EX-99.1 2 exh99_1.htm PRESS RELEASE OF EOG RESOURCES, INC.
EXHIBIT 99.1


EOG Resources, Inc.
 
News Release
 
For Further Information Contact:
Investors
 
Maire A. Baldwin
 
(713) 651-6EOG (651-6364)
 
Elizabeth M. Ivers
 
(713) 651-7132
 
Kimberly A. Matthews
 
(713) 571-4676
 
 
 
Media
 
K Leonard
 
(713) 571-3870

 
EOG Resources Reports Outstanding 2012 Results; Increases Eagle Ford and Leonard Reserve Potential; Announces New Texas Delaware Basin Wolfcamp Play; Raises Common Stock Dividend by 10 Percent

·
Achieves 39 Percent Year-Over-Year Total Company Crude Oil and Condensate Growth and 37 Percent Total Liquids Growth
·
Reports 10 Percent Total Company Production Growth
·
Delivers Strong Year-Over-Year Growth in Non-GAAP Earnings Per Share, Adjusted EBITDAX and Discretionary Cash Flow
·
Increases Eagle Ford Potential Recoverable Reserve Estimate by 600 MMBoe to 2.2 BnBoe, Net to EOG
·
Highlights Record Eagle Ford Oil Well
·
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
·
Realizes Improvements in Bakken/Three Forks Operations
·
Delivers 268 Percent Reserve Replacement at Attractive Finding Costs, Excluding
Price-Related Reserve Revisions
·
Raises Common Stock Dividend for 14th Time in 14 Years

