EOG Resources Reports 2010 Results and Increases Dividend
- Delivers 9.5 Percent Year-Over-Year Production Growth - Fourth Quarter Crude Oil Revenues Surpass Natural Gas Revenues - Records Consistent Drilling Results Across 120-Mile Trend in South Texas Eagle Ford Crude Oil Window and Drills First Well in Liquids-Rich Natural Gas Window - Adds Permian Basin Wolfcamp Play to Suite of High Quality Crude Oil Assets - Reports Increased Confidence in Colorado DJ Basin Niobrara Crude Oil Play - Notes Strong Production Results from Bradford County Marcellus Shale - Continues Advancement of Kitimat LNG Project - Increases Total Company Proved Reserves 8.5 Percent at Attractive Finding Costs - Targets 49 Percent Total Liquids Production Growth and 9.5 Percent Total Company Production Growth in 2011 - Raises Dividend on Common Stock for 12th Time in 12 Years
HOUSTON, Feb. 17, 2011 /PRNewswire/ -- EOG Resources, Inc.
(EOG) today reported fourth quarter 2010 net income of $53.7 million, or $0.21 per share. This compares to fourth quarter 2009 net income of $400.4 million, or $1.58 per share. For the full year 2010, EOG reported net income of $160.7 million, or $0.63 per share, as compared to $546.6 million, or $2.17 per share, for the full year 2009.The results for the fourth quarter 2010 included a $122.3 million, net of tax ($0.48 per share) impairment of certain non-core North American onshore and offshore natural gas assets, gains on property dispositions of $98.8 million, net of tax ($0.39 per share) and a previously disclosed non-cash net loss of $43.9 million ($28.0 million after tax, or $0.11 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash outflow related to financial commodity contracts was $18.1 million ($11.6 million after tax, or $0.05 per share). Consistent with some analysts' practice of matching realizations to settlement months, and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the quarter was $92.0 million, or $0.36 per share. Adjusted non-GAAP net income for the fourth quarter 2009 was $234.3 million, or $0.92 per share.
On a similar basis, eliminating the items detailed in the attached table, adjusted non-GAAP net income for the full year 2010 was $296.4 million, or $1.16 per share, and for the full year 2009 was $754.5 million, or $3.00 per share. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)
2010 Operational Highlights
EOG's total company production increased 9.5 percent in 2010 over 2009. Total company liquids rose 33 percent, driven by a 35 percent increase in crude oil and condensate production and a 29 percent increase in natural gas liquids. For the full year 2010, total company revenues from crude oil, condensate and natural gas liquids exceeded those from natural gas. For the fourth quarter 2010, crude oil revenues surpassed those from natural gas with almost half of total company wellhead revenues emanating from crude oil.
In the United States, crude oil and condensate production increased 32 percent in 2010 over the prior year primarily from EOG's continued development of the North Dakota Bakken/Three Forks, the Fort Worth Barnett Combo and the South Texas Eagle Ford Plays. At year-end 2010, EOG ranked as the largest crude oil producer in both the North Dakota Bakken and South Texas Eagle Ford Plays.
'EOG has become a formidable onshore U.S. crude oil producer through early identification and extensive acreage capture in a number of premier horizontal resource plays,' said Mark G. Papa, Chairman and Chief Executive Officer.
Across its large acreage position in the mature crude oil window of the South Texas Eagle Ford, EOG drilled and completed numerous wells in the fourth quarter while still maintaining its 100 percent success rate. In the eastern part of EOG's acreage in Dewitt County, the Hansen Kullin Unit 2-H and 4-H were completed in December at peak rates of 1,625 and 1,700 barrels of oil per day (Bopd), respectively. On the west side of the play, the Naylor Jones Unit 86 #1H averaged over 870 Bopd for the first 30 days. In Atascosa County, the Peeler Ranch 4-H showed a peak crude oil production rate in excess of 1,300 Bopd. EOG has a 100 percent working interest in all these wells. During the quarter, EOG increased its prospective acreage in the mature crude oil window from 505,000 to 520,000 net acres.
'I continue to be pleased by the consistency of EOG's Eagle Ford results across our 120-mile long holdings,' said Papa. 'Our confidence in taking an early-mover role in this new play is being rewarded.'
In the fourth quarter, EOG drilled its first successful horizontal Eagle Ford well outside the crude oil window. The Tully C. Garner #100H, located southwest of EOG's established crude oil acreage in Webb County, began production at a pipeline restricted rate of 2.8 million cubic feet per day (MMcfd) of rich natural gas with 239 barrels per day of condensate. EOG has a 100 percent working interest in the well. EOG has 26,000 net acres in the liquids-rich natural gas window.
EOG expanded its inventory of organic horizontal liquids plays with first-mover drilling success in the West Texas Permian Basin Wolfcamp Shale. To date, EOG has drilled and completed four wells in this liquids-rich play where it holds 120,000 net acres in Irion and Crockett Counties. Across the Wolfcamp, EOG's production mix is projected to be 78 percent crude oil, condensate and natural gas liquids with 22 percent natural gas. Potential reserves are estimated to be at least 40 million barrels of oil equivalent (MMboe), net after royalty, from one of multiple potential productive intervals. During 2011, EOG plans to operate a three-rig Wolfcamp development drilling program.
Drilling results from Weld County, Colorado, have increased EOG's confidence in the economic viability of the DJ Basin Niobrara crude oil play. To date, EOG has focused drilling efforts on its 80,000 net acre Hereford Ranch prospect where it has drilled multiple successful wells. Most importantly, EOG has made progress in establishing productivity from the Niobrara rock by successfully converting it from one dependent on fractures to a more matrix-dominated play. This increases the likelihood that the Niobrara is another true crude oil resource play that can be developed with tighter spacing and a greater number of economic wells than originally estimated.
In the Fort Worth Barnett Shale Combo where it drilled over 230 net wells in 2010, EOG continues to make operational improvements that are increasing per well reserves and lowering individual well costs. The Ava Unit #1H and #2H were completed with initial production rates of 337 and 489 Bopd with 311 and 524 thousand cubic feet per day (Mcfd) of liquids-rich natural gas, respectively. The Hailey Unit #1H and #2H were completed with initial rates of 335 and 320 Bopd with 207 and 261 Mcfd, respectively. EOG has 100 percent working interest in all four Montague County wells. EOG plans to run an active drilling program in the Barnett Shale Combo again this year.
EOG has accumulated a 600,000 net acre position in the Bakken, primarily in North Dakota. Current activity is primarily focused outside the Bakken Core on Bakken Lite and Three Forks development and drilling. As previously reported, EOG had exceptional well results from McKenzie County, North Dakota, southwest of its Core Parshall Field. During the fourth quarter, the Mandaree 12-07H and Liberty 16-36 were completed to sales at initial net production rates of 1,559 and 1,066 Bopd, plus associated liquids-rich natural gas. EOG has 86 and 95 percent working interests, respectively, in the wells.
'By augmenting our existing suite of quality crude oil assets during 2010 with exploration success in the South Texas Eagle Ford, the DJ Basin Niobrara and the Permian Basin Wolfcamp Shale Plays, we made meaningful strides in EOG's transition to a more liquids-focused company,' said Papa. 'In addition, by applying the operational efficiencies we have developed, EOG is moving into a highly efficient manufacturing mode of development drilling in plays such as the North Dakota Bakken/Three Forks, Fort Worth Barnett Combo, South Texas Eagle Ford and Manitoba Waskada.'
