10-K 1 form10-k.htm EOG FORM 10-K


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


Form 10-K


x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-9743

EOG RESOURCES, INC.
(Exact name of registrant as specified in its charter)

Delaware

 

47-0684736

(State or other jurisdiction
of incorporation or organization)

 

(I.R.S. Employer Identification No.)

333 Clay Street, Suite 4200, Houston, Texas 77002-7361
(Address of principal executive offices)      (zip code)

Registrant's telephone number, including area code: 713-651-7000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

 

Name of each exchange on which registered

Common Stock, par value $0.01 per share

 

New York Stock Exchange

Preferred Share Purchase Rights

 

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer x Accelerated Filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of February 17, 2006 and as of the last business day of the registrant's most recently completed second fiscal quarter. Common Stock aggregate market value held by non-affiliates as of February 17, 2006: $17,354,275,342 and as of June 30, 2005: $13,626,764,801.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Class: Common Stock, par value $0.01 per share, on February 17, 2006, Shares Outstanding: 242,547,524.

Documents incorporated by reference. Portions of the following document are incorporated by reference into the indicated parts of this report: Proxy Statement for the May 2, 2006 Annual Meeting of Shareholders to be filed within 120 days after December 31, 2005 (Proxy Statement) - Part III.

 

TABLE OF CONTENTS

                                                                                                                                                                                                                        Page
                                                                                                                                            PART I

Item 1.

Business

 

1

 

   General

 

1

 

   Business Segments

 

1

 

   Exploration and Production

 

1

 

   Marketing

 

6

 

   Wellhead Volumes and Prices

 

7

 

   Competition

 

8

 

   Regulation

 

8

 

   Other Matters

 

11

 

   Current Executive Officers of the Registrant

 

13

Item 1A.

Risk Factors

 

14

Item 1B.

Unresolved Staff Comments

 

17

Item 2.

Properties

 

17

 

Oil and Gas Exploration and Production Properties and Reserves

 

17

Item 3.

Legal Proceedings

 

19

Item 4.

Submission of Matters to a Vote of Security Holders

 

19

PART II

Item 5.

Market for Registrant's Common Equity, Related Shareholder Matters and

   
 

Issuer Purchases of Equity Securities

 

20

Item 6.

Selected Financial Data

 

21

Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations

 

22

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

 

37

Item 8.

Financial Statements and Supplementary Data

 

37

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

37

Item 9A.

Controls and Procedures

 

37

Item 9B.

Other Information

 

37

PART III

Item 10.

Directors and Executive Officers of the Registrant

 

38

Item 11.

Executive Compensation

 

38

Item 12.

Security Ownership of Certain Beneficial Owners and Management and

   
 

Related Stockholder Matters

 

38

Item 13.

Certain Relationships and Related Transactions

 

39

Item 14.

Principal Accounting Fees and Services

 

39

PART IV

Item 15.

Exhibits and Financial Statement Schedules

 

39

SIGNATURES

(i)

 

PART I

ITEM 1. Business

General

EOG Resources, Inc. (EOG), a Delaware corporation organized in 1985, together with its subsidiaries, explores for, develops, produces and markets natural gas and crude oil primarily in major producing basins in the United States of America (United States), Canada, offshore Trinidad, the United Kingdom North Sea and, from time to time, select other international areas. EOG's principal producing areas are further described in "Exploration and Production" below. EOG's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports are made available, free of charge, through its website, as soon as reasonably practicable after such reports have been filed with the Securities and Exchange Commission (SEC). EOG's website address is http://www.eogresources.com.

At December 31, 2005, EOG's total estimated net proved reserves were 6,194 billion cubic feet equivalent (Bcfe), of which 5,557 billion cubic feet (Bcf) were natural gas reserves and 106 million barrels (MMBbl), or 637 Bcfe, were crude oil, condensate and natural gas liquids reserves (see "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 56% of EOG's reserves (on a natural gas equivalent basis) were located in the United States, 22% in Canada, 21% in Trinidad and 1% in the United Kingdom North Sea. As of December 31, 2005, EOG employed approximately 1,400 persons, including foreign national employees.

EOG's business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis. EOG focuses its drilling activity toward natural gas deliverability in addition to natural gas reserve replacement and to a lesser extent crude oil exploration and exploitation. EOG focuses on the cost-effective utilization of advances in technology associated with the gathering, processing and interpretation of three-dimensional (3-D) seismic data, the development of reservoir simulation models, the use of new and/or improved drill bits, mud motors and mud additives, and formation logging techniques and reservoir fracturing methods. These advanced technologies are used, as appropriate, throughout EOG to reduce the risks associated with all aspects of oil and gas reserve exploration, exploitation and development. EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. EOG also makes select tactical acquisitions that result in additional economies of scale or land positions with significant additional prospects. Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

With respect to information on EOG's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by EOG's working interest in the wells or acreage.

Business Segments

EOG's operations are all natural gas and crude oil exploration and production related.

Exploration and Production

United States and Canada Operations

EOG's operations are focused on most of the productive basins in the United States and Canada.

At December 31, 2005, 88% of EOG's net proved United States and Canada reserves (on a natural gas equivalent basis) were natural gas and 12% were crude oil, condensate and natural gas liquids. Substantial portions of these reserves are in long-lived fields with well-established production characteristics. EOG believes that opportunities exist to increase production through continued development in and around many of these fields and through application of new processes and technologies. EOG also maintains an active exploration program designed to extend fields and add new trends to its broad portfolio. The following is a summary of significant developments during 2005 and certain 2006 plans for EOG's United States and Canada operations.

1

United States. During 2005, EOG continued its success in the prolific Barnett Shale play in North Texas with excellent drilling results plus significant growth in production and an increased acreage position. EOG drilled 88 net horizontal wells and grew production to approximately 100 million cubic feet per day (MMcfd), net by year-end. EOG made several significant gas discoveries, extending the trend to the west of Fort Worth. EOG increased its acreage position in the Barnett Shale play to over 500,000 acres during 2005 and may add acreage in this prolific play during 2006. EOG had 12 drilling rigs operating at year-end 2005, and plans to increase the number of rigs throughout 2006. EOG plans to drill approximately 210 gross Barnett Shale wells in 2006, which will continue EOG's strong production growth from the play. EOG is positioned for significant production and reserve growth in the Barnett Shale play for many more years.

In the Permian Basin, EOG exploited a successful Permo-Penn carbonate play and maintained an active horizontal drilling program in the Devonian formation of West Texas. Additionally, two new plays in Southeast New Mexico were deemed successful - a horizontal Wolfcamp play where EOG drilled six successful wells in 2005 and controls approximately 35,000 net acres and a horizontal Bone Spring shelf play where five successful wells were drilled in 2005 and EOG controls approximately 15,000 net acres. EOG drilled 54 net wells in the Permian Basin in 2005 and net production averaged 92 MMcfd of natural gas and 7.9 thousand barrels per day (MBbld) of crude oil, condensate and natural gas liquids. EOG has assembled an acreage position of over 130,000 net acres in several other growth plays that are currently being tested by drilling. With success, these plays will move into the exploitation phase in mid-to-late 2006.

EOG continued to intensify its activities in the Rocky Mountain area, drilling 119 net wells during 2005, including 47 net wells in the Uinta Basin, Utah, nine net wells on the LaBarge Platform, Wyoming, 41 net wells on the Moxa Arch, Wyoming, and seven net wells in the Williston Basin. The net average daily production from the Rocky Mountain area was 141 MMcfd of natural gas and 7.5 MBbld of crude oil, condensate and natural gas liquids. EOG expects to continue increasing drilling activity in these core areas during 2006, while maintaining a very active exploration program.

In the Mid-Continent area, EOG drilled 137 net wells in its core areas in 2005, most notably the Hugoton-Deep play in the Oklahoma Panhandle and the Cleveland Horizontal play in the Texas Panhandle. The net average daily production was 79 MMcfd of natural gas and 2.1 MBbld of crude oil and condensate. EOG expanded its Hugoton-Deep program by approximately 900,000 acres and 1,300 square miles of 3-D seismic through the consummation of a 10-year joint venture with Anadarko Petroleum Company. In its Cleveland horizontal program, EOG has drilled 120 net wells since 2003 and expects to drill another 50 net wells in 2006. During 2005, EOG acquired new leases on over 8,000 net acres, increasing its position to approximately 130,000 net acres available to drill for Cleveland and high potential Morrow accumulations. In addition to these two areas, EOG will continue drilling in the Texas Panhandle area and pursue exploration prospects throughout the Mid-Continent area.

The Upper Gulf Coast continues to be a significant growth area for EOG where 2005 production averaged 113 MMcfd of natural gas and 3.1 MBbld of crude oil, condensate and natural gas liquids. EOG drilled 24 wells in the Sligo Field in 2005 and anticipates drilling an equal number of wells in both 2006 and 2007. The expanded Cotton Valley development program continues with five wells drilled in 2005 and 12 wells planned for 2006. Horizontal drilling is now being deployed in a new operating area in the Spider Field, North Louisiana, where five wells were drilled in 2005 and 13 are planned for 2006. Another new growth area is the Hosston trend in Mississippi where five wells were drilled in 2005 and 10 wells are planned for 2006. EOG will continue to develop growth opportunities in East Texas, North Louisiana and Mississippi and will test several high potential prospects in the Lower Gulf Coast areas of Texas and Louisiana during 2006.

EOG continues to have excellent success in South Texas where EOG drilled 76 net wells in 2005. The area averaged net production of 181 MMcfd of natural gas and 6.0 MBbld of crude oil, condensate and natural gas liquids. This represents the fourth consecutive year-over-year increase. The activity was focused in Webb, Zapata, San Patricio, Lavaca, Duval and other counties, where EOG executed successful drilling programs in the Lobo, Roleta, Reklaw, Frio and Wilcox plays. Significant activity in these areas resulted from successful extensions of existing plays, including the Frio trend in San Patricio and Nueces Counties, and the Lobo and Roleta trends in Webb and Zapata Counties. EOG successfully added new lease positions and 3-D seismic in 2005 to sustain drilling through 2006 and beyond.

2

In 2005, EOG drilled 90 net wells in the Appalachian area. Net production averaged 20 MMcfd of natural gas and 100 barrels per day (Bbld) of crude oil and condensate. EOG has reduced its focus on the Trenton Black River and has expanded the development of intermediate depth Mississippian and Ordovician plays. EOG expects to drill 85 net wells in 2006 to further expand the shallow and intermediate plays and will continue to focus on the expansion and development of higher impact, multiple-well plays.

During 2005, EOG's net production in the Gulf of Mexico averaged 41 MMcfd of natural gas and 1.1 MBbld of crude oil, condensate and natural gas liquids. Four shelf fields (Eugene Island 135, Matagorda Island 623, High Island 206, and Mustang Island 759) accounted for over 70% of this production. Due to Hurricanes Katrina and Rita, 2005 net production decreased an average of 4 MMcfd and 60 barrels of condensate per day (Bcpd). At year-end, a net 6 MMcfd and 98 Bcpd remained shut-in. This shut-in production is projected to be online by mid-year 2006. During 2005, EOG drilled six gross wells, resulting in four discoveries. The four successful wells, two at Grand Isle 94 and one each at Mustang Island 762 and High Island A-443, resulted in a net production increase of 8 MMcfd. A similar level of activity is planned in 2006.

At December 31, 2005, EOG held approximately 2,805,000 net undeveloped acres in the United States.

Canada. In Canada, EOG conducts operations through its subsidiary EOG Resources Canada, Inc. (EOGRC) from offices in Calgary, Alberta. During 2005, EOGRC continued its successful, shallow, natural gas strategy in Western Canada. An unusually wet summer resulted in surface conditions that restricted the overall drilling program whereby a total of 960 gross wells were drilled in 2005. Several soft access shallow natural gas areas will be drilled on the winter frost early in 2006 and will increase EOGRC's 2006 drilling program to 1,200 wells. The 2005 shallow natural gas drilling program included 208 gross Horseshoe Canyon dry coalbed methane wells. EOGRC's net production during 2005 averaged 228 MMcfd of natural gas, and 3.3 MBbld of crude oil, condensate and natural gas liquids. Key producing areas in the Western Canadian Sedimentary Basin are the Southeast Alberta/Southwest Saskatchewan shallow natural gas trends including Drumheller and Twining areas, and the Grand Prairie/Wapiti areas of Northwest Alberta. EOGRC's ongoing 2006 drilling activity will continue to be concentrated in these areas and will include a similar Horseshoe Canyon dry coalbed methane program. EOGRC will also participate in two high impact exploratory tests in the Northwest Territories during the first quarter of 2006, one on a separate new structure and one as delineation to our Summit Creek discovery, which was tested in early 2005.

At December 31, 2005, EOG held approximately 1,590,000 net undeveloped acres in Canada.

Operations Outside the United States and Canada

EOG has operations offshore Trinidad and the United Kingdom North Sea, and is evaluating additional exploration, exploitation and development opportunities in the United Kingdom, Trinidad and other international areas.

Trinidad. In November 1992, EOG, through its subsidiary, EOG Resources Trinidad Limited (EOGRT) acquired an exploration and production license with a 95% working interest, subject to a 5% overriding royalty interest, with an option to convert such overriding royalty interest to a 15% working interest in the South East Coast Consortium (SECC) Block offshore Trinidad. The Kiskadee, Ibis and Parula fields have been developed and are being produced. EOG is currently developing the Oilbird field and expects first production in the first quarter of 2007. The license covering the SECC Block will expire in December 2029. Effective February 3, 2005, the other participants in the SECC Block exercised their option to convert their 5% overriding royalty interest to a 15% working interest, thereby reducing EOG's working interest to 80%.

EOGRT and the other participants in the SECC Block signed a farm-in agreement covering the SECC Deep Ibis prospect with BP Trinidad and Tobago LLC in the fourth quarter of 2004. BP will pay the entire cost for drilling the exploratory well, which is expected to spud in the second quarter of 2006. EOG will retain a 50.6% working interest in the prospect and will develop the prospect, if successful.

In July 1996, EOG, through its subsidiary, EOG Resources Trinidad-U(a) Block Limited, signed a production sharing contract with the Government of Trinidad and Tobago for the Modified U(a) Block. EOG holds a 100% working interest in this block. The Osprey field was discovered in 1998 and commenced production in 2002.

3

Surplus processing and transportation capacity at the Pelican field facilities (owned and operated by a subsidiary of the other participants in the SECC Block) is being used to process and transport much of EOG's natural gas production and all of its crude oil and condensate production from the SECC and Modified U(a) Blocks. Crude oil and condensate from EOG's Trinidad operations are being sold to the Petroleum Company of Trinidad and Tobago.

In April 2002, EOG, through its subsidiary, EOG Resources Trinidad-LRL Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for the Lower Reverse "L" (LRL) Block which is adjacent to the SECC Block. EOG holds a 100% working interest in the LRL Block. In the fourth quarter of 2003, EOG drilled the first exploration well, LRL #1, on this block. The well was determined to be non-commercial. In November 2004, EOG drilled the LRL #2 well which encountered approximately 130 feet of net pay. In December 2004, the LRL #3 exploratory well was drilled and determined to be a dry hole. EOG plans to seek third parties to join in further exploration of the block in 2006.

In October 2002, EOG, through its subsidiary, EOG Resources Trinidad U(b) Block Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for the Modified U(b) Block which is also adjacent to the SECC Block. EOG holds a 55% working interest in and operates the Modified U(b) Block. Primera Oil & Gas Ltd., a Trinidadian company, holds the remaining 45% working interest. In September 2004, EOG drilled the first exploration well on this block, and the well was determined to be non-commercial. EOG will likely drill another well on the block in 2007.

In July 2005, EOG, through its subsidiary, EOG Resources Trinidad Block 4(a) Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for Block 4(a). EOG, as the operator, holds a 90% working interest in Block 4(a). Primera Block 4(a) Limited, a Trinidadian company, holds the remaining 10% working interest. In January 2006, EOG completed drilling its first successful exploratory well on this block and plans to drill another well in the first quarter of 2006. EOG intends to commence development work on this block by mid-2006 and is targeting mid-2009 for on-line production.

Natural gas from EOG's Trinidad operations is being sold to the National Gas Company of Trinidad and Tobago (NGC) under the following arrangements:

  • Under the first take-or-pay contract, the expiration of which was extended in February 2005 from December 2008 to December 2018, natural gas is delivered to NGC for resale to Trinidad local markets. During 2005, EOG delivered net average production of 115 MMcfd of natural gas under this agreement. The extended contract, among other things, provides for a change in the pricing of wellhead natural gas volumes previously sold under a fixed price schedule with annual escalations. Prices are now partially dependent on Caribbean ammonia index prices and methanol prices.

  • Under the second take-or-pay contract, which expires in 2017, EOG delivers to NGC approximately 60 MMcfd, gross, of natural gas which is resold to an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Caribbean Nitrogen Company Limited (CNCL). During 2005, 46 MMcfd, net to EOG, of natural gas was delivered under this contract to NGC. The plant commenced production in June 2002 and currently produces approximately 1,900 metric tons of ammonia daily. EOGRT owns a 12% equity interest in CNCL. At December 31, 2005, EOGRT's investment in CNCL was $18 million. At December 31, 2005, CNCL had a long-term debt balance of $173 million, which is non-recourse to CNCL's shareholders. As part of the financing for CNCL, the shareholders have entered into a post-completion deficiency loan agreement with CNCL to fund the costs of operations, payment of principal and interest to the principal creditor and other cash deficiencies of CNCL up to $30 million, approximately $4 million of which is net to EOGRT's interest. The shareholders' agreement governing CNCL requires the consent of the holders of 90% or more of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOGRT is able to exercise significant influence over the operating and financial policies of CNCL and therefore, EOG accounts for the investment using the equity method. During 2005, EOG recognized equity income of $9 million and received cash dividends of $5 million from CNCL.

4

  • Under a fifteen-year take-or-pay contract, which expires in 2019, EOG delivers to NGC approximately 60 MMcfd, gross, of natural gas which is resold to an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Nitrogen (2000) Unlimited (N2000). During 2005, 48 MMcfd, net to EOG, of natural gas was delivered under this contract to NGC. The plant commenced production in August 2004 and currently produces approximately 2,100 metric tons of ammonia daily. EOG's subsidiary, EOG Resources NITRO2000 Ltd. (EOGNitro2000), owned a 10% equity interest in N2000 at December 31, 2005. In February 2005, EOGNitro2000 sold a portion of its ownership interest to one of the other shareholders, reducing EOGNitro2000's equity interest in N2000 to 10%. At December 31, 2004, EOGNitro2000's equity interest in N2000 was 23%. The sale resulted in a pre-tax gain of $2 million. At December 31, 2005, EOGNitro2000's investment in N2000 was $16 million. At December 31, 2005, N2000 had a long-term debt balance of $197 million, which is non-recourse to N2000's shareholders. As part of the loan agreement for the N2000 financing, affiliates of the shareholders have entered into a post-completion deficiency loan agreement with N2000 to fund the costs of operations, payment of principal and interest to the principal creditor and other cash deficiencies of N2000 up to $30 million, approximately $3 million of which is to be provided by the immediate parent company of EOGNitro2000. The shareholders' agreement governing N2000 requires the consent of the holders of 100% of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOGNitro2000 is able to exercise significant influence over the operating and financial policies of N2000 and therefore, EOG accounts for the investment using the equity method. During 2005, EOG recognized equity income of $7 million and received cash dividends of $2 million from N2000.

  • Under a natural gas contract signed in January 2004, EOG is currently supplying approximately 100 MMcfd, gross, of natural gas to NGC, which is then being resold by NGC to a methanol plant located in Point Lisas, Trinidad. The plant, in which EOG does not own an interest, started production during the fourth quarter of 2005. Under this gas contract, EOG expects to ultimately supply approximately 94 MMcfd, gross, (60 MMcfd, net to EOG, based on current pricing and operating assumptions) for the first four years of the contract term and approximately 122 MMcfd, gross, (80 MMcfd, net to EOG, based on current pricing and operating assumptions) for the remaining term of the eleven-year contract.

  • In February 2005, EOGRT executed a twenty-year take-or-pay contract with NGC LNG (Train 4) Limited, a subsidiary of NGC, for the supply of 30 MMcfd, gross, (17 MMcfd, net to EOG, based on current pricing and operating assumptions) of natural gas for use in a LNG plant in Point Fortin, Trinidad. The LNG plant began pre-start up operations in December 2005. During the first quarter of 2006, EOG expects to supply varying amounts of gas while NGC awaits the completion of pipelines from third party producers who also are under contract with NGC to supply incremental gas volumes into the LNG plant. EOG has no equity investment in the LNG plant.

In 2005, EOG's average net production from Trinidad was 231 MMcfd of natural gas and 4.5 MBbld of crude oil and condensate.

At December 31, 2005, EOG held approximately 261,600 net undeveloped acres in Trinidad.

United Kingdom. In 2002, EOG's subsidiary, EOG Resources United Kingdom Limited (EOGUK) acquired a 25% non-operating working interest in a portion of Block 49/16, located in the Southern Gas Basin of the North Sea. In August 2004, production commenced in the Valkyrie field in the Southern Gas Basin.

In 2003, EOGUK acquired a 30% non-operating working interest in a portion of Blocks 53/1 and 53/2. These blocks are also located in the Southern Gas Basin of the North Sea. In November 2003, a successful exploratory well, Arthur 1, was drilled in the Arthur field. Production from Arthur 1 commenced in January 2005. The Arthur 2 well was drilled during the first quarter of 2005 as an extension to the Arthur 1 discovery. Production from Arthur 2 commenced in July 2005. Another development well, Arthur 3, is planned for the first half of 2006 as an extension to the current discovery.

In the first half of 2005, EOGUK completed the drilling of two exploration wells, West Boulton and Polecat, which were both determined to be non-commercial.

5

In 2005, EOG delivered net average production of 39 MMcfd of natural gas in the United Kingdom.

At December 31, 2005, EOG held approximately 355,500 net undeveloped acres in the United Kingdom.

Other International. EOG continues to evaluate other select natural gas and crude oil opportunities outside the United States and Canada primarily by pursuing exploitation opportunities in countries where indigenous natural gas and crude oil reserves have been identified.

Marketing

Wellhead Marketing. EOG's United States and Canada wellhead natural gas production is currently being sold on the spot market and under long-term natural gas contracts at market-responsive prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. In 2005, a large majority of the wellhead natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The pricing mechanisms for these contracts will remain the same in 2006. Also in Trinidad, in late December 2005, EOG began selling wellhead natural gas volumes under a new contract at prices partially dependent on the United States Henry Hub market prices. In the United Kingdom, wellhead natural gas production is currently being sold on the spot market.

Substantially all of EOG's wellhead crude oil and condensate is sold under various terms and arrangements at market-responsive prices.

During 2005, sales to a major integrated oil and gas company with investment grade credit ratings accounted for 11% of EOG's oil and gas revenues. No other individual purchaser accounted for 10% or more of EOG's oil and gas revenues for the same period. EOG does not believe that the loss of any single purchaser will have a material adverse effect on the financial condition or results of operations of EOG.

6

Wellhead Volumes and Prices

The following table sets forth certain information regarding EOG's wellhead volumes of and average prices for natural gas per thousand cubic feet (Mcf), crude oil and condensate per barrel (Bbl) and natural gas liquids per Bbl. The table also presents natural gas equivalent volumes on a thousand cubic feet equivalent basis (Mcfe - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil, condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 2005.

       

2005

 

2004

 

2003

Natural Gas Volumes (MMcfd)

           
 

United States

 

718

 

631

 

638

 

Canada

 

228

 

212

 

165

 

Trinidad

 

231

 

186

 

152

 

United Kingdom

 

39

 

7

 

-

   

Total

 

1,216

 

1,036

 

955

Crude Oil and Condensate Volumes (MBbld)

           
 

United States

 

21.5

 

21.1

 

18.5

 

Canada

 

2.4

 

2.7

 

2.3

 

Trinidad

 

4.5

 

3.6

 

2.4

 

United Kingdom

 

0.2

 

-

 

-

   

Total

 

28.6

 

27.4

 

23.2

Natural Gas Liquids Volumes (MBbld)

           
 

United States

 

6.6

 

4.8

 

3.2

 

Canada

 

0.9

 

0.8

 

0.6

   

Total

 

7.5

 

5.6

 

3.8

Natural Gas Equivalent Volumes (MMcfed)(1)

           
 

United States

 

886

 

786

 

768

 

Canada

 

248

 

233

 

183

 

Trinidad

 

259

 

207

 

166

 

United Kingdom

 

40

 

7

 

-

   

Total

 

1,433

 

1,233

 

1,117

Average Natural Gas Prices ($/Mcf)(2)

           
 

United States

$

7.86

$

5.72

$

5.06

 

Canada

 

7.14

 

5.22

 

4.66

 

Trinidad

 

2.20

(3)

1.51

 

1.35

 

United Kingdom

 

6.99

 

5.14

 

-

   

Composite

 

6.62

 

4.86

 

4.40

Average Crude Oil and Condensate Prices ($/Bbl)(2)

           
 

United States

$

54.57

$

40.73

$

30.24

 

Canada

 

50.49

 

37.68

 

28.54

 

Trinidad

 

57.36

 

39.12

 

28.88

 

United Kingdom

 

49.62

 

-

 

-

   

Composite

 

54.63

 

40.22

 

29.92

Average Natural Gas Liquids Prices ($/Bbl)(2)

           
 

United States

$

35.59

$

27.79

$

21.53

 

Canada

 

35.59

 

23.23

 

19.13

   

Composite

 

35.59

 

27.13

 

21.13

                 

(1) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Includes $0.23 per Mcf as a result of a revenue adjustment related to an amended Trinidad take-or-pay contract.

7

Competition

EOG competes for reserve acquisitions and exploration/exploitation leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent EOG's exploration budget is lower than that of certain of its competitors, EOG may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms and quality of service, including pipeline connection times and distribution efficiencies. In addition, EOG faces competition from other worldwide energy supplies, such as liquefied natural gas imported into the United States from other countries.

