EOG Resources Reports First Quarter 2011 Results
HOUSTON, May 5, 2011 /PRNewswire/ --
-- Reports 14 Percent Year-Over-Year Total Company Production Growth
-- Delivers 47 Percent Total Company Crude Oil, Condensate and Natural
Gas Liquids Production Growth Over First Quarter 2010
-- Increases United States Crude Oil Volumes by 50 Percent Year-Over-Year
-- Drills Successful New Eagle Ford Fault Block Well Reaffirming
Consistent Results from 120-Mile Acreage Stake
-- Raises Confidence Level in Niobrara Crude Oil Play
-- Announces New Powder River Basin Play
-- Completes Second High-Rate Bradford County Marcellus Natural Gas Well
-- On Track to Sell Approximately $1 Billion of Assets in 2011
EOG Resources, Inc.
(EOG) today reported first quarter 2011 net income of $134.0 million, or $0.52 per share. This compares to first quarter 2010 net income of $118.0 million, or $0.46 per share.Consistent with some analysts' practice of matching cash flow 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 $177.0 million, or $0.68 per share. Adjusted non-GAAP net income for the first quarter 2010 was $117.8 million, or $0.46 per share. The results for the first quarter 2011 included a $30.3 million, net of tax ($0.12 per share) impairment of certain non-core United States natural gas assets, gains on property dispositions, net of tax, of $45.9 million ($0.18 per share) and a previously disclosed non-cash net loss of $66.7 million ($42.7 million after tax, or $0.16 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $24.9 million ($15.9 million after tax, or $0.06 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)
'EOG's strategic shift to a product mix more heavily weighted to crude oil and natural gas liquids is paying off,' said Mark G. Papa, Chairman and Chief Executive Officer. 'During the first quarter, EOG benefited from producing greater liquids volumes and rising crude oil prices.'
Operational Highlights
Total company production increased 14 percent as compared to the first quarter 2010. EOG delivered 47 percent total company crude oil, condensate and natural gas liquids production growth compared to the first quarter 2010. The growth was driven by a 50 percent rise in United States crude oil production and a 49 percent increase in total United States crude oil, condensate and natural gas liquids production.
Crude Oil and Liquids Activity
Crude oil and condensate production growth was led by the North Dakota Bakken and the South Texas Eagle Ford, two remarkably consistent horizontal oil plays, in which EOG continues to be the largest crude oil producer.
EOG's first quarter drilling and completion operations were largely unaffected by weather conditions in North Dakota where a number of Bakken wells were brought to sales. Drilled with a 12,000-foot lateral, the Liberty LR 19-23H had a peak initial production rate of 1,282 barrels of oil per day (Bopd) with 793 thousand cubic feet per day (Mcfd) of rich natural gas, gross. This well's offset, the Liberty LR 14-23H, had a peak initial gross production rate of 1,124 Bopd with 580 Mcfd of rich natural gas. EOG has 88 and 86 percent working interest in the wells, respectively. The Liberty 10-36H and Ross 27-2728H, in which EOG has 94 and 70 percent working interest, respectively, had gross initial production rates of 1,716 and 1,038 Bopd, respectively. The Bear Den 4-20H, drilled in McKenzie County, southwest of EOG's Parshall Field, began sales in March at an initial peak rate of 2,116 Bopd with 2.5 million cubic feet per day (MMcfd) of rich natural gas, gross. EOG has 90 percent working interest in the well.
Across its 120-mile South Texas Eagle Ford position in the crude oil window, EOG brought a number of highly productive wells to sales during the first quarter. In Karnes County, near the center of EOG's acreage, the Beynon Unit #2H and #3H wells began initial sales at rates of 1,747 and 1,100 Bopd with 1.4 and 0.7 MMcfd of rich natural gas, respectively. Also in Karnes County, the Dullnig Unit #5H and Joseph #3H began production at 1,353 and 1,317 Bopd, respectively, with 1.2 MMcfd of rich natural gas for both wells. On the southwest part of EOG's acreage in LaSalle County, the Naylor Jones Unit 95#1H and A#1H were completed to sales at 790 and 955 Bopd with 0.8 and 1.3 MMcfd of rich natural gas, respectively. On the northeast part of EOG's acreage in Gonzales County, the HFS #3H and #5H began production at 1,345 and 1,620 Bopd with 0.8 and 1.3 MMcfd of rich natural gas, respectively.
