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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
 
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2005
    or
o
  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
(Address of principal executive offices)
  70170
(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
 
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 þ     No o
 
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 o     No þ
 
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 þ     No o
 
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.  þ
 
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 þ     Accelerated filer o     Non-accelerated filer o
 
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act).  Yes o     No þ
 
The aggregate market value of the common stock held by non-affiliates of the registrant at June 30, 2005 based on the closing price of such stock as quoted on the New York Stock Exchange on that date was $877,972,594.
 
As of February 22, 2006 there were 38,017,698 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 2006 Annual Meeting of Stockholders have been incorporated by reference into Part III of this Form 10-K.
 


 

 
TABLE OF CONTENTS
 
             
        Page
 
  Business and Properties   3
  Risk Factors   14
  Unresolved Staff Comments   19
  Legal Proceedings   19
  Submission of Matters to a Vote of Security Holders   19
  Executive Officers of the Registrant   19
 
  Market for the Registrant’s Common Stock and Related Stockholder Matters   20
  Selected Financial Data   21
  Management’s Discussion and Analysis of Financial Condition and Results of Operations   22
  Quantitative and Qualitative Disclosures about Market Risk   34
  Financial Statements and Supplementary Data   36
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   66
  Controls and Procedures   66
  Other Information   66
 
  Directors and Executive Officers of the Registrant   67
  Executive Compensation   67
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   67
  Certain Relationships and Related Transactions   67
  Principal Accountant Fees and Services   67
 
  Exhibits and Financial Statement Schedules   67
 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, President and CEO
 Rule 13a-14a/15d-14a Certification of Executive VP and CFO
 Section 1350 Certifications
 Report of Independent Petroleum Engineers dated February 14, 2006
 Report of Independent Petroleum Engineers dated February 7, 2006


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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 shallow to moderate depth waters of the Gulf of Mexico Shelf and the Gulf Coast onshore regions and, as a result of an acquisition of undeveloped acreage in early 2006, the deepwater Gulf of Mexico. 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 these regions offer 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, 2005, we had estimated proved reserves of approximately 166.9 Bcf of natural gas and 31.5 Mmbbls of oil, or an aggregate of approximately 59.3 Mmboe, with a present value of estimated pre-tax future net cash flows of $1.8 billion, and a standardized measure of discounted future net cash flows of $1.3 billion.
 
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 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 reserves and production 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 web site and the information contained in it and connected to it shall not be deemed incorporated by reference into this Report on Form 10-K.
 
Acquisition of South Louisiana Reserves and Prospects
 
On January 20, 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, with estimated acquisition date proved reserves of 51.2 Bcfe. Also included were interests in


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22 exploratory prospects. The transaction expanded the exploration opportunities in our expanded focus area. Concurrent with the closing, our bank credit facility borrowing base was increased to $150 million, of which $60 million was drawn to fund the acquisition. In connection with the acquisition, we 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. We intend to continue to explore and develop oil and natural gas reserves in the AMI over the two year term jointly with the seller. The proved reserves acquired from the seller, prospects and the AMI are in the southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.
 
Exploration and Development Expenditures
 
Our exploration and development expenditures for 2005 totaled $478.7 million inclusive of a $0.9 million contingent consideration payment to former stockholders of a company acquired in 2002 and $170.5 million related to acquisitions in 2005. For 2006, we have budgeted exploration and development expenditures of $360 million. The drilling portfolio, both onshore and offshore, includes a mixture of lower risk development and exploitation wells, moderate risk exploration opportunities and higher risk, higher potential exploration projects. Our 2006 budget does not include any acquisitions of proved reserves that may occur during the year.
 
Our Properties
 
At December 31, 2005, we had interests in 38 producing fields and 5 fields under development all of which are located in the Gulf of Mexico Shelf and the Gulf Coast onshore regions (the “Gulf of Mexico Region”). These fields fall into four focus areas which we identify as our Eastern, Central and Western 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 21 producing fields. Our Gulf Coast onshore area is located in South Louisiana, with nine 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 171 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 47,307 gross acres (45,403 net acres) at the end of 2005. Our Eastern offshore area operations accounted for approximately 21% of our net daily production during 2005.
 
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 currently undeveloped reserves in the South Timbalier 46 field. Our Central offshore area operations accounted for approximately 40% of our net daily production during 2005.
 
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 have been drilled in the field and all have been successful. Four of these wells have been brought on production and an additional development well was drilled in early 2006. This field, in which additional reserve potential is yet to be tested, represents the most significant discovery in our


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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. On March 8, 2005, we closed the acquisition of the remaining 50% interest in South Timbalier 26 above 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 expands our interest in our core Greater Bay Marchand area and gives us additional flexibility in undertaking the future development of the South Timbalier 26 field. We have interests in 12 producing wells in this field.
 
Western Offshore Area
 
The properties in the Western offshore area are located in water depths ranging from 20 to 476 feet with working interests ranging from 17% to 100%. We owned interests in 25 fields in this area at December 31, 2005, 21 of which were producing fields with another four under development. Our Western offshore area operations accounted for approximately 25% of our net daily production during 2005.
 
Gulf Coast Onshore Area
 
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 nine producing fields in this area at December 31, 2005. Our Gulf Coast onshore area operations accounted for approximately 14% of our net daily production during 2005.
 
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, 2005, 2004 and 2003. The December 31, 2005, 2004 and 2003 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,  
    2005     2004     2003  
 
Total estimated net proved reserves(1):
                       
Oil (Mbbls)
    31,478       28,770       27,414  
Natural gas (Mmcf)
    166,949       149,835       134,404  
Total (Mboe)
    59,303       53,743       49,815  
Net proved developed reserves(2):
                       
Oil (Mbbls)
    25,656       24,737       22,306  
Natural gas (Mmcf)
    103,627       102,760       71,531  
Total (Mboe)
    42,917       41,864       34,228  
Estimated future net revenues before income taxes (in thousands)(3)
  $ 2,531,166     $ 1,271,083     $ 967,449  
Present value of estimated future net revenues before income taxes (in thousands)(3) (4)
  $ 1,806,185     $ 924,135     $ 701,237  
Standardized measure of discounted future net cash flows
(in thousands)(5)
  $ 1,261,246     $ 667,668     $ 529,415  
 
 
(1) Approximately 82% of our total proved reserves were proved undeveloped and proved developed non-producing at December 31, 2005.
 
(2) Net proved developed non-producing reserves as of December 31, 2005 were 19,884 Mbbls and 72,420 Mmcf.


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(3) 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, while 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 and the December 31, 2003 amount was calculated using a period-end oil price of $30.88 per barrel and a period-end natural gas price of $6.15 per Mcf.
 
(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,  
    2005     2004     2003  
    (In thousands)  
 
Business combinations:
                       
Proved properties
  $ 142,025     $ 2,166     $ 850  
Unproved properties
    29,333              
                         
Total business combinations
    171,358       2,166       850  
Lease acquisitions
    27,622       6,551       6,030  
Exploration
    171,859       113,278       60,170  
Development(1)
    114,814       75,732       49,013  
                         
Costs incurred
  $ 485,653     $ 197,727     $ 116,063  
                         
 
 
(1) Includes asset retirement obligations incurred of $6.9 million, $3.5 million and $3.3 million for the years ended December 31, 2005, 2004 and 2003, 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, 2005:
 
                 
    Total
 
    Productive
 
    Wells  
    Gross     Net  
 
Oil
    266       201  
Natural gas
    118       58  
                 
Total
    384       259  
                 
 
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. Seventeen gross oil wells and eight gross natural gas wells have dual completions.


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Acreage
 
The following table sets forth information as of December 31, 2005 relating to acreage held by us. Developed acreage is assigned to producing wells.
 
                 
    Gross
    Net
 
    Acreage     Acreage  
 
Developed:
               
Eastern area
    32,229       30,988  
Central area
    38,840       24,206  
Western area
    131,214       80,427  
Gulf Coast onshore area
    6,496       2,786  
                 
Total
    208,779       138,407  
                 
Undeveloped:
               
Eastern area
    15,078       14,415  
Central area
    39,240       38,139  
Western area
    170,159       123,110  
Gulf Coast onshore area
    7,070       2,527  
                 
Total
    231,547       178,191  
                 
 
Leases covering 12% of our undeveloped net acreage will expire in 2006, approximately 6% in 2007, 5% in 2008, 24% in 2009, 46% in 2010 and 7% thereafter.
 
Well Activity
 
The following table shows our well activity for the years ended December 31, 2005, 2004 and 2003. 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,  
    2005     2004     2003  
    Gross     Net     Gross     Net     Gross     Net  
 
Development Wells:
                                               
Productive
    8.0       4.7       5.0       3.2       1.0       0.3  
Non-productive
    3.0       1.1       2.0       2.0       1.0       1.0  
                                                 
Total
    11.0       5.8       7.0       5.2       2.0       1.3  
                                                 
Exploration Wells:
                                               
Productive
    30.0       15.3       19.0       12.3       15.0       8.4  
Non-productive
    17.0       9.3       5.0       2.2       4.0       2.2  
                                                 
Total
    47.0       24.6       24.0       14.5       19.0       10.6  
                                                 
 
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.


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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. While sales by producers of natural gas can currently be made at unregulated market prices, Congress could reenact price controls in the future. 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.
 
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 revised FERC pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and 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”), which FERC implements as to transportation and pipeline issues, requires that all pipelines operating on or across the outer continental shelf (“OCS”) provide open access, non-discriminatory transportation service. 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. The U.S. Minerals Management Service (“MMS”) also 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 currently is contemplating rulemaking to amend its regulations to better ensure such access for OCS shippers.
 
It should be noted that FERC currently is considering 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


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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 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 and our working interest partner in South Timbalier 26. 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.


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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 plugging and abandonment of wells. Many states also restrict production to the market demand for oil and natural gas, and states have indicated interest in revising applicable regulations. 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. 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


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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


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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.


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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. A majority of 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


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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-sensitive prices. Our purchasers of oil and condensate include Chevron Products Company (“Chevron”) and Shell. Currently, the most significant purchaser of our natural gas production is Louis Dreyfus Energy Services, L.P. (“Dreyfus”). 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 2005, Dreyfus accounted for approximately 18%, Shell 16%, Bridgeline Holdings, L.P. 15% and Chevron 10%.
 
