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