Also in the Eagle Ford, EOG drilled its most northeastern well to date in a previously untested fault block in Gonzales County. The Hill Unit #2H was completed to sales at 1,233 Bopd with 685 Mcfd of rich natural gas. EOG has 100 percent working interest in these nine Eagle Ford wells.
'Every single well we've drilled across our 120-mile Eagle Ford position that runs from southwest La Salle County to northeast Gonzales County is productive. That's a success rate of 100 percent,' Papa said. 'With 520,000 net acres, EOG holds the largest position of any operator in the crude oil window of this resource play, which according to industry studies, represents one of the most significant oil discoveries in the lower 48 during the last 40 years.'
Following the application of improved completion techniques in the Niobrara formation in the Denver-Julesburg Basin in northeast Colorado, new production data shows strong, consistent results.
'With an increased number of producing wells, EOG has gained a better understanding of the formation's geology. Our confidence level in the Niobrara has moved from cautious to optimistic,' Papa said.
Three recent Niobrara wells support this view. The Fox Creek 3-35H drilled in January began production at 553 Bopd. Four miles to the southeast, the Jersey 12-25H well began sales at 404 Bopd with 300 Mcfd. The Bessie 9-11H was completed to sales at 432 Bopd. EOG has 100 percent working interest in these wells. To date, EOG has concentrated its activity on its 80,000 net acre Hereford Ranch Field in Weld County, Colorado, with a three-rig program. EOG plans to test its remaining 140,000 net acres in the Niobrara later this year.
In the Wyoming Powder River Basin, EOG announced drilling results from a new horizontal sandstone play. Currently operating a one-rig program, EOG has drilled and completed eight wells to date with a 100 percent success rate. EOG has 75 percent working interest in the Crossbow 7-06H well, with a 30-day average production rate of 275 Bopd with 100 barrels per day of natural gas liquids and 2 MMcfd of natural gas. EOG has 138,000 net acres in the Powder River Basin where it plans to test multiple intervals over the course of 2011 and 2012.
Despite the impact of freezing weather, EOG posted favorable drilling results from the Fort Worth Barnett Shale Combo, where it is operating an 11-rig program. During the first quarter, EOG further increased its position in the core area to 185,000 net acres which encompasses southwest Cooke and southern Montague Counties. The Stephenson Unit #3H and #4H in Cooke County had initial gross production rates of 498 and 631 Bopd with 1,534 and 688 Mcfd of rich natural gas, respectively. EOG has 96 percent working interest in these wells. Also in Cooke County, the Priddy A Unit #6 slant and Priddy #4H horizontal began production at 1,162 and 830 Bopd with 626 and 501 Mcfd of rich natural gas, respectively. In western Montague County, the Rosa Unit #2H and Shockley Unit #1H were completed to sales at 468 and 416 Bopd with 779 and 272 Mcfd of rich natural gas, respectively. EOG has 100 percent working interest in these wells.
In the West Texas Permian Basin Wolfcamp Shale, EOG has drilled and completed six horizontal wells to date proving up 44,000 of its 120,000 total net acre position. EOG reported strong production results from a number of horizontal wells. The University 40-1402H and 38-0701H in Crockett County had initial 30-day averages of 390 and 230 Bopd with 600 and 440 Mcfd of natural gas, respectively. EOG has 96 and 75 percent working interest in the wells, respectively. In Irion County, the University 43-1001H and Munson 2701H, in which EOG has 75 and 85 percent working interest, posted average 30-day production rates of 440 and 330 Bopd with 400 and 700 Mcfd of natural gas, respectively. Also in the Permian Basin, EOG continued to achieve drilling success in its Leonard Play during the first quarter.
