EOG Resources Reports Third Quarter 2015 Results; Increases Delaware Basin Net Resource Potential by 1.0 BnBoe

05 Nov, 2015, 16:20 ET from EOG Resources, Inc.

HOUSTON, Nov. 5, 2015 /PRNewswire/ --

  • Updates Delaware Basin Net Resource Potential to 2.35 BnBoe
    • Increases Wolfcamp Net Reserve Potential by 500 MMBoe
    • Announces Second Bone Spring Sand Net Reserve Potential of 500 MMBoe
    • Expands Drilling Inventory from 2,700 to 4,900 Net Wells
    • Acquires 26,000 Net Acres in the Delaware Basin Oil Window in Three Transactions
    • Completes Record Horizontal Well for Delaware Basin Wolfcamp
  • Continues to Improve Well Productivity While Lowering Costs
  • Exceeds Third Quarter Oil and Total Production Guidance
  • Reduces Per-Unit Lease Operating Costs by 5 Percent Versus Second Quarter

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported a third quarter 2015 net loss of $4.1 billion, or $7.47 per share. This compares to third quarter 2014 net income of $1.1 billion, or $2.01 per share.

Adjusted non-GAAP net income for the third quarter 2015 was $13.5 million, or $0.02 per share, compared to the same prior year period adjusted non-GAAP net income of $720.6 million, or $1.31 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.)

During the third quarter 2015, proved oil and gas properties and related assets were written down to their fair value resulting in non-cash impairment charges of $4.1 billion net of tax.  The impairments were due to declines in commodity prices and were primarily related to legacy natural gas and marginal liquids assets. 

Significant reductions in operating expenses were more than offset by lower commodity price realizations, resulting in decreases in adjusted non-GAAP net income, discretionary cash flow and adjusted EBITDAX during the third quarter 2015 compared to the third quarter 2014. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)

Operational Highlights In the third quarter 2015, total crude oil and condensate production exceeded prior guidance due to improved well productivity.  Total company production decreased 5 percent compared to the third quarter 2014 excluding production related to EOG's Canadian operations, which were divested in the fourth quarter 2014.  Total capital expenditures decreased 36 percent compared to the same prior year period. 

EOG also continued to reduce completed well costs and operating costs compared to the same quarter last year.  Lease and well expenses decreased 17 percent on a per-unit basis due to improved operational efficiencies and reduced service costs.  Per-unit transportation costs decreased 11 percent, and total general and administrative expenses declined 6 percent.

"We are executing on our 2015 plan to reset the company to be successful in a low commodity price environment," said William R. "Bill" Thomas, Chairman and Chief Executive Officer.  "By continuing to make the best oil wells in the industry, significantly reducing costs and expanding resource potential in the best North American oil plays, EOG is uniquely positioned for 2016 and to lead the industry for years to come."

2015 Capital Plan Update EOG is maintaining full-year 2015 capital spending guidance.  U.S. crude oil production guidance increased due to strong well performance.  Total company crude oil production guidance is slightly lower due to delays in the startup of the U.K. Conwy project. 

Delaware Basin EOG increased its Delaware Basin net resource potential by 1.0 billion barrels of oil equivalent (BnBoe).  For the Delaware Basin Wolfcamp, EOG added 950 net drilling locations and increased its net resource potential estimate over 60 percent to 1.3 BnBoe.  Advancements in targeting and completion technology are enabling tighter well spacing and increased production per well.  In the Second Bone Spring Sand oil play, EOG provided an initial net resource potential estimate of 500 million barrels of oil equivalent (MMBoe) and added 1,250 net drilling locations in this high quality crude oil play. 

EOG added 26,000 net acres to its Delaware Basin position in the third quarter 2015 through three tactical acquisitions in Loving County, Texas, and Lea County, N.M., for a total of $368 million.  Most of the acquired acreage is adjacent to EOG's existing operating areas in the high rate of return Delaware Basin oil window.  Combined, these acquisitions added net production of 750 barrels of oil equivalent (Boe) per day with an associated 2.5 MMBoe of proved producing reserves.  These acquisitions and the updated resource potential bring EOG's total Delaware Basin net position to 2.35 BnBoe and 4,900 locations, providing decades of high return drilling potential.

