtu)
Remaining Contract Term	Contract Type	($/Mmbtu)		Daily	Total
01/07 - 12/07	Collar	$	5.00/$8.00	10,000	3,650,000

Accounting and reporting standards require that derivative instruments, including certain derivative instruments embedded in other contracts, be 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 inception of the derivative. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations. For derivative instruments designated as cash-flow hedges, changes in fair value, to the extent the hedge is effective, will be recognized in other comprehensive income (a component of stockholders’ equity) until the forecasted transaction is settled, when the resulting gains and losses will be recorded in oil and natural gas revenue. Hedge ineffectiveness is measured at least quarterly based on the changes in fair value between the derivative contract and the hedged item. Any change in fair value resulting from ineffectiveness is charged currently to other revenue.

Our hedged volume as of December 31, 2006 approximated 7% of our estimated production from proved reserves through the balance of the terms of the contracts.

We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas. Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, 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. Hedging transactions may limit the benefit we would have otherwise received from increases in the prices for oil and natural gas. Furthermore, if we do not engage in hedging transactions, we may be more adversely affected by declines in oil and natural gas prices than our competitors who engage in hedging transactions.

Discussion of Critical Accounting Policies

In preparing our financial statements in accordance with accounting principles generally accepted in the United States, management must make a number of 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.

•

Successful Efforts Method of Accounting—Oil and natural gas exploration and production companies choose one of two acceptable accounting methods, successful-efforts or full cost. The most significant difference between the two methods relates to the accounting treatment of drilling costs for unsuccessful exploration wells (“dry holes”) and exploration costs. Under the successful-efforts method, we recognize exploration costs and dry hole costs as an expense on the income statement when incurred and capitalize the costs of successful exploration wells as oil and natural gas properties. Companies that follow the full cost method capitalize all drilling and exploration costs including dry hole costs into one pool of total oil and natural gas property costs.

We use the successful-efforts method because we believe that it more conservatively reflects, on our balance sheet, the historical costs that have future value. However, using successful-efforts often causes our income to fluctuate significantly between reporting periods based on our drilling success or failure during the periods.

It is typical for companies that have an active exploratory drilling program, as we do, to incur dry hole costs. During the last three years we have drilled 97 exploration wells, of which 28 were considered dry holes. Our dry hole costs charged to expense during this period totaled $110.4 million out of total exploratory drilling costs of $509.3 million. It is impossible to predict future dry holes; however we expect to continue to have dry hole costs in the future which will vary depending on the amount of our capital dedicated to exploration activities and on the level of success of our exploratory program.

•

Proved Reserve Estimates—Evaluations of oil and natural gas reserves are important to the effective management of our producing assets. They are integral to making investment decisions and are also used as a basis of calculating the units of production rates for depletion, depreciation and amortization and evaluating capitalized costs for impairment. Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.

Independent reserve engineers prepare our oil and natural gas reserve estimates using guidelines established by the U.S. Securities and Exchange Commission and U.S. generally accepted accounting principles. The quality and quantity of data, the interpretation of the data, and the accuracy of mandated economic assumptions combined with the judgment exercised by the independent reserve engineers affect the accuracy of the estimated reserves. In addition, drilling or production results after the date of the estimate may cause material revisions to the reserve estimates in subsequent periods.

At December 31, 2006, proved oil and natural gas reserves were 58.3 million barrels of oil-equivalent (“Mmboe”). Approximately 68% of our proved reserves are classified as either proved undeveloped or proved developed non-producing reserves. Most of our proved developed non-producing reserves are “behind pipe” and will be produced after depletion of another horizon in the same well. Approximately 24% of total proved reserves are categorized as proved undeveloped reserves. As of December 31, 2006, 38% of our proved undeveloped reserves were under development and expected to become proved developed within one year.

You should not assume that the present value of the future net cash flow disclosed in this report reflects the current market value of the oil and natural gas reserves. In accordance with the U.S. Securities and Exchange Commission’s guidelines, we use prices and costs determined on the date of the estimate 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 or may not be appropriate based on external economic conditions.

The computation of the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves at December 31, 2006 was based on period-end prices of $5.54 per Mcf for natural gas and $58.40 per barrel for crude after adjusting the West Texas Intermediate posted price per barrel and the Gulf Coast spot market price per Mmbtu for energy content, quality, transportation fees, and regional price differentials for each property. We estimated the costs based on the current year costs incurred for individual properties or similar properties if a particular property did not have production during the prior year.

•

Depletion, Depreciation, and Amortization of Oil and Natural Gas Properties—We calculate depletion, depreciation, and amortization expense (“DD&A”) using the estimates of proved oil and natural gas reserves previously discussed in these critical accounting policies. We segregate the costs for depletable units and record DD&A for these property costs separately using the units of production method. The units of production method is calculated as 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 applied to (3) applicable asset cost. The volumes produced and asset cost are known, and while proved developed reserves are reasonably certain, they are based on estimates that are subject to some variability. This variability can result in net upward or downward revisions of proved developed reserves in existing fields, as more information becomes available through research and production and as a result of changes in economic conditions. Our revisions in each of the years 2002 through 2004, in each case either positive or negative, had been less than 5% of total proved reserves on a barrel of oil equivalent basis, however in 2005 our negative revisions of 4,045 Mboe represented 7.5% of our total reserves. These revisions included a downward revision of 5,351 Mboe primarily related to the proved undeveloped reserves acquired in the South Louisiana onshore acquisition in January 2005. Such revisions were derived primarily from the results of actual drilling activity in 2005. In 2006 we had net positive reserve revisions of 231 Mboe. While the revisions we have made in the past are an indicator of variability, they have had a minimal impact on the units of production rates because they have been low compared to our reserve base or relate to fields just coming on production. Actual historical revisions are not necessarily indicative of future variability.

•

Impairment of Oil and Natural Gas Properties—We continually monitor our long-lived assets recorded in property and equipment in our consolidated balance sheet to make sure that they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. Because we account for our proved oil and natural gas properties separately under the successful efforts method of accounting, we assess our assets for impairment property by property rather than in one pool of total oil and natural gas property costs. A significant amount of judgment is involved in performing these evaluations since the amount is based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. 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. In general, we do not view temporarily low oil or natural gas prices as a triggering event for conducting impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop precipitously, industry prices over the long-term are driven by market supply and demand. Accordingly, any impairment tests that we perform make use of our long-term price assumptions for the crude oil and natural gas markets.

We base our assessment of possible impairment using our best estimate of future prices, costs and expected net cash flow generated by a property. We estimate future prices based on management’s expectations and escalate both the prices and the costs for inflation if appropriate. If these undiscounted estimates indicate an impairment, we measure the impairment expense as the difference between the net book value of the asset and its estimated fair value measured by discounting the future net cash flow from the property at an

appropriate rate. Actual prices, costs, discount rates, and net cash flow may vary from our estimates. An estimate as to the sensitivity to earnings resulting from impairment reviews and impairment calculations is not practicable, given the broad range in the cost structure of our oil and natural gas assets and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions may avoid the need to impair any assets, whereas unfavorable changes might cause some assets to become impaired but not others. We recognized impairment expense of $84.7 million, $17.9 million and $6.9 million in the years ending December 31, 2006, 2005 and 2004. Substantially all of the impairment expense related to eight fields during 2006, four of which were onshore assets acquired during an acquisition in January of 2005. Three of these onshore fields along with three offshore fields experienced downward revisions of recoverable reserves at December 31, 2006. These revisions along with decreased oil and natural gas prices resulted in impairments of $52.1 million on these assets. The Company elected to release the lease on the remaining onshore field and one other offshore field experienced mechanical difficulties, it was determined that significant capital would be needed to extend their economic lives and that this capital would be better deployed to projects with more potential. The net book value of these assets of $27.0 million was therefore written off during 2006. The impairment in 2005 consisted of full impairment at six fields which we determined would need significant capital to extend its economic life. We decided that the capital would be deployed to projects with more potential and therefore impaired the assets. Additionally, we had two fields with partial impairments due to insufficient cash flow from reserves. The impairment in 2004 consisted of one field which incurred significant capital costs in excess of those anticipated.

We estimate the amount of capitalized costs of unproved properties which will prove unproductive by amortizing the balance of the unproved property costs (adjusted by an anticipated rate of future successful development) over an average lease term. We will transfer the original cost of an unproved property to proved properties when we find commercial oil and natural gas reserves sufficient to justify full development of the property. If we do not find commercial oil and natural gas reserves, the related unamortized capitalized costs will be charged to earnings when the determination is made.

•

Asset retirement obligation—We have significant obligations to plug and abandon oil and natural gas wells and related equipment as well as to dismantle and abandon facilities at the end of oil and natural gas production operations. We record the fair value of a liability for an Asset Retirement Obligation (“ARO”) in the period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the ARO included in the carrying amount of the related asset are allocated to expense using the units-of-production method. In addition, accretion of the discount related to the ARO liability resulting from the passage of time is reflected as additional depreciation, depletion and amortization expense in the Consolidated Statement of Operations.

Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment will be required to be made to the oil and natural gas property balance. This adjustment may then have a positive or negative impact on the associated depreciation expense and accretion expense depending on the nature of the revision.

•

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. Our hedging transactions have to date consisted primarily of financially-settled swaps and zero-cost collars. We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas. We are required to record our derivative instruments at fair market value as either assets or liabilities in our consolidated balance sheet. The fair value recorded is an estimate based on future commodity prices available at the time of the calculation. The fair market value could 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.

Under the above critical accounting policies our net income can vary significantly from period to period because events or circumstances which trigger recognition as an expense for unsuccessful wells or impaired properties cannot be accurately forecast. In addition, selling prices for our oil and natural gas fluctuate significantly. Therefore we focus more on cash flow from operations and on controlling our finding and development, operating, administration and financing costs.

Share-Based Compensation

In the first quarter of 2006, we adopted Statement 123(R), which requires the measurement at fair value and recognition of compensation expense for all share-based payment awards. Total share-based compensation during 2006 was $11.1 million. Determining the appropriate fair-value model and calculating the fair value of employee stock options requires judgment. We use the Black-Scholes option pricing model to estimate the fair value of these share-based awards consistent with the provisions of Statement 123(R). Option pricing models, including the Black-Scholes model, also require the use of input assumptions, including expected volatility, expected life, expected dividend rate, and expected risk-free rate of return. The assumptions for expected volatility and expected life are the two assumptions that significantly affect the grant date fair value. The expected dividend rate and expected risk-free rate of return are not significant to the calculation of fair value.

We currently use historical volatility rather than implied volatility which is based on options freely traded in the open market, as the activity level for traded options was not sufficient to estimate implied volatility in 2006. We use the midpoint scenario to estimate expected term allowed by the SEC’s Staff Accounting Bulletin 107, in order to leverage as much actual exercise and post-vesting cancellation history as is available. 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 an increase to share-based compensation determined at the date of grant.

New Accounting Policies

In February 2006, the FASB issued Statement of Financial Accounting Standards No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (“Statement 155”). Among other changes, Statement 155 eliminates the exemption from applying FASB Statement No. 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. Statement 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We have assessed the impact of Statement 155 which will not have an impact on our financial position, results of operations or cash flows.

In March 2006, the FASB issued Statement of Financial Accounting Standards No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140” (“Statement 156”). Among other changes, Statement 156 requires that all separately recognized servicing assets and servicing liabilities be initially measured at fair value, if practicable. Statement 156 is effective for all fiscal years beginning after September 15, 2006. We have assessed the impact of Statement 156 which will not have an impact on our financial position, results of operations or cash flows.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”. FIN 48 prescribes 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 and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years

beginning after December 15, 2006. We are assessing the impact of FIN 48 which is not currently expected to have an impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued Statement of Accounting Standards No. 157, “Fair Value Measurements” (“Statement 157”). Statement 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. Statement 157 applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, Statement 157 does not require any new fair value measurements. However, for some entities, the application of Statement 157 will change current practice. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are assessing the impact of Statement 157 which is not currently expected to have an impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued Statement of Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“Statement 158”). Statement 158 improves financial reporting by requiring an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net assets of a not-for-profit organization. Statement 158 also improves financial reporting by requiring an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. An employer with publicly traded equity securities is required to initially recognize the funded status of a defined benefit postretirement plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. Statement 158 will not have an impact on our financial position, results of operations or cash flows.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents and the interest rate paid on borrowings under our bank facility. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. At December 31, 2006, $167 million of our long-term debt had variable interest rates while the remaining long-term debt had fixed interest expense. If the market interest rates had averaged 1% higher during 2006, interest rates for the period on variable rate debt outstanding during the period would have increased, and net income before income taxes would have decreased by approximately $1.4 million based on total variable debt outstanding during the period. If market interest rates had averaged 1% lower during 2006, interest expense for the period on variable rate debt would have decreased, and net income before income taxes would have increased by approximately $1.4 million.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially 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 the bank 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.