Natural Gas Activity
EOG's North American natural gas production decreased 2 percent in 2010 from 2009. This retraction reflects not only EOG's continued transition to crude oil and liquids-rich drilling activities but is indicative of weak natural gas pricing fundamentals, as well as the sale of certain natural gas producing assets. In 2011, EOG plans to limit its dry gas drilling program to hold leases in the East Texas/North Louisiana Haynesville and Bossier, the Pennsylvania Marcellus and the British Columbia Horn River Basin Plays.
In the Marcellus Shale, EOG has approximately 210,000 net acres. On its 50,000 net acre position in Bradford County, EOG completed the Hoppaugh No. 3H using improved completion techniques. The well, in which EOG has a 96 percent working interest, tested at a rate of 14 MMcfd of natural gas. This is EOG's best producer in the field to date. Applying similar completion methodology in Clearfield County, EOG brought three wells to sales at rates that ranged from 7 to 9 MMcfd. EOG has a 50 percent working interest in these wells.
EOG is encouraged by early production results in the British Columbia Horn River Basin where its winter operations are being finalized. In addition, EOG and its partner continue to make progress on the Kitimat LNG export facility project with initial natural gas sales targeted for late 2015. EOG anticipates committing a percentage of its approximately 9 trillion cubic feet, net after royalty, of natural gas reserve potential in British Columbia for export through the terminal. Plans are to sell the LNG to international markets, primarily in Asia.
Reserves
EOG's total company proved reserves for 2010 increased 8.5 percent over the prior year from 1,796 to 1,950 MMBoe, all organic. Excluding the impact of property dispositions, total company and total North American net proved developed reserves increased 9.6 percent and 12.6 percent, respectively. Total liquids proved reserves increased from 17 percent to 28 percent of total proved reserves.
In 2010:
-- Total reserve replacement from all sources - the ratio of net reserve
additions from drilling, acquisitions, total revisions and
dispositions to total production - was 207 percent at a total reserve
replacement cost of $15.05 per barrel of oil equivalent (Boe), based
on exploration and development expenditures of $5,383 million. (Please
refer to the attached tables for the calculation of total reserve
replacement and total reserve replacement costs.)
-- Proved developed reserve replacement from drilling - the ratio of net
reserve additions from drilling to total production - was 180 percent.
-- In the United States, total reserve replacement from all sources was
339 percent at a reserve replacement cost of $12.96 per Boe based on
exploration and development expenditures of $4,676 million. (Please
refer to the attached tables for the calculation of United States
total reserve replacement and total reserve replacement costs.)
For the 23rd consecutive year, internal reserve estimates were within 5 percent of those prepared by the independent reserve engineering firm of DeGolyer and MacNaughton (D&M). For 2010, D&M prepared a complete independent engineering analysis of properties containing 77 percent of EOG's proved reserves on a Boe basis.
2011 Operational Plans and Targets
EOG is targeting total company production growth of 9.5 percent in 2011. Total liquids production is forecast to increase 49 percent, comprised of 55 percent crude oil growth and 34 percent natural gas liquids growth. In North America, natural gas production is expected to decrease 5 percent from 2010, reflecting the impact of producing property sales and a weak natural gas pricing environment. Estimated exploration and production expenditures for 2011 will range from $6.4 to $6.6 billion, including exploration, development and production facilities and midstream expenditures. To offset any funding gap between estimated cash flows and capital expenditures, EOG expects to sell approximately $1 billion of natural gas and midstream assets during 2011. With a continued focus on the balance sheet, EOG plans to maintain a net debt-to-total capitalization ratio below 35 percent at both year-end 2011 and 2012.
For the period March 1 through December 31, 2011, EOG has 425,000 million British thermal units per day (MMbtud) of natural gas financial price swap contracts in place at a weighted average price of $5.09 per million British thermal units (MMbtu), excluding unexercised swaptions. For the full year 2012, EOG has 250,000 MMbtud of natural gas financial price swap contracts in place at a weighted average price of $5.56 per MMbtu, excluding unexercised swaptions. For February 1 through December 31, 2011, EOG has 18,000 barrels per day (Bbld) of crude oil financial price swap contracts in place at a weighted average price of $90.69 per barrel. For the full year 2012, EOG has 2,000 Bbld of crude oil financial price swap contracts in place at a weighted average price of $100.50 per barrel.
Capital Structure
During 2010, total cash proceeds from the sale of acreage and natural gas producing assets were $673 million. At December 31, 2010, EOG's total debt outstanding was $5,223 million for a debt-to-total capitalization ratio of 34 percent. Taking into account cash on the balance sheet of $789 million at year-end, EOG's net debt was $4,434 million for a net debt-to-total capitalization ratio of 30 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (non-GAAP).)
Dividend Increase
Following an increase in the common stock dividend in 2010, EOG's Board of Directors has again increased the cash dividend on the common stock. Effective with the dividend payable on April 29, 2011, to holders of record as of April 15, 2011, the quarterly dividend on the common stock will be $0.16 per share, an increase of 3 percent over the previous indicated annual rate. The indicated annual rate of $0.64 per share reflects the 12th increase in 12 years.
Conference Call Scheduled for February 18, 2011
EOG's fourth quarter and full year 2010 results conference call will be available via live audio webcast at 8 a.m. Central standard time (9 a.m. Eastern standard time) on Friday, February 18, 2011. To listen, log on to http://www.eogresources.com/. The webcast will be archived on EOG's website through March 4, 2011.
EOG Resources, Inc. is one of the largest independent (non-integrated) oil and natural gas companies in the United States with proved reserves in the United States, Canada, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol 'EOG.'