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, 2005, we had 170 full-time employees, including 45 geoscientists, engineers and technicians and 63 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, 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


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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, such as stuck oil field drilling and service tools and casing collapse;
 
  •  fires and explosions;
 
  •  personal injuries and death; and
 
  •  natural disasters, especially hurricanes and tropical storms in the Gulf of Mexico.
 
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, 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;


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  •  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 2005, 39% of our net daily production came from our Greater Bay Marchand area and approximately 40% of our proved reserves were located in the fields that comprise this area. In addition, 20% of our net daily production came from our East Bay field and approximately 34% of our proved reserves were located on this


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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 regions 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, 2005, our independent petroleum engineers estimate, on average, 65% 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 in areas where the rate of reserve production is lower. 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 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


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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 or 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 increase again or that necessary equipment and services will be available to us at economical prices.
 
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 act by written consent and to present proposals or make nominations at stockholder meetings.
 
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.
 
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.


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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
 
In the ordinary course of business, we are a defendant in various legal proceedings. We do not expect our exposure in these proceedings, individually or in the aggregate, to have a material adverse effect on our financial position, results of operations or liquidity.
 
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
  61   Chairman and Chief Executive Officer
Phillip A. Gobe
  53   Director, President and Chief Operating Officer
David R. Looney
  49   Executive Vice President and Chief Financial Officer
John H. Peper
  53   Executive Vice President, General Counsel and Corporate Secretary
T. Rodney Dykes
  49   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 29 years of energy industry experience and was with


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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.
 
David R. Looney joined us in February 2005 and was elected executive vice president and chief financial officer in March 2005. Prior to joining us Mr. Looney had been with EOG Resources Inc. (“EOG”), where he served as Vice President, Finance, a position he had held since 1999. In that role his responsibilities included all finance and treasury functions including managing external relationships with investment banks, commercial banks and the rating agencies. Mr. Looney joined EOG in 1998 as Assistant Treasurer after holding a variety of financial roles at firms including Toronto-Dominion Bank and Chase Manhattan Bank.
 
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  
 
2004
               
First Quarter
  $ 14.81     $ 12.60  
Second Quarter
    15.45       12.60  
Third Quarter
    16.59       14.00  
Fourth Quarter
    20.91       16.07  
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 (through February 22, 2006)
    28.68       22.00  
 
On February 22, 2006 the last reported sale price of our common stock on the New York Stock Exchange was $23.89 per share.


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As of February 22, 2006 there were approximately 125 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.
 
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,  
    2005     2004     2003     2002     2001  
    (In thousands, except per share data)  
 
Statement of Operations Data:
                                       
Revenue
  $ 402,947     $ 295,210     $ 230,187     $ 133,788     $ 146,240  
Income (loss) from operations(1)
    132,027       86,068       58,560       (6,600 )     20,663  
Net income (loss)(2)
    73,095       46,416       33,250       (8,799 )     11,974  
Net income (loss) available to common stockholders(3)
    72,151       43,017       29,705       (12,129 )     11,974  
Basic net income (loss) per common share
  $ 1.94     $ 1.31     $ 0.96     $ (0.44 )   $ 0.45  
Diluted net income (loss) per common share
  $ 1.79     $ 1.20     $ 0.93     $ (0.44 )   $ 0.44  
Cash flows provided by (used in):
                                       
Operating activities
  $ 269,969     $ 165,074     $ 136,702     $ 25,417     $ 91,847  
Investing activities
    (449,159 )     (176,713 )     (110,057 )     (54,380 )     (121,067 )
Financing activities
    92,442       784       77,631       29,079       25,871  
 
                                         
    As of December 31,  
    2005     2004     2003     2002     2001  
    (In thousands)  
 
Balance Sheet Data:
                                       
Total assets
  $ 931,285     $ 647,678     $ 544,181     $ 384,220     $ 242,777  
Long-term debt, excluding current maturities
    235,000       150,109       150,317       103,687       25,408  
Stockholders’ equity
    394,593       315,049       261,485       191,922       164,867  
Cash dividends per common share
                             
 
 
(1) The 2005 income from operations includes accrued business interruption insurance recoveries of $20.6 million from deferred production at four of our 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.


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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Overview
 
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 shallow to moderate depth waters of the Gulf of Mexico Shelf and contiguous Gulf Coast onshore region.
 
While the impacts of Hurricanes Katrina, Rita, Cindy, Dennis and Emily (the “Tropical Weather”) were significant to 2005, we still made 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. Our strong cash flow provided us the flexibility to make necessary and appropriate investments to continue this growth strategy. 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 Shelf and onshore Gulf Coast regions and, as a result of an acquisition of undeveloped acreage in early 2006, the deepwater Gulf of Mexico. 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 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. 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.
 
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 contingent consideration paid will be capitalized as additional purchase price.
 
On April 16, 2003, we completed the public offering of approximately 4.2 million shares of our common stock priced at $9.50 per share. The equity offering also included shares offered by our then principal stockholder, Evercore Capital Partners, L.P. and certain of its affiliates (“Evercore”), and by Energy Income Fund, L.P. (“EIF”). After payment of underwriting discounts and commissions, the offering generated net proceeds to us of approximately $38.0 million. After expenses of approximately $0.5 million, the proceeds were used to repay a portion of outstanding borrowings under our bank credit facility.
 
On August 5, 2003, we 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 and non-U.S. purchasers. After discounts and commissions and all offering expenses, we received $145.3 million, which was used to redeem all of our outstanding 11% Senior Subordinated Notes due 2009 (the “11% Notes”) and to repay substantially all of the borrowings outstanding under our bank credit facility. The remainder of the net proceeds was set aside for general corporate purposes, including acquisitions. In October 2003, we consummated an exchange offer pursuant to which we exchanged registered Senior Notes having substantially identical terms as the Senior Notes for the privately placed Senior Notes.
 
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


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Statement. Concurrent with this offering, we entered into a stock purchase agreement with EIF 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. We have no immediate plans to enter into any additional transactions under the Registration Statement, but plan to use the proceeds of any future offering under the Registration Statement for general corporate purposes, which may include debt repayment, acquisitions, expansion and working capital.
 
On August 3, 2004 we amended and extended to August 3, 2008 our bank credit facility. The borrowing base was increased to $150 million at the time of our purchase of south Louisiana properties and reserves in January 2005. At December 31, 2005 we had $85 million outstanding under our bank credit facility. The borrowing base 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. Our borrowing base was reaffirmed effective November 1, 2005.
 
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 acquisition was composed of nine fields, four of which were producing at the time of the closing through 14 wells, with estimated acquisition date proved reserves of 51.2 billion cubic feet equivalent. Also included were interests in 22 exploratory prospects. The transaction expanded the exploration opportunities in our expanded focus area. 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, and concurrent with the closing, the borrowing base under our bank credit facility was increased to $150 million, of which $60 million was drawn to fund the acquisition. In connection with the acquisition, we also entered into a two-year agreement with the seller of the properties that defined an area of mutual interest (“AMI”) encompassing over one million acres. We intend to continue to explore and develop oil and natural gas reserves in the AMI over the two year term jointly with the seller. The proved reserves, prospects and the AMI are in the southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.
 
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.
 
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 below. For the foregoing reasons these acquisitions will affect the comparability of our historical results of operations with future periods.
 
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 and a portion of that production had not yet been restored by the end of the fourth quarter of 2005. We are continuing to work to bring operations back to pre-storm levels, but are subject to constraints due to damage to third party infrastructure. 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 two other fields began accruing in October while recovery on a fourth field began accruing in December. Through December 31, 2005 we had accrued $20.6 million for business interruption. Production was fully restored


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in three of these fields in 2005, at which time coverage ceased, and recoveries will continue to accrue on one other until production is fully restored, subject to policy limits that we do not expect, at this time, to be reached.
 
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. Despite our expanded budget of $360 million in 2006, strong commodity prices, together with growing production volumes, should enable us to adhere to our policy of funding our exploration and development expenditures with internally generated cash flow. This strategy allows us to preserve our strong balance sheet to finance acquisitions and other capital intensive projects that might result from our exploration and development activities. We believe that the near term may provide us with further opportunities to acquire targeted properties, including those within our focus area.
 
Results of Operations
 
The following table presents information about our oil and natural gas operations.
 
                         
    Years Ended December 31,  
    2005     2004     2003  
 
Net production (per day):
                       
Oil (Bbls)
    7,984       8,663       7,978  
Natural gas (Mcf)
    88,430       82,098       78,596  
Total (Boe)
    22,722       22,346       21,077  
Oil & natural gas revenues (in thousands):
                       
Oil
  $ 135,359     $ 111,006     $ 81,599  
Natural gas
    266,646       183,525       148,104  
Total
    402,005       294,531       229,703  
Average sales prices, net of hedging:
                       
Oil (per Bbl)
  $ 46.45     $ 35.01     $ 28.02  
Natural gas (per Mcf)
    8.26       6.11       5.16  
Total (per Boe)
    48.47       36.01       29.86  
Impact of hedging:
                       
Oil (per Bbl)
  $ (3.15 )   $ (4.40 )   $ (1.67 )
Natural gas (per Mcf)
    (0.24 )     (0.04 )     (0.23 )
Average costs (per Boe):
                       
Lease operating expense
  $ 6.08     $ 4.93     $ 4.76  
Taxes, other than on earnings
    1.25       1.13       0.99  
Depreciation, depletion and amortization
    12.50       11.29       10.65  
Increase in oil and natural gas revenue (net of hedging) due to:
                       
Change in prices of oil
  $ 35,863     $ 22,160          
Change in production volumes of oil
    (11,510 )     7,247          
Total increase in oil sales
    24,353       29,407          
Change in prices of natural gas
  $ 64,006     $ 28,396          
Change in production volumes of natural gas
    19,115       7,025          
Total increase in natural gas sales
    83,121       35,421          
 


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    As of December 31,  
    2005     2004     2003  
 
Total estimated net proved reserves:
                       
Oil (Mbbls)
    31,478       28,770       27,414  
Natural gas (Mmcf)
    166,949       149,835       134,404  
Total (Mboe)
    59,303       53,743       49,815  
Present value of estimated future net cash flows before income taxes (in thousands)
  $ 1,806,185     $ 924,135     $ 701,237  
Standardized measure of discounted future net cash flows (in thousands)
  $ 1,261,246     $ 667,668     $ 529,415  
 
Revenues and Net Income
 
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 is $20.6 million of accrued business interruption insurance recoveries from deferred production at four of our fields resulting from Hurricanes Katrina and Rita.
 
