-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, MFrgbe51Q6ZNm6SL8auhEVxXLj3ttX/+49Knkdz9EOAijyekc2OYG0prtpWoQcoX JpC85kcOuRrMmJc6VL6X2A== 0000950129-04-000531.txt : 20040209 0000950129-04-000531.hdr.sgml : 20040209 20040209173013 ACCESSION NUMBER: 0000950129-04-000531 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20040202 ITEM INFORMATION: ITEM INFORMATION: Financial statements and exhibits FILED AS OF DATE: 20040209 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NOBLE ENERGY INC CENTRAL INDEX KEY: 0000072207 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 730785597 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-07964 FILM NUMBER: 04578967 BUSINESS ADDRESS: STREET 1: 100 GLENBOROUGH STREET 2: SUITE 100 CITY: HOUSTON STATE: TX ZIP: 77067 BUSINESS PHONE: 2818723100 MAIL ADDRESS: STREET 1: 100 GLENBOROUGH STREET 2: SUITE 100 CITY: HOUSTON STATE: TX ZIP: 77067 FORMER COMPANY: FORMER CONFORMED NAME: NOBLE AFFILIATES INC DATE OF NAME CHANGE: 20020426 FORMER COMPANY: FORMER CONFORMED NAME: NOBLE AFFILIATES INC DATE OF NAME CHANGE: 19920703 8-K 1 h12337e8vk.txt NOBLE ENERGY, INC.- FEBRUARY 2, 2004 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ------------------------- FORM 8-K ------------------------- CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of Report (Date of earliest event reported): FEBRUARY 2, 2004 NOBLE ENERGY, INC. (Exact name of Registrant as specified in its charter) DELAWARE 001-07964 73-0785597 (State or other jurisdiction of Commission (I.R.S. Employer incorporation or organization) File Number Identification No.) 100 GLENBOROUGH, SUITE 100 HOUSTON, TEXAS 77067 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (281) 872-3100 ___________________________________________________________________________ (Former name, former address and former fiscal year, if changed since last report) ================================================================================ ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS. (c) Exhibits. The following exhibits are furnished as part of this current Report on Form 8-K: 99.1 Press Release dated February 2, 2004. 99.2 Press Release dated February 3, 2004 99.3 Transcript of Conference Call held by Noble Energy, Inc. on February 3, 2004. ITEM 12. RESULTS OF OPERATIONS AND FINANCIAL CONDITION. On February 2, 2004 Noble Energy, Inc. (the "Company") issued a press release announcing its 2003 reserve replacement estimates and year-end reserve data. A copy of the press release issued by the Company is attached hereto as Exhibit 99.1. On February 3, 2004 the Company issued a press release announcing its financial results for its full year and fourth quarter ended December 31, 2003. Shortly thereafter on February 3, 2004, the Company hosted a conference call to discuss its full year and forth quarter results, including a question and answer period. A replay of the conference call is available through May 3, 2004 on the Company's website at www.nobleenergyinc.com/InvestorRelations. A copy of the press release issued by the Company and the transcript of the conference call are attached hereto as Exhibits 99.2 and 99.3. The Company's press release announcing its financial results for its fourth quarter ended December 31, 2003 contains non-GAAP financial measures. Generally, a non-GAAP financial measure is a numerical measure of a company's performance, financial position, or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with United States generally accepted accounting principles, or GAAP. Pursuant to the requirements of Regulation G, the Company has provided quantitative reconciliations within the press release of the non-GAAP financial measures to the most directly comparable GAAP financial measures. The information in this Form 8-K and Exhibits 99.1, 99.2 and 99.3 shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liabilities of that Section. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. NOBLE ENERGY, INC. Date: February 9, 2004 By: /s/ JAMES L. McELVANY ------------------------------------- James L. McElvany Senior Vice President-Finance, Chief Financial Officer and Treasurer INDEX TO EXHIBITS Item Exhibit ---- ------- 99.1 Press Release dated February 2, 2004 99.2 Press Release dated February 3, 2004 99.3 Transcript of Conference Call held by Noble Energy, Inc. on February 3, 2004 EX-99.1 3 h12337exv99w1.txt PRESS RELEASE DATED FEBRUARY 2, 2004 EXHIBIT 99.1 [noble energy LOGO] NEWS RELEASE 100 GLENBOROUGH DRIVE CONTACT: Greg Panagos: 281-872-3125 SUITE 100 Investor_Relations@nobleenergyinc.com HOUSTON, TX 77067 NOBLE ENERGY ESTIMATES 2003 RESERVE REPLACEMENT OF 118 PERCENT; YEAR-END RESERVES TOTAL 2.7 TRILLION CUBIC FEET HOUSTON (February 2, 2004) -- Noble Energy, Inc. (NYSE: NBL) today announced that it expects to record a full year 2003 reserve replacement rate of 118 percent of global production from all sources excluding sales. The average finding and development cost is expected to be $2.16 per thousand cubic feet equivalent (Mcfe). As of December 31, 2003 Noble Energy expects to record total proved reserves of 2.7 trillion cubic feet equivalent (Tcfe), a decrease of slightly over two percent compared to the previous year-end. During 2003, Noble Energy sold reserves of approximately 108 Bcfe, or four percent of year-end 2002 proved reserves. Excluding the impact of property sales, total proved reserves would have increased nearly two percent year-on-year. Reserve additions from extensions, discoveries and other additions totaled 217 Bcfe, revisions added 39 Bcfe, and purchases accounted for another six Bcfe. Associated exploration, development and acquisition costs were $567 million, which included $289 million of expenditures associated with development projects in Israel and Equatorial Guinea where proved reserves were predominately recognized in prior years. Worldwide production totaled 222 billion cubic feet equivalent (Bcfe) in 2003. Reserve replacement for international operations is estimated to be 265 percent of production for 2003, with an average finding and development cost of $1.74 per Mcfe. International production totaled 71 Bcfe in 2003. International reserve additions from extensions, discoveries and other additions are expected to total 160 Bcfe, with revisions adding another 29 Bcfe of proved reserves. Exploration and development costs are estimated to be $329 million. Domestic reserve replacement from all sources excluding sales is estimated to be 48 percent of production, with an average finding and development cost of $3.26 per Mcfe. Domestic reserve additions from extensions, discoveries and other additions are expected to total 56 Bcfe, revisions would add another 11 Bcfe, and purchases would add six Bcfe. Exploration and development costs are estimated to be $238 million. Domestic production totaled 151 Bcfe. Domestic onshore is expected to replace 118 percent of 2003 production from all sources at a cost of $1.48 per Mcfe. Onshore reserve additions came predominantly from the Gulf Coast drilling program. Domestic offshore is not expected to replace production due to restrained capital allocation. Of 2003 offshore capital, 52 percent was directed toward developing prior discoveries, carryover wells or discoveries not yet booked. In addition, a negative revision of 13 Bcfe was made for an offshore property where recompletion and remediation activities produced less than expected results. In the deepwater Gulf of Mexico, Noble Energy announced a discovery at Green Canyon Block 199 (Lorien). An appraisal well is planned for 2004 and, if successful, the company will book significant proved reserves from the Lorien discovery. Including resources from the Lorien discovery in 2003 reserve additions would have substantially reduced offshore unit finding and development costs and increased the reserve replacement rate. For the past three years, Noble Energy has engaged Netherland, Sewell and Associates to perform an audit of the company's procedures and methods used to estimate proven reserves. Netherland, Sewell and Associates' audit for 2003 included a review of the areas representing the top 80 percent of Noble Energy's reserves. In addition, Noble Energy has obtained independent third-party estimates for several major international properties including those in Ecuador, Equatorial Guinea and Israel. Noble Energy is one of the nation's leading independent energy companies and operates throughout major basins in the United States including the Gulf of Mexico, as well as internationally, in Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea and the North Sea. Noble Energy markets natural gas and crude oil through its subsidiary, Noble Energy Marketing, Inc. This news release may include projections and other "forward-looking statements" within the meaning of the federal securities laws. Any such projections or statements reflect Noble Energy's current views about future events and financial performance. No assurances can be given that such events or performance will occur as projected and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, the volatility in commodity prices for oil and gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, competition, government regulation or other action, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy's business that are detailed in its Securities and Exchange Commission filings. -xxx- PR 252 02/02/04 2 EX-99.2 4 h12337exv99w2.txt PRESS RELEASE DATED FEBRUARY 3, 2004 EXHIBIT 99.2 (NOBLE ENERGY LOGO) NEWS RELEASE 100 GLENBOROUGH DRIVE CONTACT: Greg Panagos: 281-872-3125 SUITE 100 Investor_Relations@nobleenergyinc.com HOUSTON, TX 77067 NOBLE ENERGY ANNOUNCES FULL YEAR AND FOURTH QUARTER 2003 RESULTS Cash Flow Reached Record High of $639 Million For 2003 HOUSTON (February 3, 2004) -- Noble Energy, Inc. (NYSE: NBL) today reported full year and fourth quarter 2003 results. For the full year 2003, net income was $78.0 million, or $1.37 per share. Discretionary cash flow (see Determination of Discretionary Cash Flow and Reconciliation schedule) for the year was a record $638.9 million. For the fourth quarter 2003, the company reported a net loss of $21.1 million, or 37 cents per share, and discretionary cash flow was $171.5 million. Full year and fourth quarter 2003 income from continuing operations included a pretax, non-cash charge for asset impairments of $31.9 million ($20.8 million after tax), primarily related to a reserve revision on the East Cameron 338 field in the Gulf of Mexico after recompletion and remediation activities produced less-than-expected results. An analysis of the performance response of the field resulted in a reduction in proved reserves of 2.2 million barrels of oil equivalent. The impairment should result in substantially lower depletion costs in 2004. As previously announced on December 17, 2003, full year and fourth quarter continuing operations also included a pretax, non-cash exploration charge of $20.2 million ($5.9 million after tax) to write off the company's investment in Vietnam. Noble Energy realized a $14.3 million current tax benefit as a result of the Vietnam write-off. Discontinued operations reported a net loss of $20.9 million for the quarter, or 37 cents per share. Net income from discontinued operations included a pretax, non-cash charge of $45.8 million ($29.8 million after tax) for losses on the disposition of assets and to write down assets held for sale to their estimated fair value, which were also announced on December 17, 2003. For the year, discontinued operations reported a loss of $6.1 million, or 11 cents per share, including a pretax, non-cash charge of $59.2 million ($38.5 million after tax) for losses on the disposition of assets and to write down assets held for sale to their estimated fair value. Excluding the effects of special charges, which include the asset impairments, the Vietnam write-off, the loss on asset sales and the write down of assets held for sale, Noble Energy's net income for the fourth quarter 2003 would have been $35.4 million, or 62 cents per share. Adding back these special charges and the cumulative effect of change in accounting principle ($5.8 million after tax) to full year 2003 results, net income would have been $149.0 million, or $2.62 per share. (See Determination of Non-GAAP Measures, Table 1.) Charles Davidson, Noble Energy's Chairman, President and CEO, said, "This past year was strong with record cash flow, and we made substantial progress in 2003 toward completing the transformation of our company. Our international business is now poised to contribute significantly for years to come. Our projects in China, Ecuador and Israel are now complete. In Equatorial Guinea, Phase 2A production is ramping up and Phase 2B is scheduled for completion by year-end, so our international capital commitments are declining rapidly while free cash flow will be increasing. Our domestic operations have fully implemented disciplined business processes that have stabilized production. As a result, Noble Energy has the financial and operational flexibility to take advantage of new opportunities to create value." FULL YEAR 2003 Excluding special charges and the cumulative effect of change in accounting principle, full year 2003 net income was $149.0 million, or $2.62 per share, compared to net income of $17.7 million, or 31 cents per share, for the same period last year. Discretionary cash flow for 2003 was $638.9 million compared to last year's $476.8 million. The year-on-year increase in net income and discretionary cash flow resulted primarily from higher production volumes and realized commodity prices. The increase in realized prices that had the greatest impact on earnings and cash flow was in natural gas, which increased 43 percent year-on-year to $4.13 per thousand cubic feet (Mcf) from $2.89 per Mcf last year. The company's average realized liquids price increased 14 percent to $27.72 per barrel (Bbl) compared to $24.22 per Bbl last year. Compared to 2002, realized methanol and power prices increased by 51 percent and 13 percent, respectively. Reported production from continuing operations for the year increased seven percent to 92,116 barrels of oil equivalent per day (Boepd) from 85,949 Boepd. International volumes increased 6,650 Boepd, or 26 percent, compared to last year, primarily because of increased production in Equatorial Guinea and a full year of operations at Noble Energy's power plant in Ecuador. Domestic volumes were virtually unchanged compared to last year. Excluding the impact of property sales and discontinued operations, overall production increased four percent compared to the prior year. Exploration expense totaled $148.8 million, including the non-cash charge to write off the company's investment in Vietnam. Excluding the Vietnam write-off, exploration expense declined 15 percent compared to $150.7 million last year. (See Determination of Non-GAAP measures, Table 5.) Selling, general and administrative expense for the year was $52.5 million compared to $47.7 million in 2002. The ten percent increase in selling, general and administrative expense primarily reflects increased corporate governance costs, professional fees and other costs related to Sarbanes-Oxley compliance, along with increased salary and legal costs. Oil and gas operating expense for 2003 was $145.8 million compared to $105.4 million last year. The increase in oil and gas operating expense was due to several factors, including new operations in China, increased production and the start-up of Phase 2A in Equatorial Guinea, new production in the Gulf of Mexico and higher production taxes. Including discontinued operations, oil and gas operating expense increased 30 percent compared to 2002. Depreciation, depletion and amortization for 2003 totaled $288.7 million compared to $236.9 million last year. The increase was primarily due to higher domestic depreciation, depletion and amortization rates. Including discontinued operations, depreciation, depletion and amortization increased 11 percent over last year. FOURTH QUARTER 2003 Fourth quarter 2003 net income excluding special charges was $35.4 million, or 62 cents per share, double fourth quarter 2002 net income of $16.8 million, or 29 cents per share. Discretionary cash flow for the fourth quarter 2003 was $171.5 million compared to $149.3 million last year. Noble Energy benefited from higher realized prices for liquids and natural gas during the quarter, which increased ten percent and 12 percent, respectively, compared to the fourth quarter of 2002. The company's average realized liquids price was $28.22 per Bbl compared to $25.77 per Bbl during the fourth quarter of 2002. The company's average realized natural gas price was $3.96 per Mcf compared to $3.55 per Mcf last year. Higher realized methanol and power prices also contributed to improved operating results compared to the fourth quarter 2002, increasing seven percent and nine percent, respectively. Reported fourth quarter 2003 production, net of adjustments for discontinued operations, increased over six percent to 95,070 Boepd compared to third quarter 2003 production of 89,287 Boepd. Reported domestic production increased due to the start-up of new production in the deepwater Gulf of Mexico. 