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.
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:
Richard A. Bachmann has been president and chief executive officer and chairman of the board of directors since our incorporation in January 1998. 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 is also a director of Superior Energy Services, Inc.
Gary L. Hall joined us in January 2002, following the closing of the HHOC acquisition, as vice chairman and a member of our board of directors. Prior to joining us, Mr. Hall had been chairman of the board of directors and chief executive officer of HHOC since it began operations in 1983. He has been involved in the oil and natural gas exploration and production business in the Gulf of Mexico since 1976, serving in various positions with major integrated and independent energy companies including Mobil Oil Company and Pogo Producing Company.
Suzanne V. Baer joined us in April 2000 as vice president and chief financial officer and was promoted to executive vice president in May 2001. Ms. Baer has 34 years of financial management, investor relations and treasury experience in the energy industry. From July 1998 until March 2000, Ms. Baer had been vice president and treasurer of Burlington Resources Inc. and, from October 1997 to July 1998, was vice president and assistant treasurer of Burlington Resources. Prior to the merger of LL&E with Burlington Resources in 1997, Ms. Baer was vice president and treasurer of LL&E since 1995.
John H. Peper joined us in January 2002, following the closing of the HHOC acquisition, 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 HHOC since February 1993. Mr. Peper also served as a director of HHOC since October 1991. 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.
Bruce R. Sidner joined us in January 2002, following the closing of the HHOC acquisition, as executive vice president of exploration. Prior to joining us, Mr. Sidner had been vice-president, exploration, of HHOC since February 1984. Mr. Sidner also served as a director of HHOC since 1990. For the seven years prior to joining HHOC, Mr. Sidner served in various positions with major integrated and independent energy companies including Exxon Production Research and Pogo Producing Company.
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.
William Flores, Jr. joined us in August 2003 as senior vice president -- drilling. Mr. Flores has over 22 years experience in the energy industry. From 1999 to 2003, he was senior vice president of drilling for Ocean Energy, Inc. and from 1993 to 1999 he was vice president of operations of Ocean Energy, Inc. From 1988 to 1993, Mr. Flores was a senior drilling engineer for CNG Producing. From 1983 to 1988, he worked as a consulting engineer at the consulting firm of Stokes and Spiehler. Prior to 1983, Mr. Flores was a petroleum engineer for Apache Oil Company.
PART II
ITEM 5.
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.
On February 25, 2004, the last reported sale price of our common stock on the New York Stock Exchange was $13.29 per share.
As of February 25, 2004, there were approximately 129 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.
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
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 operations are concentrated in the shallow to moderate depth waters of the Gulf of Mexico Shelf.
In 2003, we reported another year of growth and progress with the best year on a per-share basis over our six-year history. Our strong cash flow provided us the flexibility to make necessary and appropriate investments to continue our long-term growth strategy. Our long-term strategy is to increase our oil and natural gas reserves and production while keeping our finding and development costs and operating costs competitive with our industry peers. We will implement this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve or resource potential and by making acquisitions in our core focus 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.
On January 15, 2002, we acquired HHOC for consideration of $88.3 million and the assumption of HHOC's working capital deficit. The consideration included the issuance of $38.4 million of 11% Senior Subordinated Notes due 2009 (the "Notes"). We also issued Series D Exchangeable Convertible Preferred Stock with a fair value at the issue date of $34.7 million ($38.4 million face amount) with an effective dividend rate of 10%. The acquisition moved our operations to a more balanced oil and natural gas reserves and production profile and reduced our production exposure to any particular field. Through the acquisition we added 59.1 Bcfe of proved reserves in January 2002, 98% of which were natural gas. The acquisition also included 10 producing properties and 12 offshore exploratory blocks. We have included the results of operations from the HHOC acquisition from the closing date of January 15, 2002. This acquisition has significantly affected our results of operations and production growth and will affect the comparability of our historical results of operations with results of operations from 2001.
On November 1, 2000, we consummated our initial public offering of 5.75 million shares of common stock. 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. 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 and to repay substantially all of the borrowings outstanding under our bank credit facility. The remainder of the net proceeds has been 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.
We amended our bank credit facility in connection with the Debt Offering. The amendment reduced the borrowing base under our bank credit facility to $60 million upon consummation of the Debt Offering. The
borrowing base remains subject to redetermination based on the proved reserves of our oil and natural gas properties.
During 2003, Evercore, on two occasions exercised a contractual right to request us to register with the SEC the possible public sale of our common stock held by it. Subsequent to each of these requests Evercore priced two public offerings to sell shares of our common stock. These offerings completed the sale of its interest in our company. We did not sell any shares in either of these two offerings and did not receive any proceeds from the shares offered by Evercore.
Our revenue, profitability and future growth rate depend on a number of factors beyond our control, such as 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 "Additional Factors Affecting Business" in Items 1 and 2 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 in 2004, 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. We believe this year will provide us a number of opportunities to acquire targeted properties within our focus area.
RESULTS OF OPERATIONS
The following table presents information about our oil and natural gas operations.
- ---------------
(1) Net of the effect of hedging transactions, which reduced oil price realizations by $1.67, $0.51 and $0.10 per Bbl, for 2003, 2002 and 2001, respectively and reduced gas price realizations by $0.23, $0.18 and $0.05 per Mcf for 2003, 2002 and 2001, respectively.
REVENUES AND NET INCOME
Our oil and natural gas revenues increased to $229.7 million in 2003 from $134.1 million in 2002. The significant increase for this period is the result of increased natural gas and oil prices and increased natural gas production due primarily to new production from 21 wells drilled in 2002 and in the first half of 2003. These increases were partially offset by natural reservoir declines. In addition, 2002 volumes were negatively affected by tropical storm activity.
Our oil and natural gas revenues decreased to $134.1 million in 2002 from $144.1 million in 2001. Although production volumes increased 7% on a barrel of oil equivalent basis, the 27% decline in natural gas price realizations more than offset this benefit and resulted in lower revenues.
We recognized net income of $33.3 million in 2003 compared to net loss of $8.8 million in 2002. The increase in net income was primarily due to the increase in oil and natural gas revenues previously discussed and partially offset by higher operating costs, as discussed below. We recognized a net loss of $8.8 million in 2002 compared to net income of $12.0 million in 2001. The decrease in net income was primarily due to the decrease in oil and natural gas revenues previously discussed, combined with higher depletion, depreciation and amortization expense incurred primarily as a result of the HHOC acquisition. The following items had a significant impact on our net income or loss in 2003, 2002 and 2001 and affect the comparability of the results of operations for those years:
- In January 2003, we adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("Statement 143") and the effect of adoption on our results of operations and financial condition included a cumulative effect of adoption income of $2.3 million, net of deferred income taxes of $1.3 million.
