EXHIBIT 99.1
| EOG Resources, Inc. | |
| News Release | |
| For Further Information Contact: | Investors |
| Maire A. Baldwin | |
| (713) 651-6EOG (651-6364) | |
| Kimberly A. Matthews | |
| (713) 571-4676 | |
Media | |
| K Leonard | |
| (713) 571-3870 |
EOG Resources Reports Robust First Quarter 2013 Results Led by Prolific Eagle Ford Crude Oil Wells
| · | Delivers Outstanding Crude Oil Production Growth of 36 Percent Year-Over-Year in the U.S. and 33 Percent Total Company |
| · | Surpasses Eagle Ford Production Targets |
| · | Announces Successful North Dakota Three Forks Second Bench Test |
| · | Reports Positive Results from Bakken Core 160-Acre Downspacing Program |
| · | Records Success from Permian Delaware and Midland Basins |
| · | Provides Five-Year Outlook |
FOR IMMEDIATE RELEASE: Monday, May 6, 2013
HOUSTON – EOG Resources, Inc. (EOG) today reported first quarter 2013 net income of $494.7 million, or $1.82 per share. This compares to first quarter 2012 net income of $324.0 million, or $1.20 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 first quarter 2013 was $489.9 million, or $1.80 per share. Adjusted non-GAAP net income for the first quarter 2012 was $317.5 million, or $1.17 per share. The results for the first quarter 2013 included net gains on asset dispositions of $115.0 million, net of tax ($0.42 per share) and a previously disclosed non-cash net loss of $105.0 million ($67.2 million after tax, or $0.24 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $67.1 million ($43.0 million after tax, or $0.16 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)
Earnings per share increased 52 percent, discretionary cash flow increased 28 percent and adjusted EBITDAX rose 25 percent during the first quarter 2013, compared to the first quarter 2012. (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).)
"During the first quarter, EOG met its goal of again delivering strong financial performance and highly competitive overall returns," said Mark G. Papa, Chairman and Chief Executive Officer.
Operational Highlights
EOG's total crude oil production increased 33 percent during the first quarter 2013 compared to the same prior year period. U.S. crude oil production increased 36 percent versus the first quarter 2012.
EOG's South Texas Eagle Ford crude oil operations surpassed expectations due to ongoing refinements in completion techniques. During the quarter, 27 wells were put to sales with initial production rates in excess of 2,500 barrels of crude oil per day (Bopd), including nine which exceeded peak production rates of 3,500 Bopd. EOG's southeastern New Mexico and West Texas operations in the Permian Basin also contributed to ongoing production growth. In addition, modifications in completion techniques and production enhancements combined to make EOG's rate-of-return results from the Bakken the highest in company history.
"Our first quarter results clearly demonstrate EOG's ability to consistently execute a highly efficient crude oil drilling program while simultaneously trimming costs and continually making better wells," Papa said. "To further fuel EOG's momentum, we are channeling as much capital as possible into our high rate-of-return oil plays this year."
In the South Texas Eagle Ford, the Guadalupe Unit #01H, #02H, #03H, #04H, #09H, #10H, #11H and #12H had initial rates ranging from 2,175 to 4,490 Bopd with 265 to 630 barrels per day (Bpd) of natural gas liquids (NGLs) and 1.5 to 3.6 million cubic feet per day (MMcfd) of natural gas in Gonzales County. Other excellent Gonzales County producers were the Lepori Unit #1H, #2H and #3H, which flowed at initial production rates of 3,490, 3,900 and 3,880 Bopd with 530, 585 and 590 Bpd of NGLs and 3.0, 3.4 and 3.4 MMcfd of natural gas, respectively. The Lefevre Unit #1H and #2H had initial crude oil production rates of 3,195 and 3,180 Bopd with 425 and 525 Bpd of NGLs and 2.4 and 3.0 MMcfd of natural gas, respectively. The Otto Unit #4H, #5H and #6H were completed to sales at 3,915, 3,125 and 3,485 Bopd with 570, 485 and 555 Bpd of NGLs and 3.3, 2.8 and 3.2 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these 16 Gonzales County wells.
Southwest of its Gonzales County acreage in Karnes County, EOG reported additional notable well results. The Wolf Unit #1H and #2H, in which EOG has 100 percent working interest, began sales at 5,380 and 4,475 Bopd with 400 and 500 Bpd of NGLs and 2.3 and 2.9 MMcfd of natural gas, respectively. The Lazy Oak Unit #4H and #5H went to initial production at 2,025 and 2,680 Bopd with 170 and 240 Bpd of NGLs and 1.0 and 1.4 MMcfd of natural gas, respectively. EOG has 50 percent working interest in these wells. EOG has 100 percent working interest in the Korth Unit #1H and #2H, which were completed to sales in January at 3,980 and 3,580 Bopd with 415 and 450 Bpd of NGLs and 2.4 and 2.6 MMcfd of natural gas, respectively.
