EOG Increases Potential Eagle Ford Reserves

EOG Resources, Inc. reported full year 2013 net income of $2,197 million, or $8.04 per share, as compared to $570 million, or $2.11 per share, for the full year 2012. For the fourth quarter 2013, EOG reported net income of $580 million, or $2.12 per share. This compares to a fourth quarter 2012 net loss of $505 million, or $1.88 per share.

Adjusted non-GAAP net income for the full year 2013 was $2,246 million, or $8.22 per share, and for the full year 2012 was $1,536 million, or $5.67 per share. Adjusted non-GAAP net income for the fourth quarter 2013 was $548 million, or $2.00 per share, and for the fourth quarter 2012 was $437 million, or $1.61 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 fourth quarter 2013 excluded a previously disclosed non-cash net gain of $40.5 million ($25.6 million after tax, or $0.09 per share) on the mark-to-market of financial commodity contracts and net gains on asset dispositions of $7.2 million, net of tax ($0.03 per share). During the fourth quarter 2013, the net cash inflow related to financial commodity contracts was $1.0 million ($0.7 million after tax, or $0.00 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

EOG posted excellent financial metrics for 2013 with increases of 45 percent in adjusted non-GAAP net income per share, 29 percent in discretionary cash flow and 26 percent in adjusted EBITDAX, compared to 2012. Indicative of its high rate-of-return and disciplined crude oil investment programs, EOG also posted 16 percent ROE and 12 percent ROCE last year. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income, non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP), adjusted EBITDAX (non-GAAP) to income before interest expense and income taxes (GAAP) and non-GAAP inputs to GAAP inputs as used in the calculation of ROE and ROCE.)

Operational Highlights
In the fourth quarter 2013, EOG increased its U.S. crude oil and condensate production by 53 percent, while total company crude oil and condensate production rose by 50 percent over the same prior year period. Total company liquids production - crude oil, condensate and natural gas liquids (NGLs) - climbed 41 percent.

For the full year, total company crude oil and condensate production increased 40 percent year-over-year, driven by 42 percent growth in the U.S. Total company liquids production increased 34 percent, while total natural gas production decreased 11 percent. Overall total company production increased 9 percent compared to the prior year.

"2013 was an outstanding year for EOG," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "Through virtually flawless execution of our operations plan, we generated robust crude oil production growth concurrent with strong ROE and ROCE ratios, while deleveraging the company. Our 2013 financial metrics and year-end balance sheet reflect the value of EOG's high quality crude oil investments."

South Texas Eagle Ford The single largest source of EOG's extraordinary crude oil production growth in 2013 was its mammoth South Texas Eagle Ford play. EOG increased well productivity and initial production rates by augmenting its technical knowledge of shale resources and the associated completion processes. Based on these significant improvements, EOG increased the net potential recoverable reserve estimate on its crude oil acreage by 45 percent to 3.2 billion barrels of oil equivalent (BnBoe) from 2.2 BnBoe. While continuing to decrease spacing between wells in certain areas, the average net reserves per well increased to 450 thousand barrels of crude oil equivalent (Mboe) from 400 Mboe.

Recent Eagle Ford wells include the Boothe Unit #3H, #4H and #17H in Gonzales County, which began initial production during the fourth quarter at 2,630 to 3,375 barrels of crude oil per day (Bopd) with 365 to 520 barrels per day (Bpd) of NGLs and 2.1 to 3.0 million cubic feet per day (MMcfd) of natural gas. The Rudolph Unit #1H was turned to sales at 4,230 Bopd with 505 Bpd of NGLs and 2.9 MMcfd of natural gas. The Nichols Unit #3H had an initial crude oil production rate of 3,830 Bpd with 390 Bpd of NGLs and 2.3 MMcfd of natural gas. In Karnes County, the Fleetwood Unit #1H and #2H began production at 3,630 and 3,435 Bopd with 345 and 350 Bpd of NGLs, respectively, and 2.0 MMcfd of natural gas each. EOG has 100 percent working interest in these seven wells. The Wilde Trust Unit #1H, #2H and #3H, completed in the second quarter 2013, had combined cumulative production of over 960,000 barrels of crude oil over a 200-day period. EOG holds a 100 percent working interest in these Gonzales County wells.

