EOG Resources Reports Second Quarter 2011 Results
HOUSTON, Aug. 4, 2011 /PRNewswire/ --
-- Reports 13 Percent Total Company Production Growth in the First Half
of 2011 Versus 2010
-- Achieves 60 Percent Growth in Second Quarter United States Crude Oil
and Condensate Volumes Year-Over-Year
-- On Track to Achieve 9.5 Percent Total Company Production Growth in
2011
-- Continues to Realize Top Quality, Consistent Results from Eagle Ford
Oil
-- Adds Oklahoma Panhandle Marmaton to Horizontal Crude Oil Play Book
-- Announces Favorable Well Completions from West Texas Wolfcamp and New
Mexico Leonard and Bone Spring Plays
-- Maintains Strong Performance in North Dakota
-- Raises Prospectivity Level of Colorado Niobrara Acreage
-- Anticipates Additional $600 Million of 2011 Asset Dispositions to
Offset Capital Expenditure Increase
EOG Resources, Inc.
(EOG) today reported second quarter 2011 net income of $295.6 million, or $1.10 per share. This compares to second quarter 2010 net income of $59.9 million, or $0.24 per share.Consistent with some analysts' practice of matching cash flow realizations to settlement months, and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the second quarter 2011 was $299.2 million, or $1.11 per share. Adjusted non-GAAP net income for the second quarter 2010 was $44.9 million, or $0.18 per share. The results for the second quarter 2011 included a $226.2 million, net of tax ($0.84 per share) impairment of certain non-core North American natural gas assets, gains on property dispositions, net of tax, of $105.2 million ($0.39 per share) and a previously disclosed non-cash net gain of $189.6 million ($121.4 million after tax, or $0.45 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $6.3 million ($4.0 million after tax, or $0.01 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)
Operational Highlights
Total company production increased 13 percent in the first half of 2011 compared to the same period in 2010. Driven by a 60 percent rise in United States crude oil and condensate production during the second quarter, EOG delivered 46 percent total company crude oil, condensate and natural gas liquids production growth versus the second quarter 2010. Leading the crude oil production growth was the South Texas Eagle Ford followed by the Fort Worth Barnett Shale Combo. Also contributing to the increase were newer crude oil and liquids-rich plays such as the Colorado Niobrara, Oklahoma Marmaton, West Texas Wolfcamp and New Mexico Leonard.
'Demonstrating the depth and quality of our portfolio, EOG's crude oil and liquids-rich plays delivered strong, consistent second quarter production results, driving our overall first half 2011 production growth,' said Mark G. Papa, Chairman and Chief Executive Officer. 'Just as we had forecast, EOG's natural gas production is decreasing due to asset sales and the priority we have placed on developing our outstanding crude oil and liquids investment opportunities.'
EOG is on track to achieve its targeted 9.5 percent total company organic production growth for 2011. Total company 2011 crude oil and condensate production is projected to increase by 52 percent, while total company crude oil, condensate and natural gas liquids production is forecast to rise 47 percent over 2010.
Crude Oil and Liquids Activity
Early in its transition to a liquids-focused company, EOG identified the rich oil potential of the South Texas Eagle Ford Shale and amassed a large acreage position in the sweet spot of the crude oil window.
'We are finding that well results across our 535,000 net acre position in the Eagle Ford oil window are remarkably similar. The wealth of drilling, completion and production data at our fingertips is reflected in the steadily rising momentum of our operations and success in achieving more predictable results,' Papa said.
As EOG further defines geologic sub-trends and refines completion techniques, the majority of its Eagle Ford wells are being completed to sales at initial production rates in excess of 1,000 barrels of crude oil per day (Bopd). Leveraging this consistency, EOG ramped up its drilling activity from 10 rigs at the beginning of 2011 to its current intensive program of 22 rigs.
In Gonzales County where EOG is actively drilling, the King Fehner Unit #2H, #4H, #5H and #6H wells began initial production at maximum rates ranging from 1,238 to 1,487 Bopd with 1.2 to 1.6 million cubic feet per day (MMcfd) of rich natural gas.
'These are the first Eagle Ford wells that EOG has tested with a tighter spacing pattern. If downspacing proves economically viable, we have the potential to significantly increase our reserves in the Eagle Ford,' Papa said.
EOG reported production rates from other successful wells in Gonzales County. The Merritt #4H had a peak initial production rate of 1,361 Bopd with 0.6 MMcfd of rich natural gas. The Steen Unit #1H, #2H, #4H and #6H came online with production rates ranging from 663 to 1,269 Bopd with 0.7 to 1.4 MMcfd of rich natural gas. In its far northeastern acreage where EOG announced success from a fault block earlier this year, the Hill Unit #1H and #3H were completed. They flowed to sales at peak rates of 1,461 and 1,734 Bopd with 1.0 and 1.3 MMcfd of rich natural gas, respectively.