In February 2013, EOG increased the reserve potential on its Eagle Ford acreage by 600 million barrels of crude oil equivalent (Boe) to 2.2 billion Boe and identified a 12-year inventory of more than 4,900 remaining drilling locations. Currently, EOG is pursuing manufacturing-type development of its highest rate-of-return asset with 40-acre to 65-acre spacing between wells. Based on efficiency gains and well cost improvements, EOG plans to increase its drilling program in the Eagle Ford from 400 to 425 net wells this year. If crude oil prices remain at or above current levels, EOG will further augment its drilling program in 2014.
In the Permian Basin, EOG has advanced development of its three combo shale assets, which are comprised of crude oil, NGLs and natural gas. In the Delaware Basin where EOG is focusing on the Wolfcamp and Leonard shales, it is assessing multiple producing horizons and determining optimal spacing. In the Midland Basin Wolfcamp, EOG also continues to refine completion techniques, as well as evaluate the reserve potential and determine optimal spacing on its 133,000 net acres.
EOG has accumulated 114,000 net acres in its newest asset, the West Texas Delaware Basin Wolfcamp. Its third successful horizontal well in the play, the Apache State 57 #1101H, had an initial production rate of 815 Bopd with 600 Bpd of NGLs and 3.8 MMcfd of natural gas. EOG has 100 percent working interest in this Reeves County well located south of the New Mexico border. Based on individual well reserves of 700,000 Boe, net, and over 1,100 drilling locations, EOG's estimated net reserve potential in the Delaware Basin Wolfcamp is 800 million Boe.
In the northeastern part of the Delaware Basin where EOG is targeting the Leonard shale, it completed several wells in Lea County, New Mexico. The Vaca 24 Fed Com #2H, #3H and #4H began production at 1,230, 1,410 and 1,205 Bopd with 140, 140 and 230 Bpd of NGLs and 780, 760 and 1,290 thousand cubic feet per day (Mcfd) of natural gas, respectively. EOG has 90 percent working interest in these wells. EOG has 100 percent working interest in the Vanguard 30 State Com #1H, which had an initial production rate of 1,540 Bopd with 165 Bpd of NGLs and 915 Mcfd of natural gas. The Excelsior 12 #1H, in which EOG has 48 percent working interest, was completed to sales in Loving County, Texas, adjacent to the New Mexico border, at 1,010 Bopd with 260 Bpd of NGLs and 1.4 MMcfd of natural gas.
East of the Delaware Basin in the Midland Basin Wolfcamp shale, EOG completed a number of wells in Irion County, Texas. The Munson #1005H, #1006H and #1007H began production at 965, 970 and 1,290 Bopd with 55, 60 and 100 Bpd of NGLs and 400, 430 and 730 Mcfd of natural gas, respectively. EOG has 85 percent working interest in these wells. The Faudree #10H, #11H and #12H were completed at 560, 670 and 810 Bopd with 50, 70 and 60 Bpd of NGLs and 365, 490 and 420 Mcfd of natural gas, respectively. EOG has 75 percent working interest in these wells. EOG has 80 percent working interest in the University 40D #0702H and #0701H, which began production at 660 and 705 Bopd with 75 and 95 Bpd of NGLs with 550 and 685 Mcfd of natural gas, respectively.
In North Dakota on its Antelope Extension acreage in McKenzie County, EOG previously reported success from both the Bakken formation and the first bench, the upper pay zone, of the Three Forks. During the first quarter, EOG achieved success from its first production test of the second bench of the Three Forks. The Riverview 03-3130H, in which EOG has 94 percent working interest, was completed to sales at 3,150 Bopd. EOG plans to continue testing the second bench in the same area this year. Also in McKenzie County, the West Clark 101-2425H was completed in the first bench of the Three Forks at an initial production rate of 2,205 Bopd. EOG has 100 percent working interest in the well.
In the Bakken Core Parshall Field, recent initial production rates and well results from EOG's 160-acre spacing between wells continues to be encouraging. The Wayzetta 136-2127H was completed at an initial production rate of 1,910 Bopd. Also in the Core, the Fertile 53-3024H began sales at 1,725 Bopd. EOG has 63 and 67 percent working interest in these wells, respectively. The Van Hook 20-0107H and 127-0107H were completed to sales at rates of 2,375 and 2,170 Bopd, respectively. EOG has 55 percent working interest in these wells. If crude oil prices remain in the current range, EOG plans to increase the level of its North Dakota drilling activity in 2014.
