Delaware
(State or other jurisdiction of incorporation) |
1-9743
(Commission File Number) |
47-0684736
(I.R.S. Employer Identification No.) |
[ ] | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
[ ] | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
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EOG RESOURCES, INC.
(Registrant) |
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Date: February 13, 2013
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By:
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/s/ TIMOTHY K. DRIGGERS
Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer) |
99.1
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Press Release of EOG Resources, Inc. dated February 13, 2013 (including the accompanying first quarter and full year 2013 forecast and benchmark commodity pricing information).
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EOG Resources, Inc.
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News Release
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For Further Information Contact:
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Investors
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Maire A. Baldwin
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(713) 651-6EOG (651-6364)
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Elizabeth M. Ivers
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(713) 651-7132
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Kimberly A. Matthews
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(713) 571-4676
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Media
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K Leonard
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(713) 571-3870
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·
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Achieves 39 Percent Year-Over-Year Total Company Crude Oil and Condensate Growth and 37 Percent Total Liquids Growth
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·
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Reports 10 Percent Total Company Production Growth
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·
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Delivers Strong Year-Over-Year Growth in Non-GAAP Earnings Per Share, Adjusted EBITDAX and Discretionary Cash Flow
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·
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Increases Eagle Ford Potential Recoverable Reserve Estimate by 600 MMBoe to 2.2 BnBoe, Net to EOG
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·
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Highlights Record Eagle Ford Oil Well
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·
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Announces New Wolfcamp Shale Play in Delaware Basin and Increases Leonard Shale Potential Reserves with Total Combined Delaware Basin Potential Reserves of 1.35 BnBoe, Net to EOG
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·
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Realizes Improvements in Bakken/Three Forks Operations
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·
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Delivers 268 Percent Reserve Replacement at Attractive Finding Costs, Excluding
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·
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Raises Common Stock Dividend for 14th Time in 14 Years
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·
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Total reserve replacement from all sources – the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production – was 268 percent at a total reserve replacement cost of $12.60 per barrel of oil equivalent (Boe), based on exploration and development expenditures of $6,921 million and excluding price-related revisions. (For the calculation of total reserve replacement and total reserve replacement costs, please refer to the attached tables.)
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·
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Total liquids reserve replacement from all sources – the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production – was 452 percent. (For the calculation of total liquids reserve replacement, please refer to the attached tables.)
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·
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Reserve replacement from drilling – the ratio of extensions, discoveries and other additions to total production – was 238 percent. Crude oil reserve replacement from drilling in the United States was 442 percent. (For the calculation of reserve replacement from drilling, please refer to the attached tables.)
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·
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In the United States, total reserve replacement from all sources, excluding price-related revisions, was 326 percent at a reserve replacement cost of $11.82 per Boe based on exploration and development expenditures of $6,362 million. (For the calculation of United States total reserve replacement and total reserve replacement costs, please refer to the attached tables.) In the United States, 80 percent of the reserve additions were liquids.
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·
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the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
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·
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the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
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·
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the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing;
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·
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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 and capital expenditure requirements 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;
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·
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the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;
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·
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the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;
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·
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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;
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·
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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, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;
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·
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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;
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·
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the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
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·
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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;
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·
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the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
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·
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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;
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·
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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;
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·
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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, and to otherwise satisfy its capital expenditure requirements;
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·
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the extent and effect of any hedging activities engaged in by EOG;
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·
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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;
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·
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political developments around the world, including in the areas in which EOG operates;
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·
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the use of competing energy sources and the development of alternative energy sources;
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·
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the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
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·
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acts of war and terrorism and responses to these acts; and
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·
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the other factors described under Item 1A, "Risk Factors," on pages 15 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2011 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.
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EOG RESOURCES, INC.
FINANCIAL REPORT (Unaudited; in millions, except per share data) |
||||||||||||||||
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Three Months Ended
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Twelve Months Ended
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||||||||||||||
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December 31,
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December 31,
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||||||||||||||
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2012
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2011
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2012
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2011
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||||||||||||
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||||||||||||||||
Net Operating Revenues
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$
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3,011.8
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$
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2,773.0
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$
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11,682.6
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$
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10,126.1
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||||||||
Net Income (Loss)
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$
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(505.0
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)
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$
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120.7
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$
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570.3
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$
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1,091.1
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|||||||
Net Income (Loss) Per Share
|
||||||||||||||||
Basic
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$
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(1.88
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)
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$
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0.45
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$
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2.13
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$
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4.15
|
|||||||
Diluted
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$
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(1.88
|
)
|
$
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0.45
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$
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2.11
|
$
|
4.10
|
|||||||
Average Number of Common Shares
|
||||||||||||||||
Basic
|
268.9
|
266.3
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267.6
|
262.7
|
||||||||||||
Diluted
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268.9
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269.5
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270.8
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266.3
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SUMMARY INCOME STATEMENTS
(Unaudited; in thousands, except per share data) |
||||||||||||||||
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Three Months Ended
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Twelve Months Ended
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||||||||||||||
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December 31,
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December 31,
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||||||||||||||
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2012
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2011
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2012
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2011
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Net Operating Revenues
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||||||||||||||||
Crude Oil and Condensate
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$
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1,460,684
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$
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1,189,250
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$
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5,659,437
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$
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3,838,284
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||||||||
Natural Gas Liquids
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208,493
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240,260
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727,177
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779,364
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Natural Gas
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418,329
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479,825
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1,571,762
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2,240,540
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||||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts
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66,416
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145,514
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393,744
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626,053
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Gathering, Processing and Marketing
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903,404
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654,489
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3,096,694
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2,115,792
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||||||||||||
Gains (Losses) on Asset Dispositions, Net
|
(55,474
|
)
|
49,928
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192,660
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492,909
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|||||||||||
Other, Net
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9,959
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13,749
|
41,162
|
33,173
|
||||||||||||
Total
|
3,011,811
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2,773,015
|
11,682,636
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10,126,115
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||||||||||||
Operating Expenses
|
||||||||||||||||
Lease and Well
|
234,349
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261,244
|
1,000,052
|
941,954
|
||||||||||||
Transportation Costs
|
169,789
|
122,046
|
601,431
|
430,322
|
||||||||||||
Gathering and Processing Costs
|
25,542
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25,283
|
97,945
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80,727
|
||||||||||||
Exploration Costs
|
48,660
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31,042
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185,569
|
171,658
|
||||||||||||
Dry Hole Costs
|
1,965
|
5,999
|
14,970
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53,230
|
||||||||||||
Impairments
|
1,020,496
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499,624
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1,270,735
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1,031,037
|
||||||||||||
Marketing Costs
|
880,451
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644,687
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3,035,494
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2,072,137
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||||||||||||
Depreciation, Depletion and Amortization
|
786,344
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693,527
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3,169,703
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2,516,381
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||||||||||||
General and Administrative
|
86,679
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85,108
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331,545
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304,811
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||||||||||||
Taxes Other Than Income
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135,597
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101,880
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495,395
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410,549
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Total
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3,389,872
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2,470,440
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10,202,839
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8,012,806
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||||||||||||
Operating Income (Loss)
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(378,061
|
)
|
302,575
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1,479,797
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2,113,309
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|||||||||||
Other Income (Expense), Net
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(8,407
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)
|
(4,352
|
)
|
14,495
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6,853
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||||||||||
Income (Loss) Before Interest Expense and Income Taxes
|
(386,468
|
)
|
298,223
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1,494,292
|
2,120,162
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|||||||||||
Interest Expense, Net
|
59,354
|
56,591
|
213,552
|
210,363
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||||||||||||
Income (Loss) Before Income Taxes
|
(445,822
|
)
|
241,632
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1,280,740
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1,909,799
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|||||||||||
Income Tax Provision
|
59,177
|
120,934
|
710,461
|
818,676
|
||||||||||||
Net Income (Loss)
|
$
|
(504,999
|
)
|
$
|
120,698
|
$
|
570,279
|
$
|
1,091,123
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|||||||
Dividends Declared per Common Share
|
$
|
0.17
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$
|
0.16
|
$
|
0.68
|
$
|
0.64
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EOG RESOURCES, INC.
