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EOG Resources Reports First Quarter 2015 Results and Provides Operational Update

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HOUSTON, May 4, 2015 /PRNewswire/ --

  • Remains on Track to Achieve 40 Percent Year-over-Year Capital Expenditure Decrease
  • Directs 85 Percent of Capital to High-Return Eagle Ford, Delaware Basin and Bakken Plays
  • Reduces Well Costs Below 2015 Plan Levels
  • Improves Well Productivity through Integrated Completions Technology
  • Generates Better-than-Expected Well Results and Exceeds First Quarter 2015 Production Guidance
  • Positions Itself to Resume Strong Growth as Prices Improve

 EOG Resources, Inc. (NYSE: EOG) (EOG) today reported a first quarter 2015 net loss of $169.7 million, or $0.31 per share. This compares to first quarter 2014 net income of $660.9 million, or $1.21 per share.

Adjusted non-GAAP net income for the first quarter 2015 was $16.8 million, or $0.03 per share, compared to the same prior year period adjusted non-GAAP net income of $767.7 million, or $1.40 per share.  Adjusted non-GAAP net income is calculated by matching realizations to settlement months and making certain other adjustments in order to exclude one-time items.  (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)

EOG's first quarter 2015 financial results were significantly impacted by low commodity prices. Increased liquids production volumes, higher cash settlements from commodity derivative contracts and lower operating expenses were more than offset by lower commodity price realizations, resulting in decreases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the first quarter 2015 compared to the first quarter 2014. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)

Operational Highlights

Excluding production from EOG's Canadian operations, which were sold in the fourth quarter 2014, crude oil and condensate production increased 16 percent compared to the same prior year period.  Overall total company production, excluding the divested Canadian operations, increased eight percent compared to first quarter 2014.  The South Texas Eagle Ford and Delaware Basin plays drove production gains for the quarter. 

EOG will direct 85 percent of its 2015 capital spending to its top oil plays – the South Texas Eagle Ford, the Delaware Basin in New Mexico and Texas, and the Bakken in North Dakota. In the first quarter 2015, the company continued to make significant improvements in well productivity in these plays through integrated completions technology.  EOG is also making substantial progress in reducing well and operating costs through operational efficiencies and service cost reductions. The combination of increased well productivity and lower costs will substantially improve EOG's capital returns.

2015 Capital Plan Update

EOG's capital spending plan remains on schedule to achieve a 40 percent year-over-year decrease in 2015. As previously stated, the company has no interest in accelerating oil production at the bottom of the commodity cycle. EOG's primary goal for 2015 is to position the company to resume strong oil growth when oil prices improve. Therefore, the company chose to defer a significant number of well completions.  By deferring completions until prices improve, EOG increases capital returns and builds an inventory of uncompleted wells to prepare for strong growth in a better price environment. If prices continue to improve, EOG will begin to increase well completions in the third quarter. This will produce a "U" shaped production profile in 2015. Second and third quarter production will be the low point for the year.  Fourth quarter growth will build momentum heading into 2016.  If oil prices recover and stabilize at the $65 level, EOG is prepared to resume strong double-digit oil growth in 2016 with balanced capital spending and discretionary cash flow. 

"EOG is on track to deliver a disciplined 2015 capital program that is focused on achieving strong returns on capital invested. We continue to adjust to the lower oil price environment by reducing well costs and operating expenses and by making significant well productivity improvements through technology advancements," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOG is focused on creating long-term shareholder value through disciplined, high-return investments. We are resetting the bar to be successful in a lower commodity price environment."

South Texas Eagle Ford

Building on initial positive tests in 2014, high-density completions are planned for about 95 percent of EOG's Eagle Ford wells in 2015. The company's integrated completions process combines high-density completion techniques with tailored individual well designs to improve well productivity and lower decline rates. In addition, with significantly fewer lease retention wells in 2015, EOG is able to organize its drilling program to maximize efficiencies and reduce well costs. These enhancements further the resiliency of the leading North American crude oil play in a low oil price environment.  