- In March 2002, in connection with management's plan to reduce costs and effectively combine the operations of HHOC with ours, we executed a severance plan and recorded an expense of $1.2 million.
- In December 2001, we purchased a financially-settled put swaption (the "put swaption"), which provided us with a financially-settled natural gas swap at $2.95 per Mmbtu for 30,000 Mmbtu per day for the period from February 2002 through January 2003. The put swaption also provided us the option to cancel the swap on January 15, 2002. In the fourth quarter of 2001, we recognized an expense of $1.9 million, related to the change in time value of the option portion of the contract compared to $0.5 million expensed in January 2002 related to the remaining change in time value. This expense is classified as other revenue in the consolidated statements of operations in 2002 and 2001.
- We recorded business interruption income of $3.5 million in 2001 as a result of the rupture of a high-pressure natural gas transfer line at our East Bay field. The rupture occurred in November 2000 and the transfer line was restored to service in February 2001. This income is classified as other revenue in the consolidated statements of operations in 2001.
OPERATING EXPENSES
Operating expenses were impacted by the following:
- Lease operating expense increased $2.3 million to $36.7 million in 2003. This is a result of the addition of production from new fields, whereas the majority of our new production in the past was primarily from our large fields with existing infrastructure and low variable cost. Despite the increase in absolute costs, our operating costs per Boe have decreased due to the lower fixed costs required for these new fields.
Lease operating expense decreased $2.1 million to $34.4 million in 2002. The decrease is attributable to the concerted effort to reduce operating costs, primarily at our East Bay field, which more than offset additional costs from the HHOC properties.
- Taxes, other than on earnings increased $1.1 million to $7.7 million in 2003. This increase was due to the increase in the production volumes and prices received for our oil and natural gas production on state leases, primarily at East Bay and Bay Marchand, which is subject to Louisiana severance taxes. These taxes are expected to fluctuate from period to period depending on our production volume from state leases and the commodity prices received.
Taxes, other than on earnings decreased $0.6 million to $6.6 million in 2002. This reduction was due to the decrease in the production volumes and prices received for our oil production on state leases subject to Louisiana severance taxes.
- Exploration expenditures increased $6.7 million to $17.4 million in 2003. The expense in 2003 is primarily the result of an increase in dry hole charges to $10.1 million as a result of exploratory wells drilled during the year which were found to be not commercially productive, as well as property impairments of $2.8 million, partially offset by a slight decrease in seismic expenditures and delay rentals to $4.5 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. Although our dry hole costs were higher in 2003, we allocated more dollars to exploration in 2003 while maintaining a comparable success rate.
Exploration expenditures decreased $4.4 million to $10.7 million in 2002. The expense in 2002 is primarily the result of an increase in seismic expenditures and delay rentals to $4.8 million and a decrease in dry hole charges to $5.9 million as a result of exploratory wells drilled during the year which were found to be not commercially productive.
- Depreciation, depletion and amortization increased $17.4 million to $81.9 million in 2003. 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. Some fields carry a higher depreciation burden than others, therefore, changes in the location of our production will directly impact this expense. This expense includes $5.2 million for the provision of abandonment liabilities for 2003 as compared to $6.8 million in 2002.
Depreciation, depletion and amortization increased $17.6 million to $64.5 million in 2002. The increase was due to the increased depreciable asset base resulting from the acquisition of HHOC and drilling activities subsequent to December 31, 2001, increased production volumes, amortization of unproved leases awarded at the March 2002 lease sale and acquired with HHOC and downward reserve revisions due to prices at December 31, 2001. This expense includes $6.8 million for the provision of abandonment liabilities as compared to $8.1 million in 2001.
- Other general and administrative expenses increased $4.2 million to $26.7 million in 2003. The increase was primarily due to increased compensation ($5.6 million) and increased insurance ($0.6 million) offset by a 2002 litigation settlement ($2.0 million), which increased general and administrative expenses during the prior year.
Other general and administrative expenses increased $4.3 million to $22.5 million in 2002. The increase was primarily due to a litigation settlement ($2.0 million), increased insurance costs ($0.9 million), increased rent and other office costs ($1.0 million) and other costs associated with the combination of HHOC's operations with ours primarily in the first quarter of 2002 as we assimilated HHOC.
- Non-cash stock-based compensation expense of $1.3 million was recognized in 2003, an increase of $0.8 million from 2002. This expense has increased due to additional grants of restricted stock and the granting of performance share awards to employees.
Non-cash stock-based compensation expense of $0.5 million was recognized in 2002, a decrease of $1.2 million from 2001. This expense relates to restricted stock and stock option grants made to employees.
OTHER INCOME AND EXPENSE
Interest expense increased $3.2 million to $10.2 million in 2003. The increase was a result of interest expense on the 8.75% Senior Notes issued in August 2003 partially offset by the interest savings from the redemption of the 11% Notes and the repayment of the bank facility.
Interest expense increased $5.1 million to $7.0 million in 2002. The increase was a result of increased borrowings under our bank facility and the issuance of the Notes on January 15, 2002 related to the acquisition of HHOC.
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
The increase in revenues we experienced in 2003 significantly increased our cash flows from operations, which totaled $136.7 million in 2003. We intend to fund our exploration and development expenditures from internally generated cash flow, which we define as cash flow from operations before consideration of changes in working capital plus total exploration expenditures. Our cash on hand at December 31, 2003 was $104.4 million. Our future internally generated cash flows will depend on our ability to maintain and increase production through our development and exploratory 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 July 28, 2003, consists of a revolving line of credit with a group of banks available through March 30, 2005 (the "bank facility"). The bank facility currently has a borrowing base of $60 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 facility as set out in the reserve report delivered to the banks each April 1 and October 1. The bank 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 our utilization of the bank facility. The spread can range from 1.50% to 2.25% above LIBOR and 0% to 0.75% above prime. The borrowing base under the bank facility is secured by substantially all of our assets. At March 1, 2004, we had $0.1 million outstanding and $59.9 million of credit capacity available under the bank 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 of 1.1, (ii) maintain a minimum EBITDAX to interest ratio of 5.00 times, and (iii) maintain a minimum tangible net worth as calculated in accordance with the agreement. We were in compliance with these covenants at December 31, 2003.
