EOG
$94.92
Eog Resources
$1.54
1.65%
Earnings Details
4th Quarter December 2016
Monday, February 27, 2017 4:20:00 PM
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Summary

Eog Resources (EOG) Recent Earnings

Eog Resources (EOG) reported a 4th Quarter December 2016 loss of $0.01 per share on revenue of $2.4 billion. The consensus estimate was a loss of $0.16 per share on revenue of $2.1 billion. Revenue grew 33.7% on a year-over-year basis.

EOG Resources Inc explores for, develops, produces and markets crude oil and natural gas in the USA, Trinidad, United Kingdom, China, Argentina and, from time to time, select other international areas.

Results
Reported Earnings
($0.01)
Earnings Whisper
-
Consensus Estimate
($0.16)
Reported Revenue
$2.40 Bil
Revenue Estimate
$2.07 Bil
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

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

Exceeds High-end of Fourth Quarter and Full Year 2016 Crude Oil Production Targets

Beats Fourth Quarter and Full Year 2016 Targets for Lease and Well, Transportation and DD&A Expenses

-- Achieves Record Capital Efficiency Gains in 2016

Replaces 163 Percent of 2016 Production at Low Finding Cost of $5.22/Boe (Excluding Price Revisions) and Increases Total Net Proved Reserves by 1.4 Percent in 2016

-- Targets 18 Percent Crude Oil Production Growth for 2017 within Cash Flow at Flat $50 Oil

-- Forecasts Flat to Lower Well Costs in 2017

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG’s future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG’s management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG’s future operating results and returns or EOG’s ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG’s forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG’s control. Important factors that could cause EOG’s actual results to differ materially from the expectations reflected in EOG’s forward-looking statements include, among others:

the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;

the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;

the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;

the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities;

the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral licenses and leases;

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

EOG’s ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;

the extent to which EOG’s third-party-operated crude oil and natural gas properties are operated successfully and economically;

competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;

the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;

the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;

the ability of EOG’s customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;

EOG’s ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;

-- the extent to which EOG is successful in its completion of planned asset dispositions;

-- the extent and effect of any hedging activities engaged in by EOG;

the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;

political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;

-- the use of competing energy sources and the development of alternative energy sources;

the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;

-- acts of war and terrorism and responses to these acts;

-- physical, electronic and cyber security breaches; and

the other factors described under ITEM 1A, Risk Factors, on pages 13 through 22 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, and any updates to those factors set forth in EOG’s subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

