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EOG Resources Reports Fourth Quarter and Full Year 2016 Results and Announces 2017 Capital Program

HOUSTON, Feb. 27, 2017 /PRNewswire/ -- 

  • Exceeds High-end of Fourth Quarter and Full Year 2016 Crude Oil Production Targets
  • Beats Fourth Quarter and Full Year 2016 Targets for Lease and Well, Transportation and DD&A Expenses
  • Achieves Record Capital Efficiency Gains in 2016
  • Replaces 163 Percent of 2016 Production at Low Finding Cost of $5.22/Boe (Excluding Price Revisions) and Increases Total Net Proved Reserves by 1.4 Percent in 2016
  • Targets 18 Percent Crude Oil Production Growth for 2017 within Cash Flow at Flat $50 Oil
  • Forecasts Flat to Lower Well Costs in 2017

EOG Resources, Inc. (EOG) (EOG) today reported a fourth quarter 2016 net loss of $142.4 million, or $0.25 per share. This compares to a fourth quarter 2015 net loss of $284.3 million, or $0.52 per share.  For full year 2016, EOG reported a net loss of $1.1 billion, or $1.98 per share, compared to a net loss of $4.5 billion, or $8.29 per share, for the full year 2015. 

Adjusted non-GAAP net loss for the fourth quarter 2016 was $6.7 million, or $0.01 per share, compared to adjusted non-GAAP net loss of $149.5 million, or $0.27 per share, for the same prior year period.  Adjusted non-GAAP net loss for the full year 2016 was $892.6 million, or $1.61 per share, compared to adjusted non-GAAP net income of $33.9 million, or $0.06 per share, for the full year 2015.  Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring and certain other items.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Higher crude oil, NGL and natural gas prices, significant well productivity improvements, and lease and well cost reductions resulted in increases in adjusted non-GAAP net income, discretionary cash flow and EBITDAX for the fourth quarter 2016 compared to the fourth quarter 2015.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Operational Highlights
Tremendous capital efficiency improvements in 2016 offset the impact of a significant reduction in capital expenditures resulting from low oil prices.  2016 total company crude oil and condensate volumes declined less than one percent to 282,500 barrels of oil per day (Bopd) while exploration and development expenditures (excluding acquisitions) decreased 42 percent compared to 2015.  Increased development activity and significant well productivity improvements drove substantial volume increases in the Delaware Basin, with additional growth from the Powder River and DJ Basins.  These contributions were offset by volume declines in the Bakken and Eagle Ford resulting from lower activity levels.  Natural gas liquids volumes grew 6 percent while natural gas volumes decreased 7 percent primarily due to natural decline and the sale of the company's Barnett and Haynesville Shale dry gas assets.  Compared to the same prior year period, lease and well expenses decreased 20 percent and transportation expenses decreased 8 percent, both on a per-unit basis.  Total operating costs, which includes lease and well, transportation, gathering and processing, and general and administrative expenses, were down 15 percent year over year.

"EOG achieved near company-record returns on new capital in 2016 in spite of the lowest crude oil prices in 13 years," said William R. "Bill" Thomas, Chairman and Chief Executive Officer.  "Through continued improvements in well productivity, cost reductions and expanded resource potential, EOG is positioned to excel as crude oil prices continue to recover.  More than ever, EOG continues to lead the industry through its innovative technology and disciplined culture."

2017 Capital Plan
EOG's 2017 plan is designed to maximize returns and grow crude oil volumes while maintaining a strong balance sheet through disciplined spending.  EOG expects to grow total company crude oil volumes by 18 percent, assuming investment and dividend payments within cash flow at a $50 average oil price.

Capital expenditures for 2017 are expected to range from $3.7 to $4.1 billion, including production facilities and gathering, processing and other expenditures, and excluding acquisitions.  The company expects to complete approximately 480 net wells in 2017, compared to 445 net wells in 2016.  EOG anticipates flat to lower completed well costs in 2017 versus 2016 levels as continued efficiencies and service contract expirations are expected to offset potential cost increases.