On August 5, 2003, we issued, $150 million of 8.75% Senior Notes due 2010. The 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 notes at our option, in whole or in part, at any time on or after August 1, 2007 at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium which decreases yearly from 4.375% in 2007 to 0% in 2009 and thereafter. 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 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 Senior Notes are not subject to any sinking fund requirements.
Upon closing on the Senior Notes on August 5, 2003, we called our $38.4 million 11% Notes due 2009 for redemption. The redemption of the Notes in aggregate principal and accrued interest were funded with a portion of the proceeds received from the Senior Notes and was completed in August 2003. The Notes were issued on January 15, 2002 as part of the acquisition of HHOC. 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 $110.1 million used in investing activities in 2003 primarily included oil and natural gas property capital and exploration expenditures of $103.1 million and lease acquisitions of $6.0 million. Exploration expenditures incurred are excluded from operating cash flows and included in investing activities. During 2003, we completed 23 drilling projects and 33 recompletion/workover projects, 46 of which were
successful. During 2002, we completed 17 drilling projects and 27 recompletion/workover projects, 34 of which were successful.
Our 2004 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 currently intend to allocate approximately 60% of our budget on an annual basis on low risk development and exploitation activities, approximately 25% to moderate risk exploration opportunities and approximately 15% to higher risk, higher potential exploration opportunities. Our exploration and development budget for 2004 is currently $125 million. 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 2004 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 capital requirements for at least the next twelve months. Availability under the bank facility will be used to balance short-term fluctuations in working capital requirements. However, additional financing may be required in the future to fund our growth.
DISCLOSURES ABOUT CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table aggregates the contractual commitments and commercial obligations that affect our financial condition and liquidity position as of December 31, 2003:
- ---------------
(1) Consists of commitments to purchase seismic related services.
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, zero-cost collars and a combination of options used 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 contract 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 the following contracts as of December 31, 2003:
On January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133 ("Statement 133"), as amended, Accounting for Derivative Instruments and Hedging Activities. Statement 133 establishes accounting and reporting standards requiring 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 settled, when the resulting gains and losses will be recorded in earnings. Hedge ineffectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by Statement 133, is charged currently to earnings.
Our hedged volume as of December 31, 2003 approximated 35% 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 statement 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 57 exploration wells, of which 13 were considered dry holes. Our dry hole costs charged to expense during this period totaled $29.5 million out of total exploratory drilling costs of $132.8 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 level and success of our exploratory program.
- Proved Reserve Estimates -- Our independent reserve engineers prepare our oil and natural gas reserve estimates using guidelines established by the U.S. Securities and Exchange Commission and generally accepted accounting principles. The quality and quantity of data, the interpretation of the data, and the accuracy of mandated economic assumptions combined with the judgment exercised by the 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. 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 prices and costs 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, 2003 was based on period-end prices of $6.15 per Mcf for natural gas and $30.88 per barrel for crude oil 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. While we believe that future costs can be reasonably estimated, future prices are difficult to estimate since the market prices are influenced by events beyond our control. Future global economic and political events will most likely result in significant fluctuations in future oil prices. In addition, weather conditions can cause significant fluctuations in natural gas prices.
- 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. Material downward revisions in reserves increase the DD&A per unit and reduce our net income; likewise, material upward revisions lower the DD&A per unit and increase our net income.
- Impairment of Oil and 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 could exceed its fair value. Because we account for our proved oil and natural gas properties separately under the successful efforts method of accounting, we assess our assets for impairment property by property rather than in one pool of total oil and natural gas property costs. A significant amount of judgment is involved in performing these evaluations since the amount is based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or natural gas, unfavorable adjustments to reserves, or other changes to contracts, environmental regulations or tax laws. We cannot predict the need for, nor estimate the amount of, impairment charges that may be recorded in the future.
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.
In 2002, we adopted Statement 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," ("Statement 144") which superseded Statement 121 "Accounting for Impairment of Long-Lived Assets." The Statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. The adoption of this statement did not have a material effect on our balance sheet or income statement in 2002.
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.
- 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 and combination options with major financial institutions. 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. Under the provisions of Statement 133, 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 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 2002, the Financial Accounting Standards Board ("FASB") issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 requires a company to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. The measurement provisions of this statement apply prospectively to guarantees issued or modified after December 31, 2002. The disclosure provisions apply to financial statements for periods ending after December 15, 2002. We do not currently have guarantees that require disclosure. We have adopted FIN 45, which did not have an impact on our financial position, results of operations or cash flows.
In December 2003, the FASB issued FASB Interpretation 46 (Revised December 2003), "Consolidation of Variable Interest Entities," ("FIN 46R") which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN 46R replaces FASB Interpretation 46, "Consolidation of Variable Interest Entities," which was issued in January 2003. We will be required to apply FIN 46R to variable interests in variable interest entities ("VIEs") no later than March 31, 2004. We have assessed the impact of FIN 46R, which will not currently have an impact on our financial position, results of operations or cash flows.
During the second quarter of 2002, the FASB issued Statement 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections ("Statement 145"). This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishments of Debt, and requires that all gains and losses from extinguishments of debt should be classified as extraordinary items only if they meet the criteria of in APB No. 30. Applying APB No. 30 will distinguish transactions that are part of an entity's recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. Any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB No. 30 for classification as an extraordinary item must be reclassified. We have adopted Statement 145, which did not have an impact on our financial position, results of operations or cash flows.
In June 2002, the FASB issued Statement 146, Accounting for Costs Associated with Exit or Disposal Activities ("Statement 146"). Statement 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and requires that liabilities associated with these costs be recorded at their fair value in the period in which the liability is incurred. Statement 146 became effective for disposal activities initiated after December 31, 2002. We have adopted Statement 146 which did not have an impact on our financial positions results of operations or cash flows.
In December 2002, the FASB issued Statement 148, "Accounting for Stock-Based Compensation -- Transition and Disclosure" ("Statement 148"). Statement 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, Statement 148 amends the disclosure requirements of FASB Statement 123, "Accounting for Stock-Based Compensation," to require more prominent and frequent disclosures in financial statements about the effects of stock-based compensation. The transition guidance and annual disclosure provisions of Statement 148 are effective for fiscal years ending after December 15, 2002, while the interim disclosure provisions are effective for periods beginning after December 15, 2002. Disclosures required by this standard are included in the notes to these consolidated financial statements.
