HOUSTON, Feb. 17, 2011 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) today reported fourth quarter 2010 net income of $53.7 million, or $0.21 per share. This compares to fourth quarter 2009 net income of $400.4 million, or $1.58 per share. For the full year 2010, EOG reported net income of $160.7 million, or $0.63 per share, as compared to $546.6 million, or $2.17 per share, for the full year 2009.

The results for the fourth quarter 2010 included a $122.3 million, net of tax ($0.48 per share) impairment of certain non-core North American onshore and offshore natural gas assets, gains on property dispositions of $98.8 million, net of tax ($0.39 per share) and a previously disclosed non-cash net loss of $43.9 million ($28.0 million after tax, or $0.11 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash outflow related to financial commodity contracts was $18.1 million ($11.6 million after tax, or $0.05 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 for the quarter was $92.0 million, or $0.36 per share. Adjusted non-GAAP net income for the fourth quarter 2009 was $234.3 million, or $0.92 per share.

On a similar basis, eliminating the items detailed in the attached table, adjusted non-GAAP net income for the full year 2010 was $296.4 million, or $1.16 per share, and for the full year 2009 was $754.5 million, or $3.00 per share. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

2010 Operational Highlights

EOG’s total company production increased 9.5 percent in 2010 over 2009. Total company liquids rose 33 percent, driven by a 35 percent increase in crude oil and condensate production and a 29 percent increase in natural gas liquids. For the full year 2010, total company revenues from crude oil, condensate and natural gas liquids exceeded those from natural gas. For the fourth quarter 2010, crude oil revenues surpassed those from natural gas with almost half of total company wellhead revenues emanating from crude oil.

In the United States, crude oil and condensate production increased 32 percent in 2010 over the prior year primarily from EOG’s continued development of the North Dakota Bakken/Three Forks, the Fort Worth Barnett Combo and the South Texas Eagle Ford Plays. At year-end 2010, EOG ranked as the largest crude oil producer in both the North Dakota Bakken and South Texas Eagle Ford Plays.

“EOG has become a formidable onshore U.S. crude oil producer through early identification and extensive acreage capture in a number of premier horizontal resource plays,” said Mark G. Papa, Chairman and Chief Executive Officer.

Across its large acreage position in the mature crude oil window of the South Texas Eagle Ford, EOG drilled and completed numerous wells in the fourth quarter while still maintaining its 100 percent success rate. In the eastern part of EOG’s acreage in Dewitt County, the Hansen Kullin Unit 2-H and 4-H were completed in December at peak rates of 1,625 and 1,700 barrels of oil per day (Bopd), respectively. On the west side of the play, the Naylor Jones Unit 86 #1H averaged over 870 Bopd for the first 30 days. In Atascosa County, the Peeler Ranch 4-H showed a peak crude oil production rate in excess of 1,300 Bopd. EOG has a 100 percent working interest in all these wells. During the quarter, EOG increased its prospective acreage in the mature crude oil window from 505,000 to 520,000 net acres.

“I continue to be pleased by the consistency of EOG’s Eagle Ford results across our 120-mile long holdings,” said Papa. “Our confidence in taking an early-mover role in this new play is being rewarded.”

In the fourth quarter, EOG drilled its first successful horizontal Eagle Ford well outside the crude oil window. The Tully C. Garner #100H, located southwest of EOG’s established crude oil acreage in Webb County, began production at a pipeline restricted rate of 2.8 million cubic feet per day (MMcfd) of rich natural gas with 239 barrels per day of condensate. EOG has a 100 percent working interest in the well. EOG has 26,000 net acres in the liquids-rich natural gas window.

EOG expanded its inventory of organic horizontal liquids plays with first-mover drilling success in the West Texas Permian Basin Wolfcamp Shale. To date, EOG has drilled and completed four wells in this liquids-rich play where it holds 120,000 net acres in Irion and Crockett Counties. Across the Wolfcamp, EOG’s production mix is projected to be 78 percent crude oil, condensate and natural gas liquids with 22 percent natural gas. Potential reserves are estimated to be at least 40 million barrels of oil equivalent (MMboe), net after royalty, from one of multiple potential productive intervals. During 2011, EOG plans to operate a three-rig Wolfcamp development drilling program.