|
||||||||||||||||
OPERATING HIGHLIGHTS
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
|
Three Months Ended
|
Twelve Months Ended
|
||||||||||||||
|
December 31,
|
December 31,
|
||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
||||||||||||
Wellhead Volumes and Prices
|
||||||||||||||||
Crude Oil and Condensate Volumes (MBbld) (A)
|
||||||||||||||||
United States
|
154.1
|
124.8
|
149.3
|
102.0
|
||||||||||||
Canada
|
7.5
|
7.6
|
7.0
|
7.9
|
||||||||||||
Trinidad
|
1.0
|
2.8
|
1.5
|
3.4
|
||||||||||||
Other International (B)
|
0.1
|
0.1
|
0.1
|
0.1
|
||||||||||||
Total
|
162.7
|
135.3
|
157.9
|
113.4
|
||||||||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C)
|
||||||||||||||||
United States
|
$
|
98.72
|
$
|
96.33
|
$
|
98.38
|
$
|
92.92
|
||||||||
Canada
|
85.59
|
89.32
|
86.08
|
91.92
|
||||||||||||
Trinidad
|
83.93
|
87.02
|
92.26
|
90.62
|
||||||||||||
Other International (B)
|
87.34
|
103.46
|
89.57
|
100.11
|
||||||||||||
Composite
|
98.02
|
95.75
|
97.77
|
92.79
|
||||||||||||
Natural Gas Liquids Volumes (MBbld) (A)
|
||||||||||||||||
United States
|
57.0
|
49.6
|
55.1
|
41.5
|
||||||||||||
Canada
|
0.8
|
1.1
|
0.8
|
0.9
|
||||||||||||
Total
|
57.8
|
50.7
|
55.9
|
42.4
|
||||||||||||
Average Natural Gas Liquids Prices ($/Bbl) (C)
|
||||||||||||||||
United States
|
$
|
35.36
|
$
|
51.58
|
$
|
35.41
|
$
|
50.37
|
||||||||
Canada
|
42.50
|
49.16
|
44.13
|
52.69
|
||||||||||||
Composite
|
35.45
|
51.53
|
35.54
|
50.41
|
||||||||||||
Natural Gas Volumes (MMcfd) (A)
|
||||||||||||||||
United States
|
981
|
1,085
|
1,034
|
1,113
|
||||||||||||
Canada
|
84
|
124
|
95
|
132
|
||||||||||||
Trinidad
|
335
|
313
|
378
|
344
|
||||||||||||
Other International (B)
|
8
|
11
|
9
|
13
|
||||||||||||
Total
|
1,408
|
1,533
|
1,516
|
1,602
|
||||||||||||
Average Natural Gas Prices ($/Mcf) (C)
|
||||||||||||||||
United States
|
$
|
2.93
|
$
|
3.27
|
$
|
2.51
|
$
|
3.92
|
||||||||
Canada
|
2.98
|
3.14
|
2.49
|
3.71
|
||||||||||||
Trinidad
|
4.12
|
3.87
|
3.72
|
3.53
|
||||||||||||
Other International (B)
|
5.75
|
5.70
|
5.71
|
5.62
|
||||||||||||
Composite
|
3.23
|
3.40
|
2.83
|
3.83
|
||||||||||||
Crude Oil Equivalent Volumes (MBoed) (D)
|
||||||||||||||||
United States
|
374.6
|
355.3
|
376.6
|
329.1
|
||||||||||||
Canada
|
22.3
|
29.3
|
23.6
|
30.7
|
||||||||||||
Trinidad
|
56.8
|
54.9
|
64.5
|
60.7
|
||||||||||||
Other International (B)
|
1.4
|
2.0
|
1.7
|
2.2
|
||||||||||||
Total
|
455.1
|
441.5
|
466.4
|
422.7
|
||||||||||||
Total MMBoe (D)
|
41.9
|
40.6
|
170.7
|
154.3
|
(A)
|
Thousand barrels per day or million cubic feet per day, as applicable.
|
|
|
|
|
|
|
||||||
(B)
|
Other International includes EOG's United Kingdom, China and Argentina 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 31,
|
December 31,
|
||||||
|
2012
|
2011
|
||||||
ASSETS
|
||||||||
Current Assets
|
||||||||
Cash and Cash Equivalents
|
$
|
876,435
|
$
|
615,726
|
||||
Accounts Receivable, Net
|
1,656,618
|
1,451,227
|
||||||
Inventories
|
683,187
|
590,594
|
||||||
Assets from Price Risk Management Activities
|
166,135
|
450,730
|
||||||
Income Taxes Receivable
|
29,163
|
26,609
|
||||||
Other
|
178,346
|
119,052
|
||||||
Total
|
3,589,884
|
3,253,938
|
||||||
Property, Plant and Equipment
|
||||||||
Oil and Gas Properties (Successful Efforts Method)
|
38,126,298
|
33,664,435
|
||||||
Other Property, Plant and Equipment
|
2,740,619
|
2,149,989
|
||||||
Total Property, Plant and Equipment
|
40,866,917
|
35,814,424
|
||||||
Less: Accumulated Depreciation, Depletion and Amortization
|
(17,529,236
|
)
|
(14,525,600
|
)
|
||||
Total Property, Plant and Equipment, Net
|
23,337,681
|
21,288,824
|
||||||
Other Assets
|
409,013
|
296,035
|
||||||
Total Assets
|
$
|
27,336,578
|
$
|
24,838,797
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
||||||||
Current Liabilities
|
||||||||
Accounts Payable
|
$
|
2,078,948
|
$
|
2,033,615
|
||||
Accrued Taxes Payable
|
162,083
|
147,105
|
||||||
Dividends Payable
|
45,802
|
42,578
|
||||||
Liabilities from Price Risk Management Activities
|
7,617
|
-
|
||||||
Deferred Income Taxes
|
22,838
|
135,989
|
||||||
Current Portion of Long-Term Debt
|
406,579
|
-
|
||||||
Other
|
200,191
|
163,032
|
||||||
Total
|
2,924,058
|
2,522,319
|
||||||
Long-Term Debt
|
5,905,602
|
5,009,166
|
||||||
Other Liabilities
|
894,758
|
799,189
|
||||||
Deferred Income Taxes
|
4,327,396
|
3,867,219
|
||||||
Commitments and Contingencies
|
||||||||
|
||||||||
Stockholders' Equity
|
||||||||
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 271,958,495
|
||||||||
Shares and 269,323,084 Shares Issued at December 31, 2012 and 2011, respectively
|
202,720
|
202,693
|
||||||
Additional Paid in Capital
|
2,500,340
|
2,272,052
|
||||||
Accumulated Other Comprehensive Income
|
439,895
|
401,746
|
||||||
Retained Earnings
|
10,175,631
|
9,789,345
|
||||||
Common Stock Held in Treasury, 326,264 Shares and 303,633 Shares at
|
||||||||
December 31, 2012 and 2011, respectively
|
(33,822
|
)
|
(24,932
|
)
|
||||
Total Stockholders' Equity
|
13,284,764
|
12,640,904
|
||||||
Total Liabilities and Stockholders' Equity
|
$
|
27,336,578
|
$
|
24,838,797
|
EOG RESOURCES, INC.