"Outstanding technical and operational advances enabled us to increase potential resource estimates for our Delaware Basin position by over 70 percent," Thomas said.  "We are also pleased that through our tactical acquisitions of new, high quality Delaware Basin acreage, we added assets which meet our high rate of return hurdle.  EOG's Delaware Basin assets along with the company's Eagle Ford and Bakken positions continue to grow in both size and quality.  With premier assets and commitment to innovation, EOG continues to enhance its capability for high return growth in a low oil price environment."

In addition, EOG completed a number of noteworthy new wells in the Delaware Basin in the third quarter.

In the Wolfcamp shale in Lea County, N.M., EOG completed the Thor 21 #701H and #702H with average initial production rates per well of 3,255 barrels of oil per day (Bopd), 470 barrels per day (Bpd) of natural gas liquids (NGLs) and 3.9 million cubic feet per day (MMcfd) of natural gas.  The Thor 21 #702H set a new industry 30-day production record for horizontal wells in the Delaware Basin Wolfcamp.

In the Second Bone Spring Sand in Lea County, N.M., EOG completed the Neptune 10 State Com #501H and #502H in a two-well pattern with average initial production rates per well of 2,205 Bopd, 185 Bpd of NGLs and 1.5 MMcfd of natural gas. 

In the Leonard shale in Lea County, N.M., EOG completed the Hawk 35 Fed #7H, #8H, #9H and #10H in a four-well pattern with average initial production rates per well of 1,615 Bopd, 160 Bpd of NGLs and 1.3 MMcfd of natural gas.

South Texas Eagle Ford The Eagle Ford continues to be EOG's largest high return play.  During 2015, the company expanded the use of high density completions to 95 percent of the Eagle Ford wells planned for the year.  Enabled by high density completions and proprietary targeting technology, EOG is actively testing tighter well spacing in the lower Eagle Ford with stacked-staggered "W" patterns.  Additionally, an efficient drilling program increased the amount of acreage held by production to 91 percent of EOG's 561,000 net acres in the Eagle Ford oil window.  In Gonzales County, EOG completed the Phoenix Unit #4H and #5H with average initial production rates per well of 3,815 Bopd, 415 Bpd of NGLs and 2.8 MMcfd of natural gas.  In McMullen County, EOG completed the Naylor Jones Unit 26 #1H and #2H in a two-well pattern with average initial production rates per well of 2,650 Bopd with 150 Bpd of NGLs and 1.0 MMcfd of natural gas. 

North Dakota Bakken EOG's activity in North Dakota remains focused on the Bakken Core and Antelope Extension areas.  The company continued to improve its drilling and completion techniques including the expanded use of high density completions.  In addition, recently installed water gathering facilities have significantly reduced operating expenses.  During the third quarter 2015, the company completed the Parshall #88-3029H, #23-3029H and #26-3029H in a three-well pattern with average initial production rates per well of 1,830 Bopd and 1.0 MMcfd of rich natural gas.  Average lateral lengths for the wells were 5,925 feet.

Hedging Activity For the period November 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.  In addition, EOG has put options in place which establish a floor price of $45.00 per barrel for 82,500 Bopd for November 2015.

For December 2015, EOG has natural gas financial price swap contracts in place for 175,000 million British thermal units (MMBtu) per day at a weighted average price of $4.51 per MMBtu, excluding unexercised options. Comprehensive summaries of crude oil and natural gas derivative contracts are provided in the attached tables.            

Capital Structure At September 30, 2015, EOG's total debt outstanding was $6.4 billion with a debt-to-total capitalization ratio of 33 percent. Taking into account cash on the balance sheet of $743 million at September 30, EOG's net debt was $5.7 billion with a net debt-to-total capitalization ratio of 30 percent. A reconciliation of non-GAAP measures to GAAP measures is provided in the attached tables.

Conference Call November 6, 2015 EOG's third quarter 2015 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, November 6, 2015. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through December 7, 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

David J. Streit

(713) 571-4902

Kimberly M. Ehmer

(713) 571-4676

Media

K Leonard

(713) 571-3870

 

EOG RESOURCES, INC.