In LaSalle County, the Naylor Jones A #2H, 99 #1H and 96 #1H provided additional confirmation of the consistent quality of EOG's 120-mile acreage trend. The wells, located in the southwestern part of EOG's block, had strong production rates ranging from 997 to 1,153 Bopd with 1.0 to 2.3 MMcfd of rich natural gas. In Karnes County, the heart of EOG's extensive acreage, the Max Unit #1H had a peak initial production rate of 1,591 Bopd with 1.5 MMcfd of rich natural gas. Also in Karnes County, the Braune Unit #1H was turned to sales at an initial rate of 1,611 Bopd with 1.0 MMcfd of rich natural gas. EOG has 100 percent working interest in all 16 of these Eagle Ford wells.
'With the 77 percent crude oil mix of our Eagle Ford acreage position, this large, highly rated resource play has become a significant contributor to fueling EOG's transition to an oil company in a short period of time,' Papa said.
EOG announced positive drilling results from a new horizontal crude oil play, the Marmaton sandstone in the Oklahoma Panhandle. In Ellis County where EOG has drilled a series of wells, the Brown 18 #1VH and Opal 31 #1H were completed to sales at production rates of 620 and 1,312 Bopd with 0.7 and 2.6 MMcfd of natural gas, respectively. EOG has 58 and 49 percent working interest in the wells, respectively. EOG has 88 percent working interest in the Fischer 12 #1VH, which began initial production at 508 Bopd, with strong natural gas production. Encouraging well results provide the potential for additional development drilling locations on its 34,000 net acre position. To identify further exploration opportunities, EOG plans to acquire 3D seismic over this acreage.
EOG continues to post excellent drilling results from its 131,400 net acre position in the West Texas Wolfcamp and its 108,000 net acre position in the New Mexico Leonard Shale and Bone Spring Sands plays. The current moderate level of drilling activity is expected to ramp up in 2012 and beyond. Following refinements in completion techniques, recent well results show improvement in crude oil production flow rates.
Drilled and completed in the West Texas Wolfcamp, the University 40-A #0401H began flowing to sales at a maximum oil rate of 935 Bopd with 838 thousand cubic feet per day (Mcfd) of rich natural gas. EOG has 85 percent working interest in this Irion County well. Also in Irion County, the Linthicum M #1H and I #5H had production rates of 809 and 664 Bopd with 892 and 1,178 Mcfd of rich natural gas, respectively. EOG has 75 and 85 percent working interest in the wells, respectively. EOG has 100 percent working interest in the University 9 #2802H, drilled in Reagan County, northwest of its Irion County and Crockett County activity. The well had a peak production rate of 583 Bopd with 254 Mcfd of rich natural gas.
In Lea County, New Mexico where EOG is developing its Leonard Shale acreage, the Caballo 23 #1H was completed at a production rate of 665 Bopd with 1.2 MMcfd of rich natural gas. EOG has 86 percent working interest in the well. In Eddy County, the Elk Wallow 11 St. #4 had a maximum production rate of 735 Bopd with 2.0 MMcfd of rich natural gas. EOG has 75 percent working interest in this Leonard Shale well. Also in Eddy County, EOG drilled the Parkway 23 State #3H in the Bone Spring Sands, which is producing 511 Bopd with 726 Mcfd of natural gas. EOG holds 81 percent working interest in the well.
Since mid-2009, EOG's Denver-Julesburg Basin drilling activity has been concentrated on its 80,000 net acre Hereford Ranch Field in Weld County, Colorado. The Jake 2-01H discovery, which was drilled as a horizontal well targeting the Niobrara formation, began initial production in late 2009 at a first month average rate of 645 Bopd. Since the first quarter 2011, it has been producing at a relatively stable rate of 250 to 300 Bopd. Following the Jake well, the Elmer 8-31H, which was drilled in March 2010 with a short lateral, had an initial average 30-day production rate of 283 Bopd and is currently producing approximately 225 Bopd. Encouraging data from long-term stabilized crude oil production rates indicate that the Niobrara wells will be characterized by lower initial flow rates, but flatter decline curves than other crude oil resource plays.
Acreage outside EOG's Hereford Ranch Field was also proven productive during the quarter. Southeast of the Hereford Ranch Field, the Fiscus Mesa 9-10H was drilled and completed to sales at an initial controlled rate of 335 Bopd with 174 Mcfd of natural gas. EOG has 86 percent working interest in the well. West of the Fiscus Mesa well, EOG has 75 percent working interest in the Gravel Draw 9-09H that began production at an initial controlled rate of 277 Bopd with 146 Mcfd of natural gas. Based on long-term well production results from its Hereford Ranch Field and new drilling results and production data, EOG has established the economic potential for crude oil development on 169,000 of its 220,000 net acre Niobrara position.
