2014

EOG Resources Announces Outstanding First Quarter 2014 Results and Expands Drilling Portfolio With Four Key Horizontal Plays

HOUSTON, May 5, 2014 /PRNewswire/ --

  • Reports 42 Percent Increase in Total Company and 45 Percent Growth in U.S. Crude Oil and Condensate Production Year-Over-Year
  • Raises 2014 Full-Year Crude Oil Production Goal to 29 Percent from 27 Percent
  • Adds High Rate-of-Return Horizontal Drilling Inventory in Four U.S. Crude Oil and Combo Plays with Total Estimated Potential Reserves of 400 MMboe, Net
  • Repeats Outstanding Operating Results from the Eagle Ford, Bakken and Leonard

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported first quarter 2014 net income of $660.9 million, or $1.21 per share. This compares to first quarter 2013 net income of $494.7 million, or $0.91 per share.

Adjusted non-GAAP net income for the first quarter 2014 was $767.7 million, or $1.40 per share, and adjusted non-GAAP net income for the same prior year period was $489.9 million, or $0.90 per share.

Consistent with some analysts' practice of matching realizations to settlement months and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the first quarter 2014 excluded a previously disclosed non-cash net loss of $155.7 million ($99.9 million after-tax, or $0.18 per share) on the mark-to-market of financial commodity derivative contracts, net gains on asset dispositions of $7.4 million, net of tax ($0.01 per share) and impairments of certain non-core North American assets of $36.1 million, net of tax ($0.06 per share). During the first quarter 2014, the net cash outflow related to settlements of financial commodity derivative contracts was $34.0 million ($21.8 million after-tax, or $0.04 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

EOG posted strong financial metrics driven by outstanding production from its key operating areas for the first quarter 2014. Earnings per share increased 33 percent and adjusted non-GAAP earnings per share increased 56 percent, compared to the first quarter 2013. Discretionary cash flow increased 28 percent and adjusted EBITDAX advanced 30 percent. (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income, non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP), and adjusted non-GAAP EBITDAX to income before interest expense and income taxes (GAAP).)

"By posting excellent operational and financial results generated by our great assets, EOG hit another home run in the first quarter of 2014. With such a dynamic start, EOG is well positioned to achieve strong overall returns again this year," said William R. "Bill" Thomas, Chairman and Chief Executive Officer.

Operational Highlights
In the first quarter 2014, EOG increased its total crude oil and condensate production by 42 percent, compared to the same prior year period, while U.S. crude oil and condensate production rose 45 percent. Overall total company production increased 18 percent led by a 37 percent increase in total company liquids production – crude oil, condensate and natural gas liquids (NGLs).

Following excellent results during the first quarter, EOG increased its full year 2014 crude oil and condensate production growth target to 29 percent from 27 percent. EOG also raised its total company 2014 production growth target to 12 percent from 11.5 percent.

Rocky Mountain Plays Boost Drilling Portfolio
EOG has moved four horizontal plays in the DJ Basin and Powder River Basin from the evaluation phase into its high rate-of-return drilling portfolio alongside its successful South Texas Eagle Ford, North Dakota Bakken and Delaware Basin Leonard assets. With combined estimated net potential reserves of approximately 400 million barrels of oil equivalent (MMboe), the Codell, Niobrara, Parkman and Turner plays are generating excellent rates of return and remarkably consistent well results, due in part to reductions in drilling costs and advancements in completion techniques. EOG has identified 735 net drilling locations with approximately 10 years of inventory and plans to drill 73 net wells in these two basins during 2014.

Year-to-date, EOG has completed four net wells targeting the Codell in Laramie County, Wyoming, where it holds 72,000 net acres in the DJ Basin. The Jubilee 513-0820H began production at 1,325 barrels of oil per day (Bopd) with 700 thousand cubic feet per day (Mcfd) of rich natural gas. The Windy 504-1806H started production at 1,400 Bopd with 665 Mcfd of rich natural gas. The Pole Creek 525-2413H tested at 1,165 Bopd. EOG has 75 percent, 100 percent and 93 percent working interest, respectively, in these wells. Based on the evaluation of the geologic characteristics of the formation, data from 130 vertical wells drilled by other industry operators and eight producing EOG long-lateral horizontal wells, estimated potential reserves are approximately 125 MMboe, net, of which 78 percent is crude oil. EOG plans to ramp up drilling activity from one to two rigs in May and drill 26 net wells this year.