Financial Report

(Unaudited; in millions, except per share data)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2015

2014

2015

2014

Net Operating Revenues

$

2,172.4

$

5,118.6

$

6,960.7

$

13,389.8

Net Income (Loss)

$

(4,075.7)

$

1,103.6

$

(4,240.2)

$

2,470.9

Net Income (Loss) Per Share 

        Basic

$

(7.47)

$

2.03

$

(7.77)

$

4.55

        Diluted

$

(7.47)

$

2.01

$

(7.77)

$

4.51

Average Number of Common Shares

        Basic

545.9

544.0

545.5

543.1

        Diluted

545.9

549.5

545.5

548.4

Summary Income Statements

(Unaudited; in thousands, except per share data)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2015

2014

2015

2014

Net Operating Revenues

        Crude Oil and Condensate

$

1,181,092

$

2,671,502

$

3,894,092

$

7,687,579

        Natural Gas Liquids

95,217

258,927

311,137

753,135

        Natural Gas

281,837

443,108

843,657

1,508,892

        Gains on Mark-to-Market Commodity

           Derivative Contracts

29,239

469,125

56,954

84,119

        Gathering, Processing and Marketing

572,217

1,196,933

1,820,843

3,240,139

        Gains (Losses) on Asset Dispositions, Net

(1,185)

60,346

(5,142)

75,700

        Other, Net

14,011

18,675

39,126

40,279

               Total

2,172,428

5,118,616

6,960,667

13,389,843

Operating Expenses

        Lease and Well

283,221

368,340

934,366

1,035,632

        Transportation Costs

203,594

246,067

641,739

729,883

        Gathering and Processing Costs

35,497

41,621

106,503

108,015

        Exploration Costs

31,344

48,955

114,548

139,221

        Dry Hole Costs

198

16,359

14,317

30,265

        Impairments 

6,307,420

55,542

6,445,375

207,938

        Marketing Costs

615,303

1,213,652

1,924,134

3,263,471

        Depreciation, Depletion and Amortization

722,172

1,040,018

2,544,187

2,983,111

        General and Administrative

90,959

96,931

257,580

270,725

        Taxes Other Than Income

105,677

204,969

334,244

606,411

               Total

8,395,385

3,332,454

13,316,993

9,374,672

Operating Income (Loss)

(6,222,957)

1,786,162

(6,356,326)

4,015,171

Other Income (Expense), Net

8,607

(21,338)

7,996

(16,726)

Income (Loss) Before Interest Expense and Income Taxes

(6,214,350)

1,764,824

(6,348,330)

3,998,445

Interest Expense, Net

60,571

49,704

174,400

151,723

Income (Loss) Before Income Taxes

(6,274,921)

1,715,120

(6,522,730)

3,846,722

Income Tax Provision (Benefit)

(2,199,182)

611,502

(2,282,511)

1,375,823

Net Income (Loss)

$

(4,075,739)

$

1,103,618

$

(4,240,219)

$

2,470,899

Dividends Declared per Common Share

$

0.1675

$

0.1675

$

0.5025

$

0.4175

EOG RESOURCES, INC.

Operating Highlights

(Unaudited)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2015

2014

2015

2014

Wellhead Volumes and Prices

Crude Oil and Condensate Volumes (MBbld) (A)

      United States

278.3

293.2

284.4

275.5

      Trinidad

1.0

0.9

0.9

1.0

      Other International (B)

0.2

5.4

0.2

6.1

            Total

279.5

299.5

285.5

282.6

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

      United States

$

45.93

$

97.33

$

49.94

$

100.10

      Trinidad

38.56

87.87

41.98

90.84

      Other International (B)

61.80

87.72

58.44

90.74

            Composite

45.91

97.13

49.92

99.87

Natural Gas Liquids Volumes (MBbld) (A)

      United States

77.7

85.8

76.2

78.4

      Other International (B)

0.1

0.6

0.1

0.7

            Total

77.8

86.4

76.3

79.1

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

      United States

$

13.25

$

32.61

$

14.94

$

34.83

      Other International (B)

8.05

40.38

6.05

43.01

            Composite

13.24

32.67

14.93

34.90

Natural Gas Volumes (MMcfd) (A)

      United States

889

941

895

920

      Trinidad

355

356

342

374

      Other International (B)

