EPL Announces Fourth Quarter and Year End Results for 2006

Energy Partners, Ltd. ("EPL” or the "Company”) (NYSE:EPL) today reported financial and operational results for the fourth quarter of 2006 and the full year, including year end 2006 proved reserves and reserve replacement. The Company also noted that its Board of Directors has scheduled meetings for the week of March 5, 2007 regarding its exploration of strategic alternatives. The Company plans an announcement of the status or recommendations as soon as possible thereafter. Financial Results For the fourth quarter of 2006, EPL reported a net loss to common stockholders of $52.5 million, or $1.35 per diluted share, compared to net income for the fourth quarter of 2005 of $28.1 million, or $0.69 per diluted share. While EPL’s production and revenue were near record highs, the Company said the majority of the net loss for the fourth quarter of 2006 was attributable to $77.9 million of pre-tax, non-cash costs associated with property impairments. The majority of the impairments were associated with onshore South Louisiana properties acquired in early 2005 and were due in large part to lower commodity price forecasts as compared with the prior year. The remaining impairment costs were mainly due to mechanical difficulties encountered in one offshore well located in East Cameron 378. The fourth quarter loss also included a total of $11.9 million of pre-tax costs related to the termination of the merger agreement between EPL and Stone Energy Corporation ("Stone”) and legal and financial advisor costs related to the Stone merger, unsolicited offer to acquire EPL by ATS Inc. ("ATS”), a wholly-owned subsidiary of Woodside Petroleum, Ltd. (ASX:WPL), and costs related to EPL’s exploration of strategic alternatives. Excluding the after-tax impact of $57.5 million of impairment costs and the Stone, ATS and strategic alternatives costs, EPL’s adjusted fourth quarter net income, a non-GAAP measure, would have been $4.9 million or $0.13 per basic share (see reconciliation of adjusted net income in the appendix). For the year 2006, the net loss to common stockholders was $50.4 million, or $1.32 per diluted share, compared to net income in 2005 of $72.2 million, or $1.79 per diluted share. The benefit of record annual production and revenue was offset by $84.7 million of non-cash, pre-tax property impairment costs for the full year 2006. The net loss for the year also included $51.5 million of pre-tax costs related to the merger agreement between EPL and Stone and its subsequent termination, and $15.0 million in legal and financial advisor costs associated with the Stone merger, the unsolicited ATS offer, and EPL’s exploration of strategic alternatives. Excluding the after-tax impact of $96.8 million of impairment costs, and the costs related to Stone, ATS and strategic alternatives, EPL’s adjusted 2006 net income, a non-GAAP measure, would have been $46.4 million or $1.21 per basic share (see reconciliation of adjusted net income in the appendix). Revenue for the fourth quarter of 2006 was $111.6 million, up 4% compared to fourth quarter 2005 revenues of $107.3 million. Revenue for the year 2006 was $449.6 million, a 12% increase over 2005 revenues of $402.9 million. Discretionary cash flow, which is cash flow from operations before changes in working capital and exploration expenditures, totaled $65.0 million in the fourth quarter of 2006, versus $98.6 million in the fourth quarter last year. For the full year, discretionary cash flow was $279.1 million compared to $308.8 million in 2005 (see reconciliation of discretionary cash flow in appendix). Cash flow from operations in the most recent quarter was $86.7 million, compared to $16.3 million in the fourth quarter of 2005. Cash flow from operations for 2006 totaled $272.1 million compared to $270.0 million in 2005. In the fourth quarter of 2006, production averaged 27,080 barrels of oil equivalent (Boe) per day, compared to 18,583 Boe per day in the fourth quarter of 2005. While the daily average for the fourth quarter of 27,080 Boe per day was up significantly from the third quarter average of 25,421 Boe per day, it was below the Company’s guidance range of 28,500 to 30,500 Boe per day. This was due primarily to production start-up delays and higher than anticipated downtime, due to inclement weather and mechanical problems, of which the majority have since been resolved. Natural gas production in the fourth quarter of 2006 averaged 105.7 million cubic