'We are excited about the production results from our first horizontal Wolfcamp wells,' Papa said. 'EOG will be drilling on our remaining 76,000 net acres over the course of the year.'
EOG's first quarter crude oil production in Canada increased 47 percent over the same period last year with further development of the Manitoba Waskada Field, where it drilled 47 wells.
'These positive results across the board are a direct reflection of our shift in portfolio mix to a greater focus on crude oil and liquids that began more than four years ago,' Papa said. 'We are now in execution mode on a number of these large-scale plays, developing them with efficient programs and applying technology to maximize these resources.'
EOG's total company full-year 2011 crude oil and condensate production growth forecast of approximately 55 percent remains unchanged despite significant second quarter weather-related operational issues in the North Dakota Bakken and Manitoba Waskada areas.
Natural Gas Activity
In the United States, natural gas production increased 9 percent over the same prior year period. EOG posted strong operational results from its Marcellus and Haynesville/Bossier Shale core natural gas horizontal resource plays, where it is employing drilling capital this year. In Bradford County, Pennsylvania, EOG completed the Guinan 2H. Using new completion technology, the well flowed at an initial rate of 9 MMcfd. This is the second consecutive high-rate well that EOG has brought to sales from this 100 percent working interest 50,000 net acre block.
Capital Structure
During the first quarter, total cash proceeds from sales of acreage, producing natural gas properties and midstream assets were approximately $260 million. An additional $387 million of cash proceeds from asset dispositions was received subsequent to the first quarter. On March 7, 2011, EOG received $1.39 billion of net proceeds from a public offering of its common stock. At March 31, 2011, EOG's total debt outstanding was $5,225 million for a debt-to-total capitalization ratio of 31 percent. Taking into account cash on the balance sheet of $1,668 million at the end of the quarter, EOG's net debt was $3,557 million for a net debt-to-total capitalization ratio of 23 percent. Based on current commodity prices, proceeds from the March common stock offering and the expected sale during 2011 of approximately $1.0 billion of assets, EOG has the potential to be cash flow neutral for the year. EOG is targeting a net debt-to-total capitalization ratio of 30 percent or less at both year-end 2011 and 2012. (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).)
To secure a portion of cash flows to fund its active capital expenditure program during 2011 and 2012, EOG has in place financial price swap commodity contracts for both crude oil and natural gas. For the period May 1 through December 31, 2011, EOG has 29,241 barrels per day (Bbld) of crude oil financial price swap contracts in place at a weighted average price of $96.67 per barrel. For the full-year 2012, EOG has 9,000 Bbld of crude oil financial price swap contracts in place at a weighted average price of $107.12 per barrel. For the period June 1 through December 31, 2011, EOG has 650,000 million British thermal units per day (MMbtud) of natural gas financial price swap contracts in place at a weighted average price of $4.90 per million British thermal units (MMbtu), excluding unexercised swaptions. For the full-year 2012, EOG has 525,000 MMbtud of natural gas financial price swap contracts in place at a weighted average price of $5.44 per MMbtu, excluding unexercised swaptions.
'EOG's first quarter results demonstrate that our consistent game plan is working,' Papa said. 'Without entering into dilutive joint ventures, we continue to grow our North American liquids production at high reinvestment rates of return, while making the necessary investments to retain our key natural gas horizontal resource acreage and maintaining low net debt levels.'