Our oil and natural gas revenues increased to $294.5 million in 2004 from $229.7 million in 2003. In 2004, the oil and natural gas industry experienced then record high oil prices as well as sustained high natural gas prices. The increase in revenue for this period is the result of these significantly increased natural gas and oil prices combined with increased production resulting primarily from the commencement of production from 20 new wells brought on production since year end 2003, 16 of which were natural gas. These increases were partially offset by natural reservoir declines. In addition, volumes were negatively affected by Hurricane Ivan and Tropical Storm Matthew.
 
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. We recognized net income of $46.4 million in 2004 compared to net income of $33.3 million in 2003. The increase in net income in 2004 was primarily due to the increase in oil and natural gas revenues previously discussed and partially offset by higher operating costs, as discussed below.
 
While our 2005 results were strong, we did not achieve the sequential growth in volumes that we anticipated due to downtime from the Tropical Weather during the second half of the year.
 
Operating Expenses
 
Operating expenses were impacted by the following:
 
  •  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.
 
Lease operating expense increased $3.6 million to $40.3 million in 2004. This is a result of the addition of production from new fields and $1.0 million related to the retained loss portion of repairs due to Hurricane Ivan.

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  •  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 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.
 
Taxes, other than on earnings increased $1.6 million to $9.3 million in 2004. This increase was due to the increase in commodity prices received for our oil and natural gas production on state leases, primarily at East Bay and Bay Marchand, which are subject to Louisiana severance taxes. These taxes are expected to fluctuate from period to period depending on our production volumes from state leases and the commodity prices received.
 
  •  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.
 
Exploration expenditures increased $14.4 million to $29.0 million in 2004. The expense in 2004 was comprised of $21.0 million of costs for exploratory wells or portions thereof which were found to be not commercially productive and seismic expenditures and delay rentals of $8.0 million.
 
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.
 
  •  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.
 
Impairment of properties increased $4.1 million to $6.9 million in 2004. The expense in 2004 was comprised of a property impairment at our East Cameron 378 field.
 
  •  Depreciation, depletion and amortization increased $11.2 million to $103.6 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.
 
Depreciation, depletion and amortization increased $10.5 million to $92.4 million in 2004. The increase was due to the increased depreciable asset base combined with higher production and a shift in the production contribution from our various fields. This expense includes $6.6 million of amortization for our asset retirement obligation for 2004 as compared to $5.2 million in 2003. In addition, the shift in the production contribution amongst our various fields increased 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 $8.5 million to $36.4 million in 2005. 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 general and administrative expenses increased $1.2 million to $27.9 million in 2004. The increase was primarily due to increased consulting costs of $1.9 million, of which $0.4 million was increased costs paid to our internal audit service provider and external auditors to implement the requirements of Section 404 of the


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Sarbanes-Oxley Act of 2002. The remainder included increased human resources, land and engineering consulting costs which was offset by decreased casualty insurance and technology costs.
 
  •  Non-cash stock-based compensation expense of $6.8 million was recognized in 2005, an increase of $3.7 million from 2004. The increased expense relates to the increased amortization of new restricted share units and performance share awards made to employees in late 2004 and in 2005 as well as the impact of the increased stock price throughout most of the year on our variable awards and accelerated vesting of stock awards for two former employees.
 
Non-cash stock-based compensation expense of $3.1 million was recognized in 2004, an increase of $1.8 million from 2003. This expense has increased due to additional grants of restricted share units and performance share awards to employees. The level of expense for these awards is also affected by the increased stock price in 2004.
 
Other Income and Expense
 
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.
 
Interest expense increased $4.2 million to $14.4 million in 2004. The increase was a result of interest expense on the Senior Notes issued in August 2003 partially offset by the interest savings from the redemption of the 11% Notes and the repayment of borrowings under the bank facility in 2003.
 
Financial Condition, Liquidity and Capital Resources
 
The trend of increased revenues we have experienced in 2005 has continued to provide strong cash flows from operations, which totaled $270.0 million. 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, 2005 was $6.8 million. Our future internally generated cash flows will depend on our ability to maintain and increase production through our exploration and development drilling 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 August 3, 2004, consists of a revolving line of credit with a group of banks available through August 3, 2008 (the “bank credit facility”). The bank credit facility currently has a borrowing base of $150 million that is 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 1.25% to 2.00% above LIBOR and 0% to 0.75% above prime. The borrowing base under the bank credit facility is secured by substantially all of our assets. We used our bank credit facility to fund a portion of the purchase of the south Louisiana properties in January 2005 and the acquisition of the additional interest in South Timbalier 26 in March 2005. At February 22, 2006, we had $95 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 0.375% 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 1.0 and (ii) maintain a minimum EBITDAX to interest ratio, as defined by our bank credit facility, of 3.5 times. We were in compliance with these covenants as of December 31, 2005.
 
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


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unpaid interest, if any, plus a specified premium which decreases yearly from 4.375% in 2007 to 0% in 2009 and thereafter. In addition, at any time prior to August 1, 2006, we may redeem up to a maximum of 35% of the aggregate principal amount with the net proceeds of certain equity offerings at a price equal to 108.75% of the principal amount, plus accrued and unpaid interest. 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.
 
Upon closing on the Senior Notes on August 5, 2003, we called our 11% Notes due 2009 for redemption. The redemption of the 11% Notes in aggregate principal and accrued interest was funded with a portion of the proceeds received from the Senior Notes and was completed in August 2003. The 11% Notes were issued on January 15, 2002 as part of the financing of an acquisition. In addition, $39.9 million of the proceeds from the Senior Notes were used to re-pay substantially all of the borrowings under the bank credit facility. As a result of the issuance of the Senior Notes, our bank credit facility borrowing base was reduced from $100 million to $60 million requiring a non-cash charge of $0.3 million for the write-off of the pro rata remaining balance of unamortized issue costs.
 
Net cash of $449.2 million used in investing activities in 2005 primarily included $254.9 million of oil and natural gas property capital and exploration expenditures and $193.1 million for property acquisitions which included the acquisitions of properties and reserves onshore in south Louisiana, the acquisition of the remaining 50% gross working interest in South Timbalier 26 and $27.6 million of lease acquisitions. Exploration expenditures incurred are excluded from operating cash flows and included in investing activities. During 2005, we completed 56 drilling projects and 32 recompletion/workover projects, 60 of which were successful. During 2004, we completed 31 drilling projects and 21 recompletion/workover projects, 41 of which were successful.
 
Our 2006 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 exploration opportunities and higher risk, higher potential exploration opportunities. Our exploration and development budget for 2006 is currently $360 million. We do not budget for acquisitions. During 2005, capital and exploration expenditures were approximately $485.7 million inclusive of a $0.9 million contingent consideration payment resulting from an acquisition completed during 2002, $170.5 million related to acquisitions in 2005 and $6.9 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 2006 capital expenditures.
 
We have experienced and expect to continue to experience substantial working capital requirements, primarily due to our active exploration and development program. 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.


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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, 2005:
 
                                         
    Payments Due by Period  
          Less Than
                   
    Total     1 Year     1-3 Years     3-5 Years     Thereafter  
    (In thousands)  
 
Long-term debt
  $ 235,109     $ 109     $ 85,000     $ 150,000     $  
Interest attributable to all long-term debt
    68,231       18,282       29,258       20,781        
Operating leases
    17,764       3,074       4,161       2,826       7,703  
Unconditional purchase obligations(1)
    58,367       52,367       6,000              
Other long-term liabilities
    11,213             9,842             1,371  
                                         
Total contractual obligations
  $ 390,684     $ 73,832     $ 134,261     $ 173,607     $ 9,074  
                                         
 
 
(1) Consists of commitments to purchase seismic related services and drilling rig commitments.
 
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.
 
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, 2005:
 
                                 
Natural Gas Positions  
          Strike Price
    Volume (Mmbtu)  
Remaining Contract Term
  Contract Type     ($/Mmbtu)     Daily     Total  
 
01/06 - 12/06
    Collar     $ 5.00/$9.51       15,000       5,475,000  
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


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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, 2005 approximated 8% 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 91 exploration wells, of which 26 were considered dry holes. Our dry hole costs charged to expense during this period totaled $82.9 million out of total exploratory drilling costs of $345.3 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.
 
Our 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


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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, 2005, proved oil and natural gas reserves were 59.3 million barrels of oil-equivalent (“Mmboe”). Approximately 82% 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 28% of total proved reserves are categorized as proved undeveloped reserves. As of December 31, 2005, 47% 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 outside 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, 2005 was based on period-end prices of $10.31 per Mcf for natural gas and $57.81 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 individual or contiguous properties or projects 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) applied to (3) 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 over the three years prior to the 2005 fiscal year, 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. 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


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  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 $17.9 million, $6.9 million and $2.8 million in the years ending December 31, 2005, 2004 and 2003. The impairment in 2005 consisted of full impairment at six fields which we determined would need significant capital to extend their economic lives. 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. Two fields were fully impaired in 2003 due to mechanical problems.
 
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 adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“Statement 143”) on January 1, 2003. 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


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  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.
 
New Accounting Policies
 
In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151 “Inventory Costs, an amendment of ARB No. 43, Chapter 4” (“Statement 151”). The amendments made by Statement 151 clarify that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials (spoilage) should be recognized as current-period charges and require the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. The guidance is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. Earlier application is permitted for inventory costs incurred during fiscal years beginning after November 23, 2004. Our assessment of Statement 151 is that it is not expected to have an impact on our financial position, results of operations or cash flows.
 