Capital will be allocated primarily to EOG's highest rate-of-return oil assets in the Eagle Ford, Delaware Basin, Rockies and the Bakken.  After reducing the drilled uncompleted well inventory to a normal operating level in 2016, the company will increase its focus on its 6,000 remaining premium drilling locations.  EOG is capable of delivering very strong rates of return in the current commodity price environment through premium drilling combined with the company's expectations that well costs will remain flat or lower in 2017.  Premium inventory includes wells with a direct after-tax rate of return of at least 30 percent assuming $40 flat crude oil prices.

"EOG's goal during the last two years was to exit the industry downturn in better shape than when we entered it," Thomas said.  "We clearly accomplished that goal with spectacular improvements in all facets of the business.  We made major technology advances in our proprietary well targeting, completion designs, drilling practices and production operations.  EOG is now set to resume strong oil growth within cash flow." 

Delaware Basin
In the fourth quarter 2016, EOG continued active development of its world-class position in the Delaware Basin.  EOG integrated the assets acquired in the Yates transaction and further optimized its proprietary well targeting methods across its expanded position of 416,000 net acres.

EOG completed 17 wells in the Delaware Basin Wolfcamp in the fourth quarter with an average treated lateral length of 4,900 feet per well and average 30-day initial production rates per well of 2,405 barrels of oil equivalent per day (Boed), or 1,595 Bopd, 365 barrels per day (Bpd) of natural gas liquids (NGLs) and 2.7 million cubic feet per day (MMcfd) of natural gas.  In Lea County, N.M., EOG completed the Endurance 36 State Com #705H and #706H with an average treated lateral length of 7,000 feet per well and average 30-day initial production rates per well of 2,495 Bopd, 505 Bpd of NGLs and 3.7 MMcfd of natural gas.

In the Delaware Basin Bone Spring, EOG completed three wells in the fourth quarter with an average treated lateral length of 4,400 feet per well and average 30-day initial production rates per well of 1,680 Boed, or 1,280 Bopd, 180 Bpd of NGLs and 1.3 MMcfd of natural gas.  In Lea County, N.M., EOG completed the Della 29 Fed Com #602H with a treated lateral of 4,500 feet and 30-day initial production rates of 1,905 Bopd, 225 Bpd of NGLs and 1.7 MMcfd of natural gas.  This well is six miles north of EOG's next closest Bone Spring well.

In the Delaware Basin Leonard, EOG completed eight wells in the fourth quarter with an average treated lateral length of 4,600 feet per well and average 30-day initial production rates per well of 1,745 Boed, or 985 Bopd, 345 Bpd of NGLs and 2.5 MMcfd of natural gas.  In Lea County, N.M., EOG completed the Leghorn 32 State #201H with a treated lateral of 4,500 feet and 30-day initial production rates of 2,550 Bopd, 480 Bpd of NGLs and 3.6 MMcfd of natural gas.  This well is 12 miles north of EOG's next closest Leonard well.

South Texas Eagle Ford
EOG continued to achieve strong well results and efficiencies in the South Texas Eagle Ford in the fourth quarter 2016.  For the full year 2016, crude oil production declined just 8 percent year-over-year, despite a 28 percent reduction in the number of well completions.

In the fourth quarter, EOG completed 75 wells in the Eagle Ford with an average treated lateral length of 5,700 feet per well and average 30-day initial production rates per well of 1,190 Boed, or 990 Bopd, 85 Bpd of NGLs and 0.7 MMcfd of natural gas.  The fourth quarter 2016 completions in the Eagle Ford included 45 wells that were drilled prior to 2016.

South Texas Austin Chalk
EOG continued to test its position in the South Texas Austin Chalk, which lies above the South Texas Eagle Ford.  In the fourth quarter, EOG completed nine wells in the Austin Chalk with an average treated lateral length of 4,100 feet per well and average 30-day initial production rates per well of 1,975 Boed, or 1,475 Bopd, 220 Bpd of NGLs and 1.7 MMcfd of natural gas.