In the Texas Fort Worth Barnett Combo, EOG's program in Montague County and western Cooke County continues to deliver successful production results with efficiency gains in both drilling and completion operations. In western Cooke County, the Gaedke A Unit #3H and #4H and B Unit #5H, #6H and #7H wells were brought to sales at rates ranging from 338 to 696 Bopd with 807 to 2,152 Mcfd of rich natural gas. EOG has 99 percent working interest in the wells. In Montague County, EOG has 100 percent working interest in the Stoddard A Unit #1H, B Unit #2H, C Unit #3H and D Unit #4H that came online at rates ranging from 777 to 918 Bopd with 1,262 to 2,677 Mcfd of rich natural gas. While EOG's efforts have focused on testing new completion techniques in the sweet spot of its core acreage, an inventory of several years of drilling locations has been identified in the play.
Despite weather challenges in the North Dakota Williston Basin over the last eight to nine months, EOG continued its drilling and production activities, as well as operating its proprietary crude-by-rail transportation system. Although EOG minimized the adverse impact of abnormally wet weather on production goals during the second quarter, completion operations were impacted and area flooding remains an issue.
Drilled with a 9,968 foot long-reach lateral, the Liberty LR #21-36H was completed to sales at a maximum rate of 1,201 Bopd with 1,147 Mcfd of natural gas. EOG has 95 percent working interest in the well. The Fertile #19-29H and #45-29H were both completed in the Bakken formation in Mountrail County. The wells, in which EOG has 38 and 75 percent working interest, respectively, came online at maximum rates of 1,008 and 1,223 Bopd, respectively. In Williams County, EOG has 67 percent working interest in the Hardscrabble 13-3526H, which began flowing to sales at 1,474 Bopd. EOG holds 85 percent working interest in the Clarks Creek 3-0805H, which was completed in the Three Forks formation in McKenzie County at a maximum production rate of 1,384 Bopd.
'EOG's early innovative crude-by-rail midstream investments in the Bakken and Eagle Ford have proven valuable in delivering our crude oil directly to major market hubs given the current lack of available pipeline capacity in these two prolific plays,' Papa said. 'Our Bakken crude oil rail transportation system was particularly beneficial during the recent North Dakota flooding because it enabled EOG to continue to make crude oil deliveries.'
Natural Gas Activity
In North America, EOG's natural gas production decreased 1.6 percent in the second quarter compared to the same prior year period due to reduced drilling activity and natural gas asset sales. In the United States where EOG is employing drilling capital to maintain core leasehold positions, it posted strong operational results from its Marcellus Shale and Haynesville/Bossier Shale natural gas horizontal resource plays. In Canada, EOG's natural gas production decreased due to asset divestitures and the reallocation of capital toward liquids-rich reinvestment opportunities.
Capital Structure
During the second quarter, total cash proceeds from sales of acreage, producing natural gas properties and midstream assets were approximately $684 million. Through the first half of 2011, total cash proceeds from assets sales were $944 million. Based on negotiated purchase and sale agreements and other pending transactions, EOG anticipates property sales for the full year of approximately $1.6 billion, or $600 million higher than the original $1 billion target for 2011. Estimated exploration and production expenditures will range from $6.8 billion to $7.0 billion, including exploration, development and production facilities and midstream expenditures, an increase of approximately $400 million from EOG's previously stated targets.
At June 30, 2011, EOG's total debt outstanding was $5.2 billion for a debt-to-total capitalization ratio of 30 percent. Taking into account $1.6 billion of cash on the balance sheet at the end of the quarter, EOG's net debt was $3.6 billion for a net debt-to-total capitalization ratio of 23 percent. EOG is targeting a net debt-to-total capitalization ratio of 30 percent or less at both year-end 2011 and 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).)
'Our well-timed efforts to recreate EOG as a high margin, crude oil-focused company are paying off,' Papa said. 'On the basis of both per share earnings and cash flow growth, EOG is positioned to be an industry leader for years to come.'
Conference Call Scheduled for August 5, 2011
EOG's second quarter 2011 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Friday, August 5, 2011. To listen, log onto http://www.eogresources.com/. The webcast will be archived on EOG's website through August 19, 2011.
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 or generate income or cash flows 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, 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 and
advanced completion technologies;
-- 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 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 and
hydraulic fracturing and laws and regulations imposing conditions and
restrictions on drilling and completion operations;
-- 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;
-- 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 timing and impact of liquefied natural gas imports;
-- the use of competing energy sources and the development of alternative
energy sources;
-- the extent to which EOG incurs uninsured losses and liabilities;
-- acts of war and terrorism and responses to these acts; and
-- the other factors described under Item 1A, 'Risk Factors', on pages 14
through 20 of EOG's Annual Report on Form 10-K for the fiscal year
ended December 31, 2010 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 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, 2010, 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 http://www.sec.gov/.
