EOG Resources, Inc. (NYSE: EOG) reported full year 2012 net income of $570.3 million, or $2.11 per share, as compared to $1,091.1 million, or $4.10 per share, for the full year 2011. For the fourth quarter 2012, EOG reported a net loss of $505.0 million, or $1.88 per share. This compares to fourth quarter 2011 net income of $120.7 million, or $0.45 per share. Adjusted non-GAAP net income for the full year 2012 was $1,535.6 million, or $5.67 per share, and for the full year 2011 was $1,008.5 million, or $3.79 per share. Adjusted non-GAAP net income for the fourth quarter 2012 was $437.0 million, or $1.61 per share, and for the fourth quarter 2011 was $309.0 million, or $1.15 per share.
Consistent with some analysts' practice of matching realizations to settlement months and making certain other adjustments in order to exclude one-time items, the results for the fourth quarter 2012 include $849.4 million, net of tax ($3.13 per share) of impairments of certain Canadian natural gas assets, net losses on asset dispositions of $35.6 million, net of tax ($0.13 per share) and a previously disclosed non-cash net gain of $66.4 million ($42.5 million after tax, or $0.16 per share) on the mark-to-market of financial commodity derivative contracts. During the fourth quarter, the net cash inflow related to financial commodity derivative contracts was $155.5 million ($99.5 million after tax, or $0.37 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income/loss.)
Reflecting EOG's higher revenue and production weighting to crude oil for the full year 2012, adjusted non-GAAP net income per share increased 50 percent, adjusted EBITDAX increased 26 percent and discretionary cash flow increased 26 percent as compared to 2011. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income per share to GAAP net income per share, adjusted EBITDAX (non-GAAP) to income before interest expense and income taxes (GAAP) and non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP).)
In the United States, crude oil and condensate production increased 46 percent for the full year 2012 compared to the prior year. Total United States liquids (crude oil, condensate and natural gas liquids) production increased 42 percent for full year 2012 over the same period a year ago. On a total company basis, total crude oil and condensate production increased 39 percent and total liquids production increased 37 percent for the full year compared to 2011. Overall total company production increased 10 percent year-over-year.
"We accomplished all of EOG's 2012 goals. We generated high margin organic crude oil production growth and delivered excellent year-over-year increases in EOG's financial metrics. We maintained our net-debt-to-total cap ratio below 30 percent and recorded strong crude oil reserve replacement rates at attractive finding costs," said Mark G. Papa, Chairman and Chief Executive Officer. "In addition, we added the Delaware Basin Wolfcamp, a promising new liquids resource play to our portfolio and significantly increased the potential recoverable reserves of our largest and highest rate of return asset, the South Texas Eagle Ford. These add high-value inventory to EOG's already prolific asset base."
EOG's stellar crude oil production in 2012 was primarily driven by drilling and completion activity in the Eagle Ford where the company drilled and completed 305 net wells, operating an average of 23 drilling rigs. In the North Dakota Bakken/Three Forks, positive results from downspaced drilling tests, together with significant modifications in drilling and completion techniques, further boosted EOG's crude oil production growth. Breakthroughs in geologic modeling in the Leonard/Wolfcamp horizontal shale plays in southeastern New Mexico and West Texas also contributed to EOG's excellent performance.
EOG made strides in increasing the amount of crude oil recoverable from both its Eagle Ford and Bakken resources by testing various drilling densities and further refining completion practices. In the Eagle Ford, EOG increased the estimated recoverable potential reserves by 38 percent from 1.6 billion barrels of oil equivalent (BnBoe) to 2.2 BnBoe, net to EOG. Numerous spacing pilots across EOG's 569,000 net acres in the crude oil window point to optimal resource development on 40-acre well spacing in the east and 65 acres in the west. At current activity levels, EOG has a 12-year Eagle Ford drilling inventory.
The revised Eagle Ford reserve potential is indicative of an estimated 8 percent recovery of the estimated 26.4 net BnBoe in place on EOG's acreage. Since discovering the Eagle Ford in 2010, EOG has raised the overall estimated captured reserve potential from 900 MMBoe (million barrels of oil equivalent) to 2.2 BnBoe, net to EOG.
EOG's best Eagle Ford well to date is the Burrow Unit #2H, which had an initial production rate of 6,330 barrels of oil per day (Bopd) with 713 barrels per day (Bpd) of natural gas liquids (NGLs) and 4.1 million cubic feet per day (MMcfd) of natural gas. Offsetting the Burrow Unit #2H, the Burrow Unit #1H was completed to sales at a maximum rate of 5,424 Bopd with 600 Bpd of NGLs and 3.5 MMcfd of natural gas. Two other prolific wells, the Boothe Unit #1H and #2H, began initial production at 5,380 and 3,810 Bopd with 625 and 525 Bpd of NGLs and 3.6 and 3.0 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these Gonzales County wells.