We use derivative instruments to manage commodity price risks associated with future oil and natural gas production. As of December 31, 2006, we had no crude oil positions and the following natural gas contracts in place:


Natural Gas Positions
	Contract Type	Strike Price		Volume (Mmbtu)
Remaining Contract Term	Contract Type	($/Mmbtu)		Daily	Total
01/07 - 12/07	Collar	$	5.00/$8.00	10,000	3,650,000

Our hedged volume as of December 31, 2006 approximated 7% of our estimated production from proved reserves through the balance of the terms of the contracts. Had these contracts been terminated at December 31, 2006, we estimate the loss would have been $1.5 million.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of crude oil and natural gas may have on fair value of our derivative instruments. At December 31, 2006 and 2005, the potential change in the fair value of commodity derivative instruments assuming a 10% increase in the underlying commodity price was a $1.1 million and $6.7 million increase in the combined estimated loss, respectively.

For purposes of calculating the hypothetical change in fair value, the relevant variables are the type of commodity (crude oil or natural gas), the commodities futures prices and volatility of commodity prices. The hypothetical fair value is calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes.

GLOSSARY OF OIL AND NATURAL GAS TERMS

“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Report in reference to oil and other liquid hydrocarbons.

“Boe” Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

“Bcf” One billion cubic feet.

“Bcfe” One billion cubic feet equivalent, with one barrel of oil being equivalent to six thousand cubic feet of natural gas.

“completion” 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.

“Mbbls” One thousand barrels of oil or other liquid hydrocarbons.

“Mboe” One thousand barrels of oil equivalent.

“Mcf” One thousand cubic feet of natural gas.

“Mmbbls” One million barrels of oil or other liquid hydrocarbons

“Mmboe” One million barrels of oil equivalent

“Mmbtu” One million British Thermal Units.

“Mmcf” One million cubic feet of natural gas.

“plugging and abandonment” Refers to 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. Regulations of many states require plugging of abandoned wells.

“proved undeveloped reserves” 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” 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” 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.

“EBITDAX” Net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, exploration expenditures and cumulative effect of change in accounting principle.

Item 8. Financial Statements and Supplementary Data

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

To the Board of Directors and Stockholders

Energy Partners, Ltd.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Our internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the reliability of financial reporting and the presentation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2006. No matter how well designed, there are inherent limitations in all systems of internal control. 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. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included herein, which expresses an unqualified opinion on management’s assessment and on the effectiveness of our internal control over financial reporting as of December 31, 2006.



Richard A. Bachmann		Timothy R. Woodall
Chairman and Chief Executive Officer		Executive Vice President and Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Energy Partners, Ltd.:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Energy Partners, Ltd. maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Energy Partners, Ltd.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.

In our opinion, management’s assessment that Energy Partners, Ltd. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Energy Partners, Ltd. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Energy Partners Ltd. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2006. In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule, “Valuation and Qualifying Accounts,” for the years ended December 31, 2006, 2005, and 2004. Our report dated February 28, 2007 expressed an unqualified opinion on those consolidated financial statements and schedule. Our report for the year ended December 31, 2006 refers to a change in the method of accounting for share-based payments.

LOGO

New Orleans, Louisiana

February 28, 2007

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Energy Partners, Ltd.:

We have audited the accompanying consolidated balance sheets of Energy Partners, Ltd. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statement of operations, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2006. In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule, “Valuation and Qualifying Accounts,” for the years ended December 31, 2006, 2005, and 2004. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits 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 audits provide 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, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the Company changed their method of accounting for share-based payments in 2006.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Energy Partners, Ltd.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

LOGO

New Orleans, Louisiana

February 28, 2007

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2006 and 2005

(In thousands, except share data)


	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	3,214		$	6,789
Trade accounts receivable		74,132			78,326
Other receivables		58,269			49,303
Deferred tax assets		1,387			5,582
Prepaid expenses		3,570			3,179

Total current assets		140,572			143,179

Property and equipment, at cost under the successful efforts method of accounting for oil and natural gas properties		1,527,304			1,189,078
Less accumulated depreciation, depletion and amortization		(680,845	)		(418,347	)

Net property and equipment		846,459			770,731

Other assets		13,029			13,284
Deferred financing costs—net of accumulated amortization of $6,302 in 2006 and $5,169 in 2005		3,785			4,091

	$	1,003,845		$	931,285

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	47,154		$	28,810
Accrued expenses		133,198			108,087
Fair value of commodity derivative instruments		1,552			9,875
Current maturities of long-term debt		—			109

Total current liabilities		181,904			146,881

Long-term debt		317,000			235,000
Deferred tax liabilities		62,451			87,559
Asset retirement obligation		68,767			56,039
Other		1,453			11,213

		631,575			536,692
Stockholders’ equity:
Preferred stock, $1 par value. Authorized 1,700,000 shares; no shares issued and outstanding		—			—
Common stock, par value $0.01 per share. Authorized 100,000,000 shares; issued and outstanding: 2006—42,501,726 shares; 2005—41,468,093 shares		425			415
Additional paid-in capital		365,313			348,863
Accumulated other comprehensive loss—net of deferred taxes of $558 in 2006 and $7,098 in 2005		(994	)		(12,619	)
Retained earnings		64,966			115,366
Treasury stock, at cost. 2006—3,479,814 shares; 2005—3,474,208 shares		(57,440	)		(57,432	)

Total stockholders’ equity		372,270			394,593

Commitments and contingencies	$	1,003,845		$	931,285

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

Years Ended December 31, 2006, 2005 and 2004

(In thousands, except per share data)


	2006			2005			2004
Revenue:
Oil and natural gas	$	449,186		$	402,005		$	294,531
Other		364			942			916

		449,550			402,947			295,447

Costs and expenses:
Lease operating		58,808			50,431			40,328
Transportation expense		2,028			1,051			289
Taxes, other than on earnings		13,632			10,372			9,263
Exploration expenditures and dry hole costs		51,745			64,937			28,999
Impairment of properties		84,680			17,907			6,936
Depreciation, depletion and amortization		198,162			99,524			88,784
Accretion expense		4,572			4,125			3,569
General and administrative		120,113			43,205			30,974
Other expense		4,022			—			237

Total costs and expenses		537,762			291,552			209,379

Business interruption recovery		32,869			20,632			—

Income from operations		(55,343	)		132,027			86,068

Other income (expense):
Interest income		1,428			781			1,219
Interest expense		(24,570	)		(18,121	)		(14,355	)

		(23,142	)		(17,340	)		(13,136	)

Income (loss) before income taxes		(78,485	)		114,687			72,932

Income taxes		28,085			(41,592	)		(26,516	)

Net income (loss)		(50,400	)		73,095			46,416

Less dividends earned on preferred stock and accretion of discount		—			(944	)		(3,399	)

Net income (loss) available to common stockholders	$	(50,400	)	$	72,151		$	43,017

Basic earnings (loss) per share	$	(1.32	)	$	1.94		$	1.31

Diluted earnings (loss) per share	$	(1.32	)	$	1.79		$	1.20

Weighted average common shares used in computing income (loss) per share:
Basic		38,313			37,097			32,861
Incremental common shares
Preferred stock		—			544			4,033
Stock options		—			852			638
Warrants		—			1,954			1,057
Restricted share units		—			257			60
Performance shares		—			55			—

Diluted		38,313			40,759			38,649

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

Years Ended December 31, 2006, 2005 and 2004

(In thousands)


	PREFERRED STOCK SHARES		PREFERRED STOCK			TREASURY STOCK SHARES		TREASURY STOCK			COMMON STOCK SHARES		COMMON STOCK		ADDITIONAL PAID-IN CAPITAL			ACCUMULATED OTHER COMPREHENSIVE INCOME			RETAINED EARNINGS (DEFICIT)			TOTAL
Balance at December 31, 2003	368			34,894		—			—		32,242			323		228,511			(2,441	)		198			261,485

Stock purchase, compensation and incentive plans, net	—			—		13			—		(22	)		—		1,842			—			—			1,842
Proceeds from public offering, net of costs	—			—		—			—		3,467			35		57,343			—			—			57,378
Exercise of common stock options	—			—		—			—		453			5		3,906			—			—			3,911
Tax impact of exercise of stock options	—			—		—			—		—			—		1,974			—			—			1,974
Equity offering costs	—			—		—			—		—			—		(106	)		—			—			(106	)
Purchase of shares into treasury	—			—		3,467			(57,378	)	—			—		—			—			—			(57,378	)
Conversion of warrants into common stock	—			—		—			—		175			1		319			—			—			320
Conversion of preferred stock	(24	)		(2,368	)	—			—		277			2		2,366			—			—			—
Dividends on preferred stock	—			—		—			—		—			—		—			—			(2,421	)		(2,421	)
Accretion of discount on preferred stock	—			978		—			—		—			—		—			—			(978	)		—
Comprehensive income:
Net income	—			—		—			—		—			—		—			—			46,416			46,416
Fair value of commodity derivative instruments	—			—		—			—		—			—		—			1,322			—			1,322

Comprehensive income																									47,738


Other	—			—		—			—		26			1		305			—			—			306

Balance at December 31, 2004	344			33,504		3,480			(57,378	)	36,618			367		296,460			(1,119	)		43,215			315,049

Stock purchase, compensation and incentive plans, net	—			—		(6	)		(54	)	28			—		9,720			—			—			9,666
Exercise of common stock options	—			—		—			—		761			8		7,966			—			—			7,974
Equity offering costs	—			—		—			—		—			—		(87	)		—			—			(87	)
Conversion of warrants into common stock	—			—		—			—		22			—		19			—			—			19
Conversion of preferred stock	(344	)		(34,448	)	—			—		4,033			40		34,408			—			—			—
Accretion of discount on preferred stock	—			944		—			—		—			—		—			—			(944	)		—
Comprehensive income:
Net income	—			—		—			—		—			—		—			—			73,095			73,095
Fair value of commodity derivative instruments	—			—		—			—		—			—		—			(11,500	)		—			(11,500	)

Comprehensive income																									61,595


Other	—			—		—			—		5			—		377			—			—			377

Balance at December 31, 2005	—		$	—		3,474		$	(57,432	)	41,467		$	415	$	348,863		$	(12,619	)	$	115,366		$	394,593

Stock purchase, compensation and incentive plans, net	—			—		6			(8	)	151			2		10,496			—			—			10,490
Exercise of common stock options	—			—		—			—		26			—		261			—			—			261
Conversion of warrants into common stock	—			—		—			—		834			8		1,825			—			—			1,833
Reclass of performance shares into equity	—			—		—			—		—			—		3,126			—			—			3,126
Comprehensive income:
Net income	—			—		—			—		—			—		—			—			(50,400	)		(50,400	)
Fair value of commodity derivative instruments	—			—		—			—		—			—		—			11,625			—			11,625

Comprehensive income																									(38,775	)


Other	—			—		—			—		24			—		742			—			—			742

Balance at December 31, 2006	—		$	—		3,480		$	(57,440	)	42,502		$	425	$	365,313		$	(994	)	$	64,966		$	372,270

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31, 2006, 2005 and 2004

(In thousands)


	2006			2005			2004
Cash flows from operating activities:
Net income (loss)	$	(50,400	)	$	73,095		$	46,416
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		198,162			99,524			88,784
Accretion expense		4,572			4,125			3,569
(Gain) loss on disposal of assets		4,047			(777	)		(282	)
Non cash-based compensation		11,038			6,817			3,100
Deferred income taxes		(27,452	)		41,242			26,365
Exploration expenditures		122,449			69,926			26,730
Amortization of deferred financing costs		1,133			995			907
Other		1,587			966			293

Changes in operating assets and liabilities:
Trade accounts receivable		2,390			(18,985	)		(24,931	)
Other receivables		(8,966	)		(43,703	)		(5,600	)
Prepaid expenses		(391	)		(894	)		(179	)
Other assets		283			(2,338	)		(4,522	)
Accounts payable and accrued expenses		13,599			40,073			6,180
Other liabilities		23			(97	)		(1,756	)

Net cash provided by operating activities		272,074			269,969			165,074

Cash flows used in investing activities:
Acquisition of business, net of cash acquired		(420	)		(863	)		(2,166	)
Property acquisitions		(15,897	)		(193,115	)		(6,551	)
Deposit paid on purchase of properties		—			—			(5,000	)
Exploration and development expenditures		(341,936	)		(254,900	)		(163,019	)
Other property and equipment additions		(527	)		(1,723	)		(562	)
Proceeds from sale of oil and gas assets		—			1,442			585

Net cash used in investing activities		(358,780	)		(449,159	)		(176,713	)

Cash flows from financing activities:
Deferred financing costs		(853	)		(357	)		(721	)
Repayments of long-term debt		(73,109	)		(63,108	)		(199	)
Proceeds from long-term debt		155,000			148,000			—
Proceeds from public stock offering, net of commissions		—			—			57,378
Purchase of shares into treasury		—			—			(57,378	)
Equity offering costs		—			(87	)		(106	)
Payment of preferred stock dividends		—			—			(2,421	)
Exercise of stock options and warrants		2,093			7,994			4,231

Net cash provided by financing activities		83,131			92,442			784

Net decrease in cash and cash equivalents		(3,575	)		(86,748	)		(10,855	)
Cash and cash equivalents at beginning of year		6,789			93,537			104,392

Cash and cash equivalents at end of year	$	3,214		$	6,789		$	93,537

See accompanying notes to consolidated financial statements.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Organization

Energy Partners, Ltd. was incorporated on January 29, 1998 and is an independent oil and natural gas exploration and production company with operations concentrated in the Shelf and deepwater Gulf of Mexico as well as the Gulf Coast onshore region. The Company’s future financial condition and results of operations will depend primarily upon prices received for its oil and natural gas production and the costs of finding, acquiring, developing and producing reserves.