Regulation

United States Regulation of Natural Gas and Crude Oil Production. Natural gas and crude oil production operations are subject to various types of regulation, including regulation in the United States by state and federal agencies.

United States legislation affecting the oil and gas industry is under constant review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and liquid hydrocarbon resources through proration and restrictions on flaring, require drilling bonds and regulate environmental and safety matters.

A substantial portion of EOG's oil and gas leases in Utah, Wyoming and the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (BLM) and the Minerals Management Service (MMS), both federal agencies. Operations conducted by EOG on federal oil and gas leases must comply with numerous statutory and regulatory restrictions. Certain operations must be conducted pursuant to appropriate permits issued by the BLM and the MMS.

BLM and MMS leases contain relatively standardized terms requiring compliance with detailed regulations and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act (which are subject to change by the MMS). Such offshore operations are subject to numerous regulatory requirements, including the need for prior MMS approval for exploration, development, and production plans, stringent engineering and construction specifications applicable to offshore production facilities, regulations restricting the flaring or venting of production, and regulations governing the plugging and abandonment of offshore wells and the removal of all production facilities. Under certain circumstances, the MMS may require operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect EOG's interests.

In 2002, the D.C. Circuit reversed a 2000 district court decision and upheld a 1997 MMS gas valuation rule categorically denying allowances for post-production marketing costs such as long-term storage fees and marketer fees; however, the D.C. Circuit decision expressly allows firm demand charges to be deducted. Two trade associations had sought judicial review of the 1997 gas valuation rule and procured a favorable district court decision; however, the D.C. Circuit decision and denial of certorari by the Supreme Court ended the litigation in early 2003. On March 10, 2005, the MMS published a final rule further revising the gas valuation regulations. The 2005 gas rule revision clarifies the deductibility of transportation costs and adopts the 2004 oil valuation rule's cost of capital approach for calculating non-arm's length transportation allowances described below. EOG cannot predict what effect these changes will have on EOG operations but nothing significant is anticipated.

In 2004, the MMS further amended its royalty regulations governing the valuation of crude oil produced from federal leases. The MMS's 2000 oil valuation rule had replaced a set of valuation benchmarks based on posted prices and comparable sales with an indexing system based on spot prices at nearby market centers. Among other things, the 2000 oil valuation rule (like the 1997 gas valuation rule) also categorically disallowed deductions for post-production marketing costs. Two industry trade associations sought judicial review of the 2000 oil valuation rule, but voluntarily dismissed their suit after late 2002 negotiations led the MMS to amend its oil valuation rule further in 2004. The amended rule retained indexing for valuation but replaced spot prices with New York Mercantile Exchange future prices, except in the Rocky Mountain Region and California. The 2004 oil valuation rule also liberalized allowances for non-arm's length transportation arrangements by increasing the multiplier used for calculating the cost of capital. While the 2000 oil valuation rule was likely to increase EOG's royalty obligation somewhat, the 2004 oil valuation rule is likely to lessen that increase.

Sales of crude oil, condensate and natural gas liquids by EOG are made at unregulated market prices.

8

The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978 (NGPA). These statutes are administered by the Federal Energy Regulatory Commission (FERC). Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by EOG of its own production. All other sales of natural gas by EOG, such as those of natural gas purchased from third parties, remain jurisdictional sales subject to a blanket sales certificate under the NGA, which has flexible terms and conditions. Consequently, all of EOG's sales of natural gas currently may be made at market prices, subject to applicable contract provisions. EOG's jurisdictional sales, however, are subject to the future possibility of greater federal oversight, including the possibility that the FERC might prospectively impose more restrictive conditions on such sales.

EOG owns, directly or indirectly, certain natural gas pipelines that it believes meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. EOG's gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.

EOG's natural gas gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of facilities. Additional rules and legislation pertaining to these matters are considered and/or adopted from time to time. Although EOG cannot predict what effect, if any, such legislation might have on its operations, the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the state legislatures, the FERC, the state regulatory commissions and the federal and state courts. EOG cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less regulated approach currently being followed by the FERC will continue indefinitely.

Environmental Regulation - United States. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, affect EOG's operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations and could cause EOG to incur remediation or other corrective action costs in connection with a release of regulated substances, including crude oil, into the environment. In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, EOG could be responsible under environmental laws and regulations for oil and gas properties in which EOG owns an interest but is not the operator. Compliance with such laws and regulations increases EOG's overall cost of business, but has not had a material adverse effect on EOG's operations or financial condition. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program in order to comply with environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, EOG is unable to predict the ultimate cost of compliance. EOG also could incur costs related to the clean up of sites to which it sent regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such sites.

Canadian Regulation of Natural Gas and Crude Oil Production. The crude oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. These regulatory authorities may impose regulations on or otherwise intervene in the oil and natural gas industry with respect to prices, taxes, transportation rates, the exportation of the commodity and, possibly, expropriation or cancellation of contract rights. Such regulations may be changed from time to time in response to complaints or economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for these commodities, increase EOG's costs and may have a material adverse impact on its operations.

9

It is not expected that any of these controls or regulations will affect EOG operations in a manner materially different than they would affect other oil and gas companies of similar size. EOG is unable to predict what additional legislation or amendments may be enacted.

In addition, each province has regulations that govern land tenure, royalties, production rates and other matters. The royalty regime is a significant factor in the profitability of crude oil and natural gas production. Royalties payable on production from private lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

Environmental Regulation - Canada. All phases of the crude oil and natural gas industry in Canada are subject to environmental regulation pursuant to a variety of Canadian federal, provincial, and municipal laws and regulations. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances to the environment. These laws and regulations also require that facility sites and other properties associated with EOG's operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the submission and approval of environmental assessments or permit applications. These laws and regulations are subject to frequent change and the clear trend is to place increasingly stringent limitations on activities that may affect the environment. While compliance with such legislation can require significant expenditures, failure to comply with these environmental laws and regulations could result in the assessment of administrative, civil or criminal penalties, suspension or revocation of licenses and, in some instances, the issuance of injunctions to limit or cease operations.

Spills and releases from EOG's properties may have resulted or result in soil and groundwater contamination in certain locations. Such contamination is not unusual within the crude oil and natural gas industries. Any contamination found on, under or originating from the properties may be subject to remediation requirements under Canadian laws. EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, EOG could be held responsible for oil and gas properties in which EOG owns an interest but is not the operator.

In December 2002, the Canadian federal government ratified the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which requires Canada to reduce its greenhouse gas emissions to 6% below 1990 levels over the 2008-2012 periods. The Climate Change Plan for Canada, which was released in November 2002, outlines, in very general terms, the approach the Canadian government intends to take to implement its emissions reduction commitment. The Canadian government issued a further climate change plan, Moving Forward on Climate Change: A Plan for Honouring our Kyoto Commitment, in April of 2005. Companies designated as Large Final Emitters of Greenhouse Gases (LFEs), which will include a number of companies in the oil and gas sector, will be assigned targets for emissions reduction. LFEs may meet their targets through investments in their own activities, the purchase of emissions credits from other emitters, investment in domestic offset credits, and the purchase of international credits. The Canadian government has renewed its promise that the cost to industry of compliance will not exceed $15 per tonne of carbon dioxide equivalent. The Canadian government has also committed that post-2012 emissions reduction targets will not make Canadian oil and gas production uncompetitive, and that industry will be consulted on the technical feasibility and economic impacts of targets for the period post-2012. The Canadian government's stated preference is to use the Canadian Environmental Protection Act to regulate industry where necessary. It is expected, however, that the Canadian government will largely delegate regulatory responsibility to the provinces through equivalency agreements, whereby a province will perform the necessary regulatory function if it has a substantively identical (or more onerous) program in place, as compared to that implemented by the Canadian government. The final rules, once known, could affect operations and profitability.

Other International Regulation. EOG's exploration and production operations outside the United States and Canada are subject to various types of regulations imposed by the respective governments of the countries in which EOG's operations are conducted, and may affect EOG's operations and costs within that country. EOG currently has operations in Trinidad and the United Kingdom.

10

Other Matters

Energy Prices. Since EOG is primarily a natural gas producer, it is more significantly impacted by changes in prices for natural gas than changes in prices for crude oil, condensate or natural gas liquids. Average United States and Canada wellhead natural gas prices have fluctuated, at times rather dramatically, during the last three years. These fluctuations resulted in a 75% increase in the average wellhead natural gas price for production in the United States and Canada received by EOG from 2002 to 2003, an increase of 12% from 2003 to 2004, and an increase of 37% from 2004 to 2005. In 2005, a large majority of the wellhead natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The pricing mechanisms for these contracts will remain the same in 2006. Also in Trinidad, in late December 2005, EOG began selling wellhead natural gas volumes under a new contract at prices partially dependent on the United States Henry Hub market prices. In the United Kingdom, wellhead natural gas production is currently being sold on the spot market. Crude oil and condensate prices also have fluctuated during the last three years. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, EOG is unable to predict what changes may occur in natural gas, crude oil and condensate, ammonia and methanol prices in the future.

Assuming a totally unhedged position for 2006, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2006 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf change in average wellhead natural gas price is approximately $24 million for net income and operating cash flow. EOG is not impacted as significantly by changing crude oil prices. EOG's price sensitivity in 2006 for each $1.00 per barrel change in average wellhead crude oil price is approximately $6 million for net income and operating cash flow. Summarized below and in Note 11 to Consolidated Financial Statements is information regarding EOG's current 2006 natural gas hedge position. As of February 22, 2006, EOG had no crude oil hedges.

Risk Management. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collars and price swaps, as the means to manage this price risk. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. Under Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137, 138 and 149, these physical commodity contracts qualify for the normal purchases and normal sales exception and therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

Presented below is a summary of EOG's 2006 natural gas financial collar and price swap contracts at February 22, 2006, with prices expressed in dollars per million British thermal units ($/MMBtu) and notional volumes in million British thermal units per day (MMBtud). As indicated, EOG does not have any financial collar or price swap contracts that cover periods beyond October 2006. EOG accounts for these collar and price swap contracts using mark-to-market accounting.

Natural Gas Financial Contracts

 

Collar Contracts

 

Price Swap Contracts

   

Floor Price

 

Ceiling Price

     
     

Weighted

   

Weighted

   

Weighted

     

Average

 

Ceiling

Average

   

Average

 

Volume

Floor Range

Price

 

Range

Price

 

Volume

Price

Month

(MMBtud)

($/MMBtu)

($/MMBtu)

 

($/MMBtu)

($/MMBtu)

 

(MMBtud)

($/MMBtu)

                   

February (closed)

50,000

$13.65 - 14.50

$14.05

 

$16.20 - 17.04

$16.59

 

-

-

March

50,000

13.50 - 14.30

13.87

 

15.95 - 17.05

16.46

 

170,000

$9.54

April

50,000

10.00 - 10.50

10.23

 

12.60 - 13.00

12.77

 

180,000

9.49

May

50,000

9.75 - 10.00

9.87

 

12.15 - 12.60

12.31

 

180,000

9.50

June

50,000

9.75 - 10.00

9.87

 

12.20 - 12.60

12.34

 

180,000

9.54

July

50,000

9.75 - 10.00

9.87

 

12.35 - 12.85

12.50

 

190,000

9.57

August

50,000

9.75 - 10.00

9.87

 

12.50 - 13.00

12.67

 

190,000

9.63

September

-

-

-

 

-

-

 

140,000

9.40

October

-

-

-

 

-

-

 

90,000

9.46

11

All of EOG's natural gas and crude oil activities are subject to the risks normally incident to the exploration for and development and production of natural gas and crude oil, including blowouts, cratering and fires, each of which could result in damage to life and/or property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions. EOG's activities are also subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, insurance is maintained by EOG against some, but not all, of the risks. Losses and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by insurance. Please refer to Item 1A. Risk Factors beginning on page 14 for further discussion of the risks to which EOG is subject.

EOG's operations outside of the United States and Canada are subject to certain risks, including expropriation of assets, risks of increases in taxes and government royalties, renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and currency exchange and repatriation losses, as well as changes in laws, regulations and policies governing operations of foreign companies.

Texas Severance Tax Exemption. Natural gas production from qualifying Texas wells spudded or completed after August 31, 1996, is entitled to use a reduced severance tax rate for the first 120 consecutive months of production. However, the cumulative value of the tax reduction cannot exceed 50 percent of the drilling and completion costs incurred on a well-by-well basis.

Common Stock Rights Agreement. On February 14, 2000, EOG's Board of Directors declared a dividend of one preferred share purchase right (a "Right," and the agreement governing the terms of such Rights, the "Rights Agreement") for each outstanding share of common stock, par value $0.01 per share. The Board of Directors has adopted this Rights Agreement to protect stockholders from coercive or otherwise unfair takeover tactics. The dividend was distributed to the stockholders of record on February 24, 2000. In accordance with the Rights Agreement, each share of common stock issued in connection with the two-for-one stock split effective March 1, 2005, also had one Right associated with it. Each Right, expiring February 24, 2010, represents a right to buy from EOG one hundredth (1/100) of a share of Series E Junior Participating Preferred Stock (Series E) for $90, once the Rights become exercisable. This portion of a Series E share will give the stockholder approximately the same dividend, voting, and liquidation rights as would one share of common stock. Prior to exercise, the Right does not give its holder any dividend, voting, or liquidation rights. If issued, each one hundredth (1/100) of a Series E share (i) will not be redeemable; (ii) will entitle holders to quarterly dividend payments of $0.01 per share, or an amount equal to the dividend paid on one share of common stock, whichever is greater; (iii) will entitle holders upon liquidation either to receive $1 per share or an amount equal to the payment made on one share of common stock, whichever is greater; (iv) will have the same voting power as one share of common stock; and (v) if shares of EOG's common stock are exchanged via merger, consolidation, or a similar transaction, will entitle holders to a per share payment equal to the payment made on one share of common stock.

The Rights will not be exercisable until ten days after a public announcement that a person or group has become an acquiring person (Acquiring Person) by obtaining beneficial ownership of 10% or more of EOG's common stock, or if earlier, ten business days (or a later date determined by EOG's Board of Directors before any person or group becomes an Acquiring Person) after a person or group begins a tender or exchange offer which, if consummated, would result in that person or group becoming an Acquiring Person. On February 24, 2005, the Rights Agreement was amended to create an exception to the definition of Acquiring Person to permit a qualified institutional investor to hold 10% or more, but less than 20%, of EOG's common stock without being deemed an Acquiring Person if the institutional investor meets the following requirements: (i) the institutional investor is described in Rule 13d-1(b)(1) promulgated under the Securities Exchange Act of 1934 and is eligible to report (and, if such institutional investor is the beneficial owner of greater than 5% of EOG's common stock, does in fact report) beneficial ownership of common stock on Schedule 13G; (ii) the institutional investor is not required to file a Schedule 13D (or any successor or comparable report) with respect to its beneficial ownership of EOG's common stock; (iii) the institutional investor does not beneficially own 15% or more of EOG's common stock (including in such calculation the holdings of all of the institutional investor's affiliates and associates other than those which, under published interpretations of the United States Securities and Exchange Commission or its staff, are eligible to file separate reports on Schedule 13G with respect to their beneficial ownership of EOG's common stock); and (iv) the institutional investor does not beneficially own 20% or more of EOG's common stock (including in such calculation the holdings of all of the institutional investor's affiliates and associates). On June 15, 2005, the Rights Agreement was amended again to revise the exception to the definition of Acquiring Person to permit a qualified institutional investor to hold 10% or more but less than 30% of EOG's common stock without being deemed an Acquiring Person if the institutional investor meets the other requirements described above.

12

If a person or group becomes an Acquiring Person, all holders of Rights, except the Acquiring Person, may for $90, purchase shares of EOG's common stock with a market value of $180, based on the market price of the common stock prior to such acquisition. If EOG is later acquired in a merger or similar transaction after the Rights become exercisable, all holders of Rights except the Acquiring Person may, for $90, purchase shares of the acquiring corporation with a market value of $180 based on the market price of the acquiring corporation's stock, prior to such merger.

EOG's Board of Directors may redeem the Rights for $0.005 per Right at any time before any person or group becomes an Acquiring Person. If the Board of Directors redeems any Rights, it must redeem all of the Rights. Once the Rights are redeemed, the only right of the holders of Rights will be to receive the redemption price of $0.005 per Right. The redemption price has been adjusted for the two-for-one stock split effective March 1, 2005 and will be adjusted for any future stock split or stock dividends of EOG's common stock. After a person or group becomes an Acquiring Person, but before an Acquiring Person owns 50% or more of EOG's outstanding common stock, the Board of Directors may exchange the Rights for common stock or equivalent security at an exchange ratio of one share of common stock or an equivalent security for each such Right, other than Rights held by the Acquiring Person.

Preferred Stock. EOG currently has two authorized series of preferred stock. On February 14, 2000, EOG's Board of Directors, in connection with the Rights Agreement described above, authorized 1,500,000 shares of the Series E with the rights and preferences described above. On February 24, 2005, EOG's Board of Directors increased the authorized shares of Series E to 3,000,000 as a result of the two-for-one stock split of EOG's common stock effective March 1, 2005. Currently, there are no shares of the Series E outstanding.

On July 19, 2000, EOG's Board of Directors authorized 100,000 shares of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 Liquidation Preference per share (Series B). Dividends are payable on the shares only if declared by EOG's Board of Directors and will be cumulative. If declared, dividends will be payable at a rate of $71.95 per share, per year on March 15, June 15, September 15 and December 15 of each year beginning September 15, 2000. EOG may redeem all or part of the Series B at any time beginning on December 15, 2009 at $1,000 per share, plus accrued and unpaid dividends. The Series B is not convertible into, or exchangeable for, common stock of EOG. There are 100,000 shares of the Series B currently outstanding.

Following the December 2004 redemption of all outstanding shares of EOG's Flexible Money Market Cumulative Preferred Stock, Series D, EOG filed a Certificate of Elimination with the Secretary of State of the State of Delaware on February 24, 2005 to eliminate the series from EOG's Restated Certificate of Incorporation, as amended.

Current Executive Officers of the Registrant

The current executive officers of EOG and their names and ages are as follows:

Name

Age

Position

     

Mark G. Papa

59

Chairman of the Board and Chief Executive Officer; Director

     

Edmund P. Segner, III

52

President and Chief of Staff; Director

     

Loren M. Leiker

52

Executive Vice President, Exploration and Development

     

Gary L. Thomas

56

Executive Vice President, Operations

     

Barry Hunsaker, Jr.

55

Senior Vice President and General Counsel

     

Timothy K. Driggers

44

Vice President and Chief Accounting Officer

13

Mark G. Papa was elected Chairman of the Board and Chief Executive Officer of EOG in August 1999, President and Chief Executive Officer and Director in September 1998, President and Chief Operating Officer in September 1997, President in December 1996 and was President-North America Operations from February 1994 to September 1998. Mr. Papa joined Belco Petroleum Corporation, a predecessor of EOG, in 1981. Mr. Papa is EOG's principal executive officer.

Edmund P. Segner, III became President and Chief of Staff and Director of EOG in August 1999. He became Vice Chairman and Chief of Staff of EOG in September 1997. He was a director of EOG from January 1997 to October 1997. Mr. Segner is EOG's principal financial officer.

Loren M. Leiker was elected Executive Vice President, Exploration in May 1998 and was subsequently named Executive Vice President, Exploration and Development. He was previously Senior Vice President, Exploration. Mr. Leiker joined EOG in April 1989 as International Exploration Manager.

Gary L. Thomas was elected Executive Vice President, North America Operations in May 1998 and was subsequently named Executive Vice President, Operations. He was previously Senior Vice President and General Manager of EOG in Midland. Mr. Thomas joined a predecessor of EOG in July 1978.

Barry Hunsaker, Jr. has been Senior Vice President and General Counsel since he joined EOG in May 1996.

Timothy K. Driggers was elected Vice President and Controller of EOG in October 1999 and was subsequently named Vice President and Chief Accounting Officer in August 2003. He was previously Vice President, Accounting and Land Administration. Mr. Driggers is EOG's principal accounting officer.

There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are appointed or elected annually by the Board of Directors at its meeting immediately prior to the Annual Meeting of Shareholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been duly elected or appointed and shall have qualified.

ITEM 1A. Risk Factors

Our business faces many risks. The risks described below may not be the only risks we face. Additional risks that we do not yet know of, or that we currently think are immaterial, may also impair our business operations or financial results. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline. The following risk factors should be read in conjunction with the other information contained in this report, including the consolidated financial statements and the related notes.

A substantial or extended decline in natural gas or crude oil prices would have a material adverse effect on us.

Prices for natural gas and crude oil fluctuate widely. Since we are primarily a natural gas company, we are more significantly affected by changes in natural gas prices than changes in the prices for crude oil, condensate or natural gas liquids. Among the factors that can cause these price fluctuations are:

  • the level of consumer demand;
  • weather conditions;
  • domestic drilling activity;
  • the price and availability of alternative fuels;
  • the proximity to, and capacity of, transportation facilities;
  • worldwide economic and political conditions;
  • the effect of worldwide energy conservation measures; and
  • the nature and extent of governmental regulation and taxation.

Our cash flow and earnings depend to a great extent on the prevailing prices for natural gas and crude oil. Prolonged or substantial declines in these commodity prices may adversely affect our liquidity, the amount of cash flow we have available for capital expenditures and our ability to maintain our credit quality and access to the credit and capital markets.

14

Our ability to sell our crude oil and natural gas production could be materially harmed if we fail to obtain adequate services such as transportation and processing.

The sale of our crude oil and natural gas production depends on a number of factors beyond our control, including the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities or our failure to obtain these services on acceptable terms could materially harm our business. We deliver crude oil and natural gas through gathering systems and pipelines that we do not own. These facilities may be temporarily unavailable due to market conditions or mechanical reasons, or may not be available to us in the future.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our underlying assumptions could cause the quantities of our reserves to be overstated.

Estimating quantities of proved crude oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions or changes of conditions could cause the quantities of our reserves to be overstated.

To prepare estimates of economically recoverable crude oil and natural gas reserves and future net cash flows, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs. Actual results most likely will vary from our estimates. Any significant variance could reduce our estimated quantities and present value of reserves.

If we fail to acquire or find sufficient additional reserves, our reserves and production will decline from their current levels.

The rate of production from crude oil and natural gas properties generally declines as reserves are depleted. Except to the extent that we conduct successful exploration and development activities, acquire additional properties containing proved reserves, or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced. Future crude oil and natural gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.

Drilling crude oil and natural gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.

Drilling crude oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive crude oil and natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

  • unexpected drilling conditions;
  • title problems;
  • pressure or irregularities in formations;
  • equipment failures or accidents;
  • adverse weather conditions;
  • compliance with environmental and other governmental requirements, which may increase our costs or restrict our activities; and
  • costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment.

We incur certain costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future.

15

Our exploration, production and marketing operations are regulated extensively at the federal, state and local levels, as well as by other countries in which we do business. We have and will continue to incur costs in our efforts to comply with the requirements of environmental and other regulations. Further, the crude oil and natural gas industry regulatory environment could change in ways that might substantially increase these costs.

As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, local and foreign regulations relating to discharge of materials into, and protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damages, and require suspension or cessation of operations in affected areas. Changes in or additions to regulations regarding the protection of the environment could hurt our business.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.

Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, injure or kill people, and damage property and the environment. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts that we believe to be prudent. Losses and liabilities arising from such events could reduce our revenues and increase our costs to the extent not covered by insurance.

The occurrence of any of these events and any payments made as a result of such events and the liabilities related thereto, would reduce the funds available for exploration, drilling and production and could have a material adverse effect on our financial position or results of operations.

Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.

From time to time, we use derivative instruments (primarily collars and price swaps) to hedge the impact of market fluctuations on natural gas and crude oil prices and net income and cash flow. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges. In addition, we are subject to risks associated with differences in prices at different locations, particularly where transportation constraints restrict our ability to deliver oil and gas volumes to the delivery point to which the hedging transaction is indexed.

If we acquire oil and gas properties, our failure to fully identify potential problems, to properly estimate reserves or production rates or costs, or to effectively integrate the acquired operations could seriously harm us.

From time to time, we seek to acquire oil and gas properties. Although we perform reviews of acquired properties that we believe are consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems, nor do they permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Even when problems with a property are identified, we often assume environmental and other risks and liabilities in connection with acquired properties.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs with respect to acquired properties. Actual results may vary substantially from those assumed in the estimates.

In addition, acquisitions may have adverse effects on our operating results, particularly during the periods in which the operations of acquired properties are being integrated into our ongoing operations.

Terrorist activities and military and other actions could adversely affect our business.

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as the military or other actions taken in response to these acts, cause instability in the global financial and energy markets. The United States government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These actions could adversely affect us in unpredictable ways, including the disruption of fuel supplies and markets, increased volatility in crude oil and natural gas prices, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terror.

16

Competition in the oil and gas exploration and production industry is intense, and many of our competitors have greater resources than we have.

We compete with major integrated and other independent oil and gas companies for acquisition of oil and gas leases, properties and reserves, equipment and labor required to explore, develop and operate those properties and the marketing of crude oil and natural gas production. Higher recent crude oil and natural gas prices have increased the costs of properties available for acquisition and there are a greater number of companies with the financial resources to pursue acquisition opportunities.

Many of our competitors have financial and other resources substantially larger than those we possess and have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new or expanded entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil and natural gas production, such as changing worldwide prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. We also compete in attracting and retaining personnel, including geologists, geophysicists, engineers and other specialists.

We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.