30

72

31

74

            Total

1,274

1,369

1,268

1,368

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

      United States

$

2.04

$

3.48

$

2.14

$

4.17

      Trinidad

2.90

3.50

3.01

3.61

      Other International (B)

7.18

(E)

4.16

4.63

(E)

4.56

            Composite

2.40

3.52

2.44

4.04

Crude Oil Equivalent Volumes (MBoed) (D)

      United States 

504.2

536.1

509.8

507.3

      Trinidad

60.2

60.1

57.9

63.4

      Other International (B)

5.2

17.9

5.4

19.0

            Total

569.6

614.1

573.1

589.7

Total MMBoe (D)

52.4

56.5

156.5

161.0

(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.

(E)

Includes revenue adjustment of $3.62 per Mcf and $1.19 per Mcf for the quarter and year-to-date, respectively, related to a price adjustment for natural gas sales made in China during the period June 2012 through March 2015.

 

EOG RESOURCES, INC.

Summary Balance Sheets

(Unaudited; in thousands, except share data)

September 30,

December 31,

2015

2014

ASSETS

Current Assets

     Cash and Cash Equivalents

$

742,689

$

2,087,213

     Accounts Receivable, Net

1,123,111

1,779,311

     Inventories

660,252

706,597

     Assets from Price Risk Management Activities

71,503

465,128

     Income Taxes Receivable

53,667

71,621

     Deferred Income Taxes

40,619

19,618

     Other

133,117

286,533

            Total

2,824,958

5,416,021

Property, Plant and Equipment

     Oil and Gas Properties (Successful Efforts Method)

50,025,191

46,503,532

     Other Property, Plant and Equipment

3,890,934

3,750,958

            Total Property, Plant and Equipment

53,916,125

50,254,490

     Less:  Accumulated Depreciation, Depletion and Amortization

(29,640,793)

(21,081,846)

            Total Property, Plant and Equipment, Net

24,275,332

29,172,644

Other Assets

176,957

174,022

Total Assets

$

27,277,247

$

34,762,687

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

     Accounts Payable

$

1,561,574

$

2,860,548

     Accrued Taxes Payable

174,897

140,098

     Dividends Payable

91,377

91,594

     Deferred Income Taxes

-

110,743

     Short-Term Borrowings and Current Portion of Long-Term Debt

36,279

6,579

     Other

182,834

174,746

            Total

2,046,961

3,384,308

Long-Term Debt

6,393,931

5,903,354

Other Liabilities

970,288

939,497

Deferred Income Taxes

4,581,844

6,822,946

Commitments and Contingencies

Stockholders' Equity

     Common Stock, $0.01 Par, 640,000,000 Shares Authorized and         550,052,879 Shares Issued at September 30, 2015 and 549,028,374         Shares Issued at December 31, 2014

205,503

205,492

     Additional Paid in Capital

2,897,439

2,837,150

     Accumulated Other Comprehensive Loss

(34,979)

(23,056)

     Retained Earnings

10,247,349

14,763,098

     Common Stock Held in Treasury, 383,870 Shares at September 30, 2015         and 733,517 Shares at December 31, 2014 

(31,089)

(70,102)

            Total Stockholders' Equity

13,284,223

17,712,582

Total Liabilities and Stockholders' Equity

$

27,277,247

$

34,762,687

EOG RESOURCES, INC.

Summary Statements of Cash Flows

(Unaudited; in thousands)

Nine Months Ended

September 30,

2015

2014

Cash Flows from Operating Activities

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

     Net Income (Loss)

$

(4,240,219)

$

2,470,899

     Items Not Requiring (Providing) Cash

            Depreciation, Depletion and Amortization

2,544,187

2,983,111

            Impairments 

6,445,375

207,938

            Stock-Based Compensation Expenses

101,926

103,636

            Deferred Income Taxes

(2,377,030)

974,522

            (Gains) Losses on Asset Dispositions, Net

5,142

(75,700)

            Other, Net

3,735

17,188

     Dry Hole Costs

14,317

30,265

     Mark-to-Market Commodity Derivative Contracts

            Total Gains

(56,954)

(84,119)

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

661,021

(188,937)

