EOG Resources Reports 2009 Results and Increases Dividend
- Delivers 6.5 Percent 2009 Year-Over-Year Production Growth
- Reports Consistent Operational Results in Top North American Plays
- Targets 13 Percent Total Company and 47 Percent Liquids Production Growth in 2010
- Posts 364 Percent Total Reserve Replacement at Attractive Finding Costs in 2009
- Increases Dividend on Common Stock for 11th Time in 11 Years
HOUSTON, Feb. 9 /PRNewswire-FirstCall/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) today reported fourth quarter 2009 net income available to common stockholders of $400.4 million, or $1.58 per share. This compares to fourth quarter 2008 net income available to common stockholders of $461.5 million, or $1.84 per share. For the full year 2009, EOG reported net income available to common stockholders of $546.6 million, or $2.17 per share as compared to $2,436.5 million, or $9.72 per share, for the full year 2008.
The results for the fourth quarter 2009 included a non-cash gain on a property exchange in the Rocky Mountain area of $389.6 million ($244.2 million after tax, or $0.97 per share), a gain on sale of assets of $146.5 million ($91.8 million after tax, or $0.36 per share) related to the disposition of crude oil assets and surrounding acreage in California and a previously disclosed non-cash net gain of $25.9 million ($16.7 million after tax, or $0.07 per share) on the mark-to-market of financial commodity transactions. During the quarter, the net cash inflow related to financial commodity contracts was $290.6 million ($186.6 million after tax, or $0.74 per share). Consistent with some analysts' practice of matching realizations to settlement months, and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income available to common stockholders for the quarter was $234.3 million, or $0.92 per share. Adjusted non-GAAP net income available to common stockholders for the fourth quarter 2008 was $186.0 million, or $0.74 per share. On a similar basis, eliminating the items detailed in the attached table, adjusted non-GAAP net income available to common stockholders for the full year 2009 was $754.5 million, or $3.00 per share, and for the full year 2008 was $1,879.1 million, or $7.50 per share. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income available to common stockholders to GAAP net income available to common stockholders.)
2009 Operational Highlights
EOG delivered 6.5 percent total company production growth over 2008. Total liquids production in North America increased 30 percent, comprised of 23 percent growth in crude oil and condensate and 48 percent in natural gas liquids. In the United States, the substantial increase in total liquids production was primarily driven by ongoing exploration and development drilling in the North Dakota Bakken and Fort Worth Barnett Shale Combo Plays.
"Over the last several years, we have channeled a greater amount of EOG's capital expenditure program toward crude oil and liquids-rich opportunities. The resulting increase in our liquids volumes, which is significant, reflects EOG's progress in shifting toward a more balanced mix in our North American production portfolio," said Mark G. Papa, Chairman and Chief Executive Officer.
With a position in excess of 500,000 net acres in the North Dakota Bakken, EOG focused drilling operations on its 100,000 net acres in the Bakken Core during the first part of 2009. As crude oil pricing gradually improved over the course of the year, EOG expanded its drilling program outside of the Parshall Field to its Bakken Lite acreage. Additionally, EOG began testing its first wells in the Three Forks Formation in both the Core Parshall Field and the Bakken Lite. Initial production profiles are encouraging with recoverable reserves expected to be similar to those in the Bakken Lite.
The Van Hook 100-15H, which was drilled in Mountrail County, N.D., tested the Three Forks Formation in the Parshall Field. EOG has 30 percent working interest in the well, which began initial production at a rate of 1,390 barrels of oil per day (Bopd). Also in Mountrail County, EOG drilled two Bakken Lite wells toward the end of the year. The Ross 05-08H began initial production at 370 Bopd with estimated reserves of 350 thousand barrels of oil (Mbo). EOG has 100 percent working interest in the well. To test a longer length lateral, EOG drilled the James Hill 01-31H. The well began initial production at 650 Bopd, in-line with pre-drill expectations. EOG holds 79 percent working interest in this well. Extending the productive area of its acreage, EOG drilled a well in Williams County, 90 miles west of the Parshall Field. The Round Prairie 1-17H, in which EOG has 95 percent working interest, is producing at a stabilized rate of 450 Bopd and is expected to have a similar production profile as a Bakken Lite well.
Having recognized the need for additional crude oil takeaway capacity from the Williston Basin, EOG designed, constructed and placed in service at year-end a rail and pipeline system to transport its crude oil from the core of this prolific basin, Stanley, N.D., to a market hub, Cushing, Okla. This unique transportation solution will improve the pricing and overall economics of EOG's Bakken crude oil production. In addition, EOG's Prairie Rose Pipeline was recently placed in service, which interconnects with a mainline system that transports natural gas to a processing plant near Chicago, Ill.
In an effort to focus on its more geographically concentrated western U.S. drilling operations, EOG divested its non-core California crude oil properties during the fourth quarter.
In the Fort Worth Basin, EOG commissioned a plant in February 2009 that extracts natural gas liquids from the rich natural gas production stream of the Barnett Combo Play. This enabled EOG to move into development drilling of both vertical and horizontal wells in Montague and Cooke Counties. EOG recently completed four vertical wells in Cooke County. The Dangelmayr #5 and B#6 began initial production at rates of 700 Bopd with 450 thousand cubic feet of natural gas per day (Mcfd), and 500 Bopd with 300 Mcfd, respectively. The Fitzgerald #2 and #14 began production at initial rates of 300 Bopd with 200 Mcfd and 450 Bopd with 400 Mcfd, respectively. EOG has 100 percent working interest in the wells. In Montague County, using horizontal technology, EOG recently completed the Boyd B #1H, which began flowing to sales at 300 Bopd with 1,500 Mcfd, and the Flying V #1H, at 250 Bopd with 1,400 Mcfd. EOG has 96 and 100 percent working interest in the wells, respectively. Already realizing the benefits of its refined completion techniques and improved operational efficiencies, EOG is testing optimal well spacing on its Fort Worth Barnett Combo acreage.
In an area where EOG had previously focused on the Haynesville, EOG reported strong production results from its first Bossier natural gas test. The Sustainable Forest 5 – No. 2 Alt., drilled to a vertical depth of 11,400 feet in the Trenton prospect area in DeSoto Parish, La., began producing at 13 million cubic feet per day. EOG has 100 percent working interest in the well that is estimated to have reserves in excess of 8 billion cubic feet. EOG is currently operating five rigs in the Trenton prospect where it is drilling and developing both the Bossier and Haynesville reservoirs concurrently.
