EOG Resources Reports 2005 Net Income
HOUSTON, Feb. 1 /PRNewswire-FirstCall/ — EOG Resources, Inc. today reported fourth quarter 2005 net income available to common of $461.8 million, or $1.88 per share. This compares to fourth quarter 2004 net income available to common of $204.1 million, or $0.85* per share. For the full year 2005, EOG reported net income available to common of $1,252.1 million or $5.13 per share as compared to $614.0 million, or $2.58* per share, for the full year 2004.
The results for the fourth quarter 2005 included the following previously disclosed items: a one-time tax expense of $23.6 million ($0.10 per share) related to the repatriation of accumulated foreign earnings, an $11.4 million ($7.3 million after tax or $0.03 per share) gain on the mark-to-market of financial commodity price transactions and a one-time interest charge of $7.5 million ($4.9 million after tax or $0.02 per share) related to the early retirement of EOG’s 2008 Notes. During the quarter, there was no cash realized related to financial commodity contracts. Consistent with some analysts’ practice of matching realizations to settlement months and to exclude the impact of the above one-time items, adjusted non-GAAP net income available to common for the quarter was $482.9 million, or $1.97 per share. Last year’s fourth quarter results included a $2.8 million ($1.8 million after tax, or $0.01* per share) gain on the mark-to-market of financial commodity price transactions. The net cash outflow from the settlement of financial commodity price transactions was $12.7 million ($8.1 million after tax, or $0.03* per share). Reflecting these items, fourth quarter 2004 adjusted non- GAAP net income available to common was $194.2 million, or $0.81* per share. On a similar basis, eliminating the one-time items detailed in the attached table, adjusted non-GAAP net income available to common for the full year 2005 was $1,271.5 million, or $5.21 per share and for the full year 2004 was $576.6 million, or $2.42* per share. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income available to common to net income available to common.)
* Fourth quarter and full year 2004 per share amounts are restated for the two-for-one stock split effective March 1, 2005. 2006 Production Growth Target Increased
“Without a doubt, 2005 was EOG’s strongest year to date. Through the consistent, successful execution of our drilling program, we exceeded our goals for total company production growth and increased North American natural gas production beyond our target while reducing net debt. Even though we are coming off a higher 2005 production base than we had targeted, we have the confidence to increase our 2006 production growth goals from the previously stated 9.5 percent to 10.5 percent. We expect a disproportionate amount of this 2006 production increase to emanate from our higher margin natural gas activities in the U.S. and Canada where we are targeting 16.5 percent growth,” said Mark G. Papa, Chairman and Chief Executive Officer.
Operational Highlights
For the full year 2005, total company production increased 16.2 percent on a daily basis as compared to 2004, exceeding the most recently stated production growth target of 15.5 percent. In the United States and Canada, where EOG posted outstanding operational results, natural gas production increased 12.2 percent. The largest production increases were reported from the Fort Worth Basin Barnett Shale Play, East Texas, North Louisiana, the Mid-Continent and the Rocky Mountains.
EOG holds more than 500,000 total acres in the Barnett Shale where it currently operates 12-rigs. Over the course of 2006, EOG plans to expand its drilling program across the play to a 22-rig program.
In Johnson County, the Raam Unit #1H well began natural gas production in January at an initial rate of 10 million cubic feet per day (MMcfd). After 10 days of sales, the well, in which EOG has a 100 percent working interest, is producing 8 MMcfd. In northeastern Johnson County, the Scottie Dog #2H, in which EOG has an 88 percent working interest, was completed in late December at an initial gross rate of 7.0 MMcfd. The well is currently producing 3.9 MMcfd, gross of natural gas. In western Johnson County, EOG has a 100 percent working interest in the Brown Unit #1H that began flowing to sales in January and is now producing 3.8 MMcfd.
“The Raam #1H is one of the best natural gas wells completed by any operator in the entire Barnett Shale Play, not just in Johnson County,” Papa said. “With the results of our down spacing tests and the strength of our drilling activity, in 2006 we plan to pursue development in Johnson County on 500-foot spacing.”