feet (Mmcf) per day and oil production averaged 9,465 barrels per day. Production for 2006 averaged 25,912 Boe per day, a record high for the Company and a 14% increase over the 2005 average of 22,722 Boe per day. Natural gas production averaged 106.0 Mmcf per day in 2006, and oil production averaged 8,238 barrels per day. Price realizations, all of which are stated net of hedging impact, averaged $53.64 per barrel for oil and $6.67 per thousand cubic feet (Mcf) of natural gas in the fourth quarter of 2006, compared to $45.16 per barrel and $11.39 per Mcf in the fourth quarter of 2005. For 2006, oil price realizations averaged $59.78 per barrel and natural gas averaged $6.96 per Mcf compared to $46.45 per barrel and $8.26 per Mcf in 2005. As of December 31, 2006, the Company had cash on hand of $3.2 million, total debt of $317.0 million, and a debt to total capitalization ratio of 46%. The Company also had $83.0 million of remaining capacity available under its bank facility at year-end 2006. Richard A. Bachmann, EPL’s Chairman and CEO, commented, "Our fourth quarter results were clearly overshadowed by the impairments of properties, in large part related to properties purchased in 2005 in our onshore South Louisiana acquisition. The exploratory success we have enjoyed onshore over the last two years has been offset by the significant negative reserve revisions we took at the end of 2005 on the reserves we acquired and the subsequent impairment of properties this year due in large part to lower price forecasts as compared to the prior year. In addition, our overall 2006 financial results were negatively impacted by the considerable expenses associated with the Stone merger agreement and its subsequent termination, the legal and financial costs associated with the unsolicited offer by ATS, and the additional costs incurred in the exploration of strategic alternatives.” Reserve Replacement and Costs EPL’s proved reserves at year end 2006 stood at 29.9 million barrels of oil and 170.1 billion cubic feet of natural gas, or 58.3 million Boe, down 2% from 59.3 million Boe at year end 2005. EPL’s proved reserves at year-end 2006 were 49% natural gas and 51% oil, and 76% were classified as proved developed. In 2006, the Company replaced 92% of its 2006 production at an average cost of $45.97 per Boe, based on total finding and development costs of $398.9 million (see reconciliation in the appendix). EPL added 8.4 million Boe from its exploration and development program. The Company recorded 0.2 million Boe in revisions to its proved reserves in 2006, reflecting overall positive revisions from year-end 2005 reserves for both its Gulf of Mexico ("GOM”) Shelf asset base and its onshore South Louisiana asset base. All of the Company’s proved reserve figures are based upon third party engineering estimates prepared by Ryder Scott Company, L.P. and Netherland, Sewell & Associates, Inc. Bachmann continued, "Our 76% exploratory drilling success rate in 2006 was back to our historical track record, but the percentage replacement of 2006 production was below our expectations. While we had a number of good discoveries during the year, we did not have a sizable success in our high potential, high risk exploratory program. The majority of our discoveries were made on the Shelf and onshore, and were moderate in size. The full reserve potential of these wells was not booked as proved reserves in 2006. With the benefit of more production history in the wells drilled in 2006, we would expect to see significant additions to our proved reserve base in the future from our internal estimates of approximately 5 million Boe of probable reserves associated with those wells, or 9% of our end of year proved reserves. In 2007, we expect to conclude the evaluation of the wells drilled in the deepwater GOM in 2006, and also to drill more moderate risk, high potential wells, with a focus on those around our existing fields in the South Timbalier area.” Operational Highlights EPL drilled 27 exploratory wells in 2006 on the GOM Shelf, in the deepwater GOM and onshore in South Louisiana. At year end, the Company had decisioned 25 of those wells with 16 discoveries in 20 wells offshore and three discoveries in five wells onshore for an overall exploratory success rate of 76%. Overall, EPL experienced an exploratory success rate of 76% in 2006, within the Company’s historical success range, and an improvement over the 2005 success rate of 64%. Two additional wells in the deepwater