2010 Operational Plans and Targets
Carrying the momentum of a strong operational year forward into 2010, EOG continues to target 13 percent total company full year organic production growth over 2009 with a 47 percent increase in total liquids production. The liquids growth will be driven by expanded operations in the North Dakota Bakken where EOG plans to execute an active drilling program in the Bakken Core and Lite, as well as the Three Forks Formation. Also fueling the liquids growth will be an increased level of drilling activity in the Fort Worth Barnett Combo and the Waskada Field in Manitoba.
EOG's North American natural gas production is expected to increase 2 percent over 2009. Plans are to ramp up activity levels in the Haynesville, Bossier and Marcellus Shales during the second half of the year. In the Horn River Basin, EOG will operate an active drilling program in the first half of the year, with the goal of completing and turning wells to sales during the second half of 2010.
Reserves
At December 31, 2009, total company proved reserves were approximately 10.8 trillion cubic feet equivalent, an increase of 2,087 billion cubic feet equivalent (Bcfe), or 24 percent higher than year-end 2008.
For the year-end 2009 reserve report, EOG applied new Securities and Exchange Commission (SEC) rules regarding the estimation of proved natural gas and crude oil reserves. In accordance with those rules, the proved undeveloped reserves (PUDs) category has been revised to allow the use of "reliable technology" to establish "reasonable certainty" of production for drilling locations beyond "one offset" for a producing well. The SEC has also imposed a five-year limit for the development of PUDs unless there is a specific reason for a longer period. Based on this definition and its applicability to large resource plays, EOG has added significant PUDs in the Haynesville, Horn River, Barnett Combo and Marcellus Shale Plays at precisely mapped locations which have been tied back to a plan that is executable within the next five years.
In 2009:
- Total reserve replacement from all sources - the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production - was 364 percent at a total reserve replacement cost of $1.18 per thousand cubic feet equivalent (Mcfe) based on cash exploration and development expenditures of $3,436 million. (Please refer to the attached tables for the calculation of total reserve replacement and total reserve replacement cost.)
- In the United States, total reserve replacement from all sources was 431 percent at a reserve replacement cost of $1.21 per Mcfe based on cash exploration and development expenditures of $3,037 million. (Please refer to the attached tables for the calculation of total reserve replacement and total reserve replacement cost.)
- During 2009, price related revisions were negative 786 Bcfe. Excluding the impact of price related revisions, total reserve replacement was 464 percent at a reserve replacement cost of $0.93 per Mcfe.
For the 22nd consecutive year, internal reserve estimates were within 5 percent of those prepared by the independent reserve engineering firm of DeGolyer and MacNaughton (D&M). For 2009, D&M prepared a complete independent engineering analysis of properties containing 81 percent of EOG's proved reserves on a Bcfe basis.
Capital Structure
At December 31, 2009, EOG's total debt outstanding was $2,797 million for a debt-to-total capitalization ratio of 22 percent. Taking into account cash on the balance sheet of $686 million, at the end of the year EOG's net debt was $2,111 million and the net debt-to-total capitalization ratio was 17 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)
"We expect our year-end net debt-to-total capital ratio of 17 percent will be among the lowest of our peer group," said Papa. "This accomplishment, coupled with our 10-year average ROCE of 18 percent, reflects EOG's long standing commitment to deliver superior stockholder returns. It is likely that EOG will be one of a few peer E&P companies to report positive GAAP net income for 2009."
(Please refer to the attached tables for the calculation of return on capital employed (ROCE) and the related reconciliations of after-tax interest expense (non-GAAP), net debt (non-GAAP), and total capitalization (non-GAAP) as used in the calculations of ROCE, to interest expense (GAAP), current and long-term debt (GAAP), and total capitalization (GAAP).)
Dividend Increase
Following an increase in the common stock dividend in 2009, EOG's Board of Directors has again increased the cash dividend on the common stock. Effective with the dividend payable on April 30, 2010 to holders of record as of April 16, 2010, the quarterly dividend on the common stock will be $0.155 per share, an increase of 7 percent over the previous indicated annual rate. The indicated annual rate of $0.62 per share is the 11th increase in 11 years.
Conference Call Scheduled for February 10, 2010
EOG's fourth quarter and full year 2009 results conference call will be available via live audio webcast at 8 a.m. Central Standard Time (9 a.m. Eastern Standard Time) on Wednesday, February 10, 2010. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through February 24, 2010.
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 Unites States, Canada, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
This press release, including the accompanying forecast and benchmark commodity pricing information, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, budgets, reserve information, levels of production and costs and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production or generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that these expectations will be achieved or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known and unknown risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
- the timing and extent of changes in prices for natural gas, crude oil and related commodities;
- changes in demand for natural gas, crude oil and related commodities, including ammonia and methanol;
- the extent to which EOG is successful in its efforts to discover, develop, market and produce reserves and to acquire natural gas and crude oil properties;
- the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling and advanced completion technologies;
- the extent to which EOG is successful in its efforts to economically develop its acreage in the Barnett Shale, the Bakken Formation, its Horn River Basin and Haynesville plays and its other exploration and development areas;
- EOG's ability to achieve anticipated production levels from existing and future natural gas and crude oil development projects, given the risks and uncertainties inherent in drilling, completing and operating natural gas and crude oil wells and the potential for interruptions of production, whether involuntary or intentional as a result of market or other conditions;
- the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;
- the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights of way;
- competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;
- EOG's ability to obtain access to surface locations for drilling and production facilities;
- the extent to which EOG's third-party-operated natural gas and crude oil properties are operated successfully and economically;
- EOG's ability to effectively integrate acquired natural gas and crude oil properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
- weather, including its impact on natural gas and crude oil demand, and weather-related delays in drilling and in the installation and operation of gathering and production facilities;
- the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
- EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all;
- the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
- the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
- the extent and effect of any hedging activities engaged in by EOG;
- the timing and impact of liquefied natural gas imports;
- the use of competing energy sources and the development of alternative energy sources;
- political developments around the world, including in the areas in which EOG operates;
- changes in government policies, legislation and regulations, including environmental regulations;
- the extent to which EOG incurs uninsured losses and liabilities;
- acts of war and terrorism and responses to these acts; and
- the other factors described under Item 1A, "Risk Factors," on pages 13 through 19 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2008 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and you should not place any undue reliance on any of EOG's forward-looking statements. EOG's 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.
