UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 OR 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): February 27, 2017
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EOG RESOURCES, INC.
(Exact name of registrant as specified in its charter)
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Delaware (State or other jurisdiction of incorporation) | 1-9743 (Commission File Number) | 47-0684736 (I.R.S. Employer Identification No.) |
1111 Bagby, Sky Lobby 2
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
713-651-7000
(Registrant's telephone number, including area code)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
EOG RESOURCES, INC.
Item 2.02 Results of Operations and Financial Condition.
On February 27, 2017, EOG Resources, Inc. issued a press release announcing fourth quarter 2016 financial and operational results and first quarter and full year 2017 forecast and benchmark commodity pricing information (see Item 7.01 below). A copy of this release is attached as Exhibit 99.1 to this filing and is incorporated herein by reference. This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.
Item 7.01 Regulation FD Disclosure.
Accompanying the press release announcing fourth quarter 2016 financial and operational results attached hereto as Exhibit 99.1 is first quarter and full year 2017 forecast and benchmark commodity pricing information for EOG Resources, Inc., which information is incorporated herein by reference. This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.
Item 9.01 Financial Statements and Exhibits.
(d) Exhibits
99.1 Press Release of EOG Resources, Inc. dated February 27, 2017 (including the accompanying first quarter and full year 2017 forecast and benchmark commodity pricing information).
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
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| | EOG RESOURCES, INC. (Registrant) |
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Date: February 27, 2017 | By: | /s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Executive Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer) |
EXHIBIT INDEX
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Exhibit No. | | Description |
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99.1 | - | Press Release of EOG Resources, Inc. dated February 27, 2017 (including the accompanying first quarter and full year 2017 forecast and benchmark commodity pricing information). |
EXHIBIT 99.1
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EOG Resources, Inc. | P.O. Box 4362, Houston, TX 77210-4362 |
News Release | |
For Further Information Contact: | Investors |
| Cedric W. Burgher |
| (713) 571-4658 |
| David J. Streit |
| (713) 571-4902 |
| W. John Wagner |
| (713) 571-4404 |
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| Media and Investors |
| Kimberly M. Ehmer |
| (713) 571-4676 |
EOG Resources Reports Fourth Quarter and Full Year 2016 Results and Announces 2017 Capital Program
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• | Exceeds High-end of Fourth Quarter and Full Year 2016 Crude Oil Production Targets |
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• | Beats Fourth Quarter and Full Year 2016 Targets for Lease and Well, Transportation and DD&A Expenses |
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• | Achieves Record Capital Efficiency Gains in 2016 |
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• | 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 |
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• | Targets 18 Percent Crude Oil Production Growth for 2017 within Cash Flow at Flat $50 Oil |
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• | Forecasts Flat to Lower Well Costs in 2017 |
FOR IMMEDIATE RELEASE: Monday, February 27, 2017
HOUSTON - EOG Resources, Inc. (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:
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• | 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; |
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• | the extent to which EOG is successful in its efforts to acquire or discover additional reserves; |
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• | 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; |
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• | 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; |
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• | the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities; |
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• | 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; |
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• | 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; |
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• | 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; |
