EOG Resources Reports Second Quarter 2015 Results; Increases Potential Bakken Reserves to 1.0 BnBoe

Aug 06, 2015, 16:06 ET from EOG Resources, Inc.

HOUSTON, Aug. 6, 2015 /PRNewswire/ --

  • Increases Returns in All Key Plays with Improved Well Productivity, Lower Costs
  • Maintains 2015 Total Company Oil Production Guidance; Reduces 2015 Capital Spending Guidance by $200 million
  • Announces New Williston Basin Resource Potential
    • ­Increases Bakken and Three Forks Net Reserve Potential by 600 MMBoe to 1.0 BnBoe
    • ­Increases Drilling Inventory to 1,540 Net Wells
    • ­Completes Record Bakken Well with Latest Advanced Completions Technology
  • Exceeds Second Quarter Production Forecast and Reduces Per Unit Lease Operating Costs by 17% Versus First Quarter

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported second quarter 2015 net income of $5.3 million, or $0.01 per share. This compares to second quarter 2014 net income of $706.4 million, or $1.29 per share.

Adjusted non-GAAP net income for the second quarter 2015 was $153.1 million, or $0.28 per share, compared to the same prior year period adjusted non-GAAP net income of $796.0 million, or $1.45 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.)

Higher cash settlements from commodity derivative contracts and lower operating expenses were offset by lower commodity price realizations, resulting in decreases in adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the second quarter 2015 compared to the second quarter 2014. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)

Operational Highlights In the second quarter 2015, total crude oil and condensate production increased by one percent compared to the second quarter 2014, excluding production related to EOG's Canadian operations which were divested in December 2014. On the same basis, overall total company production decreased three percent compared to the same prior year period. Total capital expenditures decreased 40 percent compared to the prior year.

In the second quarter 2015, EOG continued to improve well productivity and reduce completed well costs and operating costs. The integration of the latest high-density completion designs in combination with improved wellbore placement resulted in increased well productivity. EOG achieved significant well and operating cost reductions through operational efficiencies and service cost reductions. The combination of increased well productivity and lower costs is enabling the company to make higher returns at lower oil prices.

"EOG's return-driven culture is responding extremely well to low oil prices, and we are excited about the company's continued improvement," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "The company is generating good returns in all our key assets with $50 oil. Our goal is to continue our progress and remain the industry leader in capital returns."

2015 Capital Plan Update As a result of productivity improvements and cost reductions, EOG is maintaining full year 2015 oil production guidance and reducing full year 2015 capital spending guidance by $200 million, excluding acquisitions. The company is choosing to refrain from growing oil production into an over-supplied market. EOG's focus in 2015 is on capital efficiency to improve returns and quickly transition the company to be successful in a lower commodity price environment.

North Dakota Bakken EOG increased its net resource potential in the Bakken and Three Forks plays in the second quarter 2015 from approximately 400 million barrels of oil equivalent (MMBoe) to 1.0 billion barrels of oil equivalent (BnBoe) and grew total net drillable locations from 580 to 1,540. Successful down-spacing and advances in completion technology have generated excellent well results and led to the expanded resource potential. As a result, EOG has decades of high-return drilling potential ready to be developed.

"Our team's outstanding technical and operational advances have enabled us to more than double prior estimates for our position in the Bakken and Three Forks," said Thomas. "EOG's Bakken and Three Forks assets along with the company's Eagle Ford and Delaware Basin positions continue to grow in both size and quality. With these premier assets, EOG is uniquely positioned for high-return growth in a low oil price environment."

In the second quarter 2015, the company continued to make well productivity gains. EOG completed an industry record Bakken well using enhanced high-density completion techniques. The Riverview 102-32H came on line producing 3,395 barrels of oil per day (Bopd) and 6.0 million cubic feet per day (MMcfd) of rich natural gas.

South Texas Eagle Ford EOG continued to realize strong rates of return and capital efficiencies in the Eagle Ford, EOG's largest play. High-density completions, enhanced wellbore targeting and lower completed well costs are dramatically improving EOG's results across the entire Eagle Ford oil window.