2 International volumes increased because of increased production in Equatorial Guinea, the North Sea and Ecuador. Reported fourth quarter 2003 production volumes increased 11 percent from 85,608 Boepd for the same period last year. The increase in volumes was primarily attributable to the start-up of new projects in the deepwater Gulf of Mexico and operations in China. DOMESTIC OPERATIONS - FOURTH QUARTER 2003 Domestic operations reported a pretax operating loss for the fourth quarter of $41.7 million compared to operating income of $31.6 million for the fourth quarter last year. Excluding non-cash charges for asset impairments, losses on asset sale and the write down to market value, fourth quarter 2003 domestic operating income would have been $36.1 million. (See Determination of Non-GAAP Measures, Table 2.) Domestic operations benefited from higher realized prices for liquids and natural gas during the quarter, which increased 11 percent and eight percent, respectively, compared to the fourth quarter of 2002. The average domestic realized liquids price was $27.08 per Bbl compared to $24.45 per Bbl during the fourth quarter of 2002. The average domestic realized natural gas price was $4.44 per Mcf compared to $4.12 per Mcf last year. During 2003, Noble Energy participated in 100 gross domestic exploration and development wells, of which 64 were successful. INTERNATIONAL OPERATIONS - FOURTH QUARTER 2003 International operations reported operating income for the fourth quarter of $26.1 million compared to $23.6 million in the fourth quarter last year. Fourth quarter 2003 results reflected a 15 percent year-on-year increase in production volumes, higher realized commodity prices and operating income from China, partially offset by the pretax, non-cash charge to write off the company's investment in Vietnam. Excluding the Vietnam write-off, fourth quarter 2003 international operating income would have increased 96 percent to $46.3 million. (See Determination of Non-GAAP Measures, Table 3.) International operations benefited from higher realized prices for liquids and natural gas during the quarter, which increased nine percent and 31 percent, respectively, compared to the fourth quarter of 2002. The average international realized liquids price was $29.24 per Bbl compared to $26.81 per Bbl during the fourth quarter of 2002. The average international realized natural gas price was $1.51 per Mcf compared to $1.15 per Mcf during the fourth quarter of 2002. During 2003, Noble Energy participated in 64 gross international exploration and development wells, of which 58 were successful. Equatorial Guinea Total operating income in Equatorial Guinea, which includes results from field operations and methanol, for the fourth quarter of 2003 increased 36 percent to $22.5 million compared to $16.5 million last year. Liquid petroleum gas (LPG), natural gas and condensate sales accounted for $15.0 million, or 67 percent, of operating income from Equatorial Guinea. Fourth quarter 2003 production volumes averaged 13,266 Boepd compared to 12,946 Boepd last year. The increase in production was due to the start-up of the Phase 2A expansion project, which began producing in November 2003. The average realized price for liquids during the fourth quarter was $29.00 per Bbl compared to $25.63 per 3 Bbl for the same period last year. Natural gas was sold to the Atlantic Methanol Production Company (AMPCO) at a price of 25 cents per Mcf. AMPCO, an unconsolidated subsidiary in which the company owns a 45 percent interest, produced $7.4 million of operating income, net to Noble Energy's interest, during the fourth quarter 2003. AMPCO results are reported as income from unconsolidated subsidiaries. Fourth quarter realized methanol prices were 60 cents per gallon (Gal) compared to 56 cents per Gal last year. The company's share of AMPCO methanol sales volumes was 29.3 million Gal, flat with last year's 29.0 million Gal. North Sea In the North Sea, operating income for the fourth quarter of 2003 increased 67 percent to $15.6 million from $9.3 million last year. The quarter-on-quarter improvement reflects higher crude oil and natural gas prices and lower overall operating costs. Other International Other international, which includes operating results from Argentina, China, Ecuador, Israel and Vietnam, recorded a fourth quarter 2003 operating loss of $12.0 million compared to an operating loss of $2.2 million for fourth quarter last year. The larger operating loss resulted from the write-off of Noble Energy's investment in Vietnam, partially offset by operations in Ecuador and China. Other international operating income for the fourth quarter 2003, excluding the Vietnam write-off, would have been $8.3 million. (See Determination of Non-GAAP Measures, Table 4.) Noble Energy's Machala power plant contributed $2.3 million of operating income during the fourth quarter 2003 compared to $1.5 million for the same period last year. For the quarter, 232,348 megawatts (MW) were produced at an average sales price of 7.2 cents per kilowatt hour (Kwh). For the fourth quarter 2003, Noble Energy produced 26.3 million cubic feet per day of natural gas from the Amistad field at an average price of $3.49 per Mcf. In south Bohai Bay offshore China, production commenced from the Cheng Dao Xi (CDX) field in January 2003. Fourth quarter operating income was $4.0 million. Production averaged 3,158 barrels of oil per day for the fourth quarter. Noble energy has a 57 percent working interest in CDX. Noble Energy is one of the nation's leading independent energy companies and operates throughout major basins in the United States including the Gulf of Mexico, as well as internationally, in Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea and the North Sea. Noble Energy markets natural gas and crude oil through its subsidiary, Noble Energy Marketing, Inc. This news release may include projections and other "forward-looking statements" within the meaning of the federal securities laws. Any such projections or statements reflect Noble Energy's current views about future events and financial performance. No assurances can be given that such events or performance will occur as projected and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, the volatility in commodity prices for oil and gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, competition, government regulation or other action, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy's business that are detailed in its Securities and Exchange Commission filings. -xxx- PR 255 02/03/04 4 NOBLE ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED SUMMARY OF RESULTS (Unaudited) (In thousands, except per share)
Three Months Ended Twelve Months Ended ------------------------ ------------------------ 12/31/2003 12/31/2002 12/31/2003 12/31/2002 ---------- ---------- ---------- ---------- REVENUES Oil and Gas Sales and Royalties $ 214,869 $ 171,420 $ 839,144 $ 609,026 Gathering, Marketing and Processing 13,501 16,920 68,158 64,517 Electricity Sales 16,661 14,326 58,022 18,257 Income From Unconsol. Subs 7,436 8,254 40,626 9,532 Other Income (Loss) (8,026) 274 (15,573) 1,246 ---------- ---------- ---------- ---------- 244,441 211,194 990,377 702,578 ---------- ---------- ---------- ---------- COST AND EXPENSES Oil and Gas Operations 36,465 26,875 145,836 105,358 Transportation 4,109 3,214 14,679 16,441 Oil and Gas Exploration 53,259 43,435 148,818 150,701 Gathering, Marketing and Processing 10,424 13,831 59,114 53,982 Electricity Generation 14,407 12,829 50,846 15,946 Depreciation, Depletion and Amortization 74,401 56,561 288,734 236,881 Impairment of Operating Assets 31,937 31,937 Selling, General and Administrative 11,397 9,423 52,466 47,664 Accretion of Asset Retirement Obligation 2,316 9,331 Interest Expense 14,748 16,948 61,111 64,040 Interest Capitalized (4,556) (2,599) (14,134) (16,331) ---------- ---------- ---------- ---------- 248,907 180,517 848,738 674,682 ---------- ---------- ---------- ---------- INCOME (LOSS) BEFORE INCOME TAXES (4,466) 30,677 141,639 27,896 INCOME TAX PROVISION (BENEFIT) Current (3,098) 3,876 42,975 2,479 Deferred (1,172) 14,539 8,772 17,322 ---------- ---------- ---------- ---------- (4,270) 18,415 51,747 19,801 ---------- ---------- ---------- ---------- INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (196) 12,262 89,892 8,095 DISCONTINUED OPERATIONS (NET OF TAX) (20,854) 4,559 (6,061) 9,557 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX (5,839) ---------- ---------- ---------- ---------- NET INCOME (LOSS) $ (21,050) $ 16,821 $ 77,992 $ 17,652 ========== ========== ========== ========== INCOME (LOSS) PER SHARE BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.00 $ 0.21 $ 1.58 $ 0.14 INCOME (LOSS) PER SHARE FROM DISCONTINUED OPERATIONS $ (0.37) $ 0.08 $ (0.11) $ 0.17 LOSS PER SHARE FROM CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ (0.10) ---------- ---------- ---------- ---------- NET INCOME (LOSS) PER SHARE $ (0.37) $ 0.29 $ 1.37 $ 0.31 ========== ========== ========== ========== AVERAGE SHARES OUTSTANDING 56,816 57,306 56,964 57,196
NOBLE ENERGY, INC. AND SUBSIDIARIES DETERMINATION OF DISCRETIONARY CASH FLOW AND RECONCILIATION (Unaudited) (In thousands)
Three Months Ended Twelve Months Ended -------------------------- -------------------------- 12/31/2003 12/31/2002 12/31/2003 12/31/2002 ---------- ---------- ---------- ---------- Net Income (Loss) $ (21,050) $ 16,821 $ 77,992 $ 17,652 Depreciation, Depletion and Amortization (DD&A) 74,401 56,561 288,734 236,881 Power Project DD&A 7,937 6,892 27,116 8,459 Oil and Gas Exploration 53,259 43,435 148,818 150,701 Interest Capitalized (4,556) (2,599) (14,134) (16,331) Undistributed Earnings From Unconsol. Subs (7,436) (8,254) (40,626) (9,532) Distribution From Unconsol. Subs 8,550 12,334 46,125 23,196 DD&A - Discontinued Operations 1 9,537 28,762 48,405 Non-cash Loss on Asset Disposition 45,835 59,171 Impairment of Operating Assets 31,937 31,937 Change in Accounting Principle, net of tax 5,839 Allowance for Doubtful Accounts (250) 4,686 Deferred Income Tax Provision (Benefit) (19,414)[1] 14,539 (34,855)[2] 17,322 Accretion of Asset Retirement Obligation 2,316 9,331 ---------- ---------- ---------- ---------- DISCRETIONARY CASH FLOW [3] $ 171,530 $ 149,266 $ 638,896 $ 476,753 Adjustments to Reconcile: Working Capital $ (25,637) $ 59,695 $ (26,135) $ 58,863 Cash Exploration Costs (20,697) (18,421) (51,801) (48,051) Capitalized Interest 4,556 2,599 14,134 16,331 Return of Capital - Unconsolidated Subs (5,500) Deferred Tax, Misc. Credits and Other (21,572) 6,009 2,893 5,895 ---------- ---------- ---------- ---------- Net Cash Provided by Operating Activities $ 108,180 $ 199,148 $ 577,987 $ 504,291 ========== ========== ========== ==========
[1] Includes deferred income tax benefit from continuing operations of $1.2 million and discontinued operations of $18.2 million. [2] Includes deferred income tax provision from continuing operations of $8.8 million, and deferred income tax benefit from discontinued operations and the cumulative effect of change in accounting principle of $40.5 million and $3.2 million, respectively. [3] The table above reconciles discretionary cash flow to net cash provided by operating activities. While discretionary cash flow is not a GAAP measure of financial performance, management believes it is a good tool for internal use and the investment community in evaluating the company's overall financial performance. Among management, professional research analysts, portfolio managers and investors following the oil and gas industry, discretionary cash flow is broadly used as an indicator of a company's ability to fund exploration and production activities and meet financial obligations. Discretionary cash flow is also commonly used as a basis to value and compare companies in the oil and gas industry. - -------------------------------------------------------------------------------- CONSOLIDATED CONDENSED BALANCE SHEET (Unaudited) (In thousands)
------------ ------------ 12/31/2003 12/31/2002 ------------ ------------ ASSETS Current Assets $ 537,597 $ 310,374 ------------ ------------ Property, Plant and Equipment 3,924,987 4,334,015 Less: Accumulated Depreciation (1,825,246) (2,194,230) ------------ ------------ 2,099,741 2,139,785 Investment In Unconsol. Subs 227,669 234,668 Other 34,517 45,188 ------------ ------------ $ 2,899,524 $ 2,730,015 ============ ============ LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities $ 711,667 $ 471,754 Long-term Debt 776,021 977,116 Deferred Income Taxes, Other Deferred Credits and Noncurrent Liabilities 337,227 271,759 Shareholders' Equity 1,074,609 1,009,386 ------------ ------------ $ 2,899,524 $ 2,730,015 ============ ============
NOBLE ENERGY, INC. INCOME BEFORE INCOME TAXES (Unaudited) (Dollars in thousands) - -------------------------------------------------------------------------------- THREE MONTHS ENDED 12/31/03