Drilling results from Weld County, Colorado, have increased EOG’s confidence in the economic viability of the DJ Basin Niobrara crude oil play. To date, EOG has focused drilling efforts on its 80,000 net acre Hereford Ranch prospect where it has drilled multiple successful wells. Most importantly, EOG has made progress in establishing productivity from the Niobrara rock by successfully converting it from one dependent on fractures to a more matrix-dominated play. This increases the likelihood that the Niobrara is another true crude oil resource play that can be developed with tighter spacing and a greater number of economic wells than originally estimated.

In the Fort Worth Barnett Shale Combo where it drilled over 230 net wells in 2010, EOG continues to make operational improvements that are increasing per well reserves and lowering individual well costs. The Ava Unit #1H and #2H were completed with initial production rates of 337 and 489 Bopd with 311 and 524 thousand cubic feet per day (Mcfd) of liquids-rich natural gas, respectively. The Hailey Unit #1H and #2H were completed with initial rates of 335 and 320 Bopd with 207 and 261 Mcfd, respectively. EOG has 100 percent working interest in all four Montague County wells. EOG plans to run an active drilling program in the Barnett Shale Combo again this year.

EOG has accumulated a 600,000 net acre position in the Bakken, primarily in North Dakota. Current activity is primarily focused outside the Bakken Core on Bakken Lite and Three Forks development and drilling. As previously reported, EOG had exceptional well results from McKenzie County, North Dakota, southwest of its Core Parshall Field. During the fourth quarter, the Mandaree 12-07H and Liberty 16-36 were completed to sales at initial net production rates of 1,559 and 1,066 Bopd, plus associated liquids-rich natural gas. EOG has 86 and 95 percent working interests, respectively, in the wells.

“By augmenting our existing suite of quality crude oil assets during 2010 with exploration success in the South Texas Eagle Ford, the DJ Basin Niobrara and the Permian Basin Wolfcamp Shale Plays, we made meaningful strides in EOG’s transition to a more liquids-focused company,” said Papa. “In addition, by applying the operational efficiencies we have developed, EOG is moving into a highly efficient manufacturing mode of development drilling in plays such as the North Dakota Bakken/Three Forks, Fort Worth Barnett Combo, South Texas Eagle Ford and Manitoba Waskada.”

Natural Gas Activity

EOG’s North American natural gas production decreased 2 percent in 2010 from 2009. This retraction reflects not only EOG’s continued transition to crude oil and liquids-rich drilling activities but is indicative of weak natural gas pricing fundamentals, as well as the sale of certain natural gas producing assets. In 2011, EOG plans to limit its dry gas drilling program to hold leases in the East Texas/North Louisiana Haynesville and Bossier, the Pennsylvania Marcellus and the British Columbia Horn River Basin Plays.

In the Marcellus Shale, EOG has approximately 210,000 net acres. On its 50,000 net acre position in Bradford County, EOG completed the Hoppaugh No. 3H using improved completion techniques. The well, in which EOG has a 96 percent working interest, tested at a rate of 14 MMcfd of natural gas. This is EOG’s best producer in the field to date. Applying similar completion methodology in Clearfield County, EOG brought three wells to sales at rates that ranged from 7 to 9 MMcfd. EOG has a 50 percent working interest in these wells.

EOG is encouraged by early production results in the British Columbia Horn River Basin where its winter operations are being finalized. In addition, EOG and its partner continue to make progress on the Kitimat LNG export facility project with initial natural gas sales targeted for late 2015. EOG anticipates committing a percentage of its approximately 9 trillion cubic feet, net after royalty, of natural gas reserve potential in British Columbia for export through the terminal. Plans are to sell the LNG to international markets, primarily in Asia.

Reserves

EOG’s total company proved reserves for 2010 increased 8.5 percent over the prior year from 1,796 to 1,950 MMBoe, all organic. Excluding the impact of property dispositions, total company and total North American net proved developed reserves increased 9.6 percent and 12.6 percent, respectively. Total liquids proved reserves increased from 17 percent to 28 percent of total proved reserves.