During the first quarter 2015, EOG continued to achieve strong well results throughout the company's industry-leading 561,000 net acre position in the Eagle Ford oil window. In the eastern Eagle Ford, the Lefevre Unit 14H and 12H in Gonzales County had initial production rates of 3,550 and 2,890 barrels of oil per day (Bopd), 560 and 440 barrels per day (Bpd) of natural gas liquids (NGLs), and 3.9 and 3.1 million cubic feet per day (MMcfd) of natural gas, respectively.  In LaSalle County in the western Eagle Ford, a five-well pattern on the Naylor Jones Unit 39 (1H and 2H) and Unit 49 (1H, 2H and 3H) leases began production with average initial rates per well of 2,550 Bopd, plus 280 Bpd of NGLs and 1.4 MMcfd of natural gas. In McMullen County, the Bilbo Unit 1H and 2H averaged initial production rates of 2,660 Bopd, 230 Bpd of NGLs and 1.2 MMcfd of natural gas.

Delaware Basin

In the Delaware Basin, EOG expanded its activity level and continued to make advancements in well productivity and cost reduction.

EOG's Delaware Basin activity during the first quarter was focused in the Second Bone Spring Sand play.  After drilling three excellent wells in 2014, EOG stepped up its drilling pace and began shifting to development mode across the company's 90,000 net acre position.  In Lea County, N.M., EOG completed the Brown Bear 36 State #502H with an initial production rate of 1,700 Bopd, 185 Bpd of NGLs and 1.4 MMcfd of natural gas. EOG continues to test multiple zones and various well spacing patterns in the Second Bone Spring Sand.

EOG continued to test the oil window of the Delaware Basin Wolfcamp.  The recently completed Brown Bear 36 State #701H in Lea County, N.M., had an initial production rate of 2,165 Bopd, 360 Bpd of NGLs and 2.3 MMcfd of natural gas. 

In the Leonard Shale, EOG completed the Excelsior 12 #3H through #6H, in Loving County, Texas, which had average initial production rates per well of 1,020 Bopd, 180 Bpd of NGLs and 1.0 MMcfd of natural gas.  This four-well pattern tested 300-foot well spacing.

North Dakota Bakken and Rockies Plays

In the first quarter 2015, EOG focused activity on its Parshall Core acreage in the North Dakota Bakken where 500-foot spacing results were very encouraging.  Operational improvements continue to generate efficiency gains and lower well costs.  Average well costs in the first quarter were down 14 percent from 2014 levels. 

First quarter 2015 results included a five-well pattern in the Parshall area (Parshall 39-1608H, 58-1608H, 59-1608H, 147-1608H and 151-1608H), which averaged initial production rates per well of 1,235 Bopd, 110 Bpd of NGLs and 0.5 MMcfd of natural gas. Additionally, EOG completed a three-well pattern (Parshall 42-2117H, 43-2117H and 67-2117H), which had initial production rates per well that averaged 1,345 Bopd, 110 Bpd of NGLs and 0.5 MMcfd of natural gas.

In the DJ and Powder River Basins, EOG is focused on target selection and operational efficiencies. Both of these proven plays continue to generate strong results as evidenced by recent completions. In the DJ Basin, two first quarter Codell wells, the Jubilee 580-1720H and the Jubilee 582-0805H, had initial flow rates of 1,005 and 1,125 Bopd, 80 and 145 Bpd of NGLs and 0.3 and 0.5 MMcfd of natural gas, respectively. In the Powder River Basin, the Flatbow 13-13H was completed in the Turner with initial production of 860 Bopd, 70 Bpd of NGLs and 0.8 MMcfd of natural gas.

Hedging Activity

For the period May 1 through June 30, 2015, EOG has crude oil financial price swap contracts in place for 47,000 Bopd at a weighted average price of $91.22 per barrel. For the period July 1 through December 31, 2015, EOG has crude oil financial price swap contracts in place for 10,000 Bopd at a weighted average price of $89.98 per barrel, excluding unexercised options.

During the first quarter, EOG increased its natural gas hedges and now has hedges in place for approximately 22 percent of its North American natural gas production for the remainder of 2015.  For the period June 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for approximately 203,500 million British thermal units per day at a weighted average price of $4.31 per million British thermal units, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)            

Cash Flow and Capital Structure

At March 31, 2015, EOG's total debt outstanding was $6.9 billion for a debt-to-total capitalization ratio of 28 percent. Taking into account cash on the balance sheet of $2.1 billion at March 31, EOG's net debt was $4.8 billion for a net debt-to-total capitalization ratio of 21 percent. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)

During the first quarter 2015, EOG's combined expenditures for exploration, development, and other property, plant and equipment exceeded discretionary cash flow by $486 million due to low commodity prices and service contract commitments.  However, assuming oil prices remain near recent levels for the final three quarters of 2015, EOG expects balanced discretionary cash flow and capital spending for the remainder of the year.