     Excess Tax Benefits from Stock-Based Compensation

(24,219)

(87,827)

     Other, Net

8,904

8,701

     Changes in Components of Working Capital and Other Assets and Liabilities

            Accounts Receivable

448,311

(341,043)

            Inventories

27,007

(119,166)

            Accounts Payable

(1,310,211)

566,753

            Accrued Taxes Payable

77,575

176,412

            Other Assets

146,965

(61,966)

            Other Liabilities

(15,683)

66,618

     Changes in Components of Working Capital Associated with Investing and Financing     

        Activities

519,203

(108,568)

Net Cash Provided by Operating Activities

2,979,352

6,538,717

Investing Cash Flows

     Additions to Oil and Gas Properties

(3,918,065)

(5,653,035)

     Additions to Other Property, Plant and Equipment

(252,295)

(587,178)

     Proceeds from Sales of Assets

144,285

91,335

     Changes in Restricted Cash

-

(91,238)

     Changes in Components of Working Capital Associated with Investing Activities

(519,323)

108,999

Net Cash Used in Investing Activities

(4,545,398)

(6,131,117)

Financing Cash Flows

     Net Commercial Paper Borrowings

29,700

-

     Long-Term Debt Borrowings

990,225

496,220

     Long-Term Debt Repayments

(500,000)

(500,000)

     Settlement of Foreign Currency Swap

-

(31,573)

     Dividends Paid

(274,577)

(187,670)

     Excess Tax Benefits from Stock-Based Compensation

24,219

87,827

     Treasury Stock Purchased

(43,419)

(114,824)

     Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 

14,967

11,740

     Debt Issuance Costs

(5,933)

(895)

     Repayment of Capital Lease Obligation

(4,599)

(4,457)

     Other, Net

120

(431)

Net Cash Provided by (Used in) Financing Activities

230,703

(244,063)

Effect of Exchange Rate Changes on Cash

(9,181)

(601)

Increase (Decrease) in Cash and Cash Equivalents

(1,344,524)

162,936

Cash and Cash Equivalents at Beginning of Period

2,087,213

1,318,209

Cash and Cash Equivalents at End of Period

$

742,689

$

1,481,145

 

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 and nine-month periods ended September 30, 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 from these transactions, to eliminate the impact of the Texas margin tax rate reduction in 2015, to eliminate the net (gains) losses on asset dispositions, to add back severance costs associated with EOG's North American operations in 2015 and to add back impairment charges related to certain of EOG's assets in 2015 and 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 

Nine Months Ended

September 30,

September 30,

2015

2014

2015

2014

Reported Net Income (Loss) (GAAP)

$

(4,075,739)

$

1,103,618

$

(4,240,219)

$

2,470,899

Commodity Derivative Contracts Impact

       Gains on Mark-to-Market Commodity Derivative Contracts

(29,239)

(469,125)

(56,954)

(84,119)

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

99,879

(68,037)

661,021

(188,937)

                  Subtotal

70,640

(537,162)

604,067

(273,056)

       After-Tax MTM Impact

45,457

(344,616)

388,717

(175,179)

Less: Texas Margin Tax Rate Reduction

-

-

(19,500)

-

Less: Net (Gains) Losses on Asset Dispositions, Net of Tax

(3,429)

(38,386)

1,694

(47,426)

Add:  Severance Costs, Net of Tax

-

-

5,473

-

Add:  Impairments of Certain Assets, Net of Tax

4,047,223

-

4,047,223

36,058

Adjusted Net Income (Non-GAAP)

$

13,512

$

720,616

$

183,388

$

2,284,352

Net Income (Loss) Per Share (GAAP)

       Basic

$

(7.47)

$

2.03

$

(7.77)

$

4.55

       Diluted

$

(7.47)

$

2.01

$

(7.77)

$

4.51

Adjusted Net Income Per Share (Non-GAAP)

       Basic

$

0.02

$

1.32

$

0.34

$

4.21

       Diluted

$

0.02

$

1.31

$

0.33

$

4.17

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

-98

%

-92

%

Average Number of Common Shares (GAAP)

       Basic

545,920

543,984

545,466

543,086

       Diluted

545,920

549,518

545,466

548,401

Average Number of Common Shares (Non-GAAP)