Effective January 1, 2010, the United States Securities and Exchange Commission (SEC) now permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2008, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.
EOG RESOURCES, INC. FINANCIAL REPORT ---------------- (Unaudited; in millions, except per share data) Three Months Ended Twelve Months Ended December 31, December 31, --------------- --------------- 2009 2008 2009 2008 ---- ---- ---- ---- Net Operating Revenues $1,760.9 $1,633.7 $4,787.0 $7,127.1 ======== ======== ======== ======== Net Income Available to Common Stockholders $400.4 $461.5 $546.6 $2,436.5 ====== ====== ====== ======== Net Income Per Share Available to Common Stockholders Basic $1.60 $1.86 $2.20 $9.88 ===== ===== ===== ===== Diluted $1.58 $1.84 $2.17 $9.72 ===== ===== ===== ===== Average Number of Common Shares Basic 250.1 247.7 249.0 246.7 ===== ===== ===== ===== Diluted 253.5 250.2 251.9 250.5 ===== ===== ===== ===== SUMMARY INCOME STATEMENTS ------------------------- (Unaudited; in thousands, except per share data) Three Months Ended Twelve Months Ended December 31, December 31, --------------- --------------- 2009 2008 2009 2008 ---- ---- ---- ---- Net Operating Revenues Natural Gas $573,037 $814,733 $2,050,963 $4,452,058 Crude Oil, Condensate and Natural Gas Liquids 462,242 275,883 1,348,510 1,769,926 Gains on Mark-to-Market Commodity Derivative Contracts 25,927 528,844 431,757 597,911 Gathering, Processing and Marketing 157,437 13,628 407,116 164,535 Gains (Losses) on Property Dispositions 534,926 (321) 535,436 123,473 Other, Net 7,293 960 13,177 19,240 ----- --- ------ ------ Total 1,760,862 1,633,727 4,786,959 7,127,143 --------- --------- --------- --------- Operating Expenses Lease and Well 157,002 162,891 579,290 559,185 Transportation Costs 77,485 70,885 283,329 274,090 Gathering and Processing Costs 13,080 14,165 57,632 40,550 Exploration Costs 40,752 48,489 169,592 193,886 Dry Hole Costs 11,590 27,105 51,243 55,167 Impairments 123,911 79,268 305,832 192,859 Marketing Costs 159,556 12,431 397,375 152,842 Depreciation, Depletion and Amortization 398,937 368,135 1,549,188 1,326,875 General and Administrative 68,793 58,249 248,274 243,708 Taxes Other Than Income 55,648 40,930 174,363 320,796 ------ ------ ------- ------- Total 1,106,754 882,548 3,816,118 3,359,958 --------- ------- --------- --------- Operating Income 654,108 751,179 970,841 3,767,185 Other Income (Expense), Net (566) 2,257 2,071 31,012 ---- ----- ----- ------ Income Before Interest Expense and Income Taxes 653,542 753,436 972,912 3,798,197 Interest Expense, Net 27,307 18,343 100,901 51,658 ------ ------ ------- ------ Income Before Income Taxes 626,235 735,093 872,011 3,746,539 Income Tax Provision 225,808 273,621 325,384 1,309,620 ------- ------- ------- --------- Net Income 400,427 461,472 546,627 2,436,919 Preferred Stock Dividends - - - 443 --- --- --- --- Net Income Available to Common Stockholders $400,427 $461,472 $546,627 $2,436,476 ======== ======== ======== ========== Dividends Declared per Common Share $0.145 $0.135 $0.580 $0.510 ====== ====== ====== ====== EOG RESOURCES, INC. OPERATING HIGHLIGHTS -------------------- (Unaudited) Three Months Twelve Months Ended Ended December 31, December 31, ----------- ----------- 2009 2008 2009 2008 ---- ---- ---- ---- Wellhead Volumes and Prices --------------------------- Natural Gas Volumes (MMcfd) (A) United States 1,075 1,231 1,134 1,162 Canada 225 231 224 222 Trinidad 294 184 273 218 Other International (B) 13 18 14 17 --- --- --- --- Total 1,607 1,664 1,645 1,619 ===== ===== ===== ===== Average Natural Gas Prices ($/Mcf) (C) United States $4.21 $5.65 $3.72 $8.22 Canada 4.41 5.71 3.85 7.64 Trinidad 2.26 2.53 1.73 3.58 Other International (B) 3.96 6.23 4.34 8.18 Composite 3.88 5.32 3.42 7.51 Crude Oil and Condensate Volumes (MBbld) (A) United States 52.0 50.4 47.9 39.5 Canada 5.5 2.7 4.1 2.7 Trinidad 3.3 2.5 3.1 3.2 Other International (B) 0.1 0.1 0.1 0.1 --- --- --- --- Total 60.9 55.7 55.2 45.5 ==== ==== ==== ==== Average Crude Oil and Condensate Prices ($/Bbl) (C) United States $67.61 $46.03 $54.42 $87.68 Canada 68.92 45.60 57.72 89.70 Trinidad 63.44 47.67 50.85 92.90 Other International (B) 63.64 84.33 53.07 99.30 Composite 67.50 46.12 54.46 88.18 Natural Gas Liquids Volumes (MBbld) (A) United States 23.3 15.9 22.5 15.0 Canada 1.1 0.9 1.1 1.0 --- --- --- --- Total 24.4 16.8 23.6 16.0 ==== ==== ==== ==== Average Natural Gas Liquids Prices ($/Bbl) (C) United States $40.29 $26.45 $30.03 $53.33 Canada 39.31 30.08 30.49 54.77 Composite 40.25 26.65 30.05 53.42 Natural Gas Equivalent Volumes (MMcfed) (D) United States 1,526 1,629 1,556 1,490 Canada 265 253 256 244 Trinidad 314 199 291 237 Other International (B) 14 18 15 17 -- -- -- -- Total 2,119 2,099 2,118 1,988 ===== ===== ===== ===== Total Bcfe (D) 194.9 193.1 773.0 727.6 (A) Million cubic feet per day or thousand barrels per day, as applicable. (B) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations. (C) Dollars per thousand cubic feet or per barrel, as applicable. (D) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil and condensate and natural gas liquids. Natural gas equivalents are determined using the ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil and condensate or natural gas liquids. EOG RESOURCES, INC. SUMMARY BALANCE SHEETS ---------------------- (Unaudited; in thousands, except share data) December 31, December 31, 2009 2008 ---- ---- ASSETS Current Assets