"Capturing key acreage in the Eagle Ford, Permian and Bakken/Three Forks has provided EOG with the opportunity to make good assets even better," Papa said. "We are particularly enthused about the Delaware Basin Wolfcamp and Leonard plays. With the addition of these assets, EOG's portfolio is grounded by three dynamic crude oil production growth drivers that should continue to generate best-in-class growth for many years."
Five-Year Outlook
Based on confidence in its current asset base and multi-year inventory of drilling locations, EOG is targeting sustained peer-group leading high growth rates of crude oil production for the 2013-2017 period, provided WTI prices remain at or above the mid-$80 level. With a solid inventory of combo plays, growth from NGLs also should be robust. North American natural gas is expected to show a moderate increase next year and beyond. Production in Trinidad and China during 2014 to 2017 should be flat. Overall, EOG expects to achieve a very positive total company production growth profile while maintaining a strong balance sheet.
"EOG's outstanding asset base allows us to define long-term production gains with confidence because these onshore domestic assets are largely underpinned by high rate-of-return crude oil growth," Papa said.
Hedging Activity
EOG has hedges in place for approximately 46 percent of its North American crude oil production for the remainder of 2013. For the period May 1 through June 30, 2013, EOG has crude oil financial price swap contracts in place for 101,000 Bpd at a weighted average price of $99.29 per barrel, excluding unexercised options. For the period July 1 through December 31, 2013, EOG has hedged 93,000 Bpd at a weighted average price of $98.44 per barrel, excluding unexercised options.
Based on its increased production weighting to crude oil and to better protect cash flows, EOG has implemented a hedge program for 2014. For the period January 1 through June 30, 2014, EOG has crude oil financial price swap contracts in place for 42,000 Bpd at a weighted average price of $95.86 per barrel, excluding unexercised options.
EOG also has hedged some natural gas volumes for 2013 and 2014. For the period June 1 through October 31, 2013, EOG has natural gas financial price swap contracts in place for 200,000 million British thermal units per day (MMBtud) at a weighted average price of $4.72 per million British thermal units (MMBtu), excluding unexercised options. For the period November 1 through December 31, 2013, EOG has hedged 150,000 MMBtud at a weighted average price of $4.79 per MMBtu, excluding unexercised options. For the full year 2014, EOG has natural gas financial price swap contracts in place for 170,000 MMBtud at a weighted average price of $4.54 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
As of May 1, 2013, EOG had closed on approximately $500 million of asset sales, 90 percent of its stated goal. At March 31, 2013, EOG's total debt outstanding was $6,312 million for a debt-to-total capitalization ratio of 31 percent. Taking into account cash on the balance sheet of $1,108 million at the end of the first quarter, EOG's net debt was $5,204 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 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).)
Conference Call Scheduled for May 7, 2013
EOG's first quarter 2013 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Tuesday, May 7, 2013. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through May 21, 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, statements regarding future commodity prices 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," "should" 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, unknown or currently unforeseen 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, and EOG's ability to retain mineral licenses and leases; |
| · | 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 conditions and developments around the world (such as political instability and armed conflict), 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; |
| · | physical, electronic and cyber security breaches; and |
