EX-99.1 2 exh99-1110515.htm PRESS RELEASE OF EOG RESOURCES, INC. Exhibit
EXHIBIT 99.1


EOG Resources, Inc.
 
News Release
 
For Further Information Contact:
Investors
 
Cedric W. Burgher
 
(713) 571-4658
 
David J. Streit
 
(713) 571-4902
 
Kimberly M. Ehmer
 
(713) 571-4676
 
 
 
Media
 
K Leonard
 
(713) 571-3870

EOG Resources Reports Third Quarter 2015 Results; Increases Delaware Basin Net Resource Potential by 1.0 BnBoe
•
Updates Delaware Basin Net Resource Potential to 2.35 BnBoe
▪
Increases Wolfcamp Net Reserve Potential by 500 MMBoe
▪
Announces Second Bone Spring Sand Net Reserve Potential of 500 MMBoe
▪
Expands Drilling Inventory from 2,700 to 4,900 Net Wells
▪
Acquires 26,000 Net Acres in the Delaware Basin Oil Window in Three Transactions
▪
Completes Record Horizontal Well for Delaware Basin Wolfcamp
•
Continues to Improve Well Productivity While Lowering Costs
•
Exceeds Third Quarter Oil and Total Production Guidance
•
Reduces Per-Unit Lease Operating Costs by 5 Percent Versus Second Quarter


FOR IMMEDIATE RELEASE: Thursday, November 5, 2015

HOUSTON - EOG Resources, Inc. (EOG) today reported a third quarter 2015 net loss of $4.1 billion, or $7.47 per share. This compares to third quarter 2014 net income of $1.1 billion, or $2.01 per share.
Adjusted non-GAAP net income for the third quarter 2015 was $13.5 million, or $0.02 per share, compared to the same prior year period adjusted non-GAAP net income of $720.6 million, or $1.31 per share. Adjusted non-GAAP net income is calculated by matching realizations to settlement months and making certain other adjustments in order to exclude one-time items. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
During the third quarter 2015, proved oil and gas properties and related assets were written down to their fair value resulting in non-cash impairment charges of $4.1 billion net of tax. The impairments were due to declines in commodity prices and were primarily related to legacy natural gas and marginal liquids assets.


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

Operational Highlights
In the third quarter 2015, total crude oil and condensate production exceeded prior guidance due to improved well productivity. Total company production decreased 5 percent compared to the third quarter 2014 excluding production related to EOG’s Canadian operations, which were divested in the fourth quarter 2014. Total capital expenditures decreased 36 percent compared to the same prior year period.
EOG also continued to reduce completed well costs and operating costs compared to the same quarter last year. Lease and well expenses decreased 17 percent on a per-unit basis due to improved operational efficiencies and reduced service costs. Per-unit transportation costs decreased 11 percent, and total general and administrative expenses declined 6 percent.
“We are executing on our 2015 plan to reset the company to be successful in a low commodity price environment,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “By continuing to make the best oil wells in the industry, significantly reducing costs and expanding resource potential in the best North American oil plays, EOG is uniquely positioned for 2016 and to lead the industry for years to come.”

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

Delaware Basin
EOG increased its Delaware Basin net resource potential by 1.0 billion barrels of oil equivalent (BnBoe). For the Delaware Basin Wolfcamp, EOG added 950 net drilling locations and increased its net resource potential estimate over 60 percent to 1.3 BnBoe. Advancements in targeting and completion technology are enabling tighter well spacing and increased production per well. In the Second Bone Spring Sand oil play, EOG provided an initial net resource potential estimate of 500 million barrels of oil equivalent (MMBoe) and added 1,250 net drilling locations in this high quality crude oil play.
EOG added 26,000 net acres to its Delaware Basin position in the third quarter 2015 through three tactical acquisitions in Loving County, Texas, and Lea County, N.M., for a total of $368 million. Most of


the acquired acreage is adjacent to EOG’s existing operating areas in the high rate of return Delaware Basin oil window. Combined, these acquisitions added net production of 750 barrels of oil equivalent (Boe) per day with an associated 2.5 MMBoe of proved producing reserves. These acquisitions and the updated resource potential bring EOG’s total Delaware Basin net position to 2.35 BnBoe and 4,900 locations, providing decades of high return drilling potential.
“Outstanding technical and operational advances enabled us to increase potential resource estimates for our Delaware Basin position by over 70 percent,” Thomas said. “We are also pleased that through our tactical acquisitions of new, high quality Delaware Basin acreage, we added assets which meet our high rate of return hurdle. EOG’s Delaware Basin assets along with the company’s Eagle Ford and Bakken positions continue to grow in both size and quality. With premier assets and commitment to innovation, EOG continues to enhance its capability for high return growth in a low oil price environment.”
In addition, EOG completed a number of noteworthy new wells in the Delaware Basin in the third quarter.
In the Wolfcamp shale in Lea County, N.M., EOG completed the Thor 21 #701H and #702H with average initial production rates per well of 3,255 barrels of oil per day (Bopd), 470 barrels per day (Bpd) of natural gas liquids (NGLs) and 3.9 million cubic feet per day (MMcfd) of natural gas. The Thor 21 #702H set a new industry 30-day production record for horizontal wells in the Delaware Basin Wolfcamp.
In the Second Bone Spring Sand in Lea County, N.M., EOG completed the Neptune 10 State Com #501H and #502H in a two-well pattern with average initial production rates per well of 2,205 Bopd, 185 Bpd of NGLs and 1.5 MMcfd of natural gas.
In the Leonard shale in Lea County, N.M., EOG completed the Hawk 35 Fed #7H, #8H, #9H and #10H in a four-well pattern with average initial production rates per well of 1,615 Bopd, 160 Bpd of NGLs and 1.3 MMcfd of natural gas.