On April 30, 2003, the FASB issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" ("Statement 149"). Statement 149 amends and clarifies the accounting guidance on (1) derivative instruments (including certain derivative instruments embedded in other contracts) and (2) hedging activities that fall within the scope of FASB Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("Statement 133"). Statement 149 also amends certain other existing pronouncements, which will result in more consistent reporting of contracts that are derivatives in their entirety or that contain embedded derivatives that warrant separate accounting. Statement 149 is effective (1) for contracts entered into or modified after June 30, 2003, with certain exceptions, and (2) for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively. We have adopted Statement 149, which did not have an impact on our financial position, results of operations or cash flows.
In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("Statement 150"). Statement 150 establishes standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, financial instruments that embody obligations for the issuer are required to be classified as liabilities. Statement 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise shall be effective at the beginning of the first interim period beginning after June 15, 2003. We have adopted the Statement 150, which did not have an impact on our financial position, the results of operations or cash flows.
Statement of Financial Accounting Standards No. 141, "Business Combinations," ("Statement 141") and No. 142, "Goodwill and Intangible Assets," ("Statement 142") became effective for us on July 1, 2001 and January 1, 2002, respectively. Statement 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. Additionally, Statement 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. Statement 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under Statement 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. The appropriate application of Statement 141 and 142 to oil and natural gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves is unclear. Depending on how the accounting and disclosure literature is clarified, these oil and natural gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds may be classified separately from oil and natural gas properties, as intangible assets on our balance sheets. Additional disclosures required by Statements 141 and 142 would be included in the notes to financial statements. Historically, we, like many other oil and natural gas companies, have included these oil and natural gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and natural gas properties, even after Statements 141 and 142 became effective.
This interpretation of Statements 141 and 142 would affect only our balance sheet classification of oil and natural gas leaseholds. Our results of operations and cash flows would not be affected, since these oil and natural gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with accounting rules for oil and natural
gas companies provided in Statement of Financial Accounting Standards No. 19 "Financial Accounting and Reporting by Oil and Gas Producing Companies."
At December 31, 2003, we had unproved and proved leasehold of approximately $5.0 million and $100.0 million that would have been classified on the balance sheet as unproved intangible oil and natural gas properties and intangible acquired proved leaseholds, respectively, if we applied the interpretation currently being deliberated by the Emerging Issues Task Force ("EITF"). We will continue to classify our oil and natural gas leaseholds as oil and natural gas properties until further guidance is provided.
ITEM 7A.
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, 2003, $0.1 million of our long-term debt had variable interest rates, while the remaining long-term debt had fixed interest rates, therefore an increase in the variable interest rate would not have a material impact on net income.
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 commodity instruments to manage commodity price risks associated with future oil and natural gas production. As of December 31, 2003, we had the following contracts in place:
Our hedged volume as of December 31, 2003 approximated 35% of our estimated production from proved reserves through the balance of the terms of the contracts. Had these contracts been terminated at December 31, 2003, we estimate the loss would have been $3.8 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, 2003, the potential change in the fair value of commodity derivative instruments assuming a 10% increase in the underlying commodity price was a $4.1 million increase in the combined estimated loss.
For purposes of calculating the hypothetical change in fair value, the relevant variables are the type of commodity (crude oil or natural gas), the commodities futures prices and volatility of commodity prices. The hypothetical fair value is calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes.
GLOSSARY OF OIL AND NATURAL GAS TERMS
"Bbl" One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Report in reference to oil and other liquid hydrocarbons.
"Boe" Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
"Bcf" One billion cubic feet.
"Bcfe" One billion cubic feet equivalent, with one barrel of oil being equivalent to six thousand cubic feet of natural gas.
"completion" The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
"Mbbls" One thousand barrels of oil or other liquid hydrocarbons.
"Mboe" One thousand barrels of oil equivalent.
"Mcf" One thousand cubic feet of natural gas.
"Mmbbls" One million barrels of oil or other liquid hydrocarbons
"Mmboe" One million barrels of oil equivalent
"Mmbtu" One million British Thermal Units.
"Mmcf" One million cubic feet of natural gas.
"plugging and abandonment" Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.
"reservoir" A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
"working interest" The interest in an oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.
"EBITDAX" Net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, exploration expenditures and cumulative effect of change in accounting principle.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF MANAGEMENT
The consolidated financial statements of Energy Partners, Ltd. and subsidiaries and the related information included in this Report have been prepared by management in conformity with accounting principles generally accepted in the United States of America. The financial statements include amounts that are management's best estimates and judgments.
Management maintains a system of internal controls including internal accounting controls that provide management with reasonable assurance that our assets are protected and that published financial statements are reliable and free of material misstatement. Management is responsible for the effectiveness of internal controls. This is accomplished through established codes of conduct, accounting and other control systems, policies and procedures, employee selection and training, appropriate delegation of authority and segregation of responsibilities.
The Audit Committee of the Board of Directors, composed solely of directors who are not officers or employees of the Company, meets regularly with the independent certified public accountants, financial management and counsel. To ensure complete independence, the certified public accountants have full and free access to the Audit Committee to discuss the results of their audits, the adequacy of internal controls and the quality of financial reporting.
Our independent certified public accountants provide an objective independent review by their audit of the Company's financial statements. Their audit is conducted in accordance with auditing standards generally accepted in the United States of America standards and includes a review of internal accounting controls to the extent deemed necessary for the purposes of their audit.
INDEPENDENT AUDITORS' REPORT
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, 2003 and 2002, 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, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits 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, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.
As discussed in note 2 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations in 2003.
KPMG LLP
New Orleans, Louisiana February 9, 2004
ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2003 AND 2002 (IN THOUSANDS, EXCEPT SHARE DATA)
See accompanying notes to consolidated financial statements.
ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 (IN THOUSANDS, EXCEPT PER SHARE DATA)
See accompanying notes to consolidated financial statements.
ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 (IN THOUSANDS)
See accompanying notes to consolidated financial statements.
ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 (IN THOUSANDS)
See accompanying notes to consolidated financial statements.
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. 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. Costs to drill exploratory wells that do not find proved reserves, and geological and geophysical costs are expensed.
Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is 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 calculates the impairment of capitalized costs of proved oil and natural gas properties on a field-by-field basis, utilizing its current estimate of future revenues and operating expenses. In the event net undiscounted cash flow is less than the carrying value, an impairment loss is recorded based on the present value of expected future net cash flows over the economic lives of the reserves.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion, depreciation and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized.