During the second quarter 2015 in the eastern Eagle Ford in Gonzales County, the Otto Unit 3H and 9H, a two-well pattern, had average initial production rates per well of 4,405 Bopd, 515 barrels per day (Bpd) of NGLs and 3.4 MMcfd of natural gas. Also in Gonzales County, the Lefevre Unit 17H – 19H (three-well pattern) had average initial production rates per well of 4,150 Bopd, 405 Bpd of NGLs and 2.7 MMcfd of natural gas.

In McMullen County in the western Eagle Ford, EOG completed the Naylor Jones Unit 11 1H and 2H two-well pattern, which had average initial production rates per well of 3,150 Bopd, 170 Bpd of NGLs and 1.1 MMcfd of natural gas.

Delaware Basin In the Delaware Basin, EOG continued to actively test and develop its positions in the Leonard, the Second Bone Spring Sand and the upper Wolfcamp, as well as significantly reduce completed well costs and operating costs.

In the Leonard, EOG completed the Gem 36 State Com #1H in Lea County, N.M., which had initial production rates of 2,200 Bopd, 460 Bpd of NGLs and 2.6 MMcfd of natural gas.

In the Second Bone Spring Sand, EOG completed several wells with excellent results. In Lea County, N.M., EOG completed the Dragon 36 State #501H and #502H in a two-well pattern, which had average initial production rates per well of 1,415 Bopd, 115 Bpd of NGLs and 0.9 MMcfd of natural gas. Also in Lea County, N.M., EOG completed the Frazier 34 State Com #501H with an initial flow rate of 1,705 Bopd, 145 Bpd of NGLs and 1.1 MMcfd of natural gas.

In the Wolfcamp in Lea County, N.M., EOG completed the Hearns 27 State Com #703H, which had an initial production rate of 2,830 Bopd, 170 Bpd of NGLs and 1.1 MMcfd of natural gas.

Hedging Activity For the period August 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.

For the period September 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 million British thermal units per day at a weighted average price of $4.51 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.)

Capital Structure At June 30, 2015, EOG's total debt outstanding was $6.4 billion for a debt-to-total capitalization ratio of 27 percent. Taking into account cash on the balance sheet of $1.4 billion at June 30, EOG's net debt was $5.0 billion for a net debt-to-total capitalization ratio of 22 percent. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP.)

Conference Call August 7, 2015 EOG's second 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, August 7, 2015. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through August 21, 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

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Net Operating Revenues

$

2,469.7

$

4,187.6

$

4,788.2

$

8,271.2

Net Income (Loss)

$

5.3

$

706.4

$

(164.5)

$

1,367.3

Net Income (Loss) Per Share 

        Basic

$

0.01

$

1.30

$

(0.30)

$

2.52

        Diluted

$

0.01

$

1.29

$

(0.30)

$

2.49

Average Number of Common Shares

        Basic

545.5

543.1

545.2

542.7

        Diluted

549.7

548.7

545.2

548.0

Summary Income Statements

(Unaudited; in thousands, except per share data)

Three Months Ended

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Net Operating Revenues

        Crude Oil and Condensate

$

1,452,756

$

2,618,975

$

2,713,000

$

5,016,077

        Natural Gas Liquids

103,930

247,973

215,920

494,208

        Natural Gas

274,038

509,091

561,820

1,065,784

        Gains (Losses) on Mark-to-Market Commodity

           Derivative Contracts

(48,493)

(229,270)

27,715

(385,006)

        Gathering, Processing and Marketing

678,356

1,027,795

1,248,626

2,043,206

        Gains (Losses) on Asset Dispositions, Net

(5,564)

3,856

(3,957)

15,354

        Other, Net

14,678

9,136

25,115

21,604

               Total

2,469,701

4,187,556

4,788,239

8,271,227

Operating Expenses

        Lease and Well

289,664

346,458

651,145

667,292

        Transportation Costs

209,833

240,579

438,145

483,816

        Gathering and Processing Costs

34,997

32,470

71,006

66,394

        Exploration Costs

43,755

42,208

83,204

90,266

        Dry Hole Costs

(551)