In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153 “Exchanges of Non-monetary assets — an amendment of APB Opinion No. 29” (“Statement 153”). Statement 153 amends Accounting Principles Board (“APB”) Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement 153 does not apply to a pooling of assets in a joint undertaking intended to fund, develop, or produce oil or natural gas from a particular property or group of properties. The provisions of Statement 153 shall be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Early adoption is permitted and the provisions of Statement 153 should be applied prospectively. Our assessment of Statement 153 is that it is not expected to have an impact on our financial position, results of operations or cash flows.
 
In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123-Revised 2004, “Share-Based Payment,” (“Statement 123R”). This is a revision of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation”, and supersedes APB No. 25, “Accounting for Stock Issued to Employees.” We currently account for stock-based compensation under the provisions of APB 25. Under Statement 123R, we will be required to measure the cost of employee services received in exchange for stock, based on the grant-date fair value (with limited exceptions). That cost will be recognized as expense over the period during which an employee is required to provide service in exchange for the award (usually the vesting period). The fair value will be estimated using an option-pricing model. Excess tax benefits, as defined in Statement 123R, will be recognized as an addition to paid-in capital. This will be effective for us as of the beginning of the first annual reporting period that begins after June  15, 2005. We are currently in the process of evaluating the impact of Statement 123R on our financial statements. Based on options outstanding at the effective date, we expect the pre-tax impact to be less than $2.5 million for 2006. this does not contemplate 2006 award grants. Note (2) of the Notes to Consolidated Financial Statements illustrates the current effect on net income and earnings per share if we had applied the fair value recognition provisions of Statement 123.
 
In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3,” (“Statement 154”). Statement 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It


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establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to Statement 154. The provisions of Statement 154 shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.
 
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, 2005, $85.0 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 2005, 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 $0.7 million based on total variable debt outstanding during the period. If market interest rates had averaged 1% lower during 2005, interest expense for the period on variable rate debt would have decreased, and net income before income taxes would have increased by approximately $0.7 million.
 
Commodity Price Risk
 
Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under 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, 2005, we had no crude oil positions and the following natural gas contracts in place:
 
                                 
Natural Gas Positions  
          Strike Price
    Volume (Mmbtu)  
Remaining Contract Term
  Contract Type     ($/Mmbtu)     Daily     Total  
 
01/06 - 12/06
    Collar     $ 5.00/$9.51       15,000       5,475,000  
01/07 - 12/07
    Collar     $ 5.00/$8.00       10,000       3,650,000  
 
Our hedged volume as of December 31, 2005 approximated 8% of our estimated production from proved reserves through the balance of the terms of the contracts. Had these contracts been terminated at December 31, 2005, we estimate the loss would have been $19.7 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, 2005 and 2004, the potential change in the fair value of commodity derivative instruments assuming a 10% increase in the underlying commodity price was a $6.7 million and $4.1 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.


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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.


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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, 2005. 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, 2005 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, 2005.
 
     
-s- RICHARD A. BACHMANN
  -s- DAVID R. LOONEY
Richard A. Bachmann   David R. Looney
Chairman and Chief
Executive Officer
  Executive Vice President
and Chief Financial Officer


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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, 2005, 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, 2005, 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, 2005, 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, 2005 and 2004, 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, 2005. 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, 2005, 2004, and 2003. Our report dated February 22, 2006 expressed an unqualified opinion on those consolidated financial statements and schedule.
 
-s- KPMG LLP
 
New Orleans, Louisiana
February 22, 2006


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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, 2005 and 2004, 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, 2005. 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, 2005, 2004, and 2003. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, 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.
 
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, 2005, 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 22, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
 
-s- KPMG LLP
 
New Orleans, Louisiana
February 22, 2006


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ENERGY PARTNERS, LTD. AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
December 31, 2005 and 2004
(In thousands, except share data)
 
                 
    2005     2004  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 6,789     $ 93,537  
Trade accounts receivable
    78,326       59,341  
Other receivables
    49,303       5,600  
Deferred tax assets
    5,582       1,906  
Prepaid expenses
    3,179       2,285  
                 
Total current assets
    143,179       162,669  
Property and equipment, at cost under the successful efforts method of accounting for oil and natural gas properties
    1,189,078       769,331  
Less accumulated depreciation, depletion and amortization
    (418,347 )     (304,997 )
                 
Net property and equipment
    770,731       464,334  
Other assets
    13,284       15,970  
Deferred financing costs — net of accumulated amortization of $5,169 in 2005 and $4,174 in 2004
    4,091       4,705  
                 
    $ 931,285     $ 647,678  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 28,810     $ 21,255  
Accrued expenses
    108,087       59,387  
Fair value of commodity derivative instruments
    9,875       1,749  
Current maturities of long-term debt
    109       108  
                 
Total current liabilities
    146,881       82,499  
Long-term debt
    235,000       150,109  
Deferred tax liabilities
    87,559       53,686  
Asset retirement obligation
    56,039       45,064  
Other
    11,213       1,271  
                 
      536,692       332,629  
Stockholders’ equity:
               
Preferred stock, $1 par value. Authorized 1,700,000 shares; issued and outstanding: 2005 — no shares; 2004 — 344,399 shares. Aggregate liquidation value: 2004 — $34,440
          33,504  
Common stock, par value $0.01 per share. Authorized 50,000,000 shares; issued and outstanding: 2005 — 41,468,093 shares; 2004 — 36,618,084 shares
    415       367  
Additional paid-in capital
    348,863       296,460  
Accumulated other comprehensive loss — net of deferred taxes of $7,098 in 2005 and $630 in 2004
    (12,619 )     (1,119 )
Retained earnings
    115,366       43,215  
Treasury stock, at cost. 2005 — 3,474,208 shares; 2004 — 3,480,441 shares
    (57,432 )     (57,378 )
                 
Total stockholders’ equity
    394,593       315,049  
Commitments and contingencies
               
                 
    $ 931,285     $ 647,678  
                 
 
See accompanying notes to consolidated financial statements.


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ENERGY PARTNERS, LTD. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 2005, 2004 and 2003
(In thousands, except per share data)
 
                         
    2005     2004     2003  
 
Revenue:
                       
Oil and natural gas
  $ 402,005     $ 294,531     $ 229,703  
Other
    942       679       484  
                         
      402,947       295,210       230,187  
                         
Costs and expenses:
                       
Lease operating
    50,431       40,328       36,656  
Transportation expense
    1,051       289       37  
Taxes, other than on earnings
    10,372       9,263       7,650  
Exploration expenditures and dry hole costs
    64,937       28,999       14,561  
Impairment of properties
    17,907       6,936       2,792  
Depreciation, depletion and amortization
    103,649       92,353       81,927  
General and administrative:
                       
Stock-based compensation
    6,767       3,050       1,285  
Other general and administrative
    36,438       27,924       26,719  
                         
Total costs and expenses
    291,552       209,142       171,627  
                         
Business interruption recovery
    20,632              
Income from operations
    132,027       86,068       58,560  
                         
Other income (expense):
                       
Interest income
    781       1,219       380  
Interest expense
    (18,121 )     (14,355 )     (10,174 )
                         
      (17,340 )     (13,136 )     (9,794 )
                         
Income before income taxes and cumulative effect of change in accounting principle
    114,687       72,932       48,766  
Income taxes
    (41,592 )     (26,516 )     (17,784 )
                         
Net income before cumulative effect of change in accounting principle
    73,095       46,416       30,982  
Cumulative effect of change in accounting principle, net of income taxes of $1,276
                2,268  
                         
Net income
    73,095       46,416       33,250  
Less dividends earned on preferred stock and accretion of discount and issuanced costs
    (944 )     (3,399 )     (3,545 )
                         
Net income available to common stockholders
  $ 72,151     $ 43,017     $ 29,705  
                         
Earnings per share:
                       
Basic:
                       
Before cumulative effect of change in accounting principle
  $ 1.94     $ 1.31     $ 0.89  
Cumulative effect of change in accounting principle
                0.07  
                         
Basic earnings per share
  $ 1.94     $ 1.31     $ 0.96  
                         
Diluted:
                       
Before cumulative effect of change in accounting principle
  $ 1.79     $ 1.20     $ 0.87  
Cumulative effect of change in accounting principle
                0.06  
                         
Diluted earnings per share
  $ 1.79     $ 1.20     $ 0.93  
                         
Weighted average common shares used in computing income per share:
                       
Basic
    37,097       32,861       30,822  
Incremental common shares
                       
Preferred stock
    544       4,033       4,310  
Stock options
    852       638       235  
Warrants
    1,954       1,057       208  
Restricted share units
    257       60        
Performance shares
    55              
                         
Diluted
    40,759       38,649       35,575  
                         
 
See accompanying notes to consolidated financial statements.


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ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
Years Ended December 31, 2005, 2004 and 2003
(In thousands)
 
                                                                                         
                                              Accumulated
                   
                                        Additional
    Other
    Retained
             
    Preferred
    Preferred
    Treasury
    Treasury
    Common
    Common
    Paid-In
    Comprehensive
    Earnings
             
    Stock Shares     Stock     Stock Shares     Stock     Stock Shares     Stock     Capital     Income     (Deficit)     Total        
 
Balance at December 31, 2002
    382     $ 35,359           $       27,550     $ 276     $ 187,965     $ (2,171 )   $ (29,507 )   $ 191,922          
Stock purchase, compensation and incentive plans, net
                            42             (758 )                 (758 )        
Proceeds from public offering, net of costs
                            4,211       42       37,535                   37,577          
Exercise of common stock options
                            167       2       2,148                   2,150          
Conversion of warrants into common stock
                            30             102                   102          
Conversion of preferred stock
    (14 )     (1,418 )                 232       3       1,415                            
Dividends on preferred stock
                                                    (2,592 )     (2,592 )        
Accretion of discount on preferred stock
          953                                           (953 )              
Comprehensive income:
                                                                                       
Net income
                                                    33,250       33,250          
Fair value of commodity derivative instruments
                                              (270 )           (270 )        
                                                                                         
Comprehensive income
                                                                            32,980          
                                                                                         
Other
                            10             104                   104          
                                                                                         
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          
                                                                                         
 
See accompanying notes to consolidated financial statements.
 