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

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

For Further Information Contact: Investors
Cedric W. Burgher
(713) 571-4658
David J. Streit
(713) 571-4902
W. John Wagner
(713) 571-4404
Media and Investors
Kimberly M. Ehmer
(713) 571-4676
EOG RESOURCES, INC.
Financial Report
(Unaudited; in millions, except per share data)
Three Months Ended
Twelve Months Ended
December 31,
December 31,
2016
2015
2016
2015
Net Operating Revenues
$
2,402.0
$
1,796.8
$
7,650.6
$
8,757.4
Net Loss
$
(142.4)
$
(284.3)
$
(1,096.7)
$
(4,524.5)
Net Loss Per Share
Basic
$
(0.25)
$
(0.52)
$
(1.98)
$
(8.29)
Diluted
$
(0.25)
$
(0.52)
$
(1.98)
$
(8.29)
Average Number of Common Shares
Basic
567.3
546.4
553.4
545.7
Diluted
567.3
546.4
553.4
545.7
Summary Income Statements
(Unaudited; in thousands, except per share data)
Three Months Ended
Twelve Months Ended
December 31,
December 31,
2016
2015
2016
2015
Net Operating Revenues
Crude Oil and Condensate
$
1,366,223
$
1,040,470
$
4,317,341
$
4,934,562
Natural Gas Liquids
137,849
96,521
437,250
407,658
Natural Gas
215,373
217,381
742,152
1,061,038
Gains (Losses) on Mark-to-Market Commodity
(65,787)
4,970
(99,608)
61,924
Derivative Contracts
Gathering, Processing and Marketing
614,594
432,292
1,966,259
2,253,135
Gains (Losses) on Asset Dispositions, Net
104,034
(3,656)
205,835
(8,798)
Other, Net
29,753
8,783
81,403
47,909
Total
2,402,039
1,796,761
7,650,632
8,757,428
Operating Expenses
Lease and Well
241,846
247,916
927,452
1,182,282
Transportation Costs
193,319
207,580
764,106
849,319
Gathering and Processing Costs
32,516
39,653
122,901
146,156
Exploration Costs
39,110
34,946
124,953
149,494
Dry Hole Costs
193
429
10,657
14,746
Impairments
297,946
168,171
620,267
6,613,546
Marketing Costs
634,248
461,848
2,007,635
2,385,982
Depreciation, Depletion and Amortization
862,524
769,457
3,553,417
3,313,644
General and Administrative
102,182
109,014
394,815
366,594
Taxes Other Than Income
103,642
87,500
349,710
421,744
Total
2,507,526
2,126,514
8,875,913
15,443,507
Operating Loss
(105,487)
(329,753)
(1,225,281)
(6,686,079)
Other (Expense) Income, Net
(17,198)
(6,080)
(50,543)
1,916
Loss Before Interest Expense and Income Taxes
(122,685)
(335,833)
(1,275,824)
(6,684,163)
Interest Expense, Net
71,325
62,993
281,681
237,393
Loss Before Income Taxes
(194,010)
(398,826)
(1,557,505)
(6,921,556)
Income Tax Benefit
(51,658)
(114,530)
(460,819)
(2,397,041)
Net Loss
$
(142,352)
$
(284,296)
$
(1,096,686)
$
(4,524,515)
Dividends Declared per Common Share
$
0.1675
$
0.1675
$
0.6700
$
0.6700
EOG RESOURCES, INC.
Operating Highlights
(Unaudited)
Three Months Ended
Twelve Months Ended
December 31,
December 31,
2016
2015
2016
2015
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) (A)
United States
306.0
279.9
278.3
283.3
Trinidad
0.9
0.9
0.8
0.9
Other International (B)
4.8
0.2
3.4
0.2
Total
311.7
281.0
282.5
284.4
Average Crude Oil and Condensate Prices ($/Bbl) (C)
United States
$
47.93
$
40.34
$
41.84
$
47.55
Trinidad
40.04
32.38
33.76
39.51
Other International (B)
38.96
53.28
36.72
57.32
Composite
47.76
40.32
41.76
47.53
Natural Gas Liquids Volumes (MBbld) (A)
United States
80.9
79.1
81.6
76.9
Other International (B)
-
-
-
0.1
Total
80.9
79.1
81.6
77.0
Average Natural Gas Liquids Prices ($/Bbl) (C)
United States
$
18.51
$
13.25
$
14.63
$
14.50
Other International (B)
-
-
-
4.61
Composite
18.51
13.25
14.63
14.49
Natural Gas Volumes (MMcfd) (A)
United States
800
860
810
886
Trinidad
323
370
340
349
Other International (B)
22
27
25
30
Total
1,145
1,257
1,175
1,265
Average Natural Gas Prices ($/Mcf) (C)
United States
$
2.05
$
1.44
$
1.60
$
1.97
Trinidad
1.89
2.57
1.88
2.89
Other International (B)
3.85
6.51
3.64
5.05
Composite
2.04
1.88
1.73
2.30
Crude Oil Equivalent Volumes (MBoed) (D)
United States
520.3
502.2
494.9
507.9
Trinidad
54.6
62.7
57.5
59.1
Other International (B)
8.6
4.6
7.6
5.2
Total
583.5
569.5
560.0
572.2
Total MMBoe (D)
53.7
52.4
205.0
208.9
(A) Thousand barrels per day or million cubic feet per day, as applicable.
(B) Other International includes EOG’s United Kingdom, China, Canada and Argentina operations.
The Argentina operations were sold in the third quarter of 2016.
(C) Dollars per barrel or per thousand cubic feet, as applicable.
Excludes the impact of financial commodity derivative instruments.
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas.
Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas.
MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.
EOG RESOURCES, INC.
Summary Balance Sheets
(Unaudited; in thousands, except share data)
December 31,
December 31,
2016
2015
ASSETS
Current Assets
Cash and Cash Equivalents
$
1,599,895
$
718,506
Accounts Receivable, Net
1,216,320
930,610
Inventories
350,017
598,935
Income Taxes Receivable
12,305