EQUATORIAL OTHER CORPORATE CONSOLIDATED DOMESTIC NORTH SEA GUINEA INTERNATIONAL [1] AND OTHER [2] ------------ ----------- ----------- ----------- ----------------- ------------- REVENUES Oil Sales $ 105,311 $ 47,743 $ 21,625 $ 20,172 $ 15,771 Gas Sales [3] 109,558 102,759 5,981 787 31 Gathering, Marketing and Processing Revenue 13,501 13,501 Electricity Sales 16,661 16,661 Income from Unconsolidated Subsidiaries 7,436 7,436 Other (8,026) (8,554) 1,399 293 (1,164) ----------- ----------- ----------- ----------- ----------- ----------- Total Revenues 244,441 141,948 29,005 28,395 32,756 12,337 COSTS AND EXPENSES Oil and Gas Operations 36,465 24,214 2,532 4,354 4,308 1,057 Transportation 4,109 2,604 1,505 Oil and Gas Exploration 53,259 30,191 2,287 83 20,282 416 Gathering, Marketing and Processing Expense 10,424 10,424 Electricity Generation 14,407 14,407 DD&A 74,401 61,753 5,991 1,223 4,456 978 Impairment of Operating Assets 31,937 31,937 SG&A 11,397 3,425 264 (251) 7,959 Interest Expense (net) 12,508 12,508 ----------- ----------- ----------- ----------- ----------- ----------- Total Costs and Expenses 248,907 151,520 13,414 5,924 44,707 33,342 OPERATING INCOME (LOSS) $ (4,466) $ (9,572) $ 15,591 $ 22,471 $ (11,951) $ (21,005) Discontinued Operations (32,083) (32,083) ----------- ----------- ----------- ----------- ----------- ----------- OPERATING INCOME AFTER DISCONTINUED OPERATIONS $ (36,549) $ (41,655) $ 15,591 $ 22,471 $ (11,951) $ (21,005) =========== =========== =========== =========== =========== =========== KEY STATISTICS DAILY PRODUCTION Liquids (Bbl) 40,567 19,167 7,928 7,560 5,912 Natural Gas (Mcf) 327,015 251,602 13,992 34,236 27,185 AVERAGE REALIZED PRICE Liquids $ 28.22 $ 27.08 $ 29.65 $ 29.00 $ 29.00 Natural Gas $ 3.96 $ 4.44 $ 4.65 $ 0.25 $ 0.39
- -------------------------------------------------------------------------------- THREE MONTHS ENDED 12/31/02
EQUATORIAL OTHER CORPORATE CONSOLIDATED DOMESTIC NORTH SEA GUINEA INTERNATIONAL [1] AND OTHER [2] ------------ ----------- ----------- ----------- ----------------- ------------- REVENUES Oil Sales $ 66,420 $ 27,582 $ 19,532 $ 14,291 $ 4,954 $ 61 Gas Sales 105,000 99,721 5,244 908 35 (908) Gathering, Marketing and Processing Revenue 16,920 16,920 Electricity Sales 14,326 14,326 Income from Unconsolidated Subsidiaries 8,254 8,254 Other 274 511 565 (1,055) 253 ----------- ----------- ----------- ----------- ----------- ----------- Total Revenues 211,194 127,814 25,341 23,453 18,260 16,326 COSTS AND EXPENSES Oil and Gas Operations 26,875 19,167 3,117 2,876 1,168 547 Transportation 3,214 2,452 762 Oil and Gas Exploration 43,435 36,755 1,742 1,339 3,673 (74) Gathering, Marketing and Processing Expense 13,831 13,831 Electricity Generation 12,829 12,829 DD&A 56,561 44,149 8,452 1,997 1,609 354 SG&A 9,423 3,191 253 752 410 4,817 Interest Expense (net) 14,349 14,349 ----------- ----------- ----------- ----------- ----------- ----------- Total Costs and Expenses 180,517 103,262 16,016 6,964 20,451 33,824 OPERATING INCOME (LOSS) $ 30,677 $ 24,552 $ 9,325 $ 16,489 $ (2,191) $ (17,498) Discontinued Operations 7,014 7,014 ----------- ----------- ----------- ----------- ----------- ----------- OPERATING INCOME AFTER DISCONTINUED OPERATIONS $ 37,691 $ 31,566 $ 9,325 $ 16,489 $ (2,191) $ (17,498) =========== =========== =========== =========== =========== =========== KEY STATISTICS DAILY PRODUCTION Liquids (Bbl) 27,984 12,262 7,567 6,060 2,095 Natural Gas (Mcf) 345,746 262,956 16,096 41,314 25,380 [3] AVERAGE REALIZED PRICE Liquids $ 25.77 $ 24.45 $ 28.06 $ 25.63 $ 25.70 Natural Gas $ 3.55 $ 4.12 $ 3.54 $ 0.24 $ 0.31
NOBLE ENERGY, INC. INCOME BEFORE INCOME TAXES (Unaudited) (Dollars in thousands) - -------------------------------------------------------------------------------- TWELVE MONTHS ENDED 12/31/03
EQUATORIAL OTHER CORPORATE CONSOLIDATED DOMESTIC NORTH SEA GUINEA INTERNATIONAL[1] AND OTHER[2] ------------ --------- --------- ---------- ---------------- ------------ REVENUES Oil Sales $ 364,382 $ 153,891 $ 81,019 $ 65,016 $ 64,456 Gas Sales[3] 474,762 451,476 19,539 3,628 119 Gathering, Marketing and Processing Revenue 68,158 68,158 Electricity Sales 58,022 58,022 Income from Unconsolidated Subsidiaries 40,626 40,626 Other (15,573) (19,690) 1,105 (689) 3,701 --------- --------- --------- --------- --------- --------- Total Revenues 990,377 585,677 101,663 109,270 121,908 71,859 COSTS AND EXPENSES Oil and Gas Operations 145,836 96,260 10,662 16,319 18,630 3,965 Transportation 14,679 9,024 5,655 Oil and Gas Exploration 148,818 94,691 10,503 134 41,699 1,791 Gathering, Marketing and Processing Expense 59,114 59,114 Electricity Generation 50,846 50,846 DD&A 288,734 233,432 28,219 6,115 18,244 2,724 Impairment of Operating Assets 31,937 31,937 SG&A 52,466 15,884 603 1,872 34,107 Interest Expense (net) 56,308 56,308 --------- --------- --------- --------- --------- --------- Total Costs and Expenses 848,738 472,204 58,408 23,171 136,946 158,009 OPERATING INCOME (LOSS) $ 141,639 $ 113,473 $ 43,255 $ 86,099 $ (15,038) $ (86,150) Discontinued Operations (9,325) (9,325) Cumulative Effect of SFAS 143 (8,983) (8,983) --------- --------- --------- --------- --------- --------- OPERATING INCOME AFTER DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT $ 123,331 $ 95,165 $ 43,255 $ 86,099 $ (15,038) $ (86,150) ========= ========= ========= ========= ========= ========= KEY STATISTICS DAILY PRODUCTION Liquids (Bbl) 36,014 16,084 7,412 6,377 6,141 Natural Gas (Mcf) 336,611 260,560 13,861 39,906 22,284 AVERAGE REALIZED PRICE Liquids $ 27.72 $ 26.21 $ 29.95 $ 27.93 $ 28.75 Natural Gas $ 4.13 $ 4.75 $ 3.86 $ 0.25 $ 0.41
- -------------------------------------------------------------------------------- TWELVE MONTHS ENDED 12/31/02
EQUATORIAL OTHER CORPORATE CONSOLIDATED DOMESTIC NORTH SEA GUINEA INTERNATIONAL[1] AND OTHER[2] ------------ --------- --------- ---------- ---------------- ------------ REVENUES Oil Sales $ 257,435 $ 112,010 $ 72,041 $ 45,830 $ 27,377 $ 177 Gas Sales 351,591 331,935 19,497 3,052 160 (3,053) Gathering, Marketing and Processing Revenue 64,517 64,517 Electricity Sales 18,257 18,257 Income from Unconsolidated Subsidiaries 9,532 9,532 Other 1,246 100 389 (1,254) 2,011 --------- --------- --------- --------- --------- --------- Total Revenues 702,578 444,045 91,927 58,414 44,540 63,652 COSTS AND EXPENSES Oil and Gas Operations 105,358 82,381 10,812 9,848 5,191 (2,874) Transportation 16,441 9,618 6,823 Oil and Gas Exploration 150,701 120,695 5,210 1,341 23,454 1 Gathering, Marketing and Processing Expense 53,982 53,982 Electricity Generation 15,946 15,946 DD&A 236,881 192,708 28,279 5,849 8,962 1,083 SG&A 47,664 27,768 630 2,045 1,100 16,121 Interest Expense (net) 47,709 47,709 --------- --------- --------- --------- --------- --------- Total Costs and Expenses 674,682 423,552 54,549 19,083 61,476 116,022 OPERATING INCOME (LOSS) $ 27,896 $ 20,493 $ 37,378 $ 39,331 $ (16,936) $ (52,370) Discontinued Operations 14,703 14,703 --------- --------- --------- --------- --------- --------- OPERATING INCOME AFTER DISCONTINUED OPERATIONS $ 42,599 $ 35,196 $ 37,378 $ 39,331 $ (16,936) $ (52,370) ========= ========= ========= ========= ========= ========= KEY STATISTICS DAILY PRODUCTION Liquids (Bbl) 29,114 13,187 7,847 5,259 2,821 Natural Gas (Mcf) 341,008 280,836 16,991 34,382 8,799 [3] AVERAGE REALIZED PRICE Liquids $ 24.22 $ 23.29 $ 25.15 $ 23.88 $ 26.58 Natural Gas $ 2.89 $ 3.24 $ 3.14 $ 0.25 $ 0.38
AMPCO METHANOL OPERATIONS (Unaudited) (Dollars in thousands)
Three Months Ended Twelve Months Ended ------------------------ ------------------------ 12/31/2003 12/31/2002 12/31/2003 12/31/2002 ---------- ---------- ---------- ---------- REVENUES Methanol Sales $ 17,601 $ 16,304 $ 79,670 $ 45,604 Sales of Purchased Methanol -- 391 3,825 5,122 Other 2,443 1,555 8,564 3,589 --------- --------- --------- --------- Total Revenues 20,044 18,250 92,059 54,315 COSTS AND EXPENSES Cost of Goods Manufactured 9,729 6,814 35,755 26,457 Cost of Purchased Methanol -- 334 4,157 6,891 DD&A 2,330 2,357 9,420 9,707 SG&A 549 491 2,101 1,728 --------- --------- --------- --------- Total Costs and Expenses 12,608 9,996 51,433 44,783 INCOME/(LOSS) FROM UNCONS. SUBS $ 7,436 $ 8,254 $ 40,626 $ 9,532 ========= ========= ========= ========= Methanol Sales (MGal) 29,269 28,970 122,015 105,126 Average Realized Price ($/Gal) $ 0.60 $ 0.56 $ 0.65 $ 0.43
================================================================================ ECUADOR POWER OPERATIONS (Unaudited) (Dollars in thousands)
Three Months Ended Twelve Months Ended ------------------------ ------------------------ 12/31/2003 12/31/2002 12/31/2003 12/31/2002 ---------- ---------- ---------- ---------- REVENUES Power Sales $ 14,579 $ 12,166 $ 50,378 $ 16,097 Capacity Charge 2,082 2,160 7,644 2,160 --------- --------- --------- --------- Total Revenues 16,661 14,326 58,022 18,257 COSTS AND EXPENSES Field Lease Operating 743 967 2,903 1,451 DD&A 6,882 6,203 23,200 7,307 SG&A 722 480 2,859 998 Plant Fuel 4,012 3,699 14,367 4,085 Non-Fuel 993 791 3,600 953 Depreciation 1,055 689 3,917 1,152 --------- --------- --------- --------- Total Costs and Expenses 14,407 12,829 50,846 15,946 --------- --------- --------- --------- OPERATING INCOME (LOSS) $ 2,254 $ 1,497 $ 7,176 $ 2,311 ========= ========= ========= ========= Natural Gas Production (Mcfpd) [3] 26,317 24,133 21,485 7,638 Average Natural Gas Price $ 3.49 $ 3.08 $ 3.86 $ 3.15 Power Production - Total MW 232,348 217,037 751,689 269,229 Average Power Price ($/Kwh) $ 0.072 $ 0.066 $ 0.077 $ 0.068
- -------------------------------------------------------------------------------- [1] Other international includes operations in Argentina, China, Ecuador, Israel and Vietnam. [2] Corporate and Other includes corporate overhead, intercompany eliminations and marketing. [3] Ecuador natural gas volumes are included in Other International and Consolidated production, but are not included in natural gas sales revenue for either. Because the gas-to-power project in Ecuador is 100 percent owned by Noble Energy, intercompany natural gas sales are eliminated for accounting purposes. NOBLE ENERGY, INC. AND SUBSIDIARIES DISCONTINUED OPERATIONS SUMMARY (Unaudited) (In thousands, except per share)
Three Months Ended Year to Date ---------------------------------------------------------- 12/31/2003 12/31/2003 9/30/2003 6/30/2003 3/31/2003 ---------- ---------- ---------- ---------- ---------- REVENUES Oil and Gas Sales and Royalties $ 106,339 $ 20,036 $ 26,667 $ 26,716 $ 32,920 COST AND EXPENSES Write down to Market Value & Net Realized Loss 59,171 45,835 8,422 4,914 Oil and Gas Operations 27,731 6,283 5,005 8,119 8,324 Depreciation, Depletion and Amortization 28,762 1 7,780 8,668 12,313 ---------- ---------- ---------- ---------- ---------- 115,664 52,119 21,207 21,701 20,637 ---------- ---------- ---------- ---------- ---------- INCOME (LOSS) BEFORE INCOME TAXES (9,325) (32,083) 5,460 5,015 12,283 INCOME TAX PROVISION (BENEFIT) Current 37,219 7,013 24,152 1,755 4,299 Deferred (40,482) (18,242) (22,241) ---------- ---------- ---------- ---------- ---------- (3,264) (11,229) 1,911 1,755 4,299 ---------- ---------- ---------- ---------- ---------- NET INCOME (LOSS) $ (6,061) $ (20,854) $ 3,549 $ 3,260 $ 7,984 ========== ========== ========== ========== ========== KEY STATISTICS: Daily Production Liquids (Bbl) 4,106 2,772 4,091 4,724 4,859 Natural Gas (Mcf) 32,823 30,757 34,396 32,834 33,318 Average Realized Price Liquids ($/Bbl) $ 27.71 $ 27.89 $ 28.11 $ 25.39 $ 29.56 Natural Gas ($/Mcf) $ 5.41 $ 4.57 $ 5.08 $ 5.29 $ 6.67
- --------------------------------------------------------------------------------
Three Months Ended Year to Date ---------------------------------------------------------- 12/31/2002 12/31/2003 9/30/2003 6/30/2003 3/31/2003 ---------- ---------- ---------- ---------- ---------- REVENUES Oil and Gas Sales and Royalties $ 91,576 $ 23,760 $ 23,764 $ 24,460 $ 19,592 COST AND EXPENSES Write down to Market Value & Net Realized Loss Oil and Gas Operations 28,468 7,209 7,542 6,206 7,511 Depreciation, Depletion and Amortization 48,405 9,537 11,636 12,193 15,039 ---------- ---------- ---------- ---------- ---------- 76,873 16,746 19,178 18,399 22,550 ---------- ---------- ---------- ---------- ---------- INCOME (LOSS) BEFORE INCOME TAXES 14,703 7,014 4,586 6,061 (2,958) INCOME TAX PROVISION (BENEFIT) Current 5,146 2,455 1,605 2,121 (1,035) Deferred ---------- ---------- ---------- ---------- ---------- 5,146 2,455 1,605 2,121 (1,035) ---------- ---------- ---------- ---------- ---------- NET INCOME (LOSS) $ 9,557 $ 4,559 $ 2,981 $ 3,940 $ (1,923) ========== ========== ========== ========== ========== KEY STATISTICS: Daily Production Liquids (Bbl) 4,923 4,818 5,052 4,913 4,909 Natural Gas (Mcf) 46,615 38,829 44,122 48,320 55,401 Average Realized Price Liquids ($/Bbl) $ 22.57 $ 26.91 $ 24.15 $ 21.29 $ 17.88 Natural Gas ($/Mcf) $ 3.00 $ 3.31 $ 3.09 $ 3.40 $ 2.35
NOBLE ENERGY, INC. AND SUBSIDIARIES DETERMINATION OF NON-GAAP MEASURES (UNAUDITED) (IN THOUSANDS) TABLE 1. Reconciliation of Consolidated Net Income to Adjusted Net Income
Three Months Twelve Months Ended Ended 12/31/2003 12/31/2003 ------------ ------------- Adjusted Net Income* $ 35,426 $ 148,975 Less After-tax Adjustments to Reconcile: Cumulative Effect of Change in Accounting Principle 5,839 Impairment of Operating Assets 20,759 20,759 Vietnam Write-off 5,924 5,924 Write Down to Market Value & Net Realized Loss 29,793 38,461 ---------- ---------- Net Income (Loss) $ (21,050) $ 77,992 ========== ==========
TABLE 2. Reconciliation of Domestic Operating Income to Adjusted Domestic Operating Income
Three Months Ended 12/31/2003 ------------ Adjusted Domestic Operating Income* $ 36,117 Less Pretax Adjustments to Reconcile: Impairment of Operating Assets 31,937 Write Down to Market Value & Net Realized Loss 45,835 ---------- Domestic Operating Income (Loss) After Discontinued Operations $ (41,655) ==========
TABLE 3. Reconciliation of International Operating Income to Adjusted International Operating Income
Three Months Ended 12/31/2003 ------------ Adjusted International Operating Income* $ 46,329 Less Pretax Adjustments to Reconcile: Vietnam Write-off 20,218 ---------- International Operating Income (Loss) $ 26,111 ==========
TABLE 4. Reconciliation of Other Intl. Operating Income to Adjusted Other Intl. Operating Income
Three Months Ended 12/31/2003 ------------ Adjusted Other International Operating Income* $ 8,267 Less Pretax Adjustments to Reconcile: Vietnam Write-off 20,218 ------------ Other International Operating Income (Loss) $ (11,951) ===========
TABLE 5. Reconciliation of Exploration Expense to Adjusted Exploration Expense
Three Months Ended 12/31/2003 ------------ Adjusted Exploration Expense* $ 128,600 Less Pretax Adjustments to Reconcile: Vietnam Write-off 20,218 ---------- Exploration Expense $ 148,818 ==========