|
||||||||
SUMMARY STATEMENTS OF CASH FLOWS
|
||||||||
(Unaudited; in thousands)
|
||||||||
|
Twelve Months Ended
|
|||||||
|
December 31,
|
|||||||
|
2012
|
2011
|
||||||
Cash Flows from Operating Activities
|
||||||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
|
||||||||
Net Income
|
$
|
570,279
|
$
|
1,091,123
|
||||
Items Not Requiring (Providing) Cash
|
||||||||
Depreciation, Depletion and Amortization
|
3,169,703
|
2,516,381
|
||||||
Impairments
|
1,270,735
|
1,031,037
|
||||||
Stock-Based Compensation Expenses
|
127,778
|
128,345
|
||||||
Deferred Income Taxes
|
292,938
|
499,300
|
||||||
Gains on Asset Dispositions, Net
|
(192,660
|
)
|
(492,909
|
)
|
||||
Other, Net
|
672
|
15,139
|
||||||
Dry Hole Costs
|
14,970
|
53,230
|
||||||
Mark-to-Market Commodity Derivative Contracts
|
||||||||
Total Gains
|
(393,744
|
)
|
(626,053
|
)
|
||||
Realized Gains
|
711,479
|
180,701
|
||||||
Excess Tax Benefits from Stock-Based Compensation
|
(67,035
|
)
|
-
|
|||||
Other, Net
|
14,411
|
26,454
|
||||||
Changes in Components of Working Capital and Other Assets and Liabilities
|
||||||||
Accounts Receivable
|
(178,683
|
)
|
(339,780
|
)
|
||||
Inventories
|
(156,762
|
)
|
(176,623
|
)
|
||||
Accounts Payable
|
(17,150
|
)
|
351,087
|
|||||
Accrued Taxes Payable
|
78,094
|
92,589
|
||||||
Other Assets
|
(118,520
|
)
|
(23,625
|
)
|
||||
Other Liabilities
|
36,114
|
14,986
|
||||||
Changes in Components of Working Capital Associated with Investing and
|
||||||||
Financing Activities
|
74,158
|
237,028
|
||||||
Net Cash Provided by Operating Activities
|
5,236,777
|
4,578,410
|
||||||
|
||||||||
Investing Cash Flows
|
||||||||
Additions to Oil and Gas Properties
|
(6,735,316
|
)
|
(6,294,397
|
)
|
||||
Additions to Other Property, Plant and Equipment
|
(619,800
|
)
|
(656,415
|
)
|
||||
Proceeds from Sales of Assets
|
1,309,776
|
1,433,137
|
||||||
Changes in Components of Working Capital Associated with Investing Activities
|
(73,923
|
)
|
(237,267
|
)
|
||||
Net Cash Used in Investing Activities
|
(6,119,263
|
)
|
(5,754,942
|
)
|
||||
|
||||||||
Financing Cash Flows
|
||||||||
Common Stock Sold
|
-
|
1,388,265
|
||||||
Long-Term Debt Borrowings
|
1,234,138
|
-
|
||||||
Long-Term Debt Repayments
|
-
|
(220,000
|
)
|
|||||
Dividends Paid
|
(181,080
|
)
|
(167,169
|
)
|
||||
Excess Tax Benefits from Stock-Based Compensation
|
67,035
|
-
|
||||||
Treasury Stock Purchased
|
(58,592
|
)
|
(23,922
|
)
|
||||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan
|
82,887
|
35,913
|
||||||
Debt Issuance Costs
|
(1,578
|
)
|
(4,787
|
)
|
||||
Repayment of Capital Lease Obligation
|
(2,824
|
)
|
-
|
|||||
Other, Net
|
(235
|
)
|
239
|
|||||
Net Cash Provided by Financing Activities
|
1,139,751
|
1,008,539
|
||||||
|
||||||||
Effect of Exchange Rate Changes on Cash
|
3,444
|
(5,134
|
)
|
|||||
|
||||||||
Increase (Decrease) in Cash and Cash Equivalents
|
260,709
|
(173,127
|
)
|
|||||
Cash and Cash Equivalents at Beginning of Period
|
615,726
|
788,853
|
||||||
Cash and Cash Equivalents at End of Period
|
$
|
876,435
|
$
|
615,726
|
EOG RESOURCES, INC.
|
QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP)
|
TO NET INCOME (LOSS) (GAAP)
|
(Unaudited; in thousands, except per share data)
|
|
|
The following chart adjusts the three-month and twelve-month periods ended December 31, 2012 and 2011 reported Net Income (Loss) (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 charges related to impairments of certain of EOG's North American assets in 2012 and 2011, to add back the write-off of fees associated with revolving credit facilities cancelled in connection with the establishment of a new revolving credit facility in the fourth quarter of 2011 and to eliminate the net gains (losses) on asset dispositions primarily in North America in 2012 and 2011. 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 non-recurring items. EOG management uses this information for comparative purposes within the industry.
|
|
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||||
|
December 31,
|
December 31,
|
|||||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||||
Reported Net Income (Loss) (GAAP)
|
$
|
(504,999
|
)
|
$
|
120,698
|
$
|
570,279
|
$
|
1,091,123
|
||||||
|
|||||||||||||||
Mark-to-Market (MTM) Commodity Derivative Contracts Impact
|
|||||||||||||||
Total Gains
|
(66,416
|
)
|
(145,514
|
)
|
(393,744
|
)
|
(626,053
|
)
|
|||||||
Realized Gains
|
155,533
|
96,936
|
711,479
|
180,701
|
|||||||||||
Subtotal
|
89,117
|
(48,578
|
)
|
317,735
|
(445,352
|
)
|
|||||||||
|
|||||||||||||||
After-Tax MTM Impact
|
57,058
|
(31,101
|
)
|
203,430
|
(285,136
|
)
|
|||||||||
|
|||||||||||||||
Add: Impairments of Certain North American Assets, Net of Tax
|
849,371
|
249,084
|
887,946
|
516,198
|
|||||||||||
Add: Write-off of Fees Associated with Revolving Credit Facilities, Net of Tax
|
-
|
3,656
|
-
|
3,656
|
|||||||||||
Less: Net (Gains) Losses on Asset Dispositions, Net of Tax
|
35,599
|
(33,337
|
)
|
(126,053
|
)
|
(317,342
|
)
|
||||||||
|
|||||||||||||||
Adjusted Net Income (Non-GAAP)
|
$
|
437,029
|
$
|
309,000
|
$
|
1,535,602
|
$
|
1,008,499
|
|||||||
|
|||||||||||||||
Net Income (Loss) Per Share (GAAP)
|
|||||||||||||||
Basic
|
$
|
(1.88
|
)
|
$
|
0.45
|
$
|
2.13
|
$
|
4.15
|
||||||
Diluted
|
$
|
(1.88
|
)
|
$
|
0.45
|
$
|
2.11
|
$
|
4.10
|
||||||
|
|||||||||||||||
Adjusted Net Income Per Share (Non-GAAP)
|
|||||||||||||||
Basic
|
$
|
1.62
|
$
|
1.16
|
$
|
5.74
|
$
|
3.84
|
|||||||
Diluted
|
$
|
1.61
|
$
|
1.15
|
$
|
5.67
|
(a) |
$
|
3.79
|
(b) | |||||
|
|||||||||||||||
Percentage Increase - [(a) - (b)] / (b)
|
50%
|
|
|||||||||||||
|
|||||||||||||||
Average Number of Common Shares (GAAP)
|
|||||||||||||||
Basic
|
268,941
|
266,277
|
267,577
|
262,735
|
|||||||||||
Diluted
|
268,941
|
269,524
|
270,762
|
266,268
|
|||||||||||
|
|||||||||||||||
Average Number of Shares (Non-GAAP)
|
|||||||||||||||
Basic
|
268,941
|
266,277
|
267,577
|
262,735
|
|||||||||||
Diluted
|
271,921
|
269,524
|
270,762
|
266,268
|
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 the three-month and twelve-month periods ended December 31, 2012 and 2011 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
|
Twelve Months Ended
|
|
|||||||||||||||
|
December 31,
|
December 31,
|
|
|||||||||||||||
|
2012
|
2011
|
2012
|
|
2011
|
|
||||||||||||
|
|
|
||||||||||||||||
Net Cash Provided by Operating Activities (GAAP)
|
$
|
1,227,187
|
$
|
1,236,887
|
$
|
5,236,777
|
|
$
|
4,578,410
|
|
||||||||
|
|
|
||||||||||||||||
Adjustments
|
|
|
||||||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses)
|
42,619
|
24,715
|
159,182
|
|
145,881
|
|
||||||||||||
Excess Tax Benefits from Stock-Based Compensation
|
17,609
|
-
|
67,035
|
|
-
|
|
||||||||||||
Changes in Components of Working Capital and Other Assets and Liabilities
|
|
|
||||||||||||||||
Accounts Receivable
|
66,509
|
210,815
|
178,683
|
|
339,780
|
|
||||||||||||
Inventories
|
1,996
|
9,012
|
156,762
|
|
176,623
|
|
||||||||||||
Accounts Payable
|
100,832
|
(105,702
|
)
|
17,150
|
|
(351,087
|
)
|
|
||||||||||
Accrued Taxes Payable
|
(35,303
|
)
|
8,650
|
(78,094
|
)
|
|
(92,589
|
)
|
|
|||||||||
Other Assets
|
(1,565
|
)
|
(4,975
|
)
|
118,520
|
|
23,625
|
|
||||||||||
Other Liabilities
|
3,757
|
22,036
|
(36,114
|
)
|
|
(14,986
|
)
|
|
||||||||||
|
|
|
||||||||||||||||
Changes in Components of Working Capital Associated with Investing and
Financing Activities |
13,550
|
(103,801
|
)
|
(74,158
|
)
|
|
(237,028
|
)
|
|
|||||||||
|
|
|
||||||||||||||||
Discretionary Cash Flow (Non-GAAP)
|
$
|
1,437,191
|
$
|
1,297,637
|
$
|
5,745,743
|
(a)
|
$
|
4,568,629
|
(b)
|
||||||||
|
|
|
||||||||||||||||
Percentage Increase - [(a) - (b)] / (b)
|
26
|
%
|
|
|
EOG RESOURCES, INC.