In the western counties of Jack, Erath and Hood, EOG is doubling its drilling activity to a four-rig program in the first quarter of 2006.
“We believe that the completion techniques that further improved our drilling economics in Johnson County can be applied to our acreage in the western counties where we have seen improved drilling results over the past three months,” Papa said. “This provides the assurance to actively pursue development in these areas.”
During 2005, total daily production increased 40 percent from 2004 in the United Kingdom North Sea and offshore Trinidad. EOG reported its first full year of production from the United Kingdom North Sea.
In Trinidad, total 2005 daily production increased 25 percent over the previous year. During 2005, EOG commenced natural gas production to supply two new long-term contracts. EOG is supplying natural gas that is being used as feedstock for the M5000 Methanol Plant, which began operation in September, and for Atlantic LNG Train 4, which started taking gas in December prior to plant commissioning. During the fourth quarter 2005, EOG’s natural gas deliveries to the two plants exceeded expected volumes. EOG also reported exploration success from its first well, the 4(a) E-1, drilled on Block 4(a) offshore Trinidad, which encountered 399 feet of net gas pay from multiple sands. EOG has a 90 percent working interest in the block where it plans to immediately drill a second well, the E-2, into an adjoining fault block.
“Based on the drilling results from the E-1, we expect that together the E-1 and E-2 wells will prove up 200 to 400 net billion cubic feet of gas on Block 4(a). We intend to commence development work by mid-2006 and are targeting mid-2009 for on-line production,” said Papa.
Reserves
At December 31, 2005, total company reserves were approximately 6.2 trillion cubic feet equivalent, an increase of 548 billion cubic feet equivalent (Bcfe), or almost 10 percent higher than 2004. From drilling alone, EOG added 1,046 Bcfe of reserves. For the year, total reserve replacement — the ratio of net reserve additions from drilling, acquisitions, revisions and dispositions to total production — was 204 percent. (Please see attached tables for supporting data.)
“In the current rising cost environment, we consider the all-in unit reserve replacement costs, which are essentially flat with those of 2004 to be excellent,” said Papa. (Please see attached tables for supporting data.)
For the 18th consecutive year, internal reserve estimates were within 5 percent of those prepared by the independent reserve engineering firm of DeGolyer and MacNaughton. The firm prepared an independent engineering analysis of properties containing 82 percent of EOG’s proved reserves on a Bcfe basis.
Capital Structure
At December 31, 2005, EOG’s total current and long-term debt outstanding was $985 million, and cash on the balance sheet was $644 million for net debt of $341 million. (Please refer to the attached tables for the reconciliation of non-GAAP net debt to current and long-term debt.) The company’s debt-to-total capitalization ratio was 19 percent at December 31, 2005, down from 27 percent at December 31, 2004.
“In 2005, we executed a dynamic drilling program, posted a 16.2 percent daily production increase, achieved a 35.5 percent return on equity and a 30 percent return on capital employed, while paying down debt to end the year with a 7 percent net debt to total capitalization ratio,” said Papa. “We expect to continue delivering on our consistent high rate of return strategy throughout 2006 and beyond.” (Please refer to the attached tables for the calculation of return on equity, return on capital employed and the reconciliation of non-GAAP net debt to current and long-term debt.)
Dividend Increase Announced
Following a 33 percent increase in 2005, EOG’s Board of Directors again has increased the cash dividend on the common stock. Effective with the dividend payable on April 28, 2006 to record holders as of April 13, 2006, the quarterly dividend on the common stock will be $0.06 per share. This reflects a 50 percent increase to an indicated annual rate of $0.24 per share, the sixth increase in seven years.
Conference Call Scheduled for February 2, 2006
EOG’s fourth quarter and full year 2005 conference call will be available via live audio webcast at 8:00 a.m. Central Standard Time (9:00 a.m. Eastern Standard Time) Thursday, February 2, 2006. To listen, log on to http://www.eogresources.com/ . The webcast will be archived on EOG’s website through Thursday, February 16, 2006.