In McMullen County, southwest of EOG's Gonzales County sweet spot, the Naylor Jones Unit 59 East #1H and West #4H had initial peak production rates of 1,670 and 1,150 Bopd with 225 and 138 Bpd of NGLs and 1.3 and 0.8 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these wells that were completed in early January 2013.
"The Eagle Ford's potential reserves of 2.2 billion barrels of oil equivalent represent the largest domestic crude oil find net to one company in 40 years. Not only is 600 million net barrels a meaningful increase, this onshore U.S. oil field is readily accessible to premium markets," Papa said. "With both the technical acumen and high-quality assets, EOG is at the forefront in developing this world-class shale oil resource."
Over the course of 2012, EOG's North Dakota wells showed marked productivity improvement following the implementation of new completion techniques. On its 90,000 net acre Bakken Core, EOG confirmed that 320-acre well spacing is economically sound, and it is very encouraged by 160-acre results. Recent downspaced tests reflect a gain of approximately 30 percent to 70 percent in cumulative production over earlier wells drilled in the field. The Fertile 51-0410H, in which EOG has a 94 percent working interest, had a maximum initial production rate of 1,800 Bopd with 850 thousand cubic feet per day (Mcfd) of rich natural gas. The first 160-acre spaced wells in the Core area, the Wayzetta 022-1509H and 149-1509H, had maximum rates of 1,185 and 1,265 Bopd, respectively. EOG has 68 percent working interest in these wells.
Southwest of the Bakken Core in the Antelope Extension, the Hawkeye 01-2501H and 102-2501H were completed to sales in early January 2013. These McKenzie County wells, in which EOG has 75 percent working interest, were turned to sales at 2,445 and 2,945 Bopd, respectively. In the Stateline area near the North Dakota/Montana border, the Garden Coulee 001-1410H had an initial production rate of 1,415 Bopd with 1,260 Mcfd of rich natural gas. EOG has a 74 percent working interest in this Williams County, N.D., well.
On the Texas side of the Delaware Basin, EOG confirmed a new shale play with the completion of two horizontal Wolfcamp wells on its 114,000 net acre position. In Reeves County, the Harrison Ranch #56-1002H and #56-1001H tested at rates of 377 Bopd with 602 Bpd of NGLs and 3.9 MMcfd of natural gas and 635 Bopd with 480 Bpd of NGLs and 3.1 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these wells. Based on the geologic characteristics of the formation and the potential to drill multiple laterals combined with data from over 200 previously drilled vertical wells on EOG's acreage, estimated net potential reserves are approximately 800 MMBoe, a mix of crude oil and liquids-rich natural gas.
In southeastern New Mexico, the overall economics and size of EOG's horizontal Delaware Basin Leonard Shale play improved last year due to strong well results and decreased drilling costs. The Vaca 14 Fed #6H was completed in Lea County at an initial rate of 1,290 Bopd with 255 Bpd of NGLs and 1.4 MMcfd of natural gas. EOG has 100 percent working interest in this well. EOG has increased the total net reserve potential on its 73,000 net acres from 65 MMBoe to 550 MMBoe, predicated on better well results and a 50 percent crude oil yield. Total potential reserves on EOG'sDelaware Basin horizontal Wolfcamp and Leonard Shale plays are estimated to be 1.35 BnBoe, net.
During 2012, EOG secured premium pricing for some of its Bakken, Eagle Ford and Permian Basin crude oil by expanding its innovative crude-by-rail operations. Commissioned in April 2012, a crude oil unloading terminal at St. James, La., enabled EOG to achieve average domestic crude oil realizations exceeding benchmark West Texas Intermediate indices.
EOG's total company net proved reserves were 1,811 MMBoe at December 31, 2012. Total company net proved developed reserves decreased 2 percent, and total North American net proved developed reserves were approximately flat with the previous year, excluding the impact of property dispositions. Total company net proved undeveloped reserves decreased 15 percent year over year due to low natural gas prices in 2012 that caused essentially all of the previously booked proved undeveloped reserves in EOG's North American dry gas properties to be written off. Total proved liquids reserves increased 37 percent year-over-year, comprising 56 percent of total company proved reserves at December 31, 2012.
- Total reserve replacement from all sources – the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production – was 268 percent at a total reserve replacement cost of $12.60 per barrel of oil equivalent (Boe), based on exploration and development expenditures of $6,921 million and excluding price-related revisions. (For the calculation of total reserve replacement and total reserve replacement costs, please refer to the attached tables.)
- Total liquids reserve replacement from all sources – the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production – was 452 percent. (For the calculation of total liquids reserve replacement, please refer to the attached tables.)