FOR IMMEDIATE RELEASE: Wednesday, February 13, 2013

HOUSTON – EOG Resources, Inc. (EOG) today reported full year 2012 net income of $570.3 million, or $2.11 per share, as compared to $1,091.1 million, or $4.10 per share, for the full year 2011. For the fourth quarter 2012, EOG reported a net loss of $505.0 million, or $1.88 per share. This compares to fourth quarter 2011 net income of $120.7 million, or $0.45 per share.
Adjusted non-GAAP net income for the full year 2012 was $1,535.6 million, or $5.67 per share, and for the full year 2011 was $1,008.5 million, or $3.79 per share. Adjusted non-GAAP net income for the fourth quarter 2012 was $437.0 million, or $1.61 per share, and for the fourth quarter 2011 was $309.0 million, or $1.15 per share.
Consistent with some analysts' practice of matching realizations to settlement months and making certain other adjustments in order to exclude one-time items, the results for the fourth quarter 2012 include $849.4 million, net of tax ($3.13 per share) of impairments of certain Canadian natural gas assets, net losses on asset dispositions of $35.6 million, net of tax ($0.13 per share) and a previously disclosed non-cash net gain of $66.4 million ($42.5 million after tax, or $0.16 per share) on the mark-to-market of financial commodity derivative contracts. During the fourth quarter, the net cash inflow related to financial commodity derivative contracts was $155.5 million ($99.5 million after tax, or $0.37 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income/loss.)
Reflecting EOG's higher revenue and production weighting to crude oil for the full year 2012, adjusted non-GAAP net income per share increased 50 percent, adjusted EBITDAX increased 26 percent and discretionary cash flow increased 26 percent as compared to 2011. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income per share to GAAP net income per share, adjusted EBITDAX (non-GAAP) to income before interest expense and income taxes (GAAP) and non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP).)
In the United States, crude oil and condensate production increased 46 percent for the full year 2012 compared to the prior year. Total United States liquids (crude oil, condensate and natural gas liquids) production increased 42 percent for full year 2012 over the same period a year ago. On a total company basis, total crude oil and condensate production increased 39 percent and total liquids production increased 37 percent for the full year compared to 2011. Overall total company production increased 10 percent year-over-year.
"We accomplished all of EOG's 2012 goals. We generated high margin organic crude oil production growth and delivered excellent year-over-year increases in EOG's financial metrics. We maintained our net-debt-to-total cap ratio below 30 percent and recorded strong crude oil reserve replacement rates at attractive finding costs," said Mark G. Papa, Chairman and Chief Executive Officer. "In addition, we added the Delaware Basin Wolfcamp, a promising new liquids resource play to our portfolio and significantly increased the potential recoverable reserves of our largest and highest rate of return asset, the South Texas Eagle Ford. These add high-value inventory to EOG's already prolific asset base."
Operational Highlights
EOG's stellar crude oil production in 2012 was primarily driven by drilling and completion activity in the Eagle Ford where the company drilled and completed 305 net wells, operating an average of 23 drilling rigs. In the North Dakota Bakken/Three Forks, positive results from downspaced drilling tests, together with significant modifications in drilling and completion techniques, further boosted EOG's crude oil production growth. Breakthroughs in geologic modeling in the Leonard/Wolfcamp horizontal shale plays in southeastern New Mexico and West Texas also contributed to EOG's excellent performance.
EOG made strides in increasing the amount of crude oil recoverable from both its Eagle Ford and Bakken resources by testing various drilling densities and further refining completion practices. In the Eagle Ford, EOG increased the estimated recoverable potential reserves by 38 percent from 1.6 billion barrels of oil equivalent (BnBoe) to 2.2 BnBoe, net to EOG. Numerous spacing pilots across EOG's 569,000 net acres in the crude oil window point to optimal resource development on 40-acre well spacing in the east and 65 acres in the west. At current activity levels, EOG has a 12-year Eagle Ford drilling inventory.
The revised Eagle Ford reserve potential is indicative of an estimated 8 percent recovery of the estimated 26.4 net BnBoe in place on EOG's acreage. Since discovering the Eagle Ford in 2010, EOG has raised the overall estimated captured reserve potential from 900 MMBoe (million barrels of oil equivalent) to 2.2 BnBoe, net to EOG.
EOG's best Eagle Ford well to date is the Burrow Unit #2H, which had an initial production rate of 6,330 barrels of oil per day (Bopd) with 713 barrels per day (Bpd) of natural gas liquids (NGLs) and 4.1 million cubic feet per day (MMcfd) of natural gas. Offsetting the Burrow Unit #2H, the Burrow Unit #1H was completed to sales at a maximum rate of 5,424 Bopd with 600 Bpd of NGLs and 3.5 MMcfd of natural gas. Two other prolific wells, the Boothe Unit #1H and #2H, began initial production at 5,380 and 3,810 Bopd with 625 and 525 Bpd of NGLs and 3.6 and 3.0 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these Gonzales County wells.