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


with average initial production rates per well of 2,650 Bopd with 150 Bpd of NGLs and 1.0 MMcfd of natural gas.

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

Hedging Activity
For the period November 1 through December 31, 2015, EOG has crude oil financial price swap contracts in place for 10,000 Bopd at a weighted average price of $89.98 per barrel. In addition, EOG has put options in place which establish a floor price of $45.00 per barrel for 82,500 Bopd for November 2015.
For December 2015, EOG has natural gas financial price swap contracts in place for 175,000 million British thermal units (MMBtu) per day at a weighted average price of $4.51 per MMBtu, excluding unexercised options. Comprehensive summaries of crude oil and natural gas derivative contracts are provided in the attached tables.

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

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

This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG


typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

•
the timing, extent and duration of changes in prices for, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
•
the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
•
the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and optimize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
•
the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;
•
the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities;
•
the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;
•
the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
•
EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
•
the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
•
competition in the oil and gas exploration and production industry for employees and other personnel, facilities, equipment, materials and services;
•
the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;
•
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
•
weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;
•
the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
•
EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
•
the extent and effect of any hedging activities engaged in by EOG;
•
the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
•
political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;
•
the use of competing energy sources and the development of alternative energy sources;
•
the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
•
acts of war and terrorism and responses to these acts;
•
physical, electronic and cyber security breaches; and
•
the other factors described under ITEM 1A, Risk Factors, on pages 13 through 20 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
 
###




EOG RESOURCES, INC.
Financial Report
(Unaudited; in millions, except per share data)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
 
 
Net Operating Revenues
$
2,172.4

 
$
5,118.6

 
$
6,960.7

 
$
13,389.8

Net Income (Loss)
$
(4,075.7
)
 
$
1,103.6

 
$
(4,240.2
)
 
$
2,470.9

Net Income (Loss) Per Share
 
 
 
 
 
 
 
 
 
 
 
Basic
$
(7.47
)
 
$
2.03

 
$
(7.77
)
 
$
4.55

Diluted
$
(7.47
)
 
$
2.01

 
$
(7.77
)
 
$
4.51

Average Number of Common Shares
 
 
 
 
 
 
 
 
 
 
 
Basic
   
545.9

 
 
544.0

 
 
545.5

 
 
543.1

Diluted
 
545.9

 
 
549.5

 
 
545.5

 
 
548.4

 
 
 
 
 
 
 
 
 
 
 
 
Summary Income Statements
(Unaudited; in thousands, except per share data)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Net Operating Revenues
 
 
 
 
 
 
 
Crude Oil and Condensate
$
1,181,092

 
 $
2,671,502

 
$
3,894,092

 
$
7,687,579

Natural Gas Liquids
 
95,217

 
 
258,927

 
 
311,137

 
 
753,135

Natural Gas
 
281,837

 
 
443,108

 
 
843,657

 
 
1,508,892

Gains on Mark-to-Market Commodity Derivative Contracts
 
29,239

 
 
469,125

 
 
56,954

 
 
84,119

Gathering, Processing and Marketing
 
572,217

 
 
1,196,933

 
 
1,820,843

 
 
3,240,139

Gains (Losses) on Asset Dispositions, Net
 
(1,185
)
 
 
60,346

 
 
(5,142
)
 
 
75,700

Other, Net
 
14,011

 
 
18,675

 
 
39,126

 
 
40,279

Total
 
2,172,428

 
 
5,118,616

 
 
6,960,667

 
 
13,389,843

Operating Expenses
 
 
 
 
 
 
 
 
 
 
 
Lease and Well
 
283,221

 
 
368,340

 
 
934,366

 
 
1,035,632

Transportation Costs
 
203,594

 
 
246,067

 
 
641,739

 
 
729,883

Gathering and Processing Costs
 
35,497

 
 
41,621

 
 
106,503

 
 
108,015

Exploration Costs
 
31,344

 
 
48,955

 
 
114,548

 
 
139,221

Dry Hole Costs
 
198

 
 
16,359

 
 
14,317

 
 
30,265

Impairments
 
6,307,420

 
 
55,542

 
 
6,445,375

 
 
207,938

Marketing Costs
 
615,303

 
 
1,213,652

 
 
1,924,134

 
 
3,263,471

Depreciation, Depletion and Amortization
 
722,172

 
 
1,040,018

 
 
2,544,187

 
 
2,983,111

General and Administrative
 
90,959

 
 
96,931

 
 
257,580

 
 
270,725

Taxes Other Than Income
 
105,677

 
 
204,969

 
 
334,244

 
 
606,411

Total
 
8,395,385

 
 
3,332,454

 
 
13,316,993

 
 
9,374,672

 
Operating Income (Loss)
 
(6,222,957
)
 
 
1,786,162

 
 
(6,356,326
)
 
 
4,015,171

 
Other Income (Expense), Net
 
8,607

 
 
(21,338
)
 