InvestorsMaire A. Baldwin (713) 651-6EOG (651-6364)Elizabeth M. Ivers (713) 651-7132
MediaK Leonard (713) 571-3870
EOG RESOURCES, INC.
FINANCIAL REPORT
----------------
(Unaudited; in millions, except per share data)
Three Months Ended Six Months Ended
June 30, June 30,
-------- --------
2011 2010 2011 2010
---- ---- ---- ----
Net
Operating
Revenues $2,570.3 $1,358.0 $4,467.4 $2,728.7
======== ======== ======== ========
Net Income $295.6 $59.9 $429.5 $177.9
====== ===== ====== ======
Net Income
Per Share
Basic $1.11 $0.24 $1.65 $0.71
===== ===== ===== =====
Diluted $1.10 $0.24 $1.63 $0.70
===== ===== ===== =====
Average
Number of
Shares
Outstanding
Basic 265.8 250.8 259.8 250.6
===== ===== ===== =====
Diluted 269.3 254.5 263.4 254.2
===== ===== ===== =====
SUMMARY INCOME STATEMENTS
-------------------------
(Unaudited; in thousands, except per share data)
Three Months Ended
June 30,
--------
2011 2010
---- ----
Net Operating Revenues
Crude Oil and Condensate $938,518 $455,808
Natural Gas Liquids 183,805 104,241
Natural Gas 599,993 553,354
Gains on Mark-to-Market Commodity
Derivative Contracts 189,621 37,015
Gathering, Processing and Marketing 487,698 195,876
Gains on Asset Dispositions, Net 163,771 8,307
Other, Net 6,844 3,367
----- -----
Total 2,570,250 1,357,968
--------- ---------
Operating Expenses
Lease and Well 216,695 160,734
Transportation Costs 101,965 94,345
Gathering and Processing Costs 17,716 13,220
Exploration Costs 41,238 50,131
Dry Hole Costs 1,676 19,318
Impairments 358,654 80,362
Marketing Costs 469,437 191,213
Depreciation, Depletion and
Amortization 602,944 465,343
General and Administrative 67,406 64,737
Taxes Other Than Income 104,266 78,064
------- ------
Total 1,981,997 1,217,467
--------- ---------
Operating Income 588,253 140,501
Other Income (Expense), Net 6,224 (545)
----- ----
Income Before Interest Expense and
Income Taxes 594,477 139,956
Interest Expense, Net 51,253 29,897
------ ------
Income Before Income Taxes 543,224 110,059
Income Tax Provision 247,650 50,187
------- ------
Net Income $295,574 $59,872
======== =======
Dividends Declared per Common Share $0.160 $0.155
====== ======
Six Months Ended
June 30,
--------
2011 2010
---- ----
Net Operating Revenues
Crude Oil and Condensate $1,695,880 $861,970
Natural Gas Liquids 332,532 207,268
Natural Gas 1,183,912 1,230,336
Gains on Mark-to-Market Commodity
Derivative Contracts 122,875 44,818
Gathering, Processing and Marketing 883,281 367,819
Gains on Asset Dispositions, Net 235,513 7,632
Other, Net 13,363 8,818
------ -----
Total 4,467,356 2,728,661
--------- ---------
Operating Expenses
Lease and Well 431,784 326,726
Transportation Costs 199,598 183,056
Gathering and Processing Costs 36,912 28,881
Exploration Costs 92,147 101,328
Dry Hole Costs 24,627 42,395
Impairments 447,982 149,957
Marketing Costs 854,846 359,977
Depreciation, Depletion and
Amortization 1,171,170 897,249
General and Administrative 137,443 125,160
Taxes Other Than Income 210,143 153,529
------- -------
Total 3,606,652 2,368,258
--------- ---------
Operating Income 860,704 360,403
Other Income (Expense), Net 9,828 2,138
----- -----
Income Before Interest Expense and
Income Taxes 870,532 362,541
Interest Expense, Net 101,586 55,325
------- ------
Income Before Income Taxes 768,946 307,216
Income Tax Provision 339,399 129,329
------- -------
Net Income $429,547 $177,887
======== ========
Dividends Declared per Common Share $0.320 $0.310
====== ======
EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
--------------------
(Unaudited)
Three Months Ended
June 30,
--------
2011 2010
---- ----
Wellhead Volumes and Prices
---------------------------
Crude Oil and Condensate Volumes (MBbld) (A)
United States 92.3 57.6
Canada 8.8 6.6
Trinidad 3.3 5.4
Other International (B) 0.1 0.1
--- ---
Total 104.5 69.7
===== ====
Average Crude Oil and Condensate Prices
($/Bbl) (C)
United States $99.50 $73.18
Canada 102.65 71.63
Trinidad 99.49 68.90
Other International (B) 101.52 73.21
Composite 99.77 72.69
Natural Gas Liquids Volumes (MBbld) (A)
United States 38.4 27.5
Canada 0.7 0.9
--- ---
Total 39.1 28.4
==== ====
Average Natural Gas Liquids Prices ($/Bbl)