Rockies and the Bakken
During the fourth quarter, EOG significantly reduced its inventory of drilled uncompleted wells in the Rockies and the Bakken.       

In the Powder River Basin, EOG completed three wells in the fourth quarter with average 30-day initial production rates per well of 2,155 Boed, or 1,810 Bopd, 135 Bpd of NGLs and 1.3 MMcfd of natural gas. 

In the North Dakota Bakken, EOG completed 34 wells in the fourth quarter with average 30-day initial production rates per well of 820 Boed, or 715 Bopd, 55 Bpd of NGLs and 0.3 MMcfd of natural gas.  The fourth quarter 2016 completions in the Bakken included 31 wells that were drilled prior to 2016.

Reserves
At year-end 2016, total company net proved reserves were 2,147 million barrels of oil equivalent (MMBoe), comprised of 55 percent crude oil and condensate, 19 percent NGLs and 26 percent natural gas.  Net proved reserve additions from all sources excluding revisions due to price replaced 163 percent of EOG's 2016 production at a finding and development cost of $5.22 per barrel of oil equivalent.  Revisions due to price reduced net proved reserves by 101 MMBoe and asset divestitures decreased net proved reserves by 168 MMBoe.  Total company net proved reserves increased 1.4 percent in 2016 as proved reserve additions from drilling activities and revisions other than price offset the impact of asset divestitures and declines in commodity prices.  (For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.)

For the 29th consecutive year, internal reserves estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.

Hedging Activity
For the period January 1 through June 30, 2017, EOG has crude oil financial price swap contracts in place for 35,000 Bopd at a weighted average price of $50.04 per barrel. 

For the period March 1 through November 30, 2017, EOG has natural gas financial price swap contracts in place for 30,000 million British thermal units (MMBtu) per day at a weighted average price of $3.10 per MMBtu.  For the period March 1 through November 30, 2018, EOG has natural gas financial price swap contracts in place for 35,000 MMBtu per day at a weighted average price of $3.00 per MMBtu.

For the period March 1 through November 30, 2017, EOG sold natural gas call option contracts for 213,750 MMBtu per day at an average strike price of $3.44 per MMBtu.  For the period March 1 through November 30, 2018, EOG sold natural gas call option contracts for 120,000 MMBtu per day at an average strike price of $3.38 per MMBtu.

For the period March 1 through November 30, 2017, EOG purchased natural gas put option contracts for 171,000 MMBtu per day at an average strike price of $2.92 per MMBtu.  For the period March 1 through November 30, 2018, EOG purchased natural gas put option contracts for 96,000 MMBtu per day at an average strike price of $2.94 per MMBtu.   

For the period March 1 through November 30, 2017, EOG has natural gas collar contracts for 80,000 MMBtu per day at an average ceiling price of $3.69 per MMBtu and an average floor price of $3.20 per MMBtu.     

A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.  

Capital Structure and Asset Sales
At December 31, 2016, EOG's total debt outstanding was $7.0 billion with a debt-to-total capitalization ratio of 33 percent. Considering cash on the balance sheet of $1.6 billion at the end of the fourth quarter, EOG's net debt was $5.4 billion with a net debt-to-total capitalization ratio of 28 percent.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Proceeds from asset sales for the full year 2016 totaled $1.1 billion, which includes $662 million of proceeds from sales made during the fourth quarter 2016.  Associated production of the divested assets in 2016 at the time of each respective sale was an aggregate 220 MMcfd of natural gas, 4,000 Bopd and 8,800 Bpd of NGLs (this was partially offset by the full year impact of acquired production from the Yates transaction of 2,900 Bopd, 150 Bpd of NGLs and 20 MMcfd of natural gas).

Dividend
The board of directors declared a dividend of $0.1675 per share on EOG's Common Stock, payable April 28, 2017, to stockholders of record as of April 13, 2017.  The indicated annual rate is $0.67 per share.