40,704
Deferred Income Taxes
169,387
147,812
Other
206,679
155,677
Total
3,554,603
2,592,244
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)
49,592,091
50,613,241
Other Property, Plant and Equipment
4,008,564
3,986,610
Total Property, Plant and Equipment
53,600,655
54,599,851
Less:
Accumulated Depreciation, Depletion and Amortization
(27,893,577)
(30,389,130)
Total Property, Plant and Equipment, Net
25,707,078
24,210,721
Other Assets
197,752
167,505
Total Assets
$
29,459,433
$
26,970,470
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable
$
1,511,826
$
1,471,953
Accrued Taxes Payable
118,411
93,618
Dividends Payable
96,120
91,546
Liabilities from Price Risk Management Activities
61,817
-
Current Portion of Long-Term Debt
6,579
6,579
Other
232,538
155,591
Total
2,027,291
1,819,287
Long-Term Debt
6,979,779
6,648,911
Other Liabilities
1,282,142
971,335
Deferred Income Taxes
5,188,640
4,587,902
Commitments and Contingencies
Stockholders’ Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
205,770
205,502
576,950,272 Shares and 550,150,823 Shares Issued at December 31,
2016 and 2015, respectively
Additional Paid in Capital
5,420,385
2,923,461
Accumulated Other Comprehensive Loss
(19,010)
(33,338)
Retained Earnings
8,398,118
9,870,816
Common Stock Held in Treasury, 250,155 Shares and 292,179 Shares at
(23,682)
(23,406)
December 31, 2016 and 2015, respectively
Total Stockholders’ Equity
13,981,581
12,943,035
Total Liabilities and Stockholders’ Equity
$
29,459,433
$
26,970,470
EOG RESOURCES, INC.
Summary Statements of Cash Flows
(Unaudited; in thousands)
Twelve Months Ended
December 31,
2016
2015
Cash Flows from Operating Activities
Reconciliation of Net Loss to Net Cash Provided by Operating Activities:
Net Loss
$
(1,096,686)
$
(4,524,515)
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization
3,553,417
3,313,644
Impairments
620,267
6,613,546
Stock-Based Compensation Expenses
128,090
130,577
Deferred Income Taxes
(515,206)
(2,482,307)
(Gains) Losses on Asset Dispositions, Net
(205,835)
8,798
Other, Net
61,690
11,896
Dry Hole Costs
10,657
14,746
Mark-to-Market Commodity Derivative Contracts
Total Losses (Gains)
99,608
(61,924)
Net Cash (Payments for) Received from Settlements of Commodity Derivative Contracts
(22,219)
730,114
Excess Tax Benefits from Stock-Based Compensation
(29,357)
(26,058)
Other, Net
10,971
12,532
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable
(232,799)
641,412
Inventories
170,694
58,450
Accounts Payable
(74,048)
(1,409,197)
Accrued Taxes Payable
92,782
11,798
Other Assets
(40,636)
118,143
Other Liabilities
(16,225)
(66,257)
Changes in Components of Working Capital Associated with Investing and Financing
(156,102)
499,767
Activities
Net Cash Provided by Operating Activities
2,359,063
3,595,165
Investing Cash Flows
Additions to Oil and Gas Properties
(2,489,756)
(4,725,150)
Additions to Other Property, Plant and Equipment
(93,039)
(288,013)
Proceeds from Sales of Assets
1,119,215
192,807
Net Cash Received from Yates Acquisition
54,534
-
Changes in Components of Working Capital Associated with Investing Activities
156,102
(499,900)
Net Cash Used in Investing Activities
(1,252,944)
(5,320,256)
Financing Cash Flows
Net Commercial Paper (Repayments) Borrowings
(259,718)
259,718
Long-Term Debt Borrowings
991,097
990,225
Long-Term Debt Repayments
(563,829)
(500,000)
Dividends Paid
(372,845)
(367,005)
Excess Tax Benefits from Stock-Based Compensation
29,357
26,058
Treasury Stock Purchased
(82,125)
(48,791)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan
23,296
22,690
Debt Issuance Costs
(1,602)
(5,951)
Repayment of Capital Lease Obligation
(6,353)
(6,156)
Other, Net
-
133
Net Cash (Used in) Provided by Financing Activities
(242,722)
370,921
Effect of Exchange Rate Changes on Cash
17,992
(14,537)
Increase (Decrease) in Cash and Cash Equivalents
881,389
(1,368,707)
Cash and Cash Equivalents at Beginning of Period
718,506
2,087,213
Cash and Cash Equivalents at End of Period
$
1,599,895
$
718,506
EOG RESOURCES, INC.
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP)
To Net Loss (GAAP)
(Unaudited; in thousands, except per share data)
The following chart adjusts the three-month and twelve-month periods ended December 31, 2016 and 2015 reported Net Loss (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2016 and 2015, to add back impairment charges related to certain of EOG’s assets in 2016 and 2015, to add back an early leasehold termination payment as the result of a legal settlement in 2015, to eliminate the impact of the Texas margin tax rate reduction in 2015, to add back severance costs associated with EOG’s North American operations in 2015, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, and to add back acquisition costs and state apportionment change related to the Yates transaction in 2016.
EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items.
EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.
Three Months Ended
Three Months Ended
December 31, 2016
December 31, 2015
Income
Diluted
Income
Diluted
Before
Tax
After
Earnings
Before
Tax
After
Earnings
Tax
Impact
Tax
per Share
Tax
Impact
Tax
per Share
Reported Net Loss (GAAP)
$
(194,010)
$
51,658
$
(142,352)
$
(0.25)
$
(398,826)
$
114,530
$
(284,296)
$
(0.52)
Adjustments:
(Gains) Losses on Mark-to-Market Commodity
65,787
(23,583)
42,204
0.07
(4,970)
1,772
(3,198)
(0.01)
Derivative Contracts
Net Cash Received from Settlements of
-
29
29
-
69,093
(24,632)
44,461
0.08
Commodity Derivative Contracts
Add: Net (Gains) Losses on Asset Dispositions
(104,034)
36,856
(67,178)
(0.12)
3,656
(735)
2,921
0.01
Add:
Impairments
217,839
(76,728)
141,111
0.25
94,484
(16,335)
78,149
0.15
Add:
Legal Settlement - Early Leasehold Termination
-
-
-
-
19,355
(6,900)
12,455
0.02
Add:
Voluntary Retirement Expense
-
(57)
(57)
-
-
-
-
-
Add:
Acquisition - State Apportionment Change
-
16,424
16,424
0.03
-
-
-
-
Add:
Acquisition Costs
2,173
955
3,128
0.01
-
-
-
-
Adjustments to Net Income (Loss)
181,765
(46,104)
135,661
0.24
181,618
(46,830)
134,788
0.25
Adjusted Net Income (Loss) (Non-GAAP)
$
(12,245)
$
5,554
$
(6,691)
$
(0.01)
$
(217,208)
$
67,700
$
(149,508)
$
(0.27)
Average Number of Common Shares (GAAP)
Basic
567,337
546,432
Diluted
567,337
546,432
Average Number of Common Shares (Non-GAAP)
Basic
567,337
546,432
Diluted
567,337
546,432
Twelve Months Ended
Twelve Months Ended
December 31, 2016
December 31, 2015
Income
Diluted
Income
Diluted
Before
Tax
After
Earnings
Before
Tax
After
Earnings
Tax
Impact
Tax
per Share
Tax
Impact
Tax
per Share
Reported Net Loss (GAAP)
$(1,557,505)
$460,819
$(1,096,686)
$
(1.98)
$(6,921,556)
$2,397,041
$(4,524,515)
$
(8.29)
Adjustments:
(Gains) Losses on Mark-to-Market Commodity
99,608
(35,640)
63,968
0.12
(61,924)
22,076
(39,848)
(0.07)
Derivative Contracts
Net Cash Received from (Payments for)
(22,219)
7,950
(14,269)
(0.03)
730,114
(260,286)
469,828
0.86
Settlements of Commodity Derivative
Contracts
Add: Net (Gains) Losses on Asset Dispositions
(205,835)
61,491
(144,344)
(0.26)
8,798
(4,183)
4,615
0.01
Add:
Impairments
320,617
(113,368)
207,249
0.37
6,307,592
(2,182,220)
4,125,372
7.56
Add:
Legal Settlement - Early Leasehold Termination
-
-
-
-
19,355
(6,900)
12,455
0.02
Less: Texas Margin Tax Rate Reduction
-
-
-
-
-
(19,500)
(19,500)
(0.04)
Add:
Severance Costs
-
-
-
-
8,505
(3,032)
5,473
0.01
Add:
Trinidad Tax Settlement
-
43,000
43,000
0.08
-
-
-
-
Add:
Voluntary Retirement Expense
42,054
(15,047)
27,007
0.05
-
-
-
-
Add:
Acquisition - State Apportionment Change
-
16,424
16,424
0.03
-
-
-
-
Add:
Acquisition Costs
5,100
(88)
5,012
0.01
-
-
-
-
Adjustments to Net Income (Loss)
239,325
(35,278)
204,047
0.37
7,012,440
(2,454,045)
4,558,395
8.35
Adjusted Net Income (Loss) (Non-GAAP)
$(1,318,180)
$425,541
$
(892,639)
$
(1.61)
$
90,884
$
(57,004)
$
33,880
$
0.06
Average Number of Common Shares (GAAP)
Basic
553,384
545,697
Diluted
553,384
545,697
Average Number of Common Shares (Non-GAAP)
Basic
553,384
545,697
Diluted
553,384
549,610
EOG RESOURCES, INC.
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP)
To Net Cash Provided By Operating Activities (GAAP)
(Unaudited; in thousands)
The following chart reconciles the three-month and twelve-month periods ended December 31, 2016 and 2015 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP).
EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities.
EOG management uses this information for comparative purposes within the industry.
Three Months Ended
Twelve Months Ended
December 31,
December 31,
2016
2015
2016
2015
Net Cash Provided by Operating Activities (GAAP)
$
804,745
$
615,813
$
2,359,063
$
3,595,165
Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)
33,931
28,758
104,199
124,011
Excess Tax Benefits from Stock-Based Compensation
7,286
1,839
29,357
26,058
Changes in Components of Working Capital and Other Assets
and Liabilities
Accounts Receivable
220,939
(193,101)
232,799
(641,412)
Inventories
(33,131)
(31,443)
(170,694)
(58,450)
Accounts Payable
(127,165)
98,986
74,048
1,409,197
Accrued Taxes Payable
21,214
65,777
(92,782)
(11,798)
Other Assets
28,110
28,822
40,636
(118,143)
Other Liabilities
53,024
50,574
16,225
66,257
Changes in Components of Working Capital Associated with
36,342
19,436
156,102
(499,767)
Investing and Financing Activities
Discretionary Cash Flow (Non-GAAP)
$
1,045,295
$
685,461
$
2,748,953
$
3,891,118
Discretionary Cash Flow (Non-GAAP) - Percentage Increase/Decrease
52%
-29%
EOG RESOURCES, INC.
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense,
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs,
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX)