 
7,996

 
 
(16,726
)
 
Income (Loss) Before Interest Expense and Income Taxes
 
(6,214,350
)
 
 
1,764,824

 
 
(6,348,330
)
 
 
3,998,445

 
Interest Expense, Net
 
60,571

 
 
49,704

 
 
174,400

 
 
151,723

 
Income (Loss) Before Income Taxes
 
(6,274,921
)
 
 
1,715,120

 
 
(6,522,730
)
 
 
3,846,722

 
Income Tax Provision (Benefit)
 
(2,199,182
)
 
 
611,502

 
 
(2,282,511
)
 
 
1,375,823

 
Net Income (Loss)
$
(4,075,739
)
 
 $
1,103,618

 
$
(4,240,219
)
 
$
2,470,899

 
Dividends Declared per Common Share
$
0.1675

 
$
0.1675

 
$
0.5025

 
$
0.4175

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 




EOG RESOURCES, INC.
Operating Highlights
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Wellhead Volumes and Prices
 
 
 
Crude Oil and Condensate Volumes (MBbld) (A)
 
 
 
United States
 
278.3

 
 
293.2

 
 
284.4

 
 
275.5

Trinidad
 
1.0

 
 
0.9

 
 
0.9

 
 
1.0

Other International (B)
 
0.2

 
 
5.4

 
 
0.2

 
 
6.1

Total
 
279.5

 
 
299.5

 
 
285.5

 
 
282.6

 
Average Crude Oil and Condensate Prices ($/Bbl) (C)
 
 
 
 
 
 
 
 
 
 
 
United States
$
45.93

 
$
97.33

 
$
49.94

 
$
100.10

Trinidad
 
38.56

 
 
87.87

 
 
41.98

 
 
90.84

Other International (B)
 
61.80

 
 
87.72

 
 
58.44

 
 
90.74

Composite
 
45.91

 
 
97.13

 
 
49.92

 
 
99.87

 
Natural Gas Liquids Volumes (MBbld) (A)
 
 
 
 
 
 
 
 
 
 
 
United States
 
77.7

 
 
85.8

 
 
76.2

 
 
78.4

Other International (B)
 
0.1

 
 
0.6

 
 
0.1

 
 
0.7

Total
 
77.8

 
 
86.4

 
 
76.3

 
 
79.1

 
Average Natural Gas Liquids Prices ($/Bbl) (C)
 
 
 
 
 
 
 
 
 
 
 
United States
$
13.25

 
$
32.61

 
$
14.94

 
$
34.83

Other International (B)
 
8.05

 
 
40.38

 
 
6.05

 
 
43.01

Composite
 
13.24

 
 
32.67

 
 
14.93

 
 
34.90

 
Natural Gas Volumes (MMcfd) (A)
 
 
 
 
 
 
 
 
 
 
 
United States
 
889

 
 
941

 
 
895

 
 
920

Trinidad
 
355

 
 
356

 
 
342

 
 
374

Other International (B)
 
30

 
 
72

 
 
31

 
 
74

Total
 
1,274

 
 
1,369

 
 
1,268

 
 
1,368

 
Average Natural Gas Prices ($/Mcf) (C)
 
 
 
 
 
 
 
 
 
 
 
United States
$
2.04

 
$
3.48

 
$
2.14

 
$
4.17

Trinidad
 
2.90

 
 
3.50

 
 
3.01

 
 
3.61

Other International (B)
 
7.18

(E)
 
4.16

 
 
4.63

(E)
 
4.56

Composite
 
2.40

 
 
3.52

 
 
2.44

 
 
4.04

 
Crude Oil Equivalent Volumes (MBoed) (D)
 
 
 
 
 
 
 
 
 
 
 
United States
 
504.2

 
 
536.1

 
 
509.8

 
 
507.3

Trinidad
 
60.2

 
 
60.1

 
 
57.9

 
 
63.4

Other International (B)
 
5.2

 
 
17.9

 
 
5.4

 
 
19.0

Total
 
569.6

 
 
614.1

 
 
573.1

 
 
589.7

 
Total MMBoe (D)
 
52.4

 
 
56.5

 
 
156.5

 
 
161.0


(A)
Thousand barrels per day or million cubic feet per day, as applicable.
(B)
Other International includes EOG's Canada, United Kingdom, China and Argentina operations.
(C)
Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments.
(D)
Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.
(E)
Includes revenue adjustment of $3.62 per Mcf and $1.19 per Mcf for the quarter and year-to-date, respectively, related to a price adjustment for natural gas sales made in China during the period June 2012 through March 2015.