|
QUANTITATIVE RECONCILIATION OF ADJUSTED EARNINGS BEFORE INTEREST EXPENSE,
|
INCOME TAXES, DEPRECIATION, DEPLETION AND AMORTIZATION, EXPLORATION COSTS,
|
DRY HOLE COSTS, IMPAIRMENTS AND ADDITIONAL ITEMS (ADJUSTED EBITDAX)
|
(NON-GAAP) TO INCOME (LOSS) BEFORE INTEREST EXPENSE AND INCOME TAXES (GAAP)
|
(Unaudited; in thousands)
|
|
The following chart adjusts the three-month and twelve-month periods ended December 31, 2012 and 2011 reported Income (Loss) Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash realized from financial commodity derivative transactions by eliminating the unrealized mark-to-market (MTM) gains from these transactions and to eliminate the net gains (losses) on asset dispositions primarily in North America in 2012 and 2011. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income (Loss) Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry.
|
|
Three Months Ended
|
Twelve Months Ended
|
|
|||||||||||||||
|
December 31,
|
December 31,
|
|
|||||||||||||||
|
2012
|
2011
|
2012
|
|
2011
|
|
||||||||||||
|
||||||||||||||||||
Income (Loss) Before Interest Expense and Income Taxes (GAAP)
|
$
|
(386,468
|
)
|
$
|
298,223
|
$
|
1,494,292
|
|
$
|
2,120,162
|
|
|||||||
|
||||||||||||||||||
Adjustments:
|
|
|||||||||||||||||
Depreciation, Depletion and Amortization
|
786,344
|
693,527
|
3,169,703
|
|
2,516,381
|
|
||||||||||||
Exploration Costs
|
48,660
|
31,042
|
185,569
|
|
171,658
|
|
||||||||||||
Dry Hole Costs
|
1,965
|
5,999
|
14,970
|
|
53,230
|
|
||||||||||||
Impairments
|
1,020,496
|
499,624
|
1,270,735
|
|
1,031,037
|
|
||||||||||||
EBITDAX (Non-GAAP)
|
1,470,997
|
1,528,415
|
6,135,269
|
|
5,892,468
|
|
||||||||||||
Total Gains on MTM Commodity Derivative Contracts
|
(66,416
|
)
|
(145,514
|
)
|
(393,744
|
)
|
|
(626,053
|
)
|
|
||||||||
Realized Gains on MTM Commodity Derivative Contracts
|
155,533
|
96,936
|
711,479
|
|
180,701
|
|
||||||||||||
Net Losses (Gains) on Asset Dispositions
|
55,474
|
(49,928
|
)
|
(192,660
|
)
|
|
(492,909
|
)
|
|
|||||||||
Adjusted EBITDAX (Non-GAAP)
|
$
|
1,615,588
|
$
|
1,429,909
|
$
|
6,260,344
|
(a)
|
$
|
4,954,207
|
(b)
|
||||||||
|
||||||||||||||||||
Percentage Increase - [(a) - (b)] / (b)
|
26
|
%
|
|
|
EOG RESOURCES, INC.
|
CRUDE OIL AND NATURAL GAS FINANCIAL
|
COMMODITY DERIVATIVE CONTRACTS
|
|
Presented below is a comprehensive summary of EOG's crude oil and natural gas derivative contracts at February 13, 2013, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.
|
CRUDE OIL DERIVATIVE CONTRACTS
|
||||||||
Weighted
|
||||||||
|
Volume (1)
|
Average Price
|
||||||
|
(Bbld)
|
($/Bbl)
|
||||||
2013
|
||||||||
January 2013 (closed)
|
101,000
|
$
|
99.29
|
|||||
February 1, 2013 through April 30, 2013
|
109,000
|
99.17
|
||||||
May 1, 2013 through June 30, 2013
|
101,000
|
99.29
|
||||||
July 1, 2013 through December 31, 2013
|
93,000
|
98.44
|
(1)
|
EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional three-month or six-month periods. Options covering a notional volume of 8,000 Bbld are exercisable on April 30, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 8,000 Bbld at an average price of $97.66 per barrel for the period May 1, 2013 through July 31, 2013. Options covering a notional volume of 62,000 Bbld are exercisable on June 28, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 62,000 Bbld at an average price of $100.24 per barrel for the period July 1, 2013 through December 31, 2013. Options covering a notional volume of 54,000 Bbld are exercisable on December 31, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 54,000 Bbld at an average price of $98.91 per barrel for the period January 1, 2014 through June 30, 2014.
|
NATURAL GAS DERIVATIVE CONTRACTS
|
||||||||
Weighted
|
||||||||
|
Volume
|
Average Price
|
||||||
|
(MMBtud)
|
($/MMBtu)
|
||||||
2013 (2)
|
||||||||
January 1, 2013 through February 28, 2013 (closed)
|
150,000
|
$
|
4.79
|
|||||
March 1, 2013 through December 31, 2013
|
150,000
|
4.79
|
||||||
2014 (3)
|
(2)
|
EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for the period from March 1, 2013 through December 31, 2013.
|
(3)
|
In July 2012, EOG settled its natural gas financial price swap contracts for the period January 1, 2014 through December 31, 2014. In connection with these contracts, the counterparties retain an option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2014.
|
Bbld
|
Barrels per day.
|
$/Bbl
|
Dollars per barrel.
|
MMBtud
|
Million British thermal units per day.
|
$/MMBtu
|
Dollars per million British thermal units.
|
MMBtu
|
Million British thermal units.