Southwest of Gonzales and Karnes counties, the Naylor Jones Unit 42 #1H, #2H and 60 #2H began production at rates ranging from 1,755 to 2,050 Bopd with 195 to 205 Bpd of NGLs and 1.1 to 1.2 MMcfd of natural gas in McMullen County. In La Salle County, the Further Unit #1H and #2H had initial crude oil production rates of 2,605 and 2,550 Bpd with 125 and 155 Bpd of NGLs and 725 and 900 thousand cubic feet per day (Mcfd) of natural gas, respectively. EOG has 100 percent working interest in these five wells.

"To put our Eagle Ford position in simple terms, our current reserve potential is almost four times what we estimated four years ago when EOG discovered the play. With approximately 7,200 total identified individual net well locations, we still have about 6,000 net wells to drill across EOG's 120-mile crude oil window," Thomas said. "Our in-house talent keeps finding ways to improve development of this world-class shale asset where we hold a critical mass of very desirable acreage. This gives EOG a lot of running room to produce better and better results over a long period of time."

North Dakota Bakken In North Dakota where EOG focused drilling activity on two key areas, the Bakken Core and Antelope Extension, 2013 results surpassed expectations. Ongoing improvements in drilling and completion techniques transformed what was a steady development drilling program into a high rate-of-return crude oil growth play. By confirming downspacing economics in the Bakken Core, EOG ramped up its drilling plan from one to four wells per section, while increasing the average recoverable resource per well.

In the Bakken Core in Mountrail County, the Wayzetta 30-3230H and 31-3230H, in which EOG has 59 percent working interest, began production at 2,510 and 2,540 Bopd, respectively. The Wayzetta 35-1920H, in which EOG has a 60 percent working interest, had an initial production rate of 2,240 Bopd with 1.2 MMcfd of rich natural gas. In the Antelope Extension, EOG drilled the Hawkeye 2-2501H in McKenzie County. The well, in which EOG has 80 percent working interest, began production with 2,075 Bopd and 3.8 MMcfd of rich natural gas.

Delaware Basin Leonard EOG's Permian Basin activity also was a solid contributor to its overall 2013 domestic crude oil production growth. Although EOG tested the prospectivity of multiple target zones in its three distinct horizontal resource plays last year, it initially concentrated on the Midland Basin Wolfcamp, followed by the Delaware Basin Leonard and Wolfcamp. Based on compelling well results, EOG shifted activity to the Delaware Basin Leonard during the second half of 2013. In Lea County, New Mexico, two Leonard wells were drilled and completed in the second half of 2013 and turned to sales early in 2014. The Vaca 24 Fed Com #5H and #6H had initial crude oil production rates of 1,520 and 1,380 Bpd with 265 and 170 Bpd of NGLs and 1.5 and 0.9 MMcfd of natural gas, respectively. EOG has 89 percent working interest in these wells.

Reserves At December 31, 2013, EOG's total company net proved reserves of 2,119 million barrels of crude oil equivalent (MMBoe) increased 17 percent over year-end 2012. Total company net proved developed reserves increased 19 percent to 1,127 MMBoe. Total U.S. net proved crude oil and condensate reserves increased 31 percent. Total proved liquids reserves increased 25 percent year-over-year, comprising 60 percent of total company proved reserves at December 31, 2013.

In 2013: - Total reserve replacement from all sources - the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production - was 264 percent at a total reserve replacement cost of $13.42 per barrel of oil equivalent (Boe), based on exploration and development expenditures of $6,859 million, net of non-cash lease acquisition and asset retirement costs.

- Total liquids reserve replacement from all sources - the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production - was 346 percent.

- Reserve replacement from drilling - the ratio of extensions, discoveries and other additions to total production - was 212 percent. Crude oil reserve replacement from drilling in the United States was 297 percent.

- In the United States, total reserve replacement from all sources, net of revisions and dispositions, was 307 percent at a reserve replacement cost of $12.57 per Boe based on exploration and development expenditures of $6,290 million, net of non-cash lease acquisition and asset retirement costs.