Cash and Cash Equivalents $685,751 $331,311 Accounts Receivable, Net 771,417 722,695 Inventories 261,723 187,970 Assets from Price Risk Management Activities 20,915 779,483 Income Taxes Receivable 37,009 27,053 Other 62,726 59,939 ------ ------ Total 1,839,541 2,108,451 Property, Plant and Equipment Oil and Gas Properties (Successful Efforts Method) 24,614,311 20,803,629 Other Property, Plant and Equipment 1,350,132 1,057,888 --------- --------- Total Property, Plant and Equipment 25,964,443 21,861,517 Less: Accumulated Depreciation, Depletion and Amortization (9,825,218) (8,204,215) ---------- ---------- Total Property, Plant and Equipment, Net 16,139,225 13,657,302 Other Assets 139,901 185,473 ------- ------- Total Assets $18,118,667 $15,951,226 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Accounts Payable $979,139 $1,122,209 Accrued Taxes Payable 92,858 86,265 Dividends Payable 36,286 33,461 Liabilities from Price Risk Management Activities 27,218 4,429 Deferred Income Taxes 35,414 368,231 Current Portion of Long-Term Debt 37,000 37,000 Other 137,645 113,321 ------- ------- Total 1,345,560 1,764,916 Long-Term Debt 2,760,000 1,860,000 Other Liabilities 632,652 498,291 Deferred Income Taxes 3,382,413 2,813,522 Commitments and Contingencies Stockholders' Equity Common Stock, $0.01 Par, 640,000,000 Shares Authorized: 252,627,177 Shares and 249,758,577 Shares Issued at December 31, 2009 and 2008, respectively 202,526 202,498 Additional Paid In Capital 596,702 323,805 Accumulated Other Comprehensive Income 339,720 27,787 Retained Earnings 8,866,747 8,466,143 Common Stock Held in Treasury, 118,525 Shares and 126,911 Shares at December 31, 2009 and 2008, respectively (7,653) (5,736) ------ ------ Total Stockholders' Equity 9,998,042 9,014,497 --------- --------- Total Liabilities and Stockholders' Equity $18,118,667 $15,951,226 =========== =========== EOG RESOURCES, INC. SUMMARY STATEMENTS OF CASH FLOWS -------------------------------- (Unaudited; in thousands) Twelve Months Ended December 31, ---------------- 2009 2008 ---- ---- Cash Flows from Operating Activities Reconciliation of Net Income to Net Cash Provided by Operating Activities: Net Income $546,627 $2,436,919 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization 1,549,188 1,326,875 Impairments 305,832 192,859 Stock-Based Compensation Expenses 95,180 97,493 Deferred Income Taxes 174,392 1,133,630 Gains on Property Dispositions (535,436) (123,473) Other, Net 6,761 (14,919) Dry Hole Costs 51,243 55,167 Mark-to-Market Commodity Derivative Contracts Total Gains (431,757) (597,911) Realized Gains (Losses) 1,277,584 (136,625) Excess Tax Benefits from Stock-Based Compensation (76,134) (6,446) Other, Net 18,862 13,229 Changes in Components of Working Capital and Other Assets and Liabilities Accounts Receivable (47,818) 95,165 Inventories (50,146) (92,049) Accounts Payable (153,565) 30,253 Accrued Taxes Payable 90,929 72,467 Other Assets (5,515) (10,715) Other Liabilities (12,305) 9,061 Changes in Components of Working Capital Associated with Investing and Financing Activities 118,517 152,269 ------- ------- Net Cash Provided by Operating Activities 2,922,439 4,633,249 Investing Cash Flows Additions to Oil and Gas Properties (3,176,783) (4,718,860) Additions to Other Property, Plant and Equipment (326,226) (476,611) Proceeds from Sales of Assets 212,000 383,559 Changes in Components of Working Capital Associated with Investing Activities (118,221) (152,374) Other, Net (5,321) (2,232) ------ ------ Net Cash Used in Investing Activities (3,414,551) (4,966,518) Financing Cash Flows Long-Term Debt Borrowings 900,000 750,000 Long-Term Debt Repayments - (38,000) Dividends Paid (142,260) (115,204) Redemption of Preferred Stock - (5,395) Excess Tax Benefits from Stock-Based Compensation 76,134 6,446 Treasury Stock Purchased (10,986) (17,834) Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 20,465 72,572 Debt Issuance Costs (8,895) (7,585) Other, Net (296) 105 ---- --- Net Cash Provided by Financing Activities 834,162 645,105 Effect of Exchange Rate Changes on Cash 12,390 (34,756) ------ ------- Increase in Cash and Cash Equivalents 354,440 277,080 Cash and Cash Equivalents at Beginning of Period 331,311 54,231 ------- ------ Cash and Cash Equivalents at End of Period $685,751 $331,311 ======== ======== EOG RESOURCES, INC. QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO --------------------------------------------------------------- COMMON STOCKHOLDERS (Non-GAAP) TO NET INCOME AVAILABLE TO COMMON ---------------------------------------------------------------- STOCKHOLDERS (GAAP) ------------------- (Unaudited; in thousands, except per share data) The following chart adjusts three-month and twelve-month periods ended December 31, 2009 and 2008 reported Net Income Available to Common Stockholders (GAAP) to reflect actual net cash realized from financial commodity price transactions by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the gain on a property exchange in the Rocky Mountain area and the gain on the sale of EOG's California assets in the fourth quarter of 2009 and to eliminate the gain on the sale of EOG's Appalachian assets in the first quarter of 2008. 