|
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,
|
|||
|
2012
|
|||
|
||||
Total Stockholders' Equity - (a)
|
$
|
13,285
|
||
|
||||
Current and Long-Term Debt - (b)
|
6,312
|
|||
Less: Cash
|
(876
|
)
|
||
Net Debt (Non-GAAP) - (c)
|
5,436
|
|||
|
||||
Total Capitalization (GAAP) - (a) + (b)
|
$
|
19,597
|
||
|
||||
Total Capitalization (Non-GAAP) - (a) + (c)
|
$
|
18,721
|
||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]
|
32
|
%
|
||
|
||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]
|
29
|
%
|
EOG RESOURCES, INC.
|
||||||||||||||||||||||||||||
RESERVES SUPPLEMENTAL DATA
|
||||||||||||||||||||||||||||
(Unaudited)
|
||||||||||||||||||||||||||||
2012 NET PROVED RESERVES RECONCILIATION SUMMARY
|
||||||||||||||||||||||||||||
|
United
|
North
|
Other
|
Total
|
||||||||||||||||||||||||
|
States
|
Canada
|
America
|
Trinidad
|
Int'l
|
Int'l
|
Total
|
|||||||||||||||||||||
CRUDE OIL & CONDENSATE (MMBbls)
|
||||||||||||||||||||||||||||
Beginning Reserves
|
495.3
|
18.6
|
513.9
|
3.5
|
0.1
|
3.6
|
517.5
|
|||||||||||||||||||||
Revisions
|
4.1
|
(2.5
|
)
|
1.6
|
0.1
|
-
|
0.1
|
1.7
|
||||||||||||||||||||
Purchases in place
|
1.0
|
-
|
1.0
|
-
|
-
|
-
|
1.0
|
|||||||||||||||||||||
Extensions, discoveries and other additions
|
241.2
|
5.7
|
246.9
|
-
|
8.8
|
8.8
|
255.7
|
|||||||||||||||||||||
Sales in place
|
(16.0
|
)
|
(1.3
|
)
|
(17.3
|
)
|
-
|
-
|
-
|
(17.3
|
)
|
|||||||||||||||||
Production
|
(54.6
|
)
|
(2.6
|
)
|
(57.2
|
)
|
(0.6
|
)
|
-
|
(0.6
|
)
|
(57.8
|
)
|
|||||||||||||||
Ending Reserves
|
671.0
|
17.9
|
688.9
|
3.0
|
8.9
|
11.9
|
700.8
|
|||||||||||||||||||||
|
||||||||||||||||||||||||||||
NATURAL GAS LIQUIDS (MMBbls)
|
||||||||||||||||||||||||||||
Beginning Reserves
|
226.6
|
1.2
|
227.8
|
-
|
-
|
-
|
227.8
|
|||||||||||||||||||||
Revisions
|
47.3
|
0.6
|
47.9
|
-
|
-
|
-
|
47.9
|
|||||||||||||||||||||
Purchases in place
|
0.6
|
-
|
0.6
|
-
|
-
|
-
|
0.6
|
|||||||||||||||||||||
Extensions, discoveries and other additions
|
71.4
|
0.2
|
71.6
|
-
|
-
|
-
|
71.6
|
|||||||||||||||||||||
Sales in place
|
(7.3
|
)
|
(0.1
|
)
|
(7.4
|
)
|
-
|
-
|
-
|
(7.4
|
)
|
|||||||||||||||||
Production
|
(20.2
|
)
|
(0.3
|
)
|
(20.5
|
)
|
-
|
-
|
-
|
(20.5
|
)
|
|||||||||||||||||
Ending Reserves
|
318.4
|
1.6
|
320.0
|
-
|
-
|
-
|
320.0
|
|||||||||||||||||||||
|
||||||||||||||||||||||||||||
NATURAL GAS (Bcf)
|
||||||||||||||||||||||||||||
Beginning Reserves
|
6,045.8
|
1,035.9
|
7,081.7
|
750.7
|
18.5
|
769.2
|
7,850.9
|
|||||||||||||||||||||
Revisions
|
(1,736.0
|
)
|
(894.5
|
)
|
(2,630.5
|
)
|
(24.1
|
)
|
1.6
|
(22.5
|
)
|
(2,653.0
|
)
|
|||||||||||||||
Purchases in place
|
14.8
|
-
|
14.8
|
-
|
-
|
-
|
14.8
|
|||||||||||||||||||||
Extensions, discoveries and other additions
|
477.8
|
-
|
477.8
|
-
|
0.3
|
0.3
|
478.1
|
|||||||||||||||||||||
Sales in place
|
(386.2
|
)
|
(8.5
|
)
|
(394.7
|
)
|
-
|
-
|
-
|
(394.7
|
)
|
|||||||||||||||||
Production
|
(380.2
|
)
|
(34.6
|
)
|
(414.8
|
)
|
(138.4
|
)
|
(3.4
|
)
|
(141.8
|
)
|
(556.6
|
)
|
||||||||||||||
Ending Reserves
|
4,036.0
|
98.3
|
4,134.3
|
588.2
|
17.0
|
605.2
|
4,739.5
|
|||||||||||||||||||||
|
||||||||||||||||||||||||||||
OIL EQUIVALENTS (MMBoe)
|
||||||||||||||||||||||||||||
Beginning Reserves
|
1,729.5
|
192.5
|
1,922.0
|
128.6
|
3.2
|
131.8
|
2,053.8
|
|||||||||||||||||||||
Revisions
|
(237.9
|
)
|
(151.0
|
)
|
(388.9
|
)
|
(3.9
|
)
|
0.2
|
(3.7
|
)
|
(392.6
|
)
|
|||||||||||||||
Purchases in place
|
4.1
|
-
|
4.1
|
-
|
-
|
-
|
4.1
|
|||||||||||||||||||||
Extensions, discoveries and other additions
|
392.2
|
5.8
|
398.0
|
-
|
8.9
|
8.9
|
406.9
|
|||||||||||||||||||||
Sales in place
|
(87.6
|
)
|
(2.8
|
)
|
(90.4
|
)
|
-
|
-
|
-
|
(90.4
|
)
|
|||||||||||||||||
Production
|
(138.2
|
)
|
(8.7
|
)
|
(146.9
|
)
|
(23.6
|
)
|
(0.6
|
)
|
(24.2
|
)
|
(171.1
|
)
|
||||||||||||||
Ending Reserves
|
1,662.1
|
35.8
|
1,697.9
|
101.1
|
11.7
|
112.8
|
1,810.7
|
|||||||||||||||||||||
|
||||||||||||||||||||||||||||
Net Proved Developed Reserves (MMBoe)
|
||||||||||||||||||||||||||||
At December 31, 2011
|
877.3
|
58.5
|
935.8
|
103.7
|
3.2
|
106.9
|
1,042.7
|
|||||||||||||||||||||
At December 31, 2012
|
840.6
|
24.3
|
864.9
|
81.8
|
3.1
|
84.9
|
949.8
|
|||||||||||||||||||||
|
||||||||||||||||||||||||||||
2012 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions)
|
||||||||||||||||||||||||||||
|
United
|
North
|
Other
|
Total
|
||||||||||||||||||||||||
|
States
|
Canada
|
America
|
Trinidad
|
Int'l
|
Int'l
|
Total
|
|||||||||||||||||||||
|
||||||||||||||||||||||||||||
Acquisition Cost of Unproved Properties
|
$
|
471.3
|
$
|
33.6
|
$
|
504.9
|
$
|
1.0
|
$
|
(0.6
|
)
|
$
|
0.4
|
$
|
505.3
|
|||||||||||||
Exploration Costs
|
333.6
|
38.5
|
372.1
|
19.6
|
53.9
|
73.5
|
445.6
|
|||||||||||||||||||||
Development Costs
|
5,576.9
|
245.7
|
5,822.6
|
31.1
|
135.9
|
167.0
|
5,989.6
|
|||||||||||||||||||||
Total Drilling
|