   Basic

545,920

543,984

545,466

543,086

   Diluted

549,434

549,518

549,414

548,401

 

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 nine-month periods ended September 30, 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

Nine Months Ended

September 30,

September 30,

2015

2014

2015

2014

Net Cash Provided by Operating Activities (GAAP)

$

1,131,432

$

2,336,469

$

2,979,352

$

6,538,717

Adjustments:

Exploration Costs (excluding Stock-Based Compensation Expenses) 

25,286

42,220

95,253

119,003

Excess Tax Benefits from Stock-Based Compensation

7,826

24,068

24,219

87,827

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

(150,128)

91,707

(448,311)

341,043

Inventories

10,602

9,410

(27,007)

119,166

Accounts Payable

310,567

(219,214)

1,310,211

(566,753)

Accrued Taxes Payable

(13,451)

(60,744)

(77,575)

(176,412)

Other Assets

(70,851)

(79,487)

(146,965)

61,966

Other Liabilities

(33,165)

(9,517)

15,683

(66,618)

Changes in Components of Working Capital Associated with Investing and

Financing Activities

(349,401)

76,924

(519,203)

108,568

Discretionary Cash Flow (Non-GAAP)

$

868,717

$

2,211,836

$

3,205,657

$

6,566,507

Discretionary Cash Flow (Non-GAAP) - Percentage Decrease

-61

%

-51

%

 

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 and nine-month periods ended September 30, 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 from these transactions and to eliminate the net (gains) losses on asset dispositions.  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

Nine Months Ended

September 30,

September 30,

2015

2014

2015

2014

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

$

(6,214,350)

$

1,764,824

$

(6,348,330)

$

3,998,445

Adjustments:

     Depreciation, Depletion and Amortization

722,172

1,040,018

2,544,187

2,983,111

     Exploration Costs

31,344

48,955

114,548

139,221

     Dry Hole Costs

198

16,359

14,317

30,265

     Impairments 

6,307,420

55,542

6,445,375

207,938

             EBITDAX (Non-GAAP)

846,784

2,925,698

2,770,097

7,358,980

     Total Gains on MTM Commodity Derivative Contracts  

(29,239)

(469,125)

(56,954)

(84,119)

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

99,879

(68,037)

661,021

(188,937)

     (Gains) Losses on Asset Dispositions, Net

1,185

(60,346)

5,142

(75,700)

Adjusted EBITDAX (Non-GAAP)

$

918,609

$

2,328,190

$

3,379,306

$

7,010,224

Adjusted EBITDAX (Non-GAAP) - Percentage Decrease

-61

%

-52

%

 

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

September 30,

December 31,

2015

2014

Total Stockholders' Equity - (a)

$

13,284

$

17,713

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

6,430

5,910

Less: Cash 

(743)

(2,087)

Net Debt (Non-GAAP) - (c)

5,687

3,823

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

$

19,714

$

23,623

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

$

18,971

$

21,536

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

33

%

25

%

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

30

%

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 November 5, 2015, with notional volumes expressed in Bbld and MMBtud and prices and premiums expressed in $/Bbl and $/MMBtu.  EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.

Crude Oil Price Swap Contracts

Weighted

Volume 

Average Price

(Bbld) 

($/Bbl) 

2015

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

47,000

$

91.22

July 1, 2015 through October 31, 2015 (closed)

10,000

89.98

November 1, 2015 through December 31, 2015

10,000

89.98

Crude Oil Put Option Contracts

 Average  

Strike

 Volume 

 Premium 

Price

 (Bbld) 

 ($/Bbl) 

($/Bbl)

2015 (1)

September 1, 2015 through October 31, 2015 (closed)

82,500

$

1.75

$

45.00

November 2015

82,500

1.75

45.00

(1)

EOG has purchased put options which establish a floor price for the sale of certain notional volumes of crude oil specified in the put option contracts.  The put options grant EOG the right to receive the difference between the put option strike price and the average NYMEX West Texas Intermediate crude oil price for the contract month (Index Price), in the event the Index Price is below the put option strike price.  If the Index Price is above the put option strike price, EOG is only required to pay the put option premium.