GOM that also encountered hydrocarbons are still being evaluated. A table of EPL’s 2006 exploratory wells is available in the appendix. In addition to exploratory drilling, EPL drilled two successful development wells, and completed 35 workovers and recompletions in 2006. Three exploratory wells also successfully found the intended development objectives. Overall, EPL was 100% successful in its low risk drillwell program. At year end, undeveloped gross acres stood at 387,938, a 68% increase over the year end 2005 undeveloped acreage of 231,547. Total gross undeveloped and developed acreage at year end 2006 was 607,444 acres. Deepwater In the first quarter of 2006, EPL entered the deepwater GOM through a 25% working interest in 23 undeveloped leases from Noble Energy, Inc. (NYSE:NBL). Currently EPL has ownership in 24 leases. During the year, three deepwater wells were drilled in Mississippi Canyon 204 (Redrock), 248 (Raton), and 292 (Raton South), all of which found hydrocarbons. The first production planned in this area will be from a natural gas interval discovered in the Raton well last year, with production commencing in late 2007 or early 2008. The other two wells in Mississippi Canyon 204 and 292 are under evaluation. The Company currently has ten identified prospects in the deepwater GOM with over 380 million Boe of net unrisked potential reserves on acreage located in the Mississippi Canyon, Garden Banks, Green Canyon, Atwater Valley, and Vioska Knoll areas. 2007 Operational Update Year to date in 2007, EPL has decisioned one well offshore at South Marsh Island 79 #2. The moderate risk, moderate potential well, which reached its intended depth of 11,296 feet, was a dryhole. EPL had a 100% working interest in the well. The Company will recognize dry hole expense of $5.3 million in the first quarter of 2007 in connection with the well. The Company currently has four exploratory wells underway, including the moderate risk, high potential South Timbalier 46 #3 well located on the Shelf, two moderate risk, moderate potential wells located in South Timbalier 26 and South Pass 38 on the Shelf, and one high risk, high potential prospect called Barracuda located onshore in Terrebonne Parish. EPL’s total budget for its 2007 exploration and development program is $300 million and expected to be funded entirely through internally generated cash flow. The Company does not budget for acquisitions. The Company is currently scheduled to drill 17 exploratory wells offshore in 2007 along with six exploratory wells onshore. The exploratory program consists of 23 wells with net unrisked potential reserves of 47 million Boe. Approximately 70% of the exploration budget is dedicated to moderate to high potential prospects in legacy assets and areas with recent discoveries, such as the South Timbalier, East Cameron and Vermilion areas on the Shelf. The budget currently includes seven high potential prospects, with five of the seven wells in the moderate risk category. The Company expects 2007 production to average between 26,000 to 28,000 Boe/day, representing an increase at the upper end of the range of approximately 8% over 2006 annual production of 25,912 Boe/day. EPL has scheduled a conference call to review fourth quarter and year end 2006 results this morning, March 1, 2007, at 8:30 A.M. central time. To participate in the EPL conference call, callers in the United States and Canada can dial (877) 612-5303 and international callers can dial (706) 634-0487. The Conference I.D. for callers is 9215033. The call will be available for replay beginning two hours after the call is completed through midnight of March 6, 2007. For callers in the United States and Canada, the toll-free number for the replay is (800) 642-1687. For international callers the number is (706) 645-9291. The Conference I.D. for all callers to access the replay is 9215033. The conference call will be webcast live as well as for on-demand listening at the Company's web site, www.eplweb.com. Listeners may access the call through the "Conference Calls" link in the Investor Relations section of the site. The call will also be available through the CCBN Investor Network. Founded in 1998, EPL is an independent oil and natural gas exploration and production company based in New Orleans, Louisiana. The Company’s operations are focused along the U. S. Gulf Coast, both onshore in south Louisiana and offshore in the Gulf of Mexico. Forward-Looking Statements This press release contains forward-looking