Conference Call Scheduled for May 6, 2011
EOG's first quarter 2011 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Friday, May 6, 2011. To listen, log on to http://www.eogresources.com/. The webcast will be archived on EOG's website through May 20, 2011.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude 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 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, and demand for, crude
oil, natural gas and related commodities;
-- the extent to which EOG is successful in its efforts to acquire or
discover additional reserves;
-- 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 crude oil
and natural gas exploration and development projects, given the risks
and uncertainties inherent in drilling, completing and operating crude
oil and natural gas wells and the potential for interruptions of
development and production, whether involuntary or intentional as a
result of market or other conditions;
-- the extent to which EOG is successful in its efforts to market its
crude oil, natural gas and related commodity production;
-- 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;
-- the impact of, and changes in, government policies, laws and
regulations, including tax laws and regulations, environmental laws
and regulations relating to air emissions, waste disposal and
hydraulic fracturing and laws and regulations imposing conditions and
restrictions on drilling and completion operations;
-- EOG's ability to effectively integrate acquired crude oil and natural
gas 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;
-- the extent to which EOG's third-party-operated crude oil and natural
gas properties are operated successfully and economically;
-- 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;
-- the accuracy of reserve estimates, which by their nature involve the
exercise of professional judgment and may therefore be imprecise;
-- weather, including its impact on crude oil and natural gas 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 extent and effect of any hedging activities engaged in by EOG;
-- 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 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 20 of EOG's Annual Report on Form 10-K for the fiscal year
ended December 31, 2010 and any updates to those factors set forth in
EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on
Form 8-K.
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) 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, 2010, 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/.
For Further Information
Contact: Investors
---------
Maire A. Baldwin
(713) 651-6EOG (651-6364)
Elizabeth M. Ivers
(713) 651-7132
Media
-----
K Leonard
(713) 571-3870
EOG RESOURCES, INC.
FINANCIAL REPORT
----------------
(Unaudited; in millions, except per share data)
Three Months Ended
March 31,
---------
2011 2010
---- ----
Net Operating Revenues $1,897.1 $1,370.7
======== ========
Net Income $134.0 $118.0
====== ======
Net Income Per Share
Basic $0.52 $0.47
===== =====
Diluted $0.52 $0.46
===== =====
Average Number of Shares Outstanding
Basic 255.2 250.4
===== =====
Diluted 258.8 253.9
===== =====
SUMMARY INCOME STATEMENTS
-------------------------
(Unaudited; in thousands, except per share data)
Three Months Ended
March 31,
---------
2011 2010
---- ----
Net Operating Revenues
Crude Oil and Condensate $757,362 $406,163
Natural Gas Liquids 148,727 103,026
Natural Gas 583,919 676,982
(Losses) Gains on Mark-to-
Market Commodity Derivative
Contracts (66,746) 7,803
Gathering, Processing and
Marketing 395,583 171,943
Gains (Losses) on Property
Dispositions, Net 71,742 (676)
Other, Net 6,519 5,452
----- -----
Total 1,897,106 1,370,693
--------- ---------
Operating Expenses
Lease and Well 215,089 165,992
Transportation Costs 97,633 88,711
Gathering and Processing Costs 19,196 15,661
Exploration Costs 50,909 51,197
Dry Hole Costs 22,951 23,077
Impairments 89,328 69,595
Marketing Costs 385,409 168,764
Depreciation, Depletion and
Amortization 568,226 431,906
General and Administrative 70,037 60,423