We make, and will continue to make, substantial capital expenditures for the acquisition, development, production, exploration and abandonment of our oil and gas reserves. We intend to finance our capital expenditures primarily through cash flow from operations, commercial paper and to a lesser extent and if necessary, bank borrowings and public and private equity and debt offerings. Lower crude oil and natural gas prices, however, would reduce our cash flow and our access to the capital markets. Further, if the condition of the capital markets materially declines, we might not be able to obtain financing on terms we consider acceptable. In addition, a substantial rise in interest rates would decrease our net cash flows available for reinvestment.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties

Oil and Gas Exploration and Production Properties and Reserves

Reserve Information. For estimates of EOG's net proved and proved developed reserves of natural gas and liquids, including crude oil, condensate and natural gas liquids, see Supplemental Information to Consolidated Financial Statements.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and liquids, including crude oil, condensate and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate (upward or downward). Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.

In general, production from EOG's oil and gas properties declines as reserves are depleted. Except to the extent EOG acquires additional properties containing proved reserves or conducts successful exploration, exploitation and development activities, the proved reserves of EOG will decline as reserves are produced. Volumes generated from future activities of EOG are therefore highly dependent upon the level of success in finding or acquiring additional reserves and the costs incurred in so doing. EOG's estimates of reserves filed with other federal agencies agree with the information set forth in Supplemental Information to Consolidated Financial Statements.

17

Acreage. The following table summarizes EOG's developed and undeveloped acreage at December 31, 2005. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.

 

Developed

 

Undeveloped

 

Total

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

                       

United States

                     
 

Texas

621,849

 

378,441

 

1,728,115

 

1,082,082

 

2,349,964

 

1,460,523

 

Wyoming

202,267

 

139,653

 

408,555

 

290,219

 

610,822

 

429,872

 

Oklahoma

286,153

 

212,405

 

252,182

 

149,034

 

538,335

 

361,439

 

Pennsylvania

82,416

 

70,779

 

177,695

 

159,314

 

260,111

 

230,093

 

New Mexico

101,332

 

66,690

 

251,676

 

155,027

 

353,008

 

221,717

 

Utah

83,739

 

57,308

 

228,702

 

141,686

 

312,441

 

198,994

 

Offshore Gulf of Mexico

191,959

 

70,036

 

153,855

 

85,682

 

345,814

 

155,718

 

Montana

145,030

 

14,063

 

202,334

 

137,921

 

347,364

 

151,984

 

Nevada

-

 

-

 

123,353

 

123,353

 

123,353

 

123,353

 

West Virginia

46,816

 

39,285

 

101,981

 

67,794

 

148,797

 

107,079

 

Ohio

61,753

 

58,341

 

36,774

 

35,571

 

98,527

 

93,912

 

Louisiana

19,866

 

13,369

 

110,599

 

69,679

 

130,465

 

83,048

 

New York

407

 

395

 

85,486

 

74,573

 

85,893

 

74,968

 

California

8,907

 

5,872

 

69,078

 

58,937

 

77,985

 

64,809

 

Colorado

22,944

 

1,309

 

75,347

 

53,438

 

98,291

 

54,747

 

North Dakota

3,947

 

1,414

 

58,423

 

40,581

 

62,370

 

41,995

 

Virginia

801

 

448

 

39,158

 

38,357

 

39,959

 

38,805

 

Kansas

10,697

 

9,357

 

22,525

 

19,215

 

33,222

 

28,572

 

Mississippi

27,186

 

15,561

 

44,482

 

11,429

 

71,668

 

26,990

 

Alabama

-

 

-

 

5,535

 

5,084

 

5,535

 

5,084

 

Michigan

-

 

-

 

3,881

 

3,774

 

3,881

 

3,774

 

Kentucky

-

 

-

 

1,721

 

1,721

 

1,721

 

1,721

 

Arkansas

-

 

-

 

854

 

152

 

854

 

152

   

Total United States

1,918,069

 

1,154,726

 

4,182,311

 

2,804,623

 

6,100,380

 

3,959,349

                           

Canada

                     
 

Alberta

1,362,326

 

1,085,312

 

833,926

 

757,622

 

2,196,252

 

1,842,934

 

Saskatchewan

375,505

 

345,175

 

103,238

 

99,110

 

478,743

 

444,285

 

Nova Scotia

-

 

-

 

749,213

 

374,606

 

749,213

 

374,606

 

Northwest Territories

699

 

184

 

747,387

 

204,364

 

748,086

 

204,548

 

British Columbia

7,681

 

1,920

 

95,674

 

87,710

 

103,355

 

89,630

 

Manitoba

15,780

 

15,028

 

67,072

 

66,912

 

82,852

 

81,940

 

New Brunswick

219

 

33

 

-

 

-

 

219

 

33

   

Total Canada

1,762,210

 

1,447,652

 

2,596,510

 

1,590,324

 

4,358,720

 

3,037,976

                           

Trinidad

41,492

 

36,825

 

305,381

 

261,575

 

346,873

 

298,400

                           

United Kingdom

7,159

 

2,078

 

556,397

 

355,465

 

563,556

 

357,543

                           
   

Total

3,728,930

 

2,641,281

 

7,640,599

 

5,011,987

 

11,369,529

 

7,653,268

Producing Well Summary. The following table reflects EOG's ownership in natural gas and crude oil wells located in Texas, the Gulf of Mexico, Oklahoma, New Mexico, Utah, Louisiana, Mississippi, Pennsylvania, Wyoming, and various other states in the United States, Canada, Trinidad and the United Kingdom at December 31, 2005. Gross natural gas and crude oil wells include 809 with multiple completions.

 

Productive Wells

 

Gross

 

Net

       

Natural Gas

18,739

 

15,644

Crude Oil

1,751

 

1,201

 

Total

20,490

 

16,845

18

Drilling and Acquisition Activities. During the years ended December 31, 2005, 2004 and 2003, EOG expended $1,878 million, $1,510 million and $1,333 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties. EOG drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated:

 

2005

 

2004

 

2003

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

Development Wells Completed

                     
 

United States and Canada

                     
   

Gas

1,523

 

1,241.3

 

1,839

 

1,623.3

 

1,586

 

1,440.0

   

Oil

79

 

68.6

 

92

 

79.3

 

89

 

79.0

   

Dry

80

 

70.0

 

104

 

86.9

 

89

 

78.0

   

Total

1,682

 

1,379.9

 

2,035

 

1,789.5

 

1,764

 

1,597.0

 

Outside United States and Canada

                     
   

Gas

2

 

0.6

 

5

 

4.1

 

-

 

-

   

Oil

-

 

-

 

-

 

-

 

-

 

-

   

Dry

-

 

-

 

-

 

-

 

-

 

-

   

Total

2

 

0.6

 

5

 

4.1

 

-

 

-

 

Total Development

1,684

 

1,380.5

 

2,040

 

1,793.6

 

1,764

 

1,597.0

Exploratory Wells Completed

                     
 

United States and Canada

                     
   

Gas

61

 

47.0

 

49

 

44.2

 

46

 

28.9

   

Oil

3

 

2.6

 

5

 

3.0

 

5

 

4.2

   

Dry

23

 

17.5

 

41

 

29.2

 

39

 

29.2

   

Total

87

 

67.1

 

95

 

76.4

 

90

 

62.3

 

Outside United States and Canada

                     
   

Gas

-

 

-

 

1

 

1.0

 

2

 

0.6

   

Oil

-

 

-

 

-

 

-

 

-

 

-

   

Dry

3

 

0.7

 

3

 

1.9

 

2

 

1.5

   

Total

3

 

0.7

 

4

 

2.9

 

4

 

2.1

 

Total Exploratory

90

 

67.8

 

99

 

79.3

 

94

 

64.4

   

Total

1,774

 

1,448.3

 

2,139

 

1,872.9

 

1,858

 

1,661.4

Wells in Progress at end of period

160

 

123.9

 

63

 

49.4

 

90

 

79.5

   

Total

1,934

 

1,572.2

 

2,202

 

1,922.3

 

1,948

 

1,740.9

Wells Acquired(1)

                     
   

Gas

37

 

20.4

 

249

 

151.7

 

1,274

 

1,079.0

   

Oil

-

 

-

 

8

 

7.3

 

108

 

68.0

   

Total

37

 

20.4

 

257

 

159.0

 

1,382

 

1,147.0

                           

(1) Includes the acquisition of additional interests in certain wells in which EOG previously owned an interest.

All of EOG's drilling activities are conducted on a contract basis with independent drilling contractors. EOG owns no drilling equipment.

ITEM 3. Legal Proceedings

The information required by this Item is included in this report as set forth in the Contingencies section in Note 7 of Notes to Consolidated Financial Statements on page F-24.

ITEM 4. Submission of Matters to a Vote of Security Holders

There were no matters submitted to a vote of security holders during the fourth quarter of 2005.

19

PART II

ITEM 5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

The following table sets forth, for the periods indicated, the high and low price per share for the common stock of EOG, as reported on the New York Stock Exchange Composite Tape, and the amount of common stock dividend declared per share.

     

Price Range

     
     

High

   

Low

   

Dividend Declared

                   

2005

                 
 

First Quarter

$

48.84

 

$

32.05

 

$

0.04

 

Second Quarter

 

57.94

   

42.40

   

0.04

 

Third Quarter

 

77.00

   

57.18

   

0.04

 

Fourth Quarter

 

82.00

   

59.96

   

0.04

                   

2004(1)

                 
 

First Quarter

$

23.73

 

$

21.23

 

$

0.03

 

Second Quarter

 

31.85

   

22.66

   

0.03

 

Third Quarter

 

33.44

   

27.60

   

0.03

 

Fourth Quarter

 

38.25

   

32.08

   

0.03

                   

(1) Restated for two-for-one stock split effective March 1, 2005, as discussed below.

On February 2, 2005, EOG announced that the Board of Directors had approved a two-for-one stock split in the form of a stock dividend, payable to record holders as of February 15, 2005 and to be issued on March 1, 2005. In addition, the Board increased the quarterly cash dividend on the common stock by 33%, resulting in a quarterly cash dividend of $0.08 per share pre-split, or $0.04 per share post-split.

On February 1, 2006, the Board increased the quarterly cash dividend on the common stock from the previous $0.04 per share to $0.06 per share.

As of February 17, 2006, there were approximately 270 record holders of EOG's common stock, including individual participants in security position listings. There are an estimated 122,000 beneficial owners of EOG's common stock, including shares held in street name.

EOG currently intends to continue to pay quarterly cash dividends on its outstanding shares of common stock. However, the determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, the financial condition, funds from operations, level of exploration, exploitation and development expenditure opportunities and future business prospects of EOG.

The following table sets forth, for the periods indicated, EOG's repurchase activity:






Period


(a)
Total
Number of
Shares
Purchased(1)



(b)
Average
Price Paid
per Share

(c)
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs


(d)
Maximum Number
of Shares that May Yet
Be Purchased Under
the Plans or Programs(2)

         

October 1, 2005 - October 31, 2005

992

$67.84

-

6,386,200

November 1, 2005 - November 30, 2005

-

-

-

6,386,200

December 1, 2005 - December 31, 2005

-

-

-

6,386,200

Total

992

$67.84

   
         

(1) The quarterly total number of shares of 992 consists solely of zero shares (33,079 shares for the full year 2005) that were returned to EOG
     in payment of the exercise price of employee stock options and 992 shares (121,969 shares for the full year 2005) that were withheld by or returned
     to EOG to satisfy tax withholding obligations that arose upon the exercise of employee stock options or the vesting of restricted stock or units.
(2) In September 2001, EOG announced that its Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During
     2005, EOG did not repurchase any shares under the Board authorized repurchase program.

20

ITEM 6. Selected Financial Data
(In Thousands, Except Per Share Data)

Year Ended December 31

 

2005

 

2004

 

2003

 

2002

 

2001

Statement of Income Data:

                   

Net Operating Revenues

$

3,620,213

$

2,271,225

$

1,744,675 

$

1,094,682

$

1,655,722

Operating Income

 

1,991,815

 

979,195

 

697,314 

 

180,977

 

675,387

Net Income Before Cumulative Effect of

                   

   Change in Accounting Principle

 

1,259,576

 

624,855

 

437,276 

 

87,173

 

398,616

Cumulative Effect of Change in Accounting

                   

    Principle, Net of Income Tax(1)

 

-

 

-

 

(7,131)

 

-

 

-

Net Income

 

1,259,576

 

624,855

 

430,145 

 

87,173

 

398,616

Preferred Stock Dividends

 

7,432

 

10,892

 

11,032 

 

11,032

 

10,994

Net Income Available to Common

$

1,252,144

$

613,693

$

419,113 

$

76,141

$

387,622

Net Income Per Share Available to Common(2)

                   
 

Basic

                   
   

Net Income Available to Common

                   
   

   Before Cumulative Effect of Change

                   
   

   in Accounting Principle

$

5.24

$

2.63

$

1.86 

$

0.33

$

1.67

   

Cumulative Effect of Change in

                   
   

   Accounting Principle, Net of

                   
   

   Income Tax(1)

 

-

 

-

 

(0.03)

 

-

 

-

   

Net Income Per Share Available to

                   
   

   Common

$

5.24

$

2.63

$

1.83 

$

0.33

$

1.67

 

Diluted

                   
   

Net Income Available to Common

                   
   

   Before Cumulative Effect of Change

                   
   

   in Accounting Principle

$

5.13

$

2.58

$

1.83 

$

0.32

$

1.65

   

Cumulative Effect of Change in

                   
   

   Accounting Principle, Net of

                   
   

   Income Tax(1)

 

-

 

-

 

(0.03)

 

-

 

-

   

Net Income Per Share Available to

                   
   

   Common

$

5.13

$

2.58

$

1.80 

$

0.32

$

1.65

Dividends Per Common Share(2)

$

0.160

$

0.120

$

0.095 

$

0.080

$

0.078

Average Number of Common Shares(2)

                   
 

Basic

 

238,797

 

233,751

 

229,194 

 

230,669

 

231,530

 

Diluted

 

243,975

 

238,376

 

233,037 

 

234,491

 

234,977

                       

(1) EOG adopted Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. Pro forma net income 
     for 2000 through 2002 is not presented since the pro forma application of SFAS No. 143 to the prior periods would not result in pro forma net income materially different from
     the actual amount reported.
(2) Years 2001 through 2004 restated for two-for-one stock split effective March 1, 2005.

 

At December 31

 

2005

 

2004

 

2003

 

2002

 

2001

Balance Sheet Data:

                   

Net Oil and Gas Properties

$

6,087,179

$

5,101,603

$

4,248,917

$

3,321,548

$

3,055,910

Total Assets

 

7,753,320

 

5,798,923

 

4,749,015

 

3,813,568

 

3,414,044

Current and Long-Term Debt

 

985,067

 

1,077,622

 

1,108,872

 

1,145,132

 

855,969

Shareholders' Equity

 

4,316,292

 

2,945,424

 

2,223,381

 

1,672,395

 

1,642,686

21

ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Overview

EOG Resources, Inc. (EOG) 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 operates under a consistent strategy which focuses predominantly on achieving a strong reinvestment rate of return, drilling internally generated prospects, delivering long-term production growth and maintaining a strong balance sheet.

Net income available to common for 2005 of $1,252 million was up 104% compared to 2004 net income available to common of $614 million, attributable primarily to higher commodity prices and increased production. At December 31, 2005, EOG's total reserves were 6.2 trillion cubic feet equivalent, an increase of 548 billion cubic feet equivalent (Bcfe) from December 31, 2004.

Operations

Several important developments have occurred since January 1, 2005.

United States and Canada. The Fort Worth, Texas office was opened in 2004 to expand on EOG's drilling success in the Barnett Shale play of the Fort Worth Basin. EOG has successfully expanded the play beyond its conventional limits by using horizontal drilling and enhanced completion technology. By year-end 2005, EOG had over 500,000 acres under lease in several counties. EOG plans on substantially increasing its drilling program in 2006.

EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG plans to continue to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas production. EOG has several larger potential plays under way in Wyoming, Utah, Texas, Oklahoma and western Canada.

International. During 2005, EOG commenced natural gas production in Trinidad to supply two new long-term contracts. First, EOG is supplying natural gas that is being used as feedstock for the M5000 methanol plant which commenced operations in September 2005. Second, the Atlantic LNG Train 4 (ALNG) began taking gas in December 2005, prior to commercial operations, and volumes supplied by EOG during this pre-start up period have been higher than EOG's contractual rate.

Although EOG continues to focus on United States and Canada natural gas, EOG sees an increasing linkage between United States and Canada natural gas demand and Trinidad natural gas supply. For example, liquefied natural gas (LNG) imports from existing and planned facilities in Trinidad are serious contenders to meet increasing United States demand. In addition, ammonia, methanol and chemical production has been relocating from the United States and Canada to Trinidad, driven by attractive natural gas feedstock prices in the island nation. EOG believes that its existing position with the supply contracts to the two ammonia plants, the new methanol plant and the ALNG, will continue to give its portfolio an even broader exposure to United States and Canada natural gas fundamentals.

In 2005, EOG continued its progress in the Southern Gas Basin of the United Kingdom North Sea. Production commenced in January 2005 from the Arthur 1 well and in July 2005 from the Arthur 2 well. The Arthur 3 well is expected to spud in the first half of 2006. EOG expects only modest activity in 2006 due to the difficulty in obtaining rigs in the North Sea.

22

Capital Structure

As noted, one of management's key strategies is to keep a strong balance sheet with a consistently below average debt-to-total capitalization ratio. At December 31, 2005, EOG's debt-to-total capitalization ratio was 19%, down from 27% at year-end 2004. By primarily utilizing cash provided from its operating activities and proceeds from stock options exercised in 2005, EOG funded its $1,858 million exploration and development expenditures, paid down $93 million of debt and paid dividends to common shareholders of $36 million. In addition, in 2006, EOG's Board of Directors increased the cash dividend on common stock to an annual rate of $0.24 per share, which represents a 50% increase in the annual cash dividend. As management currently assesses price forecast and demand trends for 2006, EOG believes that operations and capital expenditure activity can essentially be funded by cash from operations.

For 2006, EOG's estimated exploration and development expenditure budget is approximately $2.5 billion, excluding acquisitions. United States and Canada natural gas continues to be a key component of this effort. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management believes that EOG continues to maintain one of the strongest prospect inventories in EOG's history.

The following review of operations for each of the three years in the period ended December 31, 2005 should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning with page F-1.

23

Results of Operations

Net Operating Revenues

During 2005, net operating revenues increased $1,349 million to $3,620 million from $2,271 million in 2004. Total wellhead revenues, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, increased $1,306 million, or 57%, to $3,607 million as compared to $2,301 million in 2004. Natural gas, crude oil, condensate and natural gas liquids revenues solely represent wellhead revenues for these products. Wellhead volume and price statistics for the years ended December 31, were as follows:

       

2005

 

2004

 

2003

Natural Gas Volumes (MMcfd) (1)

           
 

United States

 

718

 

631

 

638

 

Canada

 

228

 

212

 

165

 

Trinidad

 

231

 

186

 

152

 

United Kingdom

 

39

 

7

 

-

   

Total

 

1,216

 

1,036

 

955

                 

Average Natural Gas Prices ($/Mcf) (2)

           
 

United States

$

7.86

$

5.72

$

5.06

 

Canada

 

7.14

 

5.22

 

4.66

 

Trinidad

 

2.20

(3)

1.51

 

1.35

 

United Kingdom

 

6.99

 

5.14

 

-

   

Composite

 

6.62

 

4.86

 

4.40

                 

Crude Oil and Condensate Volumes (MBbld) (1)

           
 

United States

 

21.5

 

21.1

 

18.5

 

Canada

 

2.4

 

2.7

 

2.3

 

Trinidad

 

4.5

 

3.6

 

2.4

 

United Kingdom

 

0.2

 

-

 

-

   

Total

 

28.6

 

27.4

 

23.2

                 

Average Crude Oil and Condensate Prices ($/Bbl) (2)

           
 

United States

$

54.57

$

40.73

$

30.24

 

Canada

 

50.49

 

37.68

 

28.54

 

Trinidad

 

57.36

 

39.12

 

28.88

 

United Kingdom

 

49.62

 

-

 

-

   

Composite

 

54.63

 

40.22

 

29.92

                 

Natural Gas Liquids Volumes (MBbld) (1)

           
 

United States

 

6.6

 

4.8

 

3.2

 

Canada

 

0.9

 

0.8

 

0.6

   

Total

 

7.5

 

5.6

 

3.8

                 

Average Natural Gas Liquids Prices ($/Bbl) (2)

           
 

United States

$

35.59

$

27.79

$

21.53

 

Canada

 

35.59

 

23.23

 

19.13

   

Composite

 

35.59

 

27.13

 

21.13

                 

Natural Gas Equivalent Volumes (MMcfed) (4)

           
 

United States

 

886

 

786

 

768

 

Canada

 

248

 

233

 

183

 

Trinidad

 

259

 

207

 

166

 

United Kingdom

 

40

 

7

 

-

   

Total

 

1,433

 

1,233

 

1,117

                 

Total Bcfe (4) Deliveries

 

523.0

 

451.5

 

407.8

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Includes $0.23 per Mcf as a result of a revenue adjustment related to an amended Trinidad take-or-pay contract.
(4) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids.

24

2005 compared to 2004. Wellhead natural gas revenues for 2005 increased $1,097 million, or 60%, to $2,939 million from $1,842 million for 2004 due to a higher composite average wellhead natural gas price ($763 million), increased natural gas deliveries ($315 million) and a second quarter 2005 revenue adjustment related to an amended Trinidad take-or-pay contract ($19 million). The composite average wellhead natural gas price increased 36% to $6.62 per Mcf for 2005 from $4.86 per Mcf in 2004. Excluding the aforementioned adjustment, the composite average wellhead natural gas price increased 35% to $6.58 per Mcf for 2005. This adjustment increased the average Trinidad wellhead natural gas price by $0.23 per Mcf for 2005.

Natural gas deliveries increased 180 MMcfd, or 17%, to 1,216 MMcfd for 2005 from 1,036 MMcfd in 2004. The increase was due to higher production of 87 MMcfd in the United States, 45 MMcfd in Trinidad, 32 MMcfd in the United Kingdom and 16 MMcfd in Canada. The increase in the United States was primarily attributable to increased production from Texas (63 MMcfd) and Louisiana (20 MMcfd). The increase in Trinidad was due to the increased contractual requirements and demand related to the ammonia and methanol plants. The increase in the United Kingdom was due to the commencement of production from the Arthur field in January 2005 (24 MMcfd) and the full year production from the Valkyrie field, which commenced production in August 2004 (8 MMcfd). The increase in Canada was attributable to the drilling program, primarily in the Wapiti, Drumheller and Connorsville areas.

Wellhead crude oil and condensate revenues increased $168 million, or 42%, to $571 million from $403 million as compared to 2004, due to increases in both the composite average wellhead crude oil and condensate price ($151 million) and the wellhead crude oil and condensate deliveries ($17 million). The composite average wellhead crude oil and condensate price for 2005 was $54.63 per barrel compared to $40.22 per barrel for 2004.

Natural gas liquids revenues increased $42 million, or 76%, to $97 million from $55 million as compared to 2004, due to increases in the composite average price ($23 million) and deliveries ($19 million).

During 2005, EOG recognized gains on mark-to-market financial commodity derivative contracts of $10 million, which included realized gains of $10 million. During 2004, EOG recognized losses on mark-to-market financial commodity derivative contracts of $33 million, which included realized losses of $82 million and collar premium payments of $1 million.

2004 compared to 2003. Wellhead natural gas revenues for 2004 increased $307 million, or 20%, to $1,842 million from $1,535 million for 2003 due to increases in natural gas deliveries ($134 million) and the composite average wellhead natural gas price ($173 million). The composite average wellhead natural gas price increased 10% to $4.86 per Mcf for 2004 from $4.40 per Mcf in 2003.

Natural gas deliveries increased 81 MMcfd, or 8%, to 1,036 MMcfd for 2004 from 955 MMcfd in 2003, due to a 47 MMcfd, or 28%, increase in Canada; a 34 MMcfd, or 22%, increase in Trinidad; and a 7 MMcfd increase in the United Kingdom due to commencement of production in August 2004, partially offset by a 7 MMcfd, or 1% decline in the United States. The increased deliveries in Canada (47 MMcfd) were attributable to property acquisitions completed in the fourth quarter of 2003 and additional production related to post acquisition drilling. The increase in Trinidad was attributable to the increased production from the U(a) Block (22 MMcfd) which began supplying natural gas in mid-2004 to the N2000 ammonia plant and commencement of production from the Parula wells on the SECC Block in February 2004 (12 MMcfd).

Wellhead crude oil and condensate revenues increased $149 million, or 59%, to $403 million from $254 million as compared to 2003, due to increases in both the composite average wellhead crude oil and condensate price ($103 million) and the wellhead crude oil and condensate deliveries ($46 million). The composite average wellhead crude oil and condensate price for 2004 was $40.22 per barrel compared to $29.92 per barrel for 2003.

Wellhead crude oil and condensate deliveries increased 4.2 MBbld, or 18%, to 27.4 MBbld from 23.2 MBbld for 2003. The increase was mainly due to production from new wells in the United States (2.6 MBbld) and higher production in Trinidad from the Parula wells (0.8 MBbld) and from the U(a) Block as a result of new production (0.4 MBbld).

Natural gas liquids revenues were $26 million higher than a year ago primarily due to increases in deliveries ($14 million) and the composite average price ($12 million).

25

During 2004, EOG recognized losses on mark-to-market commodity derivative contracts of $33 million, which included realized losses of $82 million and collar premium payments of $1 million. During 2003, EOG recognized losses on mark-to-market commodity derivative contracts of $80 million, which included realized losses of $45 million and collar premium payments of $3 million.

