EXHIBIT 99.1
| News Release | |
| For Further Information Contact: | Investors |
| Maire A. Baldwin | |
| (713) 651-6EOG (651-6364) | |
| Elizabeth M. Ivers | |
| (713) 651-7132 | |
| Media | |
| K Leonard | |
| (713) 571-3870 |
EOG Resources Reports First Quarter 2012 Results and Raises 2012 Liquids Production Growth Target
- Achieves 49 Percent Crude Oil and Condensate Production Increase and 48 Percent Increase in Total Liquids Production Over First Quarter 2011
- Increases 2012 Total Company Liquids Production Target to 33 Percent from 30 Percent
- Reports Strong Year-Over-Year Earnings Per Share, Discretionary Cash Flow and Adjusted EBITDAX Performance
- Delivers Solid Execution in Eagle Ford Operations and Confirms Viability of Downspaced Drilling
- Announces Additional Bakken Infill Drilling Success and Positive Results from Expanded Williston Basin Program
- Commissions St. James, Louisiana, Crude Oil Offloading Facility and Wisconsin Sand Plant
FOR IMMEDIATE RELEASE: Tuesday, May 8, 2012
HOUSTON – EOG Resources, Inc. (EOG) today reported first quarter 2012 net income of $324.0 million, or $1.20 per share. This compares to first quarter 2011 net income of $134.0 million, or $0.52 per share.
Consistent with some analysts’ practice of matching realizations to settlement months and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the quarter was $317.5 million, or $1.17 per share. Adjusted non-GAAP net income for the first quarter 2011 was $177.0 million, or $0.68 per share. The results for the first quarter 2012 included a $37.0 million, net of tax ($0.14 per share) impairment of certain North American non-core assets, net gains on asset dispositions of $43.2 million, net of tax ($0.16 per share) and a previously disclosed non-cash net gain of $134.2 million ($85.9 million after tax, or $0.32 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $133.6 million ($85.6 million after tax, or $0.31 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)
Delivering on its goals of strong earnings, discretionary cash flow and adjusted EBITDAX growth, EOG posted robust financial metrics for the first quarter 2012 versus the same prior year period. Compared to the first quarter 2011, earnings per share increased 131 percent, discretionary cash flow increased 39 percent and adjusted EBITDAX rose 39 percent. (Please refer to the attached tables for the reconciliation of non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP) and adjusted EBITDAX (non-GAAP) to income before interest expense and income taxes (GAAP).)
“To put it simply, the marked improvement in productivity from individual wells is flowing to EOG’s bottom line,” said Mark G. Papa, Chairman and Chief Executive Officer. “Our first quarter 2012 performance reflects both our prudent strategy of reinventing EOG as an oil company and underscores our early-mover advantage in prolific new domestic crude oil shale plays where we continue to hone our drilling and completion acumen.”
Operational Highlights
Total company crude oil and condensate production increased 49 percent during the first quarter 2012 as compared to the first quarter 2011. United States crude oil and condensate production increased 61 percent driven by outstanding operational results from EOG’s big four crude oil and liquids plays: the South Texas Eagle Ford, the North Dakota Bakken, the Fort Worth Barnett Combo and the Permian Basin Wolfcamp and Leonard. Total company natural gas liquids production increased 44 percent due to liquids-rich natural gas from these same four plays in which EOG holds premier acreage positions. Combined, EOG’s first quarter 2012 total company liquids production from crude oil, condensate and natural gas liquids increased 48 percent over the same prior year period.
Based on its first quarter 2012 operational results, EOG has raised its 2012 total company liquids production growth target to 33 percent from 30 percent and increased its total company production growth target to 7 percent from 5.5 percent.
Crude Oil and Liquids Activity
In the South Texas Eagle Ford, EOG is pursuing field development on spacing densities of 65 to 90 acres between wells. Production flow rates to date confirm well results equal to, or better than, previous development patterns. Testing is under way to address the viability of further downspacing and possible impact on well reserves and recovery factors.
In Gonzales County, the northeastern part of its Eagle Ford acreage, EOG drilled two new Henkhaus wells offsetting a series of six Henkhaus wells completed in late 2011. The Henkhaus Unit #5H well, drilled with a short lateral offsetting the previously drilled and producing Henkhaus Unit #4H, was turned to sales at 2,775 barrels of oil per day (Bopd) with 438 barrels per day (Bpd) of natural gas liquids (NGLs) and 2.3 million cubic feet per day (MMcfd) of natural gas. The Henkhaus Unit #4H, on-line since mid-December 2011, has produced over 130 thousand barrels of oil equivalent (Mboe). The Henkhaus Unit #12H, drilled offsetting the Henkhaus Unit #5H, began flowing at an initial rate of 3,000 Bopd with 425 Bpd of NGLs and 2.2 MMcfd of natural gas. Drilled on 65-acre spacing between wells, the Lord A Unit #2H and A Unit #3H were completed at 2,448 and 2,562 Bopd with 440 and 400 Bpd of NGLs and 2.3 and 2.1 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these wells. Also in Gonzales County, the Brothers #4H, #5H and #6H began initial production at 3,424, 2,260 and 2,334 Bopd with 370, 233 and 274 Bpd of NGLs and 1.9, 1.2 and 1.4 MMcfd of natural gas, respectively. After 30 days on-line, these wells, in which EOG has 90 percent working interest, were producing 2,046, 1,427 and 1,553 Bopd, respectively.