(c) ASSET RETIREMENT OBLIGATION
In 2001, the Financial Accounting Standards Board (FASB) issued Statement of 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. 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. Prior to adoption of this statement, such obligations were accrued ratably over the productive lives of the assets through its depreciation, depletion and amortization for oil and natural gas properties.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(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 financing are deferred and are being 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 exercise of convertible preferred stock shares, warrants and stock option awards and the potential 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 $1.7 million and $1.3 million at December 31, 2003 and 2002, respectively and had liabilities of $0.5 million at December 31, 2003 and 2002.
(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, 2003 and 2002, interest-bearing cash equivalents were approximately $110.4 million and $4.4 million, respectively. Exploration expenditures incurred are excluded from operating cash flows and included in investing activities.
(i) HEDGING ACTIVITIES
The Company uses derivative commodity instruments to manage commodity price risks associated with future crude oil and natural gas production, but does not use them for speculative purposes. The Company's commodity price hedging program has utilized financially-settled zero-cost collar contracts to establish floor and ceiling prices on anticipated future crude oil and natural gas production and oil and natural gas swaps to fix the price of anticipated future crude oil and natural gas production. On January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 (Statement 133), as amended, "Accounting for Derivative Instruments and Hedging Activities". Statement 133 establishes accounting and reporting standards requiring 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 settled, when the resulting gains and losses will be recorded in earnings. Hedge ineffectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by Statement 133, will be charged currently to earnings.
(j) STOCK-BASED COMPENSATION
The Company has two stock award plans, the Amended and Restated 2000 Long Term Stock Incentive Plan and the 2000 Stock Option 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) permits the continued use of the intrinsic value-based method prescribed by Opinion No. 25, but requires 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. 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):
(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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
amount of any allowance may be reasonably estimated. As of December 31, 2003 and 2002, the Company had an allowance for doubtful accounts of $25,960 and $1.4 million, respectively.
(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 bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, to form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company's actual results may differ from these estimates and assumptions used in preparation of its financial statements. Significant estimates with regard to these financial statements and related unaudited disclosures include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows there-from disclosed in note 21.
(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 2003.
(3) COMMON STOCK
On November 1, 2000, the Company priced its initial public offering of 5.75 million shares of common stock and commenced trading the following day. 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.
In July 2003, Evercore exercised a contractual right to request us to register with the SEC for possible public sale 2.5 million shares of common stock. On August 8, 2003 we were informed by Evercore that it had priced a public offering of the 2.5 million shares of our common stock at $10.40 per share. In October 2003, Evercore, again exercised its contractual right to request the Company to register with the SEC for possible sale of all of Evercore's remaining approximately 4.5 million shares of common stock. On November 11, 2003 the Company was informed by Evercore that it had priced a public offering of all of these remaining shares of the Company's common stock at $11.75 per share. This offering completed the sale of Evercore's interest in the Company. The Company did not sell any shares in the offering and did not receive any proceeds from the shares offered by the selling stockholders.
(4) 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the number of additional common shares that could have been outstanding assuming the exercise of stock options, warrants and convertible preferred stock shares.
The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for the years ended December 31, 2003 and 2001. The diluted loss per share calculation for the year ended December 31, 2002 produces results that are anti-dilutive, therefore, the diluted loss per share amount as reported for this period in the accompanying consolidated statements of operations is the same as the basic loss per share amount.
(5) SUPPLEMENTAL CASH FLOW INFORMATION
The following is supplemental cash flow information:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following is supplemental disclosure of non-cash financing activities:
On November 17, 1999, the Company issued a warrant to EIF to purchase 928,050 shares of common stock as required by a financing transaction with Evercore. EIF exercised its option to convert the warrant in January 2001, receiving 466,245 shares of common stock.
(6) ACQUISITIONS
On January 15, 2002, the Company closed the acquisition of Hall-Houston Oil Company (HHOC). The results of the operations have been included in the Company's consolidated financial statements since that date. HHOC was an oil and natural gas exploration and production company with operations focused in the shallow waters of the Gulf of Mexico. As a result of the acquisition, the Company has a strengthened management team, expanded exploration opportunities as well as a reserve portfolio and production that are more balanced between oil and natural gas.
The HHOC acquisition was completed for consideration consisting of $38.4 million liquidation preference of newly authorized and issued Series D Exchangeable Convertible Preferred Stock (Series D Preferred Stock) with a fair value of $34.7 million discounted to effect the increasing dividend rate, $38.4 million of 11% Senior Subordinated Notes (the Notes), due 2009 (immediately callable at par), 574,931 shares of common stock with a fair value of approximately $3.3 million determined based on the average market price of the Company's common stock over the period of two days before and after the terms of the acquisition were agreed to and announced, $9.0 million of cash including $3.9 million of accrued interest and prepayment fees paid to former debt holders, and warrants to purchase four million shares of the Company's common stock. Of the warrants, one million have a strike price of $9.00 and three million have a strike price of $11.00 per share. The warrants had a fair value of approximately $3.0 million based on a third party valuation and are exercisable beginning January 15, 2003 and expiring on January 15, 2007. In addition, the Company incurred approximately $3.6 million in expenses in connection with the acquisition and assumed HHOC's working capital deficit.
In addition, former preferred stockholders of HHOC have the right to receive contingent consideration. Some of the former stockholders are employees of the Company, however, any contingent consideration payments are not tied to continued employment. The contingent consideration is 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 HHOC 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 beginning March 3, 2003 and ending March 1, 2007. The cumulative percentage remitted to the participants is 20% for March 3, 2003, 30% for March 1, 2004, 35% for March 1, 2005, 40% for March 1, 2006 and 50% for March 1, 2007. 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. On March 17, 2003, the Company capitalized, as additional purchase price, and paid additional consideration of $0.9 million related to the March 3, 2003 contingent consideration payment date. The Company does not expect the 2004 contingent consideration payment to exceed $2.5 million. Due to the uncertainty inherent in estimating the value of future contingent consideration which includes annual revaluations 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,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. The following table summarizes the fair value of the assets acquired and liabilities assumed at the date of acquisition:
Following the completion of the acquisition, management of the Company assessed the technical and administrative needs of the combined organization. As a result, 14 redundant positions were eliminated including finance, administrative, geophysical and engineering positions in New Orleans and Houston. Total severance costs under the plan were $1.2 million.
(7) PROPERTY AND EQUIPMENT
The following is a summary of property and equipment at December 31, 2003 and 2002:
Substantially all of the Company's oil and natural gas properties serve as collateral for its bank facility.