"EOG is committed to maintaining a strong balance sheet and disciplined capital program. As expected, our first quarter capital spending was higher than levels planned for subsequent quarters. For the remainder of the year, with cost reductions and service contract roll-offs, we have the flexibility to adjust and control spending as needed," Thomas said.  "We believe current oil prices will continue to drive supply and demand changes, and the global oil markets will rebalance. Meanwhile, we are improving our fundamentals rapidly and expect to emerge from this down cycle in a better position to deliver strong growth and return on capital employed." 

Conference Call May 5, 2015

EOG's first quarter 2015 results conference call will be available via live audio webcast at 10 a.m. Central time (11 a.m. Eastern time) on Tuesday, May 5, 2015. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through May 19, 2015.

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, extent and duration 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 is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and optimize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
  • 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, appropriate gathering, processing, compression, transportation and refining 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, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
  • 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, facilities, equipment, materials and services;
  • the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) 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 (by EOG or third parties) of production, gathering, processing, refining, 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 13 through 20 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2014 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).  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, 2014, 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.

     

For Further Information Contact: 

 

Investors

   

Cedric W. Burgher

   

(713) 571-4658

   

Kimberly M. Ehmer

   

(713) 571-4676

   

David J. Streit

   

(713) 571-4902

   

Media

   

K Leonard

   

(713) 571-3870

 

EOG RESOURCES, INC.

Financial Report

(Unaudited; in millions, except per share data)

           
 

Three Months Ended

 

March 31,

 

2015

 

2014

           

Net Operating Revenues

$

2,318.5

 

$

4,083.7

Net Income (Loss)

$

(169.7)

 

$

660.9

Net Income (Loss) Per Share 

         

        Basic

$

(0.31)

 

$

1.22

        Diluted

$

(0.31)

 

$

1.21

Average Number of Common Shares

         

        Basic

 

545.0

   

542.3

        Diluted

 

545.0

   

548.1

           
           
           
           

Summary Income Statements

(Unaudited; in thousands, except per share data)

           
 

Three Months Ended

 

March 31,

 

2015

 

2014

Net Operating Revenues

     

        Crude Oil and Condensate

$

1,260,244

 

$

2,397,102

        Natural Gas Liquids

 

111,990

   

246,235

        Natural Gas

 

287,782

   

556,693

        Gains (Losses) on Mark-to-Market Commodity

         

           Derivative Contracts

 

76,208

   

(155,736)

        Gathering, Processing and Marketing

 

570,270

   

1,015,411

        Gains on Asset Dispositions, Net

 

1,607

   

11,498

        Other, Net

 

10,437

   

12,468

               Total

 

2,318,538

   

4,083,671

Operating Expenses

         

        Lease and Well

 

361,481

   

320,834

        Transportation Costs

 

228,312

   

243,237

        Gathering and Processing Costs

 

36,009

   

33,924

        Exploration Costs

 

39,449

   

48,058

        Dry Hole Costs

 

14,670

   

8,348

        Impairments 

 

69,436

   

113,361

        Marketing Costs

 

638,662

   

1,006,304

        Depreciation, Depletion and Amortization

 

912,788

   

946,491

        General and Administrative

 

84,297

   

82,862

        Taxes Other Than Income

 

106,429

   

195,973

               Total

 

2,491,533

   

2,999,392

           

Operating Income (Loss)

 

(172,995)

   

1,084,279

           

Other Expense, Net

 

(9,991)

   

(3,338)

           

Income (Loss) Before Interest Expense and Income Taxes

 

(182,986)

   

1,080,941

           

Interest Expense, Net

 

53,345

   

50,152

           

Income (Loss) Before Income Taxes

 

(236,331)

   

1,030,789

           

Income Tax Provision (Benefit)

 

(66,583)

   

369,861

           

Net Income (Loss)

$

(169,748)

 

$

660,928

           

Dividends Declared per Common Share

$

0.1675

 

$

0.1250

 
 
 
 

EOG RESOURCES, INC.