Operating and Other Expenses

2005 compared to 2004. During 2005, operating expenses of $1,628 million were $336 million higher than the $1,292 million incurred in 2004. The following table presents the costs per Mcfe for the years ended December 31:

 

2005

2004

Lease and Well, including Transportation

$0.71

$0.60

Depreciation, Depletion and Amortization (DD&A)

1.25

1.12

General and Administrative (G&A)

0.24

0.25

Taxes Other Than Income

0.38

0.30

Interest Expense, Net

0.12

0.14

 

Total Per-Unit Costs (1)

$2.70

$2.41

(1) Total per-unit costs do not include exploration costs, dry hole costs and impairments.

The per-unit costs of lease and well, including transportation, DD&A, taxes other than income and interest expense, net for 2005 compared to 2004 were due primarily to the reasons set forth below.

Lease and well expense includes expenses for EOG operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expense can be divided into the following categories: costs to operate and maintain EOG's oil and natural gas wells, the cost of workovers, transportation costs associated with selling hydrocarbon products and lease and well administrative expenses. Operating and maintenance expenses include, among other service costs, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep, fuel and power. Workovers are costs to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses, including transportation, of $373 million were $102 million higher than 2004 due primarily to higher operating and maintenance expenses in the United States ($40 million); increased transportation related costs in the United States ($28 million) and the United Kingdom ($7 million); higher lease and well administrative expenses in the United States ($11 million); changes in the Canadian exchange rate ($6 million); and higher workover expenditures in the United States ($3 million) and Trinidad ($2 million).

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact an individual field, such as the field production profile; drilling or acquisition of new wells; disposition of existing wells; reserve revisions (upward or downward), primarily related to well performance; and impairments. Changes to the individual fields, due to any of these factors, may cause EOG's composite DD&A rate and expense to fluctuate from year to year.

DD&A expenses of $654 million were $150 million higher than 2004 primarily as a result of increased production in the United States ($46 million), Canada ($6 million) and Trinidad ($5 million) and the commencement of production in the United Kingdom ($14 million). DD&A rates increased in the United States due to a gradual proportional increase in production from higher cost properties ($59 million) and in Canada predominantly from the development of acquired proved reserves ($9 million). The Canadian exchange rate also contributed to the DD&A expense increase ($8 million).

26

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Taxes other than income of $199 million were $65 million higher than 2004.

Severance/production taxes increased due primarily to increased wellhead revenues in the United States ($41 million), Trinidad ($7 million) and Canada ($3 million), partially offset by the increase in credits taken for a Texas high cost gas severance tax exemption ($10 million) and a production tax audit lawsuit in the first quarter of 2004 ($5 million). Other items contributing to the increase were an additional Trinidadian Supplemental Petroleum Tax expense as a result of 2005 tax legislation that increased the tax expense retroactively to January 2004 ($7 million) and 2004 production tax relief in Trinidad ($6 million). Ad valorem/property taxes increased primarily due to higher property valuation in the United States ($11 million).

Net interest expense in 2005 included costs associated with the early retirement of 2008 Notes ($8 million) (see Note 2 to Consolidated Financial Statements). Excluding these early retirement costs, the 2005 net interest expense decreased $8 million compared to 2004 primarily due to higher capitalized interest ($5 million), an interest charge related to the results of a production tax audit lawsuit in the first quarter of 2004 ($2 million) and lower average debt balance in the United States ($1 million).

Exploration costs of $133 million were $39 million higher than 2004 due primarily to increased geological and geophysical expenditures in the Barnett Shale area.

Impairments include amortization of unproved leases, as well as impairments under the Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $78 million were $4 million lower than 2004 due primarily to lower amortization of unproved leases in the United States ($12 million) and lower impairments to the carrying value of certain long-lived assets in Canada ($8 million), partially offset by higher impairments to the carrying value of certain long-lived assets in the United States ($14 million) and higher amortization of unproved leases in Canada ($2 million). EOG recorded impairments of $31 million and $25 million for 2005 and 2004, respectively, under SFAS No. 144 for certain properties in the United States and Canada.

Other income, net of $36 million increased $26 million compared to 2004 primarily as a result of higher gains on sales of properties ($7 million), interest income ($6 million) and equity income from investments in the Caribbean Nitrogen Company Limited (CNCL) and Nitrogen (2000) Unlimited (N2000) ammonia plants in 2005 ($5 million); decreased net foreign currency transaction losses ($4 million); and a gain on the sale of part of EOG's interest in the N2000 ammonia plant in the first quarter of 2005 ($2 million).

Income tax provision of $706 million increased $404 million as compared to 2004, due primarily to higher pre-tax income ($383 million) and income taxes associated with the repatriation of foreign earnings ($24 million). The effective tax rate for 2005 increased to 36% from 33% in 2004.

2004 compared to 2003. During 2004, operating expenses of $1,292 million were $245 million higher than the $1,047 million incurred in 2003. The following table presents the costs per Mcfe for the years ended December 31:

  2004 2003

Lease and Well, including Transportation

$0.60

$0.52

DD&A

1.12

1.08

G&A

0.25

0.25

Taxes Other Than Income

0.30

0.21

Interest Expense, Net

0.14

0.14

 

Total Per-Unit Costs

$2.41

$2.20

The higher per-unit costs of lease and well, including transportation, DD&A and taxes other than income for 2004 compared to 2003 were due primarily to the reasons set forth below.

27

Lease and well expenses, including transportation, of $271 million were $58 million higher than 2003 due primarily to a general increase in service costs related to increased operating activities, including an increase in the number of wells, in the United States ($18 million), Canada ($16 million), and Trinidad ($1 million); increased transportation related costs in the United States ($14 million), Canada ($2 million) and the United Kingdom ($2 million); and changes in the Canadian exchange rate ($5 million).

DD&A expenses of $504 million increased $63 million from 2003 due primarily to increased production in Canada ($18 million), the United States ($10 million), and Trinidad ($4 million); the commencement of production in the United Kingdom ($2 million); increased DD&A rates in the United States due to a gradual proportional increase in production from higher cost properties ($13 million); increased DD&A rates in Canada mainly from developing acquired proved reserves ($8 million); and changes in the Canadian exchange rate ($7 million).

G&A expenses of $115 million were $15 million higher than 2003 due primarily to expanded operations.

Taxes other than income of $134 million were $48 million higher than 2003 due primarily to a decrease in credits taken against severance taxes resulting from the qualification of additional wells for a Texas high cost gas severance tax exemption ($19 million); an increase as a result of higher wellhead revenues in the United States ($13 million), Trinidad ($2 million) and Canada ($1 million); higher property taxes as a result of higher property valuation in the United States ($6 million); the results of a production tax audit lawsuit in the first quarter of 2004 ($5 million); and an increase in the number of wells and facilities in Canada ($2 million).

Exploration costs of $94 million were $18 million higher than 2003 due primarily to increased geological and geophysical expenditures in the United States ($6 million), Canada ($3 million), the United Kingdom ($3 million) and Trinidad ($1 million); and increased exploration administrative expenses across EOG ($4 million).

Impairments of $82 million were $8 million lower than 2003 due primarily to lower amortization of unproved leases in the United States ($10 million), partially offset by higher amortization of unproved leases in Canada ($2 million). Total impairments under SFAS No. 144 were $25 million in each of 2004 and 2003.

Net interest expense of $63 million was $4 million higher than 2003 due primarily to a slightly higher average debt balance.

Other income (expense), net for 2004 included income from equity investments of $11 million, gains on sales of reserves and related assets of $6 million and foreign currency transaction losses of $7 million as a result of applying the changes in the Canadian exchange rate to certain intercompany short-term loans that eliminate in consolidation.

Income tax provision increased $85 million to $301 million compared to 2003, primarily resulting from higher income before income taxes ($95 million), offset by lower deferred income taxes associated with the Alberta, Canada corporate tax rate ($5 million) and lower effective foreign income tax rates ($2 million). The net effective tax rate for 2004 remained unchanged from the 2003 rate of 33%.

In November 2003, Canada enacted legislation reducing the Canadian federal income tax rate for companies in the resource sector from 28% to 27% for 2003, with further reductions to 21% phased in over the next four years. This legislation also made changes to the tax treatment of crown royalties and the resource allowance. Beginning in 2003, Canadian taxpayers are allowed to deduct 10% of actual provincial and other crown royalties. This percentage increases each year through 2007, at which time 100% of crown royalties will be deductible. The resource allowance, a statutory deduction calculated as 25% of adjusted resource profits, will be phased out through 2007, when the deduction will be completely eliminated.

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2005 included funds generated from operations, funds from new borrowings, proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan, proceeds from the sale of oil and gas properties and proceeds from sales of partial interests in certain equity investments in Trinidad. Primary cash outflows included funds used in operations, exploration and development expenditures, oil and gas property acquisitions, repayment of debt, dividend payments to shareholders, redemption of preferred stock and common stock repurchases.

28

2005 compared to 2004. Net cash provided by operating activities of $2,369 million in 2005 increased $925 million as compared to 2004 primarily reflecting an increase in wellhead revenues ($1,306 million), a favorable change in the net cash flows from settlement of financial commodity derivative contracts ($93 million) and favorable changes in working capital and other liabilities ($35 million), partially offset by an increase in cash operating expenses ($217 million) and an increase in cash paid for income taxes ($279 million).

Net cash used in investing activities of $1,678 million in 2005 increased by $281 million as compared to 2004 due primarily to increased additions to oil and gas properties ($308 million) and unfavorable changes in working capital related to investing activities ($28 million), partially offset by an increase in proceeds from the sale of oil and gas properties in 2005 ($40 million) and the sale of part of EOG's interest in the N2000 ammonia plant in 2005 ($18 million). Changes in Components of Working Capital Associated with Investing Activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent material and equipment used in drilling and related activities.

Cash used in financing activities of $72 million in 2005 increased $29 million as compared to 2004. Cash provided by financing activities for 2005 included a long-term debt borrowing ($250 million) and proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan ($65 million). Cash used by financing activities for 2005 included repayments of long-term debt borrowings ($343 million) and cash dividend payments ($43 million).

2004 compared to 2003. Net cash provided by operating activities of $1,444 million in 2004 increased $195 million as compared to 2003 primarily reflecting an increase in wellhead revenues of $482 million, partially offset by an increase in cash operating expenses of $139 million, an increase in current tax expense of $72 million, unfavorable changes in working capital and other liabilities of $48 million and an increase in realized losses from mark-to-market commodity derivative contracts of $38 million.

Net cash used in investing activities of $1,397 million in 2004 increased by $189 million as compared to 2003 due primarily to increased additions to oil and gas properties of $171 million and unfavorable changes in working capital related to investing activities of $12 million. Changes in Components of Working Capital Associated with Investing Activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent material and equipment used in drilling and related activities.

Cash used in financing activities was $43 million in 2004 versus $57 million in 2003. Cash provided by financing activities for 2004 included long-term debt borrowing of $150 million and proceeds from sales of treasury stock attributable to employee stock option exercises and the employee stock purchase plan of $76 million. Cash used by financing activities for 2004 included repayments of long-term debt borrowings of $175 million, redemption of all 500 outstanding shares of Series D Preferred Stock of $50 million and cash dividend payments of $38 million.

29

Total Exploration and Development Expenditures

The table below sets out components of total exploration and development expenditures for the years ended December 31, 2005, 2004 and 2003, along with the total budgeted for 2006, excluding acquisitions (in millions):

 

Actual

 

Budgeted 2006

   

2005

 

2004

 

2003

 

(excluding acquisitions)

Expenditure Category

               

Capital

               
 

Drilling and Facilities

$

1,458

$

1,120 

$

731

   
 

Leasehold Acquisitions

 

131

 

143 

 

59

   
 

Producing Property Acquisitions

 

56

 

52 

 

405

   
 

Capitalized Interest

 

15

 

10 

 

9

   
   

Subtotal

 

1,660

 

1,325 

 

1,204

   

Exploration Costs

 

133

 

94 

 

76

   

Dry Hole Costs

 

65

 

92 

 

41

   
 

Exploration and Development Expenditures

 

1,858

 

1,511 

 

1,321

 

Approximately $2,500

Asset Retirement Costs

 

20

 

16 

 

12

(1)

 

Deferred Income Tax on Acquired Properties

 

-

 

(17)

 

-

   
   

Total Exploration and Development

               
   

Expenditures

$

1,878

$

1,510

$

1,333

   

(1) Asset Retirement Costs for 2003 does not include the cumulative effect of adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003.

Exploration and development expenditures of $1,858 million for 2005 were $347 million higher than the prior year due primarily to (i) increased drilling and facilities expenditures of $338 million resulting from higher drilling and facilities expenditures in the United States ($377 million) and changes in the Canadian exchange rate related to drilling and facilities expenditures ($17 million), partially offset by decreased drilling and facilities expenditures in the United Kingdom ($24 million), Trinidad ($21 million) and Canada ($11 million) and; (ii) increased exploration costs ($39 million) primarily in the Barnett Shale area; partially offset by decreased dry hole costs ($27 million). The 2005 exploration and development expenditures of $1,858 million includes $1,300 million in development, $487 million in exploration, $56 million in property acquisitions and $15 million in capitalized interest. The 2004 exploration and development expenditures of $1,511 million includes $1,009 million in development, $440 million in exploration, $52 million in property acquisitions and $10 million in capitalized interest. The 2003 exploration and development expenditures of $1,321 million included $651 million in development, $256 million in exploration, $405 million in property acquisitions and $9 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. There are no material continuing commitments associated with current expenditure plans.

30

Derivative Transactions

During 2005, EOG recognized gains on mark-to-market financial commodity derivative contracts of $10 million, which included realized gains of $10 million. During 2004, EOG recognized losses on mark-to-market financial commodity derivative contracts of $33 million, which included realized losses of $82 million and collar premium payments of $1 million. (See Note 11 to Consolidated Financial Statements.)

Presented below is a summary of EOG's 2006 natural gas financial collar and price swap contracts at February 22, 2006, with prices expressed in dollars per million British thermal units ($/MMBtu) and notional volumes in million British thermal units per day (MMBtud). As indicated, EOG does not have any financial collar or price swap contracts that cover periods beyond October 2006. As of February 22, 2006, EOG had no crude oil hedges. EOG accounts for these collar and price swap contracts using mark-to-market accounting.

Natural Gas Financial Contracts

 

Collar Contracts

 

Price Swap Contracts

   

Floor Price

 

Ceiling Price

     
     

Weighted

   

Weighted

   

Weighted

     

Average

 

Ceiling

Average

   

Average

 

Volume

Floor Range

Price

 

Range

Price

 

Volume

Price

Month

(MMBtud)

($/MMBtu)

($/MMBtu)

 

($/MMBtu)

($/MMBtu)

 

(MMBtud)

($/MMBtu)

                   

February (closed)

50,000

$13.65 - 14.50

$14.05

 

$16.20 - 17.04

$16.59

 

-

-

March

50,000

13.50 - 14.30

13.87

 

15.95 - 17.05

16.46

 

170,000

$9.54

April

50,000

10.00 - 10.50

10.23

 

12.60 - 13.00

12.77

 

180,000

9.49

May

50,000

9.75 - 10.00

9.87

 

12.15 - 12.60

12.31

 

180,000

9.50

June

50,000

9.75 - 10.00

9.87

 

12.20 - 12.60

12.34

 

180,000

9.54

July

50,000

9.75 - 10.00

9.87

 

12.35 - 12.85

12.50

 

190,000

9.57

August

50,000

9.75 - 10.00

9.87

 

12.50 - 13.00

12.67

 

190,000

9.63

September

-

-

-

 

-

-

 

140,000

9.40

October

-

-

-

 

-

-

 

90,000

9.46

Financing

EOG's debt-to-total capitalization ratio was 19% as of December 31, 2005 compared to 27% as of December 31, 2004.

During 2005, total debt decreased $93 million to $985 million (see Note 2 to Consolidated Financial Statements). The estimated fair value of EOG's debt at December 31, 2005 and 2004 was $1,025 million and $1,146 million, respectively. The estimated fair value was based upon quoted market prices and, where such prices were not available, upon interest rates currently available to EOG at year-end. EOG's debt is primarily at fixed interest rates. At December 31, 2005, a 1% decline in interest rates would result in a $46 million increase in the estimated fair value of the fixed rate obligations (see Note 11 to Consolidated Financial Statements).

During 2005 and 2004, EOG utilized cash provided by operating activities and commercial paper to fund its operations. While EOG maintains a $600 million commercial paper program, the maximum outstanding at any time during 2005 was $380 million, and the amount outstanding at year-end was zero. EOG considers this excess availability, which is backed by the $600 million Revolving Credit Agreement with domestic and foreign lenders described in Note 2 to Consolidated Financial Statements, combined with approximately $688 million of availability under its shelf registration described below, to be ample to meet its ongoing operating needs.

In 2005, the short-term commercial paper loan balance was reduced by $92 million; the $174 million, 6.00% Notes due 2008 and the remaining $75 million outstanding under the Senior Unsecured Term Loan Facility were repaid primarily with cash generated from operating activities. On February 17, 2006, a foreign subsidiary of EOG repaid $50 million of the $250 million it borrowed in 2005 (see Note 2 to Consolidated Financial Statements). During 2006, based on resources available at December 31, 2005, EOG plans to pay off the $126 million, 6.70% Notes due 2006.

31

Contractual Obligations

The following table summarizes EOG's contractual obligations at December 31, 2005 (in thousands):

                   

2012 &

Contractual Obligations (1)

 

Total

 

2006

 

2007 - 2009

 

2010 - 2011

 

Beyond

Current and Long-Term Debt

$

985,067

$

126,075

$

348,992

$

220,000

$

290,000

Non-cancelable Operating Leases

 

84,536

 

40,440

 

26,934

 

8,073

 

9,089

Interest Payments on Current

                   

   and Long-Term Debt

 

420,466

 

58,944

 

126,424

 

63,670

 

171,428

Pipeline Transportation Service

                   

   Commitments (2)

 

273,185

 

40,752

 

93,065

 

59,081

 

80,287

Drilling Rig Commitments

 

182,955

 

75,624

 

107,331

 

-

 

-

Seismic Purchase Obligations

 

3,479

 

3,479

 

-

 

-

 

-

Other Purchase Obligations

 

7,072

 

5,837

 

1,235

 

-

 

-

 

Total Contractual Obligations

$

1,956,760

$

351,151

$

703,981

$

350,824

$

550,804

(1) This table does not include the liability for dismantlement, abandonment and restoration costs of oil and gas properties. Effective with adoption of
     SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003, EOG recorded a separate liability for the fair value of this
     asset retirement obligation (see Note 13 to Consolidated Financial Statements). In addition, this table does not include EOG's pension or postretirement
     benefit obligations (see Note 6 to Consolidated Financial Statements).
(2) Amounts shown are based on current pipeline transportation rates and the foreign currency exchange rates used to convert Canadian Dollars and British
     Pounds into United States Dollars at December 31, 2005. Management does not believe that any future changes in these rates before the expiration dates
     of these commitments will have a material adverse effect on the financial condition or results of operations of EOG.

Shelf Registration

As of February 22, 2006, the amount available under various filed registration statements with the Securities and Exchange Commission for the offer and sale from time to time of EOG debt securities, preferred stock and/or common stock totaled approximately $688 million.

Off-Balance Sheet Arrangements

EOG does not participate in financial transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities, often referred to as variable interest entities (VIE) or special purpose entities (SPE), are generally established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. EOG was not involved in any unconsolidated VIE or SPE financial transactions during any of the reporting periods in this document and has no intention to participate in such transactions in the foreseeable future.

Foreign Currency Exchange Rate Risk

During 2005, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Canada, Trinidad and the United Kingdom. The foreign currency most significant to EOG's operations during 2005 was the Canadian Dollar. The continued strengthening of the Canadian Dollar in 2005 impacted both the revenues and expenses of EOG's Canadian subsidiaries. However, since the Canadian natural gas prices are largely correlated to United States prices, the changes in the Canadian currency exchange rate have less of an impact on the Canadian revenues than the Canadian expenses. EOG continues to monitor the foreign currency exchange rates of countries in which it is currently conducting business and may implement measures to protect against the foreign currency exchange rate risk.

32

Effective March 9, 2004, EOG entered into a foreign currency swap transaction with multiple banks to eliminate any exchange rate impacts that may result from the notes offered by one of the Canadian subsidiaries on the same date (see Note 2 to Consolidated Financial Statements). EOG accounts for the foreign currency swap transaction using the hedge accounting method, pursuant to the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137, 138 and 149. Under those provisions, as of December 31, 2005, EOG recorded the fair value of the swap of $36 million in Other Liabilities on the Consolidated Balance Sheets. Changes in the fair value of the foreign currency swap resulted in no net impact to Net Income Available to Common on the Consolidated Statements of Income and Comprehensive Income. The after-tax net impact from the foreign currency swap transaction resulted in a negative change of $5 million for the year ended December 31, 2005. This amount is included in Accumulated Other Comprehensive Income in the Shareholders' Equity section of the Consolidated Balance Sheets.

Outlook

Natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of future United States and Canada natural gas and crude oil price trends, and there remains a rather wide divergence in the opinions held by some in the industry. In EOG's opinion, overall natural gas production in the United States is declining. In addition, the increasing recognition of natural gas as a more environmentally friendly source of energy is likely to result in increases in demand. Being primarily a natural gas producer, EOG is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. Longer term natural gas prices will be determined by the supply and demand for natural gas as well as the prices of competing fuels, such as oil and coal.

Assuming a totally unhedged position for 2006, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2006 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf change in average wellhead natural gas price is approximately $24 million for net income and operating cash flow. EOG is not impacted as significantly by changing crude oil price. EOG's price sensitivity in 2006 for each $1.00 per barrel change in average wellhead crude oil prices is approximately $6 million for net income and operating cash flow. For information regarding EOG's natural gas hedge position as of December 31, 2005, see Note 11 to Consolidated Financial Statements.

Marketing companies have played an important role in the United States and Canada natural gas market. These companies aggregate natural gas supplies through purchases from producers like EOG and then resell the gas to end users, local distribution companies or other buyers. In recent years, several of the largest natural gas marketing companies have filed for bankruptcy or are having financial difficulty, and others are exiting this business. EOG does not believe that this will have a material effect on its ability to market its natural gas production. EOG continues to assess and monitor the creditworthiness of partners to whom it sells its production and where appropriate, to seek new markets.

EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in the United States and Canada. However, in order to diversify its overall asset portfolio and as a result of its overall success realized in Trinidad and the United Kingdom North Sea, EOG anticipates expending a portion of its available funds in the further development of opportunities outside the United States and Canada. In addition, EOG expects to conduct exploratory activity in other areas outside of the United States and Canada and will continue to evaluate the potential for involvement in other exploitation type opportunities. Budgeted 2006 exploration and development expenditures, excluding acquisitions, are approximately $2.5 billion and are structured to maintain the flexibility necessary under EOG's strategy of funding the United States and Canada exploration, exploitation, development and acquisition activities primarily from available internally generated cash flow.

The level of exploration and development expenditures may vary in 2006 and will vary in future periods depending on energy market conditions and other related economic factors. Based upon existing economic and market conditions, EOG believes net operating cash flow and available financing alternatives in 2006 will be sufficient to fund its net investing cash requirements for the year. However, EOG has significant flexibility with respect to its financing alternatives and adjustment of its exploration, exploitation, development and acquisition expenditure plans if circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to operations in the United States, Canada, Trinidad and the United Kingdom, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

33

Environmental Regulations

Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to protection of the environment, affect EOG's operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations and could cause EOG to incur remediation or other corrective action costs in connection with a release of regulated substances, including crude oil, into the environment. In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, EOG could be responsible under environmental laws and regulations for oil and gas properties in which EOG owns an interest but is not the operator. Compliance with such laws and regulations increases EOG's overall cost of business, but has not had a material adverse effect on EOG's operations or financial condition. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program in order to comply with environmental laws and regulations but, inasmuch as such laws and regulations are frequently changed, EOG is unable to predict the ultimate cost of compliance. EOG also could incur costs related to the clean up of sites to which it sent regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such sites.

Summary of Critical Accounting Policies

EOG prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States of America, which requires management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. EOG identifies certain accounting policies as critical based on, among other things, their impact on the portrayal of EOG's financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Following is a discussion of EOG's most critical accounting policies:

Proved Oil and Gas Reserves

EOG's engineers estimate proved oil and gas reserves, which directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.

Oil and Gas Exploration Costs

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. Exploratory drilling costs are capitalized when drilling is complete if it is determined that there is economic producibility supported by either actual production, a conclusive formation test or by certain technical data if the discovery is located offshore in the Gulf of Mexico. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. All other exploratory wells that do not meet these criteria are expensed after one year. As of December 31, 2005 and 2004, EOG had exploratory drilling costs related to two projects that have been deferred for more than one year (see Note 16 to Consolidated Financial Statements). These costs meet the accounting requirements outlined above for continued capitalization. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and crude oil, are capitalized.

34

Impairments

Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.

When circumstances indicate that an asset may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

Depreciation, Depletion and Amortization for Oil and Gas Properties

The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.

Assets are grouped in accordance with paragraph 30 of SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions, and 4) impairments.

Stock Options

EOG accounted for stock options under the provisions and related interpretations of Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." No compensation expense was recognized for such options. As allowed by SFAS No. 123, "Accounting for Stock-Based Compensation" issued in 1995, EOG continued to apply APB Opinion No. 25 for purposes of determining net income and to present the pro forma disclosures required by SFAS No. 123.

35

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), "Share-Based Payment," which supersedes SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123." SFAS No. 123(R) establishes standards for transactions in which an entity exchanges its equity instruments for goods or services. This standard requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. This eliminates the exception to account for such awards using the intrinsic method previously allowable under APB Opinion No. 25. SFAS No. 123(R) is effective for annual reporting periods beginning on or after June 15, 2005. EOG adopted SFAS No. 123(R) effective January 1, 2006 using the modified prospective method. EOG expects this will reduce 2006 net earnings by a pre-tax amount of approximately $25 million, taking into consideration the estimated forfeitures and cancellations. This amount includes approximately $21 million of expense for unvested options outstanding at December 31, 2005 and approximately $1 million of expense for the Employee Stock Purchase Plan. SFAS No. 123(R) also requires a public entity to present its cash flows provided by tax benefits from stock options exercised in the Financing Cash Flows section of the Statement of Cash Flows. Had SFAS No. 123(R) been in effect, EOG's Net Cash Provided by Operating Activities would have been reduced and its Net Cash Provided by Financing Activities would have been increased on its Consolidated Statements of Cash Flows by $51 million, $29 million and $12 million for 2005, 2004 and 2003, respectively.