In McMullen County, southwest of EOG's Gonzales County sweet spot, the Naylor Jones Unit 59 East #1H and West #4H had initial peak production rates of 1,670 and 1,150 Bopd with 225 and 138 Bpd of NGLs and 1.3 and 0.8 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these wells that were completed in early January 2013.
 "The Eagle Ford's potential reserves of 2.2 billion barrels of oil equivalent represent the largest domestic crude oil find net to one company in 40 years. Not only is 600 million net barrels a meaningful increase, this onshore U.S. oil field is readily accessible to premium markets," Papa said. "With both the technical acumen and high-quality assets, EOG is at the forefront in developing this world-class shale oil resource."
Over the course of 2012, EOG's North Dakota wells showed marked productivity improvement following the implementation of new completion techniques. On its 90,000 net acre Bakken Core, EOG confirmed that 320-acre well spacing is economically sound, and it is very encouraged by 160-acre results. Recent downspaced tests reflect a gain of approximately 30 percent to 70 percent in cumulative production over earlier wells drilled in the field. The Fertile 51-0410H, in which EOG has a 94 percent working interest, had a maximum initial production rate of 1,800 Bopd with 850 thousand cubic feet per day (Mcfd) of rich natural gas. The first 160-acre spaced wells in the Core area, the Wayzetta 022-1509H and 149-1509H, had maximum rates of 1,185 and 1,265 Bopd, respectively. EOG has 68 percent working interest in these wells.
Southwest of the Bakken Core in the Antelope Extension, the Hawkeye 01-2501H and 102-2501H were completed to sales in early January 2013. These McKenzie County wells, in which EOG has 75 percent working interest, were turned to sales at 2,445 and 2,945 Bopd, respectively. In the Stateline area near the North Dakota/Montana border, the Garden Coulee 001-1410H had an initial production rate of 1,415 Bopd with 1,260 Mcfd of rich natural gas. EOG has a 74 percent working interest in this Williams County, N.D., well.
On the Texas side of the Delaware Basin, EOG confirmed a new shale play with the completion of two horizontal Wolfcamp wells on its 114,000 net acre position. In Reeves County, the Harrison Ranch #56-1002H and #56-1001H tested at rates of 377 Bopd with 602 Bpd of NGLs and 3.9 MMcfd of natural gas and 635 Bopd with 480 Bpd of NGLs and 3.1 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these wells. Based on the geologic characteristics of the formation and the potential to drill multiple laterals combined with data from over 200 previously drilled vertical wells on EOG's acreage, estimated net potential reserves are approximately 800 MMBoe, a mix of crude oil and liquids-rich natural gas.
In southeastern New Mexico, the overall economics and size of EOG's horizontal Delaware Basin Leonard Shale play improved last year due to strong well results and decreased drilling costs. The Vaca 14 Fed #6H was completed in Lea County at an initial rate of 1,290 Bopd with 255 Bpd of NGLs and 1.4 MMcfd of natural gas. EOG has 100 percent working interest in this well. EOG has increased the total net reserve potential on its 73,000 net acres from 65 MMBoe to 550 MMBoe, predicated on better well results and a 50 percent crude oil yield. Total potential reserves on EOG's Delaware Basin horizontal Wolfcamp and Leonard Shale plays are estimated to be 1.35 BnBoe, net.
During 2012, EOG secured premium pricing for some of its Bakken, Eagle Ford and Permian Basin crude oil by expanding its innovative crude-by-rail operations. Commissioned in April 2012, a crude oil unloading terminal at St. James, La., enabled EOG to achieve average domestic crude oil realizations exceeding benchmark West Texas Intermediate indices.
Reserves
EOG's total company net proved reserves were 1,811 MMBoe at December 31, 2012. Total company net proved developed reserves decreased 2 percent, and total North American net proved developed reserves were approximately flat with the previous year, excluding the impact of property dispositions. Total company net proved undeveloped reserves decreased 15 percent year over year due to low natural gas prices in 2012 that caused essentially all of the previously booked proved undeveloped reserves in EOG's North American dry gas properties to be written off. Total proved liquids reserves increased 37 percent year-over-year, comprising 56 percent of total company proved reserves at December 31, 2012.
In 2012:
·
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.)
·
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.)
·
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.)
·
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.
For the 25th consecutive year, internal reserve estimates were within 5 percent of those prepared by the independent reserve engineering firm of DeGolyer and MacNaughton (D&M). For 2012, D&M prepared a complete independent engineering analysis of properties comprising 87 percent of EOG's proved reserves on a Boe basis.
Capital Structure
EOG's 2012 total cash capital expenditure program was approximately $7.5 billion. (Please refer to the attached tables for the reconciliation of total expenditures (GAAP) to total cash expenditures (non-GAAP).) Through year-end 2012, EOG's cash proceeds from asset sales were approximately $1.3 billion.
