HOUSTON, May 8, 2017 /PRNewswire/ --
- Exceeds High-End of Oil Production Forecast
- Increases Premium Net Resource Potential by 27 Percent to 6.5 BnBoe
- Reduces Completed Well Costs by 6 Percent in Major Plays Compared to 2016
- Completes Four Record-Setting Permian Basin Horizontal Oil Wells
EOG Resources, Inc. EOG (EOG) today reported first quarter 2017 net income of $28.5 million, or $0.05 per share. This compares to a first quarter 2016 net loss of $471.8 million, or $0.86 per share.
Adjusted non-GAAP net income for the first quarter 2017 was $89.4 million, or $0.15 per share, compared to an adjusted non-GAAP net loss of $455.4 million, or $0.83 per share, for the same prior year period. Adjusted non-GAAP net income (loss) is calculated by matching hedge 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.)
Higher commodity prices, increased production volumes, well productivity improvements and overall per-unit cost reductions resulted in increases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the first quarter 2017 compared to the first quarter 2016. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Operational Highlights
EOG set a company record for crude oil volumes in the first quarter 2017 by producing 315,700 barrels of oil per day (Bopd), an 18 percent increase compared to the first quarter 2016. This strong production growth reflects the company's premium drilling strategy and technical advances in its prolific plays across multiple basins. EOG defines premium inventory as prospective well locations that will earn a minimum 30 percent direct after-tax rate of return at $40 crude oil and $2.50 natural gas prices.
EOG continues to reduce total well costs in each of its major plays. First quarter 2017 average completed well costs were 6 percent lower than full year 2016 averages in the Eagle Ford, Delaware Basin and Bakken using normalized lateral lengths. For all three plays, the overall cost reductions were achieved in spite of service and equipment price inflation in certain areas, which were more than offset by continued advances in drilling and completion tools and techniques, benefits from extended lateral lengths, and new contracts at lower prices.
During the first quarter 2017, lease and well expenses on a per-unit basis increased 4 percent compared to the same prior year period primarily because of last year's disposition of natural gas producing assets with lower per-unit operating costs, the Yates acquisition properties with higher per-unit operating costs, and higher production expenses in the United Kingdom. Per-unit transportation costs decreased 8 percent and depreciation, depletion and amortization expenses decreased 14 percent on a per-unit basis year-over-year. Total general and administrative expenses decreased 3 percent compared to the first quarter 2016 primarily due to expenses related to a voluntary retirement program in 2016.
"EOG continues to lead the industry in well productivity, with record-setting well performance driving company record crude oil volumes," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "During the first quarter 2017, we increased our premium inventory by 1,200 net well locations and 1.4 BnBoe of premium net resource potential, which is approximately 2.5 times the number of wells we expect to complete during all of 2017. EOG remains committed to creating significant shareholder value through low-cost, high-return growth and organic resource expansion."
Delaware Basin
In the first quarter 2017, EOG continued to increase development activity and expand resource potential in the Delaware Basin. EOG increased its Delaware Basin premium net locations by 700 to 4,150 locations.
EOG completed 33 wells in the Delaware Basin Wolfcamp in the first quarter 2017 with an average treated lateral length of 5,600 feet per well and average 30-day initial production rates per well of 2,855 barrels of oil equivalent per day (Boed), or 1,850 Bopd, 450 barrels per day (Bpd) of natural gas liquids (NGLs) and 3.3 million cubic feet per day (MMcfd) of natural gas.
Of special note is a four-well pattern in Lea County, N.M., the Whirling Wind 14 Fed Com #701H and the Whirling Wind 11 Fed Com #702H - #704H which were completed with an average treated lateral length of 7,100 feet per well and average 30-day initial production rates per well of 5,060 Boed, or 3,510 Bopd, 700 Bpd of NGLs and 5.1 MMcfd of natural gas. Each well exceeded the prior all-time industry record for 30-day initial production from Permian Basin horizontal oil wells.
"EOG's Whirling Wind wells shattered industry records in the Permian Basin," said Thomas. "Our advanced technology and proprietary techniques are leading to break-through well performance across our diverse portfolio of premium plays."
In the Delaware Basin Bone Spring, EOG completed three wells in the first quarter 2017 with an average treated lateral length of 8,800 feet per well and average 30-day initial production rates per well of 3,255 Boed, or 2,525 Bopd, 335 Bpd of NGLs and 2.4 MMcfd of natural gas.