Taxes Other Than Income 105,877 75,465
------- ------
Total 1,624,655 1,150,791
--------- ---------
Operating Income 272,451 219,902
Other Income, Net 3,604 2,683
----- -----
Income Before Interest Expense
and Income Taxes 276,055 222,585
Interest Expense, Net 50,333 25,428
------ ------
Income Before Income Taxes 225,722 197,157
Income Tax Provision 91,749 79,142
------ ------
Net Income $133,973 $118,015
======== ========
Dividends Declared per Common
Share $0.160 $0.155
====== ======
EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
--------------------
(Unaudited)
Three Months Ended
March 31,
---------
2011 2010
---- ----
Wellhead Volumes and Prices
---------------------------
Crude Oil and Condensate Volumes (MBbld)
(A)
United States 81.4 54.1
Canada 8.5 5.8
Trinidad 4.4 3.8
Other International (B) 0.1 0.1
--- ---
Total 94.4 63.8
==== ====
Average Crude Oil and Condensate Prices
($/Bbl) (C)
United States $88.00 $73.29
Canada 84.24 73.27
Trinidad 86.84 66.45
Other International (B) 85.57 71.37
Composite 87.61 72.87
Natural Gas Liquids Volumes (MBbld) (A)
United States 34.5 23.7
Canada 0.9 0.9
--- ---
Total 35.4 24.6
==== ====
Average Natural Gas Liquids Prices
($/Bbl) (C)
United States $46.63 $46.64
Canada 47.11 45.78
Composite 46.65 46.61
Natural Gas Volumes (MMcfd) (A)
United States 1,134 1,043
Canada 143 211
Trinidad 385 351
Other International (B) 14 16
--- ---
Total 1,676 1,621
===== =====
Average Natural Gas Prices ($/Mcf) (C)
United States $4.10 $5.24
Canada 3.67 5.22
Trinidad 3.20 2.51
Other International (B) 5.63 4.28
Composite 3.87 4.64
Crude Oil Equivalent Volumes (MBoed) (D)
United States 304.9 251.6
Canada 33.2 41.8
Trinidad 68.6 62.3
Other International (B) 2.4 2.8
--- ---
Total 409.1 358.5
===== =====
Total MMBoe (D) 36.8 32.3
Thousand barrels per day or million cubic feet per day, as
(A) applicable.
Other International includes EOG's United Kingdom and China
(B) operations.
Dollars per barrel or per thousand cubic feet, as applicable.
(C) Excludes the impact of
financial commodity derivative instruments.
Thousand barrels of oil equivalent per day or million barrels
(D) 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)
March 31, December 31,
2011 2010
---- ----
ASSETS
Current Assets
Cash and Cash
Equivalents $1,668,285 $788,853
Accounts
Receivable, Net 1,228,549 1,113,279
Inventories 481,826 415,792
Assets from Price
Risk Management
Activities 45,498 48,153
Income Taxes
Receivable 30,546 54,916
Deferred Income
Taxes 28,072 9,260
Other 114,827 97,193
------- ------
Total 3,597,603 2,527,446
Property, Plant and
Equipment
Oil and Gas
Properties
(Successful
Efforts Method) 30,526,397 29,263,809
Other Property,
Plant and
Equipment 1,863,061 1,733,073
Total Property,
Plant and
Equipment 32,389,458 30,996,882
Less: Accumulated
Depreciation,
Depletion and
Amortization (12,748,006) (12,315,982)
----------- -----------
Total Property,
Plant and
Equipment, Net 19,641,452 18,680,900
Other Assets 306,467 415,887
Total Assets $23,545,522 $21,624,233
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable $1,838,959 $1,664,944
Accrued Taxes
Payable 136,897 82,168
Dividends Payable 40,247 38,962
Liabilities from
Price Risk
Management
Activities 105,231 28,339
Deferred Income
Taxes 7,944 41,703
Current Portion of
Long-Term Debt 220,000 220,000
Other 150,913 143,983
Total 2,500,191 2,220,099
Long-Term Debt 5,004,725 5,003,341
Other Liabilities 680,754 667,455
Deferred Income
Taxes 3,571,473 3,501,706
Commitments and
Contingencies
Stockholders'
Equity
Common Stock, $0.01
Par, 640,000,000
Shares Authorized
and
268,540,507 Shares
Issued at March
31, 2011 and
254,223,521 Shares
Issued at December
31, 2010 202,685 202,542
Additional Paid In
Capital 2,148,476 729,992
Accumulated Other
Comprehensive
Income 485,464 440,071
Retained Earnings 8,963,475 8,870,179
Common Stock Held
in Treasury,
121,135 Shares at
March 31, 2011
and 146,186 Shares
at December 31,
2010 (11,721) (11,152)
Total Stockholders'
Equity 11,788,379 10,231,632
---------- ----------
Total Liabilities
and
Stockholders'
Equity $23,545,522 $21,624,233
EOG RESOURCES, INC.