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. Three Months Ended Twelve Months Ended December 31, December 31, -------------- ---------------- 2009 2008 2009 2008 ---- ---- ---- ---- Reported Net Income Available to Common Stockholders (GAAP) $400,427 $461,472 $546,627 $2,436,476 Mark-to-Market (MTM) Commodity Derivative Contracts Impact Total Gains (25,927) (528,844) (431,757) (597,911) Realized Gains (Losses) 290,604 100,701 1,277,584 (136,625) ------- ------- --------- -------- Subtotal 264,677 (428,143) 845,827 (734,536) ------- -------- ------- -------- After Tax MTM Impact 169,976 (275,510) 543,946 (472,674) ------- -------- ------- -------- Less: Gain on Property Exchange, Net of Tax (244,248) - (244,248) - Less: Gain on Sale of California Assets, Net of Tax (91,822) - (91,822) - Less: Gain on Sale of Appalachian Assets, Net of Tax - - - (84,748) --- --- --- ------- Adjusted Net Income Available to Common Stockholders (Non-GAAP) $234,333 $185,962 $754,503 $1,879,054 ======== ======== ======== ========== Net Income Per Share Available to Common Stockholders (GAAP) Basic $1.60 $1.86 $2.20 $9.88 ===== ===== ===== ===== Diluted $1.58 $1.84 $2.17 $9.72 ===== ===== ===== ===== Adjusted Net Income Per Share Available to Common Stockholders (Non- GAAP) Basic $0.94 $0.75 $3.03 $7.62 ===== ===== ===== ===== Diluted $0.92 $0.74 $3.00 $7.50 ===== ===== ===== ===== Average Number of Common Shares Basic 250,127 247,672 248,996 246,662 ======= ======= ======= ======= Diluted 253,493 250,162 251,884 250,542 ======= ======= ======= ======= EOG RESOURCES, INC. QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW AVAILABLE TO ------------------------------------------------------------------- COMMON STOCKHOLDERS (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, 2009 and 2008 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow Available to Common Stockholders (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 (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, Changes in Components of Working Capital Associated with Investing and Financing Activities and Preferred Stock Dividends. EOG management uses this information for comparative purposes within the industry. Three Months Ended Twelve Months Ended December 31, December 31, --------------- ---------------- 2009 2008 2009 2008 ---- ---- ---- ---- Net Cash Provided by Operating Activities (GAAP) $828,763 $1,033,563 $2,922,439 $4,633,249 Adjustments Exploration Costs (excluding Stock-Based Compensation Expenses) 35,432 43,448 149,076 175,357 Excess Tax Benefits from Stock-Based Compensation 42,082 (63,378) 76,134 6,446 Changes in Components of Working Capital and Other Assets and Liabilities Accounts Receivable 166,917 (315,112) 47,818 (95,165) Inventories 26,554 46,695 50,146 92,049 Accounts Payable (208,133) 191,196 153,565 (30,253) Accrued Taxes Payable (74,832) 133,104 (90,929) (72,467) Other Assets 1,260 (8,041) 5,515 10,715 Other Liabilities 21,662 (12,458) 12,305 (9,061) Changes in Components of Working Capital Associated with Investing and Financing Activities 28,580 (137,880) (118,517) (152,269) Preferred Stock Dividends - - - (443) --- --- --- ---- Discretionary Cash Flow Available to Common Stockholders (Non-GAAP) $868,285 $911,137 $3,207,552 $4,558,158 ======== ======== ========== ========== EOG RESOURCES, INC. FIRST QUARTER AND FULL YEAR 2010 FORECAST AND BENCHMARK ------------------------------------------------------- COMMODITY PRICING ----------------- (a) First Quarter and Full Year 2010 Forecast The forecast items for the first quarter and full year 2010 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. This forecast replaces and supersedes any previously issued guidance or forecast. (b) Benchmark Commodity Pricing EOG bases United States and Canada natural gas price differentials upon the natural gas price at Henry Hub, Louisiana using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. EOG bases United States, Canada and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. ESTIMATED RANGES ---------------- (Unaudited) 1Q 2010 Full Year 2010 -------------- -------------- Daily Production Natural Gas (MMcfd) United States 1,040 - 1,070 1,160 - 1,190 Canada 202 - 222 200 - 230 Trinidad 290 - 310 285 - 300 Other International 10 - 15 12 - 16 Total 1,542 - 1,617 1,657 - 1,736 Crude Oil and Condensate (MBbld) United States 48.0 - 54.0 62.0 - 85.0 Canada 5.0 - 6.0 7.0 - 9.0 Trinidad 2.7 - 3.2 3.0 - 5.0 Total 55.7 - 63.2 72.0 - 99.0 Natural Gas Liquids (MBbld) United States 22.0 - 28.0 25.0 - 34.0 Canada 0.7 - 0.9 0.5 - 0.9 Total 22.7 - 28.9 25.5 - 34.9 Natural Gas Equivalent Volumes (MMcfed) United States 1,460 - 1,562 1,682 - 1,904 Canada 236 - 264 245 - 289 Trinidad 306 - 329 303 - 330 Other International 10 - 15 12 - 16 Total 2,012 - 2,170 2,242 - 2,539 Operating Costs Unit Costs ($/Mcfe) Lease and Well $0.81 - $0.85 $0.75 - $0.80 Transportation Costs $0.42 - $0.46 $0.39 - $0.42 Depreciation, Depletion and Amortization $2.20 - $2.30 $2.16 - $2.30 Expenses ($MM) Exploration, Dry Hole and Impairment $130.0 - $175.0 $525.0 - $675.0 General and Administrative $60.0 - $68.0 $260.0 - $290.0 Gathering and Processing $14.0 - $18.0 $50.0 - $70.0 Capitalized Interest $17.0 - $21.0 $60.0 - $85.0 Net Interest $24.0 - $29.0 $110.0 - $130.0 Taxes Other Than Income (% of Revenue) 5.5% - 6.5% 5.5% - 6.5% Income Taxes Effective Rate 35% - 45% 35% - 45% Current Taxes ($MM) $50 - $60 $205 - $225 Pricing - (Refer to Benchmark Commodity Pricing in text) Natural Gas ($/Mcf) Differentials (include the effect of physical contracts) United States - below NYMEX Henry Hub $0.02 - $0.30 $0.05 - $0.30 Canada - below NYMEX Henry Hub $0.30 - $0.60 $0.25 - $0.55 Realizations