Conference Call February 28, 2017
EOG's fourth quarter and full year 2016 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Tuesday, February 28, 2017.  To access the live audio webcast and related presentation materials, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.  

EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China.  EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."  For additional information about EOG, please visit www.eogresources.com.

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, costs and asset sales, 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, reduce or otherwise control operating and capital costs, 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, supplies of, 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 maximize 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 and condensate, natural gas liquids, 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 the acquisition of licenses, leases and properties, 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 to which EOG is successful in its completion of planned asset dispositions;
  • 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 22 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, 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 duration and 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, 2016, 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


W. John Wagner


(713) 571-4404




Media and Investors


Kimberly M. Ehmer


(713) 571-4676

 

EOG RESOURCES, INC.

Financial Report

(Unaudited; in millions, except per share data)














Three Months Ended


Twelve Months Ended


December 31,


December 31,


2016


2015


2016


2015













Net Operating Revenues

$

2,402.0


$

1,796.8


$

7,650.6


$

8,757.4

Net Loss

$

(142.4)


$

(284.3)


$

(1,096.7)


$

(4,524.5)

Net Loss Per Share 












        Basic

$

(0.25)


$

(0.52)


$

(1.98)


$

(8.29)

        Diluted

$

(0.25)


$

(0.52)


$

(1.98)


$

(8.29)

Average Number of Common Shares












        Basic


567.3



546.4



553.4



545.7

        Diluted


567.3



546.4



553.4



545.7

























Summary Income Statements

(Unaudited; in thousands, except per share data)














Three Months Ended


Twelve Months Ended


December 31,


December 31,


2016


2015


2016


2015

Net Operating Revenues








        Crude Oil and Condensate

$

1,366,223


$

1,040,470


$

4,317,341


$

4,934,562

        Natural Gas Liquids


137,849



96,521



437,250



407,658

        Natural Gas


215,373



217,381



742,152



1,061,038

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


(65,787)



4,970



(99,608)



61,924

        Gathering, Processing and Marketing


614,594



432,292



1,966,259



2,253,135

        Gains (Losses) on Asset Dispositions, Net


104,034



(3,656)



205,835



(8,798)

        Other, Net


29,753



8,783



81,403



47,909

               Total


2,402,039



1,796,761



7,650,632



8,757,428

Operating Expenses












        Lease and Well


241,846



247,916



927,452



1,182,282

        Transportation Costs


193,319



207,580



764,106



849,319

        Gathering and Processing Costs


32,516



39,653



122,901



146,156

        Exploration Costs


39,110



34,946



124,953



149,494

        Dry Hole Costs


193



429



10,657



14,746

        Impairments 


297,946



168,171



620,267



6,613,546

        Marketing Costs


634,248



461,848



2,007,635



2,385,982

        Depreciation, Depletion and Amortization


862,524



769,457



3,553,417



3,313,644

        General and Administrative


102,182



109,014



394,815



366,594

        Taxes Other Than Income


103,642



87,500



349,710



421,744

               Total


2,507,526



2,126,514



8,875,913



15,443,507













Operating Loss


(105,487)



(329,753)



(1,225,281)



(6,686,079)













Other (Expense) Income, Net


(17,198)



(6,080)



(50,543)



1,916













Loss Before Interest Expense and Income Taxes


(122,685)



(335,833)



(1,275,824)



(6,684,163)













Interest Expense, Net


71,325



62,993



281,681



237,393













Loss Before Income Taxes


(194,010)



(398,826)



(1,557,505)



(6,921,556)













Income Tax Benefit


(51,658)



(114,530)



(460,819)



(2,397,041)













Net Loss

$

(142,352)


$

(284,296)


$

(1,096,686)


$

(4,524,515)













Dividends Declared per Common Share

$

0.1675


$

0.1675


$

0.6700


$

0.6700

 


EOG RESOURCES, INC.