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ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2005, 2004 and 2003
(In thousands)
 
                         
    2005     2004     2003  
 
Cash flows from operating activities:
                       
Net income
  $ 73,095     $ 46,416     $ 33,250  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Cumulative effect of change in accounting principle, net of tax
                (2,268 )
Depreciation, depletion and amortization
    103,649       92,353       81,927  
Gain on disposal of assets
    (777 )     (282 )     (207 )
Non cash-based compensation
    6,817       3,100       1,285  
Deferred income taxes
    41,242       26,365       17,708  
Exploration expenditures
    69,926       26,730       12,810  
Amortization of deferred financing costs
    995       907       902  
Other
    966       293       271  
Changes in operating assets and liabilities:
                       
Trade accounts receivable
    (18,985 )     (24,931 )     (9,490 )
Other receivables
    (43,703 )     (5,600 )      
Prepaid expenses
    (894 )     (179 )     (239 )
Other assets
    (2,338 )     (4,522 )     (3,112 )
Accounts payable and accrued expenses
    40,073       6,180       4,814  
Other liabilities
    (97 )     (1,756 )     (949 )
                         
Net cash provided by operating activities
    269,969       165,074       136,702  
                         
Cash flows used in investing activities:
                       
Acquisition of business, net of cash acquired
    (863 )     (2,166 )     (850 )
Property acquisitions
    (193,115 )     (6,551 )     (6,030 )
Deposit paid on purchase of properties
          (5,000 )      
Exploration and development expenditures
    (254,900 )     (163,019 )     (103,148 )
Other property and equipment additions
    (1,723 )     (562 )     (608 )
Proceeds from sale of oil and gas assets
    1,442       585       579  
                         
Net cash used in investing activities
    (449,159 )     (176,713 )     (110,057 )
                         
Cash flows from financing activities:
                       
Deferred financing costs
    (357 )     (721 )     (4,746 )
Repayments of long-term debt
    (63,108 )     (199 )     (118,362 )
Proceeds from long-term debt
    148,000             15,000  
Proceeds from senior notes offering
                150,000  
Proceeds from public stock offering, net of commissions
          57,378       38,000  
Purchase of shares into treasury
          (57,378 )      
Equity offering costs
    (87 )     (106 )     (479 )
Payment of preferred stock dividends
          (2,421 )     (2,592 )
Exercise of stock options and warrants
    7,994       4,231       810  
                         
Net cash provided by financing activities
    92,442       784       77,631  
                         
Net increase (decrease) in cash and cash equivalents
    (86,748 )     (10,855 )     104,276  
Cash and cash equivalents at beginning of year
    93,537       104,392       116  
                         
Cash and cash equivalents at end of year
  $ 6,789     $ 93,537     $ 104,392  
                         
 
See accompanying notes to consolidated financial statements.


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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 shallow to moderate depth waters of the Gulf of Mexico Shelf and the Gulf Coast onshore regions and, as a result of an acquisition of undeveloped acreage in early 2006, the deepwater Gulf of Mexico. 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. During the Company’s limited operating history it has not, and does not currently, drill in areas that require major capital expenditures before production can begin. Therefore, 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. 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 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. 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.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
(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 uses the entitlement method for recording natural gas sales revenue. Under this method of accounting, revenue is recorded based on 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 $0.2 million and $1.4 million at December 31, 2005 and 2004, respectively and had liabilities of $0.5 million at December 31, 2005 and 2004.
 
(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, 2005 and 2004, interest-bearing cash equivalents were approximately $25.8 million and $99.9 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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 Amended and Restated 2000 Long Term Stock Incentive Plan and the Amended and Restated 2000 Stock Incentive Plan for Non-Employee Directors (the Plans). The Company accounts for its stock-based compensation in accordance with Accounting Principles Board’s Opinion No. 25, “Accounting For Stock Issued To Employees” (Opinion No. 25). Statement of Financial Accounting Standards No. 123 (Statement 123), “Accounting For Stock-Based Compensation” and Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure,” (Statement 148) permit the continued use of the intrinsic value-based method prescribed by Opinion No. 25, but require additional disclosures, including pro-forma calculations of earnings and net earnings per share as if the fair value method of accounting prescribed by Statement 123 had been applied. Effective January 1, 2006 the Company will adopt the provisions of Statement of Financial Accounting Standards No. 123-Revised 2004, “Share-Based Payment,” (“Statement 123R”). If compensation expense for the Plans had been determined using the fair-value method in Statement 123, the Company’s net income (loss) and earnings (loss) per share would have been as shown in the pro forma amounts below (in thousands, except per share amounts):
 
                         
    2005     2004     2003  
 
Net income available to common stockholders:
                       
As reported
  $ 72,151     $ 43,017     $ 29,705  
Less: Pro forma stock based employee compensation cost, after tax
    1,140       2,179       1,002  
                         
Pro forma
  $ 71,011     $ 40,838     $ 28,703  
                         
Basic earnings per share:
                       
As reported
  $ 1.94     $ 1.31     $ 0.96  
Pro forma
  $ 1.91     $ 1.24     $ 0.93  
Diluted earnings per share:
                       
As reported
  $ 1.79     $ 1.20     $ 0.93  
Pro forma
  $ 1.77     $ 1.14     $ 0.91  
Average fair value of grants during the year
  $ 6.86     $ 6.19     $ 4.67  
Black-Scholes option pricing model assumptions:
                       
Risk free interest rate
    4.5 %     4.5 %     4.5 %
Expected life (years)
    5       5       5  
Volatility
    42.0 to 43.0 %     43.0 to 45.0 %     47.0 to 49.0 %
Dividend yield
                 
Stock-based employee compensation cost, net of tax, included in net income as reported
  $ 468     $ 340     $ 28  


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
(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, 2005 and 2004, 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 fromother 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 2005.
 
(3)   Common Stock
 
On April 16, 2003, the Company completed the public offering of approximately 6.8 million shares of its common stock (the Equity Offering), which was priced at $9.50 per share. The Equity Offering included 4.2 million shares offered by the Company, 1.7 million shares offered by the Company’s then principal stockholders, Evercore Capital Partners L.P. and certain of its affiliates (Evercore), and 0.9 million shares offered by Energy Income Fund, L.P. (EIF). In addition, the underwriters exercised their option to purchase 1.0 million additional shares to cover over-allotments, the proceeds from which went to selling shareholders and not to the Company. After payment of underwriting discounts and commissions, the offering generated net proceeds to the Company of approximately $38.0 million. After expenses of approximately $0.5 million, the proceeds were used to repay a portion of outstanding borrowings under the Company’s bank credit facility.
 
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 EIF pursuant to which it 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. 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. The Company has no


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

immediate plans to enter into any additional transactions under the Registration Statement, but plans to use the proceeds for general corporate purposes, which may include debt repayment, acquisitions, expansion and working capital.
 
(4)   Supplemental Cash Flow Information
 
The following is supplemental cash flow information:
 
                         
    Years Ended December 31,  
    2005     2004     2003  
    (In thousands)  
 
Interest paid
  $ 18,121     $ 14,323     $ 5,877  
Income taxes paid, net of refunds
  $ 350     $ 151     $ 76  
 
The following is supplemental disclosure of non-cash financing activities:
 
                         
    Years Ended December 31,  
    2005     2004     2003  
    (In thousands)  
 
Accretion of preferred stock
  $ 944     $ 978     $ 953  
Conversion of preferred stock
  $ 34,448     $ 2,368     $ 1,418  
Restricted share units
  $ 805     $     $  
Exercise of options
  $     $     $ 1,442  
 
(5)   Acquisitions
 
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 $38.4 million of 11% Senior Subordinated Notes (the Notes), due 2009 (immediately callable at par) which were redeemed in August 2003 utilizing proceeds from the 8.75% Senior Notes due 2010 issuance (see note 9) and 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 expire on January 15, 2007. At December 31, 2005 there were 754,981 warrants outstanding with a strike price of $9.00 per share and 2,661,457 warrants outstanding with a strike price of $11.00 per share.
 
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 2005, 2004 and 2003, the Company capitalized, as additional purchase price, and paid additional consideration in cash, of $0.9 million,


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$2.2 million and $0.9 million related to the March 1, 2005 and 2004 and the March 3, 2003 contingent consideration determination dates, respectively. The Company does not expect the 2006 contingent consideration payment to exceed $1.0 million. 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 will be capitalized as additional purchase price.
 
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, with estimated acquisition date proved reserves of 51.2 billion cubic feet equivalent. Also included were interests in 22 exploratory prospects. The transaction expands the Company’s exploration opportunities in its expanded focus area and further reduces the concentration of its reserves and production. Upon the signing of the purchase agreement in December 2004, the Company paid a $5.0 million deposit toward the purchase price which was recorded as other assets in the consolidated balance sheet at December 31, 2004. Concurrent with the closing, the borrowing base under the Company’s bank credit facility was increased to $150 million, of which $60 million was drawn to fund the acquisition. 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 Company intends to continue to explore and develop oil and natural gas reserves in the AMI over that two year period jointly with the seller. The proved reserves, prospects and AMI are in the southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.
 
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  
 
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.
 
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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

these acquisitions. For the foregoing reasons these acquisitions will affect the comparability of the Company’s historical results of operations with future periods.
 
(6)   Property and Equipment
 
The following is a summary of property and equipment at December 31, 2005 and 2004:
 
                 
    2005     2004  
    (In thousands)  
 
Proved oil and natural gas properties
  $ 1,128,498     $ 750,850  
Unproved oil and natural gas properties
    53,676       13,275  
Other
    6,904       5,206  
                 
    $ 1,189,078     $ 769,331  
                 
 
We analyze proved properties for impairment based on the reserves as determined by our independent reserve engineers. We recognized impairment expense of $17.9 million, $6.9 million and $2.8 million in the years ending December 31, 2005, 2004 and 2003, respectively. 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 and in 2003 was related to our Ship Shoal 133 and West Cameron 149 fields.
 
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 and are recorded in other general and administrative expenses in the consolidated statement of operations.
 
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.
 