Operating Highlights

(Unaudited)

           
 

Three Months Ended

 

March 31,

 

2015

 

2014

Wellhead Volumes and Prices

 

Crude Oil and Condensate Volumes (MBbld) (A)

         

      United States

 

298.6

   

258.1

      Trinidad

 

1.0

   

1.1

      Other International (B)

 

0.1

   

7.3

            Total

 

299.7

   

266.5

           

Average Crude Oil and Condensate Prices ($/Bbl) (C)

         

      United States

$

46.71

 

$

100.58

      Trinidad

 

39.78

   

89.93

      Other International (B)

 

43.06

   

89.95

            Composite

 

46.68

   

100.25

           

Natural Gas Liquids Volumes (MBbld) (A)

         

      United States

 

77.4

   

70.8

      Other International (B)

 

0.1

   

0.8

            Total

 

77.5

   

71.6

           

Average Natural Gas Liquids Prices ($/Bbl) (C)

         

      United States

$

16.10

 

$

38.10

      Other International (B)

 

2.46

   

46.88

            Composite

 

16.08

   

38.20

           

Natural Gas Volumes (MMcfd) (A)

         

      United States

 

905

   

894

      Trinidad

 

337

   

387

      Other International (B)

 

31

   

71

            Total

 

1,273

   

1,352

           

Average Natural Gas Prices ($/Mcf) (C)

         

      United States

$

2.27

 

$

4.96

      Trinidad

 

3.09

   

3.63

      Other International (B)

 

3.28

   

4.83

            Composite

 

2.51

   

4.58

           

Crude Oil Equivalent Volumes (MBoed) (D)

         

      United States 

 

527.1

   

478.0

      Trinidad

 

57.1

   

65.6

      Other International (B)

 

5.3

   

19.9

            Total

 

589.5

   

563.5

           

Total MMBoe (D)

 

53.1

   

50.7

           
 

(A) Thousand barrels per day or million cubic feet per day, as applicable.

(B) Other International includes EOG's Canada, 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 equivalent volumes are determined using a 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,

 

2015

 

2014

ASSETS

Current Assets

         

     Cash and Cash Equivalents

$

2,127,419

 

$

2,087,213

     Accounts Receivable, Net

 

1,266,582

   

1,779,311

     Inventories

 

764,206

   

706,597

     Assets from Price Risk Management Activities

 

329,825

   

465,128

     Income Taxes Receivable

 

61,120

   

71,621

     Deferred Income Taxes

 

18,703

   

19,618

     Other

 

225,513

   

286,533

            Total

 

4,793,368

   

5,416,021

           

Property, Plant and Equipment

         

     Oil and Gas Properties (Successful Efforts Method)

 

47,727,944

   

46,503,532

     Other Property, Plant and Equipment

 

3,849,210

   

3,750,958

            Total Property, Plant and Equipment

 

51,577,154

   

50,254,490

     Less:  Accumulated Depreciation, Depletion and Amortization

 

(21,855,433)

   

(21,081,846)

            Total Property, Plant and Equipment, Net

 

29,721,721

   

29,172,644

Other Assets

 

177,365

   

174,022

Total Assets

$

34,692,454

 

$

34,762,687

           

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

         

     Accounts Payable

$

2,182,041

 

$

2,860,548

     Accrued Taxes Payable

 

121,729

   

140,098

     Dividends Payable

 

91,280

   

91,594

     Deferred Income Taxes

 

62,209

   

110,743

     Current Portion of Long-Term Debt

 

506,579

   

6,579

     Other

 

130,914

   

174,746

            Total

 

3,094,752

   

3,384,308

           
           

Long-Term Debt

 

6,393,690

   

5,903,354

Other Liabilities

 

959,068

   

939,497

Deferred Income Taxes

 

6,774,446

   

6,822,946

Commitments and Contingencies

         
           

Stockholders' Equity

         

     Common Stock, $0.01 Par, 640,000,000 Shares Authorized and

         

        549,032,089 Shares Issued at March 31, 2015 and 549,028,374

         

        Shares Issued at December 31, 2014

 

205,492

   

205,492

     Additional Paid in Capital

 

2,819,015

   

2,837,150

     Accumulated Other Comprehensive Loss

 

(36,434)

   

(23,056)

     Retained Earnings

 

14,501,816

   

14,763,098

     Common Stock Held in Treasury, 208,004 Shares at March 31, 2015

         

        and 733,517 Shares at December 31, 2014 

 

(19,391)

   

(70,102)

            Total Stockholders' Equity

 

17,470,498

   

17,712,582

Total Liabilities and Stockholders' Equity

$

34,692,454

 

$

34,762,687

 
 
 
 

EOG RESOURCES, INC.