 

Information Regarding Forward-Looking Statements

This Annual Report on Form 10-K 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.

36

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

EOG's exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk is discussed in the Derivative Transactions, Financing, Foreign Currency Exchange Rate Risk and Outlook sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity."

ITEM 8. Financial Statements and Supplementary Data

Information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page F-1.

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

ITEM 9A. Controls and Procedures

Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this report (Evaluation Date). Based on this evaluation, the principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date to ensure that information that is required to be disclosed by EOG in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to EOG's management as appropriate to allow timely decisions regarding required disclosure.

Management's Report on Internal Control over Financial Reporting. EOG's management is responsible for establishing and maintaining effective internal control over financial reporting (as defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Exchange Act). Even an effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of an internal control system in future periods can change with conditions.

EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2005. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management believes that, as of December 31, 2005, EOG's internal control over financial reporting is effective based on those criteria. EOG's assessment also appears on page F-2.

EOG's independent registered public accounting firm has issued an audit report on EOG's assessment of its internal control over financial reporting. This report begins on page F-3.

There were no changes in EOG's internal control over financial reporting that occurred during the fiscal quarter ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

ITEM 9B. Other Information

None.

37

PART III

ITEM 10. Directors and Executive Officers of the Registrant

Directors and Executive Officers of the Registrant. The information required by this Item regarding directors is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2005, under the caption entitled "Election of Directors" of Item 1.

Audit Committee Related Matters and Code of Ethics for the CEO and CFO. The information required by this Item regarding audit committee related matters is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2005, under the caption entitled "Board of Directors and Committees" of Item 1.

ITEM 11. Executive Compensation

The information required by this Item is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2005, under the caption "Compensation of Directors and Executive Officers" of Item 1.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this Item with respect to security ownership of certain beneficial owners and management is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2005, under the captions "Election of Directors" and "Compensation of Directors and Executive Officers" of Item 1.

Equity Compensation Plan Information

EOG has various plans under which employees and nonemployee members of the Board of Directors of EOG and its subsidiaries have been or may be granted certain equity compensation consisting of stock options, restricted stock, restricted stock units and phantom stock. The 1992 Stock Plan, the 1993 Nonemployee Directors Stock Option Plan, and the Employee Stock Purchase Plan have been approved by security holders. Plans that have not been approved by security holders are described below. The following table sets forth data for EOG's equity compensation plans aggregated by the various plans approved by security holders and those plans not approved by security holders as of December 31, 2005.

     

(c)

     

Number of Securities

 

(a)

(b)

Remaining Available

 

Number of Securities to be

Weighted-Average

for Future Issuance Under

 

Issued Upon Exercise of

Exercise Price of

Equity Compensation

 

Outstanding Options,

Outstanding Options,

Plans (Excluding Securities

Plan Category

Warrants and Rights

Warrants and Rights

Reflected in Column (a))

Equity Compensation

     

   Plans Approved by

     

   Security Holders

7,080,120

$34.01   

5,527,867(1) (2)

Equity Compensation

     

   Plans Not Approved

     

   by Security Holders

    5,217,234

$19.04(3)

    118,459(4) (5)

Total

12,297,354

$27.70(3)

5,646,326       

(1) Of these securities, 407,402 shares remain available for purchase under the Employee Stock Purchase Plan.
(2) Of these securities, 1,781,229 could be issued as restricted stock or restricted stock units under the 1992 Stock Plan.
(3) Weighted-average exercise price does not include 55,932 phantom stock units in the 1996 Deferral Plan which are included in column (a).
(4) Of these securities, 40,217 phantom stock units remain available for issuance under the 1996 Deferral Plan.
(5) Of these securities, 78,242 could be issued as restricted stock or restricted stock units under the 1994 Stock Plan.

38

Stock Plan Not Approved by Security Holders. The Board of Directors of EOG approved the 1994 Stock Plan, which provides equity compensation to employees who are not officers within the meaning of Rule 16a-1 of the Securities Exchange Act of 1934, as amended. Under the plan, employees have been or may be granted stock options (rights to purchase shares of EOG common stock at a price not less than the market price of the stock at the date of grant). Stock options vest either immediately at the date of grant or up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements. Terms for stock options granted under the plan have not exceeded a maximum term of 10 years. Employees have also been or may be granted shares of restricted stock and/or restricted stock units without cost to the employee. The shares and units granted vest to the employee at various times ranging from one to five years as defined in individual grant agreements. Upon vesting, restricted shares are released to the employee. Upon vesting, each restricted stock unit is converted into one share of EOG common stock and released to the employee.

Deferral Plan Phantom Stock Account. The Board of Directors of EOG approved the 1996 Deferral Plan, under which payment of base salary, annual bonus and directors fees may be deferred into a phantom stock account. In the phantom stock account, deferrals are treated as if they had purchased shares of EOG common stock at the closing stock price on the date of deferral. Dividends are credited quarterly and treated as if reinvested in EOG common stock. Payment of the phantom stock account is made in actual shares of EOG common stock. A total of 120,000 shares have been registered for issuance under the plan. As of December 31, 2005, 79,783 phantom stock units had been issued and 40,217 units remained available for issuance under the plan.

ITEM 13. Certain Relationships and Related Transactions

None.

ITEM 14. Principal Accounting Fees and Services

Information regarding auditor fees, audit-related fees, tax fees and all other fees and services billed by the principal accountant is incorporated by reference from the Proxy Statement to be filed within 120 days after December 31, 2005, under the caption "Ratification of Appointment of Auditors - General" of Item 2.

 

PART IV

ITEM 15. Exhibits and Financial Statement Schedules

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedule

See "Index to Financial Statements" set forth on page F-1.

(a)(3) Exhibits

See pages E-1 through E-4 for a listing of the exhibits.

39

INDEX TO FINANCIAL STATEMENTS
EOG RESOURCES, INC.

                                                                                                                                                                                            Page

Consolidated Financial Statements:

 
     

Management's Responsibility for Financial Reporting

F-2  

     

Report of Independent Registered Public Accounting Firm

F-3  

     

Consolidated Statements of Income and Comprehensive Income for Each of the Three Years

 
 

in the Period Ended December 31, 2005

F-5  

     

Consolidated Balance Sheets - December 31, 2005 and 2004

F-6  

     

Consolidated Statements of Shareholders' Equity for Each of the Three Years in the

 
 

Period Ended December 31, 2005

F-7  

     

Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended

 
 

December 31, 2005

F-8  

     

Notes to Consolidated Financial Statements

F-9  

     

Supplemental Information to Consolidated Financial Statements

F-31

     

Financial Statement Schedule:

 
     

Schedule II-Valuation and Qualifying Accounts

S-1  

Other financial statement schedules have been omitted because they are inapplicable or the information required
therein is included elsewhere in the consolidated financial statements or notes thereto.

F-1

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING

 

The following consolidated financial statements of EOG Resources, Inc. and its subsidiaries (EOG) were prepared by management, which is responsible for their integrity, objectivity and fair presentation. The statements have been prepared in conformity with generally accepted accounting principles in the United States of America and, accordingly, include some amounts that are based on the best estimates and judgments of management.

EOG's management is also responsible for establishing and maintaining effective internal control over financial reporting. The system of internal control of EOG is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. This system consists of 1) entity level controls, including written policies and guidelines relating to the ethical conduct of business affairs, 2) general computer controls and 3) process controls over initiating, authorizing, recording, processing and reporting transactions. Even an effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of an internal control system in future periods can change with conditions.

The adequacy of financial controls of EOG and the accounting principles employed in financial reporting by EOG are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of EOG. The independent registered public accounting firm and internal auditors have full, free, separate and direct access to the Audit Committee and meet with the committee from time to time to discuss accounting, auditing and financial reporting matters.

EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2005. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. These criteria cover the control environment, risk assessment process, control activities, information and communication systems, and monitoring activities. Based on this assessment, management believes that, as of December 31, 2005, EOG's internal control over financial reporting is effective based on those criteria.

Deloitte & Touche LLP, independent registered public accounting firm, was engaged to audit the consolidated financial statements and management's assessment of the effectiveness of EOG's internal control over financial reporting, and to issue a report thereon. In the conduct of the audit, Deloitte & Touche LLP was given unrestricted access to all financial records and related data including minutes of all meetings of shareholders, the Board of Directors and committees of the Board. Management believes that all representations made to Deloitte & Touche LLP during the audit were valid and appropriate. Their audit was made in accordance with standards of the Public Company Accounting Oversight Board (United States) and included a review of the system of internal controls to the extent considered necessary to determine the audit procedures required to support their opinion on the consolidated financial statements, management's assessment of EOG's internal control over financial reporting and the effectiveness of EOG's internal control over financial reporting. Their report begins on page F-3.

 

MARK G. PAPA

EDMUND P. SEGNER, III

TIMOTHY K. DRIGGERS

Chairman of the Board and

President and Chief of Staff

Vice President and Chief

Chief Executive Officer

 

Accounting Officer

Houston, Texas
February 22, 2006

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
EOG Resources, Inc.
Houston, Texas

We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. and subsidiaries (the "Company") as of December 31, 2005 and 2004, and the related consolidated statements of income and comprehensive income, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2005.  Our audits also included the financial statement schedule listed in the Index at Item 15.  We also have audited management's assessment, included in the accompanying Management's Responsibility for Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting.  Our responsibility is to express an opinion on these financial statements and financial statement schedule, an opinion on management's assessment, and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

F-3

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.  Also, in our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 13 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations."

 

 

DELOITTE & TOUCHE LLP

Houston, Texas
February 22, 2006

F-4

 

EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(In Thousands, Except Per Share Data)

Year Ended December 31

 

2005

 

2004

 

2003

             

Net Operating Revenues

           
 

Natural Gas

$

2,938,917 

$

1,842,316 

$

1,535,204 

 

Crude Oil, Condensate and Natural Gas Liquids

 

668,073 

 

458,446 

 

283,042 

 

Gains (Losses) on Mark-to-Market Commodity Derivative Contracts

 

10,475 

 

(33,449)

 

(80,414)

 

Other, Net

 

2,748 

 

3,912 

 

6,843 

   

Total

 

3,620,213 

 

2,271,225 

 

1,744,675 

Operating Expenses

           
 

Lease and Well, including Transportation

 

373,355 

 

271,086 

 

212,601 

 

Exploration Costs

 

133,116 

 

93,941 

 

76,358 

 

Dry Hole Costs

 

64,812 

 

92,142 

 

41,156 

 

Impairments

 

77,932 

 

81,530 

 

89,133 

 

Depreciation, Depletion and Amortization

 

654,258 

 

504,403 

 

441,843 

 

General and Administrative

 

125,918 

 

115,013 

 

100,403 

 

Taxes Other Than Income

 

199,007 

 

133,915 

 

85,867 

   

Total

 

1,628,398 

 

1,292,030 

 

1,047,361 

Operating Income

 

1,991,815 

 

979,195 

 

697,314 

Other Income, Net

 

35,828 

 

9,945 

 

15,273 

Income Before Interest Expense and Income Taxes

 

2,027,643 

 

989,140 

 

712,587 

Interest Expense

           
 

Incurred

 

77,102 

 

72,759 

 

67,252 

 

Capitalized

 

(14,596)

 

(9,631)

 

(8,541)

   

Net Interest Expense

 

62,506 

 

63,128 

 

58,711 

Income Before Income Taxes

 

1,965,137 

 

926,012 

 

653,876 

Income Tax Provision

 

705,561 

 

301,157 

 

216,600 

Net Income Before Cumulative Effect of Change

           

   in Accounting Principle

 

1,259,576 

 

624,855 

 

437,276 

Cumulative Effect of Change in Accounting

           

   Principle, Net of Income Tax

 

 

 

(7,131)

Net Income

 

1,259,576 

 

624,855 

 

430,145 

Preferred Stock Dividends

 

7,432 

 

10,892 

 

11,032 

Net Income Available to Common

$

1,252,144 

$

613,963 

$

419,113 

                 

Net Income Per Share Available to Common

           
 

Basic

           
   

Net Income Available to Common Before

           
   

   Cumulative Effect of Change in Accounting Principle

$

5.24 

$

2.63 

$

1.86 

   

Cumulative Effect of Change in Accounting

           
   

   Principle, Net of Income Tax

 

 

 

(0.03)

   

Net Income Available to Common

$

5.24 

$

2.63 

$

1.83 

 

Diluted

           
   

Net Income Available to Common Before Cumulative Effect

           
   

   of Change in Accounting Principle

$

5.13 

$

2.58 

$

1.83 

   

Cumulative Effect of Change in Accounting

           
   

   Principle, Net of Income Tax

 

 

 

(0.03)

   

Net Income Available to Common

$

5.13 

$

2.58 

$

1.80 

Average Number of Common Shares

           
 

Basic

 

238,797 

 

233,751 

 

229,194 

 

Diluted

 

243,975 

 

238,376 

 

233,037 

                 

Comprehensive Income

           

Net Income

$

1,259,576 

$

624,855 

$

430,145 

Other Comprehensive Income (Loss)

           
 

Foreign Currency Translation Adjustments

 

34,074 

 

77,925 

 

123,811 

 

Foreign Currency Swap Transaction

 

(7,567)

 

(5,816)

 

 

Income Tax Related to Foreign Currency Swap Transaction

 

2,615 

 

1,972 

 

Comprehensive Income

$

1,288,698 

$

698,936 

$

553,956 

The accompanying notes are an integral part of these consolidated financial statements.

F-5

EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)

At 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 

 

Deferred Income Taxes

 

24,376 

 

22,227 

 

Other

 

58,214 

 

45,070 

   

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, $.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, $.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 

The accompanying notes are an integral part of these consolidated financial statements.

F-6

EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(In Thousands, Except Per Share Data)

         

Accumulated

 

Common

 
     

Additional

 

Other

 

Stock

Total

 

Preferred

Common

Paid In

Unearned

Comprehensive

Retained

Held In

Shareholders'

 

Stock

Stock

Capital

Compensation

Income (Loss)

Earnings

Treasury

Equity

Balance at December 31, 2002

$147,999 

$201,247 

$             - 

$(15,033)

$(49,877)

$1,723,948 

$(335,889)

$1,672,395 

 

Net Income

430,145 

430,145 

 

Amortization of Preferred

               
   

Stock Discount

417 

(417)

 

Preferred Stock Dividends Declared

(10,615)

(10,615)

 

Common Stock Dividends

               
   

Declared, $0.10 Per Share

(21,847)

(21,847)

 

Translation Adjustment

123,811 

123,811 

 

Treasury Stock Purchased

(25,208)

(25,208)

 

Treasury Stock Issued Under:

               
   

Stock Option Plans

(16,522)

50,292 

33,770 

   

Employee Stock Purchase Plan

84 

2,515 

2,599 

 

Tax Benefits from Stock

               
   

Options Exercised

11,926 

11,926 

 

Restricted Stock and Units

6,084 

(14,467)

8,383 

 

Amortization of Unearned

               
   

Compensation

6,027 

6,027 

 

Treasury Stock Issued as

               
   

Compensation

53 

325 

378 

Balance at December 31, 2003

148,416 

201,247 

1,625 

(23,473)

73,934 

2,121,214 

(299,582)

2,223,381 

 

Net Income

624,855 

624,855 

 

Redemption of Preferred Stock,

               
   

$100,000 Per Share

(50,000)

(50,000)

 

Amortization of Preferred

               
   

Stock Discount

410 

(410)

 

Preferred Stock Dividends Declared

(10,482)

(10,482)

 

Common Stock Dividends

               
   

Declared, $0.12 Per Share

(28,332)

(28,332)

 

Translation Adjustment

77,925 

77,925 

 

Treasury Stock Purchased

(9,565)

(9,565)

 

Foreign Currency Swap Transaction

               
   

Net of Income Tax Benefit

               
   

   of $1,972

(3,844)

(3,844)

 

Treasury Stock Issued Under:

               
   

Stock Option Plans

(21,570)

101,077 

79,507 

   

Employee Stock Purchase Plan

694 

2,326 

3,020 

 

Tax Benefits from Stock

               
   

Options Exercised

29,396 

29,396 

 

Restricted Stock and Units

10,902 

(15,951)

5,049 

 

Amortization of Unearned

               
   

Compensation

9,563 

9,563 

Balance at December 31, 2004

98,826 

201,247 

21,047 

(29,861)

148,015 

2,706,845 

(200,695)

2,945,424 

 

Net Income

1,259,576 

1,259,576 

 

Common Stock Issued - Stock Split

1,248 

(1,248)

 

Amortization of Preferred

               
   

Stock Discount

236 

(236)

 

Preferred Stock Dividends Declared

(7,196)

(7,196)

 

Common Stock Dividends

               
   

Declared, $0.16 Per Share

(38,506)

(38,506)

 

Translation Adjustment

34,074 

34,074 

 

Foreign Currency Swap Transaction

(7,567)

(7,567)

 

Income Tax Related to Foreign

               
   

Currency Swap Transaction

2,615 

2,615 

 

Treasury Stock Purchased

 

Treasury Stock Issued Under:

               
   

Stock Option Plans

130 

59,347 

59,477 

   

Employee Stock Purchase Plan

2,027 

1,862 

3,889 

 

Tax Benefits from Stock

               
   

Options Exercised

50,880 

50,880 

 

Restricted Stock and Units

11,080 

(18,573)

7,493 

 

Amortization of Unearned

               
   

Compensation

12,188 

12,188 

 

Treasury Stock Issued as

               
   

Compensation

789 

649 

1,438 

Balance at December 31, 2005

$   99,062 

$202,495 

$ 84,705 

$(36,246)

$177,137 

$3,920,483 

$(131,344)

$4,316,292 

                 

The accompanying notes are an integral part of these consolidated financial statements.

F-7

EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)

Year Ended December 31

 

2005

 

2004

 

2003

Cash Flows From Operating Activities

           

Reconciliation of Net Income to Net Cash Provided by Operating Activities:

           
 

Net Income

$

1,259,576 

$

624,855 

$

430,145 

 

Items Not Requiring Cash

           
   

Depreciation, Depletion and Amortization

 

654,258 

 

504,403 

 

441,843 

   

Impairments

 

77,932 

 

81,530 

 

89,133 

   

Deferred Income Taxes

 

270,291 

 

204,231 

 

191,726 

   

Cumulative Effect of Change in Accounting

           
   

   Principle, Net of Income Tax

 

 

 

7,131 

   

Other, Net

 

9,642 

 

4,580 

 

1,033 

 

Dry Hole Costs

 

64,812 

 

92,142 

 

41,156 

 

Mark-to-Market Commodity Derivative Contracts

           
   

Total (Gains) Losses

 

(10,475)

 

33,449 

 

80,414 

   

Realized Gains (Losses)

 

9,807 

 

(82,644)

 

(44,870)

   

Collar Premium

 

 

(520)

 

(3,003)

 

Tax Benefits from Stock Options Exercised

 

50,880 

 

29,396 

 

11,926 

 

Other, Net

 

(5,086)

 

537 

 

2,141 

 

Changes in Components of Working Capital and Other Liabilities

           
   

Accounts Receivable

 

(315,557)

 

(151,799)

 

(27,945)

   

Inventories

 

(23,085)

 

(17,898)

 

(2,840)

   

Accounts Payable

 

248,411 

 

136,716 

 

74,645 

   

Accrued Taxes Payable

 

88,151 

 

18,197 

 

12,056 

   

Other Liabilities

 

(1,213)

 

(1,764)

 

(3,257)

   

Other, Net

 

(10,347)

 

(2,683)

 

(15,314)

 

Changes in Components of Working Capital

           
   

Associated with Investing and Financing Activities

 

1,429 

 

(28,381)

 

(36,944)

Net Cash Provided by Operating Activities

 

2,369,426 

 

1,444,347 

 

1,249,176 

Investing Cash Flows

           
 

Additions to Oil and Gas Properties

 

(1,724,763)

 

(1,416,684)

 

(1,245,539)

 

Proceeds from Sales of Assets

 

70,987 

 

13,459 

 

13,553 

 

Changes in Components of Working Capital

           
   

Associated with Investing Activities

 

(1,538)

 

26,788 

 

38,491 

 

Other, Net

 

(22,794)

 

(20,471)

 

(13,946)

Net Cash Used in Investing Activities

 

(1,678,108)

 

(1,396,908)

 

(1,207,441)

Financing Cash Flows

           
 

Net Commercial Paper and Line of Credit Repayments

 

(91,800)

 

(6,250)

 

(36,260)

 

Long-Term Debt Borrowings

 

250,000 

 

150,000 

 

 

Long-Term Debt Repayments

 

(250,755)

 

(175,000)

 

 

Dividends Paid

 

(42,986)

 

(37,595)

 

(31,294)

 

Redemption of Preferred Stock

 

 

(50,000)

 

 

Treasury Stock Purchased

 

 

 

(21,295)

 

Proceeds from Stock Options Exercised

 

64,668 

 

75,510 

 

35,138 

 

Changes in Components of Working Capital

           
   

Associated with Financing Activities

 

109 

 

1,593 

 

(1,547)

 

Other, Net

 

(1,546)

 

(1,496)

 

(1,938)

Net Cash Used in Financing Activities

 

(72,310)

 

(43,238)

 

(57,196)

Effect of Exchange Rate Changes on Cash

 

3,823 

 

12,336 

 

10,056 

Increase (Decrease) in Cash and Cash Equivalents

 

622,831 

 

16,537 

 

(5,405)

Cash and Cash Equivalents at Beginning of Year

 

20,980 

 

4,443 

 

9,848 

Cash and Cash Equivalents at End of Year

$

643,811 

$

20,980 

$

4,443 

The accompanying notes are an integral part of these consolidated financial statements.

F-8

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Principles of Consolidation. The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All material intercompany accounts and transactions have been eliminated.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Certain reclassifications have been made to prior period financial statements to conform with the current presentation.

On February 2, 2005, EOG announced that the Board of Directors had approved a two-for-one stock split in the form of a stock dividend, payable to record holders as of February 15, 2005 and issued on March 1, 2005. All share and per share data in the financial statements and accompanying footnotes for all periods have been restated to reflect the two-for-one stock split paid to common shareholders.

Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, marketable securities, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt. The carrying values of cash and cash equivalents, marketable securities, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Note 11).

Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.

Oil and Gas Operations. EOG accounts for its natural gas and crude oil exploration and production activities under the successful efforts method of accounting.

Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. Exploratory drilling costs are capitalized when drilling is complete if it is determined that there is economic producibility supported by either actual production, a conclusive formation test or by certain technical data if the discovery is located offshore in the Gulf of Mexico. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. All other exploratory wells that do not meet these criteria are expensed after one year. As of December 31, 2005 and 2004, EOG had exploratory drilling costs related to two projects that have been deferred for more than one year (see Note 16). These costs meet the accounting requirements outlined above for continued capitalization. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and crude oil, are capitalized.

F-9

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.

Assets are grouped in accordance with paragraph 30 of Statement of Financial Accounting Standards (SFAS) No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions, and 4) impairments.

EOG accounts for impairments under the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." When circumstances indicate that an asset may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

Inventories, consisting primarily of tubular goods and well equipment held for use in the exploration for and development and production of natural gas and crude oil reserves, are carried at cost with adjustments made from time to time to recognize any reductions in value.

Arrangements for natural gas, crude oil, condensate and natural gas liquids sales are evidenced by signed contracts with determinable market prices and are recorded when production is delivered. A significant majority of the purchasers of these products have investment grade credit ratings and material credit losses have been rare. Revenues are recorded on the entitlement method based on EOG's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold on that owner's behalf may differ from that owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when overproduction occurs.

Capitalized Interest Costs. Interest capitalization is required for those properties if its effect, compared with the effect of expensing interest, is material. Accordingly, certain interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. The amount capitalized is an allocation of the interest cost incurred during the reporting period. Capitalized interest is computed only during the exploration and development activities and not on proved properties. The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings.

Accounting for Price Risk Management Activities. EOG accounts for its price risk management activities under the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137, 138 and 149. The statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. During the three year period ending December 31, 2005, EOG elected not to designate any of its commodity price risk management activities as accounting hedges under SFAS No. 133, and accordingly, accounted for them using the mark-to-market accounting method. Under this accounting method, the changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. The gains or losses are recorded in Gains (Losses) on Mark-to-Market Commodity Derivative Contracts. The related cash flow impact is reflected as cash flows from operating activities (see Note 11).

F-10

Income Taxes. EOG accounts for income taxes under the provisions of SFAS No. 109, "Accounting for Income Taxes." SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis (see Note 5).

Foreign Currency Translation. For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included in Accumulated Other Comprehensive Income. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period.

Net Income Per Share. In accordance with the provisions of SFAS No. 128, "Earnings per Share," basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted net income per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities (see Note 8).

Stock Options. EOG accounted for stock options under the provisions and related interpretations of Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." No compensation expense was recognized for such options. As allowed by SFAS No. 123, "Accounting for Stock-Based Compensation" issued in 1995, EOG continued to apply APB Opinion No. 25 for purposes of determining net income and to present the pro forma disclosures required by SFAS No. 123.