(Non-GAAP) to Net Loss (GAAP)
(Unaudited; in thousands)
The following chart adjusts the three-month and twelve-month periods ended December 31, 2016 and 2015 reported Net Loss (GAAP) to Earnings Before Interest Expense, Income Taxes (Income Tax Benefit), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions.
EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense, Income Taxes (Income Tax Benefit), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items.
EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.
Three Months Ended
Twelve Months Ended
December 31,
December 31,
2016
2015
2016
2015
Net Loss (GAAP)
$
(142,352)
$
(284,296)
$
(1,096,686)
$
(4,524,515)
Adjustments:
Interest Expense, Net
71,325
62,993
281,681
237,393
Income Tax Benefit
(51,658)
(114,530)
(460,819)
(2,397,041)
Depreciation, Depletion and Amortization
862,524
769,457
3,553,417
3,313,644
Exploration Costs
39,110
34,946
124,953
149,494
Dry Hole Costs
193
429
10,657
14,746
Impairments
297,946
168,171
620,267
6,613,546
EBITDAX (Non-GAAP)
1,077,088
637,170
3,033,470
3,407,267
Total (Gains) Losses on MTM Commodity Derivative Contracts
65,787
(4,970)
99,608
(61,924)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts
-
69,093
(22,219)
730,114
(Gains) Losses on Asset Dispositions, Net
(104,034)
3,656
(205,835)
8,798
Adjusted EBITDAX (Non-GAAP)
$
1,038,841
$
704,949
$
2,905,024
$
4,084,255
Adjusted EBITDAX (Non-GAAP) - Percentage Increase/Decrease
47%
-29%
EOG RESOURCES, INC.
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total
Capitalization (Non-GAAP) as Used in the Calculation of
the Net Debt-to-Total Capitalization Ratio (Non-GAAP) to
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP)
(Unaudited; in millions, except ratio data)
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation.
A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown.
EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation.
EOG management uses this information for comparative purposes within the industry.
At
At
December 31,
December 31,
2016
2015
Total Stockholders’ Equity - (a)
$
13,982
$
12,943
Current and Long-Term Debt (GAAP) - (b)
6,986
6,655
Less: Cash
(1,600)
(719)
Net Debt (Non-GAAP) - (c)
5,386
5,936
Total Capitalization (GAAP) - (a) + (b)
$
20,968
$
19,598
Total Capitalization (Non-GAAP) - (a) + (c)
$
19,368
$
18,879
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]
33%
34%
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]
28%
31%
EOG RESOURCES, INC.
Reserves Supplemental Data
(Unaudited)
2016 NET PROVED RESERVES RECONCILIATION SUMMARY
United
Other
States
Trinidad
International
Total
CRUDE OIL & CONDENSATE (MMBbl)
Beginning Reserves
1,087.9
1.1
8.6
1,097.6
Revisions
42.0
-
0.9
42.9
Purchases in place
25.8
-
-
25.8
Extensions, discoveries and other additions
123.4
-
-
123.4
Sales in place
(8.7)
-
-
(8.7)
Production
(101.9)
(0.3)
(1.2)
(103.4)
Ending Reserves
1,168.5
0.8
8.3
1,177.6
NATURAL GAS LIQUIDS (MMBbl)
Beginning Reserves
382.9
-
-
382.9
Revisions
53.7
-
-
53.7
Purchases in place
1.3
-
-
1.3
Extensions, discoveries and other additions
41.9
-
-
41.9
Sales in place
(33.5)
-
-
(33.5)
Production
(29.9)
-
-
(29.9)
Ending Reserves
416.4
-
-
416.4
NATURAL GAS (Bcf)
Beginning Reserves
3,489.8
316.6
19.5
3,825.9
Revisions
298.4
29.5
5.2
333.1
Purchases in place
91.5
-
-
91.5
Extensions, discoveries and other additions
202.1
59.9
-
262.0
Sales in place
(752.0)
-
-
(752.0)
Production
(308.6)
(125.1)
(8.9)
(442.6)
Ending Reserves
3,021.2
280.9
15.8
3,317.9
OIL EQUIVALENTS (MMBoe)
Beginning Reserves
2,052.3
53.8
12.0
2,118.1
Revisions
145.5
5.0
1.7
152.2
Purchases in place
42.3
-
-
42.3
Extensions, discoveries and other additions
199.0
10.0
-
209.0
Sales in place
(167.6)
-
-
(167.6)
Production
(183.2)
(21.1)
(2.8)
(207.1)
Ending Reserves
2,088.3
47.7
10.9
2,146.9
Net Proved Developed Reserves (MMBoe)
At December 31, 2015
1,018.5
50.7
3.3
1,072.5
At December 31, 2016
1,038.5
44.5
10.9
1,093.9
2016 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions)
United
Other
States
Trinidad
International
Total
Acquisition Cost of Unproved Properties
$3,216.6
$
-
$
-
$3,216.6
Exploration Costs
156.3
2.7
6.8
165.8
Development Costs
2,228.0
75.4
30.3
2,333.7
Total Drilling
5,600.9
78.1
37.1
5,716.1
Acquisition Cost of Proved Properties
749.0
-
-
749.0
Total Exploration & Development Expenditures
6,349.9
78.1
37.1
6,465.1
Gathering, Processing and Other
108.6
-
0.2
108.8
Asset Retirement Costs
24.7
(3.2)
(41.4)
(19.9)
Total Expenditures
6,483.2
74.9
(4.1)
6,554.0
Proceeds from Sales in Place
(1,109.4)
-
(9.2)
(1,118.6)
Net Expenditures
$5,373.8
$
74.9
$
(13.3)
$5,435.4
RESERVE REPLACEMENT COSTS ($ / Boe ) *
All-in Total, Net of Revisions
$
6.50
$
5.21
$
21.82
$
6.52
All-in Total, Excluding Revisions Due to Price $
5.14
$
6.05
$
21.82
$