(8) ASSET RETIREMENT OBLIGATION
In 2001, the Financial Accounting Standards Board (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 is 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 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The pro forma asset retirement obligations would have been $26.0 million at January 1, 2002 and $36.9 million at December 31, 2002 had the Company adopted Statement 143 on January 1, 2002. The following pro forma data summarizes the Company's net loss and net loss per share as if the Company had adopted the provisions of Statement 143 on January 1, 2002 (in thousands, except per share amounts):
The following table reconciles the beginning and ending aggregate recorded amount of the asset retirement obligation for the year ended December 31, 2003 (in thousands):
(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 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. The remainder of the net proceeds will be used for general corporate purposes, including acquisitions.
The Senior Notes mature on August 1, 2010 with interest payable each February 1 and August 1, commencing February 1, 2004. The indenture relating to the Senior Notes contains certain restrictions on the Company's ability to incur additional debt, pay dividends on its common stock, make investments, create liens on its assets, engage in transactions with its affiliates, transfer or sell assets and consolidate or merge substantially all of its assets. The Senior Notes are not subject to any sinking fund requirements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On July 28, 2003 the Company amended its bank credit facility in connection with the Debt Offering. The amendment reduced the borrowing base under the bank credit facility to $60 million upon consummation of the Debt Offering. The borrowing base is subject to redetermination based on the proved reserves of the oil and gas properties that serve as collateral for the bank facility as set out in the reserve report delivered to the banks each April 1 and October 1. The bank facility is available through March 30, 2005 with interest permitted at both prime rate based borrowings and London interbank borrowing rate (LIBOR) borrowings plus a floating spread. The spread will float up or down based on our utilization of the bank facility. The spread can range from 0% to 0.75% above prime and 1.5% to 2.25% above LIBOR. Indebtedness under the bank facility is secured by substantially all of the assets of the Company. 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 weighted average interest rate at December 31, 2003 and 2002 was 4.00% and 3.18%, respectively. The bank credit facility contains customary events of default and various financial covenants which required the Company to: (i) maintain a minimum current ratio of 1.1, (ii) maintain a minimum EBITDAX to interest ratio of 5.00 times, and (iii) maintain a minimum tangible net worth as calculated in accordance with the agreement. The Company was in compliance with these covenants at December 31, 2003.
Total long-term debt outstanding at December 31, 2003 and 2002 were as follows:
Maturities of long-term debt as of December 31, 2003 were as follows (in thousands):
(10) REDEEMABLE PREFERRED STOCK
In connection with the acquisition of HHOC, in January 2002, the Company authorized 550,000 shares of Series D Preferred Stock, having a par value of $1.00 per share, of which 383,707 shares were issued in the acquisition of HHOC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Series D Preferred Stock earns cumulative dividends payable semiannually in arrears on June 30 and December 31 of each year as follows:
Any dividends accrued on or prior to December 31, 2005 shall, when declared, be payable in cash at the dividend rate per-share based on the stated value of $100. Any dividends accrued after December 31, 2005 and on or before December 31, 2008 shall, when declared, be payable, at the option of the Company, either in cash at the dividend rate per-share based on the stated value of $100 or by issuing dividend shares having an aggregate value equal to the dividend rate per-share based on the stated value of $100. The Company may, at its option on or after December 31, 2004, redeem the Series D Preferred Stock in whole, at a redemption price per-share equal to $100 plus accrued and unpaid dividends. The Company may also, at its option, on any dividend payment date, exchange the Series D Preferred Stock, in whole, along with any unpaid dividends, for an equal principal amount of Exchangeable Notes. At the time of the exchange, holders of outstanding shares will be entitled to receive $100 principal amount of Exchangeable Notes for each $100 stated value of Series D Preferred Stock and accrued and unpaid dividends. The Exchangeable Notes mature January 15, 2009 and the coupon follows the same schedule as that of the dividends on the Series D Preferred Stock. Each share of the Series D Preferred Stock is convertible at the option of the record holder at any time, into the number of shares of common stock determined by dividing $100 by the conversion price of $8.54 as adjusted pursuant to the terms of the Series D Preferred Stock designation. In 2003, 14,184.9 shares of Series D Preferred Stock were converted into 166,095 shares of common stock and in 2002, 1,445.8 shares of Series D Preferred Stock were converted into 16,929 shares of common stock.
(11) SIGNIFICANT CUSTOMERS
The Company had oil and natural gas sales to two customers accounting for approximately 30 percent and 10 percent, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2003. The Company had oil and natural gas sales to three customers accounting for approximately 41 percent, 27 percent and 11 percent, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2002. The Company had oil and natural gas sales to three customers accounting for 38 percent, 37 percent and 15 percent, respectively, of total oil and natural gas revenues, excluding the effects of hedging activities, for the year ended December 31, 2001.
(12) HEDGING ACTIVITIES
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 these hedging transactions are recorded in other revenue in the statements of operations. 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. The Company also uses financially-settled crude oil and natural gas swaps, zero-cost collars and options used to provide floor prices with varying upside price participation.
On December 12, 2001, the Company purchased a financially-settled put swaption (put swaption) in anticipation of the acquisition of Hall-Houston Oil Company and affiliated interests (collectively, HHOC). The put swaption provided the Company with a financially-settled natural gas swap at $2.95 per Mmbtu for 10,950,000 Mmbtu (30,000 Mmbtu per day) for the period of February 2002 through January 2003 and the
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
option to cancel this swap on January 15, 2002. The cost to enter into the contract was $2.4 million. On January 15, 2002, the Company exercised its right provided by the put swaption to retain the swap at $2.95 per Mmbtu.
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. In some hedges we may modify our collar to provide full upside participation after a limited non-participation range.
The Company had the following hedging contracts as of December 31, 2003:
For the years ended December 31, 2003, 2002 and 2001, hedging activities reduced oil and gas revenues by $11.5, $5.0 and $3.5 million, respectively.
The following table reconciles the change in accumulated other comprehensive income for the years ended December 31, 2003 and 2002:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Based upon current prices, the Company expects to transfer approximately $3.8 million of pretax net deferred losses in accumulated other comprehensive income as of December 31, 2003 to earnings during 2004 when the forecasted transactions actually occur.
(13) 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, 2003 and 2002. 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(14) INCOME TAXES
Components of income tax expense (benefit) for the years ended December 31, 2003, 2002 and 2001 are as follows:
The reasons for the differences between the effective tax rates and the "expected" corporate federal income tax rate of 34% is as follows:
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, 2003 and 2002 are presented below:
At December 31, 2003, the Company had net operating loss carryforwards of approximately $52.8 million, which are available to reduce future federal taxable income. The net operating loss carryforwards begin expiring in the years 2018 through 2022. 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.
(15) 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 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.