(2) Summary of Significant Accounting Policies

(a) Basis of Presentation

The consolidated financial statements include the accounts of Energy Partners, Ltd., and its wholly-owned subsidiaries (collectively, the Company). All significant intercompany accounts and transactions are eliminated in consolidation. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

(b) Property and Equipment

The Company uses 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. Effective July 1, 2005, the Company adopted Financial Accounting Standards Board Staff Position FAS 19-1, “Accounting for Suspended Well Costs” (FSP 19-1). FSP 19-1 amended Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (Statement 19), to permit the continued capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. During the year ended December 31, 2005, the Company adopted the requirements of FSP 19-1. Upon adoption, the Company evaluated all existing capitalized well costs under the provisions of FSP 19-1 and determined there was no impact to the Company’s consolidated financial statements. During the Company’s limited operating history it has not had well costs that have been capitalized for a period greater than one year for which proved reserves have not been determined. 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. Costs of undeveloped leases are expensed over the life of the leases. Capitalized costs of producing oil and natural gas properties are depreciated and depleted by the units-of-production method.

The Company capitalizes interest costs during the development phase of significant properties or projects to bring them to a condition where they are capable of use in oil and natural gas production operations. Interest capitalized is included in the cost of oil and natural gas assets and amortized with other costs on a unit-of-production basis.

The Company assesses the impairment of capitalized costs of proved oil and natural gas properties when circumstances indicate that the carrying value 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.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The calculation is performed on a field-by-field basis, utilizing its current estimate 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, and the resulting gain or loss is recognized.

(c) Asset Retirement Obligation

The Company accounts for its Asset Retirement Obligations in accordance with Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 requires companies to record the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the related long-lived asset’s carrying amount. Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset. The Company’s asset retirement obligations relate primarily to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and gas properties.

(d) Income Taxes

The Company accounts for income taxes under the asset and liability method, which requires that deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. 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. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period that includes the enactment date.

(e) Deferred Financing Costs

Costs incurred to obtain debt financing are deferred and are amortized 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 available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed in the same manner as basic earnings per share except that the denominator is increased to include the number of additional common shares that could have been outstanding assuming the conversion of convertible preferred stock shares, the exercise of stock option awards and warrants and the potential shares associated with restricted share units and performance shares that would have a dilutive effect on earnings per share.

(g) Revenue Recognition

The Company records revenues from the sales of oil and natural gas when the product is delivered at a determinable price, title has transferred and collectibility is reasonably assured. When the Company has an interest with other producers in properties from which natural gas is produced, the Company uses the entitlement method for recording natural gas sales revenue. Under this method of accounting, revenue is recorded based on

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

the Company’s net working interest in field production. Deliveries of natural gas in excess of the Company’s working interest are recorded as liabilities and under-deliveries are recorded as receivables. The Company had natural gas imbalance receivables of $0.3 million and $0.2 million at December 31, 2006 and 2005, respectively and had liabilities of $0.5 million at December 31, 2006 and 2005.

(h) Statements of Cash Flows

For purposes of the statements of cash flows, highly-liquid investments with original maturities of three months or less are considered cash equivalents. At December 31, 2006 and 2005, interest-bearing cash equivalents were approximately $10.7 million and $25.8 million, respectively. Expenditures for exploratory dry holes incurred are excluded from operating cash flows and included in investing activities.

(i) Hedging Activities

The Company uses derivative instruments to manage commodity price risks associated with future crude oil and natural gas production, but does not use them for speculative purposes. The Company’s commodity price hedging program has utilized financially-settled zero-cost collar contracts to establish floor and ceiling prices on anticipated future crude oil and natural gas production and oil and natural gas swaps to fix the price of anticipated future crude oil and natural gas production. Accounting and reporting standards require that derivative instruments, including certain derivative instruments embedded in other contracts, be 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 inception of the derivative. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations. For derivative instruments designated as cash-flow hedges, changes in fair value, to the extent the hedge is effective, will be recognized in other comprehensive income (a component of stockholders’ equity) until the forecasted transaction is settled, when the resulting gains and losses will be recorded in oil and natural gas revenue. Hedge ineffectiveness is measured at least quarterly based on the changes in fair value between the derivative contract and the hedged item. Any change in fair value resulting from ineffectiveness, will be charged currently to other revenue.

(j) Stock-Based Compensation

The Company has two stock-award plans, the 2006 Long Term Stock Incentive Plan and the Amended and Restated 2000 Stock Incentive Plan for Non-Employee Directors. Prior to January 1, 2006 the Company accounted for its stock-based compensation in accordance with Accounting Principles Board’s Opinion No. 25, “Accounting For Stock Issued to Employees” (Opinion No. 25) and related interpretations, as permitted by Statement of Financial Accounting Standards No. 123, “Accounting For Stock-Based Compensation” (Statement 123) and Statement of Financial Accounting Standards No. 148, “Accounting For Stock-Based Compensation—Transition and Disclosure,” (Statement 148). Accordingly, compensation expense for a stock option grant was recognized only if the exercise price was less than the fair market value of the Company’s common stock on the grant date.

Effective January 1, 2006, the company adopted the fair-value recognition provisions of Statement of Financial Standards No. 123 (R), “Share Based Payment” (Statement 123(R)), using the modified prospective transition method. Under this method, stock-based compensation expense for the year ended December 31, 2006 includes:

•

compensation expense for all stock-based compensation awards granted prior to January 1, 2006, but not yet vested, based on the grant-date fair-value estimated in accordance with the original provisions of Statement 123, and

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

•

compensation expense for all stock-based compensation awards granted subsequent to January 1, 2006, based on the grant-date fair-value estimated in accordance with the provisions of Statement 123(R).

Prior to the adoption of Statement No. 123(R), the Company reported all tax benefits resulting from the exercise of stock options as operating cash flows in its consolidated statements of cash flows. In accordance with Statement 123(R), the Company is now required to report the excess tax benefits from the exercise of stock options as financing cash flows. For the year ended December 31, 2006, no excess tax benefits were reported in the statement of cash flows as the Company is in a net operating loss carryforward position. See note 14 for additional disclosures.

(k) Allowance for Doubtful Accounts

The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectibility. Many of the Company’s receivables are from joint interest owners on properties of which the Company is the operator. Thus, the Company may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. The Company’s crude oil and natural gas receivables are typically collected within two months. The Company accrues an allowance on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any allowance may be reasonably estimated. As of December 31, 2006 and 2005, the Company had no allowance for doubtful accounts balances.

(l) Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. The Company evaluates its estimates and assumptions on a regular basis. The Company uses 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. The Company’s actual results may differ from these estimates and assumptions used in preparation of its financial statements. Significant estimates with regard to these financial statements and related unaudited disclosures include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows there-from disclosed in note 20.

(m) Reclassifications

Certain reclassifications have been made to the prior period financial statements in order to conform to the classification adopted for reporting in fiscal 2006.

(3) Common Stock

On July 16, 2004 the Company filed a universal shelf registration statement (the Registration Statement) which allows the Company to issue an aggregate of $300 million in common stock, preferred stock, senior debt and subordinated debt in one or more separate offerings with the size, price and terms to be determined at the time of the sale. On November 10, 2004 the Company sold approximately 3.5 million shares of its common stock to the public pursuant to the Registration Statement. Concurrent with this offering, the Company entered into a stock purchase agreement with Energy Income Fund, L.P. (EIF) pursuant to which it purchased an equal number

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

of shares of common stock owned by EIF at a price per share equal to the proceeds per share received in the offering, before expenses. The Company did not retain any of the proceeds from this offering and the stock has been recorded as treasury stock on the consolidated balance sheet at cost. The Company restored the Registration Statement to $300 million in May 2005.

On September 14, 2006, the Company and Mellon Investor Services LLC, as rights agent, entered into the Limited Rights Plan and declared a dividend distribution of one right (a Right) for each outstanding share of the Company’s common stock. Upon certain events, each Right entitles the registered holder to purchase from the Company one one-hundredth of a share of a new series of Series A Junior Participating Preferred Stock, par value $1.00 per share, of the Company (the Preferred Stock) at a price of $80 per one one-hundredth of a share of Preferred Stock, subject to adjustment. The Rights become exercisable upon the earlier of the tenth day following the public announcement or notice to the Company that a person or group acquired, or obtained the right to acquire, 10% or more of the outstanding Company common stock (the Shares Acquisition Date) or (unless the Board of Directors sets a later date) the tenth business day after any person or group commences a tender offer or exchange offer which, if successful, would cause the person or group to own 10% or more of the outstanding Company common stock (the Distribution Date).

Should any person or group acquire 10% or more of the outstanding Company common stock, all Rights not held by the 10% stockholder become rights to purchase additional shares of Company common stock for one-half of the market price of such Company common stock. After a person or group crosses the 10% threshold and before such person or group owns 50% or more of the outstanding Company common stock, the Board of Directors, instead of allowing the Rights to become exercisable, may issue one share of Company common stock or one one-hundredth (1/100) of a share of Preferred Stock in exchange for each Right (other than those held by the acquiring person or group). In the event of a merger or sale of 50% or more of the assets of the Company, the Rights Plan requires that provision be made for the Rights to become rights to purchase shares of the acquiring company for one-half of the market price of such shares.

The Rights have a six month term and may be redeemed for $0.01 per Right by the Board of Directors at any time prior to the time any person or group acquires 10% or more of the outstanding Company common stock. The Rights are subject to amendment by the Board of Directors in any manner except that after a Person becomes an Acquiring Person they may not be amended in a manner adverse to the holders of Rights.

(4) Supplemental Cash Flow Information

The following is supplemental cash flow information:


	Years Ended December 31,
	2006		2005		2004
	(In thousands)
Interest paid	$	23,084	$	18,121	$	14,323
Income taxes paid, net of refunds	$	350	$	350	$	151

The following is supplemental disclosure of non-cash financing activities:


	Years Ended December 31,
	2006		2005		2004
	(In thousands)
Accretion of preferred stock	$	—	$	944	$	978
Conversion of preferred stock	$	—	$	34,448	$	2,368
Restricted share units	$	879	$	805	$	—
Exercise of options	$	—	$	—	$	—

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(5) Mergers and Acquisitions

On June 22, 2006, the Company entered into an agreement and plan of merger (the Merger Agreement) with Stone Energy Corporation (Stone), pursuant to which EPL Acquisition Corp. LLC, a wholly-owned subsidiary of the Company, would acquire all of the shares of Stone for a combination of cash and stock valued at approximately $2.1 billion. Prior to entering into the Merger Agreement, Stone terminated its then existing merger agreement with Plains Exploration and Production Company (Plains) on the same day. As required under the terms of the terminated merger agreement between Stone and Plains, Plains was entitled to a termination fee of $43.5 million, which was advanced by the Company to Plains and was included in other assets in the Consolidated Balance Sheet. On August 28, 2006, Woodside Petroleum, Ltd. (Woodside) announced its intention to commence a tender offer, through its U.S. subsidiary ATS Inc., for all of the Company’s outstanding shares of common stock for $23.00 per share subject to, among other conditions, the Company’s stockholders voting down the proposed Stone acquisition. The tender offer was commenced on August 31, 2006 and was effective until September 28, 2006. On September 14, 2006, the Company announced that, on September 13, 2006, the Company’s board of directors (the Board) rejected as inadequate the unsolicited conditional offer by Woodside and recommended that its stockholders not tender their shares. Woodside extended its offer three times and announced on October 26, 2006 that it was extending its offer for the final time until November 17, 2006. On October 12, 2006 the Company announced that it had terminated the Merger Agreement with Stone and that the Board had directed the Company, assisted by its financial advisors, to explore strategic alternatives to maximize stockholder value, including the possible sale of the Company. In conjunction with the termination of the Merger Agreement, the Company paid to Stone $8.0 million, which was included in general and administrative expenses in the fourth quarter of 2006. In addition, the $43.5 million termination fee that was advanced to Plains in June 2006 on behalf of Stone was also expensed during 2006 along with other merger and strategic alternative related costs of $13.0 million. The Company expects to incur legal and financial advisory fees in 2007 related to the shareholder litigation as well as the exploration of potential strategic alternatives.