(C)
United States $51.50 $40.31
Canada 60.39 42.55
Composite 51.65 40.38
Natural Gas Volumes (MMcfd) (A)
United States 1,114 1,069
Canada 139 204
Trinidad 349 341
Other International (B) 13 15
--- ---
Total 1,615 1,629
===== =====
Average Natural Gas Prices ($/Mcf) (C)
United States $4.24 $4.12
Canada 4.16 3.60
Trinidad 3.51 2.58
Other International (B) 5.61 4.27
Composite 4.08 3.73
Crude Oil Equivalent Volumes (MBoed) (D)
United States 316.4 263.2
Canada 32.6 41.5
Trinidad 61.4 62.2
Other International (B) 2.2 2.7
--- ---
Total 412.6 369.6
===== =====
Total MMBoe (D) 37.5 33.6
Six Months Ended
June 30,
--------
2011 2010
---- ----
Wellhead Volumes and Prices
---------------------------
Crude Oil and Condensate Volumes (MBbld) (A)
United States 86.8 55.9
Canada 8.6 6.2
Trinidad 3.9 4.6
Other International (B) 0.1 0.1
--- ---
Total 99.4 66.8
==== ====
Average Crude Oil and Condensate Prices
($/Bbl) (C)
United States $94.05 $73.23
Canada 93.65 72.39
Trinidad 92.33 67.89
Other International (B) 93.67 72.18
Composite 93.95 72.77
Natural Gas Liquids Volumes (MBbld) (A)
United States 36.5 25.6
Canada 0.8 0.9
--- ---
Total 37.3 26.5
==== ====
Average Natural Gas Liquids Prices ($/Bbl)
(C)
United States $49.21 $43.23
Canada 52.77 44.09
Composite 49.29 43.25
Natural Gas Volumes (MMcfd) (A)
United States 1,124 1,055
Canada 141 208
Trinidad 367 346
Other International (B) 13 16
--- ---
Total 1,645 1,625
===== =====
Average Natural Gas Prices ($/Mcf) (C)
United States $4.17 $4.67
Canada 3.91 4.42
Trinidad 3.35 2.54
Other International (B) 5.62 4.27
Composite 3.98 4.18
Crude Oil Equivalent Volumes (MBoed) (D)
United States 310.7 257.5
Canada 32.9 41.7
Trinidad 65.0 62.3
Other International (B) 2.3 2.7
--- ---
Total 410.9 364.2
===== =====
Total MMBoe (D) 74.4 65.9
Thousand barrels per day or million cubic feet per day,
(A) as applicable.
Other International includes EOG's United Kingdom and
(B) China operations.
Dollars per barrel or per thousand cubic feet, as
applicable. Excludes the impact of financial commodity
(C) derivative instruments.
Thousand barrels of oil equivalent per day or million
barrels of oil equivalent, as applicable; includes
(D) 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)
June 30, December 31,
2011 2010
---- ----
ASSETS
Current Assets
Cash and Cash
Equivalents $1,577,438 $788,853
Accounts Receivable,
Net 1,279,740 1,113,279
Inventories 540,094 415,792
Assets from Price Risk
Management Activities 109,225 48,153
Income Taxes
Receivable 27,694 54,916
Deferred Income Taxes - 9,260
Other 103,759 97,193
------- ------
Total 3,637,950 2,527,446
Property, Plant and
Equipment
Oil and Gas Properties
(Successful Efforts
Method) 31,588,860 29,263,809
Other Property, Plant
and Equipment 1,871,497 1,733,073
Total Property, Plant
and Equipment 33,460,357 30,996,882
Less: Accumulated
Depreciation,
Depletion and
Amortization (13,463,534) (12,315,982)
----------- -----------
Total Property, Plant
and Equipment, Net 19,996,823 18,680,900
Other Assets 324,606 415,887
Total Assets $23,959,379 $21,624,233
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable $1,870,172 $1,664,944
Accrued Taxes Payable 148,645 82,168
Dividends Payable 42,976 38,962
Liabilities from Price
Risk Management
Activities 12,393 28,339
Deferred Income Taxes 50,180 41,703
Current Portion of
Long-Term Debt 220,000 220,000
Other 131,872 143,983
Total 2,476,238 2,220,099
Long-Term Debt 5,006,251 5,003,341
Other Liabilities 718,696 667,455
Deferred Income Taxes 3,681,009 3,501,706
Commitments and
Contingencies
Stockholders' Equity
Common Stock, $0.01
Par, 640,000,000
Shares Authorized and
268,698,963 Shares
Issued at June 30,
2011 and
254,223,521 Shares
Issued at December
31, 2010 202,687 202,542
Additional Paid In
Capital 2,181,157 729,992
Accumulated Other
Comprehensive Income 492,880 440,071
Retained Earnings 9,213,356 8,870,179
Common Stock Held in
Treasury, 143,309
Shares at June 30,
2011
and 146,186 Shares at
December 31, 2010 (12,895) (11,152)
Total Stockholders'
Equity 12,077,185 10,231,632
---------- ----------
Total Liabilities
and Stockholders'
Equity $23,959,379 $21,624,233
EOG RESOURCES, INC.