In 2010:

• Total reserve replacement from all sources - the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production - was 207 percent at a total reserve replacement cost of $15.05 per barrel of oil equivalent (Boe), based on exploration and development expenditures of $5,383 million. (Please refer to the attached tables for the calculation of total reserve replacement and total reserve replacement costs.)
• Proved developed reserve replacement from drilling – the ratio of net reserve additions from drilling to total production – was 180 percent.
• In the United States, total reserve replacement from all sources was 339 percent at a reserve replacement cost of $12.96 per Boe based on exploration and development expenditures of $4,676 million. (Please refer to the attached tables for the calculation of United States total reserve replacement and total reserve replacement costs.)

For the 23rd 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 2010, D&M prepared a complete independent engineering analysis of properties containing 77 percent of EOG’s proved reserves on a Boe basis.

2011 Operational Plans and Targets

EOG is targeting total company production growth of 9.5 percent in 2011. Total liquids production is forecast to increase 49 percent, comprised of 55 percent crude oil growth and 34 percent natural gas liquids growth. In North America, natural gas production is expected to decrease 5 percent from 2010, reflecting the impact of producing property sales and a weak natural gas pricing environment. Estimated exploration and production expenditures for 2011 will range from $6.4 to $6.6 billion, including exploration, development and production facilities and midstream expenditures. To offset any funding gap between estimated cash flows and capital expenditures, EOG expects to sell approximately $1 billion of natural gas and midstream assets during 2011. With a continued focus on the balance sheet, EOG plans to maintain a net debt-to-total capitalization ratio below 35 percent at both year-end 2011 and 2012.

For the period March 1 through December 31, 2011, EOG has 425,000 million British thermal units per day (MMbtud) of natural gas financial price swap contracts in place at a weighted average price of $5.09 per million British thermal units (MMbtu), excluding unexercised swaptions. For the full year 2012, EOG has 250,000 MMbtud of natural gas financial price swap contracts in place at a weighted average price of $5.56 per MMbtu, excluding unexercised swaptions. For February 1 through December 31, 2011, EOG has 18,000 barrels per day (Bbld) of crude oil financial price swap contracts in place at a weighted average price of $90.69 per barrel. For the full year 2012, EOG has 2,000 Bbld of crude oil financial price swap contracts in place at a weighted average price of $100.50 per barrel.

Capital Structure

During 2010, total cash proceeds from the sale of acreage and natural gas producing assets were $673 million. At December 31, 2010, EOG’s total debt outstanding was $5,223 million for a debt-to-total capitalization ratio of 34 percent. Taking into account cash on the balance sheet of $789 million at year-end, EOG’s net debt was $4,434 million for a net debt-to-total capitalization ratio of 30 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 (non-GAAP).)

Dividend Increase

Following an increase in the common stock dividend in 2010, EOG’s Board of Directors has again increased the cash dividend on the common stock. Effective with the dividend payable on April 29, 2011, to holders of record as of April 15, 2011, the quarterly dividend on the common stock will be $0.16 per share, an increase of 3 percent over the previous indicated annual rate. The indicated annual rate of $0.64 per share reflects the 12th increase in 12 years.

Conference Call Scheduled for February 18, 2011

EOG’s fourth quarter and full year 2010 results conference call will be available via live audio webcast at 8 a.m. Central standard time (9 a.m. Eastern standard time) on Friday, February 18, 2011. To listen, log on to www.eogresources.com. The webcast will be archived on EOG’s website through March 4, 2011.

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, 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, returns, budgets, reserves, 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 any of these expectations will be achieved (in full or at all) 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 and  market 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, and to produce reserves and achieve anticipated production levels from, its existing and future natural gas and crude oil exploration and 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;
• changes in government policies, laws and regulations, including environmental and tax laws and regulations;
• 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 production, gathering, processing, compression and transportation 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;
• political developments around the world, including in the areas in which EOG operates;
• 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;
• 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 14 through 19 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results.  Accordingly, 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, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances 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 press release 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, 2009, 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.