EOG completed three horizontal wells in the hydrocarbon-rich Niobrara shale during 2013, which had an average initial oil production rate of approximately 700 barrels per day (Bpd). EOG's acreage is quite consistent in this part of the DJ Basin. The estimated reserve potential on EOG's Niobrara acreage in Laramie County, Wyoming, and Weld County, Colorado is 85 MMboe, net, with wells averaging approximately 71 percent crude oil. EOG plans to drill 13 net wells during 2014 with a one-rig program. EOG has identified 235 net drilling locations on its acreage.

North of the DJ Basin in the Powder River Basin, EOG added the Parkman and Turner plays to its drilling portfolio. Active in this area for several years, EOG has transferred advanced completion technology from its other shale basins to improve well productivity in these plays. During 2014, EOG plans to drill 28 net wells in the Parkman and six net wells in the Turner.

Year-to-date, EOG has completed six net wells in the Parkman formation. The Bolt 429-05H, in which EOG has 74 percent working interest, came on-line at 1,310 Bopd with 45 Bpd of NGLs and 405 Mcfd of natural gas. The Arbalest 60-3502H started production at 955 Bopd with 80 Bpd of NGLs and 760 Mcfd of natural gas. EOG has 96 percent working interest in this well. Estimated potential reserves on EOG's 30,000 net Parkman acres are 75 MMboe, net, of which approximately 69 percent is crude oil.

In the Turner formation, where EOG has been very active in Campbell and Converse counties in recent years, it has accumulated 63,000 net acres. By transferring enhanced technology to the play, recent EOG wells are producing 34 percent crude oil versus 26 percent several years ago. EOG plans to drill six net wells during 2014 in the Turner where estimated potential net reserves are 115 MMboe.

"As we've stated in the past, EOG's Eagle Ford and Bakken assets have set the bar high for any new play we might consider adding to our top-tier drilling portfolio. The Codell, Niobrara, Turner and Parkman each meet our stringent funding hurdles, adding 400 MMboe, net, of potential reserves and 735 net drilling locations to our drilling inventory," Thomas said. "The sweet spots in these four plays are expected to make meaningful contributions to EOG's crude oil production profile for years to come."

South Texas Eagle Ford
EOG's oil-rich South Texas Eagle Ford acreage continued to deliver exceptional results in the first quarter, cementing its place at the forefront of all North American crude oil onshore shale plays. Reflecting enhancements to completion techniques and improved well productivity, the Eagle Ford once again was the single largest contributor to EOG's robust U.S. crude oil growth.

In Karnes County, EOG reported the Korth Unit #3H, #4H and #5H had initial production rates of 3,140, 3,015 and 3,400 Bopd, respectively. The wells produced 425, 325 and 415 Bpd of NGLs with 2.5, 1.9 and 2.4 million cubic feet per day (MMcfd) of natural gas, respectively. The Lynch Unit #1H and the Presley Unit #1H had initial oil rates of 4,260 and 4,970 Bpd with 460 and 555 Bpd of NGLs and 2.7 and 3.2 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these five wells.

EOG has 100 percent working interest in three recently completed high volume oil wells in Gonzales County. The Neets Unit #1H and the Magoulas Unit #1H began production at 4,940 and 4,195 Bopd with 440 and 425 Bpd of NGLs and 2.6 and 2.5 MMcfd of natural gas, respectively. The Novosad Unit #12HR had an initial daily oil rate of 3,565 Bpd with 185 Bpd of NGLs and 1.1 MMcfd of natural gas.

In its fifth year of drilling in the Eagle Ford, EOG's 564,000 net acre position in the crude oil window essentially will be held by production for 2014 by mid-year. Achieving this operational objective provides EOG's drilling program with increased flexibility, plus the opportunity to realize additional cost reductions. EOG continues to improve well productivity to further identify additional drilling locations.  