Summary Statements of Cash Flows

(Unaudited; in thousands)

           
 

Three Months Ended

 

March 31,

 

2015

 

2014

Cash Flows from Operating Activities

         

Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:

         

     Net Income (Loss)

$

(169,748)

 

$

660,928

     Items Not Requiring (Providing) Cash

         

            Depreciation, Depletion and Amortization

 

912,788

   

946,491

            Impairments 

 

69,436

   

113,361

            Stock-Based Compensation Expenses

 

33,052

   

35,565

            Deferred Income Taxes

 

(97,241)

   

232,808

            Gains on Asset Dispositions, Net

 

(1,607)

   

(11,498)

            Other, Net

 

12,469

   

5,442

     Dry Hole Costs

 

14,670

   

8,348

     Mark-to-Market Commodity Derivative Contracts

         

            Total (Gains) Losses

 

(76,208)

   

155,736

            Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts 

 

367,707

   

(34,033)

     Excess Tax Benefits from Stock-Based Compensation

 

(8,858)

   

(27,422)

     Other, Net

 

1,616

   

3,589

     Changes in Components of Working Capital and Other Assets and Liabilities

         

            Accounts Receivable

 

353,100

   

(144,317)

            Inventories

 

(62,172)

   

(68,948)

            Accounts Payable

 

(677,875)

   

361,810

            Accrued Taxes Payable

 

2,105

   

139,801

            Other Assets

 

59,176

   

(12,536)

            Other Liabilities

 

(31,855)

   

(29,169)

     Changes in Components of Working Capital Associated with Investing and

         

        Financing Activities

 

259,992

   

(68,283)

Net Cash Provided by Operating Activities

 

960,547

   

2,267,673

           

Investing Cash Flows

         

     Additions to Oil and Gas Properties

 

(1,428,733)

   

(1,736,630)

     Additions to Other Property, Plant and Equipment

 

(116,866)

   

(165,966)

     Proceeds from Sales of Assets

 

1,118

   

19,825

     Changes in Restricted Cash

 

-

   

(9,047)

     Changes in Components of Working Capital Associated with Investing Activities

 

(259,741)

   

68,258

Net Cash Used in Investing Activities

 

(1,804,222)

   

(1,823,560)

           

Financing Cash Flows

         

     Long-Term Debt Borrowings

 

990,225

   

496,220

     Long-Term Debt Repayments

 

-

   

(500,000)

     Settlement of Foreign Currency Swap

 

-

   

(31,573)

     Dividends Paid

 

(91,661)

   

(51,780)

     Excess Tax Benefits from Stock-Based Compensation

 

8,858

   

27,422

     Treasury Stock Purchased

 

(15,459)

   

(28,897)

     Proceeds from Stock Options Exercised 

 

3,984

   

985

     Debt Issuance Costs

 

(1,603)

   

(942)

     Repayment of Capital Lease Obligation

 

(1,521)

   

(1,474)

     Other, Net

 

(251)

   

25

Net Cash Provided by (Used in) Financing Activities

 

892,572

   

(90,014)

           

Effect of Exchange Rate Changes on Cash

 

(8,691)

   

(5,096)

           

Increase in Cash and Cash Equivalents

 

40,206

   

349,003

Cash and Cash Equivalents at Beginning of Period

 

2,087,213

   

1,318,209

Cash and Cash Equivalents at End of Period

$

2,127,419

 

$

1,667,212

 

EOG RESOURCES, INC.

Quantitative Reconciliation of Adjusted Net Income (Non-GAAP)

to Net Income (Loss) (GAAP)

(Unaudited; in thousands, except per share data)

           
           

The following chart adjusts the three-month periods ended March 31, 2015 and 2014 reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net gains on asset dispositions in North America in 2015 and 2014 and to add back impairment charges related to certain of EOG's North American assets in 2014.  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,

 

2015

   

2014

             

Reported Net Income (Loss) (GAAP)

$

(169,748)

   

$

660,928

             

Commodity Derivative Contracts Impact

           

       (Gains) Losses on Mark-to-Market Commodity Derivative Contracts

 

(76,208)

     

155,736

       Net Cash Received from (Payments for) Settlements of Commodity

           

           Derivative Contracts

 

367,707

     

(34,033)

                  Subtotal

 

291,499

     

121,703

             

       After-Tax MTM Impact

 

187,580

     

78,078

             

Less: Net Gains on Asset Dispositions, Net of Tax

 

(1,011)

     

(7,377)

Add: Impairments of Certain North American Assets, Net of Tax

 

-

     

36,058

             

Adjusted Net Income (Non-GAAP)

$

16,821

   

$

767,687

             