EOG Resources, Inc. is one of the largest independent (non-integrated) oil and natural gas companies in the United States with proved reserves in the United States, Canada, offshore Trinidad and the United Kingdom North Sea. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol “EOG”.
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts, including, among others, statements regarding EOG’s future financial position, business strategy, budgets, reserve information, projected levels of production, projected costs and plans and objectives of management for future operations, are forward-looking statements. EOG typically uses words such as “expect,”"anticipate,”"estimate,”"strategy,”"intend,”"plan,”"target” and “believe” or the negative of those terms or other variations of them or by comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning future operating results, the ability to replace or increase reserves or to increase production, or the ability to generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes its expectations reflected in forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, among others: the timing and extent of changes in commodity prices for crude oil, natural gas and related products, foreign currency exchange rates and interest rates; the timing and impact of liquefied natural gas imports and changes in demand or prices for ammonia or methanol; the extent and effect of any hedging activities engaged in by EOG; the extent of EOG’s success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; the availability and cost of drilling rigs, experienced drilling crews, materials and equipment used in well completions, and tubular steel; the availability, terms and timing of governmental and other permits and rights of way; the availability of pipeline transportation capacity; the extent to which EOG can economically develop its Barnett Shale acreage outside of Johnson County, Texas; whether EOG is successful in its efforts to more densely develop its acreage in the Barnett Shale and other production areas; political developments around the world; acts of war and terrorism and responses to these acts; weather; and financial market conditions. In light of these risks, uncertainties and assumptions, the events anticipated by EOG’s forward-looking statements might not occur. Forward-looking statements speak only as of the date made and EOG undertakes no obligation to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise.
The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. As noted above, statements of proved reserves are only estimates and may be imprecise. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include not only proved reserves, but also other categories of reserves that the SEC’s guidelines strictly prohibit EOG from including in filings with the SEC. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for fiscal year ended December 31, 2004, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this form from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at http://www.sec.gov/ .
EOG RESOURCES, INC. FINANCIAL REPORT (Unaudited; in millions, except per share data) Quarter Twelve Months Ended December 31 Ended December 31 2005 2004 2005 2004 Net Operating Revenues $1,213.7 $693.7 $3,620.2 $2,271.2 Net Income Available to Common $461.8 $204.1 $1,252.1 $614.0 Net Income Per Share Available to Common Basic $1.92 $0.86 * $5.24 $2.63 * Diluted $1.88 $0.85 * $5.13 $2.58 * Average Number of Shares Outstanding Basic 240.4 236.1 * 238.8 233.8 * Diluted 245.5 241.1 * 244.0 238.4 * SUMMARY INCOME STATEMENTS (Unaudited; in thousands) Quarter Twelve Months Ended December 31 Ended December 31 2005 2004 2005 2004 Net Operating Revenues Wellhead Natural Gas $1,019,008 $547,527 $2,938,917 $1,842,316 Wellhead Crude Oil, Condensate and Natural Gas Liquids 184,489 142,208 668,073 458,446 Gains (Losses) on Mark-to-Market Commodity Derivative