On March 8, 2005, the Company closed the acquisition of the remaining 50% gross working interest in South Timbalier 26 above approximately 13,000 feet subsea that it did not already own for approximately $19.6 million after closing adjustments from the effective date of December 1, 2004. The entire purchase price was allocated to property and equipment. The terms of the acquisition did not contain any contingent consideration, options or future commitments. As a result of the acquisition, the Company now owns a 100% gross working interest in the producing horizons in this field. The acquisition expands the Company’s interest in its core Greater Bay Marchand area and gives the Company additional flexibility in undertaking the future development of the South Timbalier 26 field.

On January 20, 2005, the Company closed an acquisition of properties and reserves in south Louisiana for approximately $149.6 million in cash, after adjustments for the exercise of preferential rights by third parties and closing adjustments. The entire purchase price was allocated to property and equipment. The terms of the acquisition did not contain any contingent consideration, options or future commitments. The acquisition was composed of nine fields, four of which were producing at the time of the closing through 14 wells. The transaction increased the Company’s exploration opportunities in its expanded focus area and further reduced the concentration of its reserves and production. In connection with the acquisition, the Company has also entered into a two-year agreement with the seller of the properties that defines an area of mutual interest (AMI) encompassing over one million acres. The proved reserves, prospects and AMI are in the southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following unaudited pro forma information for the year ended December 31, 2004 presents a summary of the consolidated results of operations as if the acquisition occurred on January 1, 2004 with pro forma adjustments to give effect to depreciation, depletion and amortization, interest expense and related income tax effects.


	Year Ended December 31, 2004
	(Unaudited, in thousands, except per share amounts)
Pro forma:
Revenue	$	315,413
Income from operations		94,487
Net income		51,241
Basic income per common share	$	1.46
Diluted income per common share	$	1.33

The Company has included the results of operations from the acquisitions discussed above from their respective closing dates. The Company has experienced substantial revenue and production growth as a result of these acquisitions. For the foregoing reasons these acquisitions will affect the comparability of the Company’s historical results of operations with future periods.

In connection with an acquisition in 2002, the Company issued among other things, 383,707 shares of $38.4 million liquidation preference of newly authorized and issued Series D Exchangeable Convertible Preferred Stock (Series D Preferred Stock) with an issue date fair value of $34.7 million discounted to give effect to the increasing dividend rate from 7% in June 2002 to 10% in June 2007. On February 28, 2005, the Company gave notice of the redemption of all of the Series D Preferred Stock issued in connection with the acquisition that remained outstanding on the redemption date of March 21, 2005. The redemption price was $100 per share plus accrued and unpaid dividends to the redemption date. Holders of record had the right to convert their shares into shares of common stock through the close of business on March 18, 2005. All holders exercised their right to convert their shares and there were no preferred shares outstanding as of the close of business on March 18, 2005.

The Company also issued warrants to purchase four million shares of the Company’s common stock in the same acquisition. Of the warrants, one million had a strike price of $9.00 and three million had a strike price of $11.00 per share. The warrants became exercisable on January 15, 2003 and expired on January 15, 2007. At December 31, 2006 there were 658,583 warrants outstanding with a strike price of $9.00 per share and 1,376,661 outstanding with a strike price of $11.00 per share. All of such outstanding warrants were exercised prior to the January 15, 2007 expiration date for 1,174,433 shares of the Company’s common stock.

In addition, former preferred stockholders of the acquired company have the right to receive contingent consideration based upon a percentage of the amount by which the before tax net present value of proved reserves related, in general, to exploratory prospect acreage held by the acquired company as of the closing date of the acquisition (the Ring-Fenced Properties) exceeds the net present value discounted at 30%. The potential consideration is determined annually from March 3, 2003 until March 1, 2007. The cumulative percentage remitted to the participants was 20% for the March 3, 2003, 30% for the March 1, 2004 and 35% for the March 1, 2005 determination dates and is 40% for the March 1, 2006 and 50% for the March 1, 2007 determination dates. The contingent consideration, if any, may be paid in the Company’s common stock or cash at the Company’s option (with a minimum of 20% in cash) and in no event will exceed a value of $50 million. In 2006 and 2005, the Company capitalized, as additional purchase price, and paid additional consideration in cash, of $0.4 million and $0.9 million related to the March 1, 2006 and 2005 contingent consideration determination dates,

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

respectively. The Company does not expect to make a contingent consideration payment in 2007. Due to the uncertainty inherent in estimating the value of future contingent consideration which includes annual valuations based upon, among other things, drilling results from the date of the prior revaluation, and development, operating and abandonment costs and production revenues (actual historical and future projected, as contractually defined, as of each revaluation date) for the Ring-Fenced Properties, total final consideration will not be determined until March 1, 2007. All additional contingent consideration, if any, will be capitalized as additional purchase price.

(6) Property and Equipment

The following is a summary of property and equipment at December 31, 2006 and 2005:


	2006		2005
	(In thousands)
Proved oil and natural gas properties	$	1,478,520	$	1,128,498
Unproved oil and natural gas properties		41,353		53,676
Other		7,431		6,904

	$	1,527,304	$	1,189,078

We analyze proved properties for impairment based on the reserves as determined by our independent reserve engineers. We recognized impairment expense of $84.7 million, $17.9 million and $6.9 million in the years ending December 31, 2006, 2005 and 2004, respectively. Substantially all of the impairment expense in 2006 was taken in of eight fields, four of which were onshore assets acquired during an acquisition in January of 2005. Three of these onshore fields along with three offshore fields experienced downward revisions of recoverable reserves at December 31, 2006. These revisions along with decreased oil and natural gas prices resulted in impairments of $52.1 million on these assets. The Company elected to release the lease on the remaining onshore field and one other offshore field experienced mechanical difficulties, it was determined that significant capital would be needed to extend its economic life and that this capital would be better deployed to projects with more potential. The net book value of these assets of $27.0 million was therefore written off during 2006. The impairment expense in 2005 was related to full impairments at six fields which would need significant capital to extend their economic lives and the Company decided to deploy the capital to projects with more potential and therefore impaired the assets. The Company also had two fields with partial impairments due to insufficient cash flow from reserves. The impairment expense in 2004 was related to our East Cameron 378 field.

Substantially all of the Company’s oil and natural gas properties serve as collateral for its bank facility.

(7) Tropical Weather

On August 29, 2005 Hurricane Katrina made landfall in the United States south of New Orleans causing catastrophic damage throughout portions of the Gulf of Mexico and to portions of Alabama, Louisiana and Mississippi, including New Orleans. As a result of the devastating effects of the storm on New Orleans and surrounding areas, the Company announced on August 30 that it had elected to establish temporary headquarters at its Houston, Texas office. A satellite office was also established in Baton Rouge, Louisiana. General and administrative costs associated with moving offices as well as relocation allowances paid to employees approximated $1.6 million during 2005.

On September 24, 2005 Hurricane Rita made landfall in the United States on the Texas/Louisiana border. This hurricane caused extensive damage throughout portions of the Gulf of Mexico region particularly to third party infrastructure such as pipelines and processing plants.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As a result of these two major hurricanes and three other hurricanes that traversed the Gulf of Mexico and adjacent land areas, nearly all of the Company’s production was shut in at one time or another during the third quarter of 2005 and into 2006. The Company maintained business interruption insurance on its significant properties, including its East Bay field. Recovery of lost revenue for the East Bay field and two other fields began accruing in October and recovery on a fourth field began accruing in November 2005. Recovery ceased for three of the fields in 2005, but continued at the East Bay Field until October 2006. Through the end of 2006, the total business interruption claim on these fields was $53.5 million, of which $3.6 million was outstanding as of December 31, 2006 and is recorded in other receivables on the Company’s consolidated balance sheet. Total offshore repair costs expended as of December 31, 2006 for Hurricanes Katrina, Rita and Cindy were $87.7 million of which $53.0 million is recorded in other receivables on the Company’s consolidated balance sheet net of collections as of December 31, 2006. As of February 22, 2007, an additional $24.6 million of this amount had been collected.

(8) Asset Retirement Obligation

In 2001, the FASB issued Statement 143. Statement 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, a corresponding increase in the carrying amount of the related long-lived asset and was effective for fiscal years beginning after June 15, 2002. The Company adopted Statement 143 effective January 1, 2003, using the cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. The Company previously recorded estimated costs of dismantlement, removal, site restoration and similar activities as part of its depreciation, depletion and amortization for oil and natural gas properties and recorded a separate liability for such amounts in other liabilities.

The following table reconciles the beginning and ending aggregate recorded amount of the asset retirement obligation for the year ended December 31, 2006:


	Asset Retirement Obligation
	(in thousands)
December 31, 2005	$	56,039
Accretion expense		4,572
Liabilities incurred		5,947
Liabilities settled		(353	)
Revisions in estimated cash flows		2,562

December 31, 2006	$	68,767

(9) Long-Term Debt

On August 5, 2003, the Company issued $150 million of 8.75% Senior Notes due 2010 (the Senior Notes) in a Rule 144A private offering (the Debt Offering) which allows unregistered transactions with qualified institutional buyers. In October 2003, the Company consummated an exchange offer pursuant to which it exchanged registered Senior Notes (the Registered Senior Notes) having substantially identical terms as the Senior Notes for the privately placed Senior Notes. After discounts and commissions and all offering expenses, the Company received $145.3 million, which was used to redeem all of the outstanding 11% Senior Subordinated Notes Due 2009 that had been issued in connection with a business combination in 2002, and to repay substantially all of the borrowings outstanding under the Company’s bank credit facility. In January 2005, the remainder of the net proceeds were used to purchase properties in south Louisiana as discussed in note 5.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Registered Senior Notes mature on August 1, 2010 with interest payable each February 1 and August 1, commencing February 1, 2004. The Company may redeem the notes at its option, in whole or in part, at any time on or after August 1, 2007 at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium which decreases yearly from 4.375% in 2007 to 0% in 2009 and thereafter. The notes are unsecured obligations and rank equal in right of payment to all existing and future senior debt, including the bank credit facility, and will rank senior or equal in right of payment to all existing and future subordinated indebtedness. The indenture relating to the Registered Senior Notes contains certain restrictions on the Company’s ability to incur additional debt, pay dividends on its common stock, make investments, create liens on its assets, engage in transactions with its affiliates, transfer or sell assets and consolidate or merge substantially all of its assets. The Registered Senior Notes are not subject to any sinking fund requirements.

On June 2, 2006 the Company amended and extended to May 31, 2011 its bank credit facility and increased its borrowing base from $150 million to $225 million, which was subsequently further increased to $250 million in November 2006. Modifications to the bank credit facility included among other things, the expansion of the revolving credit facility to $300 million from $200 million (subject to borrowing base limitations) and improved grid pricing for interest rate margins and commitment fees. In addition, under the amended bank credit facility, the Company has the ability to increase availability under the revolver to $400 million, subject to borrowing base limitations. At December 31, 2006, the Company had $167 million outstanding under the bank credit facility and $83 million available under its then current borrowing base of $250 million. The borrowing base is subject to redetermination semiannually based on the proved reserves of the oil and natural gas properties that serve as collateral for the bank credit facility as set out in the reserve report delivered to the banks each April 1 and October 1. The bank credit facility permits both prime rate based borrowings and London interbank offered rate (LIBOR) borrowings plus a floating spread. The spread will float up or down based on the Company’s utilization of the bank credit facility. The spread can range from 1.00% to 1.75% above LIBOR and 0% to 0.5% above prime. The borrowing base under the bank credit facility is secured by substantially all of the assets of the Company. In addition, the Company pays an annual fee on the unused portion of the bank credit facility ranging between 0.30% to 0.50% based on utilization. The bank credit facility contains customary events of default and various financial covenants, which require the Company to: (i) maintain a minimum current ratio, as defined in the bank credit facility, of 1.0x and (ii) maintain a minimum EBITDAX to interest ratio, as defined in the bank credit facility, of 3.5x. The Company was in compliance with its bank facility covenants as of December 31, 2006.