In Karnes County, the center of EOG’s 120-mile long Eagle Ford trend, the Alton Unit #2H, Unit #3H, Unit #4H, Unit #5H and Unit #6H were drilled on 85-acre spacing. The wells, in which EOG has 100 percent working interest, were completed to sales at initial individual production rates ranging from 1,940 to 3,158 Bopd with 206 to 329 Bpd of NGLs and 1.1 to 1.7 MMcfd of natural gas. The Alton Unit #6H had an average 30-day production rate of 1,770 Bopd. In McMullen County, the southwestern part of EOG’s acreage, the Thelma-Brite #4H and #6H were completed to sales at rates of 1,697 and 1,902 Bopd each with 96 Bpd of NGLs and 500 thousand cubic feet per day (Mcfd) of natural gas, respectively.
“Our confidence level in the Eagle Ford is very high. Even after we implemented denser well spacing earlier this year, individual well performance remains remarkably strong. In fact, based on ongoing completion refinements, 30-day crude oil production rates from recent wells have increased,” Papa said.
In the Williston Basin, EOG posted positive results from its first quarter operations that focused on three distinct areas. In EOG’s North Dakota Core Parshall Field, the Wayzetta 156-3329H, 124-3334H and 157-2835H were drilled on 320-acre infill spacing. Completed to sales at rates of 1,393, 992 and 1,083 Bopd with 600, 300 and 300 Mcfd of rich natural gas, respectively, these Mountrail County wells, in which EOG has 51 percent to 61 percent working interest, further confirm the economics and success of infill drilling. Additionally, production from previously drilled 640-acre offset wells in EOG’s Core Parshall Field responded positively to the new downspaced completions. In McKenzie County, 25 miles southwest of its Core Parshall Field, EOG identified potential in both the Three Forks and Bakken in the Antelope Extension area where it brought a number of wells to sales. Four Three Forks wells, the Clarks Creek 11-0706H, 13-1806H, 14-1819H and 16-0706H, were completed at initial per well rates ranging from 926 to 3,415 Bopd with 1.2 to 3.0 MMcfd of rich natural gas. In this same area, EOG completed a Bakken well, the Clarks Creek 101-1819H, at 2,320 Bopd with 1.4 MMcfd of rich natural gas. EOG has 100 percent working interest in these five McKenzie County wells. On the Montana/North Dakota border, EOG drilled and completed a series of wells in the Stateline and Diamond Point areas that include the Stateline 03-1522H and the Diamond 02-3625H, both in Roosevelt County, Montana, with production rates exceeding expectations. The wells, in which EOG has 80 percent and 93 percent working interest, respectively, were turned to sales at 994 and 1,097 Bopd and began flowing with 400 and 700 Mcfd of rich natural gas, respectively. On the North Dakota side of the border in Williams County, the Hardscrabble 08-0409H, in which EOG has 39 percent working interest, began production at a rate of 1,693 Bopd with 600 Mcfd of rich natural gas. Recent success in the Montana/North Dakota border areas adds approximately 200 new locations to EOG’s extensive Williston Basin crude oil drilling inventory.
EOG is testing several different methods to increase the recovery of oil in place on its Williston Basin acreage. Following encouraging infill drilling results from its Core Parshall Field, EOG plans to test downspaced drilling on certain parts of its Bakken Lite acreage outside the Core area later this year. Additionally, in mid-April EOG commenced two pilot Bakken waterflood projects in its Core Parshall Field to test secondary crude oil recovery methods as another viable way to improve oil recovery.
Another of EOG’s key plays, the Fort Worth Barnett Combo, is on track to deliver the second largest contribution to total company liquids growth in 2012. During the first quarter, EOG completed the Ford A Unit #1H, A Unit #2H, B Unit #1H and B Unit #2H with individual maximum crude oil rates ranging from 420 to 700 Bopd with 80 to 184 Bpd of NGLs and 490 to 1,110 Mcfd of natural gas. EOG has approximately 99 percent working interest in these Cooke County wells. Also in Cooke County, the Kirk Unit #1H and Unit #2H had maximum production rates of 500 and 619 Bopd with 170 and 175 Bpd of NGLs and 1,038 and 1,060 Mcfd of natural gas, respectively. EOG has 93 percent working interest in these wells. During the first quarter, EOG also drilled successful step-out wells that expand the prospective area of its Barnett Combo acreage.