In April 2000, an employee, pursuant to her employment agreement, was granted 90,000 shares of restricted stock and stock options to purchase 375,000 shares of common stock. The restricted stock granted became fully vested in 2002. The stock options vest and are exercisable at the prices as follows: 150,000 shares at $7.67 per share in April 2001, 150,000 shares at $8.82 per share in April 2002 and the remaining shares at $10.14 in April 2003. The grant date fair value of the restricted stock and options was $17.00.
The Company issued 131,754 and 92,990 shares of common stock as restricted stock awards in 2003 and 2002, respectively, to certain employees and officers. The restrictions on this stock generally lapse on the second and third anniversary of the date of grant and require that the employee remain employed by the Company during the vesting period. The weighted average grant-date fair value of restricted shares granted in the years ended December 31, 2003 and 2002 was approximately $10.12 and $8.19, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company has recognized non-cash compensation expense of $0.8 million, $0.5 million and $1.7 million in 2003, 2002 and 2001, respectively, related to the restricted stock and stock option grants. At December 31, 2003, there was $1.1 million of deferred stock based compensation expense related to the restricted stock awards, which will be recognized over the remaining vesting periods.
In 2003, 141,500 performance shares were awarded and 13,333 were forfeited, leaving 128,167 performance shares outstanding at December 31, 2003. 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 $0.5 million related to these awards in 2003.
The board of directors also adopted the 2000 Stock-Option Plan for Non-Employee Directors on September 12, 2000, and the stockholders approved the plan on September 15, 2000. The plan provides for automatic grants of stock options to members of the board of directors who are not employees of the Company or any subsidiary. An initial grant of a stock option to purchase 4,000 shares of our common stock was made to each non-employee director upon consummation of the public offering. An initial grant of a stock option to purchase 2,000 shares will also be made to each person who becomes a non-employee director after the effective date upon his or her initial election or appointment. After the initial grant, each non-employee director will receive an additional grant of a stock option to purchase 4,000 shares of our common stock immediately following each subsequent annual meeting. All stock options granted under the plan will have a per share exercise price equal to the fair market value of a share of common stock on the date of grant (as determined by the committee appointed to administer the plan), will be fully vested and immediately exercisable, and will expire on the earlier of (i) ten years from the date of grant or (ii) 36 months after the optionee ceases to be a director for any reason. For initial grants, fair market value was the public offering price. The total number of shares of our common stock that may be issued under the plan is 250,000, subject to adjustment in the case of certain corporate transactions and events.
A summary of stock options granted under the incentive plans for the years ended December 31, 2003, 2002 and 2001 are as follows:
A summary of information regarding stock options outstanding at December 31, 2003 is as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company also has a 401(k) Plan (the Plan) that covers all employees. The Plan was amended in 2002 such that, commencing July 1, 2002 the Company matches 50% of each individual participant's contribution not to exceed 2% 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 Plan of 15,343 and 9,206 shares of common stock in 2003 and 2002 valued at approximately $175,000 and $84,000, respectively.
(16) 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 which expire on various dates through 2005.
Future minimum commitments as of December 31, 2003 under these operating obligations are as follows (in thousands):
Rent expense for the years ended December 31, 2003, 2002 and 2001 was $3.7 million, $3.3 million and $1.8 million, respectively.
Commencing January 1, 2002, the Company has been required to make monthly deposits of $250,000 into a trust for future abandonment costs at East Bay. The Company is not entitled to access the trust fund in order to draw funds for abandonment purposes prior to December 31, 2003. Monthly deposits are not required to be made for fiscal year 2004 and are to resume January 1, 2005, however, beginning December 31, 2003 the minimum balance in the trust must be maintained at $6.0 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.
In February 2003, the Company settled a lawsuit filed in 2001 for $2 million. This settlement is reflected in general and administrative expenses in 2002. 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.
(17) RELATED PARTY
The Company's Chairman, President and Chief Executive Officer serves on the board of directors of a company that provides contract operations and other oilfield equipment and services to the Company. The Company incurred gross costs, both capital and lease operating on behalf of itself and its working interest partners, from this service provider of approximately $4.2 million, $4.0 million and $4.2 million in 2003, 2002 and 2001, respectively. Loss of this service provider would not have a material adverse effect on the operations of the Company.
Pursuant to the Company's stockholder agreement with Evercore, the Company paid an affiliate of Evercore a monitoring fee of $250,000 for each of the years 2003, 2002 and 2001. The requirement to pay this fee ceased in November 2003 when Evercore's beneficial ownership of the Company's stock became less than
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10%. An affiliate of Evercore provided investment-banking advisory services to the Company in relation to the January 2002 acquisition of HHOC. The Company paid $0.4 million for these services in 2002.
Certain officers and their affiliates that held interests prior to the HHOC transaction continue to be royalty owners in individual properties acquired from HHOC and operated by the Company.
(18) INTERIM FINANCIAL INFORMATION (UNAUDITED)
The following is a summary of consolidated unaudited interim financial information for the years ended December 31, 2003 and 2002:
(19) 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 financial presentation on a consolidated basis. The principal eliminating entries eliminate investments in subsidiaries, intercompany balances and intercompany revenues and expenses.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2003
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2003
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2003
(20) NEW ACCOUNTING POLICIES
In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 requires a company to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. The measurement provisions of this statement apply prospectively to guarantees issued or modified after December 31, 2002. The disclosure provisions apply to financial statements for periods ending after December 15, 2002. The Company does not currently have guarantees that require disclosure. The Company has adopted FIN 45, which did not have an impact on the financial position, results of operations or cash flows of the Company.
In December 2003, the FASB issued FASB Interpretation 46 (Revised December 2003), "Consolidation of Variable Interest Entities," (FIN 46R) which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN 46R replaces FASB Interpretation 46, "Consolidation of Variable Interest Entities," which was issued in January 2003. The Company will be required to apply FIN 46R to variable interests in variable interest entities (VIEs) no later than March 31, 2004. The Company has assessed the
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
impact of FIN 46R, which will not currently have an impact on the financial position, results of operations or cash flows of the Company.
During the second quarter of 2002, the FASB issued Statement 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections (Statement 145). This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishments of Debt, and requires that all gains and losses from extinguishments of debt should be classified as extraordinary items only if they meet the criteria of in APB No. 30. Applying APB No. 30 will distinguish transactions that are part of an entity's recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. Any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB No. 30 for classification as an extraordinary item must be reclassified. The Company has adopted Statement 145, which did not have an impact on the financial position, results of operations or cash flows of the Company.