EOG's pro forma net income and net income per share available to common for 2005, 2004 and 2003, had compensation costs been recorded in accordance with SFAS No. 123, are presented below (in millions, except per share data):

    2005   2004   2003

Net Income Available to Common - As Reported

$

1,252.1 

$

614.0 

$

419.1 

Deduct: Total Stock-Based Employee Compensation Expense,

           

   Net of Income Tax

 

(13.7)

 

(11.9)

 

(13.9)

Net Income Available to Common - Pro Forma

$

1,238.4 

$

602.1 

$

405.2 

               

Net Income Per Share Available to Common

           
 

Basic - As Reported

$

5.24 

$

2.63 

$

1.83 

 

Basic - Pro Forma

$

5.19 

$

2.58 

$

1.77 

               
 

Diluted - As Reported

$

5.13 

$

2.58 

$

1.80 

 

Diluted - Pro Forma

$

5.08 

$

2.53 

$

1.74 

For all grants made prior to August 2004 and employee stock purchase plan grants, the fair value of each option grant is estimated using the Black-Scholes-Merton option-pricing model with the following weighted-average assumptions used for grants in 2005, 2004 and 2003, respectively: (1) dividend yield of 0.4%, 0.4% and 0.4%, (2) expected volatility of 30%, 35% and 43%, (3) risk-free interest rate of 3.0%, 2.5% and 3.4% and (4) expected life of 0.5 years, 2.8 years and 5.2 years.

F-11

Certain of EOG's stock options issued in 2005 and 2004 contain a feature that limits the potential gain that can be realized by requiring vested options to be exercised if the market price reaches 200% of the grant price for five consecutive trading days (Capped Option). EOG may or may not issue Capped Options in the future. The fair value of each Capped Option grant is estimated using a Monte Carlo simulation with the following weighted-average assumptions: (1) dividend yield of 0.4%, (2) expected volatility of 33%, (3) risk-free interest rate of 4.3% and (4) expected life of 4.8 years. Effective May 2005, the fair value of stock option grants not containing the Capped Option feature is estimated using the Hull-White II binomial option pricing model with the following weighted-average assumptions: (1) dividend yield of 0.4%, (2) expected volatility of 32%, (3) risk-free interest rate of 4.2% and (4) expected life of 5.0 years. During 2005, approximately 1,934,000 stock options were granted at a weighted average fair value of $19.25 and were included in the above pro forma employee stock based compensation expense calculation. Approximately 111,000 of the stock options were granted with an average fair value of $9.81, based on the Black-Scholes-Merton option-pricing model. Approximately 136,000 of the stock options were granted with the Capped Option feature with an average fair value of $17.36, based on the Monte Carlo simulation. Approximately 1,687,000 of the stock options were granted without the Capped Option feature with an average fair value of $20.02, based on the Hull-White II binomial option pricing model. The weighted average fair values for the stock options granted during 2004 and 2003 were $21.06 and $16.55, respectively.

The effects of applying SFAS No. 123 in this pro forma disclosure should not be interpreted as being indicative of future effects. SFAS No. 123 does not apply to awards prior to 1995, and the extent and timing of additional future awards cannot be predicted.

Recently Issued Accounting Standards and Developments. In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty." EITF Issue 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. EOG presents purchase and sale activities related to its marketing activities on a net basis in the Consolidated Statements of Income and Comprehensive Income. The adoption of EITF Issue No. 04-13 is not expected to have a material impact on EOG's financial statements.

In April 2005, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. 19-1, "Accounting for Suspended Well Costs," which amended SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." FSP No. 19-1 allows exploratory well costs to continue to be capitalized beyond one year of the drilling completion date when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. EOG adopted FSP No. 19-1 effective July 1, 2005. The adoption of FSP No. 19-1 did not have a material impact on EOG's financial statements. (See Note 16.)

In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, "Accounting for Conditional Asset Retirement Obligations." The interpretation clarifies the requirement to record abandonment liabilities stemming from legal obligations when the retirement depends on a conditional future event. FIN No. 47 requires that the uncertainty about the timing or method of settlement of a conditional retirement obligation be factored into the measurement of the liability when sufficient information exists. FIN No. 47 is effective for fiscal years ending after December 15, 2005. The adoption of FIN No. 47 did not have a material impact on EOG's financial statements.

In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29," which provides that all nonmonetary asset exchanges that have commercial substance must be measured based on the fair value of the assets exchanged and any resulting gain or loss recorded. An exchange is defined as having commercial substance if it results in a significant change in expected future cash flows. Exchanges of operating interests by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion No. 29 previously exempted all exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. SFAS No. 153 became effective for fiscal periods beginning on or after June 15, 2005. EOG adopted SFAS No. 153 effective July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on EOG's financial statements.

F-12

In December 2004, the FASB issued SFAS No. 123(R), "Share-Based Payment," which supersedes SFAS No. 148, "Accounting for Stock Based Compensation - Transition and Disclosure, an amendment of FASB Statement No. 123." SFAS No. 123(R) establishes standards for transactions in which an entity exchanges its equity instruments for goods or services. This standard requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. This eliminates the exception to account for such awards using the intrinsic method previously allowable under APB Opinion No. 25. SFAS No. 123(R) is effective for annual reporting periods beginning on or after June 15, 2005. EOG adopted SFAS No. 123(R) effective January 1, 2006 using the modified prospective method. EOG expects this will reduce 2006 net earnings by a pre-tax amount of approximately $25 million, taking into consideration the estimated forfeitures and cancellations. The amount includes approximately $21 million of expense for unvested options outstanding at December 31, 2005 and $1 million of expense for the Employee Stock Purchase Plan. SFAS No. 123(R) also requires a public entity to present its cash flows provided by tax benefits from stock options exercised in the Financing Cash Flows section of the Statement of Cash Flows. Had SFAS No. 123(R) been in effect, EOG's Net Cash Provided by Operating Activities would have been reduced and its Net Cash Provided by Financing Activities would have been increased on its Consolidated Statements of Cash Flows by $51 million, $29 million and $12 million for 2005, 2004 and 2003, respectively (see Note 6).

On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was enacted. The Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 through 2010. The Act also provides for a two-year phase out of the existing extra-territorial income exclusion (ETI) for foreign sales that was held to be inconsistent with international trade protocols. EOG expects the net effect of the phase in of the domestic production activities deduction and the phase out of the ETI to result in favorable adjustments to the effective tax rate for 2005 and subsequent years. Under the guidance in FSP No. 109-1, "Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004," the deduction will be treated as a "special deduction" as described in SFAS No. 109. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the period in which the deduction is claimed on EOG's tax return. (See Note 5.)

The Act also creates a temporary incentive for United States corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. On October 28, 2005, EOG's Board of Directors approved EOG's Domestic Reinvestment Plan under which the categories of qualified expenditures are workers compensation and infrastructure and capital investments in the United States. During December 2005, EOG received a $450 million foreign dividend qualifying under the Act and recorded a tax charge of approximately $24 million as a result of the transaction.

On April 1, 2004, EOG adopted prospectively FSP No. 106-2, "Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" (FSP 106-2), which provides guidance on accounting for the effects of the Medicare Prescription Drug Improvement Act of 2003 for employers that sponsor postretirement health care plans that provide prescription drug benefits. The adoption of FSP 106-2 did not have a material impact on EOG's financial statements (see Note 6).

F-13

2. Long-Term Debt

Long-Term Debt at December 31 consisted of the following (in thousands):

   

2005

 

2004

Commercial Paper

$

-

$

91,800

Senior Unsecured Term Loan Facility due 2005

 

-

 

75,000

6.70% Notes due 2006

 

126,075

 

126,870

6.50% Notes due 2007

 

98,992

 

100,000

6.00% Notes due 2008

 

-

 

173,952

6.65% Notes due 2028

 

140,000

 

140,000

Subsidiary Senior Unsecured Term Loan Facility due 2008

 

250,000

 

-

7.00% Subsidiary Debt due 2011

 

220,000

 

220,000

4.75% Subsidiary Debt due 2014

 

150,000

 

150,000

   

985,067

 

1,077,622

Less: Current Portion of Long-Term Debt

 

126,075

 

-

Total

$

858,992

$

1,077,622

During 2005 and 2004, EOG utilized commercial paper, bearing market interest rates, for various corporate financing purposes. Commercial paper outstanding at December 31, 2004 was classified as long-term debt based on EOG's intent and ability to ultimately replace such amounts with other long-term debt. The weighted average interest rate for commercial paper was 3.30% for 2005. At December 31, 2005, the aggregate annual maturities of long-term debt were $126 million in 2006, $99 million in 2007, $250 million in 2008 and zero in both 2009 and 2010.

In accordance with notice delivered to holders on November 1, 2005, EOG redeemed the remaining $174 million outstanding principal amount of its 6.00% Notes due 2008 (2008 Notes) on December 5, 2005, at a redemption price of $1,039.22 per each $1,000.00 of principal amount, plus accrued and unpaid interest through the redemption date. The redemption was made in accordance with terms of the indenture and the officer's certificate establishing the terms of the 2008 Notes. In connection with the redemption, EOG recognized a loss on extinguishment of debt in the amount of $8 million, included in Net Interest Expense, representing prepaid interest and the write-off of deferred bond issuance costs.

In October 2005, EOGI International Company (EOGI) a wholly owned foreign subsidiary of EOG entered into a $600 million, 3-year unsecured Senior Term Loan Agreement (Term Loan Agreement) with The Bank of Nova Scotia, as Administrative Agent, and certain banks, as lenders. All borrowings under this agreement will be made as term loans and will be guaranteed by EOG. Proceeds from the Term Loan Agreement are to be used for general corporate purposes, including funding distributions ultimately to EOG from its foreign subsidiaries to realize a benefit of the favorable United States tax legislation regarding repatriation of foreign earnings under the American Jobs Creation Act of 2004. Borrowings up to $600 million under the Term Loan Agreement were available in multiple drawings through December 31, 2005, and prior to such date, EOGI elected to borrow $250 million, which was used to fund the distributions ultimately to EOG as described above. The $250 million was borrowed at the Eurodollar rate (a London InterBank Offering Rate (LIBOR) plus the applicable margin) of 4.90% per annum for the initial three-month interest period beginning December 6, 2005. Subsequent to December 31, 2005, borrowing capacity under the Term Loan Agreement was reduced to $100 million and such amount will be available for an additional one-year period. On February 17, 2006, EOGI repaid $50 million of the amount outstanding at December 31, 2005. Borrowings under the Term Loan Agreement accrue interest at LIBOR plus an applicable margin or at the Administrative Agent's base rate, as selected by the borrower.

F-14

On June 28, 2005, EOG entered into a new 5-year $600 million unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders and JPMorgan Chase Bank, N.A., as Administrative Agent, and concurrently terminated the existing $600 million 3-year unsecured credit facility scheduled to expire in July 2006. Under the Agreement, EOG has the option to extend, as to consenting lenders, the term for successive one-year periods with the consent of the majority banks and to request increases in the aggregate commitments to an amount not to exceed $1 billion. The Agreement also provides for the allocation, at the option of EOG, of up to $75 million of the $600 million each to EOG's current United Kingdom subsidiary and one of its Canadian subsidiaries. Interest accrues on advances at LIBOR plus an applicable margin (Eurodollar rate) or at the Administrative Agent's base rate, as selected by EOG. Advances to the Canadian or the United Kingdom subsidiaries, should they occur, would be guaranteed by EOG and would bear interest at a rate calculated in accordance with the Agreement. In addition, the Agreement provides EOG the option to request letters of credit to be issued in an aggregate amount of up to $200 million. There are no borrowings or letters of credit currently outstanding under the Agreement. At December 31, 2005, the applicable base rate and Eurodollar rate, had there been an amount borrowed under the Agreement, would have been 7.25% and 4.58%, respectively.

Both EOG's $600 million Long-Term Revolving Credit Agreement and EOGI's Term Loan Agreement contain certain restrictive covenants applicable to EOG, including a maximum debt-to-total capitalization ratio of 65%. Other than this financial covenant, there are no other financial covenants in EOG's financing agreements. EOG continues to comply with this covenant and does not view it as materially restrictive.

On September 15, 2004, EOG paid in full upon maturity the $100 million, 6.50% Notes.

On March 9, 2004, under Rule 144A of the Securities Act of 1933, as amended, EOG Resources Canada Inc., a wholly owned subsidiary of EOG, issued notes with a total principal amount of $150 million, an annual interest rate of 4.75% and a maturity date of March 15, 2014. The notes are guaranteed by EOG. In conjunction with the offering, EOG entered into a foreign currency swap transaction with multiple banks for the equivalent amount of the notes and related interest, which has in effect converted this indebtedness into Canadian Dollars (CAD) 201.3 million with a 5.275% interest rate.

EOG maintained a $150 million three-year Senior Unsecured Term Loan Facility (Facility) with a group of banks with a maturity date of October 30, 2005. The Facility accrued interest at LIBOR plus an applicable margin, or the base rate, at EOG's option, and contained substantially the same covenants as those in EOG's $600 million Long-Term Revolving Credit Agreement. On March 31, 2004, EOG repaid $75 million of the $150 million loan. The applicable interest rate for the Facility was 3.17% at December 31, 2004. On August 26, 2005, EOG repaid the remaining $75 million outstanding under the Facility and terminated the Facility.

The 6.00% to 6.70% Notes due 2006 to 2028 were issued through public offerings and have effective interest rates of 6.16% to 6.81%. The Subsidiary Debt due 2011 bears interest at a fixed rate of 7.00% and is guaranteed by EOG.

Shelf Registration. As of February 22, 2006, the amount available under various filed registration statements with the Securities and Exchange Commission for the offer and sale from time to time of EOG debt securities, preferred stock and/or common stock totaled approximately $688 million.

Fair Value of Current and Long-Term Debt. At December 31, 2005 and 2004, EOG had $985 million and $1,078 million, respectively, of long-term debt (including current portion), which had fair values of approximately $1,025 million and $1,146 million, respectively. The fair value of long-term debt is the value EOG would have to pay to retire the debt, including any premium or discount to the debt-holder for the differential between the stated interest rate and the year-end market rate. The fair value of long-term debt is based upon quoted market prices and, where such quotes were not available, upon interest rates available to EOG at year-end.

F-15

3. Shareholders' Equity

Common Stock. EOG purchases its common stock from time to time in the open market to be held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock plans and any other approved transactions or activities for which such common stock shall be required. In September 2001, the Board of Directors authorized the purchase of an aggregate maximum of 10 million shares of common stock of EOG which superseded all previous authorizations. At December 31, 2005, 6,386,200 shares remain available for repurchases under this authorization. On February 2, 2005, EOG announced that the Board of Directors had approved a two-for-one stock split in the form of a stock dividend, payable to record holders as of February 15, 2005 and issued on March 1, 2005. In addition, the Board increased the quarterly cash dividend on the common stock to a quarterly cash dividend of $0.04 per share post-split. On February 1, 2006, the Board increased the quarterly cash dividend on the common stock to $0.06 per share.

The following summarizes shares of common stock outstanding at December 31, for each of the years ended December 31 (in thousands):

   

Common Shares

   

Issued

 

Treasury

 

Outstanding

             

Balance at December 31, 2002

 

249,460

 

(20,019)

 

229,441 

 

Treasury Stock Purchased

 

-

 

(1,252)

 

(1,252)

 

Treasury Stock Issued under Stock Option Plans

 

-

 

2,971 

 

2,971 

 

Treasury Stock Issued Under Employee Stock Purchase Plan

 

-

 

148 

 

148 

 

Restricted Stock and Units

 

-

 

494 

 

494 

 

Treasury Stock Issued as Compensation

 

-

 

19 

 

19 

Balance at December 31, 2003

 

249,460

 

(17,639)

 

231,821 

 

Treasury Stock Purchased

 

-

 

(320)

 

(320)

 

Treasury Stock Issued Under Stock Option Plans

 

-

 

5,922 

 

5,922 

 

Treasury Stock Issued Under Employee Stock Purchase Plan

 

-

 

136 

 

136 

 

Restricted Stock and Units

 

-

 

296 

 

296 

Balance at December 31, 2004

 

249,460

 

(11,605)

 

237,855 

 

Treasury Stock Purchased

 

-

 

(155)

 

(155)

 

Treasury Stock Issued Under Stock Option Plans

 

-

 

3,804 

 

3,804 

 

Treasury Stock Issued Under Employee Stock Purchase Plan

 

-

 

106 

 

106 

 

Restricted Stock and Units

 

-

 

464 

 

464 

Balance at December 31, 2005

 

249,460

 

(7,386)

 

242,074 

On February 14, 2000, EOG's Board of Directors declared a dividend of one preferred share purchase right (a Right, and the agreement governing the terms of such Rights, the Rights Agreement) for each outstanding share of common stock, par value $0.01 per share. The Board of Directors has adopted this Rights Agreement to protect stockholders from coercive or otherwise unfair takeover tactics. The dividend was distributed to the stockholders of record on February 24, 2000. As mentioned above, on March 1, 2005, EOG effected a two-for-one stock split in the form of a stock dividend. In accordance with the Rights Agreement, each share of common stock issued in connection with the two-for-one stock split effective March 1, 2005 also had one Right associated with it. Each Right, expiring February 24, 2010, represents a right to buy from EOG one hundredth (1/100) of a share of Series E Junior Participating Preferred Stock (Series E) for $90, once the Rights become exercisable. This portion of a Series E share will give the stockholder approximately the same dividend, voting, and liquidation rights as would one share of common stock. Prior to exercise, the Right does not give its holder any dividend, voting, or liquidation rights. If issued, each one hundredth (1/100) of a Series E share (i) will not be redeemable; (ii) will entitle holders to quarterly dividend payments of $0.01 per share, or an amount equal to the dividend paid on one share of common stock, whichever is greater; (iii) will entitle holders upon liquidation either to receive $1 per share or an amount equal to the payment made on one share of common stock, whichever is greater; (iv) will have the same voting power as one share of common stock; and (v) if shares of EOG's common stock are exchanged via merger, consolidation, or a similar transaction, will entitle holders to a per share payment equal to the payment made on one share of common stock.

F-16

The Rights will not be exercisable until ten days after a public announcement that a person or group has become an acquiring person (Acquiring Person) by obtaining beneficial ownership of 10% or more of EOG's common stock, or if earlier, ten business days (or a later date determined by EOG's Board of Directors before any person or group becomes an Acquiring Person) after a person or group begins a tender or exchange offer which, if consummated, would result in that person or group becoming an Acquiring Person. On February 24, 2005, the Rights Agreement was amended to create an exception to the definition of Acquiring Person to permit a qualified institutional investor to hold 10% or more but less than 20% of EOG's common stock without being deemed an Acquiring Person if the institutional investor meets the following requirements: (i) the institutional investor is described in Rule 13d-1(b)(1) promulgated under the Securities Exchange Act of 1934 and is eligible to report (and, if such institutional investor is the beneficial owner of greater than 5% of EOG's common stock, does in fact report) beneficial ownership of common stock on Schedule 13G; (ii) the institutional investor is not required to file a Schedule 13D (or any successor or comparable report) with respect to its beneficial ownership of EOG's common stock; (iii) the institutional investor does not beneficially own 15% or more of EOG's common stock (including in such calculation the holdings of all of the institutional investor's affiliates and associates other than those which, under published interpretations of the United States Securities and Exchange Commission or its staff, are eligible to file separate reports on Schedule 13G with respect to their beneficial ownership of EOG's common stock); and (iv) the institutional investor does not beneficially own 20% or more of EOG's common stock (including in such calculation the holdings of all of the institutional investor's affiliates and associates). On June 15, 2005, the Rights Agreement was amended again to revise the exception to the definition of Acquiring Person to permit a qualified institutional investor to hold 10% or more but less than 30% of EOG's common stock without being deemed an Acquiring Person if the institutional investor meets the other requirements described above.

If a person or group becomes an Acquiring Person, all holders of Rights, except the Acquiring Person, may for $90, purchase shares of EOG's common stock with a market value of $180, based on the market price of the common stock prior to such acquisition. If EOG is later acquired in a merger or similar transaction after the Rights become exercisable, all holders of Rights except the Acquiring Person may, for $90, purchase shares of the acquiring corporation with a market value of $180 based on the market price of the acquiring corporation's stock, prior to such merger.

EOG's Board of Directors may redeem the Rights for $0.005 per Right at any time before any person or group becomes an Acquiring Person. If the Board of Directors redeems any Rights, it must redeem all of the Rights. Once the Rights are redeemed, the only right of the holders of Rights will be to receive the redemption price of $0.005 per Right. The redemption price has been adjusted for the two-for-one stock split effective March 1, 2005 and will be adjusted for any future stock split or stock dividends of EOG's common stock. After a person or group becomes an Acquiring Person, but before an Acquiring Person owns 50% or more of EOG's outstanding common stock, the Board of Directors may exchange the Rights for common stock or equivalent security at an exchange ratio of one share of common stock or an equivalent security for each such Right, other than Rights held by the Acquiring Person.

Preferred Stock. EOG currently has two authorized series of preferred stock. On February 14, 2000, EOG's Board of Directors, in connection with the Rights Agreement described above, authorized 1,500,000 shares of the Series E with the rights and preferences described above. On February 24, 2005, EOG's Board of Directors increased the authorized shares of the Series E to 3,000,000 as a result of the two-for-one stock split of EOG's common stock effective March 1, 2005. Currently, there are no shares of the Series E outstanding.

On July 19, 2000, EOG's Board of Directors authorized 100,000 shares of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, with a $1,000 Liquidation Preference per share (the Series B). Dividends are payable on the shares only if declared by EOG's Board of Directors and will be cumulative. If declared, dividends will be payable at a rate of $71.95 per share, per year on March 15, June 15, September 15 and December 15 of each year beginning September 15, 2000. EOG may redeem all or part of the Series B at any time beginning on December 15, 2009 at $1,000 per share, plus accrued and unpaid dividends. The Series B is not convertible into, or exchangeable for, common stock of EOG. There are 100,000 shares of the Series B currently outstanding.

F-17

Following the December 2004 redemption of all outstanding shares of EOG's Flexible Money Market Cumulative Preferred Stock, Series D, EOG filed a Certificate of Elimination with the Secretary of State of the State of Delaware on February 24, 2005 to eliminate the series from EOG's Restated Certificate of Incorporation, as amended.

4. Other Income, Net

Other income, net for 2005 consisted of equity income from investments in the Caribbean Nitrogen Company Limited (CNCL) and Nitrogen (2000) Unlimited (N2000) ammonia plants of $16 million, gains on sales of properties of $13 million, interest income of $8 million, a gain on the sale of part of EOG's interest in the N2000 ammonia plant of $2 million and net foreign currency transaction losses of $2 million. Other income, net for 2004 consisted of equity income from investments in the CNCL and N2000 ammonia plants of $11 million, foreign currency transaction losses of $7 million, and gains on sales of properties of $6 million. The foreign currency transaction gains and losses for 2005 and 2004 were results of fluctuations in the Canadian Dollar and British Pound exchange rates applied to certain intercompany short-term loans, which were eliminated during consolidation.

F-18

5. Income Taxes

The principal components of EOG's net deferred income tax liability at December 31 were as follows (in thousands):

   

2005

 

2004

         

Current Deferred Income Tax Assets

       
 

Commodity Hedging Contracts

$

(7,995)

$

(7,701)

 

Deferred Compensation Plans

 

7,366 

 

6,488 

 

United Kingdom Net Operating Loss Carryforward (Current Portion)

 

7,592 

 

10,160 

 

Other

 

17,413 

 

13,280 

   

Total Current Deferred Income Tax Assets

 

24,376 

 

22,227 

             

Current Deferred Income Tax Liabilities

       
 

Timing Differences Associated With Different Year-ends in Foreign

       
 

   Jurisdictions

 

164,659 

 

103,903 

 

Other

 

 

30 

   

Total Current Deferred Income Tax Liabilities

 

164,659 

 

103,933 

             
   

Total Net Current Deferred Income Tax Liabilities

$

140,283 

$

81,706 

             

Noncurrent Deferred Income Tax Assets (included in Other Assets)

       
 

United Kingdom Net Operating Loss Carryforward

$

$

21,764 

 

United Kingdom Oil and Gas Exploration and Development Costs

       
 

   Deducted for Tax Over Book Depreciation, Depletion and Amortization

 

(16,939)

 

(20,465)

   

Total Noncurrent Deferred Income Tax Assets

$

(16,939)

$

1,299 

             

Noncurrent Deferred Income Tax Assets

       
 

Non-Producing Leasehold Costs

$

51,130 

$

41,718 

 

Seismic Costs Capitalized for Tax

 

41,328 

 

25,563 

 

Other

 

39,211 

 

22,740 

   

Total Noncurrent Deferred Income Tax Assets

 

131,669 

 

90,021 

             

Noncurrent Deferred Income Tax Liabilities

       
 

Oil and Gas Exploration and Development Costs Deducted for

       
   

Tax Over Book Depreciation, Depletion and Amortization

 

1,209,494 

 

974,492 

 

Capitalized Interest

 

21,332 

 

16,683 

 

Other

 

6,492 

 

1,200 

   

Total Noncurrent Deferred Income Tax Liabilities

 

1,237,318 

 

992,375 

   

Total Net Noncurrent Deferred Income Tax Liability

$

1,105,649 

$

902,354 

             

Total Net Deferred Income Tax Liability

$

1,262,871 

$

982,761 

 

The components of Income Before Income Taxes for the years indicated below were as follows (in thousands):

   

2005

 

2004

 

2003

             

United States

$

1,336,658

$

641,973

$

442,109

Foreign

 

628,479

 

284,039

 

211,767

 

Total

$

1,965,137

$

926,012

$

653,876

F-19

The principal components of EOG's Income Tax Provision for the years indicated below were as follows (in thousands):

   

2005

 

2004

 

2003

             

Current:

           
 

Federal

$

333,752

$

58,148

$

3,844

 

State

 

25,527

 

3,137

 

880

 

Foreign

 

75,991

 

35,641

 

20,150

   

Total

 

435,270

 

96,926

 

24,874

Deferred:

           
 

Federal

 

132,118

 

156,862

 

151,389

 

State

 

14,774

 

7,985

 

4,052

 

Foreign

 

123,399

 

39,384

 

36,285

   

Total

 

270,291

 

204,231

 

191,726

Income Tax Provision

$

705,561

$

301,157

$

216,600

The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows:

   

2005

 

2004

 

2003

             

Statutory Federal Income Tax Rate

 

35.00%

 

35.00%

 

35.00%

State Income Tax, Net of Federal Benefit

 

1.32    

 

0.74    

 

0.73    

Income Tax Provision Related to Foreign Operations

 

(0.92)   

 

(1.83)  

 

(0.05)   

Change in Canadian Federal Tax Rate

 

-    

 

-    

 

(2.16)   

Change in Canadian Provincial Tax Rate

 

-    

 

(0.58)  

 

-    

Dividend Repatriation

 

1.20   

 

-    

 

-    

Domestic Production Activities Deduction

 

(0.42)  

 

-    

 

-    

Other

 

(0.28)  

 

(0.81)  

 

(0.40)  

 

Effective Income Tax Rate

 

35.90%

 

32.52%

 

33.12%

On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was enacted. The Act creates a temporary incentive for United States corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. During the fourth quarter of 2005, EOG made a qualifying distribution in the amount of $450 million resulting in a federal income tax of approximately $24 million.