Natural Gas Price Swap 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 1, 2015 through July 31, 2015 (closed)

275,000

3.98

August 1, 2015 through November 30, 2015 (closed)

175,000

4.51

December 2015

175,000

4.51

(2)

EOG has entered into natural gas price swap contracts which give counterparties the option of entering into price swap 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 price swap contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for the month of December 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

NYMEX        New York Mercantile Exchange

 

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, complete and equip 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

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

 

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.

Fourth Quarter and Full Year 2015 Forecast and Benchmark Commodity Pricing

     (a)  Fourth Quarter and Full Year 2015 Forecast

The forecast items for the fourth 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)

4Q 2015

Full Year 2015

Daily Production

     Crude Oil and Condensate Volumes (MBbld)

          United States

274.0

-

280.0

281.8

-

283.3

          Trinidad

0.8

-

1.0

0.8

-

1.0

          Other International

0.0

-

5.0

0.1

-

1.4

               Total

274.8

-

286.0

282.7

-

285.7

     Natural Gas Liquids Volumes (MBbld)

               Total

72.0

-

78.0

75.2

-

76.7

     Natural Gas Volumes (MMcfd)

          United States

840

-

880

881

-

891

          Trinidad

350

-

370

344

-

349

          Other International

24

-

30

29

-

31

               Total

1,214

-

1,280

1,254

-

1,271

     Crude Oil Equivalent Volumes (MBoed)  

          United States

486.0

-

504.7

503.8

-

508.5

          Trinidad

59.1

-

62.7

58.1

-

59.2

          Other International

4.0

-

10.0

4.9

-

6.6

               Total

549.1

-

577.4

566.8

-

574.3

Operating Costs

     Unit Costs ($/Boe)

          Lease and Well

$

5.30

-

$

6.10

$

5.79

-

$

5.99

          Transportation Costs

$

3.80

-

$

4.70

$

4.02

-

$

4.24

          Depreciation, Depletion and Amortization

$

14.50

-

$

15.50

$

15.79

-

$

16.02

Expenses ($MM)

     Exploration, Dry Hole and Impairment (A)

$

140

-

$

160

$

501

-

$

521

     General and Administrative

$

90

-

$

98

$

348

-

$

356

     Gathering and Processing 

$

32

-

$

36

$

139

-

$

143

     Capitalized Interest

$

10

-

$

11

$

43

-

$

44

     Net Interest

$

59

-

$

60

$

233

-

$

234

Taxes Other Than Income (% of Wellhead Revenue)

6.2

%

-

6.6

%

6.5

%

-

6.7

%

Income Taxes

     Effective Rate 

5

%

-

15

%

33

%

-

36

%

     Current Taxes ($MM)

$

15

-

$

30

$

110

-

$

125

Capital Expenditures (Excluding Acquisitions, $MM)

     Exploration and Development, Excluding Facilities

$

3,700

-

$

3,800

     Exploration and Development Facilities

$

725

-

$

775

     Gathering, Processing and Other

$

275

-

$

325

Pricing - (Refer to Benchmark Commodity Pricing in text)

     Crude Oil and Condensate ($/Bbl)

          Differentials

               United States - above (below) WTI

$

(2.00)

-

$

0.00

$

(1.27)

-

$

(0.78)

               Trinidad - above (below) WTI

$

(10.50)

-

$

(9.50)

$

(9.25)

-

$

(9.00)

     Natural Gas Liquids

          Realizations as % of WTI

27

%

-

31

%

29

%

-

30

%

     Natural Gas ($/Mcf)

          Differentials

               United States - above (below) NYMEX Henry Hub

$

(0.90)

-

$

(0.45)

$

(0.71)

-

$

(0.60)

          Realizations

               Trinidad

$

2.40

-

$

2.90

$

2.85

-

$

2.98

               Other International

$

3.25

-

$

3.75

$

4.31

-

$

4.42

(A)  Excludes the impairments of proved oil and gas properties, other property, plant and equipment and other assets in the third quarter of 2015 of $6,213 million.

 

Definitions

$/Bbl        

U.S. Dollars per barrel

$/Boe       

U.S. Dollars per barrel of oil equivalent

$/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.



RELATED LINKS

http://www.eogresources.com