In the Delaware Basin Leonard, EOG completed three wells in the first quarter 2017 with an average treated lateral length of 3,800 feet per well and average 30-day initial production rates per well of 840 Boed, or 505 Bopd, 150 Bpd of NGLs and 1.1 MMcfd of natural gas. These first quarter 2017 completions were drilled prior to 2016.
South Texas Eagle Ford
EOG's South Texas Eagle Ford continued to be the most active area in the company in the first quarter 2017. In addition to significant development activity, EOG expanded its Eagle Ford premium net locations by 500 to more than 2,400 locations. Part of the increase in premium locations was enabled by a shift to longer lateral drilling units. Seven wells that began production in the first quarter 2017 had lateral lengths in excess of 10,000 feet.
In the first quarter 2017, EOG completed 65 wells in the Eagle Ford with an average treated lateral length of 6,500 feet per well and average 30-day initial production rates per well of 1,390 Boed, or 1,130 Bopd, 130 Bpd of NGLs and 0.8 MMcfd of natural gas.
South Texas Austin Chalk
In the first quarter 2017, testing continued in the South Texas Austin Chalk. EOG completed five wells in Karnes County with an average treated lateral length of 5,700 feet per well and average 30-day initial production rates per well of 2,605 Boed, or 1,895 Bopd, 360 Bpd of NGLs and 2.1 MMcfd of natural gas.
Rockies and the Bakken
During the first quarter, EOG continued to develop its premium Powder River Basin position and reduce its inventory of drilled uncompleted wells in the Bakken.
In the Powder River Basin, EOG completed five wells in the first quarter 2017 with an average treated lateral length of 4,900 feet per well and average 30-day initial production rates per well of 1,160 Boed, or 950 Bopd, 75 Bpd of NGLs and 0.8 MMcfd of natural gas.
In the North Dakota Bakken, EOG completed 27 wells in the first quarter 2017 with an average treated lateral length of 8,500 feet per well and average 30-day initial production rates per well of 715 Boed, or 640 Bopd, 40 Bpd of NGLs and 0.2 MMcfd of natural gas. The first quarter 2017 completions in the Bakken included 24 wells that were drilled prior to 2016. Three wells completed in the first quarter 2017 were the first wells completed in the Bakken Lite area with EOG's high-density fracs. These three wells had an average treated lateral length of 7,700 feet per well and average 30-day initial production rates per well of 955 Boed, or 795 Bopd, 85 Bpd of NGLs and 0.5 MMcfd of natural gas.
Hedging Activity
For the period June 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 June 1 through November 30, 2017, EOG has 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 has 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 June 1 through November 30, 2017, EOG has 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 has 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 June 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.
EOG did not have a net crude oil hedge position as of March 31, 2017.
A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.
Capital Structure and Asset Sales
At March 31, 2017, EOG's total debt outstanding was $7.0 billion for a debt-to-total capitalization ratio of 33 percent. Considering cash on the balance sheet at the end of the first quarter, EOG's net debt was $5.4 billion for 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 year-to-date 2017 totaled $118 million. This includes proceeds from two transactions that closed in the second quarter 2017.
Conference Call May 9, 2017
EOG's first quarter 2017 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Tuesday, May 9, 2017. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview. The webcast will be archived on EOG's website through May 23, 2017.
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."
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.