* The tables above reconcile various non-GAAP measures to GAAP measures of net income, operating income and exploration expense. While these various measures are not GAAP measures of financial performance, management believes they are good tools for internal use and the investment community in evaluating the company's overall financial performance. Among management, professional research analysts, portfolio managers and investors, adjustments to GAAP measures for special, non-cash charges are typically made to establish a basis to evaluate a company's performance relative to prior periods and their peers. EX-99.3 5 h12337exv99w3.txt TRANSCRIPT OF CONFERENCE CALL EXHIBIT 99.3 NOBLE ENERGY INC. CONFERENCE CALL FOR FEBRUARY 3, 2004 @ 10 A.M. EST CHAIRPERSON: GREG PANAGOS EMAIL TRANSCRIPTION TO: JPIPPENGER@NOBLEENERGYINC.COM - -------------------------------------------------------------------------------- OPERATOR: Welcome to the Noble Energy 2003 fourth-quarter results conference call. As a reminder, this conference call is being recorded. I would now like to turn the call over to Greg Panagos, Director of Investor Relations. GREG PANAGOS: Good morning, ladies and gentlemen. Welcome to Noble Energy's fourth-quarter and full-year 2003 earnings conference call. I'm Greg Panagos, Director of Investor Relations, and with me this morning are Chuck Davidson, our Chairman and CEO, and James McElvany, our CFO. Today we'll be going over Noble Energy's fourth-quarter results. James will go over financial results and Chuck will discuss our operating results and the outlook for the company. Please note that we will be making some forward-looking statements. So I'd like to paraphrase the final paragraph of our press release, which states that this conference call may include projections and other forward-looking statements within the meaning of the federal securities laws. Any such projections or statements reflect Noble Energy's current views about future events and financial performance. No assurances can be given that such events or performance will occur as projected and actual results may differ materially from those projected. I would also like to point out that, in the course of our discussion this morning, we're likely to refer to certain measures such as discretionary cash flow or EBITDA. While these are not generally accepted accounting principles measures of accounting performance, we believe they are good tools for internal use and for the investment community in evaluating the company's overall performance. Now I'll turn the call over to James McElvany to discuss financial results. JAMES MCELVANY: Thank you, Greg, and good morning. As many of you are aware, during 2003 Noble Energy designated five non-core domestic asset packages to be sold. We classified these packages as discontinued operations. Our reported 2003 results included net income from discontinued operations below the operating income line. We have added a table in the back of the earnings release called "Discontinued Operations Summary" that provides summary income statements and volumes for each quarter and the full year for discontinued operations. To see how Noble Energy would have looked if these five property packages had not been classified as discontinued, you need only to add them back to our consolidated or domestic operations totals. Under current SEC guidelines, public companies are required to treat all assets held for sale as discontinued once they meet certain specified criteria. As you would expect, given the nature of our business, such accounting treatment will inevitably create complexities in reporting for quarterly comparisons. In Noble Energy's case, the five domestic property packages were dropped into discontinued operations over the last three quarters of 2003. Because the packages were added to discontinued operations in different quarters, we were required to restate discontinued operations in each of the previous quarters as we added the packages, making quarterly comparisons complex and of limited value. However, now that all the property packages are in discontinued operations, the fourth-quarter discontinued operations summary can be used in your evaluation for each quarter for 2003. One additional note, we have included a footnote in our discretionary cash flow schedule identifying the amounts of deferred income taxes that could not be seen in the below-the-line items reported net of tax (such as discontinued operations and change in accounting principles). We hope this footnote will help you with your cash flow analysis. Before I get into the financial performance, I'd like to take a moment to talk about our fourth-quarter impairment and reserves. I am acutely aware that there has been concern in the markets lately about reserve revisions. I would just like 2 to point out that the impairment we took in the fourth quarter is quite small in terms of revisions of proved reserves. The bulk of the impairment related to a specific property for a specific reason, namely the less-than-expected results from recompletions and remediation activities on our East Cameron 338 property in the Gulf of Mexico. As stated in our press release, a total of 2.2 million barrels of proved offshore oil equivalent reserves, or less than one-half of 1% of our total year-end 2003 reserves, were removed from our books. While we cannot predict with complete accuracy how wells will respond to workovers or recompletions, and while positive and negative revisions will always be a reality in our business, we do not anticipate significant revisions to our reserves and believe our reserves are recorded in accordance with SEC guidelines. Turning to our financial results, Noble Energy reported a fourth-quarter net loss of $21.1 million or 37 cents per share, compared with net income of $16.8 million or 29 cents per share for the third quarter. Discretionary cash flow for the fourth quarter 2003 was $171.5 million or $3.02 per share, the company's highest quarterly discretionary cash flow since the first quarter of 2001. Fourth-quarter discretionary cash flow was up 12% compared to $153.2 million or $2.71 per share last quarter. The decline in reported net income compared to the third quarter was due to the impact of several one-time non-cash charges. The first was a loss on the sale of assets. The second was the writedown of our investment in Vietnam. And third, was the property impairment. That's the property impairment I mentioned earlier. Cumulatively, these charges cost the company $56.5 million of net income. Excluding the after-tax impact of these charges, Noble Energy's fourth-quarter income would have been $31.7 million [sic $35.4] or 56 cents per share [sic 62 cents per share] per share. We also realized a $14.3-million current tax benefit as a result of the $20.2-million Vietnam write off for a net financial impact of $5.9 million. During the fourth quarter in discontinued operations, we recognized a non-cash writedown to market value on our offshore package, a loss on disposition on our California package which was partially offset by a gain on disposition from our southern Oklahoma properties, for a total loss of $45.8 million pretax. The 3 earnings impact after tax was $29.8 million or 52 cents per share, and again the detail of this is in that schedule at the back of the press release on discontinued operations. Looking at the segment reporting schedule by country, in order to gain a clearer picture of how our domestic operations performed in the fourth quarter relative to the third quarter, I added discontinued operations back to our reported results. As a result, reported domestic operating income would decline $83 million, reflecting the decreased... excuse me, the increased right down to fair value of assets held for sale, loss on assets sold and the impairment. Excluding the effect of the writedown of assets to fair market value and the loss on disposition and impairment, operating income declined $12 million compared to the third quarter from $50 million to $38 million. Revenue was about $9 million lower this quarter compared to last due to lower realized natural gas prices and lower other income. Higher exploration expense, which increased nearly $7 million, also contributed to lower operating income. However, that was partially offset by lower DD&A and SG&A expenses. Fourth-quarter domestic production was up slightly, about 800 barrels of oil equivalent per day, compared to the third quarter. International operating income decreased $3 million compared to the third quarter. Adding back the Vietnam write-off however, resulted in a quarter-to-quarter increase in international operating income of $17 million. Our North Sea operations accounted for $6 million of this increase. That resulted from a combination of higher production volumes, higher realized natural gas prices and lower DD&A expense. Marginally higher transportation and exploration expenses partially offset these improvements. In Equatorial Guinea, operating income was up close to $5 million compared to the third quarter, nearly all of which was due to higher liquids production. Higher realized liquids prices also contributed, though they were offset by increased oil and gas operating expenses and slightly lower methanol income, resulting from slightly lower methanol prices. Methanol prices declined three cents per gallon during the quarter. Other international accounted for the remaining $6 million increase in operating income. 4 In Ecuador, operating income increased $2 million as we moved into the dry season, reflecting a 26% increase in power production. Lower expenses across the board contributed the remaining $4 million to increase other international operating income. Our overall income tax rate for the fourth quarter was 42%. This rate is the sum of the tax provisions for both continuing and discontinued operations. The nearly 100% rate for continuing operations, when adjusted for the impairment and write off of Vietnam, will get you down to the 42% effective overall rate. The overall income tax rate for the full year 2003 was 36.8%. Turning to the balance sheet, as of December 31st, 2003, total debt decreased $89 million from year-end 2002. The reduction was from a $50-million reduction in our credit facility, a $39-million reduction in our Israeli bridge loan and other miscellaneous debt. Long-term debt of $776 million was down $200 million from year-end 2002. The reduction in long-term debt resulted from a shift from long-term to short-term of our $125-million AMCCO note, about $29 million of other debt reclassified [sic, and the rest was paid off.] Total debt-to-capitalization at year-end was 46% compared to 50% at the end of 2002. We did have natural gas and crude oil hedges in place during the quarter. These hedges included two-way collars as well as the continuing 70-cent premium we had for closing previous transactions. For the fourth quarter we had 185 million cubic feet of natural gas per day hedged and 15,000 barrels of oil, crude. In 2004 our hedge position is somewhat lighter. We have 120 million cubic feet per day of natural gas hedged for the year, and through the first three quarters 15,000 barrels of oil per day. In the fourth quarter of 2004, our hedge position declined further to 5,000 barrels of oil per day. Most of our hedge positions are two-way collars with an average floor of $4.31 per MCF for natural gas and $24.95 per barrel of crude. The average ceilings for natural gas are $6.53 per MCF and for crude oil are $31.16 per barrel for 2004. Before I turn the call over to Chuck, let me take a moment to talk about our outlook for 2004. With 2003 behind us and our capital budget of $460 million for 2004 approved by the Board of Directors, we felt that it was time to provide a complete update of guidance for the upcoming year. Hopefully, most of you have seen our capital expenditure press release and the outlook section included 5 in that release. In our guidance for 2004, we are trying to give reasonable ranges for estimated growth in production volumes and expenses. We believe these ranges have a reasonable degree of certainty of being achieved. Average production in 2004 is estimated to increase between ten percent and 17 percent compared to 2003 volumes. Noble Energy's production profile will be impacted by several factors including: o The timing of production increases in Israel and Phase 2A in Equatorial Guinea during 2004; o Seasonable variations in rainfalls in Ecuador also affect the company's natural gas to power projects; and o The potential weather related shut-ins in the U.S., Gulf of Mexico and Gulf Coast usually occurring in the third quarter. To give you a sense of timing for new production in 2004, let me give you some highlights of the major projects we plan to bring on stream in 2004. o Our project in Israel was commissioned in the fourth quarter of 2003 and sales are expected to reach 40 million cubic feet per day, net to Noble Energy, by the end of the first quarter of 2004. Production is projected to continue to increase throughout 2004, adding another 30 to 50 million cubic feet per day, net to Noble's interest. o Phase 2A condensate expansion in Equatorial Guinea started up during November 2003 and is expected to add nearly 10,000 barrels of oil per day equivalent, net to Noble Energy, by the end of the first quarter of 2004. Phase 2B is scheduled for completion by year-end 2004, but is not expected to contribute production until 2005. Compared to the full year 2003, costs and expenses may vary as follows: o Exploration expense is expected to range from $135 million to $150 million. Our exploration budget for 2004 is estimated to be flat with 2003, even with a 15 percent reduction in our overall capital program of $460 million. o Selling, general and administrative expenses are expected to range from $1.30 per BOE to $1.50 per BOE. We expect aggregate SG&A to be flat 6 with 2003 with some moderations in pension, medical and corporate governance costs, but down on a unit basis as production from international projects ramp up. o Oil and gas operating expense is expected to range from $4.35 per BOE to $4.65 per BOE, more or less in line with our 2003 unit rates. o Depreciation, depletion and amortization is expected to range from $7.40 per BOE to $7.75 per BOE. Reduced DD&A is driven by three factors: 1) the new lower cost international production coming online, 2) the sale of properties in 2003 with relatively high DD&A rates, and 3) the impairment we incurred in the fourth quarter that alone lowered DD&A about ten percent. o An effective tax rate of 38 percent to 48 percent is expected, with deferred taxes ranging from ten percent to 30 percent. The above estimates do not include the impact of any possible asset purchases or sales. And with that, let me turn the call over to Chuck. CHUCK DAVIDSON: Thanks, James, and good morning to everybody. Certainly it's been a busy year for Noble Energy, and we have accomplished a lot. Even more important is that we find ourselves now in a very excellent position with new low-cost and high-margin production rapidly coming on stream. James has covered the financials, and I won't repeat them once again. We see in this quarter discontinued operations accounting has somewhat obscured very strong underlying fundamentals. As James noted, the picture will rapidly clear now that all of our property's packages have either been sold or are in the discontinued operations category. It allows us to focus on the continuing operations piece, and that's where we show excellent progress. So staying above the line and looking at continuing operations, our reported production was up seven percent over 2002. Excluding the impact of property sales and discontinued operations, overall production increased about four percent over 2002, which was in line with the lower end of the guidance that we provided you a year ago. 7 But what that does mean, if you look behind the numbers, is that the properties we targeted for sale were declining in production while our core areas grew in production. No surprise there. I'm also pleased that the continued trend of stable domestic production continues. On a continuing operations basis, domestic production was flat with 2002. Also, if you look at it, again on a continuing basis, fourth quarter domestic production was up 4.7 percent versus the third quarter, and it was up 8.9 percent versus the fourth quarter of 2002. As James noted, costs were, by and large, in