Contracts 11,415 2,826 10,475 (33,449) Other, Net (1,224) 1,093 2,748 3,912 Total 1,213,688 693,654 3,620,213 2,271,225 Operating Expenses Lease and Well, including Transportation 111,619 72,110 373,355 271,086 Exploration Costs 38,283 26,475 133,116 93,941 Dry Hole Costs 8,563 41,937 64,812 92,142 Impairments 23,237 30,241 77,932 81,530 Depreciation, Depletion and Amortization 176,974 144,125 654,258 504,403 General and Administrative 37,039 34,152 125,918 115,013 Taxes Other Than Income 63,098 38,091 199,007 133,915 Total 458,813 387,131 1,628,398 1,292,030 Operating Income 754,875 306,523 1,991,815 979,195 Other Income, Net 13,330 7,296 35,828 9,945 Income Before Interest Expense and Income Taxes 768,205 313,819 2,027,643 989,140 Interest Expense, Net 19,985 14,919 62,506 63,128 Income Before Income Taxes 748,220 298,900 1,965,137 926,012 Income Tax Provision 284,564 92,145 705,561 301,157 Net Income 463,656 206,755 1,259,576 624,855 Preferred Stock Dividends 1,859 2,618 7,432 10,892 Net Income Available to Common $461,797 $204,137 $1,252,144 $613,963 * Restated for 2-for-1 stock split effective March 1, 2005. EOG RESOURCES, INC. OPERATING HIGHLIGHTS (Unaudited) Quarter Twelve Months Ended December 31 Ended December 31 2005 2004 2005 2004 Wellhead Volumes and Prices Natural Gas Volumes (MMcf/d) United States 749 666 718 631 Canada 225 234 228 212 United States & Canada 974 900 946 843 Trinidad 294 224 231 186 United Kingdom 44 19 39 7 Total 1,312 1,143 1,216 1,036 Average Natural Gas Prices ($/Mcf) United States $10.38 $6.21 $7.86 $5.72 Canada 9.73 5.79 7.14 5.22 United States & Canada Composite 10.23 6.10 7.69 5.60 Trinidad 2.25 1.63 2.20 (A) 1.51 United Kingdom 10.24 5.08 6.99 5.14 Composite 8.44 5.20 6.62 4.86 Crude Oil and Condensate Volumes (MBD) United States 20.4 22.5 21.5 21.1 Canada 2.5 2.9 2.4 2.7 United States & Canada 22.9 25.4 23.9 23.8 Trinidad 5.6 4.4 4.5 3.6 United Kingdom 0.2 0.1 0.2 — Total 28.7 29.9 28.6 27.4 Average Crude Oil and Condensate Prices ($/Bbl) United States $57.20 $46.68 $54.57 $40.73 Canada 54.05 42.50 50.49 37.68 United States & Canada Composite 56.86 46.19 54.16 40.39 Trinidad 65.78 41.14 57.36 39.12 United Kingdom 51.89 40.82 49.62 — Composite 58.55 45.43 54.63 40.22 Natural Gas Liquids Volumes (MBD) United States 6.9 4.9 6.6 4.8 Canada 0.7 1.1 0.9 0.8 Total 7.6 6.0 7.5 5.6 Average Natural Gas Liquids Prices ($/Bbl) United States $42.62 $32.75 $35.59 $27.79 Canada 46.68 26.09 35.59 23.23 Composite 42.97 31.48 35.59 27.13 Natural Gas Equivalent Volumes (MMcfe/d) United States 913 830 886 786 Canada 244 258 248 233 United States & Canada 1,157 1,088 1,134 1,019 Trinidad 327 251 259 207 United Kingdom 45 20 40 7 Total 1,529 1,359 1,433 1,233 Total Bcfe Deliveries 140.7 125.0 523.0 451.5 (A) Includes $0.23 per Mcf as a result of a revenue adjustment related to an amended Trinidad take-or-pay contract. EOG RESOURCES, INC. SUMMARY BALANCE SHEETS (Unaudited; in thousands, except share data) December 31, December 31, 2005 2004 ASSETS Current Assets Cash and Cash Equivalents $643,811 $20,980 Accounts Receivable, Net 762,207 447,742 Inventories 63,215 40,037 Assets from Price Risk Management Activities 11,415 10,747 Income Taxes Receivable 255 3,232 Deferred Income Taxes 24,376 22,227 Other 57,959 41,838 Total 1,563,238 586,803 Oil and Gas Properties (Successful Efforts Method) 11,173,389 9,599,276 Less: Accumulated Depreciation, Depletion and Amortization (5,086,210) (4,497,673) Net Oil and Gas Properties 6,087,179 5,101,603 Other Assets 102,903 110,517 Total Assets $7,753,320 $5,798,923 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Accounts Payable $679,548 $424,581 Accrued Taxes Payable 140,902 51,116 Dividends Payable 9,912 7,394 Deferred Income Taxes 164,659 103,933 Current Portion of Long-Term Debt 126,075 — Other 50,945 45,180 Total 1,172,041 632,204 Long-Term Debt 858,992 1,077,622 Other Liabilities 283,407 241,319 Deferred