(Please refer to the attached tables for the calculation of total reserve replacement, total reserve replacement costs, total liquids reserve replacement, reserve replacement from drilling, U.S. total reserve replacement and U.S. reserve replacement costs.)

For the 26th consecutive year, internal reserve estimates were within 5 percent of those prepared by the independent reserve engineering firm of DeGolyer and MacNaughton (D&M). D&M conducted an independent engineering analysis of properties comprising about 82 percent of EOG's 2013 proved reserves on a Boe basis.

Hedging Activity EOG increased the amount of crude oil hedges in place for 2014 compared to 2013. For February 2014, EOG has crude oil financial price swap contracts in place for 171,000 Bopd at a weighted average price of $96.35 per barrel, excluding unexercised options. For March 2014, EOG has crude oil financial price swap contracts in place for 181,000 Bopd at a weighted average price of $96.55 per barrel, excluding unexercised options. For the period April 1 through May 31, 2014, EOG has crude oil financial price swap contracts in place for 171,000 Bopd at a weighted average price of $96.55 per barrel, excluding unexercised options. For June 2014, EOG has crude oil financial price swap contracts in place for 161,000 Bopd at a weighted average price of $96.33 per barrel, excluding unexercised options. For the period July 1 through December 31, 2014, EOG has crude oil financial price swap contracts in place for 64,000 Bopd at a weighted average price of $95.18 per barrel, excluding unexercised options.

EOG also has hedged natural gas volumes. For the period March 1 through December 31, 2014, EOG has natural gas financial price swap contracts in place for 330,000 million British thermal units per day (MMBtud) at a weighted average price of $4.55 per million British thermal units (MMBtu), excluding unexercised options.

For the period January 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 MMBtud at a weighted average price of $4.51 MMBtu, excluding unexercised options.

Capital Structure During 2013, EOG's cash flows from operating activities exceeded total capital expenditures. Total proceeds from asset sales were $761 million. At December 31, 2013, EOG's total debt outstanding was $5,913 million for a debt-to-total capitalization ratio of 28 percent. Taking into account cash on the balance sheet of $1.3 billion at year-end, EOG's net debt was $4,595 million for a net debt-to-total capitalization ratio of 23 percent, down from 29 percent at year-end 2012. (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).)

2014 Plans EOG is targeting 27 percent total company crude oil production growth in 2014, driven by 29 percent growth in the U.S. Although natural gas prices have recently increased due to cold winter weather in North America, EOG's extensive portfolio of crude oil and liquids-rich resources offer far superior returns compared to alternative natural gas drilling investments. EOG does not plan to allocate capital to North American dry natural gas drilling in 2014. As a result, its North American natural gas production is expected to decline 6 percent. Total company production is expected to increase 11.5 percent.

Capital expenditures for 2014 are expected to range from $8.1 to $8.3 billion, including production facilities and midstream expenditures, but excluding acquisitions. "EOG is directing a larger percentage of its 2014 capital budget to the Eagle Ford and Bakken where we have tremendous drilling opportunity with excellent rates of return," Thomas said. "By increasing activity in these plays, we expect the momentum and operational efficiencies we've created to continue." With plans to drill approximately 520 net wells across its Eagle Ford acreage during 2014, EOG expects the play's extremely robust production will again lead the company's overall crude oil growth.

EOG is increasing activity in the North Dakota Bakken/Three Forks where it is targeting an 80-net well drilling program, an uptick over 2013. Operations will be primarily in the Core, followed by the Antelope Extension area. Based on successful drilling results from the first and second intervals of the Three Forks formation in the Antelope Extension last year, EOG intends to test additional benches during 2014. As a result of sound technical progress achieved last year, EOG is shifting its Permian capital expenditure program from the Midland Basin to the higher rate-of-return Delaware Basin in 2014. Concentrating on the Leonard play and, to a lesser extent, the Wolfcamp, the emphasis will be on implementing efficient drilling patterns while continuing to test additional prospective zones. "2014 should be another great year for EOG. We will stay focused on improving EOG's overall returns as we pursue a wealth of high rate-of-return drilling opportunities across our onshore domestic crude oil plays, and we'll continue to seek exciting new prospects to add to our deep inventory," Thomas said.

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