5,558

14,119

13,906

        Impairments 

68,519

39,035

137,955

152,396

        Marketing Costs

670,169

1,043,515

1,308,831

2,049,819

        Depreciation, Depletion and Amortization

909,227

996,602

1,822,015

1,943,093

        General and Administrative

82,324

90,932

166,621

173,794

        Taxes Other Than Income

122,138

205,469

228,567

401,442

               Total

2,430,075

3,042,826

4,921,608

6,042,218

Operating Income (Loss)

39,626

1,144,730

(133,369)

2,229,009

Other Income (Expense), Net

9,380

7,950

(611)

4,612

Income (Loss) Before Interest Expense and Income Taxes

49,006

1,152,680

(133,980)

2,233,621

Interest Expense, Net

60,484

51,867

113,829

102,019

Income (Loss) Before Income Taxes

(11,478)

1,100,813

(247,809)

2,131,602

Income Tax Provision (Benefit)

(16,746)

394,460

(83,329)

764,321

Net Income (Loss)

$

5,268

$

706,353

$

(164,480)

$

1,367,281

Dividends Declared per Common Share

$

0.1675

$

0.1250

$

0.3350

$

0.2500

EOG RESOURCES, INC.

Operating Highlights

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Wellhead Volumes and Prices

Crude Oil and Condensate Volumes (MBbld) (A)

      United States

276.5

274.6

287.5

266.4

      Trinidad

0.7

1.0

0.9

1.0

      Other International (B)

0.3

5.7

0.2

6.5

            Total

277.5

281.3

288.6

273.9

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

      United States

$

57.47

$

102.66

$

51.91

$

101.66

      Trinidad

49.53

94.25

44.03

92.09

      Other International (B)

62.40

94.61

56.67

92.01

            Composite

57.45

102.47

51.89

101.40

Natural Gas Liquids Volumes (MBbld) (A)

      United States

73.4

78.5

75.4

74.7

      Other International (B)

0.1

0.7

0.1

0.7

            Total

73.5

79.2

75.5

75.4

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

      United States

$

15.55

$

34.35

$

15.83

$

36.12

      Other International (B)

7.81

40.90

5.80

44.15

            Composite

15.54

34.41

15.82

36.20

Natural Gas Volumes (MMcfd) (A)

      United States

891

925

898

910

      Trinidad

334

380

336

384

      Other International (B)

32

78

31

74

            Total

1,257

1,383

1,265

1,368

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

      United States

$

2.11

$

4.14

$

2.19

$

4.54

      Trinidad

3.05

3.69

3.07

3.66

      Other International (B)

3.49

4.68

3.39

4.75

            Composite

2.40

4.04

2.45

4.31

Crude Oil Equivalent Volumes (MBoed) (D)

      United States 

498.3

507.2

512.6

492.7

      Trinidad

56.5

64.5

56.8

65.0

      Other International (B)

5.7

19.3

5.5

19.6

            Total

560.5

591.0

574.9

577.3

Total MMBoe (D)

51.0

53.8

104.1

104.5

(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)

June 30,

December 31,

2015

2014

ASSETS

Current Assets

     Cash and Cash Equivalents

$

1,367,395

$

2,087,213

     Accounts Receivable, Net

1,304,848

1,779,311

     Inventories

661,162

706,597

     Assets from Price Risk Management Activities

106,821

465,128

     Income Taxes Receivable

48,448

71,621

     Deferred Income Taxes

39,613

19,618

     Other

209,431

286,533

            Total

3,737,718

5,416,021

Property, Plant and Equipment

     Oil and Gas Properties (Successful Efforts Method)

48,936,092

46,503,532

     Other Property, Plant and Equipment

3,840,210

3,750,958

            Total Property, Plant and Equipment

52,776,302

50,254,490

     Less:  Accumulated Depreciation, Depletion and Amortization

(22,801,124)

(21,081,846)