North Dakota Bakken
In the North Dakota Bakken, EOG plans to ramp up its drilling program from six to seven rigs by mid-year. EOG's primary 2014 activity is focused on its Core acreage where it has built infrastructure to optimize operational efficiencies and minimize costs. During the first quarter, EOG achieved economic success with 1,300 feet between wells and now is testing 700-foot spacing, as well as tighter spacing patterns to determine the optimal development of the field.

EOG completed the Wayzetta 28-1424H, 29-1424H, 38-1424H, 39-1424H and 40-1424H in Mountrail County, North Dakota. The wells had initial production rates ranging from 1,000 to 2,220 Bopd with NGL production of 100 to 215 Bpd and 330 to 730 Mcfd of natural gas. EOG's working interest in these five wells ranges from 68 percent to 71 percent.

Delaware Basin
Recent advancements in completions and formation targeting have improved EOG's productivity in the Delaware Basin Leonard Shale. In Lea County, New Mexico, EOG completed the Dillon 31 #1H, #2H and #3H with 1,225, 1,395 and 1,315 Bopd with 195, 215 and 190 Bpd of NGLs and 1.1, 1.2 and 1.1 MMcfd of natural gas, respectively. EOG has 68 percent working interest in these three wells. With a two-rig program, EOG is actively developing the Leonard "A" zone, while testing other zones, and various spacing patterns between wells.

Further south in the Delaware Basin, EOG completed five Wolfcamp wells in Reeves County, Texas, in which it has 100 percent working interest. The State Harrison Ranch 56 #1401H, #1402H, #1403H, #1404H and #1405H began sales at initial rates ranging from 325 to 700 Bopd with 195 to 490 Bpd of NGLs and 1.2 to 3.1 MMcfd of natural gas. Although the Delaware Basin Wolfcamp wells typically begin production at lower initial oil rates relative to the Leonard, they maintain steady, flat production, delivering excellent after-tax rates of return. EOG continues to test spacing between wells to determine optimal development.

Crude Oil and Natural Gas Hedging Activity
For May 2014, EOG has crude oil financial price swap contracts in place for 181,000 Bopd at a weighted average price of $96.55 per barrel, excluding unexercised options. For June 2014, EOG has crude oil financial price swap contracts in place for 171,000 Bopd at a weighted average price of $96.35 per barrel, excluding unexercised options. For the period July 1 through December 31, 2014, EOG has crude oil financial price swap contracts in place for 74,000 Bopd at a weighted average price of $95.37 per barrel, excluding unexercised options.

EOG currently has natural gas hedges in place for more than 30 percent of its North American natural gas production for the remainder of 2014.  For the period June 1 through December 31, 2014, EOG has natural gas financial price swap contracts in place for 330,000 million British thermal units per day (MMBtud) at a weighted average price of $4.55 per million British thermal units (MMBtu), excluding unexercised options.

EOG has also hedged some natural gas volumes for 2015.  For the period January 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 MMBtud at a weighted average price of $4.51 per MMBtu, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)      

Cash Flow and Capital Structure
During the first quarter 2014, EOG's cash flows from operating activities exceeded total capital expenditures.

At March 31, 2014, EOG's total debt outstanding was $5,910 million for a debt-to-total capitalization ratio of 27 percent. Taking into account cash on the balance sheet of $1.7 billion at March 31, EOG's net debt was $4,243 million for a net debt-to-total capitalization ratio of 21 percent, down from 23 percent at year-end 2013. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)

Conference Call May 6, 2014
EOG's first quarter 2014 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Tuesday, May 6, 2014. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through May 20, 2014.

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, Canada, 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."  

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 and extent 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 17 through 26 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2013 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).  As noted above, 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, 2013, 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
Maire A. Baldwin
  
(713) 651-6EOG (651-6364)  
Kimberly A. Matthews  
(713) 571-4676  
David J. Streit 
(713) 571-4902

 

Media
K Leonard
(713) 571-3870

 

 


EOG RESOURCES, INC.