SUMMARY STATEMENTS OF CASH FLOWS
--------------------------------
(Unaudited; in thousands)
Three Months Ended
March 31,
---------
2011 2010
---- ----
Cash Flows from Operating
Activities
Reconciliation of Net Income
to Net Cash Provided by
Operating Activities:
Net Income $133,973 $118,015
Items Not Requiring
(Providing) Cash
Depreciation, Depletion and
Amortization 568,226 431,906
Impairments 89,328 69,595
Stock-Based Compensation
Expenses 27,430 22,494
Deferred Income Taxes 31,290 36,695
(Gains) Losses on Property
Dispositions, Net (71,742) 676
Other, Net 2,523 (953)
Dry Hole Costs 22,951 23,077
Mark-to-Market Commodity
Derivative Contracts
Total Losses (Gains) 66,746 (7,803)
Realized Gains 24,937 22,960
Other, Net 6,219 2,505
Changes in Components of
Working Capital and Other
Assets and Liabilities
Accounts Receivable (113,855) (95,770)
Inventories (67,733) (53,312)
Accounts Payable 165,497 147,632
Accrued Taxes Payable 79,748 (3,790)
Other Assets (18,656) (13,494)
Other Liabilities 8,621 (5,554)
Changes in Components of
Working Capital Associated
with Investing and
Financing Activities 1,985 (74,592)
----- -------
Net Cash Provided by Operating
Activities 957,488 620,287
Investing Cash Flows
Additions to Oil and Gas
Properties (1,527,854) (1,063,390)
Additions to Other Property,
Plant and Equipment (159,794) (61,483)
Proceeds from Sales of Assets 260,107 3,766
Changes in Components of
Working Capital Associated
with Investing
Activities (206) 74,322
Other, Net - 7,107
--- -----
Net Cash Used in Investing
Activities (1,427,747) (1,039,678)
Financing Cash Flows
Common Stock Sold 1,388,211 -
Dividends Paid (39,003) (36,289)
Treasury Stock Purchased (14,981) (5,347)
Proceeds from Stock Options
Exercised 17,363 5,277
Other, Net (1,779) 270
------ ---
Net Cash Provided by (Used In)
Financing Activities 1,349,811 (36,089)
Effect of Exchange Rate
Changes on Cash (120) (187)
---- ----
Increase (Decrease) in Cash
and Cash Equivalents 879,432 (455,667)
Cash and Cash Equivalents at
Beginning of Period 788,853 685,751
------- -------
Cash and Cash Equivalents at
End of Period $1,668,285 $230,084
========== ========
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 periods ended March 31, 2011
and 2010 reported Net Income (GAAP) to reflect
actual net cash realized from financial commodity price transactions
by eliminating the unrealized mark-to-market losses
(gains) from these transactions, to add back impairment charges
related to certain of EOG's United States (U.S.) natural
gas assets in the first quarter of 2011, to eliminate the gains on
natural gas property dispositions primarily in the U.S. in
the first quarter of 2011, and to eliminate the change in the first
quarter of 2010 in the estimated fair value of a contingent
consideration liability related to EOG's previously disclosed
acquisition of Haynesville and Bossier Shale unproved
acreage. 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
March 31,
---------
2011 2010
---- ---
Reported Net Income (GAAP) $133,973 $118,015
Mark-to-Market (MTM) Commodity
Derivative Contracts Impact