            Total Property, Plant and Equipment, Net

29,975,178

29,172,644

Other Assets

171,200

174,022

Total Assets

$

33,884,096

$

34,762,687

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

     Accounts Payable

$

1,864,483

$

2,860,548

     Accrued Taxes Payable

164,366

140,098

     Dividends Payable

91,500

91,594

     Deferred Income Taxes

-

110,743

     Current Portion of Long-Term Debt

6,579

6,579

     Other

150,653

174,746

            Total

2,277,581

3,384,308

Long-Term Debt

6,393,885

5,903,354

Other Liabilities

986,758

939,497

Deferred Income Taxes

6,798,629

6,822,946

Commitments and Contingencies

Stockholders' Equity

     Common Stock, $0.01 Par, 640,000,000 Shares Authorized and         549,401,647 Shares Issued at June 30, 2015 and 549,028,374         Shares Issued at December 31, 2014

205,496

205,492

     Additional Paid in Capital

2,857,588

2,837,150

     Accumulated Other Comprehensive Loss

(28,003)

(23,056)

     Retained Earnings

14,414,926

14,763,098

     Common Stock Held in Treasury, 256,101 Shares at June 30, 2015

         and 733,517 Shares at December 31, 2014 

(22,764)

(70,102)

            Total Stockholders' Equity

17,427,243

17,712,582

Total Liabilities and Stockholders' Equity

$

33,884,096

$

34,762,687

EOG RESOURCES, INC.

Summary Statements of Cash Flows

(Unaudited; in thousands)

Six Months Ended

June 30,

2015

2014

Cash Flows from Operating Activities

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

     Net Income (Loss)

$

(164,480)

$

1,367,281

     Items Not Requiring (Providing) Cash

            Depreciation, Depletion and Amortization

1,822,015

1,943,093

            Impairments 

137,955

152,396

            Stock-Based Compensation Expenses

61,650

65,144

            Deferred Income Taxes

(154,803)

479,109

            (Gains) Losses on Asset Dispositions, Net

3,957

(15,354)

            Other, Net

6,787

984

     Dry Hole Costs

14,119

13,906

     Mark-to-Market Commodity Derivative Contracts

            Total (Gains) Losses

(27,715)

385,006

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

561,142

(120,900)

     Excess Tax Benefits from Stock-Based Compensation

(16,393)

(63,759)

     Other, Net

6,346

7,223

     Changes in Components of Working Capital and Other Assets and Liabilities

            Accounts Receivable

298,183

(249,336)

            Inventories

37,609

(109,756)

            Accounts Payable

(999,644)

347,539

            Accrued Taxes Payable

64,124

115,668

            Other Assets

76,114

(141,453)

            Other Liabilities

(48,848)

57,101

     Changes in Components of Working Capital Associated with Investing and Financing         Activities

169,802

(31,644)

Net Cash Provided by Operating Activities

1,847,920

4,202,248

Investing Cash Flows

     Additions to Oil and Gas Properties

(2,611,848)

(3,724,486)

     Additions to Other Property, Plant and Equipment

(201,597)

(402,972)

     Proceeds from Sales of Assets

116,166

74,512

     Changes in Restricted Cash

-

(91,238)

     Changes in Components of Working Capital Associated with Investing Activities

(169,903)

31,620

Net Cash Used in Investing Activities

(2,867,182)

(4,112,564)

Financing Cash Flows

     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

(183,130)

(119,684)

     Excess Tax Benefits from Stock-Based Compensation

16,393

63,759

     Treasury Stock Purchased

(26,362)

(89,524)

     Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 

14,484

10,433

     Debt Issuance Costs

(1,585)

(895)

     Repayment of Capital Lease Obligation

(3,053)

(2,958)

     Other, Net

101

24

Net Cash Provided by (Used in) Financing Activities

307,073

(174,198)

Effect of Exchange Rate Changes on Cash

(7,629)

(3,555)

Decrease in Cash and Cash Equivalents

(719,818)

(88,069)

Cash and Cash Equivalents at Beginning of Period

2,087,213

1,318,209

Cash and Cash Equivalents at End of Period

$

1,367,395

$

1,230,140

 

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 six-month periods ended June 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) losses 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 in North America, 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 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 

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Reported Net Income (Loss) (GAAP)

$

5,268

$

706,353

$

(164,480)

$

1,367,281

Commodity Derivative Contracts Impact

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

48,493

229,270

(27,715)

385,006

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

193,435

(86,867)

561,142

(120,900)