In June 2002, the FASB issued Statement 146, Accounting for Costs Associated with Exit or Disposal Activities (Statement 146). Statement 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and requires that liabilities associated with these costs be recorded at their fair value in the period in which the liability is incurred. Statement 146 became effective for disposal activities initiated after December 31, 2002. The Company adopted Statement 146, which did not have an impact on the financial position, results of operations or cash flows of the Company.
In December 2002, the FASB issued Statement 148, "Accounting for Stock-Based Compensation -- Transition and Disclosure" (Statement 148). Statement 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, Statement 148 amends the disclosure requirements of Statement 123, "Accounting for Stock-Based Compensation," to require more prominent and frequent disclosures in financial statements about the effects of stock-based compensation. The transition guidance and annual disclosure provisions of Statement 148 are effective for fiscal years ending after December 15, 2002, while the interim disclosure provisions are effective for periods beginning after December 15, 2002. Disclosures required by Statement 148 are included in these notes to the consolidated financial statements.
On April 30, 2003, the FASB issued Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (Statement 149). Statement 149 amends and clarifies the accounting guidance on (1) derivative instruments (including certain derivative instruments embedded in other contracts) and (2) hedging activities that fall within the scope of FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133). Statement 149 also amends certain other existing pronouncements, which will result in more consistent reporting of contracts that are derivatives in their entirety or that contain embedded derivatives that warrant separate accounting. Statement 149 is effective (1) for contracts entered into or modified after June 30, 2003, with certain exceptions, and (2) for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively. The Company has adopted Statement 149, which did not have an impact on its financial position, results of operations or cash flows.
In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (Statement 150). Statement 150 establishes standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, financial instruments that embody obligations for the issuer are required to be classified as liabilities. Statement 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise shall be effective at the beginning of the first interim period beginning after June 15, 2003. The Company has adopted Statement 150, which did not have an impact on its financial position, results of operations or cash flows.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Statement of Financial Accounting Standards No. 141, "Business Combinations," (Statement 141) and No. 142, "Goodwill and Intangible Assets," (Statement 142) became effective for the Company on July 1, 2001 and January 1, 2002, respectively. Statement 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. Additionally, Statement 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. Statement 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under Statement 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. The appropriate application of Statement 141 and 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves is unclear. Depending on how the accounting and disclosure literature is clarified, these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on the Company's balance sheets. Additional disclosures required by Statements 141 and 142 would be included in the notes to financial statements. Historically, the Company, like many other oil and gas companies, have included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and gas properties, even after Statements 141 and 142 became effective.
This interpretation of Statements 141 and 142 would affect only the Company's balance sheet classification of oil and natural gas leaseholds. The results of operations and cash flows would not be affected, since these oil and natural gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with accounting rules for oil and natural gas companies provided in Statement of Financial Accounting Standards No. 19 "Financial Accounting and Reporting by Oil and Gas Producing Companies."
At December 31, 2003, the Company had unproved and proved leasehold of approximately $5 million and $100 million that would have been classified on the balance sheet as unproved intangible oil and natural gas properties and intangible acquired proved leaseholds, respectively, if the Company had applied the interpretation currently being deliberated by the Emerging Issues Task Force (EITF). The Company will continue to classify oil and natural gas leaseholds as oil and natural gas properties until further guidance is provided.
(21) SUPPLEMENTARY OIL AND NATURAL GAS DISCLOSURES -- (UNAUDITED)
Our December 31, 2003 and 2002 estimates of proved reserves are based on reserve reports prepared by Netherland, Sewell & Associates, Inc. and Ryder Scott Company, L.P., independent petroleum engineers, and the December 31, 2001 estimates are based on a reserve report prepared by Netherland, Sewell & Associates, Inc. Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved-developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth the Company's net proved reserves, including the changes therein, and proved-developed reserves:
Capitalized costs for oil and natural gas producing activities consist of the following:
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, 2003, 2002 and 2001 are as follows:
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.
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:
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, 2003, 2002 and 2001 is as follows:
The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2003 was based on period-end prices of $6.15 per Mcf for natural gas and $30.88 per barrel for crude oil. The December 31, 2002 computation was based on period-end prices of $4.83 per Mcf for natural gas and $29.53 per barrel for crude oil. The December 31, 2001 computation was based on period-end prices of $2.71 per Mcf for natural gas and $18.21 per barrel for crude oil. Spot prices as of February 25, 2004 were $5.08 per Mmbtu for natural gas and $32.50 per barrel for crude oil before adjustment for lease quality, transportation fees and price differentials.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. 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 October 2003, we implemented a new accounting system that contains general ledger, payables and receivables, fixed assets and other related accounting functions. Certain new accounting processes and procedures were implemented at that time to support the new software. This system change is the result of our process to evaluate and upgrade or replace systems and related processes to support our evolving operational needs. During the period from implementation through December 31, 2003, the new system and supporting processes were used to record and report our financial results, which are included in our consolidated totals. Following evaluation, management believes that the new system has been successfully implemented. Except for the new accounting system, there was no change in our internal control over financial reporting during the quarter ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Our management, including the Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all errors and all fraud. 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.
PART III
ITEM 10.
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 13, 2004, 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. Prior to the time of our 2004 Annual
Meeting of Stockholders the code of ethics will be posted 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.
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 13, 2004, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Except as set forth below, 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 13, 2004, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table provides information as of December 31, 2003, with respect to compensation plans under which our equity securities are authorized for issuance.
See note 15 to our consolidated financial statements for further information regarding the significant features of the above plans.
ITEM 13.
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 13, 2004, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 14.
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 13, 2004, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
1. Financial Statements:
The following financial statements are included in Part II of this Report:
Independent Auditor's Report
Consolidated Balance Sheets as of December 31, 2003 and 2002
Consolidated Statements of Operations for the years ended December 31, 2003, 2002 and 2001
Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2003, 2002 and 2001
Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001
Notes to the Consolidated Financial Statements
2. Reports on Form 8-K
On November 12, 2003 the Company filed a current report on Form 8-K, reporting, under Items 5 and 7, the agreement of Evercore Capital Partners, L.P. and certain of its affiliates to sell 4,544,572 shares of the Company's common stock and enclosing the underwriting agreement dated November 10, 2003.
3. Exhibits
- ---------------
* Filed herewith
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENERGY PARTNERS, LTD.
By: /s/ RICHARD A. BACHMANN ------------------------------------ Richard A. Bachmann Chairman, President 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.
EXHIBIT INDEX
- ---------------
* Filed herewith