FINANCIAL REPORT

(Unaudited; in millions, except per share data)



Three Months Ended


March 31,


2014


2013







Net Operating Revenues

$

4,083.7


$

3,356.5

Net Income 

$

660.9


$

494.7

Net Income Per Share 







Basic

$

1.22


$

0.92


Diluted

$

1.21


$

0.91

Average Number of Common Shares







Basic


542.3



538.7


Diluted


548.1



544.5



SUMMARY INCOME STATEMENTS
(Unaudited; in thousands, except per share data)



Three Months Ended


March 31,


2014


2013

Net Operating Revenues





Crude Oil and Condensate

$

2,397,102


$

1,781,833


Natural Gas Liquids


246,235



169,529


Natural Gas


556,693



410,879


Losses on Mark-to-Market Commodity Derivative Contracts


(155,736)



(104,956)


Gathering, Processing and Marketing


1,015,411



922,957


Gains on Asset Dispositions, Net


11,498



164,233


Other, Net


12,468



12,039


        Total


4,083,671



3,356,514

Operating Expenses







Lease and Well


320,834



249,000


Transportation Costs


243,237



184,257


Gathering and Processing Costs


33,924



24,504


Exploration Costs


48,058



44,216


Dry Hole Costs


8,348



3,962


Impairments 


113,361



53,548


Marketing Costs


1,006,304



904,649


Depreciation, Depletion and Amortization


946,491



846,388


General and Administrative


82,862



77,985


Taxes Other Than Income


195,973



134,931


        Total


2,999,392



2,523,440


Operating Income 


1,084,279



833,074


Other Expense, Net


(3,338)



(10,134)


Income Before Interest Expense and Income Taxes


1,080,941



822,940


Interest Expense, Net


50,152



61,921


Income Before Income Taxes


1,030,789



761,019


Income Tax Provision


369,861



266,294


Net Income 

$

660,928


$

494,725


Dividends Declared per Common Share

$

0.125


$

0.09375


Note: All share and per-share amounts shown have been restated to reflect the announced 2-for-1 stock split effective March 31, 2014.

 

EOG RESOURCES, INC.

OPERATING HIGHLIGHTS

(Unaudited)



Three Months Ended


March 31,


2014


2013

Wellhead Volumes and Prices


Crude Oil and Condensate Volumes (MBbld) (A)



United States


258.1



178.3


Canada


7.2



7.7


Trinidad


1.1



1.2


Other International (B)


0.1



0.1


          Total


266.5



187.3


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







United States

$

100.58


$

106.57


Canada


89.98



85.32


Trinidad


89.93



94.51


Other International (B)


87.20



95.13


          Composite


100.25



105.61


Natural Gas Liquids Volumes (MBbld) (A)






United States


70.8



58.6


Canada


0.8



0.9


          Total


71.6



59.5


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







United States

$

38.10


$

31.63


Canada


46.88



41.90


          Composite


38.20



31.78


Natural Gas Volumes (MMcfd) (A)







United States


894



934


Canada


64



79


Trinidad


387



352


Other International (B)


7



8


          Total


1,352



1,373


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







United States

$

4.96


$

3.08


Canada


4.70



3.24


Trinidad


3.63



3.91


Other International (B)


6.12



6.75


          Composite


4.58



3.32


Crude Oil Equivalent Volumes (MBoed) (D)







United States 


478.0



392.6


Canada


18.7



21.8


Trinidad


65.6



59.8


Other International (B)


1.2



1.4


          Total


563.5



475.6


Total MMBoe (D)


50.7



42.8



(A)

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

(B)

Other International includes EOG's 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 equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

 


EOG RESOURCES, INC

SUMMARY BALANCE SHEETS

(Unaudited; in thousands, except share data)



March 31,


December 31,


2014


2013

ASSETS

Current Assets







Cash and Cash Equivalents

$

1,667,212


$

1,318,209


Accounts Receivable, Net


1,801,665



1,658,853


Inventories


635,419



563,268


Assets from Price Risk Management Activities


-



8,260


Income Taxes Receivable


191



4,797


Deferred Income Taxes


429,695



244,606


Other


288,294



274,022


          Total


4,822,476



4,072,015


Property, Plant and Equipment







Oil and Gas Properties (Successful Efforts Method)