EOG's foreign subsidiaries' undistributed earnings of approximately $1.3 billion at December 31, 2005 are considered to be indefinitely invested outside the United States and, accordingly, no United States or state income taxes have been provided thereon. Upon distribution of those earnings, EOG may be subject to both foreign withholding taxes and United States income taxes, net of allowable foreign tax credits. Determination of any potential amount of unrecognized deferred income tax liabilities is not practicable.

EOG incurred a tax net operating loss of $191 million in 2002. During 2003, EOG utilized $176 million of the 2002 net operating loss. The remaining net operating loss of $15 million was utilized in 2004.

Through 2004, EOG incurred foreign net operating losses of approximately $70 million, of which $51 million was utilized in 2005. The remaining $19 million net operating loss will be carried forward indefinitely.

EOG had an alternative minimum tax credit carryforward from prior years of $6 million which was used to offset regular income taxes in 2004.

F-20

6. Employee Benefit Plans

Pension Plans

EOG has a non-contributory defined contribution pension plan and a matched defined contribution savings plan in place for most of its employees in the United States. EOG's contributions to these pension plans are based on various percentages of compensation, and in some instances, are based upon the amount of the employees' contributions. For 2005, 2004 and 2003, EOG's total contributions to these pension plans amounted to $12 million, $11 million and $8 million, respectively.

In addition, EOG's Canadian subsidiary maintains both a contributory defined benefit pension plan and a non-contributory defined contribution pension plan, as well as a matched defined contribution savings plan. EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan. With the exception of Canada's contributory defined benefit pension plan, which is closed to new employees, these pension plans are available to most employees of the Canadian and Trinidadian subsidiaries. EOG's combined contributions to these pension plans were approximately $2.0 million, $0.9 million and $0.5 million for 2005, 2004 and 2003, respectively.

The benefit obligation, fair value of plan assets and prepaid (accrued) benefit cost of the defined benefit pension plans totaled $6.4 million, $5.3 million and ($1.1) million, respectively, at December 31, 2005 and $1.0 million, $1.4 million and $0.2 million, respectively, at December 31, 2004. Weighted average discount rate and expected return on plan assets assumptions used to determine benefit obligations for the pension plans were 5.54% and 4.18%, respectively, at December 31, 2005 and 6.50% and 5.50%, respectively, at December 31, 2004. Weighted average discount rate assumptions used to determine net periodic benefit cost for the pension plans for the years ended December 31, 2005, 2004 and 2003 were 6.50%, 6.50% and 8.00%, respectively. The weighted average asset allocation of the pension plans at December 31, 2005 consisted of equities (57%), debt and fixed income securities (38%) and other assets (5%). The asset allocation at December 31, 2004 consisted of equities (54%), debt and fixed income securities (39%) and other (7%).

The investment policy for the defined benefit pension plan in Trinidad is determined by the pension plan's trustee, with input from EOG. The plan's asset allocation policy is largely dictated by local statutory requirements which restricts total investment in equities to a maximum of 50% of the plan's assets and investment overseas to 20% of the plan's assets. The investment policy for the defined benefit pension plan in Canada provides that EOG shall invest the plan assets in one or more of Canadian balanced funds and in one or more foreign equity funds as deemed appropriate for the purposes of diversification.

EOG's United Kingdom subsidiary introduced a pension plan as of January 2005, which includes a non-contributory defined contribution pension plan and a matched defined contribution savings plan. The pension plan is available to all employees of the United Kingdom subsidiary. EOG's combined contributions to these pension plans were approximately $0.1 million for 2005.

Postretirement Health Care

EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents.  EOG accrues these postretirement benefit costs over the service lives of the employees expected to be eligible to receive such benefits.

The benefit obligation and accrued benefit cost for the postretirement benefit plans totaled $3.4 million and $2.0 million, respectively, at December 31, 2005 and $2.1 million and $1.7 million, respectively, at December 31, 2004. Weighted average discount rate assumptions used to determine benefit obligations for the postretirement plans at December 31, 2005 and 2004 were 5.67% and 5.98%, respectively. Weighted average discount rate assumptions used to determine net periodic benefit cost for the years ended December 31, 2005, 2004 and 2003 were 5.98%, 6.15% and 6.40% for the postretirement plans. Net periodic benefit cost recognized for the postretirement benefit plans totaled $0.4 million, $0.5 million and $0.4 million for the years ended December 31, 2005, 2004 and 2003.

Accrued/(prepaid) benefit cost recognized in the Consolidated Balance Sheets at December 31, 2005 and 2004 totaled $1.1 million and ($0.2) million, respectively, for the pension plan and $2.0 million and $1.7 million, respectively, for the postretirement plan.

F-21

Estimated Future Employer-Paid Benefits. The following benefits, which reflect expected future service, as appropriate, are expected to be paid by EOG in the next 10 years (in thousands):

    Pension   Postretirement
    Plans   Plans

2006

$

161

$

121

2007

 

196

 

135

2008

 

197

 

146

2009

 

229

 

186

2010

 

285

 

211

2011 - 2015

 

1,700

 

1,585

 

Postretirement health care trend rates have minimal effect on the amounts reported for the postretirement health care plans for both 2005 and 2004. Most increases or decreases in healthcare costs would be borne by the employee.

Stock Plans

EOG has various stock plans (Plans) under which employees and non-employee members of the Board of Directors of EOG and its subsidiaries have been or may be granted certain equity compensation. Since the inception of the Plans, there have been 31,445,000 shares authorized for grant. At December 31, 2005, 5,606,109 shares remain available for grant.

Stock Options. Under the Plans, participants have been or may be granted rights to purchase shares of common stock of EOG at a price not less than the market price of the stock at the date of grant. Stock options granted under the Plans vest either immediately at the date of grant or up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements. Terms for stock options granted under the Plans have not exceeded a maximum term of 10 years.

Certain of EOG's stock options issued in 2005 and 2004 contain a feature that limits the potential gain that can be realized by requiring vested options to be exercised if the market price reaches 200% of the grant price for five consecutive trading days (Capped Option). EOG may or may not issue Capped Options in the future.

The following table sets forth the option transactions for the years ended December 31 (options in thousands):

 

2005

 

2004

 

2003

   

Average

   

Average

   

Average

   

Grant

   

Grant

   

Grant

 

Options

Price

 

Options

Price

 

Options

Price

                 

Outstanding at January 1

11,922 

$19.66

 

15,497 

$15.19

 

15,674 

$13.66

Granted

1,823 

61.57

 

2,619 

31.97

 

3,029 

19.57

Exercised

(3,804)

17.61

 

(5,922)

13.43

 

(2,971)

11.37

Forfeited

(243)

28.86

 

(272)

19.34

 

(235)

17.37

Outstanding at December 31

9,698 

28.12

 

11,922 

19.66

 

15,497 

15.19

                 

Options Exercisable at December 31

4,575 

16.61

 

6,104 

15.18

 

9,861 

13.52

                 

Available for Future Grant

5,606 

   

7,418 

   

2,355 

 

EOG adopted SFAS No. 123(R) effective January 1, 2006 (see Note 1) and as a result, EOG expects the expensing of the stock options would reduce 2006 net earnings by a pre-tax amount of approximately $24 million.

F-22

The following table summarizes certain information for the options outstanding at December 31, 2005 (options in thousands):

 

Options Outstanding

 

Options Exercisable

   

Weighted

 

Weighted

     

Weighted

   

Average

 

Average

     

Average

   

Remaining

 

Grant

     

Grant

Range of Grant Prices

Options

Life (Years)

 

Price

 

Options

 

Price

                 

$7.00 to $14.99

726

3

 

$  8.88

 

726

 

$  8.88

15.00 to  16.99

2,139

6

 

16.72

 

1,604

 

16.68

17.00 to  19.99

2,926

7

18.81

1,954

18.48

20.00 to  31.99

452

7

 

24.00

 

290

 

22.95

32.00 to  48.99

1,782

9

 

33.34

 

1

 

36.55

49.00 to  78.99

1,673

7

 

62.86

 

-

 

62.98

 

9,698

6

 

28.12

 

4,575

 

16.61

During 2005, 2004 and 2003, EOG repurchased approximately 155,000, 320,000 and 1,252,000 of its common shares, respectively. The difference between the cost of the treasury shares and the exercise price of the options, net of federal income tax benefit of $51 million, $29 million and $12 million, for 2005, 2004 and 2003, respectively, is reflected as an adjustment to additional paid in capital to the extent EOG has accumulated additional paid in capital relating to treasury stock and to retained earnings thereafter.

Restricted Stock and Units. Under the Plans, employees may be granted restricted stock and/or units without cost to them. The shares and units granted vest to the employee at various times ranging from one to five years from the date of grant based on the nature of the grants and as defined in individual grant agreements. Upon vesting, restricted shares are released to the employee. Upon vesting, each restricted unit is converted into one share of common stock and released to the employee. The following summarizes shares of restricted stock and units granted for the three years ended December 31 (shares and units in thousands):

   

Restricted Shares and Units

   

2005

 

2004

 

2003

             

Outstanding at January 1

 

2,566 

 

2,052 

 

1,550 

Granted

 

385 

 

659 

 

744 

Released

 

(353)

 

(82)

 

(206)

Forfeited or Expired

 

(54)

 

(63)

 

(36)

Outstanding at December 31

 

2,544 

 

2,566 

 

2,052 

Average Fair Value of Shares Granted During Year

$

52.19 

$

25.71 

$

20.21 

The fair value of the restricted shares and units at date of grant has been recorded in shareholders' equity as unearned compensation and is being amortized over the vesting period as compensation expense. Related compensation expense for 2005, 2004 and 2003 was $12 million, $10 million and $6 million, respectively.

F-23

Employee Stock Purchase Plan. EOG has an Employee Stock Purchase Plan (ESPP) in place that allows eligible employees to semi-annually purchase, through payroll deductions, shares of EOG common stock at 85 percent of the fair market value at specified dates. Contributions to the ESPP are limited to 10 percent of the employees' pay (subject to certain ESPP limits) during each of the two six-month offering periods. As of December 31, 2005, approximately 407,400 common shares remained available for issuance under the ESPP. EOG adopted SFAS No. 123(R) effective January 1, 2006 (see Note 1) and as a result, EOG expects the expense associated with the ESPP would reduce 2006 net earnings by a pre-tax amount of approximately $1 million.

The following table summarizes ESPP activities for the years ended December 31 (in thousands, except number of participants):

 

2005

2004

2003

       

Approximate Number of Participants

580

450

410

Shares Purchased

106

136

148

Aggregate Purchase Price

$3,889

$3,021

$2,599

7. Commitments and Contingencies

Letters of Credit. At December 31, 2005, EOG had standby letters of credit and guarantees outstanding totaling approximately $711 million of which $620 million represents guarantees of subsidiary indebtedness included under Note 2 "Long-Term Debt" and $91 million primarily represents guarantees of payment obligations on behalf of subsidiaries. At December 31, 2004, EOG had standby letters of credit and guarantees outstanding totaling approximately $433 million of which $370 million represents guarantees of subsidiary indebtedness and $63 million primarily represents guarantees of payment obligations on behalf of subsidiaries. As of February 22, 2006, there were no demands for payment under these guarantees.

Minimum Commitments. At December 31, 2005, total minimum commitments from long-term non-cancelable operating leases, drilling rig commitments, seismic purchase and other purchase obligations, and pipeline transportation service commitments, based on current pipeline transportation rates and the foreign currency exchange rates used to convert CAD and British Pounds into United States Dollars at December 31, 2005, are as follows (in thousands):

 

Total Minimum

 

Commitments

     

2006

$

166,132

2007 - 2009

 

228,565

2010 - 2011

 

67,154

2012 and beyond

 

89,376

 

$

551,227

Included in the table above are leases for buildings, facilities and equipment with varying expiration dates through 2016. Rental expenses associated with these leases amounted to $34 million, $26 million and $22 million for 2005, 2004 and 2003, respectively.

Contingencies. There are various suits and claims against EOG that have arisen in the ordinary course of business. Management believes that the chance that these suits and claims will individually, or in the aggregate, have a material adverse effect on the financial condition or results of operations of EOG is remote. When necessary, EOG has made accruals in accordance with SFAS No. 5, "Accounting for Contingencies," in order to provide for these matters.

F-24

8. Net Income Per Share Available to Common

The following table sets forth the computation of Net Income Per Share Available to Common for the years ended December 31 (in thousands, except per share data):

   

2005

 

2004

 

2003

             

Numerator for basic and diluted earnings per share -

           
 

Net Income Available to Common

$

1,252,144

$

613,963

$

419,113

Denominator for basic earnings per share -

           
 

Weighted average shares

 

238,797

 

233,751

 

229,194

Potential dilutive common shares -

           
 

Stock options

 

3,942

 

3,561

 

3,168

 

Restricted stock and units

 

1,236

 

1,064

 

675

Denominator for diluted earnings per share -

           
 

Adjusted weighted average shares

 

243,975

 

238,376

 

233,037

Net Income Per Share Available to Common

           
 

Basic

$

5.24

$

2.63

$

1.83

 

Diluted

$

5.13

$

2.58

$

1.80

9. Supplemental Cash Flow Information

Cash paid for interest and income taxes was as follows for the years ended December 31 (in thousands):

   

2005

 

2004

 

2003

             

Interest

$

60,467

$

60,967

$

62,472

Income taxes

 

335,628

 

56,654

 

26,330

10. Business Segment Information

EOG's operations are all natural gas and crude oil exploration and production related. SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," establishes standards for reporting information about operating segments in annual financial statements. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. EOG's chief operating decision making process is informal and involves the Chairman and Chief Executive Officer and other key officers. This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas in the United States and each of its significant international locations. For segment reporting purposes, the major United States producing areas have been aggregated as one reportable segment due to similarities in their operations as allowed by SFAS No. 131.

F-25

Financial information by reportable segment is presented below for the years ended December 31, or at December 31 (in thousands):

   

United

         

United

       
   

States

 

Canada

 

Trinidad

 

Kingdom

 

Other

 

Total

                         

2005

                       
 

Net Operating Revenues(1)

$

2,584,017

$

651,348 

$

280,622

$

104,226 

$

$

3,620,213

 

Depreciation, Depletion and Amortization

 

488,621

 

124,793 

 

24,781

 

16,063 

 

 

654,258

 

Operating Income

 

1,356,267

 

377,580 

 

204,133

 

53,835 

 

 

1,991,815

 

Interest Income

 

1,218

 

2,139 

 

4,510

 

 

 

7,867

 

Other Income (Expense)

 

19,351

 

(5,029)

 

17,631

 

(3,992)

 

 

27,961

 

Interest Expense, Net

 

38,683

 

22,843 

 

909

 

71 

 

 

62,506

 

Income Before Income Taxes

 

1,338,153

 

351,847 

 

225,365

 

49,772 

 

 

1,965,137

 

Income Tax Provision

 

485,523

 

110,794 

 

88,919

 

20,325 

 

 

705,561

 

Additions to Oil and Gas Properties, Excluding
   Dry Hole Costs

 

1,299,205

 

307,862 

 

42,384

 

10,500 

 

 

1,659,951

 

Net Oil and Gas Properties

 

4,009,700

 

1,757,123 

 

277,113

 

43,243 

 

 

6,087,179

 

Total Assets

 

5,176,701

 

1,958,655 

 

538,671

 

79,293 

 

 

7,753,320

2004

                       
 

Net Operating Revenues(2)

$

1,656,325

$

448,562 

$

153,377

$

12,961 

$

$

2,271,225

 

Depreciation, Depletion and Amortization

 

382,718

 

99,879 

 

20,022

 

1,784 

 

 

504,403

 

Operating Income (Loss)

 

682,619

 

222,155 

 

91,245

 

(16,824)

 

 

979,195

 

Interest Income

 

292

 

679 

 

659

 

 

 

1,630

 

Other Income (Expense)

 

1,072

 

(4,487)

 

10,892

 

838 

 

 

8,315

 

Interest Expense, Net

 

41,571

 

21,415 

 

-

 

142 

 

 

63,128

 

Income (Loss) Before Income Taxes

 

642,412

 

196,932 

 

102,796

 

(16,128)

 

 

926,012

 

Income Tax Provision (Benefit)

 

231,250

 

45,785 

 

31,414

 

(7,292)

 

 

301,157

 

Additions to Oil and Gas Properties, Excluding
   Dry Hole Costs

 

936,463

 

294,571 

 

59,205

 

34,303 

 

 

1,324,542

 

Net Oil and Gas Properties

 

3,276,718

 

1,515,414 

 

256,858

 

52,613 

 

 

5,101,603

 

Total Assets

 

3,727,231

 

1,600,486 

 

401,434

 

69,772 

 

 

5,798,923

2003

                       
 

Net Operating Revenues(3)

$

1,335,145

$

309,418 

$

100,112

$

$

$

1,744,675

 

Depreciation, Depletion and Amortization

 

359,439

 

66,334 

 

16,070

 

 

 

441,843

 

Operating Income (Loss)

 

487,133

 

163,783 

 

55,433

 

(9,195)

 

160 

 

697,314

 

Interest Income

 

1,385

 

950 

 

454

 

 

 

2,789

 

Other Income (Expense)

 

2,777

 

6,354 

 

3,418

 

(71)

 

 

12,484

 

Interest Expense, Net

 

43,421

 

14,618 

 

670

 

 

 

58,711

 

Income (Loss) Before Income Taxes

 

447,874

 

156,469 

 

58,635

 

(9,266)

 

164 

 

653,876

 

Income Tax Provision (Benefit)

 

163,359

 

36,190 

 

20,671

 

(3,486)

 

(134)

 

216,600

 

Additions to Oil and Gas Properties, Excluding
   Dry Hole Costs

 

605,667

 

552,164 

 

31,942

 

14,610 

 

 

1,204,383

 

Net Oil and Gas Properties

 

2,775,504

 

1,243,341 

 

215,376

 

14,696 

 

 

4,248,917

 

Total Assets

 

3,119,474

 

1,302,753 

 

309,727

 

17,061 

 

 

4,749,015

(1) EOG had sales activity with a single significant purchaser in the United States and Canada segments in 2005 that totaled $385 million of consolidated Net Operating Revenues.
(2) EOG had sales activity with a single significant purchaser in the United States and Canada segments in 2004 that totaled $280 million of consolidated Net Operating Revenues.
(3) EOG had sales activity with two significant purchasers, one totaled $222 million and the other totaled $182 million, of consolidated Net Operating Revenues in the United States and Canada segments in 2003.

F-26

11. Price, Interest Rate and Credit Risk Management Activities

Price and Interest Rate Risks. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collars and price swaps, as the means to manage this price risk. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchases and normal sales exception and therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

During 2005, 2004 and 2003, EOG elected not to designate any of its financial commodity derivative contracts as accounting hedges and accordingly, accounted for these financial commodity derivative contracts using mark-to-market accounting. During 2005, EOG recognized gains on mark-to-market financial commodity derivative contracts of $10 million, which included realized gains of $10 million. During 2004, EOG recognized losses on mark-to-market financial commodity derivative contracts of $33 million, which included realized losses of $82 million and collar premium payments of $1 million. During 2003, EOG recognized losses on mark-to-market financial commodity derivative contracts of $80 million, which included realized losses of $45 million and collar premium payments of $3 million.

Presented below is a summary of EOG's 2006 natural gas financial collar and price swap contracts at December 31, 2005 with prices expressed in dollars per million British thermal units ($/MMBtu) and notional volumes in million British thermal units per day (MMBtud). The total fair value of the natural gas financial collar and price swap contracts at December 31, 2005 was $11 million.

Natural Gas Financial Contracts

 

Collar Contracts

 

Price Swap Contracts

   

Floor Price

 

Ceiling Price

     
     

Weighted

   

Weighted

   

Weighted

     

Average

 

Ceiling

Average

   

Average

 

Volume

Floor Range

Price

 

Range

Price

 

Volume

Price

Month

(MMBtud)

($/MMBtu)

($/MMBtu)

 

($/MMBtu)

($/MMBtu)

 

(MMBtud)

($/MMBtu)

                   

February (closed)

50,000

$13.65 - 14.50

$14.05

 

$16.20 - 17.04

$16.59

 

-

-

March

50,000

13.50 - 14.30

13.87

 

15.95 - 17.05

16.46

 

-

-

April

50,000

10.00 - 10.50

10.23

 

12.60 - 13.00

12.77

 

20,000

$10.48

May

50,000

9.75 - 10.00

9.87

 

12.15 - 12.60

12.31

 

20,000

10.33

June

50,000

9.75 - 10.00

9.87

 

12.20 - 12.60

12.34

 

20,000

10.37

July

50,000

9.75 - 10.00

9.87

 

12.35 - 12.85

12.50

 

20,000

10.39

August

50,000

9.75 - 10.00

9.87

 

12.50 - 13.00

12.67

 

20,000

10.44

Presented below is a summary of EOG's 2006 natural gas financial collar and price swap contracts at February 22, 2006:

Natural Gas Financial Contracts

 

Collar Contracts

 

Price Swap Contracts

   

Floor Price

 

Ceiling Price

     
     

Weighted

   

Weighted

   

Weighted

     

Average

 

Ceiling

Average

   

Average

 

Volume

Floor Range

Price

 

Range

Price

 

Volume

Price

Month

(MMBtud)

($/MMBtu)

($/MMBtu)

 

($/MMBtu)

($/MMBtu)

 

(MMBtud)

($/MMBtu)

                   

February (closed)

50,000

$13.65 - 14.50

$14.05

 

$16.20 - 17.04

$16.59

 

-

-

March

50,000

13.50 - 14.30

13.87

 

15.95 - 17.05

16.46

 

170,000

$9.54

April

50,000

10.00 - 10.50

10.23

 

12.60 - 13.00

12.77

 

180,000

9.49

May

50,000

9.75 - 10.00

9.87

 

12.15 - 12.60

12.31

 

180,000

9.50

June

50,000

9.75 - 10.00

9.87

 

12.20 - 12.60

12.34

 

180,000

9.54

July

50,000

9.75 - 10.00

9.87

 

12.35 - 12.85

12.50

 

190,000

9.57

August

50,000

9.75 - 10.00

9.87

 

12.50 - 13.00

12.67

 

190,000

9.63

September

-

-

-

 

-

-

 

140,000

9.40

October

-

-

-

 

-

-

 

90,000

9.46

F-27

The following table summarizes the estimated fair value of financial instruments and related transactions at December 31 of the years indicated as follows (in millions):

   

2005

 

2004

   

Carrying

 

Estimated

 

Carrying

 

Estimated

   

Amount

 

Fair Value(1)

 

Amount

 

Fair Value(1)

                 

Current and Long-Term Debt(2)

$

985

$

1,025

$

1,078

$

1,146

NYMEX-Related Commodity Market Positions

 

11

 

11

 

11

 

11

(1) Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is required in interpreting
     market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts.
(2) See Note 2.

Credit Risk. While notional contract amounts are used to express the magnitude of commodity price and interest rate swap agreements, the amounts potentially subject to credit risk, in the event of nonperformance by the other parties, are substantially smaller. EOG evaluates its exposure to all counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit risk. At December 31, 2005, no individual purchaser's accounts receivable balance related to United States and Canada hydrocarbon sales accounted for 10% or more of the total balance. At December 31, 2004, EOG's net accounts receivable balance related to United States and Canada hydrocarbon sales included two receivable balances, each of which constituted 11% of the total balance. These receivables were due from two integrated oil and gas companies. The related amounts were collected during early 2005. No other individual purchaser accounted for 10% or more of the United States and Canada net accounts receivable balance at December 31, 2004. At December 31, 2005 and 2004, all of  EOG's Trinidad receivables from natural gas sales were from the National Gas Company of Trinidad and Tobago.

At December 31, 2005, EOG had an allowance for doubtful accounts of $22 million, of which $19 million is associated with the Enron bankruptcies recorded in December 2001.

Substantially all of EOG's accounts receivable at December 31, 2005 and 2004 resulted from hydrocarbon sales and/or joint interest billings to third party companies including foreign state-owned entities in the oil and gas industry. This concentration of customers and joint interest owners may impact EOG's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral or other credit enhancements from a customer or joint interest owner, EOG analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. During the three-year period ended December 31, 2005 credit losses incurred on receivables by EOG have been immaterial.