SUMMARY STATEMENTS OF CASH FLOWS
--------------------------------
(Unaudited; in thousands)
Six Months Ended
June 30,
--------
2011 2010
--- ---
Cash Flows from Operating
Activities
Reconciliation of Net Income
to Net Cash Provided by
Operating Activities:
Net Income $429,547 $177,887
Items Not Requiring
(Providing) Cash
Depreciation, Depletion and
Amortization 1,171,170 897,249
Impairments 447,982 149,957
Stock-Based Compensation
Expenses 53,427 44,953
Deferred Income Taxes 206,130 24,493
Gains on Asset Dispositions,
Net (235,513) (7,632)
Other, Net (834) (1,252)
Dry Hole Costs 24,627 42,395
Mark-to-Market Commodity
Derivative Contracts
Total Gains (122,875) (44,818)
Realized Gains 31,285 38,827
Other, Net 13,268 8,454
Changes in Components of
Working Capital and Other
Assets and Liabilities
Accounts Receivable (165,300) (39,275)
Inventories (127,062) (67,363)
Accounts Payable 189,250 254,878
Accrued Taxes Payable 94,311 (6,011)
Other Assets (4,796) (24,499)
Other Liabilities (12,017) (10,930)
Changes in Components of
Working Capital Associated
with Investing and
Financing Activities 76,640 (135,973)
------ --------
Net Cash Provided by
Operating Activities 2,069,240 1,301,340
Investing Cash Flows
Additions to Oil and Gas
Properties (3,122,567) (2,288,270)
Additions to Other Property,
Plant and Equipment (340,140) (115,661)
Proceeds from Sales of
Assets 944,481 41,939
Changes in Components of
Working Capital Associated
with Investing
Activities (76,852) 135,693
Other, Net - (4,157)
--- ------
Net Cash Used in Investing
Activities (2,595,078) (2,230,456)
Financing Cash Flows
Common Stock Sold 1,388,270 -
Long-Term Debt Borrowings - 991,395
Long-Term Debt Repayments - (37,000)
Dividends Paid (81,562) (75,179)
Treasury Stock Purchased (16,736) (7,307)
Proceeds from Stock Options
Exercised and Employee
Stock Purchase Plan 24,619 21,023
Debt Issuance Costs - (1,194)
Other, Net 212 280
--- ---
Net Cash Provided by
Financing Activities 1,314,803 892,018
Effect of Exchange Rate
Changes on Cash (380) 1,461
---- -----
Increase (Decrease) in Cash
and Cash Equivalents 788,585 (35,637)
Cash and Cash Equivalents at
Beginning of Period 788,853 685,751
------- -------
Cash and Cash Equivalents at
End of Period $1,577,438 $650,114
========== ========
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 three-month and six-month periods ended
June 30, 2011 and 2010 reported Net Income (GAAP) to reflect actual
net cash realized from
financial commodity price transactions by eliminating the unrealized
mark-to-market gains from these transactions, to add back
impairment charges related to certain of
EOG's non-core North American natural gas assets in the first and
second quarters of 2011, to eliminate the gains on asset dispositions
primarily in North America in the
first and second quarters of 2011, and to eliminate the change in the
estimated fair value of a contingent consideration liability related
to EOG's previously disclosed
acquisition of Haynesville and Bossier Shale unproved acreage in the
first and second quarters of 2010. 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 one-time items. EOG management uses this
information for comparative purposes within the industry.