At December 31, 2012, EOG's total debt outstanding was $6,312 million for a debt-to-total capitalization ratio of 32 percent. Taking into account cash on the balance sheet of $876 million at the end of the fourth quarter, EOG's net debt was $5,436 million for a net debt-to-total capitalization ratio of 29 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)
"2012 marked a turning point for EOG. We continued to develop our key crude oil assets while locking up core natural gas and Combo acreage in the Barnett, Leonard and Wolfcamp plays for the long term. In addition, we exited the Kitimat LNG project," Papa said.
2013 Plans
EOG is targeting total company crude oil production growth of 28 percent with a 23 percent increase in total liquids production in 2013. In North America, natural gas production is expected to decrease 15 percent from 2012. EOG is continuing to de-emphasize natural gas drilling in a weak price environment. Driven by high margin, domestic crude oil production, overall EOG's total company production is expected to increase 4 percent over 2012.
Estimated exploration and development expenditures for 2013 are expected to range from $7.0 to $7.2 billion, including production facilities and midstream expenditures, and excluding acquisitions. Overall asset sales are expected to be approximately $550 million, of which $466 million has closed to date.
In 2013, EOG plans an active crude oil and liquids exploration program focusing on increasing recovery of hydrocarbons in existing plays and pursuing new greenfield opportunities. The majority of EOG's capital expenditures will be directed toward its two key crude oil assets, the Eagle Ford and Bakken/Three Forks. The Eagle Ford, where EOG estimates it will drill and complete approximately 400 net wells, is expected to contribute the largest share of company production growth in 2013. In the North Dakota Bakken Core and Antelope Extension Bakken/Three Forks, plans are to test additional downspaced drilling patterns. In its southeastern New Mexico horizontal Leonard/West Texas Wolfcamp Shale plays, EOG anticipates operating a moderate drilling program in 2013. Drilling activity in the new Delaware Basin Wolfcamp play is expected to ramp up over the next two years to achieve significant production growth for EOG beginning in 2015. Very minimal dry gas drilling activity is expected in 2013.
"EOG's demonstrated ability to organically grow crude oil volumes should lead to strong 2013 returns," Papa said. "Until other commodity prices strengthen, we are directing EOG's capex dollars almost exclusively toward crude oil exploration and development. Leading with our Eagle Ford and North Dakota operations, EOG is well positioned to achieve its game plan, while identifying strategic marketing advances that will further strengthen our position. With the most attractive drilling program in our history, EOG has the critical assets in place to make 2013 another outstanding year."
2013 Hedging
For the period January 1 through June 30, 2013, EOG has crude oil financial price swap contracts in place for an average of 105,000 Bopd at a weighted average price of $99.23 per barrel, excluding unexercised options. For the period July 1 through December 31, 2013, EOG has an average of 93,000 Bopd hedged at a weighted average price of $98.44 per barrel, excluding unexercised options.
Despite very minimal dry natural gas drilling activity planned for 2013, EOG has financial price swap contracts in place for 150,000 million British thermal units per day of natural gas at a weighted average price of $4.79 per million British thermal units, excluding unexercised options for the calendar year. (For a comprehensive summary of EOG's crude oil and natural gas derivative contracts, please refer to the attached tables.)
Dividend Increase
Following an increase in the common stock dividend in 2012, EOG's Board of Directors has again increased the cash dividend on the common stock. Effective with the dividend payable on April 30, 2013, to holders of record as of April 16, 2013, the quarterly dividend on the common stock will be $0.1875 per share, an increase of 10 percent over the previous indicated annual rate. The indicated annual rate of $0.75 per share reflects the 14th increase in 14 years.
Conference Call Scheduled for Thursday, February 14, 2013
EOG's fourth quarter and full year 2012 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Thursday, February 14, 2013. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through Thursday, February 28, 2013.
 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, generate income or cash flows or pay dividends 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 and condensate, natural gas liquids, 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, advanced completion technologies and hydraulic fracturing;
·
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;
·
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, 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;
·
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, and to otherwise satisfy its capital expenditure requirements;
·
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 use of competing energy sources and the development of alternative energy sources;
·
the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
·
acts of war and terrorism and responses to these acts; and
·
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.