| · | the other factors described under Item 1A, "Risk Factors", on pages 16 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 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.
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, 2012, 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, | ||||||||
| 2013 | 2012 | |||||||
| Net Operating Revenues | $ | 3,356.5 | $ | 2,806.7 | ||||
| Net Income | $ | 494.7 | $ | 324.0 | ||||
| Net Income Per Share | ||||||||
| Basic | $ | 1.84 | $ | 1.22 | ||||
| Diluted | $ | 1.82 | $ | 1.20 | ||||
| Average Number of Common Shares | ||||||||
| Basic | 269.4 | 266.7 | ||||||
| Diluted | 272.3 | 270.2 | ||||||
SUMMARY INCOME STATEMENTS (Unaudited; in thousands, except per share data) | ||||||||
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2013 | 2012 | |||||||
| Net Operating Revenues | ||||||||
| Crude Oil and Condensate | $ | 1,781,833 | $ | 1,310,335 | ||||
| Natural Gas Liquids | 169,529 | 198,310 | ||||||
| Natural Gas | 410,879 | 367,284 | ||||||
| (Losses) Gains on Mark-to-Market Commodity Derivative Contracts | (104,956 | ) | 134,208 | |||||
| Gathering, Processing and Marketing | 922,957 | 718,157 | ||||||
| Gains on Asset Dispositions, Net | 164,233 | 67,468 | ||||||
| Other, Net | 12,039 | 10,889 | ||||||
| Total | 3,356,514 | 2,806,651 | ||||||
| Operating Expenses | ||||||||
| Lease and Well | 249,000 | 261,495 | ||||||
| Transportation Costs | 184,257 | 131,842 | ||||||
| Gathering and Processing Costs | 24,504 | 25,592 | ||||||
| Exploration Costs | 44,216 | 42,807 | ||||||
| Dry Hole Costs | 3,962 | - | ||||||
| Impairments | 53,548 | 133,147 | ||||||
| Marketing Costs | 904,649 | 705,468 | ||||||
| Depreciation, Depletion and Amortization | 846,388 | 748,743 | ||||||
| General and Administrative | 77,985 | 76,269 | ||||||
| Taxes Other Than Income | 134,931 | 121,516 | ||||||
| Total | 2,523,440 | 2,246,879 | ||||||
| Operating Income | 833,074 | 559,772 | ||||||
| Other Income (Expense), Net | (10,134 | ) | 10,631 | |||||
| Income Before Interest Expense and Income Taxes | 822,940 | 570,403 | ||||||
| Interest Expense, Net | 61,921 | 50,269 | ||||||
| Income Before Income Taxes | 761,019 | 520,134 | ||||||
| Income Tax Provision | 266,294 | 196,125 | ||||||
| Net Income | $ | 494,725 | $ | 324,009 | ||||
| Dividends Declared per Common Share | $ | 0.1875 | $ | 0.17 | ||||
| EOG RESOURCES, INC. | ||||||||
OPERATING HIGHLIGHTS | ||||||||
| (Unaudited) | ||||||||
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2013 | 2012 | |||||||
Wellhead Volumes and Prices | ||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | ||||||||
| United States | 178.3 | 131.0 | ||||||
| Canada | 7.7 | 7.5 | ||||||
| Trinidad | 1.2 | 2.2 | ||||||
Other International (B) | 0.1 | 0.1 | ||||||
| Total | 187.3 | 140.8 | ||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | ||||||||
| United States | $ | 106.57 | $ | 101.81 | ||||
| Canada | 85.32 | 89.39 | ||||||
| Trinidad | 94.51 | 99.25 | ||||||
Other International (B) | 95.13 | 107.15 | ||||||
| Composite | 105.61 | 101.12 | ||||||
Natural Gas Liquids Volumes (MBbld) (A) | ||||||||
| United States | 58.6 | 50.3 | ||||||
| Canada | 0.9 | 0.8 | ||||||
| Total | 59.5 | 51.1 | ||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | ||||||||
| United States | $ | 31.63 | $ | 42.49 | ||||
| Canada | 41.90 | 50.88 | ||||||
| Composite | 31.78 | 42.62 | ||||||
Natural Gas Volumes (MMcfd) (A) | ||||||||
| United States | 934 | 1,062 | ||||||
| Canada | 79 | 105 | ||||||
| Trinidad | 352 | 369 | ||||||
Other International (B) | 8 | 11 | ||||||
| Total | 1,373 | 1,547 | ||||||
Average Natural Gas Prices ($/Mcf) (C) | ||||||||
| United States | $ | 3.08 | $ | 2.46 | ||||
| Canada | 3.24 | 2.45 | ||||||
| Trinidad | 3.91 | 2.98 | ||||||
Other International (B) | 6.75 | 5.79 | ||||||
| Composite | 3.32 | 2.61 | ||||||
Crude Oil Equivalent Volumes (MBoed) (D) | ||||||||
| United States | 392.6 | 358.5 | ||||||
| Canada | 21.8 | 25.7 | ||||||
| Trinidad | 59.8 | 63.8 | ||||||
Other International (B) | 1.4 | 1.8 | ||||||