line with our plans. During the year, of course, we started production in China, we had our first full year of operations in Ecuador; we completed and commissioned our natural gas project in Israel; and, in November, commenced production from Phase 2A in Equatorial Guinea. I'll have more on these major projects regarding Israel and Equatorial Guinea in a moment. Our finding and development costs are still too high, but there are some unique factors that came into play in 2003. Most importantly, and we discussed this in our reserve replacement press release, just over 50 percent of our overall F&D costs for 2003 went towards developing reserves in Israel and Equatorial Guinea where the reserves were recognized in prior years. That should not be a surprise. However, what it does mean is that our proven undeveloped reserves for our whole company, as a percentage of total reserves, have now dropped from where they were before to about 28 percent. So, at the end of this year we'll have about ten percent of our reserves classified as proven undeveloped for the company. And that really is in line with the fact that we're completing the major international projects and bringing those into the development stage. I would add, though, that even with 90 percent of international capital going towards development projects, international will still manage to replace its production this year. As most of you know, on international ventures you really need to look at these kinds of statistics on a multi-year basis, especially now that we're wrapping up the majority of the spending on these projects. And for instance, and when we look at our international three-year reserve replacement costs they're at a very reasonable $4.50 per barrel of oil equivalent. Domestic onshore, we noted we looked to replace about 118 percent of our production there at a cost of about $1.48 per MCF. That's pretty much in line 8 with our expectations. There are no significant property acquisitions in these numbers for 2003. This really represents our base core programs onshore. Reserve replacement offshore in the Gulf of Mexico is a different matter. Over the past two years, we've dramatically reduced our capital allocated to the Gulf. Last year less than 25 percent of our overall F&D capital went into the Gulf. Of that capital, just over 50 percent was tied to projects that were either developing reserves, such as recompletions on the shelf and our deepwater discovery that is not yet booked. So having said that, there is also a little bit of good news on the Gulf of Mexico. Our Lorien discovery, that we announced in July, has not been booked and it will be dependant on an appraisal well that we're expecting to drill this year, which will lead to likely bookings in 2004 and clearly improve results for offshore. As James noted, the performance revisions in East Cameron didn't help things, but that's behind us. Unfortunately, it happened on a very high cost property that tripped the impairment trigger. So we enter 2004 at a very strong pace. Production volumes are coming up nicely. Many of our major projects now are seeing capital investments winding down - China, Ecuador and Israel are certainly notable in this category. Equatorial Guinea, Phase 2A, has started up and is ramping up. Two B, the second phase of that project, is scheduled for completion by year-end. So our international capital commitments are declining rapidly, and our free cash flow is growing significantly. Our domestic business has fully implemented disciplined business processes that have stabilized our production and will certainly lead to improved margins. So, I think we now find ourselves in a very good position in terms of improved financial and operational flexibility. Now, I'll just turn back and look a little bit at our full-year and fourth-quarter results. As James noted, commodity prices across the board strongly helped us throughout the year. Oil and gas revenues for the full year were up some $245 million versus 2002, mostly due to higher crude and gas prices. But increased volumes also contributed to this revenue line as well. And clearly, our balance 9 sheet is now stronger, with our total debt-to-book capital ratio dropping four full percentage points this year to 46 percent. Beyond commodity prices, though, I think we also need to take credit for a good job of maintaining our discipline and controlling expenses and managing our capital programs. At the beginning of the year, we announced a capital program of $510 million. Ultimately, we spent about seven percent more, most of it having to do with the timing of some international projects. And we also added a little bit to our program in the Gulf Coast onshore area, which was doing quite well. As a result, we've announced our 2004 capital budget is, of course, down as we complete some of the major expenditures. I'd also like to say that we did a good job on the expense side as well. When we look at exploration, SG&A and DD&A, we were successful in staying within the ranges that we laid out to you a year ago. There were two exceptions - SG&A that was about ten percent higher than we anticipated. And oil and gas operating expenses that were primarily driven by the higher commodity prices that, in turn, drove higher production taxes for our onshore production. Fourth-quarter production was in line with our expectations. Reported production, that's from continuing operations, was just about 95,000 barrels a day compared to about 89,000 barrels a day in the third quarter. The increase was in several areas resulting from start-up and new production in the Gulf of Mexico, the start up of Phase 2A in Equatorial Guinea, and some increased production in the North Sea after the seasonal slowdown we encountered in the third quarter. Reported production volumes for the full year increased about seven percent, and again I'm staying above the line on continuing operations. International volumes increased nearly 7,000 barrels a day for the full year 2003 versus 2002, and of course that was primarily because of our major projects that we were adding in the international area. And as noted earlier, domestic volumes were basically flat year-over-year. James discussed our range on production guidance for the full year. It may sound like a broad range, but we do believe that we have realistic lower and upper limits to reflect the uncertainties, primarily of a few large projects that are 10 coming on stream this year. And that's most notably having to do with the ramp-ups of production in Israel as well as the ramp-up of production in Equatorial Guinea. The upper end of the range ties closely to ramp up schedules that we've outlined for Israel and EG. We have assumed that Phase 2B in Equatorial Guinea will start at the end of the year and will have little impact on production for 2004. So an early start on that would be upside beyond the range provided. And the lower end of the range would accommodate a delay in, for instance, reaching full rates in Equatorial Guinea or a slower pace in Israel. Even though we are in a take-or-pay phase in Israel, and I'll talk more about that in a moment, our production stats will not include production until it's actually delivered. So even though we collect cash under take-or-pay, we don't include those volumes in our production, and we have excluded January volumes from our production guidance numbers. And as usual, no acquisition volumes are included in our production guidance. And with the programs that we have in place, we expect the domestic production to remain essentially stable from the levels that we've had during the past year. During last quarter's conference call, I mentioned we were well along the way on marketing five asset packages held for disposition. We also provided an update on this program in a release in December. Overall, our total property divestiture program represented about six percent of our reserves and about nine percent of our production. We've now closed on the sale of four of the five packages and we're working to close the fifth package, our offshore package, during this quarter. Overall, the total package is still expected to generate proceeds in excess of $110 million. As noted in our outlook, we expect capital expenditures this year to be about $460 million. Again, down because of the completion of some major international projects. About 35 percent of our capital budget will be going into exploration and 65 percent into production and development projects. Domestic spending is expected to be about $270 million, with the remaining going towards international projects. Just under one-half of the international spending is budgeted for completion in Equatorial Guinea and the rest for drilling North Sea, Latin America and the Far East. 11 Now I'd like to go through a few of our areas as we kind of ramp up the operational outlook before we open up for questions. And I'll start in the domestic area. And as I go through this, I'll not only be talking about 2003 results, but also be giving a flavor for what we see happening in 2004. Domestic onshore, we actually accelerated our activity in drilling programs in the fourth quarter. Overall, in 2003 our domestic onshore business drilled a total of 79 [sic 78] wells of which 51 [sic 50] were successful for an overall success rate of 64 [sic 64] percent. The bulk of these wells, there were in fact 44 [sic 45] of these wells, were drilled in the Gulf Coast region where we focused on the programs in the Aspect AMI and in other areas that we focused on in the past few years-Wildcat Ridge and South Texas and Duval County. And just as a highlight, because it did have quite a bit of activity in the fourth quarter, in south Texas and Duval County, we've now drilled six wells of which five have been successful. This is a program that's been identified through a proprietary 3D seismic survey that we acquired in 2002. Again, it's proprietary. We carry a high interest in this area with some 85 to 100 percent working interest on the wells. With the wells that have been completed so far, we've already added about 2,700 barrels a day equivalent per day, gross production, by the end of 2003. And with the success we've had, we're planning to follow up with a number of wells in 2004. Currently we have plans for at least six more wells of which five will be exploration. In Wyoming in the Wind River Basin, we've completed the well on our Ironhorse prospect. The initial test well was drilled to a depth of about 15,000 feet when testing the Cretaceous and Lance objectives. We have gotten gas production from these tests, and it is a low permeability reservoir. It's been testing at fairly low rates, but we do plan to carry out an extended test program, as well as evaluate some of the additional seismic that we've acquired in the area. Turning to offshore, we continue to shift our focus to deep shelf and deepwater drilling. And most of what we have spent on the traditional shelf has been in areas to develop assets that we already have, such as recompletions on existing 12 fields. And that's what results in such a high percentage of our capital going into ongoing development projects. We have some new projects that have come on stream that have really helped us in stabilizing the production in the Gulf. For instance, in the deep shelf our Mound Point discovery came on production in October, now producing about 34 million cubic feet equivalent on a gross basis, and we have a 25 percent interest. We just now are moving a rig on in the field to drill a second well. Also on the shelf, the Roaring Fork Field in South Timbalier started up in September. We now have three wells producing. They're producing over 22,000 barrels a day gross production, and Noble Energy has a 40 percent interest in Roaring Fork. I mentioned last quarter we had interest in three deep shelf wells that we'll be drilling, the Viosca Knoll, South Pelto and Brazos. The Viosca Knoll has been drilled, completed, and is now producing just under ten million cubic feet per day. Pelto is still drilling; it's below 14,000 feet. Brazos has reached TD and logged apparent pay. We're now evaluating our completion options. During 2004, besides these carryover wells, we plan to drill another three to four deep shelf wells as well. In the deepwater, the Boris Field continues to produce extremely well. This is a field in Green Canyon 282 in which Noble has a 25 percent interest. Our two wells there are currently producing at a rate of around 25,000 barrels a day of oil equivalent, gross. Also in the deepwater, the Mississippi Canyon 837 discovery, a prospect we call Loon, is expected to begin production in the first quarter. That was delayed from an earlier planned start-up in the fourth quarter. Gross production is expected around 12 million a day of which we have 40 percent. In 2003, as a total, deepwater production averaged around 20 percent of Noble Energy's total Gulf of Mexico production. That's up substantially from 2002 where it only averaged seven percent of our production, clearly reflecting the increased focus that we've placed on developing these deepwater opportunities. In July we announced our discovery at Green Canyon 199, Lorien, and we're proceeding ahead with our partners on looking at an evaluation and an appraisal program for that. As was noted before, we haven't booked any reserves at Lorien; we expect that to happen in 2004. We have a 20 percent interest in that 13 discovery. Also in 2004 we expect that our partner will be proceeding ahead with the development of the Swordfish deepwater discovery. We've already begun the drilling of one deepwater prospect, Queen of Hearts. It started in the fourth quarter. This is in Ewing Banks 949. It's approaching TD, so we would expect it to be decisioned this quarter. We operate this well and have a 52 percent interest. Looking forward in 2004, we would expect to drill two to three additional deepwater prospects. Overall, in 2004 approximately two-thirds of our Gulf of Mexico capital will be spent on deep shelf and deepwater exploration and development projects. Turning to international operations, we had another strong quarter. Operating income was over $26 million and, of course, that includes the effect of the $20-million writedown in Vietnam. Looking at the press release tables where we show consolidating operating income, you can see that Equatorial Guinea was once again the biggest contributor this past quarter. LPG and condensate operations and methanol combined to add $22 million of operating income, up from $18 million in the third quarter. Production was up slightly from the third quarter as well. And when you factor in the fact that the field there in Equatorial Guinea was down for some time in the third quarter, it's up dramatically at the end of the year as a result of the start-up of 2A. That expansion is continuing. The project is now adding some 10,000 to 12,000 barrels per day gross of additional condensate. It is expected to be at the full rate, incremental rate, of around 28,000 barrels a day or 9,000 barrels a day net to our interest at the end of the first quarter, and again that's the incremental rate over and above the existing production in the field. The second phase expansion, 2B, will ultimately increase our net liquids production by about 6,000 barrels a day, and that's again expected to be complete at the end of this year. As I mentioned last quarter, one of the methanol plant's compressors was down for repairs. We did manage to sell methanol from inventory. And as a result we ended up with, once again, a good solid quarter from our methanol operations, with operating income of $7 million. Methanol prices continue to be strong with 60 cent a gallon prices and methanol sales volumes of around 29 million gallons. 