Total long-term debt outstanding at December 31, 2006 and 2005 was as follows:


	2006		2005
	(In thousands)
Senior Notes, annual interest of 8.75%, payable August 1, 2010	$	150,000	$	150,000
Bank facility, interest rate based on LIBOR borrowing rates plus a floating spread payable May 31, 2011, with weighted average interest on December 31, 2006 of 6.95%		167,000		85,000
Financing note payable, annual interest of 7.99%, equal monthly payments, matured February 2006		—		109

		317,000		235,109
Less: Current maturities		—		109

	$	317,000	$	235,000

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Maturities of long-term debt as of December 31, 2006 were as follows (in thousands):


2007	$	—
2008		—
2009		—
2010		150,000
2011		167,000
Thereafter		—

	$	317,000

(10) Significant Customers

The Company had oil and natural gas sales to four customers accounting for 28%, 19%, 12% and 11%, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2006. The Company had oil and natural gas sales to four customers accounting for 18%, 16%, 15% and 10%, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2005. The Company had oil and natural gas sales to three customers accounting for approximately 22%, 14% and 13%, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2004.

(11) Hedging Activities

The Company uses financially-settled crude oil and natural gas swaps and zero-cost collars. The Company enters into hedging transactions with major financial institutions to reduce exposure to fluctuations in the price of oil and natural gas. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded in other revenue, whereas gains and losses from the settlement of hedging contracts are recorded in oil and natural gas revenue. Crude oil hedges are settled based on the average of the reported settlement prices for West Texas Intermediate crude on the NYMEX for each month. Natural gas hedges are settled based on the average of the last three days of trading of the NYMEX Henry Hub natural gas contract for each month.

With a financially-settled swap, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the hedged price for the transaction, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price of the collar, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar.

The Company had no crude oil contracts and the following natural gas hedging contracts as of December 31, 2006:


Natural Gas Positions
		Strike Price		Volume (Mmbtu)
Remaining Contract Term	Contract Type	($/Mmbtu)		Daily	Total
01/07 - 12/07	Collar	$	5.00/$8.00	10,000	3,650,000

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the years ended December 31, 2006, 2005 and 2004, settlements of hedging contracts reduced oil and gas revenues by $0.7 million, $17.0 million and $15.2 million, respectively. The Company has not discontinued hedge accounting treatment in the years presented, and therefore, has not reclassified any gains or losses into earnings as a result.

The following table reconciles the change in accumulated other comprehensive income for the years ended December 31, 2006 and 2005:


	Year Ended December 31, 2006
	(In thousands)
Accumulated other comprehensive loss as of December 31, 2005—net of taxes of $7,098				$	(12,619	)
Net income	$	(50,400	)
Other comprehensive income—net of tax
Hedging activities
Reclassification adjustments for settled contracts—net of taxes of $(247)		439
Changes in fair value of outstanding hedging positions—net of taxes of $(6,293)		11,186

Total other comprehensive income		11,625			11,625

Comprehensive income	$	(38,775	)

Accumulated other comprehensive loss as of December 31, 2006—net of taxes of $558				$	(994	)


	Year Ended December 31, 2005
	(In thousands)
Accumulated other comprehensive loss as of December 31, 2004—net of taxes of $630				$	(1,119	)
Net income	$	73,095
Other comprehensive loss—net of tax
Hedging activities
Reclassification adjustments for settled contracts—net of taxes of $(6,126)		10,890
Changes in fair value of outstanding hedging positions—net of taxes of $12,595		(22,390	)

Total other comprehensive loss		(11,500	)		(11,500	)

Comprehensive income	$	61,595

Accumulated other comprehensive loss as of December 31, 2004—net of taxes of $7,098				$	(12,619	)

Based upon current prices, the Company expects to transfer approximately $1.6 million of pretax net deferred losses in accumulated other comprehensive income as of December 31, 2006 to earnings during 2007 when the forecasted transactions actually occur.

(12) Fair Value of Financial Instruments

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2006 and 2005. The fair value of a financial instrument is the amount at which the

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, noncurrent assets, trade accounts payable and accrued expenses and derivative instruments, all of which had fair values approximating carrying amounts. The fair value of current and long-term debt is estimated based on current rates offered the Company for debt of the same maturities. The Company has off-balance sheet exposures relating to certain financial guarantees and letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal.


	2006				2005
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
Financial liabilities:
Current and long-term debt:
The Senior Notes	$	150,000	$	153,750	$	150,000	$	155,250
Bank credit facility		167,000		167,000		85,000		85,000
Financing note payable		—		—		109		109

(13) Income Taxes

Components of income tax expense for the years ended December 31, 2006, 2005 and 2004 are as follows:


	Current		Deferred		Total
	(In thousands)
2006:
Federal	$	633	$	26,672	$	27,305
State		—		780		780

	$	633	$	27,452	$	28,085

2005:
Federal	$	350	$	38,931	$	39,281
State		—		2,311		2,311

	$	350	$	41,242	$	41,592

2004:
Federal	$	151	$	24,904	$	25,055
State		—		1,461		1,461

	$	151	$	26,365	$	26,516

The reasons for the differences between the effective tax rates and the “expected” corporate federal income tax rate is as follows:


	Percentage of Pretax Earnings
	2006		2005		2004
Expected tax rate	35.0	%	34.0	%	34.0	%
State taxes	1.0		2.0		2.0
Other	(0.2	)	0.3		0.4

	35.8	%	36.3	%	36.4	%

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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, 2006 and 2005 are presented below:


	2006			2005
	(In thousands)
Current deferred tax assets:
Fair value of commodity derivative instruments	$	559		$	3,555
Accrued bonus compensation		828			821
Accrued legal provision		—			1,206

Current deferred tax assets	$	1,387		$	5,582

Non-Current Deferred tax assets:
Restricted stock awards and options	$	5,199		$	3,339
Federal and state net operating loss carryforwards		17,932			11,480
Fair market value of commodity derivative instruments		—			3,543
Other		620			1,274

Non-Current Deferred tax liability:
Property, plant and equipment, principally due to differences in depreciation		(86,202	)		(107,195	)

Net non-current deferred tax liability	$	(62,451	)	$	(87,559	)

At December 31, 2006, the Company had net operating loss carryforwards of approximately $49.8 million, which are available to reduce future federal taxable income. The net operating loss carryforwards begin expiring in the years 2018 through 2023. Although realization is not assured, management believes it is more likely than not that all of the deferred tax assets will be realized through future earnings and reversal of taxable temporary differences. As a result, no valuation allowance has been provided at December 31, 2006 and 2005. The 2006 tax provision does not use any of the net operating loss carryforwards.

(14) Employee Benefit Plans

As described in note 2, the Company has a long term-incentive plan authorizing various types of market and performance based incentive awards which may be granted to officers and employees. The 2006 Long Term Stock Incentive Plan (the Employee Plan) provides for the grant of stock options for which the exercise price, set at the time of the grant, is not less than the fair market value per share at the date of grant. The outstanding options have a term of 10 years and generally vest over 3 years with grants to a limited group of people that cliff vest at the end of 5 years. The Employee Plan also provides for restricted stock and restricted share units, which are referred to as non-vested share awards under Statement 123(R), and performance share awards. The Employee Plan was adopted by the board of directors in March 2006 and approved by stockholders in May 2006 and is administered by the Compensation Committee of the Board of Directors or such other committee as may be designated by the Board of Directors. The Compensation Committee is authorized to select the employees of the Company and its subsidiaries and affiliates who will receive awards, to determine the types of awards to be granted to each person, and to establish the terms of each award. The total number of shares that may be issued under the plan for all types of awards was 2,604,414 as of May 2006.

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 permits 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 number of shares authorized for issuance under the Director Plan is 500,000. The size of any grants of stock options and restricted share units to

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

non-employee directors, including to new directors, will be determined annually, based on the analysis of an independent compensation consultant. The option exercise price for an option granted under the Director Plan shall be the fair market value of the shares covered by the option at the time the option is granted. Options become fully exercisable on the first anniversary of the date of the grant. Prior to the one-year anniversary, the options shall be 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 has not become exercisable prior to the cessation of the optionee’s service as a director for any reason shall not thereafter become exercisable. Each option shall expire on the earlier of (i) ten (10) years from the date of the granting thereof, or (ii) thirty-six (36) months after the date the optionee ceases to be a director of the Company for any reason. Each restricted share unit represents the right to receive one share of Common Stock upon the earlier to occur of: (i) the cessation of the eligible director’s service as a director of the Company for any reason, or (ii) the occurrence of a change of control of the Company. An eligible director shall become 100% vested in a grant of restricted share units on the first anniversary of the date of grant. Prior to the first anniversary of the grant, an eligible director shall be vested in a number of restricted share units determined by pro-rating the grant based on the number of days elapsed since the date of the grant. If the service of an eligible director ceases for any reason prior to the first anniversary of the grant, other than in connection with the occurrence of a change of control of the Company, the director shall forfeit any unvested restricted share units.

During the year ended December 31, 2006, the Company recognized compensation expense of $4.4 million for option shares, $5.9 million for non-vested share awards and $0.8 million for performance share awards. Of the $4.4 million option expense included in the Company’s statements of operations for the year ended December 31, 2006, $2.4 million relates to awards granted prior to January 1, 2006. The deferred income tax benefit recognized during that same period for the awards was $4.0 million. During the year ended December 31, 2005, the Company recognized $0.7 million of compensation expense for option shares due to the modification of an award under opinion No. 25 and recognized $4.5 million for non-vested share awards and $1.4 million for performance share awards. Total deferred income tax benefit recognized during that same period for share awards was $2.4 million. During the year ended December 31, 2004, the Company recognized compensation expense of $0.5 million for option shares due to the modification of an award under Opinion No. 25 and recognized $1.3 million for non-vested share awards and $1.3 million for performance share awards. Total deferred income tax benefit recognized during that same period for share awards was $1.1 million.

The following table illustrates the pro forma effect on net income and earnings per common share for the years ended December 31, 2005 and 2004 as if the Company had applied the fair value method to measure stock-based compensation, as required under the disclosure provisions of Statement 123(R):


	2005		2004
Net income available to common stockholders:
As reported	$	72,151	$	43,017
Less: Pro forma stock based employee compensation cost, after tax		1,140		2,179

Pro forma	$	71,011	$	40,838

Basic earnings per share:
As reported	$	1.94	$	1.31
Pro forma	$	1.91	$	1.24
Diluted earnings per share:
As reported	$	1.79	$	1.20
Pro forma	$	1.77	$	1.14

Average fair value of grants during the year	$	6.86	$	6.19
Stock-based employee compensation cost, net of tax, included in net income as reported	$	468	$	340

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The fair value of each share option award is estimated on the date of grant using the Black-Scholes option valuation model with the following weighted average assumptions for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006	2005	2004
Black-Scholes option pricing model assumptions:
Risk free interest rate	4.4%	4.5%	4.5%
Expected life (years)	4.79	5.00	5.00
Expected volatility	43%	42% to 43%	43% to 45%
Dividend yield	—	—	—

Expected volatility is based on the historical volatility of the Company’s stock over the period of time equivalent to the expected term of the options granted. The expected term of options granted is derived from historical exercise patterns over a period of time with consideration of expected term of unvested options. The Company has not experienced significant differences in the historical exercise patterns among officers, employees and non-employee directors for them to be considered separately for valuation purposes. 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.

Additionally, Statement 123 (R) requires the Company to estimate pre-vesting option forfeitures at the time of grant and periodically revise those estimates in subsequent periods if actual forfeitures differ from those estimates. The Company records stock-based compensation expense only for those awards expected to vest using an estimated forfeiture rate based on its historical pre-vesting forfeiture data. The Company did estimate forfeitures for the pro forma disclosure provisions of Statement 123 for periods prior to 2006.