| Total | 475.6 | 449.8 | ||||||
Total MMBoe (D) | 42.8 | 40.9 | ||||||
| (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) | ||||||||
| March 31, | December 31, | |||||||
| 2013 | 2012 | |||||||
| ASSETS | ||||||||
| Current Assets | ||||||||
| Cash and Cash Equivalents | $ | 1,108,034 | $ | 876,435 | ||||
| Accounts Receivable, Net | 1,891,202 | 1,656,618 | ||||||
| Inventories | 697,478 | 683,187 | ||||||
| Assets from Price Risk Management Activities | 32,711 | 166,135 | ||||||
| Income Taxes Receivable | 24,435 | 29,163 | ||||||
| Deferred Income Taxes | 102,035 | - | ||||||
| Other | 225,123 | 178,346 | ||||||
| Total | 4,081,018 | 3,589,884 | ||||||
| Property, Plant and Equipment | ||||||||
| Oil and Gas Properties (Successful Efforts Method) | 39,075,040 | 38,126,298 | ||||||
| Other Property, Plant and Equipment | 2,769,601 | 2,740,619 | ||||||
| Total Property, Plant and Equipment | 41,844,641 | 40,866,917 | ||||||
| Less: Accumulated Depreciation, Depletion and Amortization | (17,906,671 | ) | (17,529,236 | ) | ||||
| Total Property, Plant and Equipment, Net | 23,937,970 | 23,337,681 | ||||||
| Other Assets | 213,625 | 409,013 | ||||||
| Total Assets | $ | 28,232,613 | $ | 27,336,578 | ||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| Current Liabilities | ||||||||
| Accounts Payable | $ | 2,258,232 | $ | 2,078,948 | ||||
| Accrued Taxes Payable | 155,140 | 162,083 | ||||||
| Dividends Payable | 50,510 | 45,802 | ||||||
| Liabilities from Price Risk Management Activities | 14,108 | 7,617 | ||||||
| Deferred Income Taxes | 2,164 | 22,838 | ||||||
| Current Portion of Long-Term Debt | 406,579 | 406,579 | ||||||
| Other | 187,958 | 200,191 | ||||||
| Total | 3,074,691 | 2,924,058 | ||||||
| Long-Term Debt | 5,905,917 | 5,905,602 | ||||||
| Other Liabilities | 864,011 | 894,758 | ||||||
| Deferred Income Taxes | 4,631,685 | 4,327,396 | ||||||
| Commitments and Contingencies | ||||||||
| Stockholders' Equity | ||||||||
| Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 272,366,287 | ||||||||
| Shares Issued at March 31, 2013 and 271,958,495 Shares Issued at December 31, 2012 | 202,724 | 202,720 | ||||||
| Additional Paid in Capital | 2,539,578 | 2,500,340 | ||||||
| Accumulated Other Comprehensive Income | 427,832 | 439,895 | ||||||
| Retained Earnings | 10,619,426 | 10,175,631 | ||||||
| Common Stock Held in Treasury, 308,010 Shares at March 31, 2013 and | ||||||||
| 326,264 Shares at December 31, 2012 | (33,251 | ) | (33,822 | ) | ||||
| Total Stockholders' Equity | 13,756,309 | 13,284,764 | ||||||
| Total Liabilities and Stockholders' Equity | $ | 28,232,613 | $ | 27,336,578 | ||||
| EOG RESOURCES, INC. | ||||||||
SUMMARY STATEMENTS OF CASH FLOWS | ||||||||
| (Unaudited; in thousands) | ||||||||
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2013 | 2012 | |||||||
| Cash Flows from Operating Activities | ||||||||
| Reconciliation of Net Income to Net Cash Provided by Operating Activities: | ||||||||
| Net Income | $ | 494,725 | $ | 324,009 | ||||
| Items Not Requiring (Providing) Cash | ||||||||
| Depreciation, Depletion and Amortization | 846,388 | 748,743 | ||||||
| Impairments | 53,548 | 133,147 | ||||||
| Stock-Based Compensation Expenses | 30,436 | 28,338 | ||||||
| Deferred Income Taxes | 200,779 | 110,148 | ||||||
| Gains on Asset Dispositions, Net | (164,233 | ) | (67,468 | ) | ||||
| Other, Net | 8,268 | 446 | ||||||
| Dry Hole Costs | 3,962 | - | ||||||
| Mark-to-Market Commodity Derivative Contracts | ||||||||
| Total Losses (Gains) | 104,956 | (134,208 | ) | |||||
| Realized Gains | 67,050 | 133,601 | ||||||
| Excess Tax Benefits from Stock-Based Compensation | (11,673 | ) | (16,651 | ) | ||||
| Other, Net | 5,022 | 3,352 | ||||||
| Changes in Components of Working Capital and Other Assets and Liabilities | ||||||||
| Accounts Receivable | (236,757 | ) | (89,948 | ) | ||||
| Inventories | (15,058 | ) | 10,208 | |||||
| Accounts Payable | 186,065 | 236,625 | ||||||
| Accrued Taxes Payable | 9,004 | (5,163 | ) | |||||
| Other Assets | (47,193 | ) | (108,840 | ) | ||||
| Other Liabilities | (52,933 | ) | (5,059 | ) | ||||