EOG RESOURCES, INC.
Summary Balance Sheets
(Unaudited; in thousands, except share data)
 
 
September 30,
 
December 31,
 
2015
 
2014
ASSETS
Current Assets
 
 
 
 
 
Cash and Cash Equivalents
$
742,689

 
$
2,087,213

Accounts Receivable, Net
 
1,123,111

 
 
1,779,311

Inventories
 
660,252

 
 
706,597

Assets from Price Risk Management Activities
 
71,503

 
 
465,128

Income Taxes Receivable
 
53,667

 
 
71,621

Deferred Income Taxes
 
40,619

 
 
19,618

Other
 
133,117

 
 
286,533

Total
 
2,824,958

 
 
5,416,021

 
Property, Plant and Equipment
 
 
 
 
 
Oil and Gas Properties (Successful Efforts Method)
 
50,025,191

 
 
46,503,532

Other Property, Plant and Equipment
 
3,890,934

 
 
3,750,958

Total Property, Plant and Equipment
 
53,916,125

 
 
50,254,490

Less: Accumulated Depreciation, Depletion and Amortization
 
(29,640,793
)
 
 
(21,081,846
)
Total Property, Plant and Equipment, Net
 
24,275,332

 
 
29,172,644

Other Assets
 
176,957

 
 
174,022

Total Assets
$
27,277,247

 
$
34,762,687

 
 
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
 
 
 
 
 
Accounts Payable
$
1,561,574

 
$
2,860,548

Accrued Taxes Payable
 
174,897

 
 
140,098

Dividends Payable
 
91,377

 
 
91,594

Deferred Income Taxes
 
—

 
 
110,743

Short-Term Borrowings and Current Portion of Long-Term Debt
 
36,279

 
 
6,579

Other
 
182,834

 
 
174,746

Total
 
2,046,961

 
 
3,384,308

 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt
 
6,393,931

 
 
5,903,354

Other Liabilities
 
970,288

 
 
939,497

Deferred Income Taxes
 
4,581,844

 
 
6,822,946

Commitments and Contingencies
 
 
 
 
 
 
 
 
 
 
 
Stockholders' Equity
 
 
 
 
 
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 550,052,879 Shares Issued at September 30, 2015 and 549,028,374 Shares Issued at December 31, 2014
 
205,503

 
 
205,492

Additional Paid in Capital
 
2,897,439

 
 
2,837,150

Accumulated Other Comprehensive Loss
 
(34,979
)
 
 
(23,056
)
Retained Earnings
 
10,247,349

 
 
14,763,098

Common Stock Held in Treasury, 383,870 Shares at September 30, 2015 and 733,517 Shares at December 31, 2014
 
(31,089
)
 
 
(70,102
)
Total Stockholders' Equity
 
13,284,223

 
 
17,712,582

Total Liabilities and Stockholders' Equity
$
27,277,247

 
$
34,762,687

 
 
 
 
 
 
 
 
 
 
 
 






EOG RESOURCES, INC.
Summary Statements of Cash Flows
(Unaudited; in thousands)
 
Nine Months Ended
 
September 30,
 
2015
 
2014
Cash Flows from Operating Activities
 
 
 
 
 
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:
 
 
 
 
 
Net Income (Loss)
$
(4,240,219
)
 
$
2,470,899

Items Not Requiring (Providing) Cash
 
 
 
 
 
Depreciation, Depletion and Amortization
 
2,544,187

 
 
2,983,111

Impairments
 
6,445,375

 
 
207,938

Stock-Based Compensation Expenses
 
101,926

 
 
103,636

Deferred Income Taxes
 
(2,377,030
)
 
 
974,522

(Gains) Losses on Asset Dispositions, Net
 
5,142

 
 
(75,700
)
Other, Net
 
3,735

 
 
17,188

Dry Hole Costs
 
14,317

 
 
30,265

Mark-to-Market Commodity Derivative Contracts
 
 
 
 
 
Total Gains
 
(56,954
)
 
 
(84,119
)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts
 
661,021

 
 
(188,937
)
Excess Tax Benefits from Stock-Based Compensation
 
(24,219
)
 
 
(87,827
)
Other, Net
 
8,904

 
 
8,701

Changes in Components of Working Capital and Other Assets and Liabilities
 
 
 
 
 
Accounts Receivable
 
448,311

 
 
(341,043
)
Inventories
 
27,007

 
 
(119,166
)
Accounts Payable
 
(1,310,211
)
 
 
566,753

Accrued Taxes Payable
 
77,575

 
 
176,412

Other Assets
 
146,965

 
 
(61,966
)
Other Liabilities
 
(15,683
)
 
 
66,618

Changes in Components of Working Capital Associated with Investing and Financing Activities
 
519,203

 
 
(108,568
)
Net Cash Provided by Operating Activities
 
2,979,352

 
 
6,538,717

 
 
 
 
 
 
Investing Cash Flows
 
 
 
 
 
Additions to Oil and Gas Properties
 
(3,918,065
)
 
 
(5,653,035
)
Additions to Other Property, Plant and Equipment
 
(252,295
)
 
 
(587,178
)
Proceeds from Sales of Assets
 
144,285

 
 
91,335

Changes in Restricted Cash
 
—

 
 
(91,238
)
Changes in Components of Working Capital Associated with Investing Activities
 
(519,323
)
 
 
108,999

Net Cash Used in Investing Activities
 
(4,545,398
)
 
 
(6,131,117
)
 
 
 
 
 
 
Financing Cash Flows
 
 
 
 
 
Net Commercial Paper Borrowings
 
29,700

 
 
—

Long-Term Debt Borrowings
 
990,225

 
 
496,220

Long-Term Debt Repayments
 
(500,000
)
 
 
(500,000
)
Settlement of Foreign Currency Swap
 
—

 
 
(31,573
)
Dividends Paid
 
(274,577
)
 
 
(187,670
)
Excess Tax Benefits from Stock-Based Compensation
 
24,219

 
 
87,827

Treasury Stock Purchased
 
(43,419
)
 
 
(114,824
)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan
 
14,967

 
 