This press release, including the accompanying forecast and benchmark commodity pricing information, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as 'expect,' 'anticipate,' 'estimate,' 'project,' 'strategy,' 'intend,' 'plan,' 'target,' 'goal,' 'may,' 'will' and 'believe' or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production or generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known and unknown risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
-- the timing and extent of changes in prices for natural gas, crude oil
and related commodities;
-- changes in demand for natural gas, crude oil and related commodities,
including ammonia and methanol;
-- the extent to which EOG is successful in its efforts to discover and
market reserves and to acquire natural gas and crude oil properties;
-- the extent to which EOG can optimize reserve recovery and economically
develop its plays utilizing horizontal and vertical drilling and
advanced completion technologies;
-- the extent to which EOG is successful in its efforts to economically
develop its acreage in, and to produce reserves and achieve
anticipated production levels from, its existing and future natural
gas and crude oil exploration and development projects, given the
risks and uncertainties inherent in drilling, completing and operating
natural gas and crude oil wells and the potential for interruptions of
production, whether involuntary or intentional as a result of market
or other conditions;
-- the availability, proximity and capacity of, and costs associated
with, gathering, processing, compression and transportation
facilities;
-- the availability, cost, terms and timing of issuance or execution of,
and competition for, mineral licenses and leases and governmental and
other permits and rights of way;
-- changes in government policies, laws and regulations, including
environmental and tax laws and regulations;
-- competition in the oil and gas exploration and production industry for
employees and other personnel, equipment, materials and services and,
related thereto, the availability and cost of employees and other
personnel, equipment, materials and services;
-- EOG's ability to obtain access to surface locations for drilling and
production facilities;
-- the extent to which EOG's third-party-operated natural gas and crude
oil properties are operated successfully and economically;
-- EOG's ability to effectively integrate acquired natural gas and crude
oil properties into its operations, fully identify existing and
potential problems with respect to such properties and accurately
estimate reserves, production and costs with respect to such
properties;
-- weather, including its impact on natural gas and crude oil demand, and
weather-related delays in drilling and in the installation and
operation of production, gathering, processing, compression and
transportation facilities;
-- the ability of EOG's customers and other contractual counterparties to
satisfy their obligations to EOG and, related thereto, to access the
credit and capital markets to obtain financing needed to satisfy their
obligations to EOG;
-- EOG's ability to access the commercial paper market and other credit
and capital markets to obtain financing on terms it deems acceptable,
if at all;
-- the accuracy of reserve estimates, which by their nature involve the
exercise of professional judgment and may therefore be imprecise;
-- the timing and extent of changes in foreign currency exchange rates,
interest rates, inflation rates, global and domestic financial market
conditions and global and domestic general economic conditions;
-- political developments around the world, including in the areas in
which EOG operates;
-- the extent and effect of any hedging activities engaged in by EOG;
-- the timing and impact of liquefied natural gas imports;
-- the use of competing energy sources and the development of alternative
energy sources;
-- the extent to which EOG incurs uninsured losses and liabilities;
-- acts of war and terrorism and responses to these acts; and
-- the other factors described under Item 1A, 'Risk Factors,' on pages 14
through 19 of EOG's Annual Report on Form 10-K for the fiscal year
ended December 31, 2009.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
Effective January 1, 2010, the United States Securities and Exchange Commission (SEC) now permits oil and gas companies, in their filings with the SEC, to disclose not only 'proved' reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also 'probable' reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as 'possible' reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2009, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at http://www.sec.gov/.
EOG RESOURCES, INC.
FINANCIAL REPORT
----------------
(Unaudited; in millions, except per share data)
Three Months Ended
December 31,
------------
2010 2009
---- ----
Net Operating
Revenues $1,789.2 $1,760.9
======== ========
Net Income $53.7 $400.4
===== ======
Net Income Per
Share
Basic $0.21 $1.60
===== =====
Diluted $0.21 $1.58
===== =====
Average Number of
Shares
Outstanding
Basic 251.4 250.1
===== =====
Diluted 254.7 253.5
===== =====
Twelve Months Ended
December 31,
------------
2010 2009
---- ----
Net Operating
Revenues $6,099.9 $4,787.0
======== ========
Net Income $160.7 $546.6
====== ======
Net Income Per
Share
Basic $0.64 $2.20
===== =====
Diluted $0.63 $2.17
===== =====
Average Number of
Shares
Outstanding
Basic 250.9 249.0
===== =====
Diluted 254.5 251.9
===== =====
SUMMARY INCOME STATEMENTS
-------------------------
(Unaudited; in thousands, except per share data)
Three Months Ended
December 31,
------------
2010 2009
---- ----
Net Operating Revenues
Crude Oil and Condensate $630,433 $372,044
Natural Gas Liquids 147,595 90,198
Natural Gas 587,521 573,037
Gains (Losses) on Mark-
to-Market Commodity
Derivative Contracts (43,904) 25,927
Gathering, Processing and
Marketing 307,890 157,437
Gains on Property
Dispositions 151,097 534,926
Other, Net 8,528 7,293
----- -----
Total 1,789,160 1,760,862
--------- ---------
Operating Expenses
Lease and Well 190,783 157,002
Transportation Costs 98,871 77,485
Gathering and Processing
Costs 19,405 13,080
Exploration Costs 38,746 40,752
Dry Hole Costs 27,391 11,590
Impairments 239,782 123,911
Marketing Costs 292,477 159,556
Depreciation, Depletion
and Amortization 543,789 398,937
General and
Administrative 74,004 68,793
Taxes Other Than Income 89,301 55,648
------ ------
Total 1,614,549 1,106,754
--------- ---------
Operating Income 174,611 654,108
Other Income (Expense),
Net 6,333 (566)
----- ----
Income Before Interest
Expense and Income Taxes 180,944 653,542
Interest Expense, Net 41,371 27,307
------ ------
Income Before Income
Taxes 139,573 626,235
Income Tax Provision 85,900 225,808
------ -------
Net Income $53,673 $400,427
======= ========
Dividends Declared per
Common Share $0.155 $0.145
====== ======
Twelve Months Ended
December 31,
------------
2010 2009
---- ----
Net Operating Revenues
Crude Oil and Condensate $1,998,771 $1,089,711
Natural Gas Liquids 462,345 258,799
Natural Gas 2,420,099 2,050,963
Gains (Losses) on Mark-
to-Market Commodity
Derivative Contracts 61,912 431,757
Gathering, Processing and
Marketing 909,680 407,116
Gains on Property
Dispositions 223,538 535,436
Other, Net 23,551 13,177
------ ------
Total 6,099,896 4,786,959
--------- ---------
Operating Expenses
Lease and Well 698,430 579,290
Transportation Costs 385,189 283,329
Gathering and Processing
Costs 66,758 57,632
Exploration Costs 187,381 169,592
Dry Hole Costs 72,486 51,243
Impairments 742,647 305,832
Marketing Costs 884,212 397,375
Depreciation, Depletion
and Amortization 1,941,926 1,549,188
General and
Administrative 280,474 248,274
Taxes Other Than Income 317,074 174,363
------- -------
Total 5,576,577 3,816,118
--------- ---------
Operating Income 523,319 970,841
Other Income (Expense),
Net 14,243 2,071
------ -----
Income Before Interest
Expense and Income Taxes 537,562 972,912
Interest Expense, Net 129,586 100,901
------- -------
Income Before Income
Taxes 407,976 872,011
Income Tax Provision 247,322 325,384
------- -------
Net Income $160,654 $546,627
======== ========
Dividends Declared per
Common Share $0.620 $0.580
====== ======
EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
--------------------
(Unaudited)
Three Months Ended
December 31,
------------
2010 2009
---- ----
Wellhead Volumes and Prices
---------------------------
Crude Oil and Condensate Volumes
(MBbld) (A)
United States 74.4 52.0
Canada 8.6 5.5
Trinidad 4.7 3.3
Other International (B) 0.1 0.1
--- ---
Total 87.8 60.9
==== ====
Average Crude Oil and Condensate
Prices ($/Bbl) (C)
United States $80.38 $67.61
Canada 75.47 68.92
Trinidad 74.36 63.44
Other International (B) 74.29 63.64
Composite 79.55 67.50
Natural Gas Liquids Volumes
(MBbld) (A)
United States 35.7 23.3
Canada 0.8 1.1
--- ---
Total 36.5 24.4
==== ====
Average Natural Gas Liquids
Prices ($/Bbl) (C)
United States $43.95 $40.29
Canada 44.98 39.31
Composite 43.97 40.25
Natural Gas Volumes (MMcfd) (A)
United States 1,241 1,075
Canada 185 225
Trinidad 340 294
Other International (B) 12 13
--- ---
Total 1,778 1,607
===== =====
Average Natural Gas Prices
($/Mcf) (C)
United States $3.78 $4.21
Canada 3.30 4.41
Trinidad 2.99 2.26
Other International (B) 5.91 3.96
Composite 3.59 3.88
Crude Oil Equivalent Volumes
(MBoed) (D)
United States 317.0 254.4
Canada 40.3 44.1
Trinidad 61.3 52.3
Other International (B) 2.0 2.3
--- ---
Total 420.6 353.1
===== =====
Total MMBoe (D) 38.7 32.5
Twelve Months Ended
December 31,
------------
2010 2009
---- ----
Wellhead Volumes and Prices
---------------------------
Crude Oil and Condensate Volumes
(MBbld) (A)
United States 63.2 47.9
Canada 6.7 4.1
Trinidad 4.7 3.1
Other International (B) 0.1 0.1
--- ---
Total 74.7 55.2
==== ====
Average Crude Oil and Condensate
Prices ($/Bbl) (C)
United States $74.88 $54.42
Canada 72.66 57.72
Trinidad 68.80 50.85
Other International (B) 73.11 53.07
Composite 74.29 54.46
Natural Gas Liquids Volumes
(MBbld) (A)
United States 29.5 22.5
Canada 0.9 1.1
--- ---
Total 30.4 23.6
==== ====
Average Natural Gas Liquids
Prices ($/Bbl) (C)
United States $41.68 $30.03
Canada 43.40 30.49
Composite 41.73 30.05
Natural Gas Volumes (MMcfd) (A)
United States 1,133 1,134
Canada 200 224
Trinidad 341 273
Other International (B) 14 14
--- ---
Total 1,688 1,645
===== =====
Average Natural Gas Prices
($/Mcf) (C)
United States $4.30 $3.72
Canada 3.91 3.85
Trinidad 2.65 1.73
Other International (B) 4.90 4.34
Composite 3.93 3.42
Crude Oil Equivalent Volumes
(MBoed) (D)
United States 281.5 259.4
Canada 40.9 42.6
Trinidad 61.5 48.5
Other International (B) 2.5 2.4
--- ---
Total 386.4 352.9
===== =====
Total MMBoe (D) 141.1 128.8
(A) Thousand barrels per day or million cubic feet per day, as
applicable.
