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 |