Net Income (Loss) Per Share (GAAP)

           

       Basic

$

(0.31)

   

$

1.22

       Diluted

$

(0.31)

   

$

1.21

             

Adjusted Net Income Per Share (Non-GAAP)

           

       Basic

$

0.03

   

$

1.42

       Diluted

$

0.03

   

$

1.40

             

Adjusted Net Income Per Diluted Share (Non-GAAP) - Percentage Decrease

 

-98

%

     
             

Average Number of Common Shares (GAAP)

           

       Basic

 

544,998

     

542,278

       Diluted

 

544,998

     

548,071

             

Average Number of Common Shares (Non-GAAP)

           

      Basic

 

544,998

     

542,278

      Diluted

 

549,401

     

548,071

 

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, 2015 and 2014 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,

 

2015

   

2014

   

Net Cash Provided by Operating Activities (GAAP)

$

960,547

   

$

2,267,673

             

Adjustments:

           

     Exploration Costs (excluding Stock-Based Compensation Expenses) 

 

32,097

     

40,124

     Excess Tax Benefits from Stock-Based Compensation

 

8,858

     

27,422

     Changes in Components of Working Capital and Other Assets and Liabilities

           

          Accounts Receivable

 

(353,100)

     

144,317

          Inventories

 

62,172

     

68,948

          Accounts Payable

 

677,875

     

(361,810)

          Accrued Taxes Payable

 

(2,105)

     

(139,801)

          Other Assets

 

(59,176)

     

12,536

          Other Liabilities

 

31,855

     

29,169

     Changes in Components of Working Capital Associated with Investing and 

           

        Financing Activities

 

(259,992)

     

68,283

             

Discretionary Cash Flow (Non-GAAP)

$

1,099,031

   

$

2,156,861

             

Discretionary Cash Flow (Non-GAAP) - Percentage Decrease

 

-49

%

     

 

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 (Loss) Before Interest Expense and Income Taxes (GAAP)

(Unaudited; in thousands)

           

The following chart adjusts the three-month periods ended March 31, 2015 and 2014 reported Income (Loss) 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 received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net gains on asset dispositions in North America in 2015 and 2014.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income (Loss) 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,

 

2015

   

2014

             

Income (Loss) Before Interest Expense and Income Taxes (GAAP)

$

(182,986)

   

$

1,080,941

             

Adjustments:

           

     Depreciation, Depletion and Amortization

 

912,788

     

946,491

     Exploration Costs

 

39,449

     

48,058

     Dry Hole Costs

 

14,670

     

8,348

     Impairments 

 

69,436

     

113,361

             EBITDAX (Non-GAAP)

 

853,357

     

2,197,199

     Total (Gains) Losses on MTM Commodity Derivative 

           

        Contracts 

 

(76,208)

     

155,736

     Net Cash Received from (Payments for) Settlements of

           

        Commodity Derivative Contracts

 

367,707

     

(34,033)

     Gains on Asset Dispositions, Net

 

(1,607)

     

(11,498)

             

Adjusted EBITDAX (Non-GAAP)

$

1,143,249

   

$

2,307,404

             

Adjusted EBITDAX (Non-GAAP) - Percentage Decrease

 

-50

%

     

 

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

   

At

 
 

March 31,

   

December 31,

 
 

2015

   

2014

 
               

Total Stockholders' Equity - (a)

$

17,470

   

$

17,713

 
               

Current and Long-Term Debt (GAAP) - (b)

 

6,900

     

5,910

 

Less: Cash 

 

(2,127)

     

(2,087)

 

Net Debt (Non-GAAP) - (c)

 

4,773

     

3,823

 
               

Total Capitalization (GAAP) - (a) + (b)

$

24,370

   

$

23,623

 
               

Total Capitalization (Non-GAAP) - (a) + (c)

$

22,243

   

$

21,536

 
               

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]

 

28

%

   

25

%

               

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]

 

21

%

   

18

%

 

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 4, 2015, 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) 

2015(1)

       

January 1, 2015 through April 30, 2015 (closed)

47,000

 

$            91.22

May 1, 2015 through June 30, 2015

47,000

 

91.22

July 1, 2015 through December 31, 2015

10,000

 

89.98

           

(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 37,000 Bbld are exercisable on June 30, 2015.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 37,000 Bbld at an average price of $91.56 per barrel for each month during the period July 1, 2015 through December 31, 2015.