Operating Highlights

(Unaudited)














Three Months Ended


Twelve Months Ended


December 31,


December 31,


2016


2015


2016


2015

Wellhead Volumes and Prices




Crude Oil and Condensate Volumes (MBbld) (A)




      United States


306.0



279.9



278.3



283.3

      Trinidad


0.9



0.9



0.8



0.9

      Other International (B)


4.8



0.2



3.4



0.2

            Total


311.7



281.0



282.5



284.4













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












      United States

$

47.93


$

40.34


$

41.84


$

47.55

      Trinidad


40.04



32.38



33.76



39.51

      Other International (B)


38.96



53.28



36.72



57.32

            Composite


47.76



40.32



41.76



47.53













Natural Gas Liquids Volumes (MBbld) (A)












      United States


80.9



79.1



81.6



76.9

      Other International (B)


-



-



-



0.1

            Total


80.9



79.1



81.6



77.0













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












      United States

$

18.51


$

13.25


$

14.63


$

14.50

      Other International (B)


-



-



-



4.61

            Composite


18.51



13.25



14.63



14.49













Natural Gas Volumes (MMcfd) (A)












      United States


800



860



810



886

      Trinidad


323



370



340



349

      Other International (B)


22



27



25



30

            Total


1,145



1,257



1,175



1,265













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












      United States

$

2.05


$

1.44


$

1.60


$

1.97

      Trinidad


1.89



2.57



1.88



2.89

      Other International (B)


3.85



6.51



3.64



5.05

            Composite


2.04



1.88



1.73



2.30













Crude Oil Equivalent Volumes (MBoed) (D)












      United States 


520.3



502.2



494.9



507.9

      Trinidad


54.6



62.7



57.5



59.1

      Other International (B)


8.6



4.6



7.6



5.2

            Total


583.5



569.5



560.0



572.2













Total MMBoe (D)


53.7



52.4



205.0



208.9













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

(B) Other International includes EOG's United Kingdom, China, Canada and Argentina operations.  The Argentina operations were sold in the third quarter of 2016.

(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)








December 31,


December 31,


2016


2015

ASSETS

Current Assets






     Cash and Cash Equivalents

$

1,599,895


$

718,506

     Accounts Receivable, Net


1,216,320



930,610

     Inventories


350,017



598,935

     Income Taxes Receivable


12,305



40,704

     Deferred Income Taxes


169,387



147,812

     Other


206,679



155,677

            Total


3,554,603



2,592,244







Property, Plant and Equipment






     Oil and Gas Properties (Successful Efforts Method)


49,592,091



50,613,241

     Other Property, Plant and Equipment


4,008,564



3,986,610

            Total Property, Plant and Equipment


53,600,655



54,599,851

     Less:  Accumulated Depreciation, Depletion and Amortization


(27,893,577)



(30,389,130)

            Total Property, Plant and Equipment, Net


25,707,078



24,210,721

Other Assets


197,752



167,505

Total Assets

$

29,459,433


$

26,970,470







LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities






     Accounts Payable

$

1,511,826


$

1,471,953

     Accrued Taxes Payable


118,411



93,618

     Dividends Payable


96,120



91,546

     Liabilities from Price Risk Management Activities


61,817



-

     Current Portion of Long-Term Debt


6,579



6,579

     Other


232,538



155,591

            Total


2,027,291



1,819,287













Long-Term Debt


6,979,779



6,648,911

Other Liabilities


1,282,142



971,335

Deferred Income Taxes


5,188,640



4,587,902

Commitments and Contingencies












Stockholders' Equity






     Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
        576,950,272 Shares and 550,150,823 Shares Issued at December 31,
        2016 and 2015, respectively


205,770



205,502

     Additional Paid in Capital


5,420,385



2,923,461

     Accumulated Other Comprehensive Loss


(19,010)



(33,338)

     Retained Earnings


8,398,118



9,870,816

     Common Stock Held in Treasury, 250,155 Shares and 292,179 Shares at
        December 31, 2016 and 2015, respectively


(23,682)



(23,406)

            Total Stockholders' Equity


13,981,581



12,943,035

Total Liabilities and Stockholders' Equity

$

29,459,433


$

26,970,470

 

EOG RESOURCES, INC.