As a result of these two major hurricanes and three other hurricanes that traversed the Gulf of Mexico and adjacent land areas in July 2005, nearly all of the Company’s production was shut in at one time or another during the third quarter of 2005 and a portion of that production had not yet been restored at the end of the fourth quarter of 2005. The Company is continuing to work to bring production back to pre-storm levels, but is subject to constraints due to damage to third party infrastructure. In 2005 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. Recovery ceased for three of the fields in 2005, but will continue, including situations where production is shut-in due to third party constraints, until production is restored to pre-storm levels on the other field, subject to policy limits that the Company does not expect at this time to be reached. Through December 31, 2005, the total business interruption claim on these fields was $20.6 million, of which $20.4 million had not been collected and is recorded in other receivables on the Company’s consolidated balance sheet. As of February 22, 2006 an additional $7.3 million had been collected. Total offshore repair costs expended as of December 31, 2005 for Hurricanes Katrina, Rita and Cindy were $27.3 million. Of this amount $2.7 million represents uninsured amounts that are reflected in lease


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

operating expenses and the remaining $24.6 million is recorded in other receivables on the Company’s consolidated balance sheet.
 
(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 effect of adopting Statement 143 on the Company’s 2003 results of operations and financial condition included a net increase in long-term liabilities of $14.2 million; an increase in net property, plant and equipment of $17.8 million; a cumulative effect of adoption income of $2.3 million, net of deferred income taxes of $1.3 million.
 
The following table reconciles the beginning and ending aggregate recorded amount of the asset retirement obligation for the year ended December 31, 2005 (in thousands):
 
         
    Asset
 
    Retirement
 
    Obligation  
 
December 31, 2004
  $ 45,064  
Accretion expense
    4,125  
Liabilities incurred
    7,151  
Liabilities settled
    (54 )
Revisions in estimated cash flows
    (247 )
         
December 31, 2005
  $ 56,039  
         
 
(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 (see note 6) 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.
 
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. In addition, at any time prior to August 1, 2006, the Company may redeem up to a maximum of 35% of the aggregate principal amount with the net proceeds of certain equity offerings at a price equal to 108.75% of the principal amount, plus accrued and unpaid interest. 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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 August 3, 2004 the Company amended and extended to August 3, 2008 its bank credit facility. The borrowing base was increased to $150 million at the time of our purchase of south Louisiana properties and reserves in January 2005 (see note 5). 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 1.25% to 2.00% above LIBOR and 0% to 0.75% 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 0.375% to 0.5% 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 1.0 and (ii) maintain a minimum EBITDAX to interest ratio, as defined in the bank credit facility, of 3.5 times. The Company was in compliance with its bank facility covenants as of December 31, 2005.
 
Total long-term debt outstanding at December 31, 2005 and 2004 was as follows:
 
                 
    2005     2004  
    (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 August 3, 2008, with weighted average interest on December 31, 2005 of 6.07%
    85,000        
Financing note payable, annual interest of 7.99%, equal monthly payments, maturing February 2006
    109       217  
                 
      235,109       150,217  
Less: Current maturities
    109       108  
                 
    $ 235,000     $ 150,109  
                 
 
Maturities of long-term debt as of December 31, 2005 were as follows (in thousands):
 
         
2006
  $ 109  
2007
     
2008
    85,000  
2009
     
2010
    150,000  
Thereafter
     
         
    $ 235,109  
         
 
(10)   Significant Customers
 
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. The Company had oil and natural gas sales to two customers accounting for approximately 30% and 10%, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2003.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
(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, 2005:
 
                                 
Natural Gas Positions  
          Strike Price
    Volume (Mmbtu)  
Remaining Contract Term
  Contract Type     ($/Mmbtu)     Daily     Total  
 
01/06 - 12/06
    Collar     $ 5.00/$9.51       15,000       5,475,000  
01/07 - 12/07
    Collar     $ 5.00/$8.00       10,000       3,650,000  
 
For the years ended December 31, 2005, 2004 and 2003, settlements of hedging contracts reduced oil and gas revenues by $17.0 million, $15.2 million and $11.5 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, 2005 and 2004:
 
                 
    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 income — 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 income
    (11,500 )     (11,500 )
                 
Comprehensive income
  $ 61,595          
                 
Accumulated other comprehensive loss as of December 31, 2005 — net of taxes of $7,098
          $ (12,619 )
                 
 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                 
    Year Ended
 
    December 31, 2004  
    (In thousands)  
 
Accumulated other comprehensive loss as of December 31, 2003 — net of taxes of $1,373
          $ (2,441 )
Net income
  $ 46,416          
Other comprehensive loss — net of tax
               
Hedging activities
               
Reclassification adjustments for settled contracts — net of taxes of $(5,475)
    9,734          
Changes in fair value of outstanding hedging positions — net of taxes of $4,732
    (8,412 )        
                 
Total other comprehensive loss
    1,322       1,322  
                 
Comprehensive income
  $ 47,738          
                 
Accumulated other comprehensive loss as of December 31, 2004 — net of taxes of $630
          $ (1,119 )
                 
 
Based upon current prices, the Company expects to transfer approximately $9.9 million of pretax net deferred losses in accumulated other comprehensive income as of December 31, 2005 to earnings during 2006 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, 2005 and 2004. The fair value of a financial instrument is the amount at which the 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.
 
                                 
    2005     2004  
    Carrying
          Carrying
    Fair
 
    Amount     Fair Value     Amount     Value  
    (In thousands)  
 
Financial liabilities:
                               
Current and long-term debt:
                               
The Senior Notes
  $ 150,000     $ 155,250     $ 150,000     $ 163,500  
Bank credit facility
    85,000       85,000              
Financing note payable
    109       109       217       217  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
(13)   Income Taxes
 
Components of income tax expense for the years ended December 31, 2005, 2004 and 2003 are as follows:
 
                         
    Current     Deferred     Total  
    (In thousands)  
 
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  
                         
2003:
                       
Federal
  $ 76     $ 16,701     $ 16,777  
State
          1,007       1,007  
                         
    $ 76     $ 17,708     $ 17,784  
                         
 
The reasons for the differences between the effective tax rates and the “expected” corporate federal income tax rate of 34% is as follows:
 
                         
    Percentage of
 
    Pretax Earnings  
    2005     2004     2003  
 
Expected tax rate
    34.0 %     34.0 %     34.0 %
Stock-based compensation
    0.0       0.0       0.6  
State taxes
    2.0       2.0       2.1  
Other
    0.3       0.4       (0.2 )
                         
      36.3 %     36.4 %     36.5 %
                         


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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, 2005 and 2004 are presented below:
 
                 
    2005     2004  
    (In thousands)  
 
Current deferred tax assets:
               
Fair value of commodity derivative instruments
  $ 3,555     $ 630  
Accrued bonus compensation
    821       1,276  
Accrued legal provision
    1,206        
                 
Current deferred tax assets
  $ 5,582     $ 1,906  
                 
Non-Current Deferred tax assets:
               
Restricted stock awards and options
  $ 3,339     $ 1,531  
Federal and state net operating loss carryforwards
    11,480       15,916  
Fair market value of commodity derivative instruments
    3,543        
Other
    1,274       498  
                 
Non-Current Deferred tax liability:
               
Property, plant and equipment, principally due to differences in depreciation
    (107,195 )     (71,631 )
                 
Net non-current deferred tax liability
  $ (87,559 )   $ (53,686 )
                 
 
At December 31, 2005, the Company had net operating loss carryforwards of approximately $31.9 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, 2005 and 2004. The 2005 tax provision includes the use of $12.3 million of net operating loss carryforwards.
 
(14)   Employee Benefit Plans
 
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 Amended and Restated 2000 Long Term Stock Incentive Plan (the 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 options have a term of 10 years and generally vest over 3 years. The Plan also provides for restricted stock, restricted share units and performance share awards. The amended plan was approved by stockholders on May 9, 2002 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 is 4,800,000.
 
The Company issued restricted stock and restricted share unit awards to employees and officers in the amount of 460,710 in 2005, 333,759 in 2004 and 131,754 in 2003. The restrictions on this stock generally lapse on the first, second and third anniversary of the date of grant and require that the employee remain employed by the Company during the vesting period. Some grants carry restrictions that lapse on the fourth and sixth anniversary of the date of grant. The weighted average grant-date fair value of restricted shares granted in the years ended December 31, 2005, 2004 and 2003 was approximately $24.72, $15.23 and $10.12, respectively.
 
The Company has recognized non-cash compensation expense of $4.6 million, $1.8 million and $0.8 million in 2005, 2004 and 2003, respectively, related to the restricted share and stock option grants. At December 31, 2005,


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

there was $10.5 million of deferred stock based compensation expense related to the restricted share awards, which will be recognized over the remaining vesting periods.
 
In 2005, 2004 and 2003, respectively, 73,617, 137,000 and 141,500 performance shares were awarded of which 28,155, 54,167 and 13,333 were forfeited in 2005, 2004 and 2003, respectively, leaving 256,462 performance shares outstanding at December 31, 2005. These shares cliff vest at the end of three years and are based on the attainment of certain performance goals. The expected fair value of the shares on the vesting date is charged to expense ratably over the vesting period unless it is determined that the performance goals will not be met. The Company recognized non-cash compensation expense of $1.4 million, $1.3 million and $0.5 million related to these awards in 2005, 2004 and 2003, respectively.
 
The 2000 Stock Incentive Plan for Non-Employee Directors was approved by the Board of Directors and our stockholders in September 2000. In May 2005, the Company’s stockholders approved an amendment and restatement of the Plan to permit 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 and to increase the number of shares authorized for issuance under the Plan by 250,000 to 500,000. The size of any grants of stock options and restricted share units to non-employee directors, including to new directors, will be determined annually, based on the advice of an independent compensation consultant. The option exercise price for an option granted under the 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, the director shall forfeit any unvested restricted share units.
 