5.22
RESERVE REPLACEMENT *
Drilling Only
109%
47%
0%
101%
All-in Total, Net of Revisions & Dispositions
120%
71%
61%
114%
All-in Total, Excluding Revisions Due to Price 176%
61%
61%
163%
All-in Total, Liquids
187%
0%
75%
185%
*
See attached reconciliation schedule for calculation methodology
EOG RESOURCES, INC.
Quantitative Reconciliation of Total Exploration and Development Expenditures (Non-GAAP)
As Used in the Calculation of Reserve Replacement Costs ($ / BOE)
To Total Costs Incurred in Exploration and Development Activities (GAAP)
(Unaudited; in millions, except ratio information)
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe.
There are numerous ways that industry participants present Reserve Replacement Costs, including an
"All-In" calculation, which reflects total exploration and development expenditures divided by total net proved reserve additions from all sources.
Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program.
Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry.
Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures.
Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs.
EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures.
For the Twelve Months Ended December 31, 2016
United
Other
States
Trinidad
International
Total
Total Costs Incurred in Exploration and Development Activities (GAAP)
$ 6,374.6
$
74.9
$
(4.3)
$
6,445.2
Less:
Asset Retirement Costs
(24.7)
3.2
41.4
19.9
Non-Cash Acquisition Costs of Unproved Properties
(3,101.8)
-
-
(3,101.8)
Non-Cash Acquisition Costs of Proved Properties
(732.3)
-
-
(732.3)
Total Exploration & Development Expenditures (Non-GAAP) (a)
$ 2,515.8
$
78.1
$
37.1
$
2,631.0
Total Expenditures (GAAP)
$ 6,483.2
$
74.9
$
(4.1)
$
6,554.0
Less:
Asset Retirement Costs
(24.7)
3.2
41.4
19.9
Non-Cash Acquisition Costs of Unproved Properties
(3,101.8)
-
-
(3,101.8)
Non-Cash Acquisition Costs of Proved Properties
(732.3)
-
-
(732.3)
Non-Cash Acquisition Costs of Other Assets
(16.6)
-
-
(16.6)
Total Cash Expenditures (Non-GAAP)
$ 2,607.8
$
78.1
$
37.3
$
2,723.2
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions due to price (b)
(102.8)
2.1
-
(100.7)
Revisions other than price
248.3
2.9
1.7
252.9
Purchases in place
42.3
-
-
42.3
Extensions, discoveries and other additions (c)
199.0
10.0
-
209.0
Total Proved Reserve Additions (d)
386.8
15.0
1.7
403.5
Sales in place
(167.6)
-
-
(167.6)
Net Proved Reserve Additions From All Sources (e)
219.2
15.0
1.7
235.9
Production (f)
183.2
21.1
2.8
207.1
RESERVE REPLACEMENT COSTS ($ / Boe)
All-in Total, Net of Revisions (a / d)
$
6.50
$
5.21
$
21.82
$
6.52
All-in Total, Excluding Revisions Due to Price (a / (d - b))
$
5.14
$
6.05
$
21.82
$
5.22
RESERVE REPLACEMENT
Drilling Only (c / f)
109%
47%
0%
101%
All-in Total, Net of Revisions & Dispositions (e / f)
120%
71%
61%
114%
All-in Total, Excluding Revisions Due to Price ((e - b ) / f)
176%
61%
61%
163%
Net Proved Reserve Additions From All Sources - Liquids (MMBbls)
Revisions
95.7
-
0.9
96.6
Purchases in place
27.1
-
-
27.1
Extensions, discoveries and other additions (g)
165.3
-
-
165.3
Total Proved Reserve Additions
288.1
-
0.9
289.0
Sales in place
(42.2)
-
-
(42.2)
Net Proved Reserve Additions From All Sources (h)
245.9
-
0.9
246.8
Production (i)
131.8
0.3
1.2
133.3
RESERVE REPLACEMENT - LIQUIDS
Drilling Only (g / i)
125%
0%
0%
124%
All-in Total, Net of Revisions & Dispositions (h / i)
187%
0%
75%
185%
EOG RESOURCES, INC.
Quantitative Reconciliation of Drillbit Exploration and Development Expenditures (Non-GAAP)
As Used in the Calculation of Proved Developed Reserve Replacement Costs ($ / BOE)
To Total Costs Incurred in Exploration and Development Activities (GAAP)
(Unaudited; in millions, except ratio information)
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Drillbit Exploration and Development Expenditures
(Non-GAAP), as used in the calculation of Proved Developed Reserve Replacement Costs per Boe.
These statistics provide management and investors with an indication of the results of the current year capital investment program.
Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry.
For the Twelve Months Ended December 31, 2016
Total
PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe)
Total Costs Incurred in Exploration and Development Activities (GAAP)
$
6,445.2
Less:
Asset Retirement Costs
19.9
Acquisition Costs of Unproved Properties
(3,216.6)
Acquisition Cost of Proved Properties
(749.0)
Drillbit Exploration & Development Expenditures (Non-GAAP) (j)
$
2,499.5
Total Proved Reserves - Extensions, discoveries and other additions (MMBoe)
209.0
Add: Conversion of proved undeveloped reserves to proved developed
149.2
Less: Proved undeveloped extensions and discoveries
(138.1)
Proved Developed Reserves - Extensions and discoveries (MMBoe)
220.1