                  Subtotal

241,928

142,403

533,427

264,106

       After-Tax MTM Impact

155,680

91,359

343,260

169,437

Less: Texas Margin Tax Rate Reduction

(19,500)

-

(19,500)

-

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

6,134

(1,663)

5,123

(9,040)

Add:  Severance Costs, Net of Tax

5,473

-

5,473

-

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

-

-

-

36,058

Adjusted Net Income (Non-GAAP)

$

153,055

$

796,049

$

169,876

$

1,563,736

Net Income (Loss) Per Share (GAAP)

       Basic

$

0.01

$

1.30

$

(0.30)

$

2.52

       Diluted

$

0.01

$

1.29

$

(0.30)

$

2.49

Adjusted Net Income Per Share (Non-GAAP)

       Basic

$

0.28

$

1.47

$

0.31

$

2.88

       Diluted

$

0.28

$

1.45

$

0.31

$

2.85

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

-81

%

-89

%

Average Number of Common Shares (GAAP)

       Basic

545,504

543,099

545,245

542,675

       Diluted

549,683

548,676

545,245

548,046

Average Number of Common Shares (Non-GAAP)

       Basic

545,504

543,099

545,245

542,675

       Diluted

549,683

548,676

549,505

548,046

 

EOG RESOURCES, INC.

Quantitative Reconciliation Of Discretionary Cash Flow (Non-GAAP)

To Net Cash Provided By Operating Activities (GAAP)

(Unaudited; in thousands)

The following chart reconciles the three-month and six-month periods ended June 30, 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

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

Net Cash Provided by Operating Activities (GAAP)

$

887,373

$

1,934,575

$

1,847,920

$

4,202,248

Adjustments:

Exploration Costs (excluding Stock-Based Compensation Expenses) 

37,870

36,659

69,967

76,783

Excess Tax Benefits from Stock-Based Compensation

7,535

36,337

16,393

63,759

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

54,917

105,019

(298,183)

249,336

Inventories

(99,781)

40,808

(37,609)

109,756

Accounts Payable

321,769

14,271

999,644

(347,539)

Accrued Taxes Payable

(62,019)

24,133

(64,124)

(115,668)

Other Assets

(16,938)

128,917

(76,114)

141,453

Other Liabilities

16,993

(86,270)

48,848

(57,101)

Changes in Components of Working Capital Associated with Investing and

Financing Activities

90,190

(36,639)

(169,802)

31,644

Discretionary Cash Flow (Non-GAAP)

$

1,237,909

$

2,197,810

$

2,336,940

$

4,354,671

Discretionary Cash Flow (Non-GAAP) - Percentage Decrease

-44

%

-46

%

 

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 six-month periods ended June 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) losses from these transactions and to eliminate the net (gains) losses on asset dispositions in North America.  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

Six Months Ended

June 30,

June 30,

2015

2014

2015

2014

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

$

49,006

$

1,152,680

$

(133,980)

$

2,233,621

Adjustments:

     Depreciation, Depletion and Amortization

909,227

996,602

1,822,015

1,943,093

     Exploration Costs

43,755

42,208

83,204

90,266

     Dry Hole Costs

(551)

5,558

14,119

13,906

     Impairments 

68,519

39,035

137,955

152,396

             EBITDAX (Non-GAAP)

1,069,956

2,236,083

1,923,313

4,433,282

     Total (Gains) Losses on MTM Commodity Derivative

            Contracts  

48,493

229,270

(27,715)

385,006

     Net Cash Received from (Payments for) Settlements of

            Commodity Derivative Contracts

193,435

(86,867)

561,142

(120,900)

     (Gains) Losses on Asset Dispositions, Net

5,564

(3,856)

3,957

(15,354)

Adjusted EBITDAX (Non-GAAP)

$

1,317,448

$

2,374,630

$

2,460,697

$

4,682,034

Adjusted EBITDAX (Non-GAAP) - Percentage Decrease

-45

%

-47

%

 

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

June 30,

December 31,

2015

2014

Total Stockholders' Equity - (a)

$

17,427

$

17,713

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

6,400

5,910

Less: Cash 

(1,367)

(2,087)

Net Debt (Non-GAAP) - (c)