44,324,008



42,821,803


Other Property, Plant and Equipment


3,128,400



2,967,085


          Total Property, Plant and Equipment


47,452,408



45,788,888


Less:  Accumulated Depreciation, Depletion and Amortization


(20,453,971)



(19,640,052)


          Total Property, Plant and Equipment, Net


26,998,437



26,148,836

Other Assets


320,375



353,387

Total Assets

$

32,141,288


$

30,574,238


LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities







Accounts Payable

$

2,647,209


$

2,254,418


Accrued Taxes Payable


270,908



159,365


Dividends Payable


67,768



50,795


Liabilities from Price Risk Management Activities


227,036



127,542


Current Portion of Long-Term Debt


6,579



6,579


Other


176,142



263,017


          Total


3,395,642



2,861,716



Long-Term Debt


5,902,952



5,906,642

Other Liabilities


922,586



865,067

Deferred Income Taxes


5,886,794



5,522,354

Commitments and Contingencies













Stockholders' Equity







Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 546,892,339







     Shares Issued at March 31, 2014 and 546,378,440 Shares Issued at December 31, 2013 


205,471



202,732


Additional Paid in Capital


2,697,807



2,646,879


Accumulated Other Comprehensive Income 


402,803



415,834


Retained Earnings


12,760,895



12,168,277


Common Stock Held in Treasury, 396,906 Shares at March 31, 2014 and 206,830 Shares at December 31, 2013


(33,662)



(15,263)


     Total Stockholders' Equity


16,033,314



15,418,459

Total Liabilities and Stockholders' Equity

$

32,141,288


$

30,574,238








Note: All share amounts shown have been restated to reflect the announced 2-for-1 stock split effective March 31, 2014.

 

EOG RESOURCES, INC.

SUMMARY STATEMENTS OF CASH FLOWS

(Unaudited; in thousands)











Three Months Ended


March 31,


2014


2013

Cash Flows from Operating Activities






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







Net Income 

$

660,928


$

494,725


Items Not Requiring (Providing) Cash









Depreciation, Depletion and Amortization


946,491



846,388




Impairments 


113,361



53,548




Stock-Based Compensation Expenses


35,565



30,436




Deferred Income Taxes


232,808



200,779




Gains on Asset Dispositions, Net


(11,498)



(164,233)




Other, Net


5,442



8,268


Dry Hole Costs


8,348



3,962


Mark-to-Market Commodity Derivative Contracts









Total Losses


155,736



104,956




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


(34,033)



67,050


Excess Tax Benefits from Stock-Based Compensation


(27,422)



(11,673)


Other, Net


3,589



5,022


Changes in Components of Working Capital and Other Assets and Liabilities









Accounts Receivable


(144,317)



(236,757)




Inventories


(68,948)



(15,058)




Accounts Payable


361,810



186,065




Accrued Taxes Payable


139,801



9,004




Other Assets


(12,536)



(47,193)




Other Liabilities


(29,169)



(52,933)


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


(68,283)



(57,421)

Net Cash Provided by Operating Activities


2,267,673



1,424,935







Investing Cash Flows







Additions to Oil and Gas Properties


(1,736,630)



(1,604,123)


Additions to Other Property, Plant and Equipment


(165,966)



(92,201)


Proceeds from Sales of Assets


19,825



479,436


Changes in Restricted Cash


(9,047)



-


Changes in Components of Working Capital Associated with Investing Activities


68,258



57,149

Net Cash Used in Investing Activities


(1,823,560)



(1,159,739)







Financing Cash Flows







Long-Term Debt Borrowings


496,220



-


Long-Term Debt Repayments


(500,000)



-


Settlement of Foreign Currency Swap


(31,573)



-


Dividends Paid


(51,780)



(46,220)


Excess Tax Benefits from Stock-Based Compensation


27,422



11,673


Treasury Stock Purchased


(28,897)