(B) Other International includes EOG's United Kingdom and China
operations.
(C) Dollars per barrel or per thousand cubic feet, as applicable.
Excludes the impact of financial commodity derivative instruments.
(D) Thousand barrels of oil equivalent per day or million barrels of
oil equivalent, as applicable; includes crude oil and condensate,
natural gas liquids and natural gas. Crude oil equivalents are
determined using the ratio of 1.0 barrel of crude oil and condensate
or natural gas liquids to 6.0 thousand cubic feet of natural gas.
MMBoe is calculated by multiplying the MBoed amount by the number of
days in the period and then dividing that amount by one thousand.
EOG RESOURCES, INC.
SUMMARY BALANCE SHEETS
----------------------
(Unaudited; in thousands, except share data)
December
December 31, 31,
2010 2009
---- ----
ASSETS
Current Assets
Cash and Cash Equivalents $788,853 $685,751
Accounts Receivable, Net 1,113,279 771,417
Inventories 415,792 261,723
Assets from Price Risk
Management Activities 48,153 20,915
Income Taxes Receivable 54,916 37,009
Deferred Income Taxes 9,260 -
Other 97,193 62,726
------ ------
Total 2,527,446 1,839,541
Property, Plant and Equipment
Oil and Gas Properties
(Successful Efforts Method) 29,263,809 24,614,311
Other Property, Plant and
Equipment 1,733,073 1,350,132
Total Property, Plant and
Equipment 30,996,882 25,964,443
Less: Accumulated
Depreciation, Depletion and
Amortization (12,315,982) (9,825,218)
----------- ----------
Total Property, Plant and
Equipment, Net 18,680,900 16,139,225
Other Assets 415,887 139,901
Total Assets $21,624,233 $18,118,667
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable $1,664,944 $979,139
Accrued Taxes Payable 82,168 92,858
Dividends Payable 38,962 36,286
Liabilities from Price Risk
Management Activities 28,339 27,218
Deferred Income Taxes 41,703 35,414
Current Portion of Long-Term
Debt 220,000 37,000
Other 143,983 137,645
Total 2,220,099 1,345,560
Long-Term Debt 5,003,341 2,760,000
Other Liabilities 667,455 632,652
Deferred Income Taxes 3,501,706 3,382,413
Commitments and Contingencies
Stockholders' Equity
Common Stock, $0.01 Par,
640,000,000 Shares
Authorized and
254,223,521 Shares Issued at
December 31, 2010 and
252,627,177 Shares Issued at
December 31, 2009 202,542 202,526
Additional Paid In Capital 729,992 596,702
Accumulated Other
Comprehensive Income 440,071 339,720
Retained Earnings 8,870,179 8,866,747
Common Stock Held in
Treasury, 146,186 Shares at
December 31, 2010
and 118,525 Shares at
December 31, 2009 (11,152) (7,653)
------- ------
Total Stockholders' Equity 10,231,632 9,998,042
---------- ---------
Total Liabilities and
Stockholders' Equity $21,624,233 $18,118,667
EOG RESOURCES, INC.