 

Natural Gas Derivative Contracts

 

Weighted

 

Volume

 

Average Price

 

(MMBtud) 

 

($/MMBtu) 

2015(2)

       

January 1, 2015 through February 28, 2015 (closed)

235,000

 

$             4.47

March 2015 (closed)

225,000

 

4.48

April 2015 (closed)

195,000

 

4.49

May 2015 (closed)

235,000

 

4.13

June 2015 

 

275,000

 

3.97

July 2015

 

275,000

 

3.98

August 1, 2015 through December 31, 2015

175,000

 

4.51

           

(2)

EOG has entered into natural gas derivative contracts which give counterparties the 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 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period June 1, 2015 through December 31, 2015.

 

$/Bbl

Dollars per barrel

     

$/MMBtu

Dollars per million British thermal units

     

Bbld

Barrels per day

     

MMBtu

Million British thermal units

     

MMBtud

Million British thermal units per day

     

 

EOG RESOURCES, INC.

Direct After-Tax Rate of Return (ATROR)

 

The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be).  As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. 

 
 

Direct ATROR

Based on Cash Flow and Time Value of Money

  - Estimated future commodity prices and operating costs

  - Costs incurred to drill and complete a well, including facilities

Excludes Indirect Capital

  - Gathering and Processing and other Midstream

  - Land, Seismic, Geological and Geophysical

 

Payback ~12 Months on 100% Direct ATROR Wells

First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured

ATROR of Drilling Program Has Been Rising

 
 

Return on Equity / Return on Capital Employed 

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

  - Eagle Ford, Bakken, Permian Facilities

  - Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells

Has Been Increasing Due to Increasing Direct ATROR of Drilling Program

 

EOG RESOURCES, INC.

Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income

(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of

Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP),

Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively

(Unaudited; in millions, except ratio data)

                 

The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations.  EOG management uses this information for comparative purposes within the industry.

                     
   

2014

     

2013

     

2012

Return on Capital Employed (ROCE) (Non-GAAP)

                   
                     

Net Interest Expense (GAAP)

$

201

   

$

235

       

Tax Benefit Imputed (based on 35%) 

 

(70)

     

(82)

       

After-Tax Net Interest Expense (Non-GAAP) - (a) 

$

131

   

$

153

       
                     

Net Income (GAAP) - (b)

$

2,915

   

$

2,197

       
                     

Add:  After-Tax Mark-to-Market Commodity Derivative Contracts Impact

 

(515)

     

182

       

Add:  Impairments of Certain Assets, Net of Tax

 

553

     

4

       

Add:  Tax Expense Related to the Repatriation of Accumulated 

                   

             Foreign Earnings in Future Years

 

250

     

-

       

Less: Net Gains on Asset Dispositions, Net of Tax

 

(487)

     

(137)

       
                     

Adjusted Net Income (Non-GAAP) - (c)   

$

2,716

   

$

2,246

       
                     

Total Stockholders' Equity - (d)   

$

17,713

   

$

15,418

   

$

13,285

                     

Average Total Stockholders' Equity * - (e)   

$

16,566

   

$

14,352

       
                     

Current and Long-Term Debt (GAAP) - (f) 

$

5,910

   

$

5,913

   

$

6,312

Less: Cash                                                       

 

(2,087)

     

(1,318)

     

(876)

Net Debt (Non-GAAP) - (g) 

$

3,823

   

$

4,595

   

$

5,436

                     

Total Capitalization (GAAP) - (d) + (f)  

$

23,623

   

$

21,331

   

$

19,597

                     

Total Capitalization (Non-GAAP) - (d) + (g) 

$

21,536

   

$

20,013

   

$

18,721

                     

Average Total Capitalization (Non-GAAP) * - (h)   

$

20,775

   

$

19,367

       
                     

ROCE (GAAP Net Income) - [(a) + (b)] / (h)       

 

14.7

%

   

12.1

%

     
                     

ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h)       

 

13.7

%

   

12.4

%

     
                     

Return on Equity (ROE) (Non-GAAP)

                   
                     

ROE (GAAP Net Income) - (b) / (e)

 

17.6

%

   

15.3

%

     
                     

ROE (Non-GAAP Adjusted Net Income) - (c) / (e)

 

16.4

%

   

15.6

%

     
                     

* Average for the current and immediately preceding year

         

 

 

 

EOG RESOURCES, INC.