A summary of stock options granted under the incentive plans for the years ended December 31, 2005, 2004 and 2003 is as follows:
 
                                                 
    2005     2004     2003  
          Weighted
          Weighted
          Weighted
 
          Average
          Average
          Average
 
    Number of
    Exercise
    Number of
    Exercise
    Number of
    Exercise
 
    Shares     Price     Shares     Price     Shares     Price  
 
Outstanding at beginning of year
    2,032,329     $ 11.09       2,009,282     $ 9.68       1,997,965     $ 9.30  
Granted
    595,300     $ 26.07       637,000     $ 14.01       519,200     $ 10.18  
Exercised
    (759,288 )   $ 10.50       (453,492 )   $ 8.73       (232,871 )   $ 7.98  
Forfeited
    (40,232 )   $ 14.82       (160,461 )   $ 11.75       (275,012 )   $ 8.87  
                                                 
Outstanding at end of year
    1,828,109     $ 16.13       2,032,329     $ 11.09       2,009,282     $ 9.68  
                                                 
Exercisable at end of year
    1,012,220     $ 11.08       1,247,964     $ 10.78       840,027     $ 10.13  
                                                 
Available for future grants
    666,357               1,508,851               2,584,978          
                                                 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
A summary of information regarding stock options outstanding at December 31, 2005 is as follows:
 
                                         
          Options Outstanding     Options Exercisable  
          Remaining
    Weighted
          Weighted
 
          Contractual
    Average
          Average
 
Range of Exercise Prices
  Shares     Life     Price     Shares     Price  
 
$ 7.00 - $14.00
    1,113,709       6.9 years     $ 10.85       919,453     $ 10.62  
$14.01 - $21.00
    126,100       6.5 years     $ 16.56       33,333     $ 15.70  
$21.01 - $28.00
    588,300       7.7 years     $ 26.05           $  
 
The Company also has a 401(k) Plan that covers all employees. The 401(k) Plan was amended in 2002 such that, commencing in July 1, 2002 the Company matched 50% of each individual participant’s contribution not to exceed 2% of the participant’s compensation. By a subsequent amendment in November 2004, the Company match was increased, effective January 1, 2005, to 100% of each individual participant’s 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 30,586, 13,210 and 15,343 shares of common stock in 2005, 2004 and 2003 valued at approximately $786,000, $207,000 and $175,000, respectively.
 
(15)   Commitments and Contingencies
 
The Company has operating leases for office space and equipment, which expire on various dates through 2011. In addition, the Company has agreed to purchase seismic-related services and drilling rig commitments which expire on various dates through 2007.
 
Future minimum commitments as of December 31, 2005 under these operating obligations are as follows (in thousands):
 
         
2006
  $ 55,441  
2007
    8,086  
2008
    2,075  
2009
    1,542  
2010
    1,284  
Thereafter
    7,703  
         
    $ 76,131  
         
 
Expense relating to operating obligations for the years ended December 31, 2005, 2004 and 2003 was $4.8 million, $6.3 million and $3.7 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.
 
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.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
(16)   Related Party
 
Pursuant to the Company’s stockholder agreement with Evercore, the Company paid an affiliate of Evercore a monitoring fee of $250,000 in 2003. The requirement to pay this fee ceased in November 2003 when Evercore’s beneficial ownership of the Company’s stock became less than 10% and the stockholder agreement terminated by its terms.
 
(17)   Interim Financial Information (Unaudited)
 
The following is a summary of consolidated unaudited interim financial information for the years ended December 31, 2005 and 2004:
 
                                 
    Three Months Ended  
    March 31     June 30     September 30     December 31  
    (In thousands, except per share data)  
 
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  
2004
                               
Revenues
  $ 63,472     $ 75,067     $ 74,117     $ 82,554  
Costs and expenses
    48,391       48,658       55,736       56,357  
                                 
Income from operations
    15,081       26,409       18,381       26,197  
Net income
    7,446       14,656       9,569       14,745  
Net income available to common stockholders
    6,517       13,835       8,746       13,919  
Earnings per share:
                               
Basic
  $ 0.20     $ 0.42     $ 0.27     $ 0.42  
Diluted
    0.20       0.38       0.25       0.37  
 
(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, although the Company believes that the disclosures made are adequate to make the information presented not misleading. Certain reclassifications were made to conform all of the financial information to the


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

financial presentation on a consolidated basis. The principal eliminating entries eliminate investments in subsidiaries, intercompany balances and intercompany revenues and expenses.
 
Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2005
 
                                 
    Parent
                   
    Company
    Guarantor
             
    Only     Subsidiaries     Eliminations     Consolidated  
          (In thousands)        
 
ASSETS
Current assets:
                               
Cash and cash equivalents
  $ 6,789     $     $     $ 6,789  
Accounts receivable
    147,110       (19,481 )           127,629  
Other current assets
    8,670       91             8,761  
                                 
Total current assets
    162,569       (19,390 )           143,179  
Property and equipment
    775,274       413,804             1,189,078  
Less accumulated depreciation, depletion and amortization
    (303,290 )     (115,057 )           (418,347 )
                                 
Net property and equipment
    471,984       298,747             770,731  
Investment in affiliates
    238,988             (238,988 )      
Notes receivable, long-term
          216,370       (216,370 )      
Other assets
    17,396       (21 )           17,375  
                                 
    $ 890,937     $ 495,706     $ (455,358 )   $ 931,285  
                                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
                               
Accounts payable and accrued expenses
  $ 135,367     $ 1,530     $     $ 136,897  
Fair value of commodity derivative instruments
    9,875                   9,875  
Current maturities of long-term debt
          109             109  
                                 
Total current liabilities
    145,242       1,639             146,881  
Long-term debt
    235,000       216,370       (216,370 )     235,000  
Other liabilities
    116,102       38,709             154,811  
                                 
      496,344       256,718       (216,370 )     536,692  
Stockholders’ equity:
                               
Common stock
    415                   415  
Additional paid-in capital
    348,863                   348,863  
Accumulated other comprehensive loss
    (12,619 )                 (12,619 )
Retained earnings
    115,366       238,988       (238,988 )     115,366  
Treasury stock
    (57,432 )                 (57,432 )
                                 
Total stockholders’ equity
    394,593       238,988       (238,988 )     394,593  
                                 
    $ 890,937     $ 495,706     $ (455,358 )   $ 931,285  
                                 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Supplemental Condensed Consolidating Statement of Operations
Year Ended December 31, 2005
 
                                 
    Parent
                   
    Company
    Guarantor
             
    Only     Subsidiaries     Eliminations     Consolidated  
          (In thousands)        
 
Revenue:
                               
Oil and gas
  $ 276,257     $ 125,748     $     $ 402,005  
Other
    29,566       328       (28,952 )     942  
                                 
      305,823       126,076       (28,952 )     402,947  
Costs and expenses:
                               
Lease operating expenses
    29,843       21,639             51,482  
Taxes, other than on earnings
    1,803       8,569             10,372  
Exploration expenditures
    54,598       28,246             82,844  
Depreciation, depletion and amortization
    66,306       37,343             103,649  
General and administrative
    41,891       16,314       (15,000 )     43,205  
                                 
Total costs and expenses
    194,441       112,111       (15,000 )     291,552  
                                 
Business interruption recovery
    20,632                   20,632  
Income from operations
    132,014       13,965       (13,952 )     132,027  
                                 
Interest expense, net
    (17,327 )     (13 )           (17,340 )
                                 
Income before income taxes
    114,687       13,952       (13,952 )     114,687  
Income taxes
    (41,592 )                 (41,592 )
                                 
Net income
  $ 73,095     $ 13,952     $ (13,952 )   $ 73,095  
                                 
 
Supplemental Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2005
 
                                 
    Parent
                   
    Company
    Guarantor
             
    Only     Subsidiaries     Eliminations     Consolidated  
          (In thousands)        
 
Net cash provided by operating activities
  $ 32,227     $ 237,742     $     $ 269,969  
Cash flows used in investing activities:
                               
Acquisition of business, net of cash acquired
    (863 )                 (863 )
Property acquisitions
    (48,544 )     (144,571 )           (193,115 )
Exploration and development expenditures
    (161,837 )     (93,063 )           (254,900 )
Other property and equipment additions
    (1,723 )                 (1,723 )
Proceeds from the sale of oil and natural gas assets
    1,442                   1,442  
                                 
Net cash used in investing activities
    (211,525 )     (237,634 )           (449,159 )
Cash flows provided by (used in) financing activities:
                               
Deferred financing costs
    (357 )                 (357 )
Repayments of long-term debt
    (63,000 )     (108 )           (63,108 )
Equity offering costs
    (87 )                 (87 )
Proceeds from public offering net of commissions
    148,000                   148,000  
Exercise of stock options and warrants
    7,994                   7,994  
                                 
Net cash provided by (used in) financing activities
    92,550       (108 )           92,442  
                                 
Net decrease in cash and cash equivalents
    (86,748 )                 (86,748 )
Cash and cash equivalents at the beginning of the period
    93,537                   93,537  
                                 
Cash and cash equivalents at the end of the period
  $ 6,789     $     $          —     $ 6,789  
                                 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
(19)   New Accounting Pronouncements
 
In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151 “Inventory Costs, an amendment of ARB No. 43, Chapter 4” (“Statement 151”). The amendments made by Statement 151 clarify that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials (spoilage) should be recognized as current-period charges and require the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. The guidance is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. Earlier application is permitted for inventory costs incurred during fiscal years beginning after November 23, 2004. The Company has assessed the impact of Statement 151, which will not have an impact on the financial position, results of operations or cash flows of the Company.
 
In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153 “Exchanges of Non-monetary assets — an amendment of APB Opinion No. 29” (“Statement 153”). Statement 153 amends Accounting Principles Board (“APB”) Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement 153 does not apply to a pooling of assets in a joint undertaking intended to fund, develop, or produce oil or natural gas from a particular property or group of properties. The provisions of Statement 153 shall be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Early adoption is permitted and the provisions of Statement 153 should be applied prospectively. The Company has assessed the impact of Statement 153, which will not have an impact on the financial position, results of operations or cash flows of the Company.
 