6,381.8
|
317.8
|
6,699.6
|
51.7
|
189.2
|
240.9
|
6,940.5
|
|||||||||||||||||||||
Acquisition Cost of Proved Properties
|
0.7
|
-
|
0.7
|
-
|
-
|
-
|
0.7
|
|||||||||||||||||||||
Total Exploration & Development Expenditures
|
6,382.5
|
317.8
|
6,700.3
|
51.7
|
189.2
|
240.9
|
6,941.2
|
|||||||||||||||||||||
Gathering, Processing and Other
|
633.4
|
50.2
|
683.6
|
0.2
|
1.8
|
2.0
|
685.6
|
|||||||||||||||||||||
Asset Retirement Costs
|
80.5
|
33.3
|
113.8
|
1.5
|
11.7
|
13.2
|
127.0
|
|||||||||||||||||||||
Total Expenditures
|
7,096.4
|
401.3
|
7,497.7
|
53.4
|
202.7
|
256.1
|
7,753.8
|
|||||||||||||||||||||
Proceeds from Sales in Place
|
(1,182.3
|
)
|
(127.5
|
)
|
(1,309.8
|
)
|
-
|
-
|
-
|
(1,309.8
|
)
|
|||||||||||||||||
Net Expenditures
|
$
|
5,914.1
|
$
|
273.8
|
$
|
6,187.9
|
$
|
53.4
|
$
|
202.7
|
$
|
256.1
|
$
|
6,444.0
|
||||||||||||||
|
||||||||||||||||||||||||||||
RESERVE REPLACEMENT COSTS ($ / Boe ) *
|
||||||||||||||||||||||||||||
Total Drilling, Before Revisions
|
$
|
16.22
|
$
|
54.79
|
$
|
16.78
|
$
|
-
|
$
|
21.26
|
$
|
27.07
|
$
|
17.01
|
||||||||||||||
All-in Total, Net of Revisions
|
$
|
40.17
|
$
|
(2.19
|
)
|
$
|
506.06
|
$
|
(13.26
|
)
|
$
|
20.79
|
$
|
46.33
|
$
|
376.14
|
||||||||||||
All-in Total, Excluding Revisions Due to Price
|
$
|
11.82
|
$
|
62.31
|
$
|
12.29
|
$
|
(15.67
|
)
|
$
|
20.79
|
$
|
41.53
|
$
|
12.60
|
|||||||||||||
|
||||||||||||||||||||||||||||
RESERVE REPLACEMENT *
|
||||||||||||||||||||||||||||
Drilling Only
|
284
|
%
|
67
|
%
|
271
|
%
|
0
|
%
|
1,483
|
%
|
37
|
%
|
238
|
%
|
||||||||||||||
All-in Total, Net of Revisions & Dispositions
|
51
|
%
|
-1,701
|
%
|
-53
|
%
|
-17
|
%
|
1,517
|
%
|
21
|
%
|
-42
|
%
|
||||||||||||||
All-in Total, Excluding Revisions Due to Price
|
326
|
%
|
26
|
%
|
308
|
%
|
-14
|
%
|
1,517
|
%
|
24
|
%
|
268
|
%
|
||||||||||||||
All-in Total, Liquids
|
458
|
%
|
90
|
%
|
444
|
%
|
17
|
%
|
0
|
%
|
1,483
|
%
|
452
|
%
|
||||||||||||||
|
||||||||||||||||||||||||||||
* 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 ($ / BOE)
|
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 Boe. 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. The following chart also reconciles Total Expenditures (GAAP) to Total Cash Expenditures (Non-GAAP) in respect of EOG's 2012 capital expenditure program.
|
|
United
|
North
|
Other
|
Total
|
||||||||||||||||||||||||
|
States
|
Canada
|
America
|
Trinidad
|
Int'l
|
Int'l
|
Total
|
|||||||||||||||||||||
|
||||||||||||||||||||||||||||
Total Costs Incurred in Exploration and Development
Activities (GAAP) |
$
|
6,463.0
|
$
|
351.1
|
$
|
6,814.1
|
$
|
53.2
|
$
|
200.9
|
$
|
254.1
|
$
|
7,068.2
|
||||||||||||||
Less: Asset Retirement Costs
|
(80.5
|
)
|
(33.3
|
)
|
(113.8
|
)
|
(1.5
|
)
|
(11.7
|
)
|
(13.2
|
)
|
(127.0
|
)
|
||||||||||||||
Non-Cash Acquisition Costs of Unproved Properties
|
(20.3
|
)
|
-
|
(20.3
|
)
|
-
|
-
|
-
|
(20.3
|
)
|
||||||||||||||||||
Acquisition Cost of Proved Properties
|
(0.7
|
)
|
-
|
(0.7
|
)
|
-
|
-
|
-
|
(0.7
|
)
|
||||||||||||||||||
Total Exploration & Development Expenditures for
Drilling Only (Non-GAAP) (a) |
$
|
6,361.5
|
$
|
317.8
|
$
|
6,679.3
|
$
|
51.7
|
$
|
189.2
|
$
|
240.9
|
$
|
6,920.2
|
||||||||||||||
|
||||||||||||||||||||||||||||
Total Costs Incurred in Exploration and Development Activities (GAAP)
|
$
|
6,463.0
|
$
|
351.1
|
$
|
6,814.1
|
$
|
53.2
|
$
|
200.9
|
$
|
254.1
|
$
|
7,068.2
|
||||||||||||||
Less: Asset Retirement Costs
|
(80.5
|
)
|
(33.3
|
)
|
(113.8
|
)
|
(1.5
|
)
|
(11.7
|
)
|
(13.2
|
)
|
(127.0
|
)
|
||||||||||||||
Non-Cash Acquisition Costs of Unproved Properties
|
(20.3
|
)
|
-
|
(20.3
|
)
|
-
|
-
|
-
|
(20.3
|
)
|
||||||||||||||||||
|
||||||||||||||||||||||||||||
Total Exploration & Development Expenditures (Non-
GAAP) (b) |
$
|
6,362.2
|
$
|
317.8
|
$
|
6,680.0
|
$
|
51.7
|
$
|
189.2
|
$
|
240.9
|
$
|
6,920.9
|
||||||||||||||
|
||||||||||||||||||||||||||||
Total Expenditures (GAAP)
|
$
|
7,096.4
|
$
|
401.3
|
$
|
7,497.7
|
$
|
53.4
|
$
|
202.7
|
$
|
256.1
|
$
|
7,753.8
|
||||||||||||||
Less: Asset Retirement Costs
|
(80.5
|
)
|
(33.3
|
)
|
(113.8
|
)
|
(1.5
|
)
|
(11.7
|
)
|
(13.2
|
)
|
(127.0
|
)
|
||||||||||||||
Non-Cash Gathering, Processing & Other Costs (Capital
Lease) |
(65.8
|
)
|
- |
(65.8
|
)
|
- | - |
-
|
(65.8
|
)
|
||||||||||||||||||
Non-Cash Acquisition Costs of Unproved Properties
|
(20.3
|
)
|
-
|
(20.3
|
)
|
-
|
-
|
-
|
(20.3
|
)
|
||||||||||||||||||
|
||||||||||||||||||||||||||||
Total Cash Expenditures (Non-GAAP)
|
$
|
6,929.8
|
$
|
368.0
|
$
|
7,297.8
|
$
|
51.9
|
$
|
191.0
|
$
|
242.9
|
$
|
7,540.7
|
||||||||||||||
|
||||||||||||||||||||||||||||
Net Proved Reserve Additions From All Sources - Oil
Equivalents (MMBoe) |
||||||||||||||||||||||||||||
Revisions due to price (c)
|
(379.9
|
)
|
(150.3
|
)
|
(530.2
|
)
|
(0.6
|
)
|
-
|
(0.6
|
)
|
(530.8
|
)
|
|||||||||||||||
Revisions other than price