- Reserve replacement from drilling – the ratio of extensions, discoveries and other additions to total production – was 238 percent. Crude oil reserve replacement from drilling in the United States was 442 percent. (For the calculation of reserve replacement from drilling, please refer to the attached tables.)
- In the United States, total reserve replacement from all sources, excluding price-related revisions, was 326 percent at a reserve replacement cost of $11.82 per Boe based on exploration and development expenditures of $6,362 million. (For the calculation of United States total reserve replacement and total reserve replacement costs, please refer to the attached tables.) In the United States, 80 percent of the reserve additions were liquids.
For the 25th consecutive year, internal reserve estimates were within 5 percent of those prepared by the independent reserve engineering firm of DeGolyer and MacNaughton (D&M). For 2012, D&M prepared a complete independent engineering analysis of properties comprising 87 percent of EOG's proved reserves on a Boe basis.
EOG's 2012 total cash capital expenditure program was approximately $7.5 billion. (Please refer to the attached tables for the reconciliation of total expenditures (GAAP) to total cash expenditures (non-GAAP).) Through year-end 2012, EOG's cash proceeds from asset sales were approximately $1.3 billion.
At December 31, 2012, EOG's total debt outstanding was $6,312 million for a debt-to-total capitalization ratio of 32 percent. Taking into account cash on the balance sheet of $876 million at the end of the fourth quarter, EOG's net debt was $5,436 million for a net debt-to-total capitalization ratio of 29 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)
"2012 marked a turning point for EOG. We continued to develop our key crude oil assets while locking up core natural gas and Combo acreage in the Barnett, Leonard and Wolfcamp plays for the long term. In addition, we exited the Kitimat LNG project," Papa said.
EOG is targeting total company crude oil production growth of 28 percent with a 23 percent increase in total liquids production in 2013. In North America, natural gas production is expected to decrease 15 percent from 2012. EOG is continuing to de-emphasize natural gas drilling in a weak price environment. Driven by high margin, domestic crude oil production, overall EOG's total company production is expected to increase 4 percent over 2012.
Estimated exploration and development expenditures for 2013 are expected to range from $7.0 to $7.2 billion, including production facilities and midstream expenditures, and excluding acquisitions. Overall asset sales are expected to be approximately $550 million, of which $466 million has closed to date.
In 2013, EOG plans an active crude oil and liquids exploration program focusing on increasing recovery of hydrocarbons in existing plays and pursuing new greenfield opportunities. The majority of EOG's capital expenditures will be directed toward its two key crude oil assets, the Eagle Ford and Bakken/Three Forks. The Eagle Ford, where EOG estimates it will drill and complete approximately 400 net wells, is expected to contribute the largest share of company production growth in 2013. In the North Dakota Bakken Core and Antelope Extension Bakken/Three Forks, plans are to test additional downspaced drilling patterns. In its southeastern New Mexico horizontal Leonard/West Texas Wolfcamp Shale plays, EOG anticipates operating a moderate drilling program in 2013. Drilling activity in the new Delaware Basin Wolfcamp play is expected to ramp up over the next two years to achieve significant production growth for EOG beginning in 2015. Very minimal dry gas drilling activity is expected in 2013.
"EOG's demonstrated ability to organically grow crude oil volumes should lead to strong 2013 returns," Papa said. "Until other commodity prices strengthen, we are directing EOG's capex dollars almost exclusively toward crude oil exploration and development. Leading with our Eagle Ford and North Dakota operations, EOG is well positioned to achieve its game plan, while identifying strategic marketing advances that will further strengthen our position. With the most attractive drilling program in our history, EOG has the critical assets in place to make 2013 another outstanding year."
For the period January 1 through June 30, 2013, EOG has crude oil financial price swap contracts in place for an average of 105,000 Bopd at a weighted average price of $99.23 per barrel, excluding unexercised options. For the period July 1 through December 31, 2013, EOG has an average of 93,000 Bopd hedged at a weighted average price of $98.44 per barrel, excluding unexercised options.
Despite very minimal dry natural gas drilling activity planned for 2013, EOG has financial price swap contracts in place for 150,000 million British thermal units per day of natural gas at a weighted average price of $4.79 per million British thermal units, excluding unexercised options for the calendar year. (For a comprehensive summary of EOG's crude oil and natural gas derivative contracts, please refer to the attached tables.)
Following an increase in the common stock dividend in 2012, EOG's Board of Directors has again increased the cash dividend on the common stock. Effective with the dividend payable on April 30, 2013, to holders of record as of April 16, 2013, the quarterly dividend on the common stock will be $0.1875 per share, an increase of 10 percent over the previous indicated annual rate. The indicated annual rate of $0.75 per share reflects the 14th increase in 14 years.