(11,024)


Proceeds from Stock Options Exercised 


985



8,004


Debt Issuance Costs


(942)



-


Repayment of Capital Lease Obligation


(1,474)



(1,427)


Other, Net


25



272

Net Cash Used in Financing Activities


(90,014)



(38,722)







Effect of Exchange Rate Changes on Cash


(5,096)



5,125







Increase in Cash and Cash Equivalents


349,003



231,599

Cash and Cash Equivalents at Beginning of Period


1,318,209



876,435

Cash and Cash Equivalents at End of Period

$

1,667,212


$

1,108,034

 


EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP) 

TO NET INCOME (GAAP)

(Unaudited; in thousands, except per share data)



The following chart adjusts the three-month periods ended March 31, 2014 and 2013 reported Net Income (GAAP) to reflect actual net cash (payments for) received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market losses from these transactions, to eliminate the net gains on asset dispositions in North America in 2014 and 2013 and to add back impairment charges related to certain of EOG's non-core North American assets in 2014.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items.  EOG management uses this information for comparative purposes within the industry.


Three Months Ended 



March 31,



2014


2013









Reported Net Income (GAAP)

$

660,928


$

494,725










Mark-to-Market (MTM) Commodity Derivative Contracts Impact








Total Losses


155,736



104,956



Net Cash (Payments for) Received from Settlements of Commodity








    Derivative Contracts


(34,033)



67,050



          Subtotal


121,703



172,006











After-Tax MTM Impact


78,078



110,127










Less: Net Gains on Asset Dispositions, Net of Tax


(7,377)



(114,993)


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


36,058



-










Adjusted Net Income (Non-GAAP)

$

767,687


$

489,859










Net Income Per Share (GAAP)








Basic

$

1.22


$

0.92



Diluted

$

1.21

(a) 

$

0.91

(b) 









Percentage Increase - [(a) - (b)] / (b)


33%













Adjusted Net Income Per Share (Non-GAAP)








Basic

$

1.42


$

0.91



Diluted

$

1.40

(c) 

$

0.90

(d) 









Percentage Increase - [(c) - (d)] / (d)


56%













Average Number of Common Shares (GAAP)








Basic


542,278



538,717



Diluted


548,071



544,526


















Note: All share and per-share amounts shown have been restated to reflect the announced 2-for-1 stock split effective March 31, 2014.

 


EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW (NON-GAAP)

TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)

(Unaudited; in thousands)


The following chart reconciles the three-month periods ended March 31, 2014 and 2013 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP).  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities.  EOG management uses this information for comparative purposes within the industry.



Three Months Ended



March 31,



2014


2013



Net Cash Provided by Operating Activities (GAAP)

$

2,267,673


$

1,424,935











Adjustments:


Exploration Costs (excluding Stock-Based Compensation Expenses) 


40,124



36,645



Excess Tax Benefits from Stock-Based Compensation


27,422



11,673



Changes in Components of Working Capital and Other Assets and Liabilities









Accounts Receivable


144,317



236,757




Inventories


68,948



15,058




Accounts Payable


(361,810)



(186,065)




Accrued Taxes Payable


(139,801)



(9,004)




Other Assets


12,536



47,193




Other Liabilities


29,169



52,933



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









68,283



57,421











Discretionary Cash Flow (Non-GAAP)

$

2,156,861

(a) 

$

1,687,546

(b) 










Percentage Increase - [(a) - (b)] / (b)


28%





 

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 BEFORE INTEREST EXPENSE AND INCOME TAXES (GAAP)

(Unaudited; in thousands)










The following chart adjusts the three-month periods ended March 31, 2014 and 2013 reported Income 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 (payments for) received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) losses from these transactions and to eliminate the net gains on asset dispositions in North America in 2014 and 2013.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items.  EOG management uses this information for comparative purposes within the industry.