5,033

3,823

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

$

23,827

$

23,623

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

$

22,460

$

21,536

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

27

%

25

%

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

22

%

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 August 6, 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

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

47,000

$

91.22

July 2015 (closed)

10,000

89.98

August 1, 2015 through December 31, 2015

10,000

89.98

Natural Gas Derivative Contracts

Weighted

Volume

Average Price

(MMBtud) 

($/MMBtu) 

2015(1)

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 (closed)

275,000

3.97

July 2015 (closed)

275,000

3.98

August 2015 (closed)

175,000

4.51

September 1, 2015 through December 31, 2015

175,000

4.51

(1)

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 September 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, 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.

Third Quarter and Full Year 2015 Forecast and Benchmark Commodity Pricing

     (a)  Third Quarter and Full Year 2015 Forecast

The forecast items for the third 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)

3Q 2015

Full Year 2015

Daily Production

     Crude Oil and Condensate Volumes (MBbld)

          United States

269.0

-

277.0

279.2

-

284.2

          Trinidad

0.6

-

0.8

0.7

-

0.9

          Other International

0.1

-

0.3

4.0

-

6.5

               Total

269.7

-

278.1

283.9

-

291.6

     Natural Gas Liquids Volumes (MBbld)

               Total

72.0

-

77.0

74.0

-

77.0

     Natural Gas Volumes (MMcfd)

          United States

845

-

885

870

-

890

          Trinidad

330

-

360

330

-

345

          Other International

27

-

32

28

-

30

               Total

1,202

-

1,277

1,228

-

1,265

     Crude Oil Equivalent Volumes (MBoed)  

          United States

481.8

-

501.5

498.2

-

509.5

          Trinidad

55.6

-

60.8

55.7

-

58.4

          Other International

4.6

-

5.6

8.7

-

11.5

               Total

542.0

-

567.9

562.6

-

579.4

Operating Costs

     Unit Costs ($/Boe)

          Lease and Well

$

5.70

-

$

6.60

$

6.00

-

$

6.40

          Transportation Costs

$

4.30

-

$

4.70

$

4.30

-

$

4.50

          Depreciation, Depletion and Amortization

$

17.60

-

$

18.00

$

17.70

-

$

17.90

Expenses ($MM)

     Exploration, Dry Hole and Impairment

$

140

-

$

160

$

515

-

$

555

     General and Administrative

$

90

-

$

100

$

345

-

$

370

     Gathering and Processing 

$

32

-

$

36

$

135

-

$

145

     Capitalized Interest

$

10

-

$

11

$

42

-

$

45

     Net Interest

$

59

-

$

60

$

230

-

$

235

Taxes Other Than Income (% of Wellhead Revenue)

6.5

%

-

7.0

%

6.5

%

-

6.7

%

Income Taxes

     Effective Rate 

25

%

-

35

%

25

%

-

35

%

     Current Taxes ($MM)

$

60

-

$

75

$

175

-

$

200

Capital Expenditures (Excluding Acquisitions, $MM)

     Exploration and Development, Excluding Facilities

$

3,700

-

$

3,800

     Exploration and Development Facilities

$

670

-

$

710

     Gathering, Processing and Other

$

330

-

$

390

Pricing - (Refer to Benchmark Commodity Pricing in text)

     Crude Oil and Condensate ($/Bbl)

          Differentials

               United States - above (below) WTI

$

(1.60)

-

$

0.40

$

(1.70)

-

$

(0.70)

               Trinidad - above (below) WTI

$

(10.50)

-

$

(9.50)

$

(10.00)

-

$

(9.25)

     Natural Gas Liquids

          Realizations as % of WTI

24

%

-

28

%

27

%

-

29

%

     Natural Gas ($/Mcf)

          Differentials

               United States - above (below) NYMEX Henry Hub

$

(0.80)

-

$

(0.35)

$

(0.75)

-

$

(0.45)

          Realizations

               Trinidad

$

2.75

-

$

3.25

$

2.90

-

$

3.15

               Other International

$

3.25

-

$

3.75

$

3.35

-

$

3.55

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.



RELATED LINKS

http://www.eogresources.com