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• | the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically; |
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• | 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; |
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• | the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services; |
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• | the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; |
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• | 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; |
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• | 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; |
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• | 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; |
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• | the extent to which EOG is successful in its completion of planned asset dispositions; |
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• | the extent and effect of any hedging activities engaged in by EOG; |
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• | 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; |
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• | political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates; |
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• | the use of competing energy sources and the development of alternative energy sources; |
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• | the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; |
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• | acts of war and terrorism and responses to these acts; |
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• | physical, electronic and cyber security breaches; and |
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• | 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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EOG RESOURCES, INC. Financial Report (Unaudited; in millions, except per share data) |
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| Three Months Ended | | Twelve Months Ended |
| December 31, | | December 31, |
| 2016 | | 2015 | | 2016 | | 2015 |
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Net Operating Revenues | $ | 2,402 |
| | $ | 1,796.8 |
| | $ | 7,650.6 |
| | $ | 8,757.4 |
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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 |
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Diluted | | 567.3 |
| | | 546.4 |
| | | 553.4 |
| | | 545.7 |
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Summary Income Statements (Unaudited; in thousands, except per share data) |
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| 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 |
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Natural Gas Liquids | | 137,849 |
| | | 96,521 |
| | | 437,250 |
| | | 407,658 |
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Natural Gas | | 215,373 |
| | | 217,381 |
| | | 742,152 |
| | | 1,061,038 |
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Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | | (65,787 | ) | | | 4,970 |
| | | (99,608 | ) | | | 61,924 |
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Gathering, Processing and Marketing | | 614,594 |
| | | 432,292 |
| | | 1,966,259 |
| | | 2,253,135 |
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Gains (Losses) on Asset Dispositions, Net | | 104,034 |
| | | (3,656 | ) | | | 205,835 |
| | | (8,798 | ) |
Other, Net | | 29,753 |
| | | 8,783 |
| | | 81,403 |
| | | 47,909 |
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Total | | 2,402,039 |
| | | 1,796,761 |
| | | 7,650,632 |
| | | 8,757,428 |
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Operating Expenses | | | | | | | | | | | |
Lease and Well | | 241,846 |
| | | 247,916 |
| | | 927,452 |
| | | 1,182,282 |
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Transportation Costs | | 193,319 |
| | | 207,580 |
| | | 764,106 |
| | | 849,319 |
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Gathering and Processing Costs | | 32,516 |
| | | 39,653 |
| | | 122,901 |
| | | 146,156 |
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Exploration Costs | | 39,110 |
| | | 34,946 |
| | | 124,953 |
| | | 149,494 |
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Dry Hole Costs | | 193 |
| | | 429 |
| | | 10,657 |
| | | 14,746 |
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Impairments | | 297,946 |
| | | 168,171 |
| | | 620,267 |
| | | 6,613,546 |
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Marketing Costs | | 634,248 |
| | | 461,848 |
| | | 2,007,635 |
| | | 2,385,982 |
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Depreciation, Depletion and Amortization | | 862,524 |
| | | 769,457 |
| | | 3,553,417 |