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For Further Information Contact: |
Investors |
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Cedric W. Burgher | |
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(713) 571-4658 | |
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David J. Streit | |
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(713) 571-4902 | |
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W. John Wagner | |
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(713) 571-4404 | |
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Media and Investors | |
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Kimberly M. Ehmer | |
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(713) 571-4676 |
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EOG RESOURCES, INC. | |||||
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Financial Report | |||||
|
(Unaudited; in millions, except per share data) | |||||
|
Three Months Ended | |||||
|
March 31, | |||||
|
2017 |
2016 | ||||
|
Net Operating Revenues |
$ |
2,610.6 |
$ |
1,354.3 | |
|
Net Income (Loss) |
$ |
28.5 |
$ |
(471.8) | |
|
Net Income (Loss) Per Share |
|||||
|
Basic |
$ |
0.05 |
$ |
(0.86) | |
|
Diluted |
$ |
0.05 |
$ |
(0.86) | |
|
Average Number of Common Shares |
|||||
|
Basic |
573.9 |
546.7 | |||
|
Diluted |
578.6 |
546.7 | |||
|
Summary Income Statements | |||||
|
(Unaudited; in thousands, except per share data) | |||||
|
Three Months Ended | |||||
|
March 31, | |||||
|
2017 |
2016 | ||||
|
Net Operating Revenues |
|||||
|
Crude Oil and Condensate |
$ |
1,430,061 |
$ |
753,711 | |
|
Natural Gas Liquids |
153,444 |
75,319 | |||
|
Natural Gas |
230,602 |
165,503 | |||
|
Gains on Mark-to-Market Commodity |
|||||
|
Derivative Contracts |
62,020 |
5,435 | |||
|
Gathering, Processing and Marketing |
726,537 |
333,953 | |||
|
Gains (Losses) on Asset Dispositions, Net |
(16,758) |
9,147 | |||
|
Other, Net |
24,659 |
11,281 | |||
|
Total |
2,610,565 |
1,354,349 | |||
|
Operating Expenses |
|||||
|
Lease and Well |
255,777 |
240,865 | |||
|
Transportation Costs |
178,714 |
190,454 | |||
|
Gathering and Processing Costs |
38,144 |
28,524 | |||
|
Exploration Costs |
56,894 |
29,829 | |||
|
Dry Hole Costs |
- |
246 | |||
|
Impairments |
193,187 |
71,617 | |||
|
Marketing Costs |
736,536 |
340,854 | |||
|
Depreciation, Depletion and Amortization |
816,036 |
928,891 | |||
|
General and Administrative |
97,238 |
100,531 | |||
|
Taxes Other Than Income |
130,293 |
60,679 | |||
|
Total |
2,502,819 |
1,992,490 | |||
|
Operating Income (Loss) |
107,746 |
(638,141) | |||
|
Other Income (Expense), Net |
3,151 |
(4,437) | |||
|
Income (Loss) Before Interest Expense and Income Taxes |
110,897 |
(642,578) | |||
|
Interest Expense, Net |
71,515 |
68,390 | |||
|
Income (Loss) Before Income Taxes |
39,382 |
(710,968) | |||
|
Income Tax Provision (Benefit) |
10,865 |
(239,192) | |||
|
Net Income (Loss) |
$ |
28,517 |
$ |
(471,776) | |
|
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1675 | |
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EOG RESOURCES, INC. | |||||
|
Operating Highlights | |||||
|
(Unaudited) | |||||
|
Three Months Ended | |||||
|
March 31, | |||||
|
2017 |
2016 | ||||
|
Wellhead Volumes and Prices |
|||||
|
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||
|
United States |
312.5 |
265.8 | |||
|
Trinidad |
0.8 |
0.7 | |||
|
Other International (B) |
2.4 |
1.4 | |||
|
Total |
315.7 |
267.9 | |||
|
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||
|
United States |
$ |
50.38 |
$ |
30.87 | |
|
Trinidad |
41.56 |
22.78 | |||
|
Other International (B) |
47.77 |
32.33 | |||
|
Composite |
50.34 |
30.85 | |||
|
Natural Gas Liquids Volumes (MBbld) (A) |
|||||
|
United States |
78.8 |
79.4 | |||
|
Other International (B) |
- |