Trinidad $1.60 - $2.60 $1.60 - $2.60 Other International $3.00 - $5.00 $3.00 - $5.00 Crude Oil and Condensate ($/Bbl) Differentials United States - below WTI $3.00 - $8.00 $3.00 - $6.00 Canada - below WTI $6.50 - $8.50 $5.00 - $8.00 Trinidad - below WTI $9.00 - $12.50 $8.65 - $12.65 Definitions ----------- $/Bbl U.S. Dollars per barrel $/Mcf U.S. Dollars per thousand cubic feet $/Mcfe U.S. Dollars per thousand cubic feet equivalent $MM U.S. Dollars in millions MBbld Thousand barrels per day MMcfd Million cubic feet per day MMcfed Million cubic feet equivalent per day NYMEX New York Mercantile Exchange WTI West Texas Intermediate EOG RESOURCES, INC. RESERVES SUPPLEMENTAL DATA -------------------------- (Unaudited) 2009 NET PROVED RESERVES RECONCILIATION SUMMARY United North NATURAL GAS (Bcf) States Canada America Trinidad ---------- ---------- ----------- ------------ Beginning Reserves 4,889.0 1,237.2 6,126.2 1,198.1 Revisions (378.0) (447.2) (825.2) (104.9) Purchases in place 450.8 - 450.8 - Extensions, discoveries and other additions 1,925.0 846.5 2,771.5 - Sales in place (114.4) (5.1) (119.5) - Production (422.3) (81.9) (504.2) (107.4) ------ ----- ------ ------ Ending Reserves 6,350.1 1,549.5 7,899.6 985.8 ======= ======= ======= ===== CRUDE OIL & CONDENSATE (MMBbls) Beginning Reserves 133.4 7.5 140.9 8.3 Revisions 4.4 (0.2) 4.2 (1.8) Purchases in place 15.7 - 15.7 - Extensions, discoveries and other additions 58.2 19.8 78.0 - Sales in place (5.8) - (5.8) - Production (17.5) (1.5) (19.0) (1.1) ----- ---- ----- ---- Ending Reserves 188.4 25.6 214.0 5.4 ===== ==== ===== === NATURAL GAS LIQUIDS (MMBbls) Beginning Reserves 72.5 3.3 75.8 - Revisions 6.1 (0.9) 5.2 - Purchases in place 5.8 - 5.8 - Extensions, discoveries and other additions 18.5 - 18.5 - Sales in place (3.2) - (3.2) - Production (8.2) (0.4) (8.6) - ---- ---- ---- --- Ending Reserves 91.5 2.0 93.5 - ==== === ==== === NATURAL GAS EQUIVALENTS (Bcfe) Beginning Reserves 6,124.0 1,302.0 7,426.0 1,248.1 Revisions (314.9) (453.8) (768.7) (115.5) Purchases in place 579.6 - 579.6 - Extensions, discoveries and other additions 2,385.8 965.3 3,351.1 - Sales in place (168.2) (5.4) (173.6) - Production (576.6) (93.2) (669.8) (114.1) ------ ----- ------ ------ Ending Reserves 8,029.7 1,714.9 9,744.6 1,018.5 ======= ======= ======= ======= Net Proved Developed Reserves (Bcfe) At December 31, 2008 4,502.3 1,166.2 5,668.5 929.6 At December 31, 2009 4,466.0 745.9 5,211.9 633.3 2009 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) United North States Canada America Trinidad ---------- ---------- ----------- ------------ Acquisition Cost of Unproved Properties $613.0 $17.8 $630.8 $0.8 Exploration Costs 473.5 51.2 524.7 14.2 Development Costs 1,839.1 219.8 2,058.9 21.3 ------- ----- ------- ---- Total Drilling 2,925.6 288.8 3,214.4 36.3 Acquisition Cost of Proved Properties 111.7 - 111.7 - ----- --- ----- --- Total Exploration & Development Expenditures 3,037.3 288.8 3,326.1 36.3 Gathering, Processing and Other 324.6 1.0 325.6 0.2 Asset Retirement Costs 59.8 17.8 77.6 6.1 Non-Cash Acquisition Costs 387.9 - 387.9 - ----- --- ----- --- Total Expenditures 3,809.6 307.6 4,117.2 42.6 Proceeds from Sales in Place (211.1) (0.9) (212.0) - ------ ---- ------ --- Net Expenditures $3,598.5 $306.7 $3,905.2 $42.6 ======== ====== ======== ===== RESERVE REPLACEMENT COSTS ($ / Mcfe ) * Total Drilling, Before Revisions $1.23 $0.30 $0.96 $- All-in Total, Net of Revisions $1.21 $0.56 $1.10 $(0.31) RESERVE REPLACEMENT * Drilling Only 414% 1036% 500% - All-in Total, Net of Revisions & Dispositions 431% 543% 446% -101% * See attached reconciliation schedule for calculation methodology 2009 NET PROVED RESERVES RECONCILIATION SUMMARY Other Total NATURAL GAS (Bcf) Int'l Int'l Total --------- --------- --------- Beginning Reserves 14.9 1,213.0 7,339.2 Revisions 3.0 (101.9) (927.1) Purchases in place - - 450.8 Extensions, discoveries and other additions - - 2,771.5 Sales in place - - (119.5) Production (5.2) (112.6) (616.8) ---- ------ ------ Ending Reserves 12.7 998.5 8,898.1 ==== ===== ======= CRUDE OIL & CONDENSATE (MMBbls) Beginning Reserves 0.1 8.4 149.3 Revisions - (1.8) 2.4 Purchases in place - - 15.7 Extensions, discoveries and other additions - - 78.0 Sales in place - - (5.8) Production - (1.1) (20.1) --- ---- ----- Ending Reserves 0.1 5.5 219.5 === === ===== NATURAL GAS LIQUIDS (MMBbls) Beginning Reserves - - 75.8 Revisions - - 5.2 Purchases in place - - 5.8 Extensions, discoveries and other additions - - 18.5 Sales in place - - (3.2) Production - - (8.6) - - ---- Ending Reserves - - 93.5 === === ==== NATURAL GAS EQUIVALENTS (Bcfe) Beginning Reserves 15.3 1,263.4 8,689.4 Revisions 3.1 (112.4) (881.1) Purchases in place - - 579.6 Extensions, discoveries and other additions - - 3,351.1 Sales in place - - (173.6) Production (5.4) (119.5) (789.3) ---- ------ ------ Ending Reserves 13.0 1,031.5 10,776.1 ==== ======= ======== Net Proved Developed Reserves (Bcfe) At December 31, 2008 15.3 944.9 6,613.4 At December 31, 2009 13.0 646.3 5,858.2 2009 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) Other Total Int'l Int'l Total --------- --------- --------- Acquisition Cost of Unproved Properties $(0.3) $0.5 $631.3 Exploration Costs 71.9 86.1 610.8 Development Costs 2.0 23.3 2,082.2 --- ---- ------- Total Drilling 73.6 109.9 3,324.3 Acquisition Cost of Proved Properties - - 111.7 --- --- ----- Total Exploration & Development Expenditures 73.6 109.9 3,436.0 