| Changes in Components of Working Capital Associated with Investing and | ||||||||
| Financing Activities | (57,421 | ) | (223,675 | ) | ||||
| Net Cash Provided by Operating Activities | 1,424,935 | 1,077,605 | ||||||
| Investing Cash Flows | ||||||||
| Additions to Oil and Gas Properties | (1,604,123 | ) | (1,878,813 | ) | ||||
| Additions to Other Property, Plant and Equipment | (92,201 | ) | (170,704 | ) | ||||
| Proceeds from Sales of Assets | 479,436 | 450,110 | ||||||
| Changes in Components of Working Capital Associated with Investing Activities | 57,149 | 224,087 | ||||||
| Net Cash Used in Investing Activities | (1,159,739 | ) | (1,375,320 | ) | ||||
| Financing Cash Flows | ||||||||
| Dividends Paid | (46,220 | ) | (43,250 | ) | ||||
| Excess Tax Benefits from Stock-Based Compensation | 11,673 | 16,651 | ||||||
| Treasury Stock Purchased | (11,024 | ) | (20,072 | ) | ||||
| Proceeds from Stock Options Exercised | 8,004 | 20,198 | ||||||
| Repayment of Capital Lease Obligation | (1,427 | ) | - | |||||
| Other, Net | 272 | (412 | ) | |||||
| Net Cash Used in Financing Activities | (38,722 | ) | (26,885 | ) | ||||
| Effect of Exchange Rate Changes on Cash | 5,125 | 2,938 | ||||||
| Increase (Decrease) in Cash and Cash Equivalents | 231,599 | (321,662 | ) | |||||
| Cash and Cash Equivalents at Beginning of Period | 876,435 | 615,726 | ||||||
| Cash and Cash Equivalents at End of Period | $ | 1,108,034 | $ | 294,064 | ||||
| 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, 2013 and 2012 reported Net Income (GAAP) to reflect actual net cash realized from financial commodity price transactions by eliminating the unrealized mark-to-market losses (gains) from these transactions, to eliminate the net gains on asset dispositions in North America in 2013 and 2012 and to add back impairment charges related to certain of EOG's North American assets in 2012. 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, | ||||||||||
| 2013 | 2012 | |||||||||
| Reported Net Income (GAAP) | $ | 494,725 | $ | 324,009 | ||||||
| Mark-to-Market (MTM) Commodity Derivative Contracts Impact | ||||||||||
| Total Losses (Gains) | 104,956 | (134,208 | ) | |||||||
| Realized Gains | 67,050 | 133,601 | ||||||||
| Subtotal | 172,006 | (607 | ) | |||||||
| After-Tax MTM Impact | 110,127 | (389 | ) | |||||||
| Less: Net Gains on Asset Dispositions, Net of Tax | (114,993 | ) | (43,211 | ) | ||||||
| Add: Impairments of Certain North American Assets, Net of Tax | - | 37,049 | ||||||||
| Adjusted Net Income (Non-GAAP) | $ | 489,859 | $ | 317,458 | ||||||
| Net Income Per Share (GAAP) | ||||||||||
| Basic | $ | 1.84 | $ | 1.22 | ||||||
| Diluted | $ | 1.82 | (a) | $ | 1.20 | (b) | ||||
| Percentage Increase - [(a) - (b)] / (b) | 52 | % | ||||||||
| Adjusted Net Income Per Share (Non-GAAP) | ||||||||||
| Basic | $ | 1.82 | $ | 1.19 | ||||||
| Diluted | $ | 1.80 | $ | 1.17 | ||||||
| Average Number of Common Shares | ||||||||||
| Basic | 269,358 | 266,674 | ||||||||
| Diluted | 272,263 | 270,242 | ||||||||
| 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, 2013 and 2012 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, | ||||||||||
| 2013 | 2012 | |||||||||
| Net Cash Provided by Operating Activities (GAAP) | $ | 1,424,935 | $ | 1,077,605 | ||||||
| Adjustments | ||||||||||
| Exploration Costs (excluding Stock-Based Compensation Expenses) | 36,645 | 36,188 | ||||||||
| Excess Tax Benefits from Stock-Based Compensation | 11,673 | 16,651 | ||||||||
| Changes in Components of Working Capital and Other Assets and Liabilities | ||||||||||
| Accounts Receivable | 236,757 | 89,948 | ||||||||
| Inventories | 15,058 | (10,208 | ) | |||||||
| Accounts Payable | (186,065 | ) | (236,625 | ) | ||||||
| Accrued Taxes Payable | (9,004 | ) | 5,163 | |||||||
| Other Assets | 47,193 | 108,840 | ||||||||
| Other Liabilities | 52,933 | 5,059 | ||||||||
| Changes in Components of Working Capital Associated with Investing and | ||||||||||
| Financing Activities | 57,421 | 223,675 | ||||||||
| Discretionary Cash Flow (Non-GAAP) | $ | 1,687,546 | (a) | $ | 1,316,296 | (b) | ||||