Total Proved Reserves - Revisions (MMBoe)
152.2
Less: Proved Undeveloped Reserves - Revisions
(64.4)
Proved Developed - Revisions due to price
76.7
Proved Developed Reserves - Revisions other than price (MMBoe)
164.5
Proved Developed Reserves - Extensions and discoveries plus revisions
other than price (MMBoe) (k)
384.6
Proved Developed Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe) (j / k)
$
6.50
EOG RESOURCES, INC.
Crude Oil and Natural Gas Financial
Commodity Derivative Contracts
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.
Presented below is a comprehensive summary of EOG’s crude oil price swap contracts through February 20, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl.
Crude Oil Price Swap Contracts
Weighted
Volume
Average Price
(Bbld)
($/Bbl)
2016
April 12, 2016 through April 30, 2016 (closed)
90,000
$
42.30
May 1, 2016 through June 30, 2016 (closed)
128,000
42.56
2017
January 2017 (closed)
35,000
$
50.04
February 1, 2017 through June 30, 2017
35,000
50.04
EOG has entered into crude oil collar contracts, which establish ceiling and floor prices for the sale of notional volumes of crude oil as specified in the collar contracts.
The collars require that EOG pay the difference between the ceiling price and the average U.S. NYMEX West Texas Intermediate crude oil price for the contract month (Index Price) in the event the Index Price is above the ceiling price.
The collars grant EOG the right to receive the difference between the floor price and the Index Price in the event the Index Price is below the floor price.
Presented below is a comprehensive summary of EOG’s crude oil collar contracts through February 20, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl.
Crude Oil Collar Contracts
Weighted Average Price ($/Bbl)
Volume (Bbld)
Ceiling Price
Floor Price
2016
September 1, 2016 through December 31, 2016 (closed)
70,000
$
54.25
$
45.00
Presented below is a comprehensive summary of EOG’s natural gas price swap contracts through February 20, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
Natural Gas Price Swap Contracts
Weighted
Volume
Average Price
(MMBtud)
($/MMBtu)
2016
March 1, 2016 through August 31, 2016 (closed)
60,000
$
2.49
2017
March 1, 2017 through November 30, 2017
30,000
$
3.10
2018
March 1, 2018 through November 30, 2018
35,000
$
3.00
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts.
The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price.
In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as 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 Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price.
Presented below is a comprehensive summary of EOG’s natural gas call and put option contracts through February 20, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMbtu.
Natural Gas Option Contracts
Call Options Sold
Put Options Purchased
Weighted
Weighted
Volume
Average Price
Volume
Average Price
(MMBtud)
($/MMBtu)
(MMBtud)
($/MMBtu)
2016
September 2016 (closed)
56,250
$
3.46
-
$
-
October 1, 2016 through November 30, 2016 (closed)
106,250
3.48
-
-
2017
March 1, 2017 through November 30, 2017
213,750
$
3.44
171,000
$
2.92
2018
March 1, 2018 through November 30, 2018
120,000
$
3.38
96,000
$
2.94
EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts.
The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price.
The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price.
Presented below is a comprehensive summary of EOG’s natural gas collar contracts through February 20, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMbtu.
Natural Gas Collar Contracts
Weighted Average Price ($/MMbtu)
Volume (MMBtud)
Ceiling Price
Floor Price
2017
March 1, 2017 through November 30, 2017
80,000
$
3.69
$
3.20
Definitions
Bbld
Barrels per day
$/Bbl
Dollars per barrel
MMBtud
Million British thermal units per day
$/MMBtu
Dollars per million British thermal units
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 (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively
(Unaudited; in millions, except ratio data)
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (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 purposes of comparing its financial performance with the financial performance of other companies in the industry.
2016
2015
2014
2013
Return on Capital Employed (ROCE) (Non-GAAP)
Net Interest Expense (GAAP)
$
282
$ 237
$ 201
Tax Benefit Imputed (based on 35%)
(99)
(83)
(70)
After-Tax Net Interest Expense (Non-GAAP) - (a)
$
183
$ 154
$ 131
Net Income (Loss) (GAAP) - (b)
$
(1,097)
$ (4,525)
$ 2,915
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) 204
(a)
4,559
(b)
(199)
(c)
Adjusted Net Income (Non-GAAP) - (c)
$
(893)
$ 34
$ 2,716
Total Stockholders’ Equity - (d)
$
13,982
$ 12,943
$ 17,713
$ 15,418
Average Total Stockholders’ Equity * - (e)
$
13,463
$ 15,328