Summary Statements of Cash Flows

(Unaudited; in thousands)








Twelve Months Ended


December 31,


2016


2015

Cash Flows from Operating Activities






Reconciliation of Net Loss to Net Cash Provided by Operating Activities:






     Net Loss

$

(1,096,686)


$

(4,524,515)

     Items Not Requiring (Providing) Cash






            Depreciation, Depletion and Amortization


3,553,417



3,313,644

            Impairments 


620,267



6,613,546

            Stock-Based Compensation Expenses


128,090



130,577

            Deferred Income Taxes


(515,206)



(2,482,307)

            (Gains) Losses on Asset Dispositions, Net


(205,835)



8,798

            Other, Net


61,690



11,896

     Dry Hole Costs


10,657



14,746

     Mark-to-Market Commodity Derivative Contracts






            Total Losses (Gains)


99,608



(61,924)

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


(22,219)



730,114

     Excess Tax Benefits from Stock-Based Compensation


(29,357)



(26,058)

     Other, Net


10,971



12,532

     Changes in Components of Working Capital and Other Assets and Liabilities






            Accounts Receivable


(232,799)



641,412

            Inventories


170,694



58,450

            Accounts Payable


(74,048)



(1,409,197)

            Accrued Taxes Payable


92,782



11,798

            Other Assets


(40,636)



118,143

            Other Liabilities


(16,225)



(66,257)

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


(156,102)



499,767

Net Cash Provided by Operating Activities


2,359,063



3,595,165







Investing Cash Flows






     Additions to Oil and Gas Properties


(2,489,756)



(4,725,150)

     Additions to Other Property, Plant and Equipment


(93,039)



(288,013)

     Proceeds from Sales of Assets


1,119,215



192,807

     Net Cash Received from Yates Acquisition


54,534



-

     Changes in Components of Working Capital Associated with Investing Activities


156,102



(499,900)

Net Cash Used in Investing Activities


(1,252,944)



(5,320,256)







Financing Cash Flows






     Net Commercial Paper (Repayments) Borrowings


(259,718)



259,718

     Long-Term Debt Borrowings


991,097



990,225

     Long-Term Debt Repayments


(563,829)



(500,000)

     Dividends Paid


(372,845)



(367,005)

     Excess Tax Benefits from Stock-Based Compensation


29,357



26,058

     Treasury Stock Purchased


(82,125)



(48,791)

     Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 


23,296



22,690

     Debt Issuance Costs


(1,602)



(5,951)

     Repayment of Capital Lease Obligation


(6,353)



(6,156)

     Other, Net


-



133

Net Cash (Used in) Provided by Financing Activities


(242,722)



370,921







Effect of Exchange Rate Changes on Cash


17,992



(14,537)







Increase (Decrease) in Cash and Cash Equivalents


881,389



(1,368,707)

Cash and Cash Equivalents at Beginning of Period


718,506



2,087,213

Cash and Cash Equivalents at End of Period

$

1,599,895


$

718,506







 

EOG RESOURCES, INC.

Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP)

To Net Loss (GAAP)

(Unaudited; in thousands, except per share data)

































The following chart adjusts the three-month and twelve-month periods ended December 31, 2016 and 2015 reported Net Loss (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2016 and 2015, to add back impairment charges related to certain of EOG's assets in 2016 and 2015, to add back an early leasehold termination payment as the result of a legal settlement in 2015, to eliminate the impact of the Texas margin tax rate reduction in 2015, to add back severance costs associated with EOG's North American operations in 2015, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, and to add back acquisition costs and state apportionment change related to the Yates transaction in 2016.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.


