In the Permian Basin, EOG has ramped up drilling activity in both the West Texas Wolfcamp and New Mexico Leonard Plays. On the border between Crockett and Irion Counties in West Texas, EOG drilled the University 40 #1303H, #1310H, #1311H and #1312H in the Middle Wolfcamp interval. The wells, in which EOG has 75 percent working interest, were completed to sales at initial individual crude oil rates ranging from 517 to 645 Bopd with NGL production of 40 to 65 Bpd and 210 to 375 Mcfd of natural gas. The Linthicum M#2H in Irion County, in which EOG has 88 percent working interest, was turned to sales at 1,027 Bopd with 137 Bpd of NGLs and 778 Mcfd of natural gas. Based on drilling results to date on its West Texas Wolfcamp acreage, EOG estimates gross per well reserves to be 430 Mboe. In Lea County, New Mexico, EOG reported drilling success from the Leonard Shale with the Caballo 23 Fed #2H, #3H and #5H, which began initial sales at 820, 1,020 and 990 Bopd with 80, 200 and 110 Bpd of NGLs and 460, 1,105 and 600 Mcfd of natural gas, respectively. EOG has 86 percent working interest in the wells.
“During the first quarter, we made progress toward achieving a number of EOG’s 2012 operational goals,” Papa said. “Production results and very strong 30-day flow rates from our Eagle Ford wells drilled on tighter spacing indicate we are effectively improving our completions. In addition, we expanded our Bakken operations in two different areas and confirmed economic infill drilling on our Core sweet spot acreage. Also, we’ve rapidly moved into development mode in the West Texas Wolfcamp. The momentum in our operations continues to drive every facet of our exploration and development activities. We are very upbeat about EOG’s potential,” Papa said.
Since the beginning of 2012, EOG has made additional strides in strategically positioning its marketing and operations. In April, EOG commissioned its crude-by-rail offloading facility at St. James, Louisiana. At this Gulf Coast sales point, EOG has the flexibility to market its Bakken, Eagle Ford and Permian crude oil production at Light Louisiana Sweet oil-indexed prices, which currently are trading at a premium to West Texas Intermediate. In addition, EOG’s Wisconsin sand plant is in full operation. With the addition of this sand, EOG has the capacity to meet the requirements for the majority of its domestic well completions this year and beyond. Self-sourced sand is expected to generate significant operational cost savings.
Natural Gas Activity
Consistent with EOG’s previously announced projections and pessimistic short-term view of the current natural gas price environment, its North American natural gas production declined by 9 percent in the first quarter 2012 compared to the same period 2011.
Hedging Activity
EOG has hedged approximately 28 percent of its North American crude oil production for 2012. For the period May 1 to June 30, 2012, EOG has crude oil financial price swap contracts in place for 52,000 barrels a day at a weighted average price of $105.80 per barrel, excluding unexercised options. For the period July 1 to December 31, 2012, EOG has crude oil financial price swap contracts in place for an average of 38,000 barrels a day at a weighted average price of $106.74 per barrel, excluding unexercised options.
EOG has hedged approximately 45 percent of its North American natural gas production for 2012. For the period June 1 through December 31, 2012, EOG has natural gas financial price swap contracts in place for 525,000 million British thermal units per day (MMBtud) at a weighted average price of $5.44 per million British thermal units (MMBtu), excluding unexercised options. For each of the years 2013 and 2014, EOG has natural gas financial price swap contracts in place for 150,000 MMBtud at a weighted average price of $4.79 per MMBtu, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)
Capital Structure
Through May 1, cash proceeds from asset sales were approximately $565 million. At March 31, 2012, EOG’s total debt outstanding was $5,011 million for a debt-to-total capitalization ratio of 28 percent. Taking into account cash on the balance sheet of $294 million at the end of the first quarter, EOG’s net debt was $4,717 million for a net debt-to-total capitalization ratio of 27 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)
“EOG made a strong start out of the gates for 2012. Based on first quarter performance in our big four plays, we’ve increased EOG’s 2012 total company liquids production growth target to 33 percent and total company production growth target to 7 percent. In the first quarter, 85 percent of EOG’s North American wellhead revenues emanated from liquids, driven by crude oil. With strong natural gas hedges in place for the remainder of the year, we are well positioned to realize our plan for 2012 while maintaining a strong balance sheet,” Papa said.
Conference Call Scheduled for May 9, 2012
EOG’s first quarter 2012 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, May 9, 2012. To listen, log on to www.eogresources.com. The webcast will be archived on EOG’s website through May 23, 2012.