| Percentage Increase - [(a) - (b)] / (b) | 28 | % | ||||||||
| 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, 2013 and 2012 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) (losses) gains from these transactions and to eliminate the net gains on asset dispositions in North America in 2013 and 2012. 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, | ||||||||||
| 2013 | 2012 | |||||||||
| Income Before Interest Expense and Income Taxes (GAAP) | $ | 822,940 | $ | 570,403 | ||||||
| Adjustments: | ||||||||||
| Depreciation, Depletion and Amortization | 846,388 | 748,743 | ||||||||
| Exploration Costs | 44,216 | 42,807 | ||||||||
| Dry Hole Costs | 3,962 | - | ||||||||
| Impairments | 53,548 | 133,147 | ||||||||
| EBITDAX (Non-GAAP) | 1,771,054 | 1,495,100 | ||||||||
| Total Losses (Gains) on MTM Commodity Derivative Contracts | 104,956 | (134,208 | ) | |||||||
| Realized Gains on Commodity Derivative Contracts | 67,050 | 133,601 | ||||||||
| Net Gains on Asset Dispositions | (164,233 | ) | (67,468 | ) | ||||||
| Adjusted EBITDAX (Non-GAAP) | $ | 1,778,827 | (a) | $ | 1,427,025 | (b) | ||||
| Percentage Increase - [(a) - (b)] / (b) | 25 | % | ||||||||
| 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 3, 2013, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. |
| CRUDE OIL DERIVATIVE CONTRACTS | ||||||||
| Weighted | ||||||||
| Volume | Average Price | |||||||
| (Bbld) | ($/Bbl) | |||||||
2013 (1) | ||||||||
| January 2013 (closed) | 101,000 | $ | 99.29 | |||||
| February 1, 2013 through April 30, 2013 (closed) | 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 | ||||||
2014 (2) | ||||||||
| January 1, 2014 through June 30, 2014 | 42,000 | $ | 95.86 | |||||
| (1) | EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month periods. 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 each month during 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 each month during the period January 1, 2014 through June 30, 2014. |
| (2) | 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 total notional volume of 11,000 Bbld are exercisable on June 27, 2014, and options covering a total notional volume of 31,000 Bbld are exercisable on June 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 42,000 Bbld at an average price of $95.86 per barrel for each month during the period July 1, 2014 through December 31, 2014. |
| NATURAL GAS DERIVATIVE CONTRACTS | ||||||||
| Weighted | ||||||||
| Volume | Average Price | |||||||
| (MMBtud) | ($/MMBtu) | |||||||
2013 (3) | ||||||||
| January 1, 2013 through April 30, 2013 (closed) | 150,000 | $ | 4.79 | |||||
| May 2013 (closed) | 200,000 | 4.72 | ||||||
| June 1, 2013 through October 31, 2013 | 200,000 | 4.72 | ||||||
| November 1, 2013 through December 31, 2013 | 150,000 | 4.79 | ||||||
2014 (4) | ||||||||
| January 1, 2014 through December 31, 2014 | 170,000 | $ | 4.54 | |||||
| (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. For the period June 1, 2013 through October 31, 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 200,000 MMBtud at an average price of $4.72 per MMBtu for each month during that period. For the period November 1, 2013 through December 31, 2013, 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 during that period. |
| (4) | EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. Additionally, in connection with certain natural gas derivative contracts settled in July 2012, counterparties retain an option of entering into derivative contracts at future dates. All 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 320,000 MMBtud at an average price of $4.66 per MMBtu for each month during the period January 1, 2014 through December 31, 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. |
| At | ||||
| March 31, | ||||
| 2013 | ||||
| Total Stockholders' Equity - (a) | $ | 13,756 | ||
| Current and Long-Term Debt - (b) | 6,312 | |||
| Less: Cash | (1,108 | ) | ||
| Net Debt (Non-GAAP) - (c) | 5,204 | |||
| Total Capitalization (GAAP) - (a) + (b) | $ | 20,068 | ||
| Total Capitalization (Non-GAAP) - (a) + (c) | $ | 18,960 | ||
| Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 31 | % | ||
| Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 27 | % | ||
| EOG RESOURCES, INC. | ||||||||||||
SECOND QUARTER AND FULL YEAR 2013 FORECAST AND BENCHMARK COMMODITY PRICING | ||||||||||||
| (a) Second Quarter and Full Year 2013 Forecast | ||||||||||||
| The forecast items for the second 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) | |||||||||||||||
| 2Q 2013 | Full Year 2013 | ||||||||||||||
| Daily Production | |||||||||||||||
| Crude Oil and Condensate Volumes (MBbld) | |||||||||||||||
| United States | 185.0 | - | 200.0 | 186.0 | - | 202.0 | |||||||||
| Canada | 6.0 | - | 7.0 | 6.0 | - | 7.0 | |||||||||
| Trinidad | 1.3 | - | 1.8 | 1.0 | - | 2.0 | |||||||||
| Other International | 0.0 | - | 0.0 | 0.0 | - | 0.2 | |||||||||
| Total | 192.3 | - | 208.8 | 193.0 | - | 211.2 | |||||||||
| Natural Gas Liquids Volumes (MBbld) | |||||||||||||||
| United States | 59.0 | - | 63.5 | 55.5 | - | 66.0 | |||||||||
| Canada | 0.5 | - | 1.0 | 0.5 | - | 0.8 | |||||||||
| Total | 59.5 | - | 64.5 | 56.0 | - | 66.8 | |||||||||
| Natural Gas Volumes (MMcfd) | |||||||||||||||
| United States | 900 | - | 940 | 865 | - | 905 | |||||||||
| Canada | 70 | - | 80 | 64 | - | 80 | |||||||||
| Trinidad | 325 | - | 365 | 350 | - | 375 | |||||||||
| Other International | 7 | - | 9 | 8 | - | 10 | |||||||||
| Total | 1,302 | - | 1,394 | 1,287 | - | 1,370 | |||||||||
| Crude Oil Equivalent Volumes (MBoed) | |||||||||||||||
| United States | 394.0 | - | 420.2 | 385.7 | - | 418.8 | |||||||||
| Canada | 18.2 | - | 21.3 | 17.2 | - | 21.1 | |||||||||
| Trinidad | 55.5 | - | 62.6 | 59.3 | - | 64.5 | |||||||||
| Other International | 1.2 | - | 1.5 | 1.3 | - | 1.9 | |||||||||
| Total | 468.9 | - | 505.6 | 463.5 | - | 506.3 | |||||||||
ESTIMATED RANGES | |||||||||||||||
| (Unaudited) | |||||||||||||||
| 2Q 2013 | Full Year 2013 | ||||||||||||||
| Operating Costs | |||||||||||||||
| Unit Costs ($/Boe) | |||||||||||||||
| Lease and Well | $ | 6.15 | - | $ | 6.55 | $ | 6.15 | - | $ | 6.55 | |||||
| Transportation Costs | $ | 4.50 | - | $ | 4.80 | $ | 4.40 | - | $ | 4.80 | |||||
| Depreciation, Depletion and Amortization | $ | 19.95 | - | $ | 20.45 | $ | 19.85 | - | $ | 20.75 | |||||
| Expenses ($MM) | |||||||||||||||
| Exploration, Dry Hole and Impairment | $ | 125.0 | - | $ | 165.0 | $ | 500.0 | - | $ | 550.0 | |||||
| General and Administrative | $ | 80.0 | - | $ | 90.0 | $ | 360.0 | - | $ | 390.0 | |||||
| Gathering and Processing | $ | 25.0 | - | $ | 35.0 | $ | 100.0 | - | $ | 130.0 | |||||
| Capitalized Interest | $ | 10.0 | - | $ | 12.0 | $ | 40.0 | - | $ | 50.0 | |||||
| Net Interest | $ | 60.0 | - | $ | 62.0 | $ | 226.0 | - | $ | 246.0 | |||||
| Taxes Other Than Income (% of Wellhead Revenue) | 5.9% | - | 6.3% | 5.6% | - | 6.6% | |||||||||
| Income Taxes | |||||||||||||||
| Effective Rate | 30% | - | 40% | 35% | - | 45% | |||||||||
| Current Taxes ($MM) | $ | 60 | - | $ | 75 | $ | 260 | - | $ | 280 | |||||
| Capital Expenditures ($MM) - FY 2013 (Excluding Acquisitions) | |||||||||||||||
| 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) below WTI | $ | (7.00) | - | $ | (11.50) | $ | (4.50) | - | $ | (9.50) | |||||
| Canada - (above) below WTI | $ | 7.00 | - | $ | 9.00 | $ | 7.80 | - | $ | 10.80 | |||||
| Trinidad - (above) below WTI | $ | 1.05 | - | $ | 3.05 | $ | 1.00 | - | $ | 3.00 | |||||
| Natural Gas Liquids | |||||||||||||||
| Realizations as % of WTI | |||||||||||||||
| United States | 33% | - | 37% | 32% | - | 35% | |||||||||
| Canada | 37% | - | 43% | 39% | - | 43% | |||||||||
| Natural Gas ($/Mcf) | |||||||||||||||
| Differentials | |||||||||||||||
| United States - (above) below NYMEX Henry Hub | $ | 0.20 | - | $ | 0.40 | $ | 0.20 | - | $ | 0.50 | |||||
| Canada - (above) below NYMEX Henry Hub | $ | 0.45 | - | $ | 0.65 | $ | 0.30 | - | $ | 0.60 | |||||
| Realizations | |||||||||||||||
| Trinidad | $ | 3.10 | - | $ | 3.60 | $ | 2.80 | - | $ | 3.40 | |||||
| Other International | $ | 4.90 | - | $ | 5.40 | $ | 5.00 | - | $ | 6.00 | |||||
| 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 |