Income Taxes 1,122,588 902,354 Shareholders’ Equity Preferred Stock, $0.01 Par, 10,000,000 Shares Authorized: Series B, 100,000 Shares Issued, Cumulative, $100,000,000 Liquidation Preference 99,062 98,826 Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 249,460,000* Shares Issued 202,495 201,247 Additional Paid In Capital 84,705 21,047 Unearned Compensation (36,246) (29,861) Accumulated Other Comprehensive Income 177,137 148,015 Retained Earnings 3,920,483 2,706,845 Common Stock Held in Treasury, 7,385,862 Shares at December 31, 2005 and 11,605,112* Shares at December 31, 2004 (131,344) (200,695) Total Shareholders’ Equity 4,316,292 2,945,424 Total Liabilities and Shareholders’ Equity $7,753,320 $5,798,923 * Restated for 2-for-1 stock split effective March 1, 2005. EOG RESOURCES, INC. SUMMARY STATEMENTS OF CASH FLOWS (Unaudited; in thousands) Twelve Months Ended December 31 2005 2004 Cash Flows from Operating Activities Reconciliation of Net Income to Net Cash Provided by Operating Activities: Net Income $1,259,576 $624,855 Items Not Requiring Cash Depreciation, Depletion and Amortization 654,258 504,403 Impairments 77,932 81,530 Deferred Income Taxes 270,291 204,231 Other, Net 9,642 4,580 Dry Hole Costs 64,812 92,142 Mark-to-Market Commodity Derivative Contracts Total (Gains) Losses (10,475) 33,449 Realized Gains (Losses) 9,807 (82,644) Collar Premium — (520) Tax Benefits From Stock Options Exercised 50,880 29,396 Other, Net (5,086) 537 Changes in Components of Working Capital and Other Liabilities Accounts Receivable (315,557) (151,799) Inventories (23,085) (17,898) Accounts Payable 248,411 136,716 Accrued Taxes Payable 88,151 18,197 Other Liabilities (1,213) (1,764) Other, Net (10,347) (2,683) Changes in Components of Working Capital Associated with Investing and Financing Activities 1,429 (28,381) Net Cash Provided by Operating Activities 2,369,426 1,444,347 Investing Cash Flows Additions to Oil and Gas Properties (1,724,763) (1,416,684) Proceeds from Sales of Assets 70,987 13,459 Changes in Components of Working Capital Associated with Investing Activities (1,538) 26,788 Other, Net (22,794) (20,471) Net Cash Used in Investing Activities (1,678,108) (1,396,908) Financing Cash Flows Commercial Paper Repayments (91,800) (6,250) Long-Term Debt Borrowings 250,000 150,000 Long-Term Debt Repayments (250,755) (175,000) Dividends Paid (42,986) (37,595) Redemption of Preferred Stock — (50,000) Proceeds from Stock Options Exercised 64,668 75,510 Changes in Components of Working Capital Associated with Financing Activities 109 1,593 Other, Net (1,546) (1,496) Net Cash Used in Financing Activities (72,310) (43,238) Effect of Exchange Rate Changes on Cash 3,823 12,336 Increase in Cash and Cash Equivalents 622,831 16,537 Cash and Cash Equivalents at Beginning of Period 20,980 4,443 Cash and Cash Equivalents at End of Period $643,811 $20,980 EOG RESOURCES, INC. QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON (Non-GAAP) TO NET INCOME AVAILABLE TO COMMON (GAAP) (Unaudited; in thousands, except per share data)
The following chart adjusts three-month and twelve-month periods ended December 31 reported Net Income Available to Common to reflect actual cash realized from oil and gas hedges by eliminating the unrealized mark-to-market gains or losses from these transactions, to add the one-time interest charge related to early retirement of the 2008 Notes and the one-time tax expense related to the repatriation of accumulated foreign earnings in the fourth quarter 2005, to eliminate the upward revenue adjustment for an amended Trinidad gas sales agreement recorded in the second quarter of 2005 and to eliminate a tax benefit related to the Alberta (Canada) corporate tax rate reduction recorded in the second quarter of 2004. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude one-time items. EOG management uses this information for comparative purposes within the industry.