Gathering, Processing and Other 0.4 0.6 326.2 Asset Retirement Costs (0.1) 6.0 83.6 Non-Cash Acquisition Costs - - 387.9 --- --- ----- Total Expenditures 73.9 116.5 4,233.7 Proceeds from Sales in Place - - (212.0) --- --- ------ Net Expenditures $73.9 $116.5 $4,021.7 ===== ====== ======== RESERVE REPLACEMENT COSTS ($ / Mcfe ) * Total Drilling, Before Revisions $- $- $0.99 All-in Total, Net of Revisions $23.74 $(0.98) $1.18 RESERVE REPLACEMENT * Drilling Only - - 425% All-in Total, Net of Revisions & Dispositions 57% -94% 364% * See attached reconciliation schedule for calculation methodology EOG RESOURCES, INC. QUANTITATIVE RECONCILIATION OF TOTAL EXPLORATION AND DEVELOPMENT ---------------------------------------------------------------- EXPENDITURES FOR DRILLING ONLY (Non-GAAP) AND TOTAL EXPLORATION --------------------------------------------------------------- AND DEVELOPMENT EXPENDITURES (Non-GAAP) AS USED IN THE ------------------------------------------------------ CALCULATION OF RESERVE REPLACEMENT COSTS ($ / MCFE) TO TOTAL ------------------------------------------------------------ COSTS INCURRED IN EXPLORATION AND DEVELOPMENT ACTIVITIES (GAAP) --------------------------------------------------------------- (Unaudited; in millions, except ratio information) The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Mcfe. There are numerous ways that industry participants present Reserve Replacement Costs, including "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. United North States Canada America Trinidad ---------- ---------- ----------- ------------ Total Costs Incurred in Exploration and Development Activities (GAAP) $3,485.0 $306.6 $3,791.6 $42.4 Less: Asset Retirement Costs (59.8) (17.8) (77.6) (6.1) Acquisition Cost of Proved Properties (111.7) - (111.7) - Non-Cash Acquisition Costs (387.9) - (387.9) - ------ --- ------ --- Total Exploration & Development Expenditures for Drilling Only (Non-GAAP) (a) $2,925.6 $288.8 $3,214.4 $36.3 ======== ====== ======== ===== Total Costs Incurred in Exploration and Development Activities (GAAP) $3,485.0 $306.6 $3,791.6 $42.4 Less: Asset Retirement Costs (59.8) (17.8) (77.6) (6.1) Non-Cash Acquisition Costs (387.9) - (387.9) - ------ --- ------ --- Total Exploration & Development Expenditures (Non-GAAP) (1) (b) $3,037.3 $288.8 $3,326.1 $36.3 ======== ====== ======== ===== Net Proved Reserve Additions From All Sources - Natural Gas Equivalents (Bcfe) Revisions due to price (c) (536.3) (249.7) (786.0) - Revisions other than price 221.4 (204.1) 17.3 (115.5) Purchases in place 579.6 - 579.6 - Extensions, discoveries and other additions (d) 2,385.8 965.3 3,351.1 - ------- ----- ------- --- Total Proved Reserve Additions (e) 2,650.5 511.5 3,162.0 (115.5) Disposition in Property Exchanges (f) (131.5) - (131.5) - Sales in place (36.7) (5.4) (42.1) - ----- ---- ----- --- Net Proved Reserve Additions From All Sources (g) 2,482.3 506.1 2,988.4 (115.5) ======= ===== ======= ====== Production (h) 576.6 93.2 669.8 114.1 RESERVE REPLACEMENT COSTS ($ / Mcfe) Total Drilling, Before Revisions (a / d ) $1.23 $0.30 $0.96 $- All-in Total, Net of Revisions (b / (e + f)) $1.21 $0.56 $1.10 $(0.31) All-in Total, Excluding Revisions Due to Price (b / (e + f - c )) $0.99 $0.38 $0.87 $(0.31) RESERVE REPLACEMENT Drilling Only (d / h) 414% 1036% 500% - All-in Total, Net of Revisions & Dispositions (g / h) 431% 543% 446% -101% All-in Total, Excluding Revisions Due to Price ((g - c) / h ) 524% 811% 564% -101% (1) Acquisition costs for certain properties in Montague and Cooke counties, Texas were partially settled with EOG common stock valued at $89.6 million. Other Total Int'l Int'l Total --------- --------- --------- Total Costs Incurred in Exploration and Development Activities (GAAP) $73.5 $115.9 $3,907.5 Less: Asset Retirement Costs 0.1 (6.0) (83.6) Acquisition Cost of Proved Properties - - (111.7) Non-Cash Acquisition Costs - - (387.9) --- --- ------ Total Exploration & Development Expenditures for Drilling Only (Non-GAAP) (a) $73.6 $109.9 $3,324.3 ===== ====== ======== Total Costs Incurred in Exploration and Development Activities (GAAP) $73.5 $115.9 $3,907.5 Less: Asset Retirement Costs 0.1 (6.0) (83.6) Non-Cash Acquisition Costs - - (387.9) --- --- ------ Total Exploration & Development Expenditures (Non-GAAP) (1) (b) $73.6 $109.9 $3,436.0 ===== ====== ======== Net Proved Reserve Additions From All Sources - Natural Gas Equivalents (Bcfe) Revisions due to price (c) - - (786.0) Revisions other than price 3.1 (112.4) (95.1) Purchases in place - - 579.6 Extensions, discoveries and other additions (d) - - 3,351.1 --- --- ------- Total Proved Reserve Additions (e) 3.1 (112.4) 3,049.6 Disposition in Property Exchanges (f) - - (131.5) Sales in place - - (42.1) --- --- ----- Net Proved Reserve Additions From All Sources (g) 3.1 (112.4) 2,876.0 === ====== ======= Production (h) 5.4 119.5 789.3 RESERVE REPLACEMENT COSTS ($ / Mcfe) Total Drilling, Before Revisions (a / d) $- $- $0.99 All-in Total, Net of Revisions (b / (e + f)) $23.74 $(0.98) $1.18 All-in Total, Excluding Revisions Due to Price (b / (e + f - c )) $23.74 $(0.98) $0.93 RESERVE REPLACEMENT Drilling Only (d / h) - - 425% All-in Total, Net of Revisions & Dispositions (g / h) 57% -94% 364% All-in Total, Excluding Revisions Due to Price ((g - c) / h ) 57% -94% 464% (1) Acquisition costs for certain properties in Montague and Cooke counties, Texas were partially settled with EOG common stock valued at $89.6 