SUMMARY STATEMENTS OF CASH FLOWS
--------------------------------
(Unaudited; in thousands)
Twelve Months Ended
December 31,
------------
2010 2009
--- ---
Cash Flows from Operating
Activities
Reconciliation of Net Income
to Net Cash Provided by
Operating Activities:
Net Income $160,654 $546,627
Items Not Requiring
(Providing) Cash
Depreciation, Depletion and
Amortization 1,941,926 1,549,188
Impairments 742,647 305,832
Stock-Based Compensation
Expenses 107,378 95,180
Deferred Income Taxes 76,245 174,392
Gains on Property
Dispositions, Net (223,538) (535,436)
Other, Net (468) 6,761
Dry Hole Costs 72,486 51,243
Mark-to-Market Commodity
Derivative Contracts
Total Gains (61,912) (431,757)
Realized Gains 7,033 1,277,584
Excess Tax Benefits from
Stock-Based Compensation - (76,134)
Other, Net 17,273 18,862
Changes in Components of
Working Capital and Other
Assets and Liabilities
Accounts Receivable (339,126) (47,818)
Inventories (171,791) (50,146)
Accounts Payable 654,688 (153,565)
Accrued Taxes Payable (53,098) 90,929
Other Assets (32,169) (5,515)
Other Liabilities 19,342 (12,305)
Changes in Components of
Working Capital Associated
with Investing and
Financing Activities (208,968) 118,517
-------- -------
Net Cash Provided by
Operating Activities 2,708,602 2,922,439
Investing Cash Flows
Additions to Oil and Gas
Properties (5,210,612) (3,176,783)
Additions to Other Property,
Plant and Equipment (370,770) (326,226)
Acquisition of Galveston LNG
Inc. (210,000) -
Proceeds from Sales of Assets 672,593 212,000
Changes in Components of
Working Capital Associated
with Investing
Activities 208,933 (118,221)
Other, Net 7,082 (5,321)
----- ------
Net Cash Used in Investing
Activities (4,902,774) (3,414,551)
Financing Cash Flows
Long-Term Debt Borrowings 2,478,659 900,000
Long-Term Debt Repayments (37,000) -
Dividends Paid (153,240) (142,260)
Excess Tax Benefits from
Stock-Based Compensation - 76,134
Treasury Stock Purchased (11,295) (10,986)
Proceeds from Stock Options
Exercised and Employee Stock
Purchase Plan 34,560 20,465
Debt Issuance Costs (8,300) (8,895)
Other, Net 35 (296)
--- ----
Net Cash Provided by
Financing Activities 2,303,419 834,162
Effect of Exchange Rate
Changes on Cash (6,145) 12,390
------ ------
Increase in Cash and Cash
Equivalents 103,102 354,440
Cash and Cash Equivalents at
Beginning of Period 685,751 331,311
------- -------
Cash and Cash Equivalents at
End of Period $788,853 $685,751
======== ========
EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP)
-------------------------------------------------------------
TO NET INCOME (GAAP)
--------------------
(Unaudited; in thousands, except per share data)
The following chart adjusts three-month and twelve-month periods
ended December 31, 2010 and 2009 reported Net Income (GAAP) to
reflect actual net cash realized from financial commodity price
transactions by eliminating the unrealized mark-to-market gains
from these transactions, to add back impairment charges related to
certain of EOG's North American onshore and offshore natural gas
assets in the third and fourth quarters of 2010, to eliminate the
change in the estimated fair value of a contingent consideration
liability related to EOG's previously disclosed acquisition of
Haynesville and Bossier Shale unproved acreage, to eliminate the
gains on property dispositions primarily in the Rocky Mountain area
and to eliminate gains realized in the fourth quarter of 2009 on a
property exchange in the Rocky Mountain area and on the sale of
EOG's California assets. 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
December 31,
------------
2010 2009
---- ----
Reported Net Income
(GAAP) $53,673 $400,427
Mark-to-Market (MTM)
Commodity Derivative
Contracts Impact
Total (Gains) Losses 43,904 (25,927)
Realized Gains
(Losses) (18,147) 290,604
Subtotal 25,757 264,677
------ -------
After-Tax MTM Impact 16,424 169,976
------ -------
Add: Impairment of
Certain North
American Onshore and
Offshore Natural Gas
Assets, Net of Tax 122,344 -
Less: Gains on
Property
Dispositions, Net of
Tax (98,835) -
Less: Change in Fair
Value of Contingent
Consideration
Liability, Net of Tax (1,580) -
Less: Gain on Property
Exchange, Net of Tax - (244,248)
Less: Gain on Sale of
California Assets,
Net of Tax - (91,822)
--- -------
Adjusted Net Income
(Non-GAAP) $92,026 $234,333
======= ========
Net Income Per Share
(GAAP)
Basic $0.21 $1.60
===== =====
Diluted $0.21 $1.58
===== =====
Adjusted Net Income
Per Share (Non-GAAP)
Basic $0.37 $0.94
===== =====
Diluted $0.36 $0.92
===== =====
Average Number of
Shares
Basic 251,365 250,127
======= =======
Diluted 254,716 253,493
======= =======
Twelve Months Ended
December 31,
------------
2010 2009
---- ----
Reported Net Income
(GAAP) $160,654 $546,627
Mark-to-Market (MTM)
Commodity Derivative
Contracts Impact
Total (Gains) Losses (61,912) (431,757)
Realized Gains
(Losses) 7,033 1,277,584
Subtotal (54,879) 845,827
------- -------
After-Tax MTM Impact (35,203) 543,946
------- -------
Add: Impairment of
Certain North
American Onshore and
Offshore Natural Gas
Assets, Net of Tax 330,675 -
Less: Gains on
Property
Dispositions, Net of
Tax (145,216) -
Less: Change in Fair
Value of Contingent
Consideration
Liability, Net of Tax (14,521) -
Less: Gain on Property
Exchange, Net of Tax - (244,248)
Less: Gain on Sale of
California Assets,
Net of Tax - (91,822)
--- -------
Adjusted Net Income
(Non-GAAP) $296,389 $754,503
======== ========
Net Income Per Share
(GAAP)
Basic $0.64 $2.20
===== =====
Diluted $0.63 $2.17
===== =====
Adjusted Net Income
Per Share (Non-GAAP)
Basic $1.18 $3.03
===== =====
Diluted $1.16 $3.00
===== =====
Average Number of
Shares
Basic 250,876 248,996
======= =======
Diluted 254,500 251,884
======= =======
EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF DISCRETIONARY
CASH FLOW (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, 2010 and 2009 Net Cash Provided by Operating
Activities (GAAP) to Discretionary Cash Flow (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, and Changes in Components of Working Capital
Associated with Investing and Financing Activities. EOG management
uses this information for comparative purposes within the industry.
Three Months Ended
December 31,
------------
2010 2009
---- ----
Net Cash Provided by
Operating Activities
(GAAP) $622,875 $828,763
Adjustments
Exploration Costs
(excluding Stock-
Based Compensation
Expenses) 32,676 35,432
Excess Tax Benefits
from Stock-Based
Compensation - 42,082
Changes in Components
of Working Capital and
Other Assets and
Liabilities
Accounts Receivable 214,313 166,917
Inventories 37,610 26,554
Accounts Payable (127,270) (208,133)
Accrued Taxes Payable 12,994 (74,832)
Other Assets 16,118 1,260
Other Liabilities 25,006 21,662
Changes in Components
of Working Capital
Associated
with Investing and
Financing Activities (7,727) 28,580
------ ------
Discretionary Cash Flow
(Non-GAAP) $826,595 $868,285
======== ========
Twelve Months Ended
December 31,
------------
2010 2009
---- ----
Net Cash Provided by
Operating Activities
(GAAP) $2,708,602 $2,922,439
Adjustments
Exploration Costs
(excluding Stock-
Based Compensation
Expenses) 163,274 149,076
Excess Tax Benefits
from Stock-Based
Compensation - 76,134
Changes in Components
of Working Capital and
Other Assets and
Liabilities
Accounts Receivable 339,126 47,818
Inventories 171,791 50,146
Accounts Payable (654,688) 153,565
Accrued Taxes Payable 53,098 (90,929)
Other Assets 32,169 5,515
Other Liabilities (19,342) 12,305
Changes in Components
of Working Capital
Associated
with Investing and
Financing Activities 208,968 (118,517)
------- --------
Discretionary Cash Flow
(Non-GAAP) $3,002,998 $3,207,552
========== ==========
EOG RESOURCES, INC.