11,740

Debt Issuance Costs
 
(5,933
)
 
 
(895
)
Repayment of Capital Lease Obligation
 
(4,599
)
 
 
(4,457
)
Other, Net
 
120

 
 
(431
)
Net Cash Provided by (Used in) Financing Activities
 
230,703

 
 
(244,063
)
 
 
 
 
 
 
Effect of Exchange Rate Changes on Cash
 
(9,181
)
 
 
(601
)
 
 
 
 
 
 
Increase (Decrease) in Cash and Cash Equivalents
 
(1,344,524
)
 
 
162,936

Cash and Cash Equivalents at Beginning of Period
 
2,087,213

 
 
1,318,209

Cash and Cash Equivalents at End of Period
$
742,689

 
$
1,481,145





EOG RESOURCES, INC.
Quantitative Reconciliation of Adjusted Net Income (Non-GAAP)
to Net Income (Loss) (GAAP)
(Unaudited; in thousands, except per share data)
 
 
The following chart adjusts the three-month and nine-month periods ended September 30, 2015 and 2014 reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market gains from these transactions, to eliminate the impact of the Texas margin tax rate reduction in 2015, to eliminate the net (gains) losses on asset dispositions, to add back severance costs associated with EOG's North American operations in 2015 and to add back impairment charges related to certain of EOG's assets in 2015 and 2014. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry.
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
Reported Net Income (Loss) (GAAP)
$
(4,075,739
)
 
$
1,103,618

 
$
(4,240,219
)
 
$
2,470,899

 
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivative Contracts Impact
 
 
 
 
 
 
 
 
 
 
 
Gains on Mark-to-Market Commodity Derivative Contracts
 
(29,239
)
 
 
(469,125
)
 
 
(56,954
)
 
 
(84,119
)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts
 
99,879

 
 
(68,037
)
 
 
661,021

 
 
(188,937
)
Subtotal
 
70,640

 
 
(537,162
)
 
 
604,067

 
 
(273,056
)
 
 
 
 
 
 
 
 
 
 
 
 
After-Tax MTM Impact
 
45,457

 
 
(344,616
)
 
 
388,717

 
 
(175,179
)
 
 
 
 
 
 
 
 
 
 
 
 
Less: Texas Margin Tax Rate Reduction
 
—

 
 
—

 
 
(19,500
)
 
 
—

Less: Net (Gains) Losses on Asset Dispositions, Net of Tax
 
(3,429
)
 
 
(38,386
)
 
 
1,694

 
 
(47,426
)
Add: Severance Costs, Net of Tax
 
—

 
 
—

 
 
5,473

 
 
—

Add: Impairments of Certain Assets, Net of Tax
 
4,047,223

 
 
—

 
 
4,047,223

 
 
36,058

 
 
 
 
 
 
 
 
 
 
 
 
Adjusted Net Income (Non-GAAP)
$
13,512

 
$
720,616

 
$
183,388

 
$
2,284,352

 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss) Per Share (GAAP)
 
 
 
 
 
 
 
 
 
 
 
Basic
$
(7.47
)
 
$
2.03

 
$
(7.77
)
 
$
4.55

Diluted
$
(7.47
)
 
$
2.01

 
$
(7.77
)
 
$
4.51

 
 
 
 
 
 
 
 
 
 
 
 
Adjusted Net Income Per Share (Non-GAAP)
 
 
 
 
 
 
 
 
 
 
 
Basic
$
0.02

 
$
1.32

 
$
0.34

 
$
4.21

Diluted
$
0.02

 
$
1.31

 
$
0.33

 
$
4.17

 
 
 
 
 
 
 
 
 
 
 
 
Adjusted Net Income Per Diluted Share (Non-GAAP) - Percentage Decrease
 
-98
 %
 
 
 
 
 
-92
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average Number of Common Shares (GAAP)
 
 
 
 
 
 
 
 
 
 
 
Basic
 
545,920

 
 
543,984

 
 
545,466

 
 
543,086

Diluted
 
545,920

 
 
549,518

 
 
545,466

 
 
548,401

 
 
 
 
 
 
 
 
 
 
 
 
Average Number of Common Shares (Non-GAAP)
 
 
 
 
 
 
 
 
 
 
 
Basic
 
545,920

 
 
543,984

 
 
545,466

 
 
543,086

Diluted
 
549,434

 
 
549,518

 
 
549,414

 
 
548,401






EOG RESOURCES, INC.
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP)
to Net Cash Provided by Operating Activities (GAAP)
(Unaudited; in thousands)
 
The following chart reconciles the three-month and nine-month periods ended September 30, 2015 and 2014 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry.
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
Net Cash Provided by Operating Activities (GAAP)
$
1,131,432

 
$
2,336,469

 
$
2,979,352

 
$
6,538,717

 
 
 
 
 
 
 
 
 
 
 
 
Adjustments:
 
 
 
 
 
 
 
 
 
 
 
Exploration Costs (excluding Stock-Based Compensation Expenses)
 
25,286

 
 
42,220

 
 
95,253

 
 
119,003

Excess Tax Benefits from Stock-Based Compensation
 
7,826

 
 
24,068

 
 
24,219

 
 
87,827

Changes in Components of Working Capital and Other Assets and Liabilities
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable
 
(150,128
)
 
 
91,707

 
 
(448,311
)
 
 
341,043

Inventories
 
10,602

 
 