14 In late 2003, we announced we'd commenced operations in Israel, one of our larger and more important international projects. And then a few weeks ago we announced that we had commissioned our facility. We're still waiting for Israel to complete the authorization process to allow gas to be transported into our customer's facilities, Israel Electric's generating plant there at Ashdod. This authorization has continued to be delayed due to our customer, Israel Electric, encountering some labor issues that are really unrelated to our project. However, as we've noted earlier, the early take-or-pay provision in our contract became effective January 1. That substantially mitigates the financial impacts of the delay. Regardless, we do expect approval for gas to begin flowing into IEC shortly, and we're taking it really on a day-by-day basis for right now. More importantly, we continued to stay focused on ways that we can increase the volumes in Israel because of the growing demand for natural gas in the country. We and our partners have contracted to sell, under this base contract, an average of about 170 million cubic feet a day of natural gas to IEC over an 11-year period. And that's when it reaches its full rate which is at the end of this year. But again, our priority this year is to finalize the marketing of additional volumes. We've already entered into a non-binding term sheet with one industrial user there at Ashdod in the vicinity of the power plant. We've already contacted other parties and are looking at additional opportunities. Israel has a number of potential industrial natural gas consumers, and they have very strong projected annual electricity growth over the next several years. With our facilities at Mari-B designed to produce up to 600 million cubic feet per day, we can significantly expand production at minimal additional cost. Wrapping up, in Ecuador our Machala power plant had strong revenues and cash flow this year of $58 million of revenue and $34 million of cash flow. During the fourth quarter we had operating income of a little over $2 million and cash flow of over $10 million. Again, it's in the fourth quarter and the first quarter of the year, that we see the highest demand for power in Ecuador, and basically we operate under a baseload configuration. As a result of high utilization in the fourth quarter, natural gas volumes that were delivered to the power plant increased some 22 percent versus the third quarter. 15 In 2004, as part of our overall program, we will be drilling at least three additional wells in the field. This is to basically maintain our deliverability and gas supplies. That presumably would carry us well into the next decade in terms of adequate deliverability. The rig is just in the process of arriving for that work. So, we would expect that through the first through third quarters, we'll have activity in Ecuador as we drill to complete these wells. In the North Sea, operating income rose to $16 million from $10 million. This is due obviously to strong overall crude and gas prices and some lower overall operating costs in the North Sea. And in China, production has remained steady. The fourth quarter averaged 3,300 barrels a day. We've done a little bit of work in the field and that's enhanced production a bit. We expect to carry out a modest drilling program in 2004 that is expected to maintain production in China. We have a 57% interest in this project in the Bohai Bay. I think with that, why don't we open up the lines for questions? OPERATOR: Thank you. We will now begin the question-and-answer session. To place yourself into the question queue, please press star one on your touchtone phone. If you're using a speakerphone, please pick up your handset and then press the star one. If your question has been answered and you would like to withdraw your request, you may do so by pressing star two. Please go ahead if you have any questions. Our first question comes in from Questioner. Please go ahead. QUESTIONER: Good morning. CHUCK DAVIDSON: Good morning. QUESTIONER: Two quick questions. First, could you break out the proved developed reserves in the U.S. versus international? Just the rates? 16 CHUCK DAVIDSON: Yes. Overall I mentioned on the call that we were down to about ten percent of PUDs in total for the company, and they're doing a little work there. GREG PANAGOS: Domestic reserves are 30 percent of total reserves. That's proved developed and undeveloped. CHUCK DAVIDSON: I don't know if you heard that. QUESTIONER: Yes, I got that. Maybe at some point later if you get it, just tell me what the percent of proved developed are within the U.S. and within international. CHUCK DAVIDSON: I'll give you some general things, and we'll get back with some of the specifics. The only place where we're really carrying much in the way of PUDs in the U.S. We have the Bowdoin Field, where it's a long-lived gas field, and we have additional locations in that field. And we do some additional drilling, and we carry PUDs there. Most of our deepwater has been developed, but we carry reserves in Swordfish, fairly small, as PUDs. And as I mentioned before, at Lorien we keep unbooked, and Boris shifted. So really when you look at PUDs in the U.S., it's fairly minimal. We do have more reserves in the U.S. that are behind pipe because of the multi-zones in the Gulf of Mexico. We have some proved developed, non-producing that's behind pipe. In International, we still have a little bit proved undeveloped in Israel, some proved undeveloped in Ecuador, some proved undeveloped in Argentina and that's basically it. Most everything in EG is now shifting to proved developed. We still have reserves associated with the 2B project that are proved undeveloped. And there's a ton of probable reserves, and they're non-booked reserves associated in EG with additional gas resources. We'll have the details when we put together all the schedules on our 10K for all those pieces, but that gives you the general feel for where they are. 17 QUESTIONER: Great. Thanks. And then what's the timing on the two to three additional deepwater prospects this year that you didn't mention, as well as the timing of the Ironhorse test results? CHUCK DAVIDSON: The Ironhorse is undergoing tests right now. So we're flowing gas, but it's at low rates. They want to continue to flow it because it's long-term. You really have to see what the decline rates are going to be, what's going to be the mix on it and things like that. So that's ongoing through the early part of this year. Deepwater drilling is really - as soon as we get the prospects ready, I would expect that a number of prospects will be generally equally spaced through the year. I do know that we're getting another one ready with our partner right now that may follow. It will start late in the first quarter, or early in the second quarter. QUESTIONER: Thank you. CHUCK DAVIDSON: Thank you. OPERATOR: Thank you. Your next question comes from in from Questioner. Please go ahead. QUESTIONER: Good morning, guys. CHUCK DAVIDSON: Good morning. QUESTIONER: Actually I have a couple of questions. One, on the base production for 2003 from what you are using that ten to 17 percent growth rate, what is that base production. Because we have a lot of moving numbers during the course of the year, whether it's excluding all of it or including part of it. 18 CHUCK DAVIDSON: The base on which it is set is what would be the continuing operations number. I can't give you the exact number right now but I believe it's 92,100 barrels of oil equivalent per day. That's the base. And of course, what's been excluded is all the properties that were held or sold, which is roughly around 9,000 to 10,000 barrels a day equivalent at the end of the year. So if you're kind of looking at pre-property sale versus post-property sale, and looking at what's held down in discontinued operations, I think down in discontinued operations we have just under 10,000 barrels a day equivalent of production. QUESTIONER: Okay. You answered the question because just the sales of properties occurred during the course of the year, so some of the volumes were in there, some of them weren't. CHUCK DAVIDSON: I agree with you. The discontinued ops we agree is very confusing and appreciate you asking the clarifying question. Did you say you had one more question? QUESTIONER: Yes, one more just on Israel. Could you give us a sense as to during the course of January and now into February you've got a take-or-pay fee coming back to you. Can you give us a sense as to what that might be and where that might be reported from an accounting standpoint, because you won't have volumes associated with it. CHUCK DAVIDSON: Right. The gross invoice for January take-or-pay was about $6.4 million, and so net to us be around $3.1 million net. And you're correct, we will collect cash for this. That invoice has been delivered to IEC, and it's the invoice on a monthly basis. And I think it's payable by about the third week of this month in February. James I think will just comment on how he records the entries on that. JAMES MCELVANY: That'll go into our other deferred credit account. 19 CHUCK DAVIDSON: Just another clarification for those who are tracking take-or-pay, because the industry probably hasn't had take-or-pay contracts in a long time. This one was important to us because of the investment we're making in Israel and just because there could be an issue where something might slow their ability to take gas. They do have the ability to make up this volume. And in this phase of the contract, they can begin to make up these volumes starting in the second contract year, which is October, beginning October 1. And the way they do that is by increasing their minimum pay. They nominate higher than their minimum pay to start making up. QUESTIONER: Actually, one last very quick one. Just in Ecuador, the additional wells to be drilled, the three or four wells, I'm assuming you're not going to be adding reserves there. You just want to make sure you have additional deliverability. Is that correct? CHUCK DAVIDSON: We would expect to add some reserves there. We have taken, I think, a very conservative approach in our booking of proved reserves in Ecuador. And we do have some proved undeveloped there. But we left a lot in the probable category and felt that we would wait until we brought the rig back to develop those. And so it will be a mix of shifting some reserves from proven undeveloped. But we also expect that we will have some exposure to proven reserve additions as well. QUESTIONER: Right. Thank you. Thank you very much, guys. CHUCK DAVIDSON: Thank you. OPERATOR: Thank you. Your next question comes in from Questioner. Please go ahead. QUESTIONER: Hi. Thanks. Good morning. 20 CHUCK DAVIDSON: Good morning. QUESTIONER: Just curious about what kind of timeframe you would expect more of a stabilization on the domestic gas front. I mean obviously, you know, 2003 brought pretty poor production replacement in the U.S. And you've spoken to the reduced cap ex in the Gulf of Mexico. I just want a sense on sort of the near-term here in the U.S. And then the related question would be an update on the deep shelf as a play. I heard you say two-thirds of your Gulf capital is going to be directed to deep shelf and deepwater. But a couple of industry players seem to be broadly backing off plans in the deep shelf, and I just wondered what your take is today. CHUCK DAVIDSON: Yes. In terms of the gas front, from our standpoint when we forget about properties that we're selling, which were higher decline rate properties, for instance when we look at domestic onshore we're holding our own there. Gulf of Mexico clearly is a different issue. And as you've seen on our stats, we've actually been adding in the Gulf of Mexico quite a bit of oil production. And as we brought deepwater production up, it's become a greater component of our overall Gulf of Mexico production. So I think for us, and also for the industry, we're still struggling with the old issue of finding and supplying additional volumes of gas. It continues to be a bit of a struggle, but we still take the view, and I still take the view, that North America is relatively mature and that we have to constrain capital. Clearly, with the amount of capital constraint that we apply to the Gulf of Mexico, we were not in a position to replace production through a drill bit approach. It was more developing what we had and then continuing to build on the deep shelf and the deepwater programs that do give us exposure going forward. I think for Noble, clearly the answer in terms of having decent reserve costs, decent metrics in the Gulf of Mexico is dependant on a deepwater program and somewhat a deep shelf program. Deep shelf for us is a little different than others. We have stayed in the range of drilling 15,000 foot to 20,000 foot wells. Our success rates have continued to stay in the ranges that we've talked to you 21 before, of 50 percent to 60 percent success rate. I think the challenge on the deep shelf continues to be that reservoir quality can be problematic, and that you've got to absolutely avoid drilling problems. That's been mitigated some in the recent period because rig rates and drilling costs are down, but I think the deep shelf has a bit of exposure if we see drilling costs go up dramatically there. I think that program stays a risk. That's why we continue to move and keep really two fronts going in the Gulf of Mexico, and that's both deep shelf and deepwater. If I was going to take my choice, the program right now that's really been helping us is the deepwater projects that are close to infrastructure, sub-sea tiebacks that have good metrics and bring production on quickly. The other thing that is helping a little bit, but probably not going to make a major difference is the MMS did finalize it's incentive program for deep shelf royalty relief. And that should help some operators in terms of part of their programs. But I don't think you would expect that to make a huge difference in the drilling programs. QUESTIONER: Do you have a well count as to how many deep shelf wells you're going to drill this year versus last? I apologize if I missed that. CHUCK DAVIDSON: It will be approximately the same. Total well count deep shelf will be four to six. We would expect that's fairly comparable with what we had in 2003. There might be a one well difference there. In the deepwater, we expect to drill more deepwater wells this year than 2003. In 2003 as we restructured things, we ended up drilling one deepwater prospect and it was successful. That was Lorien. This year, that will step up significantly and, again, I think that positions us much better to show improved results in the Gulf of Mexico in the parts that we're focused on. QUESTIONER: Very good. Thanks. 