Three Months Ended





March 31,





2014


2013











Income Before Interest Expense and Income Taxes (GAAP)

$

1,080,941


$

822,940











Adjustments:








Depreciation, Depletion and Amortization


946,491



846,388



Exploration Costs


48,058



44,216



Dry Hole Costs


8,348



3,962



Impairments 


113,361



53,548




EBITDAX (Non-GAAP)


2,197,199



1,771,054



Total Losses on MTM Commodity Derivative Contracts 


155,736



104,956



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


(34,033)



67,050



Net Gains on Asset Dispositions


(11,498)



(164,233)











Adjusted EBITDAX (Non-GAAP)

$

2,307,404

(a) 

$

1,778,827

(b) 










Percentage Increase - [(a) - (b)] / (b)


30%





 

EOG RESOURCES, INC.

CRUDE OIL AND NATURAL GAS FINANCIAL

COMMODITY DERIVATIVE CONTRACTS


Presented below is a comprehensive summary of EOG's crude oil and natural gas derivative contracts at May 5, 2014, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.


CRUDE OIL DERIVATIVE CONTRACTS


Weighted


Volume 


Average Price


(Bbld) 


($/Bbl) 

2014(1)




January 2014 (closed)

156,000


$             96.30

February 2014 (closed)

171,000


96.35

March 1, 2014 through April 30, 2014 (closed)

181,000


96.55

May 2014

181,000


96.55

June 2014

171,000


96.35

July 1, 2014 through December 31, 2014

74,000


95.37






2015(2)

-


$                    -



(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional three-month and six-month periods. Options covering a notional volume of 10,000 Bbld are exercisable on or about May 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $100.00 per barrel for each month during the period June 1, 2014 through August 31, 2014. Options covering a notional volume of 118,000 Bbld are exercisable on or about June 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 118,000 Bbld at an average price of $96.64 per barrel for each month during the period July 1, 2014 through December 31, 2014.



(2)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month periods. Options covering a notional volume of 69,000 Bbld are exercisable on or about December 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 69,000 Bbld at an average price of $95.20 per barrel for each month during the period January 1, 2015 through June 30, 2015.


NATURAL GAS DERIVATIVE CONTRACTS


Weighted


Volume


Average Price


(MMBtud) 


($/MMBtu) 

2014(3)




January 2014 (closed)

230,000


$             4.51

February 2014 (closed)

710,000


4.57

March 2014 (closed)

810,000


4.60

April 2014 (closed)

465,000


4.52

May 2014 (closed)

685,000


4.55

June 1, 2014 through December 31, 2014

330,000


4.55


2015(4)




January 1, 2015 through December 31, 2015

175,000


$             4.51






(3)

 

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. All such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 480,000 MMBtud at an average price of $4.63 per MMBtu for each month during the period June 1, 2014 through December 31, 2014.



(4)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  All such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period January 1, 2015 through December 31, 2015.





$/Bbl          

Dollars per barrel

$/MMBtu    

Dollars per million British thermal units

Bbld

Barrels per day

MMBtu

Million British thermal units

MMBtud

Million British thermal units per day





EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF NET DEBT (NON-GAAP) AND TOTAL 

CAPITALIZATION (NON-GAAP) AS USED IN THE CALCULATION OF 

THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO (NON-GAAP) TO

CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP)

(Unaudited; in millions, except ratio data)




The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation.  A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation.  EOG management uses this information for comparative purposes within the industry.





At


At


March 31,


December 31,


2014


2013




Total Stockholders' Equity - (a)

$

16,033


$

15,418





Current and Long-Term Debt - (b)


5,910



5,913

Less: Cash 


(1,667)



(1,318)

Net Debt (Non-GAAP) - (c)


4,243



4,595





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

$

21,943


$

21,331





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

$

20,276


$

20,013





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


27%



28%





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


21%



23%

 


EOG RESOURCES, INC.

  SECOND QUARTER AND FULL YEAR 2014 FORECAST AND BENCHMARK COMMODITY PRICING



(a)  Second Quarter and Full Year 2014 Forecast



The forecast items for the second quarter and full year 2014 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, Canada 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 and Canada natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.