- | |||
|
Total |
78.8 |
79.4 | |||
|
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||
|
United States |
$ |
21.63 |
$ |
10.41 | |
|
Other International (B) |
- |
- | |||
|
Composite |
21.63 |
10.41 | |||
|
Natural Gas Volumes (MMcfd) (A) |
|||||
|
United States |
728 |
829 | |||
|
Trinidad |
308 |
361 | |||
|
Other International (B) |
22 |
25 | |||
|
Total |
1,058 |
1,215 | |||
|
Average Natural Gas Prices ($/Mcf) (C) |
|||||
|
United States |
$ |
2.32 |
$ |
1.27 | |
|
Trinidad |
2.57 |
1.88 | |||
|
Other International (B) |
3.76 |
3.63 | |||
|
Composite |
2.42 |
1.50 | |||
|
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||
|
United States |
512.6 |
483.6 | |||
|
Trinidad |
52.2 |
60.8 | |||
|
Other International (B) |
5.9 |
5.5 | |||
|
Total |
570.7 |
549.9 | |||
|
Total MMBoe (D) |
51.4 |
50.0 | |||
|
(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. | |||||
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(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. | |||||
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(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. |
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EOG RESOURCES, INC. | |||||
|
Summary Balance Sheets | |||||
|
(Unaudited; in thousands, except share data) | |||||
|
March 31, |
December 31, | ||||
|
2017 |
2016 | ||||
|
ASSETS | |||||
|
Current Assets |
|||||
|
Cash and Cash Equivalents |
$ |
1,546,566 |
$ |
1,599,895 | |
|
Accounts Receivable, Net |
1,187,112 |
1,216,320 | |||
|
Inventories |
314,194 |
350,017 | |||
|
Assets from Price Risk Management Activities |
1,142 |
- | |||
|
Income Taxes Receivable |
80,503 |
12,305 | |||
|
Other |
264,559 |
206,679 | |||
|
Total |
3,394,076 |
3,385,216 | |||
|
Property, Plant and Equipment |
|||||
|
Oil and Gas Properties (Successful Efforts Method) |
50,195,608 |
49,592,091 | |||
|
Other Property, Plant and Equipment |
3,977,721 |
4,008,564 | |||
|
Total Property, Plant and Equipment |
54,173,329 |
53,600,655 | |||
|
Less: Accumulated Depreciation, Depletion and Amortization |
(28,566,869) |
(27,893,577) | |||
|
Total Property, Plant and Equipment, Net |
25,606,460 |
25,707,078 | |||
|
Deferred Income Taxes |
16,232 |
16,140 | |||
|
Other Assets |
195,206 |
190,767 | |||
|
Total Assets |
$ |
29,211,974 |
$ |
29,299,201 | |
|
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
|
Current Liabilities |
|||||
|
Accounts Payable |
$ |
1,556,875 |
$ |
1,511,826 | |
|
Accrued Taxes Payable |
143,710 |
118,411 | |||
|
Dividends Payable |
96,155 |
96,120 | |||
|
Liabilities from Price Risk Management Activities |
7,636 |
61,817 | |||
|
Current Portion of Long-Term Debt |
6,579 |
6,579 | |||
|
Other |
221,052 |
232,538 | |||
|
Total |
2,032,007 |
2,027,291 | |||
|
Long-Term Debt |
6,980,008 |
6,979,779 | |||
|
Other Liabilities |
1,248,102 |
1,282,142 | |||
|
Deferred Income Taxes |
5,023,626 |
5,028,408 | |||
|
Commitments and Contingencies |
|||||
|
Stockholders' Equity |
|||||
|
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and |
|||||
|
577,636,588Shares Issued at March 31, 2017 and 576,950,272 |
|||||
|
Shares Issued at December 31, 2016 |
205,776 |
205,770 | |||
|
Additional Paid in Capital |
5,447,291 |
5,420,385 | |||
|
Accumulated Other Comprehensive Loss |
(18,664) |
(19,010) | |||
|
Retained Earnings |
8,329,951 |
8,398,118 | |||
|
Common Stock Held in Treasury, 378,442 Shares at March 31, 2017 |
|||||
|
and 250,155 Shares at December 31, 2016 |
(36,123) |
(23,682) | |||
|
Total Stockholders' Equity |
13,928,231 |
13,981,581 | |||
|
Total Liabilities and Stockholders' Equity |
$ |
29,211,974 |
$ |
29,299,201 | |
|
EOG RESOURCES, INC. | |||||
|
Summary Statements of Cash Flows | |||||
|
(Unaudited; in thousands) | |||||
|
Three Months Ended | |||||
|
March 31, | |||||
|
2017 |
2016 | ||||
|