22 CHUCK DAVIDSON: Thanks. OPERATOR: Thank you. Your next question comes in from Questioner. Please go ahead. QUESTIONER: Good morning. I wanted to hear a little bit more about Ironhorse in terms of the number of wells or prospects you've identified in that area more broadly. Secondly, would you talk a little bit about your potential exposure to the ultra deep shelf. There's been a lot of industry speculation about the promise of some of that in the shallow water Gulf of Mexico. And then lastly, just briefly touch upon the incremental reserve additions that you could associate with the capacity that you have offshore Israel. Thanks. CHUCK DAVIDSON: In terms of Ironhorse, again the area that we have there is around 27,000 to 28,000 gross acres, and so it's a fairly large area. We're exploring a couple of formations there. There's just tight gas, non-conventional gas. We've drilled one well. We have acquired some additional 3D seismic, and we're now looking at how that seismic ties into the particular well we drilled and the test results. So I think it's too early to promise when we might be drilling another well there, or if we'll be drilling another well there. I think it all depends on the evaluation results. But it's as we expected, it's an area that contains gas and the key will be to achieve commercial rates from it. QUESTIONER: I guess to narrow the question, how many more ideas or possibilities have you identified on that acreage position which would then... CHUCK DAVIDSON: Without getting into a lot of technical detail, there appears, through the seismic, to be areas that are better identified than others and it's tying those in, and then understanding the degree that productivity might be enhanced as you move to those areas. It's not just a big formation that you can just drill up on 28,000 acres. You really have to look at the faulting, look at the change in reservoir 23 character and potential reservoir quality as you go through. So it's still a large opportunity. It's too early to tell where it might lead ultimately. QUESTIONER: Okay. CHUCK DAVIDSON: On the ultra deep shelf, where we are there, we have generally not gone towards the ultra deep shelf. And when I think of ultra deep I'm thinking of 25,000 to 30,000 feet. Potentially high upside opportunities there, clearly high risk opportunities, high potential drilling cost opportunities. We have not focused our portfolio there. We may have a few that approach those depths, but we have generally not pushed them into our drilling program near term. Right now, as we go through our exploration processes, we can't seem to see the risk/reward that comes out and which can compete against other things. I think, in terms of Israel, we look at other resources there that are unbooked. We have probables of somewhere around, on a gross basis, about 200 BCFs, which would roughly be about half of that net to our interest. We'll have to look at the recovery at Mari-B. In our own thoughts there are some probables associated with improved recovery there, but obviously those won't even be considered for booking until we have performance in the reservoir. I would just add that we had a note in our release on how we determine reserves. Mari-B in Israel is one where we had a third-party independent engineering study done, as well, there was one done in Equatorial Guinea and one in Ecuador. QUESTIONER: Okay. And just a follow-up on Mari-B, is there a number you can put to the incremental capital costs for you that would get you to capacity for that 600? CHUCK DAVIDSON: Well, to get to the 600 million, let me put it this way: We have, I think, five wells that are completed right now. And they have current deliverabilities of some 80 to 100 million a day each. So, we have deliverability of let's call it approaching 400 to 500 million a day. So, if we wanted to get the 600 million 24 we'd have to tie in a couple more wells, maybe a sub-sea well, to bring it in. Which is, maybe, we're talking $25 to $30 million apiece. The bulk of our capital in Israel has been spent. The facilities were designed to handle 600 million. We have a 30-inch pipeline that offtakes from the platform that goes to the delivery point. So the key on Israel is the growth of the market and the growth in our ability to access it. That's why it's such an important thing to grow production at relatively low incremental cost, very high margin. So that's why our focus is on additional marketing in accelerating the delivery of gas in Israel. QUESTIONER: Great. Thank you. CHUCK DAVIDSON: Thanks. OPERATOR: Thank you. Your next question comes in from Questioner. Please go ahead. QUESTIONER: Good morning. CHUCK DAVIDSON: Good morning. QUESTIONER: I see here that in North America over half of your budget is earmarked for exploration. And I know you've done superbly onshore, but it's been the offshore that's been a little bit of a struggle. Even if you booked Lorien, your finding costs would still have looked high. First, where is that exploration going to and second, what gives you encouragement, with the exploration, that you can begin to turn things around, particularly in the offshore? CHUCK DAVIDSON: Right. I think you're correct on the stats there in terms of our split. Actually, onshore U.S. we've actually pulled back the percentage that goes into exploration this year a little bit from what we had last year. And that's just because we've had more development opportunities that came up, particularly in 25 the Gulf Coast where we're following up on some things. So that when we look at our overall capital program for 2004, two-thirds is development and one-third is exploration. In the U.S., though, we've always carried a bit higher percentage on exploration. The exploration dollars in the Gulf of Mexico are clearly focused on that deepwater drilling program and the deep shelf drilling program. There is very little else that's outside that that would make our cut in our high-grade process. The onshore exploration program is almost totally focused along the Gulf Coast. We've now done post-mortems on that for two years. It shows solid returns. Given that this is flush production, low cost production from an operating cost standpoint, we see that F&D costs are very competitive. I would also add that we look at Lorien from a standpoint that that's a sub-sea tieback, and that the development costs are not substantial there. We see it as an overall project that looks like it's going to be a good return. Yes, it is higher cost, but it's high quality flush production, high rate. It's no different than Boris. We see Boris as being higher overall cost, but excellent return because of the productivity of the well. QUESTIONER: The confidence that you have in stepping up the deepwater drilling and also continuing with an active program on the shelf, is you've got a better sense of how to unlock or identify those reserves to begin to bring those finding costs down. Or is there something in particular that you feel you've got a better grasp of that should help improve things in both of those areas or continue that success that you've had on Lorien and Boris? CHUCK DAVIDSON: I think that in the case of deepwater, we really had to shake that whole portfolio out and have completed that process. We're now focusing on the Mississippi Canyon areas in deepwater. We're focusing more in the Green Canyon area, the Mississippi Canyon area where we have more knowledge, there's more infrastructure and the time between discovery and production is reduced. We just look at our overall success rate and, as I mentioned earlier, a full 20 percent of our production in the Gulf of Mexico is now coming from deepwater. 26 We've had good success rates on the deepwater program, especially in the last three years as we've changed its focus. And it's also gotten the scrutiny of a much enhanced exploration process where now each prospect has to go through a significant review process, peer review process, risking process. So I feel more comfortable when I see the results. I saw the results at Lorien, where our post-drill results matched fairly closely with our pre-drill expectations. And as we see more of that, where results match pre-drill expectations, it gives us more confidence that what we're looking at from a program basis makes sense. QUESTIONER: Okay. Thank you. CHUCK DAVIDSON: Thank you. OPERATOR: Thank you. Your next question comes in from Questioner. Please go ahead. QUESTIONER: Good morning. CHUCK DAVIDSON: Good morning. QUESTIONER: I think most of my questions have been answered, just a couple of follow-ups. Are the asset dispositions basically through, or do you plan any kind of further sales in 2004? CHUCK DAVIDSON: Right now we have not identified any specific further sales in 2004. So we're just finishing up that one offshore package. The nature of this business is that we're always pruning and trimming, but 2003 was kind of a significant catch-up for us to clean out in several areas. So, right now we have not identified anything specific going forward. If anything, it would hopefully just be some minor things in various areas. 27 QUESTIONER: Okay, and I think lastly, getting back to your deep shelf play, you answered a few questions about this. It sounds like your success rates are really what your original objective was. What about in terms of target sizes for your reserves? And further, do you have anything that's been on production long enough that would give you an indication of what kind of decline curves you're looking for? CHUCK DAVIDSON: On the target sizes, I think that as we've improved the exploration processes, we have moved probably the pre-drill estimates down somewhat. Before, I think early in the program, a lot of people were thinking of target sizes of 50 to 100 Bcf. And I think the reality is there's probably more that are in the 20 to 50 Bcf range rather than 50 to 100 Bcf. And so we have seen results that tend to work more into that latter range rather than the former range. There's a different component to our program which is very unique to Noble, and that is that we're in a carbonate play in the Viosca Knoll. It has a whole different set of economics than what we talk about in terms of some of these other deep shelf opportunities. So that for instance, while it may be below 15,000 feet, it has a different pressure regime, it has much lower drilling costs, it has a lot of infrastructure that we and Chevron have put together. And as a result, we see very high returns on those. That program has been underway for a number of years. So we've got reasonable decline rates. But you can't use it because it's out of a carbonate rather than... It's out of James Lime rather than being out of some of the other sandstone. In the deep shelf, I would say we've had a number of deep shelf wells, but their decline rates run all over the map just like in other areas. I think there is one theme, and that is that for deep shelf wells, there's probably more of a reservoir quality issue. So that you can get tighter rock, and so you see some different rates there. But for instance, Mound Point, we're not seeing enough production history there to put up a decline rate. I'd say that the data is limited. QUESTIONER: Fair enough. Thank you. 28 CHUCK DAVIDSON: Thank you. OPERATOR: Thank you. Your next question comes in from Questioner. Please go ahead. QUESTIONER: Good morning. CHUCK DAVIDSON: Good morning. QUESTIONER: Two quick ones. Ironhorse, would you be willing to talk about the rates that you're getting there, and how much they might be below what you see as a hurdle rate for economic thresholds? CHUCK DAVIDSON: Well, I think the answer on that is that it all depends on what the decline rate is. I know in visiting with our folks the rates that we have seen so far have been below a million cubic feet a day of production. The key is what it will do on a sustained basis into a pipeline. We have a connection there and that's why we plan an extended testing period there. The key is ultimate reserves and that can only be determined with this tight rock by some extended testing. QUESTIONER: Okay, all right. Last one. Ecuador utilization, any changes as you see them in 2004 versus 2003 on average? CHUCK DAVIDSON: No, we see 2004 utilization following about the same pattern and again, we have the dry season and the wet season, but we don't really see any major differences. We're projecting on average for the year about an 80 to 85 percent dispatch rate. So we're probably up a little bit this year after everything sort of settled down and the plant was running fine. I think we're comfortable that the market has remained about the same, and we continue to have strong electricity prices because, of course, crude oil prices in Ecuador drive their power prices. 29 QUESTIONER: Okay. Thanks very much. CHUCK DAVIDSON: Thank you. OPERATOR: Thank you. Your next question comes in from Questioner. Please go ahead. QUESTIONER: Hi guys. A couple of quick ones. You said Lorien met your pre-drill estimates, Chuck. So, if you had booked it, what would your domestic reserve replacement have been if you hazarded a guess? CHUCK DAVIDSON: The Lorien was probably on a net basis maybe be somewhere about, and I'm going to give you a range, five to ten million barrels equivalent, net. If you, for instance, look at the lower end of that offshore it would be about $16 a barrel. So it has a big swing. But it's just one well. QUESTIONER: Okay. CHUCK DAVIDSON: But if, I mean, if you just want to fly through the whole domestic you can just add that. And again if you look at it on the lower end of the range, it would probably add another third to reserves added on the domestic, so it would cut the overall domestic rate down proportionately. QUESTIONER: Okay, thanks. Two more quick ones. You already have production capacity on gas in Ecuador. So why are you drilling more wells? Are you going to ramp up your power generation there, or are you contemplating that? CHUCK DAVIDSON: What we did was, when we did the initial drilling program in Ecuador, we drilled a few wells. We basically had enough supply that would last us, I think our 30 estimate now is before deliverability would become a factor, it would carry us into at least through this year and maybe 2005. But what we didn't want to do is, until we saw how the power market worked -- payments, all those pieces -- we didn't want to overdrill the field. And we had had drilling problems early on which we wanted to make sure that we had studied on a little bit before we threw a lot of money at these wells. So we drilled enough to give us a few years of deliverability with a plan that we bring the rig back and develop additional capacity. And this time we expect that capacity would last us really well beyond 2010. QUESTIONER: Okay, and then the last one for me - what about more activity in the North Sea or the acquisitions market? How aggressive are you looking at both? CHUCK DAVIDSON: On the activity side in the North Sea, I didn't mention, we have a discovery that we had last year. We've actually gone back and done some appraisal drilling. We had that project that's looking like we'll work to see if we can't sanction it this year. That's the plan at least. We don't have booked reserves there. We continue to look at acquisition opportunities in the North Sea. Perhaps not as many came about in 2003 as what the industry had been anticipating. It's an area that we're interested in, but we have had better success in the North Sea in acquiring either discoveries that have been undeveloped or some new