9,410

 
 
(27,007
)
 
 
119,166

Accounts Payable
 
310,567

 
 
(219,214
)
 
 
1,310,211

 
 
(566,753
)
Accrued Taxes Payable
 
(13,451
)
 
 
(60,744
)
 
 
(77,575
)
 
 
(176,412
)
Other Assets
 
(70,851
)
 
 
(79,487
)
 
 
(146,965
)
 
 
61,966

Other Liabilities
 
(33,165
)
 
 
(9,517
)
 
 
15,683

 
 
(66,618
)
Changes in Components of Working Capital Associated with Investing and Financing Activities
 
(349,401
)
 
 
76,924

 
 
(519,203
)
 
 
108,568

 
 
 
 
 
 
 
 
 
 
 
 
Discretionary Cash Flow (Non-GAAP)
$
868,717

 
$
2,211,836

 
$
3,205,657

 
$
6,566,507

 
 
 
 
 
 
 
 
 
 
 
 
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease
 
-61
 %
 
 
 
 
 
-51
 %
 
 
 





EOG RESOURCES, INC.
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense,
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs,
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX)
(Non-GAAP) to Income (Loss) Before Interest Expense and Income Taxes (GAAP)
(Unaudited; in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
The following chart adjusts the three-month and nine-month periods ended September 30, 2015 and 2014 reported Income (Loss) Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) gains from these transactions and to eliminate the net (gains) losses on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income (Loss) Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry.
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
 
 
Income (Loss) Before Interest Expense and Income Taxes (GAAP)
$
(6,214,350
)
 
$
1,764,824

 
$
(6,348,330
)
 
$
3,998,445

 
 
 
 
 
 
 
 
 
 
 
 
Adjustments:
 
 
 
 
 
 
 
 
 
 
 
Depreciation, Depletion and Amortization
 
722,172

 
 
1,040,018

 
 
2,544,187

 
 
2,983,111

Exploration Costs
 
31,344

 
 
48,955

 
 
114,548

 
 
139,221

Dry Hole Costs
 
198

 
 
16,359

 
 
14,317

 
 
30,265

Impairments
 
6,307,420

 
 
55,542

 
 
6,445,375

 
 
207,938

EBITDAX (Non-GAAP)
 
846,784

 
 
2,925,698

 
 
2,770,097

 
 
7,358,980

Total Gains on MTM Commodity Derivative Contracts
 
(29,239
)
 
 
(469,125
)
 
 
(56,954
)
 
 
(84,119
)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts
 
99,879

 
 
(68,037
)
 
 
661,021

 
 
(188,937
)
(Gains) Losses on Asset Dispositions, Net
 
1,185

 
 
(60,346
)
 
 
5,142

 
 
(75,700
)
 
 
 
 
 
 
 
 
 
 
 
 
Adjusted EBITDAX (Non-GAAP)
$
918,609

 
$
2,328,190

 
$
3,379,306

 
$
7,010,224

 
 
 
 
 
 
 
 
 
 
 
 
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease
 
-61
 %
 
 
 
 
 
-52
 %
 
 
 





EOG RESOURCES, INC.
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total
Capitalization (Non-GAAP) as Used in the Calculation of
the Net Debt-to-Total Capitalization Ratio (Non-GAAP) to
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP)
(Unaudited; in millions, except ratio data)
 
 
 
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry.
 
 
 
 
At
 
At
 
September 30,
 
December 31,
 
2015
 
2014
 
 
 
Total Stockholders' Equity - (a)
$
13,284

 
$
17,713

 
 
 
 
 
 
Current and Long-Term Debt (GAAP) - (b)
 
6,430

 
 
5,910

Less: Cash
 
(743
)
 
 
(2,087
)
Net Debt (Non-GAAP) - (c)
 
5,687

 
 
3,823

 
 
 
 
 
 
Total Capitalization (GAAP) - (a) + (b)
$
19,714

 
$
23,623

 
 
 
 
 
 
Total Capitalization (Non-GAAP) - (a) + (c)
$
18,971

 
$
21,536

 
 
 
 
 
 
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]
 
33
%
 
 
25
%
 
 
 
 
 
 
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]
 
30
%
 
 
18
%





EOG RESOURCES, INC.
Crude Oil and Natural Gas Financial
Commodity Derivative Contracts
 
Presented below is a comprehensive summary of EOG's crude oil and natural gas derivative contracts at November 5, 2015, with notional volumes expressed in Bbld and MMBtud and prices and premiums expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.
 
Crude Oil Price Swap Contracts
 
Weighted
 
Volume
 
Average Price
 
(Bbld)
 
($/Bbl)
2015
 
 
 
 
 
January 1, 2015 through June 30, 2015 (closed)
47,000

 
$
91.22

July 1, 2015 through October 31, 2015 (closed)
10,000

 
89.98

November 1, 2015 through December 31, 2015
10,000

 
89.98

 
 
 
 
 
 
 

Crude Oil Put Option Contracts
 
 
Volume
(Bbld)
 
Average
Premium
($/Bbl)
 
Strike
Price
($/Bbl)
2015 (1)
 
 
 
 
 
September 1, 2015 through October 31, 2015 (closed)
82,500

 
$
1.75

 
$
45.00

November 2015
82,500

 
1.75

 
45.00

 
 
 
 
 
 
 
(1)
EOG has purchased put options which establish a floor price for the sale of certain notional volumes of crude oil specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the average NYMEX West Texas Intermediate crude oil price for the contract month (Index Price), in the event the Index Price is below the put option strike price. If the Index Price is above the put option strike price, EOG is only required to pay the put option premium.