Cash Flows from Operating Activities |
|||||
|
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: |
|||||
|
Net Income (Loss) |
$ |
28,517 |
$ |
(471,776) | |
|
Items Not Requiring (Providing) Cash |
|||||
|
Depreciation, Depletion and Amortization |
816,036 |
928,891 | |||
|
Impairments |
193,187 |
71,617 | |||
|
Stock-Based Compensation Expenses |
30,460 |
32,380 | |||
|
Deferred Income Taxes |
694 |
(196,696) | |||
|
(Gains) Losses on Asset Dispositions, Net |
16,758 |
(9,147) | |||
|
Other, Net |
(3,052) |
5,442 | |||
|
Dry Hole Costs |
- |
246 | |||
|
Mark-to-Market Commodity Derivative Contracts |
|||||
|
Total Gains |
(62,020) |
(5,435) | |||
|
Net Cash Received from Settlements of Commodity Derivative Contracts |
1,912 |
17,687 | |||
|
Other, Net |
(428) |
1,407 | |||
|
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
|
Accounts Receivable |
28,688 |
132,398 | |||
|
Inventories |
24,736 |
57,578 | |||
|
Accounts Payable |
20,426 |
(289,627) | |||
|
Accrued Taxes Payable |
(38,613) |
2,460 | |||
|
Other Assets |
(44,677) |
3,946 | |||
|
Other Liabilities |
(51,251) |
7,992 | |||
|
Changes in Components of Working Capital Associated with Investing and Financing |
|||||
|
Activities |
(63,324) |
2,228 | |||
|
Net Cash Provided by Operating Activities |
898,049 |
291,591 | |||
|
Investing Cash Flows |
|||||
|
Additions to Oil and Gas Properties |
(912,227) |
(547,399) | |||
|
Additions to Other Property, Plant and Equipment |
(34,336) |
(25,792) | |||
|
Proceeds from Sales of Assets |
46,812 |
6,667 | |||
|
Changes in Components of Working Capital Associated with Investing Activities |
63,324 |
(2,228) | |||
|
Net Cash Used in Investing Activities |
(836,427) |
(568,752) | |||
|
Financing Cash Flows |
|||||
|
Net Commercial Paper Repayments |
- |
(259,718) | |||
|
Long-Term Debt Borrowings |
- |
991,097 | |||
|
Long-Term Debt Repayments |
- |
(400,000) | |||
|
Dividends Paid |
(96,707) |
(92,170) | |||
|
Treasury Stock Purchased |
(18,628) |
(12,672) | |||
|
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
2,356 |
2,688 | |||
|
Debt Issuance Costs |
- |
(1,592) | |||
|
Repayment of Capital Lease Obligation |
(1,619) |
(1,569) | |||
|
Net Cash (Used in) Provided by Financing Activities |
(114,598) |
226,064 | |||
|
Effect of Exchange Rate Changes on Cash |
(353) |
1,072 | |||
|
Decrease in Cash and Cash Equivalents |
(53,329) |
(50,025) | |||
|
Cash and Cash Equivalents at Beginning of Period |
1,599,895 |
718,506 | |||
|
Cash and Cash Equivalents at End of Period |
$ |
1,546,566 |
$ |
668,481 | |
|
EOG RESOURCES, INC. | |||||||||||||||
|
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) | |||||||||||||||
|
To Net Income (Loss) (GAAP) | |||||||||||||||
|
(Unaudited; in thousands, except per share data) | |||||||||||||||
|
The following chart adjusts the three-month periods ended March 31, 2017 and 2016 reported Net Income (Loss) (GAAP) to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market gains from these transactions, to eliminate the net (gains) losses on asset dispositions in 2017 and 2016, to add back impairment charges related to certain of EOG's assets in 2017 and to add back certain voluntary retirement expense 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 | ||||||||||||||
|
March 31, 2017 |
March 31, 2016 | ||||||||||||||
|
Income |
Diluted |
Income |
Diluted | ||||||||||||
|
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
|
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
|
Reported Net Income (Loss) (GAAP) |
$ 39,382 |
$(10,865) |
$28,517 |
$ 0.05 |
$(710,968) |
$239,192 |
$(471,776) |
$ (0.86) | |||||||
|
Adjustments: |
|||||||||||||||
|
Gains on Mark-to-Market Commodity |
|||||||||||||||
|
Derivative Contracts |
(62,020) |
22,191 |
(39,829) |
(0.07) |
(5,435) |
1,938 |
(3,497) |
(0.01) | |||||||
|