information regarding EPL that is intended to be covered by the safe harbor "forward-looking statements" provided by the Private Securities Litigation Reform Act of 1995. All statements included in this press release that address activities, events or developments that EPL expects, believes or anticipates will or may occur in the future are forward-looking statements. These include statements regarding: reserve and production estimates, oil and natural gas prices, the impact of derivative positions, production expense estimates, cash flow estimates, future financial performance, planned capital expenditures, the completion of any transaction; and other matters that are discussed in EPL's filings with the Securities and Exchange Commission (SEC). These statements are based on current expectations and projections about future events and involve known and unknown risks, uncertainties, and other factors that may cause actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. There is no assurance that the exploration of strategic alternatives will result in any agreements or transactions. Please refer to EPL's filings with the SEC, including Form 10-K for the year ended December 31, 2006 to be filed shortly, for a discussion of these risks. The documents filed with the SEC by EPL may be obtained free of charge from EPL's website at www.eplweb.com or by directing a request to: Energy Partners, Ltd. 201 St. Charles Avenue, Suite 3400, New Orleans, Louisiana 70170, Attn: Secretary, (504) 569-1875. Appendix 2006 Exploratory Wells   Lease Well Number EPL Working Interest Risk Result Region West Cameron 98 (1) #3st 100% Mod Success Shelf West Cameron 3 #1  25% Mod Success Shelf West Cameron 176 #1  25% Mod Success Shelf Vermilion 101 #1  75% Mod Success Shelf South Timbalier 46 (1) #3  100% Mod Success Shelf South Timbalier 42 (1) #2  60% Mod Success Shelf South Marsh Island 79 #1  100% Mod Success Shelf Eugene Island 312 #1  40% Mod Success Shelf East Cameron 46 #A-6 25% Mod Success Shelf East Cameron 268 #1  50% Mod Success Shelf East Cameron 109 #5  75% Mod Success Shelf East Cameron 109 #A-6 50% Mod Success Shelf South Timbalier 23 #CM-2st 27% Mod Success Shelf South Timbalier 23 #SB-15st3 27% Low Success Shelf South Timbalier 23 #CC-4st 27% Low Success Shelf West Cameron 202 #1  25% High Dryhole Shelf South Pass 26 #1 (Denali) 40% High Dryhole Shelf West Cameron 25 #1  100% High Dryhole Shelf Grand Island 66 #1  50% Mod Dryhole Shelf Lakeside Dixie Rice#1 45% High Success Onshore Little Lake #3  50% Mod Success Onshore Little Lake S/L 18143 #1 50% Mod Success Onshore Bay Batiste #1  25% Mod Dryhole Onshore Four Rivers #1  33% Mod Dryhole Onshore Mississippi Canyon 248 #1  25% Mod Success Deepwater Mississippi Canyon 204 #1  25% Mod Evaluating Deepwater Mississippi Canyon 292 #5  25% Mod Evaluating Deepwater   (1) Wells with development sands.   ENERGY PARTNERS, LTD. CONSOLIDATED STATEMENTS OF OPERATIONS (In Thousands, except per share data)   Three Months Ended Years Ended December 31, December 31, 2006  2005  2006  2005  (Unaudited) (Unaudited) Revenues: Oil and natural gas $111,592  $106,345  $449,186  $402,005  Other 42  919  364  942  111,634  107,264  449,550  402,947    Costs and expenses: Lease operating 14,092  9,711  58,808  50,431  Transportation expense 490  258  2,028  1,051  Taxes, other than on earnings 2,684  2,114  13,632  10,372  Exploration expenditures, dry hole costs and impairments 81,934  29,904  136,425  82,844  Depreciation, depletion and amortization 58,996  23,148  198,162  99,524  Accretion expense 1,322  1,071  4,572  4,125  General and administrative 26,919  12,922  120,113  43,205  Other expense 1,478  -  4,022  -  Total costs and expenses 187,915  79,128  537,762  291,552    Business interruption recovery 1,293  20,632  32,869  20,632    Income (loss) from operations (74,988) 48,768  (55,343) 132,027    Other income (expense): Interest income 348  263  1,428  781  Interest expense (7,380) (4,809) (24,570) (18,121) (7,032) (4,546) (23,142) (17,340)     Income (loss) before income taxes (82,020) 44,222  (78,485) 114,687  Income taxes 29,474  (16,118) 28,085  (41,592)   Net income (loss) (52,546) 28,104  (50,400) 73,095    Less dividends earned on preferred stock and accretion of discount -  -  -  (944)   Net income (loss) available to common stockholders $(52,546) $28,104  $(50,400) $72,151    Basic earnings (loss) per share $(1.35) $0.74  $(1.32) $1.94    Diluted earnings (loss) per share $(1.35) $0.69  $(1.32) $1.79    