Total Losses (Gains) 66,746 (7,803)
Realized Gains 24,937 22,960
Subtotal 91,683 15,157
------ ------
After-Tax MTM Impact 58,640 9,704
------ -----
Add: Impairment of Certain U.S. Natural
Gas Assets, Net of Tax 30,283 -
Less: Gains on Property Dispositions, Net
of Tax (45,886) -
Less: Change in Fair Value of Contingent
Consideration Liability, Net of Tax - (9,933)
--- ------
Adjusted Net Income (Non-GAAP) $177,010 $117,786
======== ========
Net Income Per Share (GAAP)
Basic $0.52 $0.47
===== =====
Diluted $0.52 $0.46
===== =====
Adjusted Net Income Per Share (Non-GAAP)
Basic $0.69 $0.47
===== =====
Diluted $0.68 $0.46
===== =====
Average Number of Shares
Basic 255,200 250,370
======= =======
Diluted 258,819 253,869
======= =======
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 periods ended March 31,
2011 and 2010 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), 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
March 31,
---------
2011 2010
---- ----
Net Cash Provided by Operating
Activities (GAAP) $957,488 $620,287
Adjustments
Exploration Costs (excluding Stock-
Based Compensation Expenses) 44,767 45,683
Changes in Components of Working
Capital and Other Assets and
Liabilities
Accounts Receivable 113,855 95,770
Inventories 67,733 53,312
Accounts Payable (165,497) (147,632)
Accrued Taxes Payable (79,748) 3,790
Other Assets 18,656 13,494
Other Liabilities (8,621) 5,554
Changes in Components of Working
Capital Associated
with Investing and Financing
Activities (1,985) 74,592
------ ------
Discretionary Cash Flow (Non-GAAP) $946,648 $764,850
======== ========
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.
March 31,
2011
----
Total Stockholders' Equity - (a) $11,788
-------
Current and Long-Term Debt - (b) 5,225
Less: Cash (1,668)
------
Net Debt (Non-GAAP) - (c) 3,557
Total Capitalization (GAAP) - (a) + (b) $17,013
=======
Total Capitalization (Non-GAAP) - (a) + (c) $15,345
=======
Debt-to-Total Capitalization (GAAP) - (b) /[(a)
+ (b)] 31%
===
Net Debt-to-Total Capitalization (Non-GAAP) -
(c) /[(a) + (c)] 23%
===
EOG RESOURCES, INC.
SECOND QUARTER AND FULL YEAR 2011 FORECAST AND BENCHMARK COMMODITY
PRICING
------------------------------------------------------------------
(a) Second Quarter and Full Year 2011 Forecast
The forecast items for the second quarter and full year 2011 set
forth below for EOG Resources, Inc. (EOG) are based on
current available information and expectations as of the date of the
accompanying press release. This forecast replaces
and supersedes any previously issued guidance or forecast.
(b) Benchmark Commodity Pricing
EOG bases United States and Canada natural gas price differentials
upon the natural gas price at Henry Hub, Louisiana
using the simple average of the NYMEX settlement prices for the last
three trading days of the applicable month.
EOG bases United States, Canada and Trinidad crude oil and condensate
price differentials upon the West Texas
Intermediate crude oil price at Cushing, Oklahoma, using the simple
average of the NYMEX settlement prices for each
trading day within the applicable calendar month.