A summary of option share activity for the years ended December 31, 2006, 2005 and 2004 is as follows:


	Options		Weighted- Average Exercise Price Per Share		Weighted- Average Remaining Contractual Terms	Aggregate Intrinsic Value
					(in years)	(in thousands)
Outstanding on January 1, 2004	2,009,282		$	9.68
Granted	637,000			14.01
Exercised	(453,492	)		8.73
Forfeited/Cancelled	(160,461	)		11.75

Outstanding on December 31, 2004	2,032,329		$	11.09
Granted	595,300			26.07
Exercised	(759,288	)		10.50
Forfeited/Cancelled	(40,232	)		14.82

Outstanding on December 31, 2005	1,828,109		$	16.13
Granted	544,181			21.69
Exercised	(28,599	)		9.15
Forfeited/Cancelled	(201,007	)		25.49

Outstanding on December 31, 2006	2,142,684		$	16.76	7.17	$	35,912

Exercisable on December 31, 2006	1,239,345		$	12.24	5.91	$	15,168
Available for future grants on December 31, 2006	2,662,285

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The weighted-average grant-date fair value of option shares granted during the years ended December 31, 2006, 2005 and 2004 was $9.24, $6.86 and $6.22, respectively. The aggregate intrinsic value of option shares (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) exercised during the years ended December 31, 2006, 2005 and 2004 was $0.4 million, $12.6 million and $2.8 million, respectively. The following table summarizes information about option shares outstanding at December 31, 2006:


Range of Exercise Prices	Shares	Options Outstanding			Options Exercisable
Range of Exercise Prices	Shares	Remaining Contractual Life	Weighted Average Price		Shares	Weighted Average Price
$ 7.00 – $14.00	1,085,410	5.8 years	$	10.89	1,036,577	$	10.76
$14.01 – $21.00	307,318	7.9 years	$	17.48	109,133	$	16.20
$21.01 – $28.00	760,256	8.8 years	$	24.96	93,635	$	23.95

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 years ended December 31, 2006, 2005 and 2004 was $21.62 per share, $26.50 per share, and $15.23 per share, respectively. The total fair value of non-vested share awards that vested during each of the years ended December 31, 2006, 2005 and 2004 was $3.3 million, $3.4 million and $0.9 million, respectively. A summary of the status of the Company’s non-vested share awards as of December 31, 2006 and changes during the year ended December 31, 2006 is as follows:


	Shares		Weighted- Average Grant-Date Fair Value
Non-vested share awards outstanding at January 1, 2006	656,629		$	23.08
Granted	268,722			21.62
Vested	(139,995	)		23.87
Forfeited/Cancelled	(72,068	)		23.98

Non-vested share awards outstanding at December 31, 2006	713,288		$	23.71

During the period from 2003 through 2005, performance shares were awarded to officers and key employees with the number of shares to be issued upon being earned, at the end of their respective three year cycles, being based on certain performance measures. The shares awarded can range from a minimum of 0% to a maximum of 200% of the target number of shares depending on the level at which the goals are attained. The Company did not award any performance shares in 2006. In the year ended December 31, 2006, 55,111 shares were earned and issued and 35,756 shares expired unearned or were forfeited leaving 331,190 shares reserved based on the maximum award available, of which 69,000 shares are considered probable of being earned as of December 31, 2006.

As of December 31, 2006, there was $4.7 million of total unrecognized compensation expense related to option shares granted which is expected to be recognized over a weighted-average period of 2 years. As of December 31, 2006, there was $8.0 million of total unrecognized compensation expense related to non-vested share awards granted which is expected to be recognized over a weighted-average period of 2 years and as of December 31, 2006, there was $0.7 million of total unrecognized compensation expense related to performance shares granted which is expected to be recognized over a weighted-average period of 1 year.

The Company also has a 401(k) Plan that covers all employees. The 401(k) Plan was amended in 2004, such that the Company match was increased, effective January 1, 2005, to 100% of each individual participant’s

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

contribution not to exceed 6% of the participant’s compensation. The contributions may be in the form of cash or the Company’s common stock. The Company made matching contributions to the 401(k) Plan of 38,220, 30,586 and 13,210 shares of common stock in 2006, 2005 and 2004 valued at approximately $0.9 million, $0.8 million and $207,000, respectively.

(15) Commitments and Contingencies

The Company has operating leases for office space and equipment, which expire on various dates through 2016. In addition, the Company has agreed to purchase seismic-related services and drilling rig commitments which expire on various dates through 2008.

Future minimum commitments as of December 31, 2006 under these operating obligations are as follows (in thousands):


2007	$	91,338
2008		3,240
2009		1,562
2010		1,284
2011		1,284
Thereafter		6,419

	$	105,127

Expense relating to operating obligations for the years ended December 31, 2006, 2005 and 2004 was $9.6 million, $4.8 million and $6.3 million, respectively.

Commencing January 1, 2002, the Company was required to make monthly deposits of $250,000 into a trust for future abandonment costs at East Bay. The Company was not entitled to access the trust fund in order to draw funds for abandonment purposes prior to December 31, 2003. Monthly deposits were not required to be made for fiscal year 2004 but resumed January 1, 2005. Beginning December 31, 2003 the minimum balance in the trust must be maintained at $6.0 million (with a maximum balance not to exceed $15.0 million) until such time that the remaining abandonment obligation is less than that amount. Therefore if funds are drawn to pay for ongoing abandonment activities, deposits may be necessary. These deposits are classified as other assets in the accompanying consolidated balance sheets.

On August 28, 2006, Woodside commenced an action against the Company, the Company’s directors, and Stone in the Delaware Court of Chancery for New Castle County (the Delaware Court) styled as ATS, Inc. v. Bachmann et al., C.A. No. 2374-N (the Woodside Litigation). As amended on October 20, 2006, the Woodside complaint alleged that the termination fee provisions in the Merger Agreement were invalid under Delaware law and that the fee the Company paid Stone in connection with the termination of the Merger Agreement and Stone’s termination of its merger agreement with Plains constituted an invalid penalty under Delaware law. Woodside also alleged that the EPL directors breached their fiduciary duties by agreeing to the termination fee provisions in the Merger Agreement and the fees paid to Stone. Woodside asserted that, absent the invalidation of the termination fee payments, the Company’s shareholders will be unable to make a fully informed choice as to whether to accept the Tender Offer. Woodside sought declaratory and injunctive relief.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Action alleges that the Company’s directors breached their fiduciary duties by agreeing to the termination fee provisions in the Merger Agreement, adopting the sixth-month stockholders rights agreement, amending and extending coverage to all full time employees of its change of control severance arrangements, and paying a fee to Stone in connection with the termination of the Merger Agreement. Farrington also alleges that the Company’s directors have failed to adequately disclose material information relevant to the Company stockholders’ decision whether to accept the Tender Offer. Farrington seeks declaratory and injunctive relief as well as unspecified damages.

On October 26, 2006, Woodside dismissed its legal action without prejudice.

From time to time, the Company is involved in litigation arising out of operations in the normal course of business. In management’s opinion, the Company is not involved in any litigation, the outcome of which would have a material effect on the financial position, results of operations or liquidity of the Company.

(16) Related Party

One of the Company’s directors is a senior managing director of Evercore Group L.L.C. (Evercore). Evercore provided financial advisory service to the Company in connection with the Merger Agreement, the Woodside offer and the Company’s exploration of strategic alternatives. Evercore received fees of $1.6 million in 2006 in connection with financial advisory services related to the Merger Agreement and the consideration of the unsolicited offer from Woodside. In addition, inclusive of $2.3 million accrued during 2006, the Company has committed to an additional $7.0 million due to Evercore upon the earlier of the consummation of a transaction or September 5, 2007.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(17) Interim Financial Information (Unaudited)

The following is a summary of consolidated unaudited interim financial information for the years ended December 31, 2006 and 2005:


	Three Months Ended
	March 31		June 30		September 30			December 31
	(In thousands, except per share data)
2006
Revenues	$	110,118	$	121,234	$	107,491		$	111,634
Costs and expenses		94,805		107,375		148,594			187,913
Business interruption recovery		12,689		10,594		8,293			1,293

Income (loss) from operations		28,002		24,453		(32,810	)		(74,988	)
Net income (loss)		14,803		12,585		(25,242	)		(52,546	)
Net income (loss) available to common stockholders		14,803		12,585		(25,242	)		(52,546	)
Earnings (loss) per share:
Basic	$	0.39	$	0.33	$	(0.66	)	$	(1.35	)
Diluted		0.37		0.31		(0.66	)		(1.35	)
2005
Revenues	$	97,478	$	106,156	$	92,049		$	107,264
Costs and expenses		61,535		73,790		77,099			79,128
Business interruption recovery		—		—		—			20,632

Income from operations		35,943		32,366		14,950			48,768
Net income		20,421		18,050		6,520			28,104
Net income available to common stockholders		19,477		18,050		6,520			28,104
Earnings per share:
Basic	$	0.56	$	0.48	$	0.17		$	0.74
Diluted		0.51		0.45		0.16			0.69

(18) Supplemental Condensed Consolidating Financial Information

In connection with the Debt Offering, discussed above, all of the Company’s current active subsidiaries (the Guarantor Subsidiaries) jointly, severally and unconditionally guaranteed the payment obligations under the Debt Offering. 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. The Company has 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.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Supplemental Condensed Consolidating Balance Sheet

As of December 31, 2006


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	3,214		$	—		$	—		$	3,214
Accounts receivable		120,373			12,028			—			132,401
Other current assets		4,895			62			—			4,957

Total current assets		128,482			12,090			—			140,572
Property and equipment		1,091,709			435,595			—			1,527,304
Less accumulated depreciation, depletion and amortization		(445,073	)		(235,772	)		—			(680,845	)

Net property and equipment		646,636			199,823			—			846,459
Investment in affiliates		169,970			852			(170,822	)		—
Notes receivable, long-term		—			216,370			(216,370	)		—
Other assets		16,835			(21	)		—			16,814

	$	961,923		$	429,114		$	(387,192	)	$	1,003,845


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	179,124		$	1,228		$	—		$	180,352
Fair value of commodity derivative instruments		1,552			—			—			1,552
Current maturities of long-term debt		—			—			—			—

Total current liabilities		180,676			1,228			—			181,904
Long-term debt		317,000			216,370			(216,370	)		317,000
Other liabilities		91,977			40,694			—			132,671

		589,653			258,292			(216,370	)		631,575
Stockholders’ equity:
Preferred stock		—			3			(3	)		—
Common stock		425			98			(98	)		425
Additional paid-in capital		365,313			1,606			(1,606	)		365,313
Accumulated other comprehensive loss		(994	)		—			—			(994	)
Retained earnings		64,966			169,118			(169,118	)		64,966
Treasury stock		(57,440	)		—			—			(57,440	)

Total stockholders’ equity		372,270			170,822			(170,822	)		372,270

	$	961,923		$	429,114		$	(387,192	)	$	1,003,845

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Supplemental Condensed Consolidating Statement of Operations

Year Ended December 31, 2006


	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and gas	$	303,425		$	145,761		$	—		$	449,186
Other		(54,711	)		202			54,873			364

		248,714			145,963			54,873			449,550
Costs and expenses:
Lease operating expenses		6,431			54,405			—			60,836
Taxes, other than on earnings		1,739			11,893			—			13,632
Exploration expenditures, dry hole cost and impairments		82,511			53,914			—			136,425
Depreciation, depletion, amortization and accretion		123,141			79,593			—			202,734
General and administrative		119,083			16,030			(15,000	)		120,113
Other expenses		4,022			—			—			4,022

Total costs and expenses		336,927			215,835			(15,000	)		537,762

Business interruption recovery		32,869			—			—			32,869
Income (loss) from operations		(55,344	)		(69,872	)		69,873			(55,343	)

Interest expense, net		(23,141	)		(1	)		—			(23,142	)

Income (loss) before income taxes		(78,485	)		(69,873	)		69,873			(78,485	)
Income taxes		28,085			—			—			28,085

Net income (loss)	$	(50,400	)	$	(69,873	)	$	69,873		$	(50,400	)


Supplemental Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2006
	Parent Company Only			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by operating activities	$	225,000		$	47,074		$	—		$	272,074
Cash flows used in investing activities:
Acquisition of business, net of cash acquired		(420	)		—			—			(420	)
Property acquisitions		(15,897	)		—			—			(15,897	)
Exploration and development expenditures		(294,971	)		(46,965	)		—			(341,936	)
Other property and equipment additions		(527	)		—			—			(527	)
Proceeds from the sale of oil and natural gas assets		—			—			—			—

Net cash used in investing activities		(311,815	)		(46,965	)		—			(358,780	)
Cash flows provided by (used in) financing activities:
Deferred financing costs		(853	)		—			—			(853	)
Repayments of long-term debt		(73,000	)		(109	)		—			(73,109	)
Proceeds from public offering net of commissions		155,000			—			—			155,000
Exercise of stock options and warrants		2,093			—			—			2,093

Net cash provided by (used in) financing activities		83,240			(109	)		—			83,131

Net decrease in cash and cash equivalents		(3,575	)		—			—			(3,575	)
Cash and cash equivalents at the beginning of the period		6,789			—			—			6,789

Cash and cash equivalents at the end of the period	$	3,214		$	—		$	—		$	3,214

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(19) New Accounting Pronouncements

In February 2006, the FASB issued Statement of Financial Accounting Standards No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (Statement 155). Among other changes, Statement 155 eliminates the exemption from applying FASB Statement No. 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. Statement 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Company has assessed the impact of Statement 155 which will not have an impact on the Company’s financial position, results of operations or cash flows.