Natural Gas Price Swap Contracts
 
Weighted
 
Volume
 
Average Price
 
(MMBtud)
 
($/MMBtu)
2015 (2)
 
 
 
 
 
January 1, 2015 through February 28, 2015 (closed)
235,000

 
$
4.47

March 2015 (closed)
225,000

 
4.48

April 2015 (closed)
195,000

 
4.49

May 2015 (closed)
235,000

 
4.13

June 1, 2015 through July 31, 2015 (closed)
275,000

 
3.98

August 1, 2015 through November 30, 2015 (closed)
175,000

 
4.51

December 2015
175,000

 
4.51

 
 
(2)
EOG has entered into natural gas price swap contracts which give counterparties the option of entering into price swap contracts at future dates. All such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas price swap contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for the month of December 2015.

$/Bbl
 
Dollars per barrel
$/MMBtu
 
Dollars per million British thermal units
Bbld
 
Barrels per day
MMBtu
 
Million British thermal units
MMBtud
 
Million British thermal units per day
NYMEX
 
New York Mercantile Exchange




EOG RESOURCES, INC.
Direct After-Tax Rate of Return (ATROR)
 
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOG’s interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements.
 
Direct ATROR
Based on Cash Flow and Time Value of Money
  - Estimated future commodity prices and operating costs
  - Costs incurred to drill, complete and equip a well, including facilities
Excludes Indirect Capital
  - Gathering and Processing and other Midstream
  - Land, Seismic, Geological and Geophysical
 
Payback ~12 Months on 100% Direct ATROR Wells
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured
 
 
Return on Equity / Return on Capital Employed
Based on GAAP Accrual Accounting
Includes All Indirect Capital and Growth Capital for Infrastructure
  - Eagle Ford, Bakken, Permian Facilities
  - Gathering and Processing
Includes Legacy Gas Capital and Capital from Mature Wells





EOG RESOURCES, INC.
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP),
Net Income (GAAP), Current and Long-Term (GAAP) and Total Capitalization (GAAP), Respectively
(Unaudited; in millions, except ratio data)
 
 
 
 
 
 
The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for comparative purposes within the industry.
 
 
 
 
 
 
 
2014
 
2013
 
2012
Return on Capital Employed (ROCE) (Non-GAAP)
 
 
 
 
 
 
 
 
 
 
 
Net Interest Expense (GAAP)
$
201

 
$
235

 
 
Tax Benefit Imputed (based on 35%)
(70
)
 
(82
)
 
 
After-Tax Net Interest Expense (Non-GAAP) - (a)
$
131

 
$
153

 
 
 
 
 
 
 
 
Net Income (GAAP) - (b)
$
2,915

 
$
2,197

 
 
 
 
 
 
 
 
Add: After-Tax Mark-to-Market Commodity Derivative Contracts Impact
(515
)
 
182

 
 
Add: Impairments of Certain Assets, Net of Tax
553

 
4

 
 
Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years
250

 
—

 
 
Less: Net Gains on Asset Dispositions, Net of Tax
(487
)
 
(137
)
 
 
 
 
 
 
 
 
Adjusted Net Income (Non-GAAP) - (c)
$
2,716

 
$
2,246

 
 
 
 
 
 
 
 
Total Stockholders' Equity - (d)
$
17,713

 
$
15,418

 
$
13,285

 
 
 
 
 
 
Average Total Stockholders' Equity * - (e)
$
16,566

 
$
14,352

 
 
 
 
 
 
 
 
Current and Long-Term Debt (GAAP) - (f)
$
5,910

 
$
5,913

 
$
6,312

Less: Cash
(2,087
)
 
(1,318
)
 
(876
)
Net Debt (Non-GAAP) - (g)
$
3,823

 
$
4,595

 
$
5,436

 
 
 
 
 
 
Total Capitalization (GAAP) - (d) + (f)
$
23,623

 
$
21,331

 
$
19,597

 
 
 
 
 
 
Total Capitalization (Non-GAAP) - (d) + (g)
$
21,536

 
$
20,013

 
$
18,721

 
 
 
 
 
 
Average Total Capitalization (Non-GAAP) * - (h)
$
20,775

 
$
19,367

 
 
 
 
 
 
 
 
ROCE (GAAP Net Income) - [(a) + (b)] / (h)
14.7
%
 
12.1
%
 
 
 
 
 
 
 
 
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h)
13.7
%
 
12.4
%
 
 
 
 
 
 
 
 
Return on Equity (ROE) (Non-GAAP)
 
 
 
 
 
 
 
 
 
 
 
ROE (GAAP Net Income) - (b) / (e)
17.6
%
 
15.3
%
 
 
 
 
 
 
 
 
ROE (Non-GAAP Adjusted Net Income) - (c) / (e)
16.4
%
 
15.6
%
 
 
 
 
 
 
 
 
* Average for the current and immediately preceding year
 
 
 
 
 





EOG RESOURCES, INC.
Fourth Quarter and Full Year 2015 Forecast and Benchmark Commodity Pricing
 
(a) Fourth Quarter and Full Year 2015 Forecast
 
The forecast items for the fourth quarter and full year 2015 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.
 
