Market Overview

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

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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

 

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/eog-resources-reports-third-quarter-2015-results-increases-delaware-basin-net-resource-potential-by-10-bnboe-300173633.html

SOURCE EOG Resources, Inc.

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