|
142.0
|
(0.7
|
)
|
141.3
|
(3.3
|
)
|
0.2
|
(3.1
|
)
|
138.2
|
||||||||||||||||||
Purchases in place
|
4.1
|
-
|
4.1
|
-
|
-
|
-
|
4.1
|
|||||||||||||||||||||
Extensions, discoveries and other additions (d)
|
392.2
|
5.8
|
398.0
|
-
|
8.9
|
8.9
|
406.9
|
|||||||||||||||||||||
Total Proved Reserve Additions (e)
|
158.4
|
(145.2
|
)
|
13.2
|
(3.9
|
)
|
9.1
|
5.2
|
18.4
|
|||||||||||||||||||
Sales in place
|
(87.6
|
)
|
(2.8
|
)
|
(90.4
|
)
|
-
|
-
|
-
|
(90.4
|
)
|
|||||||||||||||||
Net Proved Reserve Additions From All Sources (f)
|
70.8
|
(148.0
|
)
|
(77.2
|
)
|
(3.9
|
)
|
9.1
|
5.2
|
(72.0
|
)
|
|||||||||||||||||
|
||||||||||||||||||||||||||||
Production (g)
|
138.2
|
8.7
|
146.9
|
23.6
|
0.6
|
24.2
|
171.1
|
|||||||||||||||||||||
|
||||||||||||||||||||||||||||
RESERVE REPLACEMENT COSTS ($ / BOE)
|
||||||||||||||||||||||||||||
Total Drilling, Before Revisions (a / d)
|
$
|
16.22
|
$
|
54.79
|
$
|
16.78
|
$
|
-
|
$
|
21.26
|
$
|
27.07
|
$
|
17.01
|
||||||||||||||
All-in Total, Net of Revisions (b / e)
|
$
|
40.17
|
$
|
(2.19
|
)
|
$
|
506.06
|
$
|
(13.26
|
)
|
$
|
20.79
|
$
|
46.33
|
$
|
376.14
|
||||||||||||
All-in Total, Excluding Revisions Due to Price (b / (e - c))
|
$
|
11.82
|
$
|
62.31
|
$
|
12.29
|
$
|
(15.67
|
)
|
$
|
20.79
|
$
|
41.53
|
$
|
12.60
|
|||||||||||||
|
||||||||||||||||||||||||||||
RESERVE REPLACEMENT
|
||||||||||||||||||||||||||||
Drilling Only (d / g)
|
284
|
%
|
67
|
%
|
271
|
%
|
0
|
%
|
1,483
|
%
|
37
|
%
|
238
|
%
|
||||||||||||||
All-in Total, Net of Revisions & Dispositions (f / g)
|
51
|
%
|
-1,701
|
%
|
-53
|
%
|
-17
|
%
|
1,517
|
%
|
21
|
%
|
-42
|
%
|
||||||||||||||
All-in Total, Excluding Revisions Due to Price ((f - c ) / g)
|
326
|
%
|
26
|
%
|
308
|
%
|
-14
|
%
|
1,517
|
%
|
24
|
%
|
268
|
%
|
||||||||||||||
|
||||||||||||||||||||||||||||
Net Proved Reserve Additions From All Sources -
Liquids (MMBbls) |
||||||||||||||||||||||||||||
Revisions
|
51.4
|
(1.9
|
)
|
49.5
|
0.1
|
-
|
0.1
|
49.6
|
||||||||||||||||||||
Purchases in place
|
1.6
|
-
|
1.6
|
-
|
-
|
-
|
1.6
|
|||||||||||||||||||||
Extensions, discoveries and other additions (h)
|
312.6
|
5.9
|
318.5
|
-
|
8.8
|
8.8
|
327.3
|
|||||||||||||||||||||
Total Proved Reserve Additions
|
365.6
|
4.0
|
369.6
|
0.1
|
8.8
|
8.9
|
378.5
|
|||||||||||||||||||||
Sales in place
|
(23.3
|
)
|
(1.4
|
)
|
(24.7
|
)
|
-
|
-
|
-
|
(24.7
|
)
|
|||||||||||||||||
Net Proved Reserve Additions From All Sources (i)
|
342.3
|
2.6
|
344.9
|
0.1
|
8.8
|
8.9
|
353.8
|
|||||||||||||||||||||
|
||||||||||||||||||||||||||||
Production (j)
|
74.8
|
2.9
|
77.7
|
0.6
|
-
|
0.6
|
78.3
|
|||||||||||||||||||||
|
||||||||||||||||||||||||||||
RESERVE REPLACEMENT - LIQUIDS
|
||||||||||||||||||||||||||||
Drilling Only (h / j)
|
418
|
%
|
203
|
%
|
410
|
%
|
0
|
%
|
0
|
%
|
1,467
|
%
|
418
|
%
|
||||||||||||||
All-in Total, Net of Revisions & Dispositions (i / j)
|
458
|
%
|
90
|
%
|
444
|
%
|
17
|
%
|
0
|
%
|
1,483
|
%
|
452
|
%
|
EOG RESOURCES, INC.
|
|||||||||||
FIRST QUARTER AND FULL YEAR 2013 FORECAST AND BENCHMARK COMMODITY PRICING
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
(a) First Quarter and Full Year 2013 Forecast
The forecast items for the first quarter and full year 2013 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. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, 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 2013
|
|
|
Full Year 2013
|
||||||
Daily Production
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate Volumes (MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
160.0
|
-
|
|
172.0
|
|
|
180.0
|
-
|
|
197.0
|
Canada
|
|
6.5
|
-
|
|
7.5
|
|
|
6.0
|
-
|
|
7.0
|
Trinidad
|
|
0.8
|
-
|
|
1.5
|
|
|
1.0
|
-
|
|
2.0
|
Other International
|
|
0.0
|
-
|
|
0.0
|
|
|
5.0
|
-
|
|
6.0
|
Total
|
|
167.3
|
-
|
|
181.0
|
|
|
192.0
|
-
|
|
212.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Volumes (MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
52.0
|
-
|
|
56.0
|
|
|
55.5
|
-
|
|
66.0
|
Canada
|
|
0.5
|
-
|
|
0.9
|
|
|
0.5
|
-
|
|
0.8
|
Total
|
|
52.5
|
-
|
|
56.9
|
|
|
56.0
|
-
|
|
66.8
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes (MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
900
|
-
|
|
930
|
|
|
865
|
-
|
|
905
|
Canada
|
|
70
|
-
|
|
85
|
|
|
64
|
-
|
|
80
|
Trinidad
|
|
335
|
-
|
|
365
|
|
|
350
|
-
|
|
375
|
Other International
|
|
8
|
-
|
|
11
|
|
|
8
|
-
|
|
10
|
Total
|
|
1,313
|
-
|
|
1,391
|
|
|
1,287
|
-
|
|
1,370
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent Volumes (MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
362.0
|
-
|
|
383.0
|
|
|
379.7
|
-
|
|
413.8
|
Canada
|
|
18.7
|
-
|
|
22.6
|
|
|
17.2
|
-
|
|
21.1
|
Trinidad
|
|
56.6
|
-
|
|
62.3
|
|
|
59.3
|
-
|
|
64.5
|
Other International
|
|
1.3
|
-
|
|
1.8
|
|
|
6.3
|
-
|
|
7.7
|
Total
|
|
438.6
|
-
|
|
469.7
|
|
|
462.5
|
-
|
|
507.1
|
|
|
|
|
|
ESTIMATED RANGES