Quarter Twelve Months Ended December 31 Ended December 31 2005 2004 2005 2004 Reported Net Income Available to Common $461,797 $204,137 $1,252,144 $613,963 Mark-to-Market (MTM) Commodity Derivative Contracts Impact Total (Gains) Losses (11,415) (2,826) (10,475) 33,449 Realized (Losses) Gains — (12,137) 9,807 (82,644) Collar Premium — (520) — (520) Subtotal (11,415) (15,483) (668) (49,715) After Tax MTM Impact (7,346) (9,963) (430) (31,992) Add: Interest charge related to early retirement of the 2008 Notes, net of tax 4,855 — 4,855 — Add: Tax expense related to the repatriation of accumulated foreign earnings 23,625 — 23,625 — Less: Revenue adjustment for an amended Trinidad gas sales agreement, net of tax — — (8,672) — Less: Tax benefit related to the Alberta (Canada) corporate tax rate reduction — — — (5,335) Adjusted Non-GAAP Net Income Available to Common $482,931 $194,174 $1,271,522 $576,636 Adjusted Non-GAAP Net Income Per Share Available to Common Basic $2.01 $0.82 * $5.32 $2.47 * Diluted $1.97 $0.81 * $5.21 $2.42 * Average Number of Shares Outstanding Basic 240,427 236,140 * 238,797 233,751 * Diluted 245,463 241,113 * 243,975 238,376 * * Restated for 2-for-1 stock split effective March 1, 2005. EOG RESOURCES, INC. QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW AVAILABLE TO COMMON (Non-GAAP) TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP) (Unaudited; in thousands)
The following chart reconciles three-month and twelve-month periods ended December 31 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow Available to Common (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs, Changes in Components of Working Capital, Other Liabilities and Preferred Stock Dividends. EOG management uses this information for comparative purposes within the industry.
Quarter Twelve Months Ended December 31 Ended December 31 2005 2004 2005 2004 Net Cash Provided by Operating Activities (GAAP) $865,214 $426,473 $2,369,426 $1,444,347 Adjustments Exploration Costs 38,283 26,475 133,116 93,941 Changes in Components of Working Capital and Other Liabilities Accounts Receivable 144,129 97,627 315,557 151,799 Inventories 8,349 9,187 23,085 17,898 Accounts Payable (169,172) (80,159) (248,411) (136,716) Accrued Taxes Payable (80,133) (11,769) (88,151) (18,197) Other Liabilities 49 6,384 1,213 1,764 Other, Net 11,151 (2,518) 10,347 2,683 Changes in Components of Working Capital Associated with Investing and Financing Activities (3,371) 10,785 (1,429) 28,381 Preferred Dividends (1,859) (2,618) (7,432) (10,892) Discretionary Cash Flow Available to Common (Non-GAAP) $812,640 $479,867 $2,507,321 $1,575,008
EOG RESOURCES, INC. QUANTITATIVE RECONCILIATION OF NET DEBT (NON-GAAP) AS USED IN THE CALCULATION
OF THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO TO CURRENT AND LONG-TERM DEBT
(GAAP) (Unaudited; in millions, except ratio information)
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) as used in the Net Debt-to-Total Capitalization ratio calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt in their Net Debt-to-Total Capitalization calculation. EOG management uses this information for comparative purposes within the industry.