Weighted average common shares used in computing income (loss) per share: Basic 38,947  37,984  38,313  37,097  Incremental common shares -  2,877  -  3,662  Diluted 38,947  40,861  38,313  40,759        Net income (loss) available to common stockholders, as reported: $(52,546) $28,104  $(50,400) $72,151  Add back: Impact of property impairments on the periods presented 77,939  7,968  84,680  17,907    Impact of merger and acquisition costs on the periods presented 11,873  -  66,520  -    Deduct: Impact of income taxes on impairments and merger and acquisition costs at a rate of 36% (32,332) (2,868) (54,432) (6,447)           Adjusted Non-GAAP net income (Unaudited) $4,934  $33,204  $46,368  $83,611    The table above reconciles net income (loss) as reported to an adjusted non-GAAP amount and is provided as supplemental information, and should not be relied upon as alternative measures to GAAP. The Company's management utilizes both the GAAP and the non-GAAP results, calculated above, to evaluate the Company's performance and believes that comparative analysis of results can be enhanced by excluding the impact of the certain items. Management believes in certain cases, the Company's GAAP results are not indicative of the Company's operating performance for the applicable period, nor should they be considered in developing trend analysis for future periods. Specifically, the Company believes that it is useful to provide investors with information regarding the impact of merger and acquisition costs as well as property impairments on the periods presented because these items are not typical and are not expected to be reoccuring at these levels.   ENERGY PARTNERS, LTD. CONSOLIDATED STATEMENTS OF NET CASH PROVIDED BY OPERATING ACTIVITIES (In Thousands)   Three Months Ended Years Ended December 31, December 31, 2006  2005  2006  2005  (Unaudited) (Unaudited) Cash flows from operating activities: Net income (loss) $(52,546) $28,104  $(50,400) $73,095  Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 60,318  24,219  202,734  103,649  (Gain) loss on sale of oil and natural gas assets 550  (869) 4,047  (777) Stock-based compensation 3,070  550  11,038  6,817  Deferred income taxes (29,124) 16,114  (27,452) 41,242  Exploration expenditures 80,341  28,718  122,449  69,926  Amortization of deferred financing costs 429  249  1,133  995  Other 392  292  1,587  966  Changes in operating assets and liabilities: Trade accounts receivable (1,582) (32,572) 2,390  (18,985) Other receivables 35,111  (36,881) (8,966) (43,703) Prepaid expenses (1,770) 1,282  (391) (894) Other assets (419) (607) 283  (2,338) Accounts payable and accrued expenses (8,977) (12,318) 13,599  40,073  Other liabilities 897  17  23  (97)   Net cash provided by operating activities $86,690  $16,298  $272,074  $269,969    Reconciliation of discretionary cash flow: Net cash provided by operating activities 86,690  16,298  272,074  269,969  Changes in working capital (23,260) 81,079  (6,938) 25,944  Non-cash exploration expenditures (80,341) (28,718) (122,449) (69,926) Total exploration expenditures 81,934  29,904  136,425  82,844  Discretionary cash flow (Unaudited) $65,023  $98,563  $279,112  $308,831    The table above reconciles discretionary cash flow to net cash provided by operating activities. Discretionary cash flow is defined as cash flow from operations before changes in working capital and exploration expenditures. Discretionary cash flow is widely accepted as a financial indicator of an oil and natural gas company's ability to generate cash which is used to internally fund exploration and development activities, pay dividends and service debt. Discretionary cash flow is presented based on management's belief that this non-GAAP financial measure is useful information to investors because it is widely used by professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. Many investors use the published research of these analysts in making their investment decisions. Discretionary cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as defined by GAAP, or as a measure of liquidity, or an alternative to net income. Investors should be cautioned that discretionary cash flow as reported by us may not be comparable in all instances to discretionary cash flow as reported by other companies.   