|
|
|
|
|
|||
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
1Q 2013
|
|
Full Year 2013
|
|||||||||
Operating Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit Costs ($/Boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
|
6.27
|
-
|
$
|
6.57
|
|
$
|
6.20
|
-
|
$
|
6.75
|
|
Transportation Costs
|
$
|
4.55
|
-
|
$
|
4.80
|
|
$
|
4.40
|
-
|
$
|
4.80
|
|
Depreciation, Depletion and Amortization
|
$
|
20.75
|
-
|
$
|
21.55
|
|
$
|
20.15
|
-
|
$
|
21.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses ($MM)
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, Dry Hole and Impairment
|
$
|
127.0
|
-
|
$
|
142.0
|
|
$
|
500.0
|
-
|
$
|
550.0
|
|
General and Administrative
|
$
|
85.0
|
-
|
$
|
90.0
|
|
$
|
365.0
|
-
|
$
|
385.0
|
|
Gathering and Processing
|
$
|
28.0
|
-
|
$
|
32.0
|
|
$
|
100.0
|
-
|
$
|
130.0
|
|
Capitalized Interest
|
$
|
12.0
|
-
|
$
|
18.0
|
|
$
|
50.0
|
-
|
$
|
62.0
|
|
Net Interest
|
$
|
55.0
|
-
|
$
|
60.0
|
|
$
|
205.0
|
-
|
$
|
225.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other Than Income (% of Wellhead Revenue)
|
|
6.2%
|
-
|
|
6.6%
|
|
|
5.6%
|
-
|
|
6.6%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective Rate
|
|
35%
|
-
|
|
45%
|
|
|
35%
|
-
|
|
45%
|
|
Current Taxes ($MM)
|
$
|
50
|
-
|
$
|
65
|
|
$
|
230
|
-
|
$
|
250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures ($MM) - FY 2013 (Excluding Non-cash Items)
|
|
|
|
|
|
|
|
|
|
|
||
Exploration and Development, Excluding Facilities
|
|
|
|
|
|
|
$
|
5,900
|
-
|
$
|
6,000
|
|
Exploration and Development Facilities
|
|
|
|
|
|
|
$
|
710
|
-
|
$
|
770
|
|
Gathering, Processing and Other
|
|
|
|
|
|
|
$
|
435
|
-
|
$
|
465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing - (Refer to Benchmark Commodity Pricing in text)
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate ($/Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
|
United States - above WTI
|
$
|
(8.50
|
) -
|
$
|
(12.50
|
)
|
$
|
(4.50
|
) -
|
$
|
(9.50
|
) |
Canada - below WTI
|
$
|
9.50
|
-
|
$
|
11.50
|
|
$
|
7.85
|
-
|
$
|
10.85
|
|
Trinidad - below WTI
|
$
|
1.05
|
-
|
$
|
3.05
|
|
$
|
1.25
|
-
|
$
|
4.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations as % of WTI
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
35%
|
-
|
|
37%
|
|
|
34%
|
-
|
|
38%
|
|
Canada
|
|
50%
|
-
|
|
52%
|
|
|
50%
|
-
|
|
54%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas ($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
|
United States - below NYMEX Henry Hub
|
$
|
0.35
|
-
|
$
|
0.55
|
|
$
|
0.30
|
-
|
$
|
0.60
|
|
Canada - below NYMEX Henry Hub
|
$
|
0.11
|
-
|
$
|
0.21
|
|
$
|
0.17
|
-
|
$
|
0.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations
|
|
|
|
|
|
|
|
|
|
|
|
|
Trinidad
|
$
|
3.12
|
-
|
$
|
3.62
|
|
$
|
2.55
|
-
|
$
|
3.25
|
|
Other International
|
$
|
4.80
|
-
|
$
|
5.30
|
|
$
|
4.70
|
-
|
$
|
5.60
|
Definitions
|
|
$/Bbl
|
U.S. Dollars per barrel
|
$/Boe
|
U.S. Dollars per barrel of oil equivalent
|
$/Mcf
|
U.S. Dollars per thousand cubic feet
|
$MM
|
U.S. Dollars in millions
|
MBbld
|
Thousand barrels per day
|
Mboed
|
Thousand barrels of oil equivalent per day
|
MMcfd
|
Million cubic feet per day
|
NYMEX
|
New York Mercantile Exchange
|
WTI
|
West Texas Intermediate
|
__N,M/O_MVU_^\X_OW_[[
MMU__];?/AC__\LMO/_VT%?WY7__SS_?QEOFI)-ZNZU/(MV=^"O46^75KOJ\Y
M7E\/-6,0@I"$(BS"1;@)#T&'7G>F#E.'J<.7I>=Q!.S^MZ$;2Y
M;L)%6`2ZRK\O2LN#E0 06'L)-"()_YQ\6&V+;PK:%6PNW;D$_[&-KN@7]
M\+&XM1PBE4.DLM\K)TCE!*G@:L'5@JL%5PL^;\%_50\*0WD,)P;E$&"_8`O]
M.CI<;55W[A;ZOTQL[VZONY>,=4&IV6$S,F9DP[\RTLPB04
M(0EQA.7?EW]?_GWY]^7?EW]?_>_C"-,S5PN>L*@H*HJ*HJ*H*"J*BM`FM`EM
MHMMXC$'[H'W0;@C@9,+)A),))Q,!;2$(1\5C=!ZC\Q@=$)JX,I_+3V+GN#)Q
M9>+*1&U;H)3EX>06^B?/P_+/]#R34@9_&!QI)GC<@IX9'(0F]DSLN04_!:5!
M:5#JXSBB9Y1UP;$/@#E>O+>]$VK;@N5IP^:$JIQ0%0C=GJ0=R.0P!JL7
MH^EG`KR>7C(F4K^I:?Q<7MEJ>L9!Q==["FBF@&8Z:M["15B$22C",?5MWB+$
M1(AI)[R%\^\7'R+HF8*>"1X3/*;M;H+'!(]IN[N%(ISG$>M,L<[$E8DK$U>F
M_?,6-#;)+Y,<:2:N3%R9-MLI^IFBGVG[O06-I\93XZFQ:0]"$X0F"$T0FM@S
M;>Q3S"+%+!*$)@A->_X41TAQA"VPLQ$$J@D0MG"4BK0F.-J""+
M_VKMYMAEW@K=[CV"J<6KW(LNSA]2)8#:@L=@9Z&*/.#\D>,]Q5RVX(WZ`;@(
MK)I8-;%J@K*4TI!2&O;F]$5X"#?A_/ODBJ>Y+;2:0JLI?R-E=*30:@JMI@22
ME%*20JLIM)HR6+:@#>L)K:;0:DJO20DW:8^48JPIP2>E_*08:]JA)4),.[04
M8TTQUL2,B1E3C#7%6%.,->%DSK:S*2U;*^5OI8RNQ(PI_IX./;9@X$PSIQ\I
M?)^K9\[T4[_[T_/'3]G31H?#@_%I`OHIH)]@-D7)4R@\Q;)3P#I%I?/$-#\R
MWE.X-L%F@LTM%.$\$L9,C)G0,J%E(LI$E`DD$T@F?DR0N(5S)\U_M)AH,4%B
M(H($B0D-$AMN2M.&X\6&F]OT8R9#GBT4P?.8TFD.Y.QW]Z:
T$4P2*90QM)T`-%,MPF,^U1)/@U@$[$#CW
M1<)\WFMG%$=3C72'Z$6,GZW=N38T^KY>7?]-MD;J;9BM;14!MD:J;IBMCY+5
M2S.)89&]8/QX1=AZTHC("T2(U;"UW8A(%T%V9NPG0B-P`_OOF+Q,1V@9@9N)
M.F">X2309,`!5F6JQK$!*G&8JJ>6*"-4G6J((U4GX@(4Y3!5XW8(E-@P52=`
M'6<\SL%WA%9AK$>63@6;L_"3P49WM2T;Y1'&-ASS\&D(O3\FZ*RV'&\VB[K?
M;W[3WQXV1-[A4`U0G\.J*'.L/:4Q]._UL-KJ0-&?M$?8?::4^7S9+[+;FX0(
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