opportunities, rather than just buying old fields. And so we've been careful not to pursue some of the options that get involved in old fields with some very high operating costs, with others who own the infrastructure and with very high abandonment costs. But there seems to be still quite a few opportunities there, undeveloped discoveries that we're hopeful will be turned loose. We maintain a group there to not only manage our operations, or the non-operated production we have there, but also look at additional acquisition opportunities. QUESTIONER: Thanks, Chuck. CHUCK DAVIDSON: Thank you. 31 OPERATOR: Thank you. Your next question comes in from Questioner. Please go ahead. QUESTIONER: I'm afraid most of my questions have been answered, but one quick one. Chuck, in your mind what is a reasonable finding and development cost that you're looking at for the Gulf of Mexico in aggregate? CHUCK DAVIDSON: Well, I think, in aggregate, if it includes a sizeable portion of near-term production, I'm going to say deepwater that is sub-sea tieback so it comes on production in one to two years, or shelf production that is flowing back... deep shelf production that is flowing back quickly. Using, I would say, modest price curves, not the high prices that we're doing now, you can still see things that make sense, even all the way up to $2 an Mcf which is $12 a barrel. You'll get higher rates of return that generate in excess of your cost of capital. That to me, in today's world, with flush production, with oil prices above $20 a barrel and gas prices of maybe $3.50, that you can make it work. I think as you go above that, you have to really start looking at the individual projects pretty carefully. QUESTIONER: Thank you. OPERATOR: Thank you. Your next question comes in from Questioner. Please go ahead. QUESTIONER: Good morning, gentlemen. I guess a lot of my questions have been answered. But a couple of little things to fill in a few blanks. The 160 Bs, I guess, that you added internationally, can you give me a breakdown of where they came from? CHUCK DAVIDSON: I'll kind of give you a cross-section of some of the areas in the North Sea in a couple of our projects there, for instance Hanze had significantly performed better and as a result we had reserve additions there. While most of our capital 32 went towards EG, Equatorial Guinea, towards developing our big projects, we did have some reserve additions in Equatorial Guinea that brought reserves up there. And some of it had to do with just some gas reserves, that we didn't have booked before, that go to the methanol plant there. And it was kind of scattered after that. We didn't add any reserves, of course, in Israel. And we didn't add any reserves, of course, in Ecuador. And I think we ended up shy of just about flat. So it was basically Equatorial Guinea and North Sea. QUESTIONER: Okay. All right, great. And then on the mechanical side, I was wondering if you could just break down that other international category in terms of volumes and pricing. I know in China, I think you said you did 3,300 barrels net. GREG PANAGOS: Yes. Other international, we have 3,300 barrels a day in China. The remaining liquid volumes would be Argentina. QUESTIONER: Okay. GREG PANAGOS: Then we have natural gas that is really split between Argentina and Ecuador. And Argentina is a very small part of that. The Equador volumes for the fourth quarter were 26 million cubic feet per day as detailed in the AMPCO/Ecuador schedule at the back of the press release. So you just have to take the difference. And the difference is Argentina. QUESTIONER: Okay. And then what was your hedging impact for the fourth quarter on gas, just total company? JAMES MCELVANY: It was eight cents with the gas. QUESTIONER: That's a negative eight cents or positive? 33 JAMES MCELVANY: Yes, negative eight cents. It was eight cents, and was a negative 75 cents for crude. CHUCK DAVIDSON: 75 cents a barrel negative for crude in the fourth quarter. QUESTIONER: Okay, great. And then just one more question mechanically. Your U.S. severance tax, what was that? CHUCK DAVIDSON: I think I'll have to get back to you on that one. QUESTIONER: Okay. Great. Thanks a lot. CHUCK DAVIDSON: Thank you. OPERATOR: Thank you. Your next question comes in from Questioner. Please go ahead. QUESTIONER: Good morning. A couple of quick questions. As most of your capital spending program is over international projects, you indicated that your cash flow generation is going to exceed your capital needs. What would be the logic of placement of the cash flow? CHUCK DAVIDSON: We kind of have several alternatives we're looking at, one that has kind of already been underway. As we had been developing the international projects, we had pushed our debt up a bit. And so, initially, we've been allowing some of the excess cash flow to reduce debt because we just kind of went through this past quarter with a period when international actually started generating cash flow in excess of its capital needs. So the first step was we're allowing some of our debt to come down. We've been, from a long-term basis, targeting debt-to- 34 book cap somewhere around the low 40s. At very high commodity prices, it might even go below that. The next area, which I think is very dependant on timing and pricing and market values, is, again, we don't include any acquisitions in our capital budget, but we have really, starting about a year ago, started putting in place a process and a group that is looking at opportunities here domestically or internationally. If they're here domestically, they're likely to be onshore and in some of the longer-life gas basins. Or, as we had responded to one question earlier, we're looking at places for instance like the North Sea. And quite honestly, when we looked at the U.S. so far, those have been very expensive, so we haven't acquired any. But that's all part of a cycle and we'll be opportunistic. And we may see something that fits and that would be a place where additional capital would be expended. Also, we continue to look and identify new international ventures that, again, we don't have them carried in our budget but we're constantly evaluating new opportunities that could lead to major programs down the road. We see that as a possible alternative for cash. Going beyond that, if you look at these high commodity prices, we obviously know that there are other options, including stock repurchases down the road if that looks like the best option versus let's say acquiring other projects or investing in new developments. And so we really look at all three pieces, but the bottom line is in the capital program. We lay out basically only for the base drilling program we've identified, and all the incremental opportunities would be added to that. QUESTIONER: You mentioned too high F&D costs. What would be a realistic F&D cost and the realistic oil and gas prices? CHUCK DAVIDSON: I think when you look at domestic, and it all depends on what the view is of realistic oil and gas prices, but I keep getting back to something on a gas-equivalent basis of below... this is all-in now, this is onshore and offshore, below $1.50. And it could be even much lower than that depending upon depending upon the area. Now an earlier question was about the Gulf of Mexico. And I think Gulf of Mexico could be as high as $2 an MCF because of flush production there. But 35 not for deepwater projects that take five years to come on stream. They cannot be anywhere near that. QUESTIONER: And you don't see right now any opportunities that you can buy reserves for less than that? CHUCK DAVIDSON: I think it's right on the borderline. We have seen recent acquisitions announced that are right at $1.50 an Mcf, or maybe even a little bit above $1.50 an Mcf. So they're right on the threshold and, unfortunately, some of those might be some longer-life reserves. Or they might require additional capital to develop, which would push the ultimate full-life FD&A costs above that. QUESTIONER: Okay, thank you. CHUCK DAVIDSON: Thank you. OPERATOR: Thank you. Your next question comes in from Questioner. Please go ahead. QUESTIONER: Good morning, guys. I wonder if we can get back to some of the regional volume breakdowns. You know, we've got enough information I think to layer in Israel, Ecuador, EG. What are you looking for in volumes out of the U.S., the U.K. and international? Should we just assume your best efforts are to keep those areas flat? CHUCK DAVIDSON: I think in terms of U.S. domestic we feel very comfortable that for 2004 we'll see, and again, let's keep it on continuing operations so we don't get caught up in discontinued operations, that a flat volume profile on there is very reasonable for us. I think in terms of U.K., I think that our thoughts are we're going to see some natural decline there. Hanze has been producing very well, but we expect it to go on a decline some this year. And then we have this Donan discovery that 36 we'll be developing, that will be my guess is 2005, which would kick up production there. So this year some decline in U.K., kind of just a natural decline, not a specific decline. We just have to watch Hanze very carefully because it's a high rate property. QUESTIONER: And other international? CHUCK DAVIDSON: China is flat. This year we're doing a little bit of drilling. I think the last report you saw with China on a gross basis was a little above 7,000 barrels a day. And then of course EG and Israel are growing. So on the international side probably the one area that's probably got more decline to it than the others is the North Sea area, and all the other areas kind of fit the model. As we said, they're more longer life in production, they're more stable. So we're not fighting decline rates on those. QUESTIONER: Getting back to the take-or-pay, do you have a high degree of confidence you'll actually get paid on that? I mean if you look at take-or-pays in other parts of the world and granted, they may not be Israel-type business practices, but oftentimes it's hard to actually get that money out of the companies. CHUCK DAVIDSON: I think we have a very high degree of confidence that our purchaser will honor the contract. QUESTIONER: Okay. And what about the new contract that you mentioned that you have agreement on? What kind of volumes are you talking about? CHUCK DAVIDSON: It's with a refinery. It's relatively small amounts, maybe 10 to 15 million cubic feet a day, something like that, but it's a small amount, and we will see additional customers in the area. That's kind of just an easy add-on because they're literally across the fence from the power plant. 37 QUESTIONER: Okay. CHUCK DAVIDSON: The big ones that we need to go after this year are the larger industrial customers, independent power producers. We've got a candidate there, as well as Israeli Electric is a candidate there. So those are the big targets for 2004. QUESTIONER: Right. And then, again I hate to go back to something that's been covered quite robustly, but with regards to Ironhorse, I know you need to watch performance there, but do you have any plans to drill more this year in the current budget? CHUCK DAVIDSON: I'll put it this way: We have not approved any additional drilling with our partner there. We've both said that it's going to be dependant on the evaluation as well. So we have not approved anything, and we can accommodate it in our budget absolutely. QUESTIONER: Okay. And then one final, thing. Can you just help me get my hands around the F&D number that you reported. And if you start blending it into three and five-year averages, it basically points to the fact that your DD&A should be actually rising, rather than what you've given in terms of 2004 guidance coming down. And I wonder if you could just kind of just help explain that. CHUCK DAVIDSON: I'm stumped on that one because we've looked at it on a total company basis, as we bring in the international reserves that are very long-life and have low DD&A rates, it actually brings it down. And as James noted, the impairment alone at East Cameron 338 that is a fairly short-life property that would have been generating a lot of DD&A has been generating a lot of DD&A. It was a high DD&A, high completion rate property even before the impairment. I think that the drop we see alone from that is about 75 cents a barrel equivalent for 2004. 38 QUESTIONER: Right. Yeah, okay, that might explain it. CHUCK DAVIDSON: Those are always just pay now or pay later, and for Gulf of Mexico properties that are shorter lived it comes back and you recoup it very quickly. QUESTIONER: Yes. GREG PANAGOS: Another contributing factor to that would be property sales, some of which had higher DD&A rates than the company average. QUESTIONER: Right. CHUCK DAVIDSON: That's absolutely right. QUESTIONER: Okay, Thanks a lot. CHUCK DAVIDSON: Thank you. OPERATOR: Thank you. Your next question comes in from Questioner. Please go ahead. QUESTIONER: Hi, guys. With regard to the production guidance that you've given, and I realize that most of your exploration work has long lead times, but is there any exploration success built into the 2004 number? CHUCK DAVIDSON: We have tended in this guidance, in the divisions as they looked at their exploration program, to not factor in much for exploration success. Now that might be a little conservative, but usually what happens is when you get caught 39 up in that you get over optimistic on when wells will come on and when you get results. So for instance, I would tell you there is nothing in the international budget for exploration success. There is some for onshore because they get wells on quickly and it's a more ongoing program. They would factor in what we would call an exploration wedge that broadens out a little bit in the latter part of the year, and they factored in timing estimates for wells. Offshore it gets more difficult. For instance, even though we would expect to appraise Lorien, we wouldn't factor it in. We're getting ready to drill another deep shelf well at Mound Point. Even though theoretically it would be down it really is not going to contribute to their production this year, at least we wouldn't include it in our guidance. Let's put it that way. QUESTIONER: Okay. And offshore on the extended wells that you have ongoing, is that a stimulation target there? Could you do something to raise the rates on that well? CHUCK DAVIDSON: On the onshore well? QUESTIONER: No, offshore. CHUCK DAVIDSON: Well, we've got one that we're producing at Mound Point. QUESTIONER: Right. CHUCK DAVIDSON: And it's producing. This is one well producing about 34 million a day equivalent. QUESTIONER: I'm sorry, I thought you had one that was a million a day. 40 CHUCK DAVIDSON: That was onshore. That's the Ironhorse. And we have done some stimulation work on that, and that's what we're evaluating. QUESTIONER: Okay. CHUCK DAVIDSON: You're on target. QUESTIONER: All right. Thank you, Chuck. CHUCK DAVIDSON: Thank you. OPERATOR: Thank you. Once again, if there are any questions please press star one on your touchtone phone. Sir, there are no questions at this time. GREG PANAGOS: Thank you all for listening. And if you have any more questions, please feel free to give me a call. OPERATOR: Thank you very much. That concludes today's conference call. Please disconnect your lines and have a wonderful day. 41 -----END PRIVACY-ENHANCED MESSAGE-----