Net Cash Received from Settlements of |
|||||||||||||||
|
Commodity Derivative Contracts |
1,912 |
(684) |
1,228 |
- |
17,687 |
(6,306) |
11,381 |
0.02 | |||||||
|
Add: Net (Gains) Losses on Asset Dispositions |
16,758 |
(5,736) |
11,022 |
0.02 |
(9,147) |
3,210 |
(5,937) |
(0.01) | |||||||
|
Add: Impairments |
137,751 |
(49,287) |
88,464 |
0.15 |
- |
- |
- |
- | |||||||
|
Add: Voluntary Retirement Expense |
- |
- |
- |
- |
22,391 |
(7,982) |
14,409 |
0.03 | |||||||
|
Adjustments to Net Income (Loss) |
94,401 |
(33,516) |
60,885 |
0.10 |
25,496 |
(9,140) |
16,356 |
0.03 | |||||||
|
Adjusted Net Income (Loss) (Non-GAAP) |
$133,783 |
$(44,381) |
$89,402 |
$ 0.15 |
$(685,472) |
$230,052 |
$(455,420) |
$ (0.83) | |||||||
|
Average Number of Common Shares (GAAP) |
|||||||||||||||
|
Basic |
573,935 |
546,715 | |||||||||||||
|
Diluted |
578,593 |
546,715 | |||||||||||||
|
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
|
Basic |
573,935 |
546,715 | |||||||||||||
|
Diluted |
578,593 |
546,715 | |||||||||||||
|
EOG RESOURCES, INC. | ||||||
|
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||
|
To Net Cash Provided By Operating Activities (GAAP) | ||||||
|
(Unaudited; in thousands) | ||||||
|
The following chart reconciles the three-month periods ended March 31, 2017 and 2016 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. | ||||||
|
Three Months Ended | ||||||
|
March 31, | ||||||
|
2017 |
2016 | |||||
|
Net Cash Provided by Operating Activities (GAAP) |
$ |
898,049 |
$ |
291,591 | ||
|
Adjustments: |
||||||
|
Exploration Costs (excluding Stock-Based Compensation Expenses) |
50,734 |
23,357 | ||||
|
Changes in Components of Working Capital and Other Assets |
||||||
|
and Liabilities |
||||||
|
Accounts Receivable |
(28,688) |
(132,398) | ||||
|
Inventories |
(24,736) |
(57,578) | ||||
|
Accounts Payable |
(20,426) |
289,627 | ||||
|
Accrued Taxes Payable |
38,613 |
(2,460) | ||||
|
Other Assets |
44,677 |
(3,946) | ||||
|
Other Liabilities |
51,251 |
(7,992) | ||||
|
Changes in Components of Working Capital Associated with |
||||||
|
Investing and Financing Activities |
63,324 |
(2,228) | ||||
|
Discretionary Cash Flow (Non-GAAP) |
$ |
1,072,798 |
$ |
397,973 | ||
|
Discretionary Cash Flow (Non-GAAP) - Percentage Increase |
170% |
|||||
|
EOG RESOURCES, INC. | ||||||
|
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net, | ||||||
|
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | ||||||
|
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | ||||||
|
(Non-GAAP) to Net Income (Loss) (GAAP) | ||||||
|
(Unaudited; in thousands) | ||||||
|
The following chart adjusts the three-month periods ended March 31, 2017 and 2016 reported Net Income (Loss) (GAAP) to Earnings Before Interest Expense, Net, Income Taxes (Income Tax Provision (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 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 Net Income (Loss) (GAAP) to add back Interest Expense, Net, Income Taxes (Income Tax Provision (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 |
||||||
|
March 31, |
||||||
|
2017 |
2016 |
|||||
|
Net Income (Loss) (GAAP) |
$ |
28,517 |
$ |
(471,776) |
||
|
Adjustments: |
||||||
|
Interest Expense, Net |
71,515 |
68,390 |
||||
|
Income Tax Provision (Benefit) |
10,865 |
(239,192) |
||||
|
Depreciation, Depletion and Amortization |
816,036 |
928,891 |
||||
|
Exploration Costs |
56,894 |
29,829 |
||||
|
Dry Hole Costs |
- |
246 |
||||
|
Impairments |
193,187 |
71,617 |
||||
|
EBITDAX (Non-GAAP) |
1,177,014 |
388,005 |
||||
|
Total Gains on MTM Commodity Derivative Contracts |
(62,020) |
(5,435) |
||||
|
Net Cash Received from Settlements of Commodity |
||||||
|
Derivative Contracts |
1,912 |
17,687 |
||||
|
(Gains) Losses on Asset Dispositions, Net |
16,758 |
(9,147) |
||||
|
Adjusted EBITDAX (Non-GAAP) |