Three Months Ended
June 30,
--------
2011 2010
---- ---
Reported Net Income (GAAP) $295,574 $59,872
Mark-to-Market (MTM) Commodity Derivative
Contracts Impact
Total Gains (189,621) (37,015)
Realized Gains 6,348 15,867
Subtotal (183,273) (21,148)
-------- -------
After-Tax MTM Impact (117,281) (13,540)
-------- -------
Add: Impairments of Certain Non-core North
American Natural Gas Assets, Net of Tax 226,177 -
Less: Gains on Asset Dispositions, Net of
Tax (105,224) -
Less: Change in Fair Value of Contingent
Consideration Liability, Net of Tax - (1,421)
--- ------
Adjusted Net Income (Non-GAAP) $299,246 $44,911
======== =======
Net Income Per Share (GAAP)
Basic $1.11 $0.24
===== =====
Diluted $1.10 $0.24
===== =====
Adjusted Net Income Per Share (Non-GAAP)
Basic $1.13 $0.18
===== =====
Diluted $1.11 $0.18
===== =====
Average Number of Shares
Basic 265,830 250,825
======= =======
Diluted 269,332 254,503
======= =======
Six Months Ended
June 30,
--------
2011 2010
---- ---
Reported Net Income (GAAP) $429,547 $177,887
Mark-to-Market (MTM) Commodity Derivative
Contracts Impact
Total Gains (122,875) (44,818)
Realized Gains 31,285 38,827
Subtotal (91,590) (5,991)
------- ------
After-Tax MTM Impact (58,641) (3,836)
------- ------
Add: Impairments of Certain Non-core North
American Natural Gas Assets, Net of Tax 256,460 -
Less: Gains on Asset Dispositions, Net of Tax (151,110) -
Less: Change in Fair Value of Contingent
Consideration Liability, Net of Tax - (11,354)
--- -------
Adjusted Net Income (Non-GAAP) $476,256 $162,697
======== ========
Net Income Per Share (GAAP)
Basic $1.65 $0.71
===== =====
Diluted $1.63 $0.70
===== =====
Adjusted Net Income Per Share (Non-GAAP)
Basic $1.83 $0.65
===== =====
Diluted $1.81 $0.64
===== =====
Average Number of Shares
Basic 259,766 250,596
======= =======
Diluted 263,363 254,206
======= =======
EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW (NON-GAAP)
-----------------------------------------------------------------
TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)
---------------------------------------------------
(Unaudited; in thousands)
The following chart reconciles the three-month and six-month
periods ended June 30, 2011 and 2010 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),
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
June 30,
--------
2011 2010
---- ----
Net Cash Provided by Operating
Activities (GAAP) $1,111,752 $681,053
Adjustments
Exploration Costs (excluding
Stock-Based Compensation
Expenses) 35,775 44,820
Changes in Components of Working
Capital and Other Assets and
Liabilities
Accounts Receivable 51,445 (56,495)
Inventories 59,329 14,051
Accounts Payable (23,753) (107,246)
Accrued Taxes Payable (14,563) 2,221
Other Assets (13,860) 11,005
Other Liabilities 20,638 5,376
Changes in Components of Working
Capital Associated
with Investing and Financing
Activities (74,655) 61,381
------- ------
Discretionary Cash Flow (Non-
GAAP) $1,152,108 $656,166
========== ========
Six Months Ended
June 30,
--------
2011 2010
---- ----
Net Cash Provided by Operating
Activities (GAAP) $2,069,240 $1,301,340
Adjustments
Exploration Costs (excluding
Stock-Based Compensation
Expenses) 80,542 90,503
Changes in Components of Working
Capital and Other Assets and
Liabilities
Accounts Receivable 165,300 39,275
Inventories 127,062 67,363
Accounts Payable (189,250) (254,878)
Accrued Taxes Payable (94,311) 6,011
Other Assets 4,796 24,499
Other Liabilities 12,017 10,930
Changes in Components of Working
Capital Associated
with Investing and Financing
Activities (76,640) 135,973
------- -------
Discretionary Cash Flow (Non-
GAAP) $2,098,756 $1,421,016
========== ==========
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.
June 30,
2011
----
Total Stockholders' Equity - (a) $12,077
-------
Current and Long-Term Debt - (b) 5,226
Less: Cash (1,577)
------
Net Debt (Non-GAAP) - (c) 3,649
-----
Total Capitalization (GAAP) - (a) + (b) $17,303
=======
Total Capitalization (Non-GAAP) - (a) + (c) $15,726
=======
Debt-to-Total Capitalization (GAAP) - (b) /[(a) +
(b)] 30%
===
Net Debt-to-Total Capitalization (Non-GAAP) - (c)
/[(a) + (c)] 23%
===
EOG RESOURCES, INC.