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 | ||||||
| March 31, | ||||||
| 2012 | 2011 | |||||
| Net Operating Revenues | $ | 2,806.7 | $ | 1,897.1 | ||
| Net Income | $ | 324.0 | $ | 134.0 | ||
| Net Income Per Share | ||||||
| Basic | $ | 1.22 | $ | 0.52 | ||
| Diluted | $ | 1.20 | $ | 0.52 | ||
| Average Number of Common Shares | ||||||
| Basic | 266.7 | 255.2 | ||||
| Diluted | 270.2 | 258.8 | ||||
| SUMMARY INCOME STATEMENTS | ||||||
| (Unaudited; in thousands, except per share data) | ||||||
| Three Months Ended | ||||||
| March 31, | ||||||
| 2012 | 2011 | |||||
| Net Operating Revenues | ||||||
| Crude Oil and Condensate | $ | 1,310,335 | $ | 757,362 | ||
| Natural Gas Liquids | 198,310 | 148,727 | ||||
| Natural Gas | 367,284 | 583,919 | ||||
| Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | 134,208 | (66,746 | ) | |||
| Gathering, Processing and Marketing | 718,157 | 395,583 | ||||
| Gains on Asset Dispositions, Net | 67,468 | 71,742 | ||||
| Other, Net | 10,889 | 6,519 | ||||
| Total | 2,806,651 | 1,897,106 | ||||
| Operating Expenses | ||||||
| Lease and Well | 261,495 | 215,089 | ||||
| Transportation Costs | 131,842 | 97,633 | ||||
| Gathering and Processing Costs | 25,592 | 19,196 | ||||
| Exploration Costs | 42,807 | 50,909 | ||||
| Dry Hole Costs | - | 22,951 | ||||
| Impairments | 133,147 | 89,328 | ||||
| Marketing Costs | 705,468 | 385,409 | ||||
| Depreciation, Depletion and Amortization | 748,743 | 568,226 | ||||
| General and Administrative | 76,269 | 70,037 | ||||
| Taxes Other Than Income | 121,516 | 105,877 | ||||
| Total | 2,246,879 | 1,624,655 | ||||
| Operating Income | 559,772 | 272,451 | ||||
| Other Income, Net | 10,631 | 3,604 | ||||
| Income Before Interest Expense and Income Taxes | 570,403 | 276,055 | ||||
| Interest Expense, Net | 50,269 | 50,333 | ||||
| Income Before Income Taxes | 520,134 | 225,722 | ||||
| Income Tax Provision | 196,125 | 91,749 | ||||
| Net Income | $ | 324,009 | $ | 133,973 | ||
| Dividends Declared per Common Share | $ | 0.17 | $ | 0.16 | ||
| EOG RESOURCES, INC. | ||||||||
| OPERATING HIGHLIGHTS | ||||||||
| (Unaudited) | ||||||||
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2012 | 2011 | |||||||
| Wellhead Volumes and Prices | ||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | ||||||||
| United States | 131.0 | 81.4 | ||||||
| Canada | 7.5 | 8.5 | ||||||
| Trinidad | 2.2 | 4.4 | ||||||
Other International (B) | 0.1 | 0.1 | ||||||
| Total | 140.8 | 94.4 | ||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | ||||||||
| United States | $ | 101.81 | $ | 88.00 | ||||
| Canada | 89.39 | 84.24 | ||||||
| Trinidad | 99.25 | 86.84 | ||||||
Other International (B) | 107.15 | 85.57 | ||||||
| Composite | 101.12 | 87.61 | ||||||
Natural Gas Liquids Volumes (MBbld) (A) | ||||||||
| United States | 50.3 | 34.5 | ||||||
| Canada | 0.8 | 0.9 | ||||||
| Total | 51.1 | 35.4 | ||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | ||||||||
| United States | $ | 42.49 | $ | 46.63 | ||||
| Canada | 50.88 | 47.11 | ||||||
| Composite | 42.62 | 46.65 | ||||||
Natural Gas Volumes (MMcfd) (A) | ||||||||
| United States | 1,062 | 1,134 | ||||||
| Canada | 105 | 143 | ||||||
| Trinidad | 369 | 385 | ||||||
Other International (B) | 11 | 14 | ||||||
| Total | 1,547 | 1,676 | ||||||
Average Natural Gas Prices ($/Mcf) (C) | ||||||||
| United States | $ | 2.46 | $ | 4.10 | ||||
| Canada | 2.45 | 3.67 | ||||||
| Trinidad | 2.98 | 3.20 | ||||||
Other International (B) | 5.79 | 5.63 | ||||||
| Composite | 2.61 | 3.87 | ||||||
Crude Oil Equivalent Volumes (MBoed) (D) | ||||||||
| United States | 358.5 | 304.9 | ||||||
| Canada | 25.7 | 33.2 | ||||||
| Trinidad | 63.8 | 68.6 | ||||||
Other International (B) | 1.8 | 2.4 | ||||||
| Total | 449.8 | 409.1 | ||||||
Total MMBoe (D) | 40.9 | 36.8 | ||||||
| (A) Thousand barrels per day or million cubic feet per day, as applicable. | ||||||||
| (B) Other International includes EOG's United Kingdom and China operations. | ||||||||
| (C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. | ||||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. | ||||||||
| EOG RESOURCES, INC. | ||||||||
| SUMMARY BALANCE SHEETS | ||||||||
| (Unaudited; in thousands, except share data) | ||||||||
| March 31, | December 31, | |||||||
| 2012 | 2011 | |||||||
| ASSETS | ||||||||
| Current Assets | ||||||||
| Cash and Cash Equivalents | $ | 294,064 | $ | 615,726 | ||||
| Accounts Receivable, Net | 1,543,491 | 1,451,227 | ||||||
| Inventories | 561,512 | 590,594 | ||||||
| Assets from Price Risk Management Activities | 451,399 | 450,730 | ||||||
| Income Taxes Receivable | 24,593 | 26,609 | ||||||