ESTIMATED RANGES
----------------
(Unaudited)
2Q 2011
-------
Daily Production
Crude Oil and Condensate Volumes
(MBbld)
United States 85.2 - 93.2
Canada 7.6 - 8.6
Trinidad 3.4 - 4.0
Total 96.2 - 105.8
Natural Gas Liquids Volumes
(MBbld)
United States 35.0 - 39.0
Canada 0.4 - 0.8
Total 35.4 - 39.8
Natural Gas Volumes (MMcfd)
United States 1,080 - 1,112
Canada 113 - 137
Trinidad 316 - 348
Other International 10 - 14
Total 1,519 - 1,611
Crude Oil Equivalent Volumes
(MBoed)
United States 300.2 - 317.5
Canada 26.8 - 32.2
Trinidad 56.1 - 62.0
Other International 1.7 - 2.3
Total 384.8 - 414.0
Operating Costs
Unit Costs ($/Boe)
Lease and Well $5.55 - $6.27
Transportation Costs $3.00 - $3.36
Depreciation, Depletion and
Amortization $15.54 - $16.62
Expenses ($MM)
Exploration, Dry Hole and
Impairment $135.0 - $165.0
General and Administrative $73.0 - $80.0
Gathering and Processing $16.5 - $20.5
Capitalized Interest $13.0 - $17.0
Net Interest $48.1 - $53.1
Taxes Other Than Income (% of
Revenue) 5.9% - 7.1%
Income Taxes
Effective Rate 35% - 50%
Current Taxes ($MM) $90 - $105
Capital Expenditures ($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)
Crude Oil and Condensate ($/Bbl)
Differentials
United States -below WTI $6.00 - $8.50
Canada -below WTI $7.00 - $8.00
Trinidad -below WTI $8.15 - $12.15
Natural Gas ($/Mcf)
Differentials
United States -below NYMEX
Henry Hub $0.06 - $0.14
Canada -below NYMEX Henry Hub $0.41 - $0.56
Realizations
Trinidad $2.75 - $3.25
Other International $5.48 - $6.20
ESTIMATED RANGES
----------------
(Unaudited)
Full Year 2011
--------------
Daily Production
Crude Oil and Condensate
Volumes (MBbld)
United States 94.2 - 114.2
Canada 7.0 - 9.5
Trinidad 2.5 - 4.1
Total 103.7 - 127.8
Natural Gas Liquids Volumes
(MBbld)
United States 34.8 - 44.8
Canada 0.7 - 0.9
Total 35.5 - 45.7
Natural Gas Volumes (MMcfd)
United States 1,116 - 1,154
Canada 106 - 140
Trinidad 316 - 340
Other International 12 - 16
Total 1,550 - 1,650
Crude Oil Equivalent Volumes
(MBoed)
United States 315.0 - 351.3
Canada 25.4 - 33.7
Trinidad 55.2 - 60.8
Other International 2.0 - 2.7
Total 397.6 - 448.5
Operating Costs
Unit Costs ($/Boe)
Lease and Well $5.56 - $6.04
Transportation Costs $2.88 - $3.24
Depreciation, Depletion and
Amortization $15.50 - $16.52
Expenses ($MM)
Exploration, Dry Hole and
Impairment $515.0 - $560.0
General and Administrative $313.0 - $333.0
Gathering and Processing $68.0 - $85.0
Capitalized Interest $51.0 - $70.0
Net Interest $190.0 - $210.0
Taxes Other Than Income (% of
Revenue) 6.0% - 7.0%
Income Taxes
Effective Rate 35% - 45%
Current Taxes ($MM) $310 - $330
Capital Expenditures ($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 - $550
Pricing -(Refer to Benchmark
Commodity Pricing in text)
Crude Oil and Condensate
($/Bbl)
Differentials
United States -below WTI $5.45 - $7.45
Canada -below WTI $7.50 - $8.50
Trinidad -below WTI $8.00 - $12.75
Natural Gas ($/Mcf)
Differentials
United States -below NYMEX
Henry Hub $0.03 - $0.15
Canada -below NYMEX Henry Hub $0.44 - $0.55
Realizations
Trinidad $2.55 - $3.15
Other International $5.50 - $6.20
Definitions
-----------
$/Bbl U.S. Dollars per barrel
$/Boe U.S. Dollars per barrel of oil equivalent
$/Mcf U.S. Dollars per thousand cubic feet
$MM U.S. Dollars in millions
MBbld Thousand barrels per day
Mboed Thousand barrels of oil equivalent per day
MMcfd Million cubic feet per day
NYMEX New York Mercantile Exchange
WTI West Texas Intermediate
EOG Resources, Inc.
Web Site: http://www.eogresources.com/