(b) Benchmark Commodity Pricing
 
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.
 
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.
 
 
 
Estimated Ranges
(Unaudited)
 
 
4Q 2015
 
 
Full Year 2015
Daily Production
 
 
 
 
 
 
 
 
 
 
 
Crude Oil and Condensate Volumes (MBbld)
 
 
 
 
 
 
 
 
 
 
 
United States
 
274.0

-
 
280.0

 
 
281.8

-
 
283.3

Trinidad
 
0.8

-
 
1.0

 
 
0.8

-
 
1.0

Other International
 
0.0

-
 
5.0

 
 
0.1

-
 
1.4

Total
 
274.8

-
 
286.0

 
 
282.7

-
 
285.7

 
Natural Gas Liquids Volumes (MBbld)
 
 
 
 
 
 
 
 
 
 
 
Total
 
72.0

-
 
78.0

 
 
75.2

-
 
76.7

 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas Volumes (MMcfd)
 
 
 
 
 
 
 
 
 
 
 
United States
 
840

-
 
880

 
 
881

-
 
891

Trinidad
 
350

-
 
370

 
 
344

-
 
349

Other International
 
24

-
 
30

 
 
29

-
 
31

Total
 
1,214

-
 
1,280

 
 
1,254

-
 
1,271

 
Crude Oil Equivalent Volumes (MBoed)
 
 
 
 
 
 
 
 
 
 
 
United States
 
486.0

-
 
504.7

 
 
503.8

-
 
508.5

Trinidad
 
59.1

-
 
62.7

 
 
58.1

-
 
59.2

Other International
 
4.0

-
 
10.0

 
 
4.9

-
 
6.6

Total
 
549.1

-
 
577.4

 
 
566.8

-
 
574.3

 




 
Estimated Ranges
(Unaudited)
 
4Q 2015
 
Full Year 2015
Operating Costs
 
 
 
 
 
 
 
 
 
 
 
Unit Costs ($/Boe)
 
 
 
 
 
 
 
 
 
 
 
Lease and Well
$
5.30

-
$
6.10

 
$
5.79

-
$
5.99

Transportation Costs
$
3.80

-
$
4.70

 
$
4.02

-
$
4.24

Depreciation, Depletion and Amortization
$
14.50

-
$
15.50

 
$
15.79

-
$
16.02

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expenses ($MM)
 
 
 
 
 
 
 
 
 
 
 
Exploration, Dry Hole and Impairment (A)
$
140

-
$
160

 
$
501

-
$
521

General and Administrative
$
90

-
$
98

 
$
348

-
$
356

Gathering and Processing
$
32

-
$
36

 
$
139

-
$
143

Capitalized Interest
$
10

-
$
11

 
$
43

-
$
44

Net Interest
$
59

-
$
60

 
$
233

-
$
234

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Taxes Other Than Income (% of Wellhead Revenue)
 
6.2
%
-
 
6.6
%
 
 
6.5
%
-
 
6.7
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes
 
 
 
 
 
 
 
 
 
 
 
Effective Rate
 
5
%
-
 
15
%
 
 
33
%
-
 
36
%
Current Taxes ($MM)
$
15

-
$
30

 
$
110

-
$
125

 
 
 
 
 
 
 
 
 
 
 
 
Capital Expenditures (Excluding Acquisitions, $MM)
 
 
 
 
 
 
 
 
 
 
 
Exploration and Development, Excluding Facilities
 
 
 
 
 
 
$
3,700

-
$
3,800

Exploration and Development Facilities
 
 
 
 
 
 
$
725

-
$
775

Gathering, Processing and Other
 
 
 
 
 
 
$
275

-
$
325

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pricing - (Refer to Benchmark Commodity Pricing in text)
 
 
 
 
 
 
 
 
 
 
 
Crude Oil and Condensate ($/Bbl)
 
 
 
 
 
 
 
 
 
 
 
Differentials
 
 
 
 
 
 
 
 
 
 
 
United States - above (below) WTI
$
(2.00
)
-
$
0.00

 
$
(1.27
)
-
$
(0.78
)
Trinidad - above (below) WTI
$
(10.50
)
-
$
(9.50
)
 
$
(9.25
)
-
$
(9.00
)
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas Liquids
 
 
 
 
 
 
 
 
 
 
 
Realizations as % of WTI
 
27
%
-
 
31
%
 
 
29
%
-
 
30
%
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas ($/Mcf)
 
 
 
 
 
 
 
 
 
 
 
Differentials
 
 
 
 
 
 
 
 
 
 
 
United States - above (below) NYMEX Henry Hub
$
(0.90
)
-
$
(0.45
)
 
$
(0.71
)
-
$
(0.60
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Realizations
 
 
 
 
 
 
 
 
 
 
 
Trinidad
$
2.40

-
$
2.90

 
$
2.85

-
$
2.98

Other International
$
3.25

-
$
3.75

 
$
4.31

-
$
4.42

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




Definitions
 
 
 
 
 
 
 
 
 
 
 
$/Bbl
 
U.S. Dollars per barrel
 
 
 
 
 
 
 
 
 
 
 
$/Boe
 
U.S. Dollars per barrel of oil equivalent
 
 
 
 
 
 
 
 
 
 
 
$/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