| Other | 166,974 | 119,052 | ||||||
| Total | 3,042,033 | 3,253,938 | ||||||
| Property, Plant and Equipment | ||||||||
| Oil and Gas Properties (Successful Efforts Method) | 35,092,346 | 33,664,435 | ||||||
| Other Property, Plant and Equipment | 2,277,035 | 2,149,989 | ||||||
| Total Property, Plant and Equipment | 37,369,381 | 35,814,424 | ||||||
| Less: Accumulated Depreciation, Depletion and Amortization | (15,235,540 | ) | (14,525,600 | ) | ||||
| Total Property, Plant and Equipment, Net | 22,133,841 | 21,288,824 | ||||||
| Other Assets | 379,662 | 296,035 | ||||||
| Total Assets | $ | 25,555,536 | $ | 24,838,797 | ||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| Current Liabilities | ||||||||
| Accounts Payable | $ | 2,289,903 | $ | 2,033,615 | ||||
| Accrued Taxes Payable | 123,391 | 147,105 | ||||||
| Dividends Payable | 45,333 | 42,578 | ||||||
| Liabilities from Price Risk Management Activities | 25,787 | - | ||||||
| Deferred Income Taxes | 122,833 | 135,989 | ||||||
| Other | 165,100 | 163,032 | ||||||
| Total | 2,772,347 | 2,522,319 | ||||||
| Long-Term Debt | 5,010,523 | 5,009,166 | ||||||
| Other Liabilities | 790,416 | 799,189 | ||||||
| Deferred Income Taxes | 3,990,407 | 3,867,219 | ||||||
| Commitments and Contingencies | ||||||||
| Stockholders' Equity | ||||||||
| Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 269,967,577 Shares Issued at March 31, 2012 and 269,323,084 Shares Issued at December 31, 2011 | 202,700 | 202,693 | ||||||
| Additional Paid in Capital | 2,328,435 | 2,272,052 | ||||||
| Accumulated Other Comprehensive Income | 429,451 | 401,746 | ||||||
| Retained Earnings | 10,067,541 | 9,789,345 | ||||||
| Common Stock Held in Treasury, 386,828 Shares at March 31, 2012 and 303,633 Shares at December 31, 2011 | (36,284 | ) | (24,932 | ) | ||||
| Total Stockholders' Equity | 12,991,843 | 12,640,904 | ||||||
| Total Liabilities and Stockholders' Equity | $ | 25,555,536 | $ | 24,838,797 | ||||
| EOG RESOURCES, INC. | ||||||||
| SUMMARY STATEMENTS OF CASH FLOWS | ||||||||
| (Unaudited; in thousands) | ||||||||
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2012 | 2011 | |||||||
| Cash Flows from Operating Activities | ||||||||
| Reconciliation of Net Income to Net Cash Provided by Operating Activities: | ||||||||
| Net Income | $ | 324,009 | $ | 133,973 | ||||
| Items Not Requiring (Providing) Cash | ||||||||
| �� Depreciation, Depletion and Amortization | 748,743 | 568,226 | ||||||
| Impairments | 133,147 | 89,328 | ||||||
| Stock-Based Compensation Expenses | 28,338 | 27,430 | ||||||
| Deferred Income Taxes | 110,148 | 31,290 | ||||||
| Gains on Asset Dispositions, Net | (67,468 | ) | (71,742 | ) | ||||
| Other, Net | 446 | 2,523 | ||||||
| Dry Hole Costs | - | 22,951 | ||||||
| Mark-to-Market Commodity Derivative Contracts | ||||||||
| Total (Gains) Losses | (134,208 | ) | 66,746 | |||||
| Realized Gains | 133,601 | 24,937 | ||||||
| Excess Tax Benefits from Stock-Based Compensation | (16,651 | ) | - | |||||
| Other, Net | 3,352 | 6,219 | ||||||
| Changes in Components of Working Capital and Other Assets and Liabilities | ||||||||
| Accounts Receivable | (89,948 | ) | (113,855 | ) | ||||
| Inventories | 10,208 | (67,733 | ) | |||||
| Accounts Payable | 236,625 | 165,497 | ||||||
| Accrued Taxes Payable | (5,163 | ) | 79,748 | |||||
| Other Assets | (108,840 | ) | (18,656 | ) | ||||
| Other Liabilities | (5,059 | ) | 8,621 | |||||
| Changes in Components of Working Capital Associated with Investing and Financing Activities | (223,675 | ) | 1,985 | |||||
| Net Cash Provided by Operating Activities | 1,077,605 | 957,488 | ||||||
| Investing Cash Flows | ||||||||
| Additions to Oil and Gas Properties | (1,878,813 | ) | (1,527,854 | ) | ||||
| Additions to Other Property, Plant and Equipment | (170,704 | ) | (159,794 | ) | ||||
| Proceeds from Sales of Assets | 450,110 | 260,107 | ||||||
| Changes in Components of Working Capital Associated with Investing Activities | 224,087 | (206 | ) | |||||
| Net Cash Used in Investing Activities | (1,375,320 | ) | (1,427,747 | ) | ||||
| Financing Cash Flows | ||||||||
| Common Stock Sold | - | 1,388,211 | ||||||
| Dividends Paid | (43,250 | ) | (39,003 | ) | ||||
| Excess Tax Benefits from Stock-Based Compensation | 16,651 | - | ||||||
| Treasury Stock Purchased | (20,072 | ) | (14,981 | ) | ||||
| Proceeds from Stock Options Exercised | 20,198 | 17,363 | ||||||
| Other, Net | (412 | ) | (1,779 | ) | ||||
| Net Cash (Used in) Provided by Financing Activities | (26,885 | ) | 1,349,811 | |||||
| Effect of Exchange Rate Changes on Cash | 2,938 | (120 | ) | |||||