In March 2006, the FASB issued Statement of Financial Accounting Standards No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140” (Statement 156). Among other changes, Statement 156 requires that all separately recognized servicing assets and servicing liabilities be initially measured at fair value, if practicable. Statement 156 is effective for all fiscal years beginning after September 15, 2006. The Company has assessed the impact of Statement 156 which will not have an impact on the Company’s financial position, results of operations or cash flows.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”. FIN 48 prescribes 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 and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company is assessing the impact of FIN 48 which is not currently expected to have an impact on the Company’s financial position, results of operations or cash flows.

In September 2006, the FASB issued Statement of Accounting Standards No. 157, “Fair Value Measurments” (Statement 157). Statement 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. Statement 157 applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, Statement 157 does not require any new fair value measurements. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is assessing the impact of Statement 157 which is not currently expected to have an impact on the Company’s financial position, results of operations or cash flows.

In September 2006, the FASB issued Statement of Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (Statement 158). Statement 158 improves financial reporting by requiring an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net assets of a not-for-profit organization. Statement 158 also improves financial reporting by requiring an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. An employer with publicly traded equity securities is required to initially recognize the funded status of a defined benefit postretirement plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. Statement 158 will not have an impact on the Company’s financial position, results of operations or cash flows.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(20) Supplementary Oil and Natural Gas Disclosures—(Unaudited)

Our December 31, 2006, 2005 and 2004 estimates of proved reserves are based on reserve reports prepared by Netherland, Sewell & Associates, Inc. and Ryder Scott Company, L.P., independent petroleum engineers. 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, 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 the Company’s net proved reserves, including the changes therein, and proved-developed reserves:


	Crude Oil (Mbbls)		Natural Gas (Mmcf)
Proved-developed and undeveloped reserves:
December 31, 2003	27,414		134,404
Extensions, discoveries and other additions	3,231		67,049
Revisions	1,296		(21,570	)
Production	(3,171	)	(30,048	)

December 31, 2004	28,770		149,835
Purchases of reserves in place	3,949		52,690
Extensions, discoveries and other additions	1,086		24,490
Revisions	587		(27,789	)
Production	(2,914	)	(32,277	)

December 31, 2005	31,478		166,949
Sales of reserves in place	(129	)	(750	)
Extensions, discoveries and other additions	1,057		44,336
Revisions	515		(1,704	)
Production	(3,007	)	(38,708	)

December 31, 2006	29,914		170,123

Proved-developed reserves:
December 31, 2004	24,737		102,760
December 31, 2005	25,646		103,627
December 31, 2006	24,811		117,392

During 2005, the Company revised downward its estimate of proved reserves by a total of approximately 4,045 Mboe. The net downward revision of the Company’s estimates was due to information received from production results and drilling activity that occurred during 2005. Reserves were revised downward by 5,351 Mboe related primarily to the proved undeveloped reserves acquired in the South Louisiana onshore acquisition in January 2005.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Capitalized costs for oil and natural gas producing activities consist of the following:


	2006			2005
	(In thousands)
Proved properties	$	1,478,520		$	1,128,498
Unproved properties		41,353			53,676
Accumulated depreciation, depletion and amortization		(675,556	)		(414,163	)

Net capitalized costs	$	844,317		$	768,011

Costs incurred for oil and natural gas property acquisition, exploration and development activities for the years ended December 31, 2006, 2005 and 2004 are as follows:


	Years Ended December 31,
	2006		2005		2004
	(In thousands)
Acquisitions	$	16,316	$	198,980	$	8,717
Exploration		224,147		171,859		113,278
Development (1)		167,346		114,814		75,732

Costs incurred	$	407,809	$	485,653	$	197,727

(1)	Includes asset retirement obligations incurred of $8.5 million, $6.9 million and $3.5 million for the years ended December 31, 2006, 2005 and 2004, respectively.

Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves

The following information has been developed utilizing procedures prescribed by Statement of Financial Accounting Standards No. 69 (Statement 69), “Disclosures about Oil and Gas Producing Activities”. It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its 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 the Company.

The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will probably differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10% discount rate 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.

Under the Standardized Measure, future cash inflows were estimated by applying, period end oil and gas prices adjusted for each field and the conversion of year end spot prices from Mmbtu to the reported Mcf value, to the estimated future production of period-end proved reserves. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs in order to arrive at net cash flow 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% discount rate is required by Statement 69.

ENERGY PARTNERS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Management does not rely solely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:


	2006			2005			2004
	(In thousands)
Future cash inflows	$	2,688,624		$	3,540,136		$	2,136,571
Future production costs		(700,915	)		(645,025	)		(570,552	)
Future development costs		(355,238	)		(363,949	)		(294,936	)
Future income tax expense		(415,250	)		(770,858	)		(358,421	)

Future net cash flows after income taxes		1,217,220			1,760,304			912,662
10% annual discount for estimated timing of cash flows		323,746			(499,058	)		(244,994	)

Standardized measure of discounted future net cash flows	$	893,474		$	1,261,246		$	667,668

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, 2006, 2005 and 2004 is as follows:


	2006			2005			2004
	(In thousands)
Beginning of the period	$	1,261,246		$	667,668		$	529,415
Sales and transfers of oil and natural gas produced, net of production costs		(379,624	)		(342,396	)		(247,007	)
Net changes in prices and production costs		(648,509	)		861,576			140,169
Extensions, discoveries and improved recoveries, net of future production costs		250,255			145,143			270,223
Revision of quantity estimates		8,316			(160,227	)		(50,384	)
Previously estimated development costs incurred during the period		97,073			33,481			55,893
Purchase and sales of reserves in place		(5,951	)		271,675			—
Changes in estimated future development costs		(28,356	)		143			(7,300	)
Changes in production rates (timing) and other		(91,709	)		(19,764	)		(8,819	)
Accretion of discount		180,618			92,414			70,124
Net change in income taxes		250,115			(288,467	)		(84,646	)

Net increase (decrease)		(367,772	)		593,578			138,523

End of period	$	893,474		$	1,261,246		$	667,668

The computation of the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves at December 31, 2006 was based on period-end prices of $5.53 per Mcf for natural gas and $58.49 per barrel for crude oil. The December 31, 2005 computation was based on period-end prices of $10.31 per Mcf for natural gas and $57.81 per barrel for crude oil. The December 31, 2004 computation was based on period-end prices of $6.23 per Mcf for natural gas and $41.84 per barrel for crude oil. Spot prices as of February 21, 2007 were $7.34 per Mmbtu for natural gas and $60.07 per barrel for crude oil before adjustment for lease quality, transportation fees and price differentials.

Schedule II

VALUATION AND QUALIFYING ACCOUNTS


	Balance at the Beginning of the Year		Additions Charged to Costs and Expenses		Deductions		Balance at the End of the Year
	(In thousands)
Allowance for doubtful accounts:
2004	$	26	$	—	$	26	$	—
2005		—		—		—		—
2006		—		—		—		—

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

None.

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of certain members of our management, including the Chief Executive Officer and Chief Financial Officer, we completed an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based on this evaluation, our Chief Executive Officer and Chief Financial Officer believe that the disclosure controls and procedures were effective as of the end of the period covered by this report with respect to timely communication to them and other members of management responsible for preparing periodic reports and all material information required to be disclosed in this report as it relates to our Company and its consolidated subsidiaries.

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons or by collusion of two or more people. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Accordingly, our disclosure controls and procedures are designed to provide reasonable, not absolute, assurance that the objectives of our disclosure control system are met and, as set forth above, our Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period, that our disclosure controls and procedures were effective to provide reasonable assurance that the objectives of our disclosure control system were met. See Management’s Report on Internal Control Over Financial Reporting and the Report of Independent Registered Public Accounting Firm —Internal Control Over Financial Reporting, which are included herein.

Item 9B. Other Information

None.

PART III

Item 10. Directors and Executive Officers of the Registrant

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 9, 2007, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference, and “Part I—Item 4A. Executive Officers”.

Code of Ethics—The Company has adopted a code of ethics that applies to all directors and employees, including our chief executive officer, chief financial officer and controller which is available on our website at www.eplweb.com. A copy is also available by writing to the Secretary of the Company at 201 St. Charles Avenue, Suite 3400, New Orleans, Louisiana, 70170. The Company will post on its website any waiver the Code of Conduct granted to any of its directors or executive officers.

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 9, 2007, 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

For the 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 9, 2007, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions

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 9, 2007, 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 9, 2007, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Documents to be filed as part of this Report:

1. Financial Statements:

The following financial statements are included in this Report on Form 10-K:

Independent Auditor’s Report

Consolidated Balance Sheets as of December 31, 2006 and 2005

Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004

Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2006, 2005 and 2004

Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004

Notes to the Consolidated Financial Statements

2. Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts.

(b) Exhibits


Exhibit Number		Title
3.1	—	Restated Certificate of Incorporation of Energy Partners, Ltd., dated as of November 16, 1999 (incorporated by reference to Exhibit 3.1 to EPL’s registration statement on Form S-1 (File No. 333-42876)).

3.2	—	Amendment to Restated Certificate of Incorporation of Energy Partners, Ltd., dated as of September 15, 2000 (incorporated by reference to Exhibit 3.2 to EPL’s registration statement on Form S-1 (File No. 333-42876)).

3.3	—	Certificate of Elimination of the Series A Convertible Preferred Stock, Series B Convertible Preferred Stock and Series C Preferred Stock of Energy Partners, Ltd. (incorporated by reference to Exhibit 4.2 of EPL’s Form 8-K filed January 22, 2002).

3.4	—	Certificate of Elimination of the Series D Exchangeable Convertible Preferred Stock of Energy Partners, Ltd. (incorporated by reference to EPL’s Form 10-K filed February 27, 2006).

3.5	—	Amended and Restated Bylaws of Energy Partners, Ltd. (incorporated by reference to Exhibit 3.1 to EPL’s Form 8-K filed September 14, 2006 (File No. 333-42876)).

3.6	—	Amendment to Restated Certificate of Incorporation of Energy Partners, Ltd. dated as of May 5, 2006 (incorporated by reference to Exhibit 3.1 to EPL’s Form 10-Q filed May 9, 2006).

4.1	—	Indenture, dated as of August 5, 2003, among Energy Partners, Ltd., the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to EPL’s Form S-4 filed September 5, 2003 (File No. 333-108540)).

10.2	—	Amended and Restated 2000 Stock Incentive Plan for Non-Employee Directors (incorporated by reference to EPL’s proxy statement on Form 14A filed April 4, 2005 (File No. 001-16179)).


Exhibit Number		Title

10.3	—	Purchase and Sale Agreement by and between Ocean Energy, Inc. and Energy Partners, Ltd. dated as of January 26, 2000 (incorporated by reference to Exhibit 10.18, to EPL’s registration statement on Form S-1 (File No. 333-42876)).

10.4	—	Earnout Agreement dated as of January 15, 2002, by and between Energy Partners, Ltd. and Hall-Houston Oil Company (incorporated by reference to Exhibit 2.5 of EPL’s Form 8-K filed January 22, 2002).

10.5	—	First Amendment to Earnout Agreement between Energy Partners, Ltd. and Participants effective July 1, 2002 (incorporated by reference to Exhibit 10.1 to EPL’s Form 10-Q filed November 13, 2002).

10.6	—	Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to EPL’s proxy statement on Form 14A filed March 27, 2002).

10.7	—	Second Amendment to Earnout Agreement between Energy Partners, Ltd. and Participants effective January 1, 2003 (incorporated by reference to Exhibit 10.12 to EPL’s Form 10-K filed March 9, 2004).

10.8	—	Purchase and Sale Agreement, dated as of December 16, 2004, between Castex Energy 1995, L.P., Castex Energy, Inc., the Company and EPL of Louisiana, L.L.C. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K dated December 16, 2004).