million. EOG RESOURCES, INC. QUANTITATIVE RECONCILIATION OF NET DEBT (Non-GAAP) AND TOTAL ------------------------------------------------------------ CAPITALIZATION (Non-GAAP) AS USED IN THE CALCULATION OF ------------------------------------------------------- THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO (Non-GAAP) ----------------------------------------------------- TO CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP) -------------------------------------------------------------------- (Unaudited; in millions, except ratio data) The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. December 31, 2009 ---- Total Stockholders' Equity - (a) $9,998 ------ Current and Long-Term Debt - (b) 2,797 Less: Cash (686) ---- Net Debt (Non-GAAP) - (c) 2,111 ----- Total Capitalization (GAAP) - (a) + (b) $12,795 ======= Total Capitalization (Non-GAAP) - (a) + (c) $12,109 ======= Debt-to-Total Capitalization (GAAP) - (b) / ( (a) + (b) ) 22% === Net Debt-to-Total Capitalization (Non-GAAP) - (c) / ( (a) + (c) ) 17% === EOG RESOURCES, INC. QUANTITATIVE RECONCILIATION OF AFTER-TAX INTEREST EXPENSE (Non-GAAP), NET ------------------------------------------------------------------------- DEBT (Non-GAAP) AND TOTAL CAPITALIZATION (Non-GAAP) AS USED IN THE ------------------------------------------------------------------ CALCULATION OF RETURN ON CAPITAL EMPLOYED (Non-GAAP) TO INTEREST EXPENSE ------------------------------------------------------------------------ (GAAP), CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION ------------------------------------------------------------------ (GAAP), RESPECTIVELY -------------------- (Unaudited; in millions, except ratio data) The following chart reconciles Interest Expense (GAAP), Current and Long- Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (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, Net Debt and Total Capitalization in their ROCE calculation. EOG management uses this information for comparative purposes within the industry. 1999 2000 2001 2002 ---- ---- ---- ---- Interest Expense $61.0 $45.1 $59.7 Tax Benefit Imputed (based on 35%) (21.4) (15.8) (20.9) ----- ----- ----- After-Tax Interest Expense (Non-GAAP) - (a) $39.6 $29.3 $38.8 ----- ----- ----- Net Income - (b) $396.9 $398.6 $87.2 ------ ------ ----- Total Stockholders' Equity - (c) $1,129.6 $1,380.9 $1,642.7 $1,672.4 -------- -------- -------- -------- Current and Long-Term Debt - (d) $990.3 $859.0 $856.0 $1,145.1 Less: Cash (24.8) (20.2) (2.5) (9.8) ----- ----- ---- ---- Net Debt (Non-GAAP) - (e) $965.5 $838.8 $853.5 $1,135.3 ------ ------ ------ -------- Total Capitalization (GAAP) - (c) + (d) $2,119.9 $2,239.9 $2,498.7 $2,817.5 ======== ======== ======== ======== Total Capitalization (Non-GAAP) - (c) + (e) $2,095.1 $2,219.7 $2,496.2 $2,807.7 ======== ======== ======== ======== Average Total Capitalization (Non-GAAP)* - (f) $2,157.4 $2,358.0 $2,652.0 ======== ======== ======== Return on Capital Employed (Non-GAAP) - ( (a) + (b) ) / (f) 20.2% 18.1% 4.8% ==== ==== === Average Return on Capital Employed (Non-GAAP) 2000 - 2009 2003 2004 2005 2006 ---- ---- ---- ---- Interest Expense $58.7 $63.1 $62.5 $43.2 Tax Benefit Imputed (based on 35%) (20.5) (22.1) (21.9) (15.1) ----- ----- ----- ----- After-Tax Interest Expense (Non- GAAP) - (a) $38.2 $41.0 $40.6 $28.1 ----- ----- ----- ----- Net Income - (b) $430.1 $624.9 $1,259.6 $1,299.9 ------ ------ -------- -------- Total Stockholders' Equity - (c) $2,223.4 $2,945.4 $4,316.3 $5,599.7 -------- -------- -------- -------- Current and Long-Term Debt - (d) $1,108.9 $1,077.6 $985.1 $733.4 Less: Cash (4.4) (21.0) (643.8) (218.3) ---- ----- ------ ------ Net Debt (Non-GAAP) - (e) $1,104.5 $1,056.6 $341.3 $515.1 -------- -------- ------ ------ Total Capitalization (GAAP) - (c) + (d) $3,332.3 $4,023.0 $5,301.4 $6,333.1 ======== ======== ======== ======== Total Capitalization (Non-GAAP) - (c) + (e) $3,327.9 $4,002.0 $4,657.6 $6,114.8 ======== ======== ======== ======== Average Total Capitalization (Non-GAAP)* - (f) $3,067.8 $3,665.0 $4,329.8 $5,386.2 ======== ======== ======== ======== Return on Capital Employed (Non-GAAP) - ( (a) + (b) ) / (f) 15.3% 18.2% 30.0% 24.7% ==== ==== ==== ==== Average Return on Capital Employed (Non-GAAP) 2000 - 2009 2007 2008 2009 ---- ---- ---- Interest Expense $46.8 $51.7 $100.9 Tax Benefit Imputed (based on 35%) (16.4) (18.1) (35.3) ----- ----- ----- After-Tax Interest Expense (Non-GAAP) - (a) $30.4 $33.6 $65.6 ----- ----- ----- Net Income - (b) $1,089.9 $2,436.9 $546.6 -------- -------- ------ Total Stockholders' Equity - (c) $6,990.1 $9,014.5 $9,998.0 -------- -------- -------- Current and Long-Term Debt - (d) $1,185.0 $1,897.0 $2,797.0 Less: Cash (54.2) (331.3) (685.8) ----- ------ ------ Net Debt (Non-GAAP) - (e) $1,130.8 $1,565.7 $2,111.2 -------- -------- -------- Total Capitalization (GAAP) - (c) + (d) $8,175.1 $10,911.5 $12,795.0 ======== ========= ========= Total Capitalization (Non-GAAP) - (c) + (e) $8,120.9 $10,580.2 $12,109.2 ======== ========= ========= Average Total Capitalization (Non-GAAP)* - (f) $7,117.9 $9,350.6 $11,344.7 ======== ======== ========= Return on Capital Employed (Non-GAAP) - ( (a) + (b) ) / (f) 15.7% 26.4% 5.4% ==== ==== === Average Return on Capital Employed (Non-GAAP) 2000 - 2009 17.9% ==== * Average of "Total Capitalization (Non-GAAP)" for the current and immediately preceding year
SOURCE EOG Resources, Inc.
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