Three Months Ended 


Three Months Ended 


December 31, 2016


December 31, 2015




















Income




Diluted




Income




Diluted


Before


Tax


After


Earnings


Before


Tax


After


Earnings


Tax


Impact


Tax


per Share


Tax


Impact


Tax


per Share

Reported Net Loss (GAAP)

$   (194,010)


$  51,658


$   (142,352)


$     (0.25)


$   (398,826)


$   114,530


$   (284,296)


$     (0.52)

Adjustments:
















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

65,787


(23,583)


42,204


0.07


(4,970)


1,772


(3,198)


(0.01)

Net Cash Received from Settlements of
     Commodity Derivative Contracts

-


29


29


-


69,093


(24,632)


44,461


0.08

Add: Net (Gains) Losses on Asset Dispositions

(104,034)


36,856


(67,178)


(0.12)


3,656


(735)


2,921


0.01

Add:  Impairments

217,839


(76,728)


141,111


0.25


94,484


(16,335)


78,149


0.15

Add:  Legal Settlement - Early Leasehold Termination

-


-


-


-


19,355


(6,900)


12,455


0.02

Add:  Voluntary Retirement Expense

-


(57)


(57)


-


-


-


-


-

Add:  Acquisition - State Apportionment Change

-


16,424


16,424


0.03


-


-


-


-

Add:  Acquisition Costs

2,173


955


3,128


0.01


-


-


-


-

Adjustments to Net Income (Loss)

181,765


(46,104)


135,661


0.24


181,618


(46,830)


134,788


0.25

















Adjusted Net Income (Loss) (Non-GAAP)

$     (12,245)


$    5,554


$      (6,691)


$     (0.01)


$   (217,208)


$     67,700


$   (149,508)


$     (0.27)

















Average Number of Common Shares (GAAP)
















       Basic







567,337








546,432

       Diluted







567,337








546,432

















Average Number of Common Shares (Non-GAAP)
















      Basic







567,337








546,432

      Diluted







567,337








546,432


































Twelve Months Ended 


Twelve Months Ended 


December 31, 2016


December 31, 2015




















Income




Diluted




Income




Diluted


Before


Tax


After


Earnings


Before


Tax


After


Earnings


Tax


Impact


Tax


per Share


Tax


Impact


Tax


per Share

Reported Net Loss (GAAP)

$(1,557,505)


$460,819


$(1,096,686)


$     (1.98)


$(6,921,556)


$2,397,041


$(4,524,515)


$     (8.29)

Adjustments:
















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

99,608


(35,640)


63,968


0.12


(61,924)


22,076


(39,848)


(0.07)

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

(22,219)


7,950


(14,269)


(0.03)


730,114


(260,286)


469,828


0.86

Add: Net (Gains) Losses on Asset Dispositions

(205,835)


61,491


(144,344)


(0.26)


8,798


(4,183)


4,615


0.01

Add:  Impairments

320,617


(113,368)


207,249


0.37


6,307,592


(2,182,220)


4,125,372


7.56

Add:  Legal Settlement - Early Leasehold Termination

-


-


-


-


19,355


(6,900)


12,455


0.02

Less: Texas Margin Tax Rate Reduction

-


-


-


-


-


(19,500)


(19,500)


(0.04)

Add:  Severance Costs

-


-


-


-


8,505


(3,032)


5,473


0.01

Add:  Trinidad Tax Settlement

-


43,000


43,000


0.08


-


-


-


-

Add:  Voluntary Retirement Expense

42,054


(15,047)


27,007


0.05


-


-


-


-

Add:  Acquisition - State Apportionment Change

-


16,424


16,424


0.03


-


-


-


-

Add:  Acquisition Costs

5,100


(88)


5,012


0.01


-


-


-


-

Adjustments to Net Income (Loss)

239,325


(35,278)


204,047


0.37


7,012,440


(2,454,045)


4,558,395


8.35

















Adjusted Net Income (Loss) (Non-GAAP)

$(1,318,180)


$425,541


$   (892,639)


$     (1.61)


$      90,884


$    (57,004)


$      33,880


$      0.06

















Average Number of Common Shares (GAAP)
