$ |
1,133,664 |
$ |
391,110 |
||
|
Adjusted EBITDAX (Non-GAAP) - Percentage Increase |
190% |
|||||
|
EOG RESOURCES, INC. | ||||||
|
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | ||||||
|
Capitalization (Non-GAAP) as Used in the Calculation of | ||||||
|
The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | ||||||
|
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | ||||||
|
(Unaudited; in millions, except ratio data) | ||||||
|
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | ||||||
|
At |
At | |||||
|
March 31, |
December 31, | |||||
|
2017 |
2016 | |||||
|
Total Stockholders' Equity - (a) |
$ |
13,928 |
$ |
13,982 | ||
|
Current and Long-Term Debt (GAAP) - (b) |
6,987 |
6,986 | ||||
|
Less: Cash |
(1,547) |
(1,600) | ||||
|
Net Debt (Non-GAAP) - (c) |
5,440 |
5,386 | ||||
|
Total Capitalization (GAAP) - (a) + (b) |
$ |
20,915 |
$ |
20,968 | ||
|
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
19,368 |
$ |
19,368 | ||
|
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
33% |
33% | ||||
|
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
28% |
28% | ||||
|
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. On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through May 8, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
|
Crude Oil Price Swap Contracts | |||||||||||
|
Weighted | |||||||||||
|
Volume |
Average Price | ||||||||||
|
(Bbld) |
($/Bbl) | ||||||||||
|
2017 |
|||||||||||
|
January 1, 2017 through February 28, 2017 (closed) |
35,000 |
$ 50.04 | |||||||||
|
March 1, 2017 through June 30, 2017 (closed) |
30,000 |
50.05 | |||||||||
|
On March 14, 2017, EOG entered into a crude oil price swap contract for the period March 1, 2017 through June 30, 2017, with notional volumes of 5,000 Bbld at a price of $48.81 per Bbl. This contract offsets the remaining crude oil price swap contract for the same time period with notional volumes of 5,000 Bbld at a price of $50.00 per Bbl. The net cash EOG will receive for settling these contracts is $0.7 million. The offsetting contracts were excluded from the above table. | |||||||||||
|
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through May 8, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
|
Natural Gas Price Swap Contracts | |||||||||||
|
Weighted | |||||||||||
|
Volume |
Average Price | ||||||||||
|
(MMBtud) |
($/MMBtu) | ||||||||||
|
2017 |
|||||||||||
|
March 1, 2017 through May 31, 2017 (closed) |
30,000 |
$ 3.10 | |||||||||
|
June 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 May 8, 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) | ||||||||
|
2017 |
|||||||||||
|
March 1, 2017 through May 31, 2017 (closed) |
213,750 |
$ 3.44 |
171,000 |
$ 2.92 | |||||||
|
June 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 May 8, 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 May 31, 2017 (closed) |
80,000 |
$ 3.69 |
$ 3.20 | ||||||||
|
June 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 (Loss) | ||||||||||||
|
(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 (Loss) (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 (Loss), 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 (Loss) (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) |
||||||||||||
|
ROE (GAAP) (GAAP Net Income) - (b) / (e) |
-8.1% |
-29.5% |
17.6% |
|||||||||
|
ROE (Non-GAAP) (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 |
|||||||||||
|
Foreign Earnings in Future Years |
- |
250 |
250 |
|||||||||
|
Total |
$ |
(484) |
$ |
285 |
$ |
(199) |
||||||
|
EOG RESOURCES, INC. | |||||||||||
|
Second Quarter and Full Year 2017 Forecast and Benchmark Commodity Pricing | |||||||||||
|
(a) Second Quarter and Full Year 2017 Forecast |
|||||||||||
|
The forecast items for the second 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) |