In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123-Revised 2004, “Share-Based Payment,” (“Statement 123R”). This is a revision of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation”, and supersedes APB No. 25, “Accounting for Stock Issued to Employees.” The Company currently accounts for stock-based compensation under the provisions of APB 25. Under Statement 123R, the Company will be required to measure the cost of employee services received in exchange for stock, based on the grant-date fair value (with limited exceptions). That cost will be recognized as expense over the period during which an employee is required to provide service in exchange for the award (usually the vesting period). The fair value will be estimated using an option-pricing model. Excess tax benefits, as defined in Statement 123R, will be recognized as an addition to paid-in capital. This will be effective for us as of the beginning of the first annual reporting period that begins after June  15, 2005. The Company is currently in the process of evaluating the impact of Statement 123R on its financial statements. Based on options outstanding at the effective date, the Company expects the pre-tax impact to be less than $2.5 million for 2006. This does not contemplate 2006 award grants. Note (2) of the Notes to Consolidated Financial Statements illustrates the current effect on net income and earnings per share if we had applied the fair value recognition provisions of Statement 123.
 
In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3,” (“Statement 154”). Statement 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to Statement 154. The provisions of Statement 154 shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.
 
(20)   Supplementary Oil and Natural Gas Disclosures — (Unaudited)
 
Our December 31, 2005, 2004 and 2003 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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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
    Natural Gas
 
    (Mbbls)     (Mmcf)  
 
Proved-developed and undeveloped reserves:
               
December 31, 2002
    26,353       126,957  
Extensions, discoveries and other additions
    2,275       40,270  
Revisions
    1,698       (4,135 )
Production
    (2,912 )     (28,688 )
                 
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  
                 
Proved-developed reserves:
               
December 31, 2003
    22,306       71,531  
December 31, 2004
    24,737       102,760  
December 31, 2005
    25,646       103,627  
 
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.
 
Capitalized costs for oil and natural gas producing activities consist of the following:
 
                 
    2005     2004  
    (In thousands)  
 
Proved properties
  $ 1,128,498     $ 750,850  
Unproved properties
    53,676       13,275  
Accumulated depreciation, depletion and amortization
    (414,163 )     (301,639 )
                 
Net capitalized costs
  $ 768,011     $ 462,486  
                 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Costs incurred for oil and natural gas property acquisition, exploration and development activities for the years ended December 31, 2005, 2004 and 2003 are as follows:
 
                         
    Years Ended December 31,  
    2005     2004     2003  
          (In thousands)        
 
Business combinations
                       
Proved properties
  $ 142,025     $ 2,166     $ 850  
Unproved properties
    29,333              
                         
Total business combinations
    171,358       2,166       850  
Lease acquisitions
    27,622       6,551       6,030  
Exploration
    171,859       113,278       60,170  
Development (1)
    114,814       75,732       49,013  
                         
Costs incurred
  $ 485,653     $ 197,727     $ 116,063  
                         
 
 
(1) Includes asset retirement obligations incurred of $6.9 million, $3.5 million and $3.3 million for the years ended December 31, 2005, 2004 and 2003, 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 field and determinable escalations 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.
 
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.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:
 
                         
    2005     2004     2003  
          (In thousands)        
 
Future cash inflows
  $ 3,540,136     $ 2,136,571     $ 1,672,895  
Future production costs
    (645,025 )     (570,552 )     (441,042 )
Future development and abandonment costs
    (363,949 )     (294,936 )     (264,404 )
Future income tax expense
    (770,858 )     (358,421 )     (245,934 )
                         
Future net cash flows after income taxes
    1,760,304       912,662       721,515  
10% annual discount for estimated timing of cash flows
    (499,058 )     (244,994 )     (192,100 )
                         
Standardized measure of discounted future net cash flows
  $ 1,261,246     $ 667,668     $ 529,415  
                         
 
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, 2005, 2004 and 2003 is as follows:
 
                         
    2005     2004     2003  
          (In thousands)        
 
Beginning of the period
  $ 667,668     $ 529,415     $ 476,901  
Sales and transfers of oil and natural gas produced, net of production costs
    (342,396 )     (247,007 )     (185,360 )
Net changes in prices and production costs
    861,576       140,169       59,988  
Extensions, discoveries and improved recoveries, net of future production costs
    145,143       270,223       149,459  
Revision of quantity estimates
    (160,227 )     (50,384 )     18,380  
Previously estimated development costs incurred during the period
    33,481       55,893       21,379  
Purchase and sales of reserves in place
    271,675              
Changes in estimated future development costs
    143       (7,300 )     (15,851 )
Changes in production rates (timing) and other
    (19,764 )     (8,819 )     (37,680 )
Accretion of discount
    92,414       70,124       60,827  
Net change in income taxes
    (288,467 )     (84,646 )     (18,628 )
                         
Net increase
    593,578       138,523       52,514  
                         
End of period
  $ 1,261,246     $ 667,668     $ 529,415  
                         
 
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 computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2004 was based on period-end prices of $6.23 per Mcf for natural gas and $41.84 per barrel for crude oil. The December 31, 2003 computation was based on period-end prices of $6.15 per Mcf for natural gas and $30.88 per barrel for crude oil. Spot prices as of February 22, 2006 were $7.26  per Mmbtu for natural gas and $60.85 per barrel for crude oil before adjustment for lease quality, transportation fees and price differentials.


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Schedule II
 
VALUATION AND QUALIFYING ACCOUNTS
 
                                 
    Balance at the
    Additions Charged
             
    Beginning of the
    to Costs and
          Balance at the
 
    Year     Expenses     Deductions     End of the Year  
          (In thousands)              
 
Allowance for doubtful accounts:
                               
2003
  $ 279     $     $ 253     $ 26  
2004
    26             26        
2005
                       


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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.
 
In conjunction with the temporary relocation of our headquarters to Houston, Texas and establishing a second temporary office in Baton Rouge, Louisiana due to Hurricane Katrina, we elected to cease hosting our accounting system in-house and to outsource the hosting to a third party data center which allowed us to expedite the set up of our temporary multiple location structure and expedited the move back to New Orleans in December 2005. The transfer was not made in response to any pre-existing deficiency in our internal controls over financial reporting. Upon our return to our permanent headquarters in New Orleans, Louisiana, we resumed hosting our accounting system in-house. There have been no other changes in our internal control over financial reporting during the fiscal quarter ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
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 sufficiently 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.


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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  4, 2006, 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 210 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  4, 2006, 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 4, 2006, 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  4, 2006, 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  4, 2006, 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, 2005 and 2004
 
Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003
 
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2005, 2004 and 2003
 
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003


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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.
  3 .5     Amended and Restated Bylaws of Energy Partners, Ltd., dated as of March 20, 2003 (incorporated by reference to Exhibit 3.1 to EPL’s Form 8-K filed April 3, 2003 (File No. 333-42876)).
  10 .1     Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to EPL’s proxy statement on Form 14A filed March 27, 2002 (File No. 001-16179)).
  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     Fourth Amended and Restated Credit Agreement, among Energy Partners, Ltd., EPL of Louisiana, L.L.C. and Delaware EPL of Texas, LLC, the undersigned banks and financial institutions that are parties to the Credit Agreement and JPMorgan Chase Bank, dated as of August 3, 2004 (incorporated by reference to Exhibit 10.1 of EPL’s Form 10-Q filed August 5, 2004).
  10 .4     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 .5     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 .6     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 .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     Offer Letter of Mr. David R. Looney, dated February 9, 2005 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed February 14, 2005).
  10 .12     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).


68


Table of Contents

             
Exhibit
       
Number
     
Title
 
  10 .13     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 .14     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 .15     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).
  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, President, 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 14, 2006.
  99 .2*     Report of Independent Petroleum Engineers dated as of February 7, 2006.
 
 
* Filed herewith

69


Table of Contents

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 27, 2006
         
/s/  DAVID R. LOONEY

David R. Looney
  Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
  February 27, 2006
         
/s/  DINA M. BRACCI

Dina M. Bracci
  Controller (Principal Accounting Officer)   February 27, 2006
         
/s/  JOHN C. BUMGARNER, JR.

John C. Bumgarner, Jr.
  Director   February 27, 2006
         
/s/  JERRY D. CARLISLE

Jerry D. Carlisle
  Director   February 27, 2006
         
/s/  HAROLD D. CARTER

Harold D. Carter
  Director   February 27, 2006
         
/s/  ENOCH L. DAWKINS

Enoch L. Dawkins
  Director   February 27, 2006
         
/s/  NORMAN C. FRANCIS

Norman C. Francis
  Director   February 27, 2006
         
/s/  ROBERT D. GERSHEN

Robert D. Gershen
  Director   February 27, 2006
         
/s/  PHILLIP A. GOBE

Phillip A. Gobe
  President, Chief Operating Officer and Director   February 27, 2006
         
/s/  WILLIAM R. HERRIN, JR.

William R. Herrin, Jr.
  Director   February 27, 2006
         
/s/  WILLIAM O. HILTZ

William O. Hiltz
  Director   February 27, 2006
         
/s/  JOHN G. PHILLIPS

John G. Phillips
  Director   February 27, 2006


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Table of Contents

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.
  3 .5     Amended and Restated Bylaws of Energy Partners, Ltd., dated as of March 20, 2003 (incorporated by reference to Exhibit 3.1 to EPL’s Form 8-K filed April 3, 2003 (File No. 333-42876)).
  10 .1     Amended and Restated 2000 Long Term Stock Incentive Plan (incorporated by reference to EPL’s proxy statement on Form 14A filed March 27, 2002 (File No. 001-16179)).
  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     Fourth Amended and Restated Credit Agreement, among Energy Partners, Ltd., EPL of Louisiana, L.L.C. and Delaware EPL of Texas, LLC, the undersigned banks and financial institutions that are parties to the Credit Agreement and JPMorgan Chase Bank, dated as of August 3, 2004 (incorporated by reference to Exhibit 10.1 of EPL’s Form 10-Q filed August 5, 2004).
  10 .4     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 .5     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 .6     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 .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     Offer Letter of Mr. David R. Looney, dated February 9, 2005 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed February 14, 2005).
  10 .12     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 .13     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 .14     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 .15     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).


Table of Contents

             
Exhibit
       
Number
     
Title
 
  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, President, 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 14, 2006.
  99 .2*     Report of Independent Petroleum Engineers dated as of February 7, 2006.
 
 
* Filed herewith