12/31/2005 Total Shareholders’ Equity – (a) $4,316.3 Current and Long-Term Debt 985.1 Less: Cash (643.8) Net Debt (Non-GAAP) – (b) 341.3 Total Capitalization (Non-GAAP) – (a) + (b) $4,657.6 Net Debt-to-Total Capitalization – (b) / [(a) + (b)] 7%
EOG RESOURCES, INC. QUANTITATIVE RECONCILIATION OF COMMON SHAREHOLDERS’ EQUITY (NON-GAAP) AS USED
IN THE CALCULATION OF THE RETURN ON EQUITY (ROE) TO SHAREHOLDERS’ EQUITY (GAAP) (Unaudited; in millions, except ratio information)
The following chart reconciles Shareholders’ Equity (GAAP) to Common Shareholders’ Equity (Non-GAAP) as used in the Return on Equity (ROE) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Common Shareholders’ Equity in their ROE calculation. EOG management uses this information for comparative purposes within the industry.
2004 2005 Shareholders’ Equity $2,945.4 $4,316.3 Less: Preferred Stock (98.8) (99.1) Common Shareholders’ Equity (Non-GAAP) $2,846.6 $4,217.2 Average Common Shareholders’ Equity – (a) $3,531.9 Net Income Available to Common – (b) $1,252.1 Return on Equity (ROE) – (b) / (a) 35.5% EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF AFTER-TAX INTEREST EXPENSE (NON-GAAP) AND NET
DEBT (NON-GAAP) AS USED IN THE CALCULATION OF THE RETURN ON CAPITAL EMPLOYED
(ROCE) TO INTEREST EXPENSE (GAAP) AND CURRENT AND LONG-TERM DEBT (GAAP), RESPECTIVELY (Unaudited; in millions, except ratio information)
The following chart reconciles Interest Expense (GAAP) and Current and Long-Term Debt (GAAP) to After-Tax Interest Expense (Non-GAAP) and Net Debt (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Interest Expense and Net Debt in their ROCE calculation. EOG management uses this information for comparative purposes within the industry.
2004 2005 Interest Expense $62.5 Tax Benefit Imputed (based on 35%) (21.9) After Tax Interest Expense (Non-GAAP) – (a) $40.6 Net Income – (b) $1,259.6 Shareholders’ Equity $2,945.4 $4,316.3 Current and Long-Term Debt 1,077.6 985.1 Less: Cash (21.0) (643.8) Net Debt (Non-GAAP) 1,056.6 341.3 Total Capitalization (Non-GAAP) $4,002.0 $4,657.6 Average Total Capitalization (Non-GAAP) – (c) $4,329.8 Return on Capital Employed (ROCE) – [(a) + (b)] / (c) 30% EOG RESOURCES, INC. RESERVES SUPPLEMENTAL DATA (Unaudited) 2005 RESERVES RECONCILIATION SUMMARY United U.S. and NATURAL GAS (Bcf) States Canada Canada Trinidad Beginning Reserves 2,382.5 1,298.3 3,680.8 1,309.4 Revisions of previous estimates (21.3) 3.1 (18.2) 26.7 Purchases in place 30.2 — 30.2 — Extensions, discoveries and other additions 835.9 104.7 940.6 — Sales in place (11.8) — (11.8) — Production (267.4) (83.3) (350.7) (84.5) Ending Reserves 2,948.1 1,322.8 4,270.9 1,251.6 LIQUIDS (MMBbls) (A) Beginning Reserves 75.8 7.8 83.6 16.3 Revisions of previous estimates 3.6 1.3 4.9 (1.4) Purchases in place 1.3 — 1.3 — Extensions, discoveries and other additions 14.0 0.9 14.9 — Sales in place (0.4) — (0.4) — Production (10.2) (1.2) (11.4) (1.7) Ending Reserves 84.1 8.8 92.9 13.2 NATURAL GAS EQUIVALENTS (Bcfe) Beginning Reserves 2,837.2 1,344.9 4,182.1 1,407.0 Revisions of previous estimates (0.1) 11.3 11.2 18.1 Purchases in place 38.2 — 38.2 — Extensions, discoveries and other additions 920.0 110.2 1,030.2 — Sales in place (14.2) — (14.2) — Production (328.7) (90.7) (419.4) (94.4) Ending Reserves 3,452.4 1,375.7 4,828.1 1,330.7 Net Proved Developed Reserves (Bcfe) At December 31, 2004 2,218.5 1,114.7 3,333.2 826.2 At December 31, 2005 2,509.9 1,192.9 3,702.8 750.7 (A) Includes crude oil, condensate and natural gas liquids. 2005 EXPLORATION AND DEVELOPMENT EXPENDITURES (In Millions) Acquisition Cost of Unproved Properties $102.7 $24.3 $127.0 $4.5 Exploration Costs 286.9 42.4 329.3 19.9 Development Costs 983.5 276.6 1,260.1 25.8 Total Drilling 1,373.1 343.3 1,716.4 50.2 Acquisition Cost of Proved Properties 55.5 0.5 56.0 — Total 1,428.6 343.8 1,772.4 50.2 Proceeds from Sales in Place (49.6) (3.4) (53.0) — Net Expenditures $1,379.0 $340.4 $1,719.4 $50.2 Asset Retirement Costs $8.3 $10.7 $19.0 $— 2005 RESERVES RECONCILIATION SUMMARY United Other Total NATURAL GAS (Bcf) Kingdom Int’l Int’l Total Beginning Reserves 56.8 — 1,366.2 5,047.0 Revisions of previous estimates (22.6) — 4.1 (14.1) Purchases in place — — — 30.2 Extensions, discoveries and other additions 15.0 — 15.0 955.6 Sales in place — — — (11.8) Production (14.3) — (98.8) (449.5) Ending Reserves 34.9 — 1,286.5 5,557.4 LIQUIDS (MMBbls) (A) Beginning Reserves 0.1 — 16.4 100.0 Revisions of previous estimates — — (1.4) 3.5 Purchases in place — — — 1.3 Extensions, discoveries and other additions 0.1 — 0.1 15.0 Sales in place — — — (0.4) Production (0.1) — (1.8) (13.2) Ending Reserves 0.1 — 13.3 106.2 NATURAL GAS EQUIVALENTS (Bcfe) Beginning Reserves 57.6 — 1,464.6 5,646.7 Revisions of previous estimates (22.6) — (4.5) 6.7 Purchases in place — — — 38.2 Extensions, discoveries and other additions 15.4 — 15.4 1,045.6 Sales in place — — — (14.2) Production (14.8) — (109.2) (528.6) Ending Reserves 35.6 — 1,366.3 6,194.4 Net Proved Developed Reserves (Bcfe) At December 31, 2004 57.6 — 883.8 4,217.0 At December 31, 2005 29.5 — 780.2 4,483.0 (A) Includes crude oil, condensate and natural gas liquids. 2005 EXPLORATION AND DEVELOPMENT EXPENDITURES (In Millions) Acquisition Cost of Unproved Properties $— $— $4.5 $131.5 Exploration Costs 18.1 2.8 40.8 370.1 Development Costs 14.4 — 40.2 1,300.3 Total Drilling 32.5 2.8 85.5 1,801.9 Acquisition Cost of Proved Properties — — — 56.0 Total 32.5 2.8 85.5 1,857.9 Proceeds from Sales in Place — — — (53.0) Net Expenditures $32.5 $2.8 $85.5 $1,804.9 Asset Retirement Costs $0.8 $— $0.8 $19.8
EOG Resources, Inc.
CONTACT: investors, Maire A. Baldwin, +1-713-651-6EOG [651-6364], ormedia and investors, Elizabeth M. Ivers, +1-713-651-7132, both of EOGResources, Inc.
Web site: http://www.eogresources.com/