| (Decrease) Increase in Cash and Cash Equivalents | (321,662 | ) | 879,432 | |||||
| Cash and Cash Equivalents at Beginning of Period | 615,726 | 788,853 | ||||||
| Cash and Cash Equivalents at End of Period | $ | 294,064 | $ | 1,668,285 | ||||
| EOG RESOURCES, INC. | |||||||||
| QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP) | |||||||||
| TO NET INCOME (GAAP) | |||||||||
| (Unaudited; in thousands, except per share data) | |||||||||
| The following chart adjusts the three-month periods ended March 31, 2012 and 2011 reported Net Income (GAAP) to reflect actual net cash realized from financial commodity price transactions by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net gains on asset dispositions primarily in North America in 2012 and 2011 and to add back impairment charges related to certain of EOG's North American assets 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 | |||||||||
| March 31, | |||||||||
| 2012 | 2011 | ||||||||
| Reported Net Income (GAAP) | $ | 324,009 | $ | 133,973 | |||||
| Mark-to-Market (MTM) Commodity Derivative Contracts Impact | |||||||||
| Total (Gains) Losses | (134,208 | ) | 66,746 | ||||||
| Realized Gains | 133,601 | 24,937 | |||||||
| Subtotal | (607 | ) | 91,683 | ||||||
| After-Tax MTM Impact | (389 | ) | 58,640 | ||||||
| Less: Net Gains on Asset Dispositions, Net of Tax | (43,211 | ) | (45,886 | ) | |||||
| Add: Impairment of Certain North American Assets, Net of Tax | 37,049 | 30,283 | |||||||
| Adjusted Net Income (Non-GAAP) | $ | 317,458 | $ | 177,010 | |||||
| Net Income Per Share (GAAP) | |||||||||
| Basic | $ | 1.22 | $ | 0.52 | |||||
| Diluted | $ | 1.20 | (a) | $ | 0.52 | (b) | |||
| Percentage Increase - [(a) - (b)] / (b) | 131% | ||||||||
| Adjusted Net Income Per Share (Non-GAAP) | |||||||||
| Basic | $ | 1.19 | $ | 0.69 | |||||
| Diluted | $ | 1.17 | (c) | $ | 0.68 | (d) | |||
| Percentage Increase - [(c) - (d)] / (d) | 72% | ||||||||
| Average Number of Common Shares | |||||||||
| Basic | 266,674 | 255,200 | |||||||
| Diluted | 270,242 | 258,819 | |||||||
| 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 periods ended March 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 | ||||||||||
| March 31, | ||||||||||
| 2012 | 2011 | |||||||||
| Net Cash Provided by Operating Activities (GAAP) | $ | 1,077,605 | $ | 957,488 | ||||||
| Adjustments | ||||||||||
| Exploration Costs (excluding Stock-Based Compensation Expenses) | 36,188 | 44,767 | ||||||||
| Excess Tax Benefits from Stock-Based Compensation | 16,651 | - | ||||||||
| Changes in Components of Working Capital and Other Assets and Liabilities | ||||||||||
| Accounts Receivable | 89,948 | 113,855 | ||||||||
| Inventories | (10,208 | ) | 67,733 | |||||||
| Accounts Payable | (236,625 | ) | (165,497 | ) | ||||||
| Accrued Taxes Payable | 5,163 | (79,748 | ) | |||||||
| Other Assets | 108,840 | 18,656 | ||||||||
| Other Liabilities | 5,059 | (8,621 | ) | |||||||
| Changes in Components of Working Capital Associated | ||||||||||
| with Investing and Financing Activities | 223,675 | (1,985 | ) | |||||||
| Discretionary Cash Flow (Non-GAAP) | $ | 1,316,296 | (a) | $ | 946,648 | (b) | ||||
| Percentage Increase - [(a) - (b)] / (b) | 39% | |||||||||
| 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 BEFORE INTEREST EXPENSE AND INCOME TAXES (GAAP) | ||||||||||
| (Unaudited; in thousands) | ||||||||||
| The following chart adjusts the three-month periods ended March 31, 2012 and 2011 reported Income 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) losses from these transactions and to eliminate the net gains 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 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 | ||||||||||
| March 31, | ||||||||||
| 2012 | 2011 | |||||||||
| Income Before Interest Expense and Income Taxes (GAAP) | $ | 570,403 | $ | 276,055 | ||||||
| Adjustments: | ||||||||||
| Depreciation, Depletion and Amortization | 748,743 | 568,226 | ||||||||
| Exploration Costs | 42,807 | 50,909 | ||||||||
| Dry Hole Costs | - | 22,951 | ||||||||
| Impairments | 133,147 | 89,328 | ||||||||
| EBITDAX (Non-GAAP) | 1,495,100 | 1,007,469 | ||||||||
| Total (Gains) Losses on MTM Commodity Derivative Contracts | (134,208 | ) | 66,746 | |||||||
| Realized Gains on MTM Commodity Derivative Contracts | 133,601 | 24,937 | ||||||||
| Net Gains on Asset Dispositions | (67,468 | ) | (71,742 | ) | ||||||
| Adjusted EBITDAX (Non-GAAP) | $ | 1,427,025 | (a) | $ | 1,027,410 | (b) | ||||
| Percentage Increase - [(a) - (b)] / (b) | 39% | |||||||||
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 May 8, 2012, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.