$ 16,566
Current and Long-Term Debt (GAAP) - (f)
$
6,986
$ 6,655
$ 5,906
$ 5,909
Less: Cash
(1,600)
(719)
(2,087)
(1,318)
Net Debt (Non-GAAP) - (g)
$
5,386
$ 5,936
$ 3,819
$ 4,591
Total Capitalization (GAAP) - (d) + (f)
$
20,968
$ 19,598
$ 23,619
$ 21,327
Total Capitalization (Non-GAAP) - (d) + (g)
$
19,368
$ 18,879
$ 21,532
$ 20,009
Average Total Capitalization (Non-GAAP) * - (h)
$
19,124
$ 20,206
$ 20,771
ROCE (GAAP Net Income) - [(a) + (b)] / (h)
-4.8%
-21.6%
14.7%
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h)
-3.7%
0.9%
13.7%
Return on Equity (ROE) (Non-GAAP)
ROE (GAAP Net Income) - (b) / (e)
-8.1%
-29.5%
17.6%
ROE (Non-GAAP Adjusted Net Income) - (c) / (e)
-6.6%
0.2%
16.4%
* Average for the current and immediately preceding year
Adjustments to Net Income (Loss) (GAAP)
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016:
Year Ended December 31, 2016
Before
Income Tax
After
Tax
Impact
Tax
Adjustments:
Add:
Mark-to-Market Commodity Derivative Contracts Impact
$ 77
$
(28)
$
49
Add:
Impairments of Certain Assets
321
(113)
208
Less:
Net Gains on Asset Dispositions
(206)
62
(144)
Add:
Trinidad Tax Settlement
-
43
43
Add:
Voluntary Retirement Expense
42
(15)
27
Add:
Acquisition - State Apportionment Change
-
16
16
Add:
Acquisition Costs
5
-
5
Total
$ 239
$
(35)
$
204
(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015:
Year Ended December 31, 2015
Before
Income Tax
After
Tax
Impact
Tax
Adjustments:
Add:
Mark-to-Market Commodity Derivative Contracts Impact
$ 668
$
(238)
$
430
Add:
Impairments of Certain Assets
6,308
(2,183)
4,125
Less:
Texas Margin Tax Rate Reduction
-
(20)
(20)
Add:
Legal Settlement - Early Leasehold Termination
19
(6)
13
Add:
Severance Costs
9
(3)
6
Add:
Net Losses on Asset Dispositions
9
(4)
5
Total
$ 7,013
$
(2,454)
$
4,559
(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014:
Year Ended December 31, 2014
Before
Income Tax
After
Tax
Impact
Tax
Adjustments:
Less:
Mark-to-Market Commodity Derivative Contracts Impact
$ (800)
$
285
$
(515)
Add:
Impairments of Certain Assets
824
(271)
553
Less:
Net Gains on Asset Dispositions
(508)
21
(487)
Add:
Tax Expense Related to the Repatriation of Accumulated
-
250
250
Foreign Earnings in Future Years
Total
$ (484)
$
285
$
(199)
EOG RESOURCES, INC.
First Quarter and Full Year 2017 Forecast and Benchmark Commodity Pricing
(a)
First Quarter and Full Year 2017 Forecast
The forecast items for the first quarter and full year 2017 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)
1Q 2017
Full Year 2017
Daily Sales Volumes
Crude Oil and Condensate Volumes (MBbld)
United States
300.0
-
310.0
320.0
-
335.0
Trinidad
0.3
-
0.5
0.3
-
0.5
Other International
2.0
-
4.0
4.0
-
7.0
Total
302.3
-
314.5
324.3
-
342.5
Natural Gas Liquids Volumes (MBbld)
Total
72.0
-
78.0
72.0
-
82.0
Natural Gas Volumes (MMcfd)
United States
670
-
710
725
-
760
Trinidad
300
-
330
275
-
315
Other International
18
-
24
25
-
30
Total
988
-
1,064
1,025
-
1,105
Crude Oil Equivalent Volumes (MBoed)
United States
483.7
-
506.3
512.8
-
543.7
Trinidad
50.3
-
55.5
46.1
-
53.0
Other International
5.0
-
8.0
8.2
-
12.0
Total
539.0
-
569.8
567.1
-
608.7
Operating Costs
Unit Costs ($/Boe)
Lease and Well
$ 4.60
- $ 5.00
$ 4.30
- $ 5.00
Transportation Costs
$ 3.40
- $ 4.00
$ 3.10
- $ 3.90
Depreciation, Depletion and Amortization
$ 15.80
- $ 16.10
$ 15.50
- $ 16.00
Expenses ($MM)
Exploration, Dry Hole and Impairment
$ 95
- $ 125
$ 415
- $ 465
General and Administrative
$ 90
- $ 100
$ 365
- $ 395
Gathering and Processing
$ 28
- $ 30
$ 105
- $ 125
Capitalized Interest
$ 7
- $ 8
$ 25
- $ 30
Net Interest
$ 69
- $ 71
$ 273
- $ 283
Taxes Other Than Income (% of Wellhead Revenue)
6.7%
-
7.1%
6.5%
-
6.9%
Income Taxes
Effective Rate
31%
-
36%
31%
-
36%
Current Taxes ($MM)
$ 30
- $ 45
$ 130
- $ 170
Capital Expenditures (Excluding Acquisitions, $MM)
Exploration and Development, Excluding Facilities
$ 3,000
- $ 3,350
Exploration and Development Facilities
$ 475
- $ 510
Gathering, Processing and Other
$ 225
- $ 240
Pricing - (Refer to Benchmark Commodity Pricing in text)
Crude Oil and Condensate ($/Bbl)
Differentials
United States - above (below) WTI
$ (2.00)
- $ (1.00)
$ (2.50)
- $ (0.50)
Trinidad - above (below) WTI
$ (9.75)
- $ (7.75)
$ (9.50)
- $ (7.50)
Other International - above (below) WTI
$ (10.00) - $ (8.00)
$ (3.00)
- $ 0.00
Natural Gas Liquids
Realizations as % of WTI
31%
-
35%
31%
-
35%
Natural Gas ($/Mcf)
Differentials
United States - above (below) NYMEX Henry Hub
$ (1.10)
- $ (0.70)
$ (1.15)
- $ (0.65)
Realizations
Trinidad
$ 2.00
- $ 2.40
$ 1.90
- $ 2.50
Other International
$ 3.75
- $ 4.25
$ 3.50
- $ 4.50
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

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SOURCE EOG Resources, Inc.

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