       Basic







553,384








545,697

       Diluted







553,384








545,697

















Average Number of Common Shares (Non-GAAP)
















      Basic







553,384








545,697

      Diluted







553,384








549,610

 

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 twelve-month periods ended December 31, 2016 and 2015 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


Twelve Months Ended



December 31,


December 31,



2016


2015


2016


2015














Net Cash Provided by Operating Activities (GAAP)

$

804,745


$

615,813


$

2,359,063


$

3,595,165














Adjustments:













Exploration Costs (excluding Stock-Based Compensation Expenses) 



33,931



28,758



104,199



124,011

Excess Tax Benefits from Stock-Based Compensation



7,286



1,839



29,357



26,058

Changes in Components of Working Capital and Other Assets













and Liabilities













Accounts Receivable



220,939



(193,101)



232,799



(641,412)

Inventories



(33,131)



(31,443)



(170,694)



(58,450)

Accounts Payable



(127,165)



98,986



74,048



1,409,197

Accrued Taxes Payable



21,214



65,777



(92,782)



(11,798)

Other Assets



28,110



28,822



40,636



(118,143)

Other Liabilities



53,024



50,574



16,225



66,257

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



36,342



19,436



156,102



(499,767)


Discretionary Cash Flow (Non-GAAP)


$

1,045,295


$

685,461


$

2,748,953


$

3,891,118














Discretionary Cash Flow (Non-GAAP) - Percentage Increase/Decrease



52%






-29%




 

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 Net Loss (GAAP)

(Unaudited; in thousands)













The following chart adjusts the three-month and twelve-month periods ended December 31, 2016 and 2015 reported Net Loss (GAAP) to Earnings Before Interest Expense, Income Taxes (Income Tax Benefit), 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.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense, Income Taxes (Income Tax Benefit), 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 and certain other items.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.














Three Months Ended


Twelve Months Ended


December 31,


December 31,


2016


2015


2016


2015













Net Loss (GAAP)

$

(142,352)


$

(284,296)


$

(1,096,686)


$

(4,524,515)













Adjustments:












     Interest Expense, Net


71,325



62,993



281,681



237,393

     Income Tax Benefit


(51,658)



(114,530)



(460,819)



(2,397,041)

     Depreciation, Depletion and Amortization


862,524



769,457



3,553,417



3,313,644

     Exploration Costs


39,110



34,946



124,953



149,494

     Dry Hole Costs


193



429



10,657



14,746

     Impairments 


297,946



168,171



620,267



6,613,546

             EBITDAX (Non-GAAP)


1,077,088



637,170



3,033,470



3,407,267

     Total (Gains) Losses on MTM Commodity Derivative Contracts  


65,787



(4,970)



99,608



(61,924)

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


-



69,093



(22,219)



730,114

     (Gains) Losses on Asset Dispositions, Net


(104,034)



3,656



(205,835)



8,798













Adjusted EBITDAX (Non-GAAP)

$

1,038,841


$

704,949


$

2,905,024


$

4,084,255













Adjusted EBITDAX (Non-GAAP) - Percentage Increase/Decrease


47%






-29%




 

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


December 31,


December 31,


2016


2015







Total Stockholders' Equity - (a)

$

13,982


$

12,943







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


6,986



6,655

Less: Cash 


(1,600)



(719)

Net Debt (Non-GAAP) - (c)


5,386



5,936







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

$

20,968


$

19,598







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

$

19,368


$

18,879







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


33%



34%







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


28%



31%

 

EOG RESOURCES, INC.

Reserves Supplemental Data

(Unaudited)










2016 NET PROVED RESERVES RECONCILIATION SUMMARY  








 United 




 Other 





 States 


Trinidad


 International 


 Total 


CRUDE OIL & CONDENSATE (MMBbl)









Beginning Reserves

1,087.9


1.1


8.6


1,097.6


Revisions 

42.0


-


0.9


42.9


Purchases in place

25.8


-


null