12. Accounting for Certain Long-Lived Assets

EOG reviews its oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. During 2005, 2004 and 2003, such reviews indicated that unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily to downward reserve revisions, drilling of marginal or uneconomic wells, or development dry holes in certain producing fields. As a result, EOG recorded pre-tax charges of $31 million, $17 million and $21 million, in the United States operating segment during 2005, 2004 and 2003, respectively, and $8 million and $4 million in the Canada operating segment during 2004 and 2003, respectively. There were no pre-tax charges recorded in the Canada operating segment in 2005. The pre-tax charges are included in Impairments on the Consolidated Statements of Income and Comprehensive Income. The carrying values for assets determined to be impaired were adjusted to estimated fair values based on projected future net cash flows discounted using EOG's risk-adjusted discount rate. Amortization expenses of lease acquisition costs of unproved properties, including amortization of capitalized interest, were $47 million, $57 million and $64 million for 2005, 2004 and 2003, respectively.

F-28

13. Accounting for Asset Retirement Obligations

EOG adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. The adoption of the statement resulted in an after-tax charge of $7 million, which was reported in the first quarter of 2003 as Cumulative Effect of Change in Accounting Principle. The following table presents the reconciliation of the beginning and ending aggregate carrying amount of short-term and long-term legal obligations associated with the retirement of oil and gas properties pursuant to SFAS No. 143 for 2005 (in thousands):

   

Asset Retirement Obligations

   

Short-Term

 

Long-Term

 

Total

             

Balance at December 31, 2004

$

6,970 

$

131,789 

$

138,759 

Liabilities Incurred

 

45 

 

8,404 

 

8,449 

Liabilities Settled

 

(3,559)

 

(2,406)

 

(5,965)

Accretions

 

183 

 

7,499 

 

7,682 

Revisions

 

(555)

 

10,068 

 

9,513 

Reclassifications

 

3,082 

 

(3,082)

 

Foreign Currency Translations

 

69 

 

2,981 

 

3,050 

Balance at December 31, 2005

$

6,235 

$

155,253 

$

161,488 

14. Investment in Caribbean Nitrogen Company Limited and Nitrogen (2000) Unlimited

EOG, through certain wholly owned subsidiaries, owns equity interests in two Trinidadian companies: CNCL and N2000. During the first quarters of 2005, 2004 and 2003, EOG completed separate share sale agreements whereby portions of the EOG subsidiaries' shareholdings in CNCL and N2000 were sold to a third party energy company. The sales left EOG with equity interests of 12% in CNCL and 10% in N2000 at December 31, 2005. The 2005 N2000 sale resulted in a pre-tax gain of $2 million. The 2003 and 2004 sales did not result in any gain or loss.

At December 31, 2005, the investment in CNCL was $18 million. CNCL commenced ammonia production in June 2002, and is currently producing approximately 1,900 metric tons of ammonia daily. At December 31, 2005, CNCL had a long-term debt balance of $173 million, which is non-recourse to CNCL's shareholders. EOG will be liable for its share of any post-completion deficiency funds, loans to fund the costs of operation, payment of principal and interest to the principal creditor and other cash deficiencies of CNCL up to $30 million, approximately $4 million of which is net to EOG's interest. The shareholders' agreement governing CNCL requires the consent of the holders of 90% or more of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOG is able to exercise significant influence over the operating and financial policies of CNCL and therefore, it accounts for the investment using the equity method. During 2005, EOG recognized equity income of $9 million and received cash dividends of $5 million from CNCL.

At December 31, 2005, the investment in N2000 was $16 million. N2000 commenced ammonia production in August 2004, and is currently producing approximately 2,100 metric tons of ammonia daily. At December 31, 2005, N2000 had a long-term debt balance of $197 million, which is non-recourse to N2000's shareholders. At December 31, 2005, EOG was liable for its share of any post-completion deficiency funds, loans to fund the costs of operation, payment of principal and interest to the principal creditor and other cash deficiencies of N2000 up to $30 million, approximately $3 million of which is net to EOG's interest. The shareholders' agreement governing N2000 requires the consent of the holders of 100% of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOG is able to exercise significant influence over the operating and financial policies of N2000 and therefore, it accounts for the investment using the equity method. During 2005, EOG recognized equity income of $7 million and received cash dividends of $2 million from N2000.

F-29

15. Property Acquisitions

On October 1, 2003, a Canadian subsidiary of EOG closed an asset purchase of natural gas properties in the Wintering Hills, Drumheller East and Twining areas of southeast Alberta from a subsidiary of Husky Energy Inc. for approximately $320 million. These properties are essentially adjacent to existing EOG operations or are properties in which EOG already had a working interest. The transaction was partially funded by commercial paper borrowings of $140.5 million on October 1, 2003. The remainder of the purchase price, $179.5 million, was funded by EOG's available cash balance. Subsequent to the closing, the purchase price was reduced by exercised preferential rights on the properties which totaled approximately $5 million. In late December 2003, a Canadian subsidiary of EOG closed another property acquisition for $46 million.

16. Suspended Well Costs

EOG's net changes in suspended well costs for the years ended December 31, 2005, 2004 and 2003, in accordance with FSP No. 19-1, "Accounting for Suspended Well Costs," are presented below (in thousands):

   

Year Ended December 31,

   

2005

 

2004

 

2003

             

Balance at January 1

$

20,520 

$

14,964 

$

11,738 

 

Additions Pending the Determination of Proved Reserves

 

18,533 

 

15,634 

 

10,143 

 

Reclassifications to Proved Properties

 

(9,245)

 

(6,206)

 

(7,184)

 

Charged to Dry Hole Costs

 

(2,267)

 

(4,295)

 

 

Foreign Currency Translation

 

327 

 

423 

 

267 

Ending Balance

$

27,868 

$

20,520 

$

14,964 

The following table provides an aging of suspended well costs for the years ended December 31, 2005, 2004 and 2003 (in thousands, except well count):

   

Year Ended December 31,

   

2005

   

2004

   

2003

 
                   

Capitalized exploratory well costs that have been

                 
 

capitalized for a period less than one year

$

14,878

 

$

16,270

 

$

10,519

 

Capitalized exploratory well costs that have been

                 
 

capitalized for a period greater then one year

 

12,990

(1)

 

4,250

(2)

 

4,445

(2)

 

   Total

$

27,868

 

$

20,520

 

$

14,964

 

Number of exploratory wells that have been capitalized

                 
 

for a period greater than one year

 

2

   

1

   

1

 

(1) Costs as of December 31, 2005 related to an outside operated, deepwater offshore Gulf of Mexico discovery ($4 million) and an outside operated, winter access
     only, Northwest Territories discovery in Northern Canada ($9 million). EOG is continuing to evaluate these discoveries and plans to drill an additional exploratory
     well in each discovery.
(2) Costs related to the deepwater offshore Gulf of Mexico discovery.

F-30

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands Except Per Share Data Unless Otherwise Indicated)
(Unaudited Except for Results of Operations for Oil and Gas Producing Activities)

 

Oil and Gas Producing Activities

The following disclosures are made in accordance with Statement of Financial Accounting Standards (SFAS) No. 69, "Disclosures about Oil and Gas Producing Activities":

Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.

Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and EOG's estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause EOG's share of future production from Canadian reserves to be materially different from that presented.

F-31

 

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Estimates of proved and proved developed reserves at December 31, 2005, 2004 and 2003 were based on studies performed by the engineering staff of EOG for all reserves. Opinions by DeGolyer and MacNaughton (D&M), independent petroleum consultants, for the years ended December 31, 2005, 2004 and 2003 covered producing areas containing 82%, 77% and 72%, respectively, of proved reserves of EOG on a net-equivalent-cubic-feet-of-gas basis. D&M's opinions indicate that the estimates of proved reserves prepared by EOG's engineering staff for the properties reviewed by D&M, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ materially from the estimates prepared by D&M. Such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the engineering staff of EOG. All reports by D&M were developed utilizing geological and engineering data provided by EOG.

No major discovery or other favorable or adverse event subsequent to December 31, 2005 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

The following tables set forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2005, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2005, as estimated by the engineering staff of EOG.

NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY

 

United

   

United

 
 

States

Canada

Trinidad

Kingdom

TOTAL

           

NET PROVED RESERVES

         
           

Natural Gas (Bcf)(1)

         

Net proved reserves at December 31, 2002

2,006.2 

777.9 

1,306.5 

4,090.6 

 

Revisions of previous estimates

(24.9)

(18.5)

(74.9)

(118.3)

 

Purchases in place

43.9 

361.0 

404.9 

 

Extensions, discoveries and other additions

345.5 

118.3 

129.3 

59.2 

652.3 

 

Sales in place

(30.8)

(30.8)

 

Production

(238.3)

(60.2)

(55.4)

(353.9)

Net proved reserves at December 31, 2003

2,101.6 

1,178.5 

1,305.5 

59.2 

4,644.8 

 

Revisions of previous estimates

(62.8)

(26.8)

34.2 

(55.4)

 

Purchases in place

44.4 

16.6 

61.0 

 

Extensions, discoveries and other additions

537.8 

208.0 

37.9 

783.7 

 

Sales in place

(1.3)

(0.6)

(1.9)

 

Production

(237.2)

(77.4)

(68.2)

(2.4)

(385.2)

Net proved reserves at December 31, 2004

2,382.5 

1,298.3 

1,309.4 

56.8 

5,047.0 

 

Revisions of previous estimates

(21.3)

3.1 

26.7 

(22.6)

(14.1)

 

Purchases in place

30.2 

30.2 

 

Extensions, discoveries and other additions

835.9 

104.7 

15.0 

955.6 

 

Sales in place

(11.8)

(11.8)

 

Production

(267.4)

(83.3)

(84.5)

(14.3)

(449.5)

Net proved reserves at December 31, 2005

2,948.1 

1,322.8 

1,251.6 

34.9 

5,557.4 

F-32

 

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

 

United

   

United

 
 

States

Canada

Trinidad

Kingdom

TOTAL

           

Liquids (MBbl)(2)

         

Net proved reserves at December 31, 2002

63,355 

7,166 

14,694 

85,215 

 

Revisions of previous estimates

1,487 

214 

(1,120)

581 

 

Purchases in place

738 

1,379 

2,117 

 

Extensions, discoveries and other additions

15,669 

598 

1,212 

84 

17,563 

 

Sales in place

(344)

(344)

 

Production

(7,897)

(1,091)

(881)

(9,869)

Net proved reserves at December 31, 2003

73,008 

8,266 

13,905 

84 

95,263 

 

Revisions of previous estimates

2,649 

(116)

3,417 

69 

6,019 

 

Purchases in place

157 

158 

 

Extensions, discoveries and other additions

9,859 

920 

229 

11,008 

 

Sales in place

(411)

(14)

(425)

 

Production

(9,474)

(1,290)

(1,291)

(9)

(12,064)

Net proved reserves at December 31, 2004

75,788 

7,767 

16,260 

144 

99,959 

 

Revisions of previous estimates

3,539 

1,361 

(1,444)

3,460 

 

Purchases in place

1,340 

1,340 

 

Extensions, discoveries and other additions

14,021 

915 

68 

15,004 

 

Sales in place

(410)

(410)

 

Production

(10,234)

(1,219)

(1,651)

(79)

(13,183)

Net proved reserves at December 31, 2005

84,044 

8,824 

13,165 

137 

106,170 

             

Bcf Equivalent (Bcfe)(1)

         

Net proved reserves at December 31, 2002

2,386.3 

820.9 

1,394.7 

4,601.9 

 

Revisions of previous estimates

(15.9)

(17.2)

(81.7)

(114.8)

 

Purchases in place

48.3 

369.3 

417.6 

 

Extensions, discoveries and other additions

439.6 

121.8 

136.5 

59.7 

757.6 

 

Sales in place

(32.9)

(32.9)

 

Production

(285.7)

(66.7)

(60.7)

(413.1)

Net proved reserves at December 31, 2003

2,539.7 

1,228.1 

1,388.8 

59.7 

5,216.3 

 

Revisions of previous estimates

(47.0)

(27.5)

54.8 

0.4 

(19.3)

 

Purchases in place

45.4 

16.6 

62.0 

 

Extensions, discoveries and other additions

597.0 

213.5 

39.3 

849.8 

 

Sales in place

(3.8)

(0.7)

(4.5)

 

Production

(294.1)

(85.1)

(75.9)

(2.5)

(457.6)

Net proved reserves at December 31, 2004

2,837.2 

1,344.9 

1,407.0 

57.6 

5,646.7 

 

Revisions of previous estimates

(0.1)

11.3 

18.1 

(22.6)

6.7 

 

Purchases in place

38.2 

38.2 

 

Extensions, discoveries and other additions

920.0 

110.2 

15.4 

1,045.6

 

Sales in place

(14.2)

(14.2)

 

Production

(328.7)

(90.7)

(94.4)

(14.8)

(528.6)

Net proved reserves at December 31, 2005

3,452.4 

1,375.7 

1,330.7 

35.6 

6,194.4 

F-33

 

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

 

United

   

United

 
 

States

Canada

Trinidad

Kingdom

TOTAL

           

NET PROVED DEVELOPED RESERVES

         

Natural Gas (Bcf)(1)

         
 

December 31, 2002

1,658.7

683.3

555.2

-

2,897.2

 

December 31, 2003

1,749.3

889.2

429.9

-

3,068.4

 

December 31, 2004

1,855.7

1,070.1

760.9

56.8

3,743.5

 

December 31, 2005

2,090.6

1,141.0

703.9

28.8

3,964.3

Liquids (MBbl)(2)

         
 

December 31, 2002

47,476

7,045

7,135

-

61,656

 

December 31, 2003

56,321

7,995

5,229

-

69,545

 

December 31, 2004

60,478

7,414

10,874

144

78,910

 

December 31, 2005

69,887

8,651

7,799

110

86,447

Bcf Equivalents (Bcfe)(1)

         
 

December 31, 2002

1,943.6

725.5

598.0

-

3,267.1

 

December 31, 2003

2,087.3

937.2

461.2

-

3,485.7

 

December 31, 2004

2,218.5

1,114.7

826.2

57.6

4,217.0

 

December 31, 2005

2,509.9

1,192.9

750.7

29.5

4,483.0

(1) Billion cubic feet or billion cubic feet equivalent, as applicable.
(2) Thousand barrels; includes crude oil, condensate and natural gas liquids.

Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the capitalized costs relating to EOG's natural gas and crude oil producing activities at December 31 of the years indicated as follows:

   

2005

 

2004

         

Proved properties

$

10,784,191 

$

9,307,422 

Unproved properties

 

389,198 

 

291,854 

 

Total

 

11,173,389 

 

9,599,276 

Accumulated depreciation, depletion

       

   and amortization

 

(5,086,210)

 

(4,497,673)

 

Net capitalized costs

$

6,087,179 

$

5,101,603 

 

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" and SFAS No. 143, "Accounting for Asset Retirement Obligations."

Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property.

Exploration costs include additions to exploration wells including those in progress and exploration expenses.

F-34

 

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Development costs include additions to production facilities and equipment and additions to development wells including those in progress.

The following tables set forth costs incurred related to EOG's oil and gas activities for the years ended December 31:

   

United

         

United

       
   

States

 

Canada

 

Trinidad

 

Kingdom

 

Other

 

TOTAL

                         

2005

                       

Acquisition Costs of Properties

                       
 

Unproved

$

102,727

$

24,278 

$

4,505

$

-

$

-

$

131,510 

 

Proved

 

55,477

 

468 

 

-

 

-

 

-

 

55,945 

   

Subtotal

 

158,204

 

24,746 

 

4,505

 

-

 

-

 

187,455 

Exploration Costs

 

286,862

 

42,426 

 

19,924

 

18,040

 

2,844

 

370,096 

Development Costs (1)

 

991,811

 

287,303 

 

25,769

 

15,259

 

-

 

1,320,142 

   

Total

$

1,436,877

$

354,475 

$

50,198

$

33,299

$

2,844

$

1,877,693 

2004

                       

Acquisition Costs of Properties

                       
 

Unproved

$

129,230

$

13,490 

$

74

$

-

$

-

$

142,794 

 

Proved

 

47,653

 

4,587 

 

-

 

-

 

-

 

52,240 

   

Subtotal

 

176,883

 

18,077 

 

74

 

-

 

-

 

195,034 

Exploration Costs

 

212,324

 

27,771 

 

35,227

 

27,818

 

3,443

 

306,583 

Development Costs (2)

 

666,443

 

277,045 

 

48,618

 

33,133

 

-

 

1,025,239 

Subtotal

1,055,650

322,893 

83,919

60,951

3,443

1,526,856 

Deferred Income Tax on

                       

Acquired Properties

 

-

 

(16,834)

 

-

 

-

 

-

 

(16,834)

   

Total

$

1,055,650

$

306,059 

$

83,919

$

60,951

$

3,443

$

1,510,022 

2003

                       

Acquisition Costs of Properties

                       
 

Unproved

$

43,890

$

14,536 

$

172

$

-

$

-

$

58,598 

 

Proved

 

18,347

 

386,532 

 

-

 

-

 

-

 

404,879 

   

Subtotal

 

62,237

 

401,068 

 

172

 

-

 

-

 

463,477 

Exploration Costs

 

145,104

 

15,429 

 

20,517

 

20,958

 

4,664

 

206,672 

Development Costs (3) (4)

 

488,424

 

149,091 

 

23,140

 

2,812

 

-

 

663,467 

   

Total

$

695,765

$

565,588 

$

43,829

$

23,770

$

4,664

$

1,333,616 

(1) Includes Asset Retirement Costs of $8 million, $11 million, $0 million and $1 million for the United States, Canada, Trinidad and the United Kingdom, respectively.
(2) Includes Asset Retirement Costs of $6 million, $7 million, $2 million and $2 million for the United States, Canada, Trinidad and the United Kingdom, respectively.
(3) Includes Asset Retirement Costs of $8 million, $4 million, $0 million and $0 million for the United States, Canada, Trinidad and the United Kingdom, respectively.
(4) Asset Retirement Costs for 2003 do not include the cumulative effect of adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003.

F-35

 

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Results of Operations for Oil and Gas Producing Activities(1). The following tables set forth results of operations for oil and gas producing activities for the years ended December 31:

United

United

States

Canada

Trinidad

Kingdom

Other(2)

TOTAL

2005

Natural Gas, Crude Oil, Condensate and

                       
 

Natural Gas Liquids Revenues

$

2,571,191

$

651,349 

$

280,622

$

103,828 

$

$

3,606,990

Other, Net

 

2,351

 

(1)

 

-

 

398 

 

 

2,748

   

Total

 

2,573,542

 

651,348 

 

280,622

 

104,226 

 

 

3,609,738

Exploration Costs

 

112,143

 

11,512 

 

5,243

 

4,218 

 

 

133,116

Dry Hole Costs

 

20,090

 

24,372 

 

2,571

 

17,779 

 

 

64,812

Production Costs

 

412,787

 

96,296 

 

39,135

 

10,061 

 

 

558,279

Impairments

 

70,879

 

7,053 

 

-

 

 

 

77,932

Depreciation, Depletion and Amortization

 

488,621

 

124,793 

 

24,781

 

16,063

 

 

654,258

Income Before Income Taxes

 

1,469,022

 

387,322 

 

208,892

 

56,105 

 

 

2,121,341

Income Tax Provision

 

527,646

 

138,365 

 

64,350

 

22,045 

 

-

 

752,406

Results of Operations

$

941,376

$

248,957 

$

144,542

$

34,060 

$

$

1,368,935

                             

2004

Natural Gas, Crude Oil, Condensate and

                       
 

Natural Gas Liquids Revenues

$

1,687,646

$

448,346 

$

153,377

$

12,972 

$

$

2,302,341

Other, Net

 

2,128

 

205 

 

-

 

 

 

2,333

   

Total

 

1,689,774

 

448,551 

 

153,377

 

12,972 

 

 

2,304,674

Exploration Costs

 

71,823

 

10,264 

 

7,109

 

4,745 

 

 

93,941

Dry Hole Costs

 

45,164

 

11,447 

 

15,851

 

19,680 

 

 

92,142

Production Costs

 

294,338

 

83,527 

 

14,670

 

1,790 

 

 

394,325

Impairments

 

68,309

 

13,221 

 

-

 

 

 

81,530

Depreciation, Depletion and Amortization

 

382,718

 

99,879 

 

20,022

 

1,784 

 

 

504,403

Income (Loss) Before Income Taxes

 

827,422

 

230,213 

 

95,725

 

(15,027)

 

 

1,138,333

Income Tax Provision (Benefit)

 

295,063

 

75,146 

 

33,953

 

(7,230)

 

 

396,932

Results of Operations

$

532,359

$

155,067 

$

61,772

$

(7,797)

$

$

741,401

                             

2003

                       

Natural Gas, Crude Oil, Condensate and

                       
 

Natural Gas Liquids Revenues

$

1,410,946

$

309,336 

$

100,112

$

$

$

1,820,394

Other, Net

 

4,613

 

82 

 

-

 

 

 

4,695

   

Total

 

1,415,559

 

309,418 

 

100,112

 

 

 

1,825,089

Exploration Costs

 

65,885

 

5,726 

 

3,997

 

739 

 

11 

 

76,358

Dry Hole Costs

 

20,706

 

4,139 

 

7,890

 

8,421 

 

 

41,156

Production Costs

 

219,447

 

58,249 

 

11,363

 

51 

 

 

289,112

Impairments

 

81,661

 

7,473 

 

-

 

 

(1)

 

89,133

Depreciation, Depletion and Amortization

 

359,439

 

66,334 

 

16,070

 

 

 

441,843

Income (Loss) Before Income Taxes

 

668,421

 

167,497 

 

60,792

 

(9,211)

 

(12)

 

887,487

Income Tax Provision (Benefit)

 

239,534

 

61,928 

 

24,661

 

(3,673)

 

(5)

 

322,445

Results of Operations

$

428,887

$

105,569 

$

36,131

$

(5,538)

$

(7)

$

565,042

(1) Excludes gains or losses on mark-to-market financial commodity derivative contracts, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2005.
(2) Other includes other international operations.

F-36

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the engineering staff of EOG. The estimates were based on commodity prices at year-end. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG.

The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's crude oil and natural gas reserves for the years ended December 31:

   

United

         

United

   
   

States

 

Canada

 

Trinidad

 

Kingdom

 

TOTAL

2005

                   
 

Future cash inflows(1)

$

29,570,753 

$

11,699,916 

$

4,355,408 

$

447,719 

$

46,073,796 

 

Future production costs

 

(7,623,688)

 

(2,824,960)

 

(617,551)

 

(50,027)

 

(11,116,226)

 

Future development costs

 

(1,565,491)

 

(362,191)

 

(268,306)

 

(12,482)

 

(2,208,470)

 

Future net cash flows before income taxes

 

20,381,574 

 

8,512,765 

 

3,469,551 

 

385,210 

 

32,749,100 

 

Future income taxes

 

(6,349,537)

 

(2,524,804)

 

(1,311,384)

 

(146,492)

 

(10,332,217)

 

Future net cash flows

 

14,032,037 

 

5,987,961 

 

2,158,167 

 

238,718 

 

22,416,883 

 

Discount to present value at 10% annual rate

 

(6,720,718)

 

(2,966,998)

 

(994,539)

 

(32,925)

 

(10,715,180)

 

Standardized measure of discounted

                   
   

future net cash flows relating

                   
   

to proved oil and gas reserves

$

7,311,319 

$

3,020,963 

$

1,163,628 

$

205,793 

$

11,701,703 

2004

                   
 

Future cash inflows

$

17,044,764 

$

7,530,192 

$

3,419,365 

$

312,843 

$

28,307,164 

 

Future production costs

 

(4,485,711)

 

(2,436,056)

 

(486,892)

 

(77,245)

 

(7,485,904)

 

Future development costs

 

(873,309)

 

(281,233)

 

(218,784)

 

(2,422)

 

(1,375,748)

 

Future net cash flows before income taxes

 

11,685,744 

 

4,812,903 

 

2,713,689 

 

233,176 

 

19,445,512 

 

Future income taxes

 

(3,583,378)

 

(1,295,774)

 

(986,977)

 

(60,010)

 

(5,926,139)

 

Future net cash flows

 

8,102,366 

 

3,517,129 

 

1,726,712 

 

173,166 

 

13,519,373 

 

Discount to present value at 10% annual rate

 

(3,795,487)

 

(1,570,232)

 

(809,757)

 

(25,919)

 

(6,201,395)

 

Standardized measure of discounted

                   
   

future net cash flows relating

                   
   

to proved oil and gas reserves

$

4,306,879 

$

1,946,897 

$

916,955 

$

147,247 

$

7,317,978 

2003

                   
 

Future cash inflows

$

14,030,539 

$

6,221,171 

$

2,995,951 

$

320,427 

$

23,568,088 

 

Future production costs

 

(3,026,650)

 

(1,289,592)

 

(449,200)

 

(47,524)

 

(4,812,966)

 

Future development costs

 

(524,401)

 

(200,324)

 

(228,504)

 

(21,289)

 

(974,518)

 

Future net cash flows before income taxes

 

10,479,488 

 

4,731,255 

 

2,318,247 

 

251,614 

 

17,780,604 

 

Future income taxes

 

(3,382,125)

 

(1,376,955)

 

(786,418)

 

(96,896)

 

(5,642,394)

 

Future net cash flows

 

7,097,363 

 

3,354,300 

 

1,531,829 

 

154,718 

 

12,138,210 

 

Discount to present value at 10% annual rate

 

(3,393,605)

 

(1,610,085)

 

(778,985)

 

(41,420)

 

(5,824,095)

 

Standardized measure of discounted

                   
   

future net cash flows relating

                   
   

to proved oil and gas reserves

$

3,703,758 

$

1,744,215 

$

752,844 

$

113,298 

$

6,314,115 

                         

(1) Estimated natural gas prices used to calculate 2005 future cash inflows for the United States, Canada, Trinidad and the United Kingdom were $8.46, $8.51, $2.84 and $12.65, respectively.
     Estimated liquids prices used to calculate 2005 future cash inflows for the United States, Canada, Trinidad and the United Kingdom were $55.08, $50.39, $61.16 and $50.46, respectively.

F-37

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2005:

   

United

         

United

   
   

States

 

Canada

 

Trinidad

 

Kingdom