ENERGY PARTNERS, LTD. SELECTED PRODUCTION, PRICING AND OPERATIONAL STATISTICS (Unaudited)   Three Months Ended Years Ended December 31, December 31, 2006  2005  2006  2005    PRODUCTION AND PRICING Net Production (per day): Oil (Bbls) 9,465  4,916  8,238  7,984  Natural gas (Mcf) 105,687  82,001  106,042  88,430  Total (Boe) 27,080  18,583  25,912  22,722  Oil and Natural Gas Revenues (in thousands): Oil $46,705  $20,423  $179,752  $135,359  Natural gas 64,887  85,922  269,434  266,646  Total 111,592  106,345  449,186  402,005  Average Sales Prices: Oil (per Bbl) $53.64  $45.16  $59.78  $46.45  Natural gas (per Mcf) 6.67  11.39  6.96  8.26  Average (per Boe) 44.79  62.20  47.49  48.47    Impact of hedging: Oil (per Bbl) $-  $(6.50) $-  $(3.15) Natural gas (per Mcf) 0.03  (1.03) (0.02) (0.24)   OPERATIONAL STATISTICS Average Costs (per Boe): Lease operating expense $5.66  $5.68  $6.22  $6.08  Taxes, other than on earnings 1.08  1.24  1.41  1.25  Depreciation, depletion and amortization 23.68  13.54  20.95  12.00  Accretion expense 0.53  0.63  0.48  0.50    ENERGY PARTNERS, LTD. CONSOLIDATED BALANCE SHEETS (In Thousands, except share data)   December 31, December 31, 2006  2005  (Unaudited) ASSETS Current assets: Cash and cash equivalents $3,214  $6,789  Trade accounts receivable 74,132  78,326  Other receivables 58,269  49,303  Deferred tax asset 1,387  5,582  Prepaid expenses 3,570  3,179  Total current assets 140,572  143,179    Property and equipment, at cost under the successful efforts method of accounting for oil and natural gas properties 1,527,304  1,189,078  Less accumulated depreciation, depletion and amortization (680,845) (418,347) Net property and equipment 846,459  770,731    Other assets 13,029  13,284  Deferred financing costs -- net of accumulated amortization 3,785  4,091  $1,003,845  $931,285    LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $47,154  $28,810  Accrued expenses 133,198  108,087  Fair value of commodity derivative instruments 1,552  9,875  Current maturities of long-term debt -  109  Total current liabilities 181,904  146,881    Long-term debt 317,000  235,000  Deferred income taxes 62,451  87,559  Asset retirement obligation 68,767  56,039  Other 1,453  11,213  631,575  536,692    Stockholders’ equity: Preferred stock, $1 par value, authorized 1,700,000 shares; no shares issued and outstanding -  -  Common stock, par value $0.01 per share. Authorized 100,000,000 shares; issued and outstanding: 2006 – 42,501,726 shares; 2005 – 41,468,093 shares 425  415  Additional paid-in capital 365,313  348,863  Accumulated other comprehensive loss (994) (12,619) Retained earnings 64,966  115,366  Treasury stock, at cost. 2006 - 3,479,814 and 2005 - 3,474,208 shares (57,440) (57,432) Total stockholders’ equity 372,270  394,593  Commitments and contingencies       $1,003,845  $931,285    ENERGY PARTNERS, LTD. SUPPLEMENTAL OIL & NATURAL GAS DISCLOSURE (Unaudited)   Crude Oil Natural Gas Equivalents (Mbbl) (Mmcf) (Mboe) Proved developed and undeveloped reserves:   December 31, 2003 27,414  134,404  49,815    Extensions, discoveries and other additions 3,232  67,049  14,407  Revisions 1,295  (21,570) (2,300) Production (3,171) (30,048) (8,179) December 31, 2004 28,770  149,835  53,743    Purchases of reserves in place 3,949  52,690  12,731  Extensions, discoveries and other additions 1,086  24,490  5,168  Revisions 587  (27,789) (4,045) Production (2,914) (32,277) (8,294) December 31, 2005 31,478  166,949  59,303    Sales of reserves in place (129) (750) (254) Extensions, discoveries and other additions 1,057  44,336  8,446  Revisions 515  (1,704) 231  Production (3,007) (38,708) (9,458) December 31, 2006 29,914  170,123  58,268    Proved developed reserves:   December 31, 2004 24,737  102,760  41,864  December 31, 2005 25,646  103,627  42,917  December 31, 2006 24,811  117,392  44,376    Costs incurred for oil and natural gas property acquisition, exploration and development activities for the three-years ended December 31 are as follows (in Thousands):   2006  2005  2004      Business combinations 420  171,358  2,166    Lease acquisitions 15,896  27,622  6,551  Exploration 224,147  171,859  113,278  Development 158,837  107,910  72,235  Total finding and development costs 398,880  307,391  192,064  Total finding, development and acquisition costs 399,300  478,749  194,230  Asset retirement liabilities incurred 5,947  7,151  3,686  Asset retirement revisions 2,562  (247) (189) Total cost incurred $407,809  $485,653  $197,727    All of the amounts reflected as business combinations in 2006 and 2004 and $0.9 million in 2005 relate to the contingent consideration payments made to former Hall-Houston shareholders.