RESERVES SUPPLEMENTAL DATA
--------------------------
(Unaudited)
2010 NET PROVED RESERVES
RECONCILIATION SUMMARY
United North
CRUDE OIL & CONDENSATE (MMBbls) States Canada America
------ ------ -------
Beginning Reserves 188.4 25.6 214.0
Revisions (8.2) (0.1) (8.3)
Purchases in place - - -
Extensions, discoveries and other
additions 199.5 3.2 202.7
Sales in place (1.1) (0.6) (1.7)
Production (23.1) (2.5) (25.6)
----- ---- -----
Ending Reserves 355.5 25.6 381.1
===== ==== =====
NATURAL GAS LIQUIDS (MMBbls)
Beginning Reserves 91.5 2.0 93.5
Revisions 27.5 (0.2) 27.3
Purchases in place - - -
Extensions, discoveries and other
additions 42.2 - 42.2
Sales in place - - -
Production (10.8) (0.3) (11.1)
----- ---- -----
Ending Reserves 150.4 1.5 151.9
===== === =====
NATURAL GAS (Bcf)
Beginning Reserves 6,350.1 1,549.5 7,899.6
Revisions (222.7) (29.9) (252.6)
Purchases in place - - -
Extensions, discoveries and other
additions 821.3 3.4 824.7
Sales in place (34.6) (316.2) (350.8)
Production (422.6) (73.0) (495.6)
------ ----- ------
Ending Reserves 6,491.5 1,133.8 7,625.3
======= ======= =======
OIL EQUIVALENTS (MMBoe)
Beginning Reserves 1,338.3 285.8 1,624.1
Revisions (17.9) (5.3) (23.2)
Purchases in place - - -
Extensions, discoveries and other
additions 378.6 3.8 382.4
Sales in place (6.9) (53.3) (60.2)
Production (104.3) (14.9) (119.2)
------ ----- ------
Ending Reserves 1,587.8 216.1 1,803.9
======= ===== =======
Net Proved Developed Reserves
(MMBoe)
At December 31, 2009 744.3 124.3 868.6
At December 31, 2010 839.8 79.8 919.6
Net Proved Developed Reserves
(MMBoe) -Excluding Sales
At December 31, 2009 738.0 78.7 816.7
At December 31, 2010 839.8 79.8 919.6
2010 NET PROVED RESERVES
RECONCILIATION SUMMARY
Other
CRUDE OIL & CONDENSATE (MMBbls ) Trinidad Int'l
-------- -----
Beginning Reserves 5.4 0.1
Revisions (0.8) -
Purchases in place - -
Extensions, discoveries and other
additions 1.8 -
Sales in place - -
Production (1.7) -
---- ---
Ending Reserves 4.7 0.1
=== ===
NATURAL GAS LIQUIDS (MMBbls )
Beginning Reserves - -
Revisions - -
Purchases in place - -
Extensions, discoveries and other
additions - -
Sales in place - -
Production - -
--- ---
Ending Reserves - -
=== ===
NATURAL GAS (Bcf)
Beginning Reserves 985.8 12.7
Revisions (88.6) 1.9
Purchases in place - -
Extensions, discoveries and other
additions 63.0 7.9
Sales in place - -
Production (132.6) (5.2)
------ ----
Ending Reserves 827.6 17.3
===== ====
OIL EQUIVALENTS (MMBoe)
Beginning Reserves 169.7 2.2
Revisions (15.5) 0.3
Purchases in place - -
Extensions, discoveries and other
additions 12.3 1.3
Sales in place - -
Production (23.8) (0.9)
----- ----
Ending Reserves 142.7 2.9
===== ===
Net Proved Developed Reserves
(MMBoe)
At December 31, 2009 105.5 2.2
At December 31, 2010 90.4 3.0
Net Proved Developed Reserves
(MMBoe) -Excluding Sales
At December 31, 2009 105.5 2.2
At December 31, 2010 90.4 3.0
2010 NET PROVED RESERVES
RECONCILIATION SUMMARY
Total
CRUDE OIL & CONDENSATE (MMBbls ) Int'l Total
----- -----
Beginning Reserves 5.5 219.5
Revisions (0.8) (9.1)
Purchases in place - -
Extensions, discoveries and other
additions 1.8 204.5
Sales in place - (1.7)
Production (1.7) (27.3)
---- -----
Ending Reserves 4.8 385.9
=== =====
NATURAL GAS LIQUIDS (MMBbls )
Beginning Reserves - 93.5
Revisions - 27.3
Purchases in place - -
Extensions, discoveries and other
additions - 42.2
Sales in place - -
Production - (11.1)
--- -----
Ending Reserves - 151.9
=== =====
NATURAL GAS (Bcf)
Beginning Reserves 998.5 8,898.1
Revisions (86.7) (339.3)
Purchases in place - -
Extensions, discoveries and other
additions 70.9 895.6
Sales in place - (350.8)
Production (137.8) (633.4)
------ ------
Ending Reserves 844.9 8,470.2
===== =======
OIL EQUIVALENTS (MMBoe)
Beginning Reserves 171.9 1,796.0
Revisions (15.2) (38.4)
Purchases in place - -
Extensions, discoveries and other
additions 13.6 396.0
Sales in place - (60.2)
Production (24.7) (143.9)
----- ------
Ending Reserves 145.6 1,949.5
===== =======
Net Proved Developed Reserves
(MMBoe)
At December 31, 2009 107.7 976.3
At December 31, 2010 93.4 1,013.0
Net Proved Developed Reserves
(MMBoe) -Excluding Sales
At December 31, 2009 107.7 924.4
At December 31, 2010 93.4 1,013.0
EOG RESOURCES, INC.
RESERVES SUPPLEMENTAL DATA (CONTINUED)
--------------------------------------
(Unaudited)
2010 EXPLORATION AND
DEVELOPMENT
EXPENDITURES ($
Millions)
United North
States Canada America
------ ------ -------
Acquisition Cost of
Unproved Properties $400.7 $14.0 $414.7
Exploration Costs 454.4 38.6 493.0
Development Costs 3,821.2 414.7 4,235.9
------- ----- -------
Total Drilling 4,676.3 467.3 5,143.6
Acquisition Cost of
Proved Properties - - -
--- --- ---
Total Exploration &
Development
Expenditures 4,676.3 467.3 5,143.6
Gathering, Processing
and Other 369.6 210.7 580.3
Asset Retirement Costs 71.2 2.4 73.6
Non-Cash Acquisition
Costs 2.8 - 2.8
--- --- ---
Total Expenditures 5,119.9 680.4 5,800.3
Proceeds from Sales in
Place (325.9) (344.7) (670.6)
------ ------ ------
Net Expenditures $4,794.0 $335.7 $5,129.7
======== ====== ========
RESERVE REPLACEMENT
COSTS ($ /Boe ) *
Total Drilling, Before
Revisions $12.35 $122.97 $13.45
All-in Total, Net of
Revisions $12.96 $(311.53) $14.32
RESERVE REPLACEMENT *
Drilling Only 363% 26% 321%
All-in Total, Net of
Revisions &
Dispositions 339% -368% 251%
2010 EXPLORATION AND
DEVELOPMENT
EXPENDITURES ($
Millions)
Other
Trinidad Int'l
-------- -----
Acquisition Cost of
Unproved Properties $- $(0.1)
Exploration Costs 23.4 86.8
Development Costs 118.1 11.6
----- ----
Total Drilling 141.5 98.3
Acquisition Cost of
Proved Properties - -
--- ---
Total Exploration &
Development
Expenditures 141.5 98.3
Gathering, Processing
and Other 0.1 0.3
Asset Retirement
Costs (3.1) 1.8
Non-Cash Acquisition
Costs - -
--- ---
Total Expenditures 138.5 100.4
Proceeds from Sales
in Place (2.0) -
---- ---
Net Expenditures $136.5 $100.4
====== ======
RESERVE REPLACEMENT
COSTS ($ /Boe ) *
Total Drilling,
Before Revisions $11.50 $75.62
All-in Total, Net of
Revisions $(44.22) $61.44
RESERVE REPLACEMENT *
Drilling Only 52% 144%
All-in Total, Net of
Revisions &
Dispositions -13% 178%
2010 EXPLORATION AND
DEVELOPMENT
EXPENDITURES ($
Millions)