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 "potential" reserves and/or other 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, 2011, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.  In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

 
 
 
EOG RESOURCES, INC.
FINANCIAL REPORT
 (Unaudited; in millions, except per share data)
  
 
 
Three Months Ended
  
Twelve Months Ended
  
 
December 31,
  
December 31,
  
 
2012
  
2011
  
2012
  
2011
  
 
  
   
   
   
 
Net Operating Revenues
  
$
3,011.8
    
$
2,773.0
    
$
11,682.6
    
$
10,126.1
  
Net Income (Loss)
  
$
(505.0
)
  
$
120.7
    
$
570.3
    
$
1,091.1
  
Net Income (Loss) Per Share
                                
Basic
  
$
(1.88
)
  
$
0.45
    
$
2.13
    
$
4.15
  
Diluted
  
$
(1.88
)
  
$
0.45
    
$
2.11
    
$
4.10
  
Average Number of Common Shares
                                
Basic
    
268.9
      
266.3
      
267.6
      
262.7
  
Diluted
    
268.9
      
269.5
      
270.8
      
266.3
  
 
 

SUMMARY INCOME STATEMENTS
(Unaudited; in thousands, except per share data)
  
 
 
  
Three Months Ended
    
Twelve Months Ended
  
 
  
December 31,
    
December 31,
  
 
  
2012
    
2011
    
2012
    
2011
  
Net Operating Revenues
  
   
   
   
 
Crude Oil and Condensate
  
$
1,460,684
    
$
1,189,250
    
$
5,659,437
    
$
3,838,284
  
Natural Gas Liquids
    
208,493
      
240,260
      
727,177
      
779,364
  
Natural Gas
    
418,329
      
479,825
      
1,571,762
      
2,240,540
  
Gains on Mark-to-Market Commodity Derivative Contracts
    
66,416
      
145,514
      
393,744
      
626,053
  
Gathering, Processing and Marketing
    
903,404
      
654,489
      
3,096,694
      
2,115,792
  
Gains (Losses) on Asset Dispositions, Net
    
(55,474
)
    
49,928
      
192,660
      
492,909
  
Other, Net
    
9,959
      
13,749
      
41,162
      
33,173
  
Total
    
3,011,811
      
2,773,015
      
11,682,636
      
10,126,115
  
Operating Expenses
                                
Lease and Well
    
234,349
      
261,244
      
1,000,052
      
941,954
  
Transportation Costs
    
169,789
      
122,046
      
601,431
      
430,322
  
Gathering and Processing Costs
    
25,542
      
25,283
      
97,945
      
80,727
  
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
  
Marketing Costs
    
880,451
      
644,687
      
3,035,494
      
2,072,137
  
Depreciation, Depletion and Amortization
    
786,344
      
693,527
      
3,169,703
      
2,516,381
  
General and Administrative
    
86,679
      
85,108
      
331,545
      
304,811
  
Taxes Other Than Income
    
135,597
      
101,880
      
495,395
      
410,549
  
Total
    
3,389,872
      
2,470,440
      
10,202,839
      
8,012,806
  
 
Operating Income (Loss)
    
(378,061
)
    
302,575
      
1,479,797
      
2,113,309
  
 
Other Income (Expense), Net
    
(8,407
)
    
(4,352
)
    
14,495
      
6,853
  
 
Income (Loss) Before Interest Expense and Income Taxes
    
(386,468
)
    
298,223
      
1,494,292
      
2,120,162
  
 
Interest Expense, Net
    
59,354
      
56,591
      
213,552
      
210,363
  
 
Income (Loss) Before Income Taxes
    
(445,822
)
    
241,632
      
1,280,740
      
1,909,799
  
 
Income Tax Provision
    
59,177
      
120,934
      
710,461
      
818,676
  
 
Net Income (Loss)
  
$
(504,999
)
  
$
120,698
    
$
570,279
    
$
1,091,123
  
 
Dividends Declared per Common Share
  
$
0.17
    
$
0.16
    
$
0.68
    
$
0.64
  
 
 
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