| Crude Oil Derivative Contracts | ||||||||
| Weighted | ||||||||
| Volume | Average Price | |||||||
| (Bbld) | ($/Bbl) | |||||||
2012 (1) | ||||||||
| January 1, 2012 through February 29, 2012 (closed) | 34,000 | $ | 104.95 | |||||
| March 1, 2012 through April 30, 2012 (closed) | 52,000 | 105.80 | ||||||
| May 1, 2012 through June 30, 2012 | 52,000 | 105.80 | ||||||
| July 1, 2012 through August 31, 2012 | 50,000 | 106.90 | ||||||
| September 1, 2012 through December 31, 2012 | 32,000 | 106.61 | ||||||
| (1) | EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period. Options covering a notional volume of 17,000 Bbld are exercisable on June 29, 2012. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 17,000 Bbld at an average price of $106.31 per barrel for the period July 1, 2012 through December 31, 2012. Options covering a notional volume of 18,000 Bbld are exercisable on August 31, 2012. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 18,000 Bbld at an average price of $107.42 per barrel for the period September 1, 2012 through February 28, 2013. Options covering a notional volume of 15,000 Bbld are exercisable on December 31, 2012. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 15,000 Bbld at an average price of $110.03 per barrel for the period January 1, 2013 through June 30, 2013. |
| Natural Gas Derivative Contracts | ||||||||
| Weighted | ||||||||
| Volume | Average Price | |||||||
| (MMBtud) | ($/MMBtu) | |||||||
2012 (2) | ||||||||
| January 1, 2012 through May 31, 2012 (closed) | 525,000 | $ | 5.44 | |||||
| June 1, 2012 through December 31, 2012 | 525,000 | $ | 5.44 | |||||
2013 (3) | ||||||||
| January 1, 2013 through December 31, 2013 | 150,000 | $ | 4.79 | |||||
2014 (3) | ||||||||
| January 1, 2014 through December 31, 2014 | 150,000 | $ | 4.79 | |||||
| (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 425,000 MMBtud at an average price of $5.44 per MMBtu for the period from June 1, 2012 through December 31, 2012. |
| (3) | 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 each month of 2013 and 2014. |
| Definitions | |
| Bbld | Barrels per day. |
| $/Bbl | Dollars per barrel. |
| MMBtud | Million British thermal units per day. |
| $/MMBtu | Dollars per 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 LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP) | ||||
| (Unaudited; in millions, except ratio data) | ||||
| The following chart reconciles Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | ||||
| March 31, | ||||
| 2012 | ||||
| Total Stockholders' Equity - (a) | $ | 12,992 | ||
| Long-Term Debt - (b) | 5,011 | |||
| Less: Cash | (294 | ) | ||
| Net Debt (Non-GAAP) - (c) | 4,717 | |||
| Total Capitalization (GAAP) - (a) + (b) | $ | 18,003 | ||
| Total Capitalization (Non-GAAP) - (a) + (c) | $ | 17,709 | ||
| Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 28 | % | ||
| Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 27 | % | ||
| EOG RESOURCES, INC. | ||||||||||||||||||
| SECOND QUARTER AND FULL YEAR 2012 FORECAST AND BENCHMARK COMMODITY PRICING | ||||||||||||||||||
(a) Second Quarter and Full Year 2012 Forecast The forecast items for the second quarter and full year 2012 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) | ||||||||||||||||||
| 2Q 2012 | Full Year 2012 | |||||||||||||||||
| Daily Production | ||||||||||||||||||
| Crude Oil and Condensate Volumes (MBbld) | ||||||||||||||||||
| United States | 130.6 | - | 151.5 | 133.0 | - | 151.4 | ||||||||||||
| Canada | 5.0 | - | 6.0 | 5.5 | - | 7.8 | ||||||||||||
| Trinidad | 0.8 | - | 2.0 | 1.0 | - | 2.2 | ||||||||||||
| Other International | 0.0 | - | 0.0 | 0.1 | - | 0.3 | ||||||||||||
| Total | 136.4 | - | 159.5 | 139.6 | - | 161.7 | ||||||||||||
| Natural Gas Liquids Volumes (MBbld) | ||||||||||||||||||