Total
Int'l Total
----- -----
Acquisition Cost of
Unproved Properties $(0.1) $414.6
Exploration Costs 110.2 603.2
Development Costs 129.7 4,365.6
----- -------
Total Drilling 239.8 5,383.4
Acquisition Cost of
Proved Properties - -
--- ---
Total Exploration &
Development
Expenditures 239.8 5,383.4
Gathering, Processing
and Other 0.4 580.7
Asset Retirement Costs (1.3) 72.3
Non-Cash Acquisition
Costs - 2.8
--- ---
Total Expenditures 238.9 6,039.2
Proceeds from Sales in
Place (2.0) (672.6)
---- ------
Net Expenditures $236.9 $5,366.6
====== ========
RESERVE REPLACEMENT
COSTS ($ /Boe ) *
Total Drilling, Before
Revisions $17.63 $13.59
All-in Total, Net of
Revisions $(149.88) $15.05
RESERVE REPLACEMENT *
Drilling Only 55% 275%
All-in Total, Net of
Revisions &
Dispositions -6% 207%
* See attached reconciliation schedule for calculation methodology
EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF TOTAL
EXPLORATION AND DEVELOPMENT
EXPENDITURES
-------------------------------------
FOR DRILLING ONLY (Non-GAAP) AND TOTAL
EXPLORATION AND DEVELOPMENT
EXPENDITURES (Non-GAAP)
---------------------------------------
AS USED IN THE CALCULATION OF RESERVE
REPLACEMENT COSTS ($ / 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
------ ------ -------
Total Costs
Incurred in
Exploration and
Development
Activities (GAAP) $4,750.3 $469.7 $5,220.0
Less: Asset
Retirement Costs (71.2) (2.4) (73.6)
Acquisition Cost
of Proved
Properties - - -
Non-Cash
Acquisition Costs (2.8) - (2.8)
---- --- ----
Total Exploration
& Development
Expenditures
for Drilling Only
(Non-GAAP) (a) $4,676.3 $467.3 $5,143.6
======== ====== ========
Total Costs
Incurred in
Exploration and
Development
Activities (GAAP) $4,750.3 $469.7 $5,220.0
Less: Asset
Retirement Costs (71.2) (2.4) (73.6)
Non-Cash
Acquisition Costs (2.8) - (2.8)
---- --- ----
Total Exploration
& Development
Expenditures
(Non-GAAP) (b) $4,676.3 $467.3 $5,143.6
======== ====== ========
Net Proved Reserve
Additions From
All Sources
-Oil Equivalents
(MMBoe)
Revisions due to
price (c) 15.7 14.5 30.2
Revisions other
than price (33.6) (19.8) (53.4)
Purchases in place - - -
Extensions,
discoveries and
other additions
(d) 378.6 3.8 382.4
----- --- -----
Total Proved
Reserve Additions
(e) 360.7 (1.5) 359.2
Sales in place (6.9) (53.3) (60.2)
---- ----- -----
Net Proved Reserve
Additions From
All Sources (f) 353.8 (54.8) 299.0
===== ===== =====
Production (g) 104.3 14.9 119.2
RESERVE
REPLACEMENT COSTS
($ /BOE)
Total Drilling,
Before Revisions
(a /d ) $12.35 $122.97 $13.45
All-in Total, Net
of Revisions (b /
e) $12.96 $(311.53) $14.32
All-in Total,
Excluding
Revisions Due to
Price (b /(e -
c )) $13.55 $(29.21) $15.63
RESERVE
REPLACEMENT
Drilling Only (d /
g ) 363% 26% 321%
All-in Total, Net
of Revisions &
Dispositions (f /
g ) 339% -368% 251%
All-in Total,
Excluding
Revisions Due to
Price ((f - c )
/g ) 324% -465% 226%
Other
Trinidad Int'l
-------- -----
Total Costs
Incurred in
Exploration and
Development
Activities (GAAP) $138.4 $100.1
Less: Asset
Retirement Costs 3.1 (1.8)
Acquisition Cost
of Proved
Properties - -
Non-Cash
Acquisition Costs - -
--- ---
Total Exploration
& Development
Expenditures
for Drilling Only
(Non-GAAP) (a) $141.5 $98.3
====== =====
Total Costs
Incurred in
Exploration and
Development
Activities (GAAP) $138.4 $100.1
Less: Asset
Retirement Costs 3.1 (1.8)
Non-Cash
Acquisition Costs - -
--- ---
Total Exploration
& Development
Expenditures
(Non-GAAP) (b) $141.5 $98.3
====== =====
Net Proved Reserve
Additions From
All Sources
-Oil Equivalents
(MMBoe)
Revisions due to
price (c) (2.0) -
Revisions other
than price (13.5) 0.3
Purchases in place - -
Extensions,
discoveries and
other additions
(d) 12.3 1.3
---- ---
Total Proved
Reserve Additions
(e) (3.2) 1.6
Sales in place - -
--- ---
Net Proved Reserve
Additions From
All Sources (f) (3.2) 1.6
==== ===
Production (g) 23.8 0.9
RESERVE
REPLACEMENT COSTS
($ /BOE)
Total Drilling,
Before Revisions
(a /d ) $11.50 $75.62
All-in Total, Net
of Revisions (b /
e) $(44.22) $61.44
All-in Total,
Excluding
Revisions Due to
Price (b /(e -
c )) $(117.92) $61.44
RESERVE
REPLACEMENT
Drilling Only (d /
g ) 52% 144%
All-in Total, Net
of Revisions &
Dispositions (f /
g ) -13% 178%
All-in Total,
Excluding
Revisions Due to
Price ((f - c )
/g ) -5% 178%
Total
Int'l Total
----- -----
Total Costs
Incurred in
Exploration and
Development
Activities (GAAP) $238.5 $5,458.5
Less: Asset
Retirement Costs 1.3 (72.3)
Acquisition Cost
of Proved
Properties - -
Non-Cash
Acquisition Costs - (2.8)
--- ----
Total Exploration
& Development
Expenditures
for Drilling Only
(Non-GAAP) (a) $239.8 $5,383.4
====== ========
Total Costs
Incurred in
Exploration and
Development
Activities (GAAP) $238.5 $5,458.5
Less: Asset
Retirement Costs 1.3 (72.3)
Non-Cash
Acquisition Costs - (2.8)
--- ----
Total Exploration
& Development
Expenditures
(Non-GAAP) (b) $239.8 $5,383.4
====== ========
Net Proved Reserve
Additions From
All Sources
-Oil Equivalents
(MMBoe)
Revisions due to
price (c) (2.0) 28.2
Revisions other
than price (13.2) (66.6)
Purchases in place - -
Extensions,
discoveries and
other additions
(d) 13.6 396.0
---- -----
Total Proved
Reserve Additions
(e) (1.6) 357.6
Sales in place - (60.2)
--- -----
Net Proved Reserve
Additions From
All Sources (f) (1.6) 297.4
==== =====
Production (g) 24.7 143.9
RESERVE
REPLACEMENT COSTS
($ /BOE)
Total Drilling,
Before Revisions
(a /d ) $17.63 $13.59
All-in Total, Net
of Revisions (b /
e) $(149.88) $15.05
All-in Total,
Excluding
Revisions Due to
Price (b /(e -
c )) $599.50 $16.34
RESERVE
REPLACEMENT
Drilling Only (d /
g ) 55% 275%
All-in Total, Net
of Revisions &
Dispositions (f /
g ) -6% 207%
All-in Total,
Excluding
Revisions Due to
Price ((f - c )
/g ) 2% 187%
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,
2010
----
Total Stockholders' Equity - (a) $10,232
-------
Current and Long-Term Debt - (b) 5,223
Less: Cash (789)
----
Net Debt (Non-GAAP) - (c) 4,434
-----
Total Capitalization (GAAP) -(a)
+ (b) $15,455
=======
Total Capitalization (Non-GAAP) -
(a) + (c) $14,666
=======
Debt-to-Total Capitalization
(GAAP) - (b) /[(a) + (b)] 34%
===
Net Debt-to-Total Capitalization
(Non-GAAP) - (c) /[(a) + (c)] 30%
===
EOG RESOURCES, INC.