Second Quarter and Full Year 2015 Forecast and Benchmark Commodity Pricing

 

     (a)  Second Quarter and Full Year 2015 Forecast

 

The forecast items for the second quarter and full year 2015 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 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 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 2015

     

Full Year 2015

 

Daily Production

                             

     Crude Oil and Condensate Volumes (MBbld)

                             

          United States

 

264.0

 

-

 

274.0

     

264.0

 

-

 

293.0

 

          Trinidad

 

0.6

 

-

 

0.9

     

0.7

 

-

 

0.9

 

          Other International

 

0.2

 

-

 

0.4

     

6.0

 

-

 

11.0

 

               Total

 

264.8

 

-

 

275.3

     

270.7

 

-

 

304.9

 
                               

     Natural Gas Liquids Volumes (MBbld)

                             

               Total

 

72.0

 

-

 

77.0

     

68.0

 

-

 

88.0

 
                               

     Natural Gas Volumes (MMcfd)

                             

          United States

 

850

 

-

 

890

     

850

 

-

 

890

 

          Trinidad

 

330

 

-

 

360

     

330

 

-

 

360

 

          Other International

 

27

 

-

 

33

     

27

 

-

 

33

 

               Total

 

1,207

 

-

 

1,283

     

1,207

 

-

 

1,283

 
                               

     Crude Oil Equivalent Volumes (MBoed)  

                             

          United States

 

477.7

 

-

 

499.3

     

473.7

 

-

 

529.3

 

          Trinidad

 

55.6

 

-

 

60.9

     

55.7

 

-

 

60.9

 

          Other International

 

4.7

 

-

 

5.9

     

10.5

 

-

 

16.5

 

               Total

 

538.0

 

-

 

566.1

     

539.9

 

-

 

606.7

 
                               

Operating Costs

                             

     Unit Costs ($/Boe)

                             

          Lease and Well

$

6.55

 

-

$

6.85

   

$

6.35

 

-

$

6.85

 

          Transportation Costs

$

4.25

 

-

$

4.65

   

$

4.35

 

-

$

4.65

 

          Depreciation, Depletion and Amortization

$

17.50

 

-

$

17.90

   

$

17.60

 

-

$

18.20

 
                               

Expenses ($MM)

                             

     Exploration, Dry Hole and Impairment

$

130

 

-

$

150

   

$

515

 

-

$

565

 

     General and Administrative

$

85

 

-

$

95

   

$

355

 

-

$

380

 

     Gathering and Processing 

$

33

 

-

$

39

   

$

135

 

-

$

165

 

     Capitalized Interest

$

12

 

-

$

13

   

$

45

 

-

$

50

 

     Net Interest

$

59

 

-

$

60

   

$

225

 

-

$

230

 
                               

Taxes Other Than Income (% of Wellhead Revenue)

 

6.5

%

-

 

7.0

%

   

6.3

%

-

 

6.9

%

                               

Income Taxes

                             

     Effective Rate 

 

20

%

-

 

30

%

   

25

%

-

 

30

%

     Current Taxes ($MM)

$

25

 

-

$

40

   

$

110

 

-

$

130

 
                               

Capital Expenditures (Excluding Acquisitions, $MM)

                             

     Exploration and Development, Excluding Facilities

               

$

3,950

 

-

$

4,050

 

     Exploration and Development Facilities

               

$

580

 

-

$

620

 

     Gathering, Processing and Other

               

$

370

 

-

$

430

 
                               

Pricing - (Refer to Benchmark Commodity Pricing in text)

                             

     Crude Oil and Condensate ($/Bbl)

                             

          Differentials

                             

               United States - above (below) WTI

$

(1.25)

 

-

$

0.75

   

$

(2.00)

 

-

$

0.00

 

               Trinidad - above (below) WTI

$

(10.50)

 

-

$

(9.50)

   

$

(12.00)

 

-

$

(8.00)

 
                               

     Natural Gas Liquids

                             

          Realizations as % of WTI

 

31

%

-

 

35

%

   

30

%

-

 

36

%

                               

     Natural Gas ($/Mcf)

                             

          Differentials

                             

               United States - above (below) NYMEX Henry Hub

$

(0.80)

 

-

$

(0.35)

   

$

(0.85)

 

-

$

(0.35)

 
                               

          Realizations

                             

               Trinidad

$

2.70

 

-

$

3.50

   

$

2.70

 

-

$

3.50

 

               Other International

$

3.00

 

-

$

3.50

   

$

3.00

 

-

$

3.50

 
                       

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

                     
                       

 

SOURCE EOG Resources, Inc.

 

 

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