|||||||||||
|
2Q 2017 |
Full Year 2017 | ||||||||||
|
Daily Sales Volumes |
|||||||||||
|
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
|
United States |
322.0 |
- |
332.0 |
320.0 |
- |
335.0 | |||||
|
Trinidad |
0.2 |
- |
0.4 |
0.3 |
- |
0.5 | |||||
|
Other International |
0.0 |
- |
0.0 |
4.0 |
- |
7.0 | |||||
|
Total |
322.2 |
- |
332.4 |
324.3 |
- |
342.5 | |||||
|
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
|
Total |
72.0 |
- |
78.0 |
72.0 |
- |
82.0 | |||||
|
Natural Gas Volumes (MMcfd) |
|||||||||||
|
United States |
710 |
- |
750 |
725 |
- |
760 | |||||
|
Trinidad |
280 |
- |
320 |
275 |
- |
315 | |||||
|
Other International |
18 |
- |
24 |
25 |
- |
30 | |||||
|
Total |
1,008 |
- |
1,094 |
1,025 |
- |
1,105 | |||||
|
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
|
United States |
512.3 |
- |
535.0 |
512.8 |
- |
543.7 | |||||
|
Trinidad |
46.9 |
- |
53.7 |
46.1 |
- |
53.0 | |||||
|
Other International |
3.0 |
- |
4.0 |
8.2 |
- |
12.0 | |||||
|
Total |
562.2 |
- |
592.7 |
567.1 |
- |
608.7 | |||||
|
Estimated Ranges |
|||||||||||
|
(Unaudited) |
|||||||||||
|
2Q 2017 |
Full Year 2017 | ||||||||||
|
Operating Costs |
|||||||||||
|
Unit Costs ($/Boe) |
|||||||||||
|
Lease and Well |
$ |
4.60 |
- |
$ |
5.00 |
$ |
4.25 |
- |
$ |
4.95 | |
|
Transportation Costs |
$ |
3.20 |
- |
$ |
3.60 |
$ |
3.10 |
- |
$ |
3.70 | |
|
Depreciation, Depletion and Amortization |
$ |
15.70 |
- |
$ |
16.10 |
$ |
15.50 |
- |
$ |
16.00 | |
|
Expenses ($MM) |
|||||||||||
|
Exploration, Dry Hole and Impairment |
$ |
95 |
- |
$ |
125 |
$ |
415 |
- |
$ |
465 | |
|
General and Administrative |
$ |
85 |
- |
$ |
95 |
$ |
365 |
- |
$ |
395 | |
|
Gathering and Processing |
$ |
28 |
- |
$ |
30 |
$ |
125 |
- |
$ |
145 | |
|
Capitalized Interest |
$ |
6 |
- |
$ |
8 |
$ |
25 |
- |
$ |
30 | |
|
Net Interest |
$ |
69 |
- |
$ |
72 |
$ |
273 |
- |
$ |
283 | |
|
Taxes Other Than Income (% of Wellhead Revenue) |
6.9% |
- |
7.3% |
6.5% |
- |
6.9% | |||||
|
Income Taxes |
|||||||||||
|
Effective Rate |
32% |
- |
37% |
31% |
- |
36% | |||||
|
Current Taxes ($MM) |
$ |
50 |
- |
$ |
85 |
$ |
135 |
- |
$ |
175 | |
|
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 toBenchmark Commodity Pricingin text) |
|||||||||||
|
Crude Oil and Condensate ($/Bbl) |
|||||||||||
|
Differentials |
|||||||||||
|
United States - above (below) WTI |
$ |
(2.00) |
- |
$ |
0.00 |
$ |
(2.50) |
- |
$ |
(0.50) | |
|
Trinidad - above (below) WTI |
$ |
(11.00) |
- |
$ |
(9.00) |
$ |
(11.00) |
- |
$ |
(9.00) | |
|
Other International - above (below) WTI |
$ |
(4.00) |
- |
$ |
2.00 |
$ |
(7.00) |
- |
$ |
1.00 | |
|
Natural Gas Liquids |
|||||||||||
|
Realizations as % of WTI |
36% |
- |
44% |
36% |
- |
44% | |||||
|
Natural Gas ($/Mcf) |
|||||||||||
|
Differentials |
|||||||||||
|
United States - above (below) NYMEX Henry Hub |
$ |
(1.10) |
- |
$ |
(0.60) |
$ |
(1.15) |
- |
$ |
(0.65) | |
|
Realizations |
|||||||||||
|
Trinidad |
$ |
2.20 |
- |
$ |
2.60 |
$ |
2.10 |
- |
$ |
2.70 | |
|
Other International |
$ |
3.30 |
- |
$ |
3.80 |
$ |
3.30 |
- |
$ |
4.30 | |
|
Definitions |
|||||||||||
|
$/Bbl U.S. Dollars per barrel |
|||||||||||
|
$/Boe U.S. Dollars per barrel of oil equivalent |
|||||||||||
|
$/Mcf U.S. Dollars per thousand cubic feet |
|||||||||||
|
$MM U.S. Dollars in millions |
|||||||||||
|
MBbld Thousand barrels per day |
|||||||||||
|
MBoed Thousand barrels of oil equivalent per day |
|||||||||||
|
MMcfd Million cubic feet per day |
|||||||||||
|
NYMEX New York Mercantile Exchange |
|||||||||||
|
WTI West Texas Intermediate |
|||||||||||
To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/eog-resources-announces-first-quarter-2017-results-and-converts-14-bnboe-net-resource-potential-to-premium-300453502.html
SOURCE EOG Resources, Inc.
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