FIRST QUARTER AND FULL YEAR 2011 FORECAST AND BENCHMARK COMMODITY
PRICING
-----------------------------------------------------------------
(a) First Quarter and Full Year 2011 Forecast
The forecast items for the first quarter and full year 2011 set forth
below for EOG Resources, Inc. (EOG) are based on current available
information and expectations as of the date of the accompanying
press release. This forecast replaces and supersedes any previously
issued guidance or forecast.
(b) Benchmark Commodity Pricing
EOG bases United States, Canada and Trinidad crude oil and condensate
price differentials upon the West Texas Intermediate crude oil price
at Cushing, Oklahoma, using the simple average of the NYMEX
settlement prices for each trading day within the applicable
calendar month.
EOG bases United States and Canada natural gas price differentials
upon the natural gas price at Henry Hub, Louisiana using the simple
average of the NYMEX settlement prices for the last three trading
days of the applicable month.
ESTIMATED RANGES
----------------
(Unaudited)
1Q 2011
-------
Daily Production
Crude Oil and Condensate Volumes
(MBbld)
United States 72.0 - 84.0
Canada 7.5 - 8.5
Trinidad 4.0 - 5.0
Total 83.5 - 97.5
Natural Gas Liquids Volumes
(MBbld)
United States 31.0 - 37.0
Canada 0.8 - 1.2
Total 31.8 - 38.2
Natural Gas Volumes (MMcfd)
United States 1,120 - 1,150
Canada 122 - 140
Trinidad 344 - 376
Other International 14 - 16
Total 1,600 - 1,682
Crude Oil Equivalent Volumes
(MBoed)
United States 289.7 - 312.7
Canada 28.6 - 33.0
Trinidad 61.3 - 67.7
Other International 2.3 - 2.7
Total 381.9 - 416.1
Operating Costs
Unit Costs ($/Boe)
Lease and Well $5.40 - $5.88
Transportation Costs $2.82 - $3.18
Depreciation, Depletion and
Amortization $14.88 - $15.96
Expenses ($MM)
Exploration, Dry Hole and
Impairment $115.0 - $130.0
General and Administrative $72.0 - $78.0
Gathering and Processing $16.0 - $20.0
Capitalized Interest $18.0 - $22.0
Net Interest $43.0 - $48.0
Taxes Other Than Income (% of
Revenue) 6.2% - 6.8%
Income Taxes
Effective Rate 35% - 50%
Current Taxes ($MM) $50 - $65
Capital Expenditures ($MM) -FY
2011 (Excluding Acquisitions)
Exploration and Development,
Excluding Facilities
Exploration and Development
Facilities
Gathering, Processing and Other
Pricing -(Refer to Benchmark
Commodity Pricing in text)
Natural Gas ($/Mcf)
Differentials (include the effect
of physical contracts)
United States -below NYMEX Henry
Hub $0.09 - $0.17
Canada -below NYMEX Henry Hub $0.45 - $0.60
Realizations
Trinidad $2.10 - $2.60
Other International $3.00 - $5.75
Crude Oil and Condensate ($/Bbl)
Differentials
United States - below WTI $4.00 - $6.00
Canada - below WTI $7.00 - $8.00
Trinidad - below WTI $8.00 - $12.00
ESTIMATED RANGES
----------------
(Unaudited)
Full Year 2011
--------------
Daily Production
Crude Oil and Condensate Volumes
(MBbld)
United States 94.2 - 114.2
Canada 7.0 - 9.5
Trinidad 2.5 - 4.1
Total 103.7 - 127.8
Natural Gas Liquids Volumes
(MBbld)
United States 34.8 - 44.8
Canada 0.7 - 0.9
Total 35.5 - 45.7
Natural Gas Volumes (MMcfd)
United States 1,133 - 1,170
Canada 100 - 133
Trinidad 307 - 330
Other International 12 - 16
Total 1,552 - 1,649
Crude Oil Equivalent Volumes
(MBoed)
United States 317.8 - 354.0
Canada 24.4 - 32.6
Trinidad 53.6 - 59.1
Other International 2.0 - 2.6
Total 397.8 - 448.3
Operating Costs
Unit Costs ($/Boe)
Lease and Well $5.16 - $5.64
Transportation Costs $3.06 - $3.42
Depreciation, Depletion and
Amortization $15.48 - $16.50
Expenses ($MM)
Exploration, Dry Hole and
Impairment $495.0 - $540.0
General and Administrative $315.0 - $335.0
Gathering and Processing $63.0 - $80.0
Capitalized Interest $75.0 - $90.0
Net Interest $170.0 - $190.0
Taxes Other Than Income (% of
Revenue) 5.6% - 6.5%
Income Taxes
Effective Rate 35% - 45%
Current Taxes ($MM) $215 - $235
Capital Expenditures ($MM) -FY
2011 (Excluding Acquisitions)
Exploration and Development,
Excluding Facilities $5,350 - $5,450
Exploration and Development
Facilities $550 - $600
Gathering, Processing and Other $500 - $550
Pricing -(Refer to Benchmark
Commodity Pricing in text)
Natural Gas ($/Mcf)
Differentials (include the effect
of physical contracts)
United States -below NYMEX Henry
Hub $0.03 - $0.15
Canada -below NYMEX Henry Hub $0.50 - $0.60
Realizations
Trinidad $2.00 - $2.60
Other International $5.00 - $5.70
Crude Oil and Condensate ($/Bbl)
Differentials
United States - below WTI $3.50 - $5.50
Canada - below WTI $6.60 - $7.50
Trinidad - below WTI $8.25 - $13.00
Definitions
-----------
$/Bbl U.S. Dollars per barrel
$/Boe U.S. Dollars per barrel equivalent
$/Mcf U.S. Dollars per thousand cubic feet
$MM U.S. Dollars in millions
MBbld Thousand barrels per day
Mboed Thousand barrels equivalent per day
MMcfd Million cubic feet per day
NYMEX New York Mercantile Exchange
WTI West Texas Intermediate
EOG Resources, Inc.
CONTACT: Investors, Maire A. Baldwin, +1-713-651-6EOG, (651-6364), or
Elizabeth M. Ivers, +1-713-651-7132, or Media, K Leonard, +1-713571-3870, all
of EOG Resources, Inc.
Web Site: http://www.eogresources.com/