ESTIMATED RANGES







(Unaudited)







2Q 2014



Full Year 2014

Daily Production













Crude Oil and Condensate Volumes (MBbld)














United States


265.0

-


280.0



267.0

-


287.0



Canada


4.5

-


5.5



4.5

-


6.5



Trinidad


0.7

-


0.9



0.6

-


1.0



Other International


0.0

-


0.0



0.0

-


1.2




Total


270.2

-


286.4



272.1

-


295.7


















Natural Gas Liquids Volumes (MBbld)














United States


68.0

-


78.0



68.0

-


77.0



Canada


0.5

-


0.7



0.6

-


0.8




Total


68.5

-


78.7



68.6

-


77.8


















Natural Gas Volumes (MMcfd)














United States


878

-


898



850

-


880



Canada


56

-


68



55

-


69



Trinidad


340

-


360



350

-


370



Other International


8

-


10



8

-


12




Total


1,282

-


1,336



1,263

-


1,331


















Crude Oil Equivalent Volumes (MBoed)  














United States


479.3

-


507.7



476.7

-


510.7



Canada


14.3

-


17.5



14.3

-


18.8



Trinidad


57.4

-


60.9



58.9

-


62.7



Other International


1.3

-


1.7



1.3

-


3.2




Total


552.3

-


587.8



551.2

-


595.4

















Operating Costs













Unit Costs ($/Boe)














Lease and Well

$

6.20

-

$

6.50


$

6.25

-

$

6.75



Transportation Costs

$

4.75

-

$

4.95


$

4.80

-

$

5.20



Depreciation, Depletion and Amortization

$

18.40

-

$

19.10


$

18.30

-

$

19.10

















Expenses ($MM)













Exploration, Dry Hole and Impairment

$

130

-

$

150


$

500

-

$

550


General and Administrative

$

90

-

$

100


$

380

-

$

390


Gathering and Processing 

$

30

-

$

36


$

125

-

$

145


Capitalized Interest

$

15

-

$

17


$

55

-

$

65


Net Interest

$

47

-

$

51


$

190

-

$

210

















Taxes Other Than Income (% of Wellhead Revenue)


6.0%

-


6.4%



6.0%

-


6.5%

















Income Taxes













Effective Rate 


35%

-


40%



35%

-


40%


Current Taxes ($MM)

$

155

-

$

170


$

585

-

$

605

















Capital Expenditures ($MM) - FY 2014 (Excluding Acquisitions)













Exploration and Development, Excluding Facilities







$

6,450


$

6,550


Exploration and Development Facilities







$

880


$

920


Gathering, Processing and Other







$

770


$

810

















Pricing - (Refer to Benchmark Commodity Pricing in text)













Crude Oil and Condensate ($/Bbl)














Differentials















United States - (above) below WTI

$

(0.50)

-

$

0.50


$

(0.50)

-

$

0.30




Canada - (above) below WTI

$

9.00

-

$

11.50


$

10.00

-

$

14.00




Trinidad - (above) below WTI

$

9.00

-

$

11.00


$

8.00

-

$

12.00


















Natural Gas Liquids














Realizations as % of WTI















United States


30%

-


37%



31%

-


37%




Canada


30%

-


40%



32%

-


42%


















Natural Gas ($/Mcf)














Differentials















United States - (above) below NYMEX Henry Hub

$

0.20

-

$

0.60


$

0.25

-

$

0.60




Canada - (above) below NYMEX

Henry Hub

$

0.15

-

$

0.55


$

0.25

-

$

0.65



















Realizations















Trinidad

$

3.15

-

$

3.65


$

2.75

-

$

3.25




Other International

$

4.50

-

$

6.50


$

4.30

-

$

6.30

















Definitions













$/Bbl 


U.S. Dollars per barrel






$/Boe

U.S. Dollars per barrel of oil equivalent






$/Mcf 


U.S. Dollars per thousand cubic feet






$MM


U.S. Dollars in millions






MBbld

Thousand barrels per day






MBoed

Thousand barrels of oil equivalent per day






MMcfd

Million cubic feet per day






NYMEX

New York Mercantile Exchange






WTI


West Texas Intermediate






 

 

SOURCE EOG Resources, Inc.



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