10.9	—	Exploration Agreement, dated as of December 16, 2004, between Castex Energy 1995, L.P., Castex Energy, Inc., the Company and EPL of Louisiana, L.L.C. (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K dated December 16, 2004).

10.10	—	Offer Letter of Mr. Phillip A. Gobe, dated October 19, 2004 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed October 25, 2004.

10.11	—	First Amendment to Energy Partners, Ltd. Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to Exhibit 10.2 of EPL’s Form 10-Q filed August 5, 2004).

10.12	—	Form of Nonqualified Stock Option Grant under the Energy Partners, Ltd. Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to Exhibit 10.3 of EPL’s Form 10-Q filed August 5, 2004).

10.13	—	Form of Restricted Share Unit Agreement under the Energy Partners, Ltd. Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to Exhibit 10.4 of EPL’s Form 10-Q filed August 5, 2004).

10.14	—	Energy Partners, Ltd. Change of Control Severance Plan (incorporated by reference to Exhibit 10.2 of the EPL’s Form 8-K filed March 30, 2005).

10.15	—	Energy Partners, Ltd. Change of Control Severance Agreement (incorporated by reference to Exhibit 10.1 of the EPL’s Form 8-K filed March 30, 2005).

10.16	—	Form of Performance Share Agreement under the Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to Exhibit 10.3 of EPL’s Form 8-K filed March 30, 2005).

10.17	—	Form of Stock Option Grant under the Energy Partners, Ltd. 2000 Stock Option Plan for Non-employee Directors (incorporated by reference to Exhibit 10.5 of EPL’s Form 10-Q filed August 5, 2004).

10.18	—	Fifth Amended and Restated Credit Agreement dated June 2, 2006 (incorporated by reference to Exhibit 99.1 of EPL’s Form 8-K filed June 13, 2006).


Exhibit Number		Title

10.19	—	Offer Letter of Mr. Timothy Woodall, dated July 11, 2006 (incorporated by reference to Exhibit 10.1 to EPL’s Form 8-K filed on August 22, 2006).

10.20	—	Form of Indemnity Agreement (incorporated by reference to Exhibit 10.1 to EPL’s Form 8-K filed on September 14, 2006).

10.21	—	Form of First Amendment to Change of Control Severance Agreement (incorporated by reference to Exhibit 10.2 to EPL’s Form 8-K filed on September 14, 2006).

10.22	—	First Amendment to Energy Partners, Ltd. Change of Control Severance Plan dated September 13, 2006 (incorporated by reference to Exhibit 10.3 to EPL’s Form 8-K filed on September 14, 2006).

10.23	—	Rights Agreement, dated September 14, 2006, between Energy Partners, Ltd. and Mellon Investor Services LLC, as Rights Agent (incorporated by reference to Exhibit 4.1 to EPL’s Form 8-A12B filed on September 14, 2006).

10.24	—	2006 Long Term Stock Incentive Plan (incorporated by reference to EPL’s proxy statement on Form 14A filed April 5, 2006).

10.25*	—	Energy Partners, Ltd. Long Term Stock Incentive Plan Restricted Share Unit Agreement

10.26*	—	Energy Partners, Ltd. 2006 Long Term Stock Incentive Plan

21.1*	—	Subsidiaries of Energy Partners, Ltd.

23.1*	—	Consent of KPMG LLP.

23.2*	—	Consent of Netherland, Sewell & Associates, Inc.

23.3*	—	Consent of Ryder Scott Company, L.P.

31.1*	—	Rule 13a-14a(a)/15d-14(a) Certification of Chairman and Chief Executive Officer of Energy Partners, Ltd.

31.2*	—	Rule 13a-14a(a)/15d-14(a) Certification of Executive Vice President and Chief Financial Officer of Energy Partners, Ltd.

32.0*	—	Section 1350 Certifications.

99.1*	—	Report of Independent Petroleum Engineers dated as of February 16, 2006.

99.2*	—	Report of Independent Petroleum Engineers dated as of February 14, 2006.

*	Filed herewith

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.


ENERGY PARTNERS, LTD.

By:		/s/ RICHARD A. BACHMANN
		Richard A. Bachmann *Chairman and Chief Executive Officer*

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on behalf of the registrant in the capacities and on the date indicated.


Signature	Title	Date

/s/ RICHARD A. BACHMANN Richard A. Bachmann	Chairman and Chief Executive Officer (Principal Executive Officer)	February 28, 2007

/s/ TIMOTHY R. WOODALL Timothy R. Woodall	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 28, 2007

/s/ DINA M. BRACCI RIVIERE Dina M. Bracci Riviere	Controller (Principal Accounting Officer)	February 28, 2007

/s/ JOHN C. BUMGARNER, JR. John C. Bumgarner, Jr.	Director	February 28, 2007

/s/ JERRY D. CARLISLE Jerry D. Carlisle	Director	February 28, 2007

/s/ HAROLD D. CARTER Harold D. Carter	Director	February 28, 2007

/s/ ENOCH L. DAWKINS Enoch L. Dawkins	Director	February 28, 2007

/s/ NORMAN C. FRANCIS Norman C. Francis	Director	February 28, 2007

/s/ ROBERT D. GERSHEN Robert D. Gershen	Director	February 28, 2007

/s/ PHILLIP A. GOBE Phillip A. Gobe	President, Chief Operating Officer and Director	February 28, 2007

/s/ WILLIAM R. HERRIN, JR. William R. Herrin, Jr.	Director	February 28, 2007

/s/ WILLIAM O. HILTZ William O. Hiltz	Director	February 28, 2007

/s/ JOHN G. PHILLIPS John G. Phillips	Director	February 28, 2007

INDEX TO EXHIBITS


Exhibit Number		Title
3.1	—	Restated Certificate of Incorporation of Energy Partners, Ltd., dated as of November 16, 1999 (incorporated by reference to Exhibit 3.1 to EPL’s registration statement on Form S-1 (File No. 333-42876)).

3.2	—	Amendment to Restated Certificate of Incorporation of Energy Partners, Ltd., dated as of September 15, 2000 (incorporated by reference to Exhibit 3.2 to EPL’s registration statement on Form S-1 (File No. 333-42876)).

3.3	—	Certificate of Elimination of the Series A Convertible Preferred Stock, Series B Convertible Preferred Stock and Series C Preferred Stock of Energy Partners, Ltd. (incorporated by reference to Exhibit 4.2 of EPL’s Form 8-K filed January 22, 2002).

3.4	—	Certificate of Elimination of the Series D Exchangeable Convertible Preferred Stock of Energy Partners, Ltd. (incorporated by reference to EPL’s Form 10-K filed February 27, 2006).

3.5	—	Amended and Restated Bylaws of Energy Partners, Ltd. (incorporated by reference to Exhibit 3.1 to EPL’s Form 8-K filed September 14, 2006 (File No. 333-42876)).

3.6	—	Amendment to Restated Certificate of Incorporation of Energy Partners, Ltd. dated as of May 5, 2006 (incorporated by reference to Exhibit 3.1 to EPL’s Form 10-Q filed May 9, 2006).

4.1	—	Indenture, dated as of August 5, 2003, among Energy Partners, Ltd., the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to EPL’s Form S-4 filed September 5, 2003 (File No. 333-108540)).

10.2	—	Amended and Restated 2000 Stock Incentive Plan for Non-Employee Directors (incorporated by reference to EPL’s proxy statement on Form 14A filed April 4, 2005 (File No. 001-16179)).

10.3	—	Purchase and Sale Agreement by and between Ocean Energy, Inc. and Energy Partners, Ltd. dated as of January 26, 2000 (incorporated by reference to Exhibit 10.18, to EPL’s registration statement on Form S-1 (File No. 333-42876)).

10.4	—	Earnout Agreement dated as of January 15, 2002, by and between Energy Partners, Ltd. and Hall-Houston Oil Company (incorporated by reference to Exhibit 2.5 of EPL’s Form 8-K filed January 22, 2002).

10.5	—	First Amendment to Earnout Agreement between Energy Partners, Ltd. and Participants effective July 1, 2002 (incorporated by reference to Exhibit 10.1 to EPL’s Form 10-Q filed November 13, 2002).

10.6	—	Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to EPL’s proxy statement on Form 14A filed March 27, 2002).

10.7	—	Second Amendment to Earnout Agreement between Energy Partners, Ltd. and Participants effective January 1, 2003 (incorporated by reference to Exhibit 10.12 to EPL’s Form 10-K filed March 9, 2004).

10.8	—	Purchase and Sale Agreement, dated as of December 16, 2004, between Castex Energy 1995, L.P., Castex Energy, Inc., the Company and EPL of Louisiana, L.L.C. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K dated December 16, 2004).

10.9	—	Exploration Agreement, dated as of December 16, 2004, between Castex Energy 1995, L.P., Castex Energy, Inc., the Company and EPL of Louisiana, L.L.C. (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K dated December 16, 2004).


Exhibit Number		Title
10.10	—	Offer Letter of Mr. Phillip A. Gobe, dated October 19, 2004 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed October 25, 2004.

10.11	—	First Amendment to Energy Partners, Ltd. Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to Exhibit 10.2 of EPL’s Form 10-Q filed August 5, 2004).

10.12	—	Form of Nonqualified Stock Option Grant under the Energy Partners, Ltd. Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to Exhibit 10.3 of EPL’s Form 10-Q filed August 5, 2004).

10.13	—	Form of Restricted Share Unit Agreement under the Energy Partners, Ltd. Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to Exhibit 10.4 of EPL’s Form 10-Q filed August 5, 2004).

10.14	—	Energy Partners, Ltd. Change of Control Severance Plan (incorporated by reference to Exhibit 10.2 of the EPL’s Form 8-K filed March 30, 2005).

10.15	—	Energy Partners, Ltd. Change of Control Severance Agreement (incorporated by reference to Exhibit 10.1 of the EPL’s Form 8-K filed March 30, 2005).

10.16	—	Form of Performance Share Agreement under the Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to Exhibit 10.3 of EPL’s Form 8-K filed March 30, 2005).

10.17	—	Form of Stock Option Grant under the Energy Partners, Ltd. 2000 Stock Option Plan for Non-employee Directors (incorporated by reference to Exhibit 10.5 of EPL’s Form 10-Q filed August 5, 2004).

10.18	—	Fifth Amended and Restated Credit Agreement dated June 2, 2006 (incorporated by reference to Exhibit 99.1 of EPL’s Form 8-K filed June 13, 2006).

10.19	—	Offer Letter of Mr. Timothy Woodall, dated July 11, 2006 (incorporated by reference to Exhibit 10.1 to EPL’s Form 8-K filed on August 22, 2006).

10.20	—	Form of Indemnity Agreement (incorporated by reference to Exhibit 10.1 to EPL’s Form 8-K filed on September 14, 2006).

10.21	—	Form of First Amendment to Change of Control Severance Agreement (incorporated by reference to Exhibit 10.2 to EPL’s Form 8-K filed on September 14, 2006).

10.22	—	First Amendment to Energy Partners, Ltd. Change of Control Severance Plan dated September 13, 2006 (incorporated by reference to Exhibit 10.3 to EPL’s Form 8-K filed on September 14, 2006).

10.23	—	Rights Agreement, dated September 14, 2006, between Energy Partners, Ltd. and Mellon Investor Services LLC, as Rights Agent (incorporated by reference to Exhibit 4.1 to EPL’s Form 8-A12B filed on September 14, 2006).

10.24	—	2006 Long Term Stock Incentive Plan (incorporated by reference to EPL’s proxy statement on Form 14A filed April 5, 2006).

10.25*	—	Energy Partners, Ltd. Long Term Stock Incentive Plan Restricted Share Unit Agreement

10.26*	—	Energy Partners, Ltd. 2006 Long Term Stock Incentive Plan

21.1*	—	Subsidiaries of Energy Partners, Ltd.

23.1*	—	Consent of KPMG LLP.


Exhibit Number		Title
23.2*	—	Consent of Netherland, Sewell & Associates, Inc.

23.3*	—	Consent of Ryder Scott Company, L.P.

31.1*	—	Rule 13a-14a(a)/15d-14(a) Certification of Chairman and Chief Executive Officer of Energy Partners, Ltd.

31.2*	—	Rule 13a-14a(a)/15d-14(a) Certification of Executive Vice President and Chief Financial Officer of Energy Partners, Ltd.

32.0*	—	Section 1350 Certifications.

99.1*	—	Report of Independent Petroleum Engineers dated as of February 16, 2006.

99.2*	—	Report of Independent Petroleum Engineers dated as of February 14, 2006.

*	Filed herewith