THIRD QUARTER AND FULL YEAR 2011 FORECAST AND BENCHMARK COMMODITY PRICING
-------------------------------------------------------------------------
(a) Third Quarter and Full Year 2011 Forecast
The forecast items for the third quarter and full year 2011 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)
3Q 2011
-------
Daily Production
Crude Oil and Condensate
Volumes (MBbld)
United States 103.5 - 113.5
Canada 6.5 - 8.0
Trinidad 2.2 - 3.2
Total 112.2 - 124.7
Natural Gas Liquids Volumes
(MBbld)
United States 38.5 - 43.5
Canada 0.7 - 1.1
Total 39.2 - 44.6
Natural Gas Volumes (MMcfd)
United States 1,100 - 1,130
Canada 115 - 125
Trinidad 300 - 320
Other International 9 - 13
Total 1,524 - 1,588
Crude Oil Equivalent Volumes
(MBoed)
United States 325.3 - 345.4
Canada 26.4 - 29.9
Trinidad 52.2 - 56.5
Other International 1.5 - 2.2
Total 405.4 - 434.0
Operating Costs
Unit Costs ($/Boe)
Lease and Well $5.85 - $6.45
Transportation Costs $2.89 - $3.25
Depreciation, Depletion and
Amortization $16.20 - $17.16
Expenses ($MM)
Exploration, Dry Hole and
Impairment $145.0 - $175.0
General and Administrative $92.0 - $99.0
Gathering and Processing $16.5 - $20.5
Capitalized Interest $13.0 - $17.0
Net Interest $48.5 - $53.5
Taxes Other Than Income (% of
Revenue) 5.8% - 6.4%
Income Taxes
Effective Rate 35% - 50%
Current Taxes ($MM) $60 - $75
Capital Expenditures ($MM) -
FY 2011 (Excluding
Acquisitions)
Exploration and Development,
Excluding Facilities
Exploration and Development
Facilities
Gathering, Processing and
Other
Pricing -(Refer to Benchmark
Commodity Pricing in text)
Crude Oil and Condensate
($/Bbl)
Differentials
United States -below WTI $3.75 - $6.25
Canada -below WTI $7.00 - $8.15
Trinidad -below WTI $8.15 - $12.15
Natural Gas ($/Mcf)
Differentials
United States -below NYMEX
Henry Hub $0.05 - $0.15
Canada -below NYMEX Henry
Hub $0.35 - $0.55
Realizations
Trinidad $2.25 - $3.00
Other International $5.25 - $6.00
ESTIMATED RANGES
----------------
(Unaudited)
Full Year 2011
--------------
Daily Production
Crude Oil and Condensate
Volumes (MBbld)
United States 99.4 - 105.7
Canada 7.0 - 8.2
Trinidad 3.0 - 3.5
Total 109.4 - 117.4
Natural Gas Liquids
Volumes (MBbld)
United States 38.5 - 40.9
Canada 0.8 - 1.0
Total 39.3 - 41.9
Natural Gas Volumes
(MMcfd)
United States 1,114 - 1,130
Canada 126 - 130
Trinidad 338 - 360
Other International 12 - 16
Total 1,590 - 1,636
Crude Oil Equivalent
Volumes (MBoed)
United States 323.6 - 334.9
Canada 28.8 - 30.9
Trinidad 59.3 - 63.5
Other International 2.0 - 2.7
Total 413.7 - 432.0
Operating Costs
Unit Costs ($/Boe)
Lease and Well $5.88 - $6.24
Transportation Costs $2.82 - $3.00
Depreciation, Depletion
and Amortization $16.12 - $16.54
Expenses ($MM)
Exploration, Dry Hole and
Impairment $518.0 - $563.0
General and Administrative $311.0 - $325.0
Gathering and Processing $70.0 - $77.0
Capitalized Interest $56.0 - $64.0
Net Interest $197.5 - $207.0
Taxes Other Than Income (%
of Revenue) 6.0% - 6.7%
Income Taxes
Effective Rate 35% - 45%
Current Taxes ($MM) $260 - $280
Capital Expenditures ($MM)
-FY 2011 (Excluding
Acquisitions)
Exploration and
Development, Excluding
Facilities $5,750 - $5,850
Exploration and
Development Facilities $450 - $500
Gathering, Processing and
Other $600 - $650
Pricing -(Refer to
Benchmark Commodity
Pricing in text)
Crude Oil and Condensate
($/Bbl)
Differentials
United States -below WTI $4.00 - $6.00
Canada -below WTI $5.50 - $6.75
Trinidad -below WTI $6.35 - $9.25
Natural Gas ($/Mcf)
Differentials
United States -below
NYMEX Henry Hub $0.03 - $0.15
Canada -below NYMEX Henry
Hub $0.30 - $0.50
Realizations
Trinidad $2.80 - $3.15
Other International $5.35 - $6.00
Definitions
-----------
$/Bbl U.S. Dollars per barrel
U.S. Dollars per barrel of
$/Boe oil equivalent
U.S. Dollars per thousand
$/Mcf cubic feet
$MM U.S. Dollars in millions
MBbld Thousand barrels per day
Thousand barrels of oil
MBoed equivalent per day
MMcfd Million cubic feet per day
NYMEX New York Mercantile Exchange
WTI West Texas Intermediate
EOG Resources, Inc.
Web Site: http://www.eogresources.com/