| United States | 45.1 | - | 56.0 | 50.0 | - | 60.0 | ||||||||||||
| Canada | 0.7 | - | 1.1 | 0.7 | - | 0.9 | ||||||||||||
| Total | 45.8 | - | 57.1 | 50.7 | - | 60.9 | ||||||||||||
| Natural Gas Volumes (MMcfd) | ||||||||||||||||||
| United States | 1,020 | - | 1,060 | 1,010 | - | 1,050 | ||||||||||||
| Canada | 84 | - | 104 | 82 | - | 102 | ||||||||||||
| Trinidad | 320 | - | 350 | 340 | - | 365 | ||||||||||||
| Other International | 8 | - | 10 | 8 | - | 10 | ||||||||||||
| Total | 1,432 | - | 1,524 | 1,440 | - | 1,527 | ||||||||||||
| Crude Oil Equivalent Volumes (MBoed) | ||||||||||||||||||
| United States | 345.7 | - | 384.2 | 351.3 | - | 386.4 | ||||||||||||
| Canada | 19.8 | - | 24.5 | 19.9 | - | 25.7 | ||||||||||||
| Trinidad | 54.1 | - | 60.3 | 57.7 | - | 63.0 | ||||||||||||
| Other International | 1.3 | - | 1.6 | 1.4 | - | 2.0 | ||||||||||||
| Total | 420.9 | - | 470.6 | 430.3 | - | 477.1 | ||||||||||||
| ESTIMATED RANGES | ||||||||||||||||||
| (Unaudited) | ||||||||||||||||||
| 2Q 2012 | Full Year 2012 | |||||||||||||||||
| Operating Costs | ||||||||||||||||||
| Unit Costs ($/Boe) | ||||||||||||||||||
| Lease and Well | $ | 6.57 | - | $ | 6.90 | $ | 6.30 | - | $ | 6.90 | ||||||||
| Transportation Costs | $ | 3.42 | - | $ | 3.72 | $ | 3.30 | - | $ | 3.66 | ||||||||
| Depreciation, Depletion and Amortization | $ | 18.42 | - | $ | 19.62 | $ | 18.60 | - | $ | 19.26 | ||||||||
| Expenses ($MM) | ||||||||||||||||||
| Exploration, Dry Hole and Impairment | $ | 105.0 | - | $ | 125.0 | $ | 463.0 | - | $ | 500.0 | ||||||||
| General and Administrative | $ | 77.2 | - | $ | 83.2 | $ | 337.5 | - | $ | 357.5 | ||||||||
| Gathering and Processing | $ | 21.5 | - | $ | 25.5 | $ | 88.0 | - | $ | 106.0 | ||||||||
| Capitalized Interest | $ | 10.0 | - | $ | 14.0 | $ | 44.0 | - | $ | 56.0 | ||||||||
| Net Interest | $ | 47.5 | - | $ | 53.5 | $ | 190.0 | - | $ | 210.0 | ||||||||
| Taxes Other Than Income (% of Revenue) | 6.2 | % | - | 6.6 | % | 5.7 | % | - | 6.7 | % | ||||||||
| Income Taxes | ||||||||||||||||||
| Effective Rate | 35 | % | - | 45 | % | 35 | % | - | 45 | % | ||||||||
| Current Taxes ($MM) | $ | 75 | - | $ | 90 | $ | 320 | - | $ | 340 | ||||||||
| Capital Expenditures ($MM) - FY 2012 (Excluding Acquisitions) | ||||||||||||||||||
| Exploration and Development, Excluding Facilities | $ | 6,200 | - | $ | 6,300 | |||||||||||||
| Exploration and Development Facilities | $ | 630 | - | $ | 675 | |||||||||||||
| Gathering, Processing and Other | $ | 570 | - | $ | 600 | |||||||||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) | ||||||||||||||||||
| Crude Oil and Condensate ($/Bbl) | ||||||||||||||||||
| Differentials | ||||||||||||||||||
| United States - (above) below WTI | $ | (0.25 | ) | - | $ | (1.75 | ) | $ | (0.25 | ) | - | $ | (1.75 | ) | ||||
| Canada - (above) below WTI | $ | 13.00 | - | $ | 18.00 | $ | 9.45 | - | $ | 13.15 | ||||||||
| Trinidad - (above) below WTI | $ | 4.00 | - | $ | 5.10 | $ | 6.30 | - | $ | 7.30 | ||||||||
| Natural Gas Liquids | ||||||||||||||||||
| Realizations as % of WTI | 38 | % | - | 44 | % | 38 | % | - | 44 | % | ||||||||
| United States | 50 | % | - | 55 | % | 50 | % | - | 55 | % | ||||||||
| Canada | ||||||||||||||||||
| Natural Gas ($/Mcf) | ||||||||||||||||||
| Differentials | ||||||||||||||||||
| United States - (above) below NYMEX Henry Hub | $ | 0.22 | - | $ | 0.40 | $ | 0.25 | - | $ | 0.40 | ||||||||
| Canada - (above) below NYMEX Henry Hub | $ | 0.50 | - | $ | 0.70 | $ | 0.40 | - | $ | 0.75 | ||||||||
| Realizations | ||||||||||||||||||
| Trinidad | $ | 2.35 | - | $ | 2.80 | $ | 2.25 | - | $ | 3.00 | ||||||||
| Other International | $ | 4.75 | - | $ | 5.72 | $ | 5.00 | - | $ | 5.90 | ||||||||
| 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 | |||||||||||||||||