| | | 3,313,644 |
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General and Administrative | | 102,182 |
| | | 109,014 |
| | | 394,815 |
| | | 366,594 |
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Taxes Other Than Income | | 103,642 |
| | | 87,500 |
| | | 349,710 |
| | | 421,744 |
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Total | | 2,507,526 |
| | | 2,126,514 |
| | | 8,875,913 |
| | | 15,443,507 |
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Operating Loss | | (105,487 | ) | | | (329,753 | ) | | | (1,225,281 | ) | | | (6,686,079 | ) |
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Other (Expense) Income, Net | | (17,198 | ) | | | (6,080 | ) | | | (50,543 | ) | | | 1,916 |
|
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Loss Before Interest Expense and Income Taxes | | (122,685 | ) | | | (335,833 | ) | | | (1,275,824 | ) | | | (6,684,163 | ) |
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Interest Expense, Net | | 71,325 |
| | | 62,993 |
| | | 281,681 |
| | | 237,393 |
|
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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 | ) |
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Net Loss | $ | (142,352 | ) | | $ | (284,296 | ) | | $ | (1,096,686 | ) | | $ | (4,524,515 | ) |
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Dividends Declared per Common Share | $ | 0.1675 |
| | $ | 0.1675 |
| | $ | 0.6700 |
| | $ | 0.6700 |
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EOG RESOURCES, INC. Operating Highlights (Unaudited) | |
| |
| Three Months Ended | | Twelve Months Ended | |
| December 31, | | December 31, | |
| 2016 | | 2015 | | 2016 | | 2015 | |
Wellhead Volumes and Prices | | | | |
Crude Oil and Condensate Volumes (MBbld) (A) | | | | |
United States | | 306.0 |
| | | 279.9 |
| | | 278.3 |
| | | 283.3 |
| |
Trinidad | | 0.9 |
| | | 0.9 |
| | | 0.8 |
| | | 0.9 |
| |
Other International (B) | | 4.8 |
| | | 0.2 |
| | | 3.4 |
| | | 0.2 |
| |
Total | | 311.7 |
| | | 281.0 |
| | | 282.5 |
| | | 284.4 |
| |
| |
Average Crude Oil and Condensate Prices ($/Bbl) (C) | | | | | | | | | | | | |
United States | $ | 47.93 |
| | $ | 40.34 |
| | $ | 41.84 |
| | $ | 47.55 |
| |
Trinidad | | 40.04 |
| | | 32.38 |
| | | 33.76 |
| | | 39.51 |
| |
Other International (B) | | 38.96 |
| | | 53.28 |
| | | 36.72 |
| | | 57.32 |
| |
Composite | | 47.76 |
| | | 40.32 |
| | | 41.76 |
| | | 47.53 |
| |
| |
Natural Gas Liquids Volumes (MBbld) (A) | | | | | | | | | | | | |
United States | | 80.9 |
| | | 79.1 |
| | | 81.6 |
| | | 76.9 |
| |
Other International (B) | | — |
| | | — |
| | | — |
| | | 0.1 |
| |
Total | | 80.9 |
| | | 79.1 |
| | | 81.6 |
| | | 77.0 |
| |
| |
Average Natural Gas Liquids Prices ($/Bbl) (C) | | | | | | | | | | | | |
United States | $ | 18.51 |
| | $ | 13.25 |
| | $ | 14.63 |
| | $ | 14.50 |
| |
Other International (B) | | — |
| | | — |
| | | — |
| | | 4.61 |
| |
Composite | | 18.51 |
| | | 13.25 |
| | | 14.63 |
| | | 14.49 |
| |
| |
Natural Gas Volumes (MMcfd) (A) | | | | | | | | | | | | |
United States | | 800 |
| | | 860 |
| | | 810 |
| | | 886 |
| |
Trinidad | | 323 |
| | | 370 |
| | | 340 |
| | | 349 |
| |
Other International (B) | | 22 |
| | | 27 |
| | | 25 |
| | | 30 |
| |
Total | | 1,145 |
| | | 1,257 |
| | | 1,175 |
| | | 1,265 |
| |
| |
Average Natural Gas Prices ($/Mcf) (C) | | | | | | | | | | | | |
United States | $ | 2.05 |
| | $ | 1.44 |
| | $ | 1.60 |
| | $ | 1.97 |
| |
Trinidad | | 1.89 |
| | | 2.57 |
| | | 1.88 |
| | | 2.89 |
| |
Other International (B) | | 3.85 |
| | | 6.51 |
| | | 3.64 |
| | | 5.05 |
| |
Composite | | 2.04 |
| | | 1.88 |
| | | 1.73 |
| | | 2.30 |
| |
| |
Crude Oil Equivalent Volumes (MBoed) (D) | | | | | | | | | | | | |
United States | | 520.3 |
| | | 502.2 |
| | | 494.9 |
| | | 507.9 |
| |
Trinidad | | 54.6 |
| | | 62.7 |
| | | 57.5 |
| | | 59.1 |
| |
Other International (B) | | 8.6 |
| | | 4.6 |
| | | 7.6 |
| | | 5.2 |
| |
Total | | 583.5 |
| | | 569.5 |
| | | 560.0 |
| | | 572.2 |
| |
| |
Total MMBoe (D) | | 53.7 |
| | | 52.4 |
| | | 205.0 |
| | | 208.9 |
| |
| |
(A) | Thousand barrels per day or million cubic feet per day, as applicable. |
| |
(B) | Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. |
| |
(C) | Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. |
| |
(D) | Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
|
| | | | | | | |
EOG RESOURCES, INC. Summary Balance Sheets (Unaudited; in thousands, except share data) |
|
| December 31, | | December 31, |
| 2016 | | 2015 |
ASSETS |
Current Assets | | | | | |
Cash and Cash Equivalents | $ | 1,599,895 |
| | $ | 718,506 |
|
Accounts Receivable, Net | | 1,216,320 |
| | | 930,610 |
|
Inventories | | 350,017 |
| | | 598,935 |
|
Income Taxes Receivable | | 12,305 |
| | | 40,704 |
|
Deferred Income Taxes | | 169,387 |
| | | 147,812 |
|
Other | | 206,679 |
| | | 155,677 |
|
Total | | 3,554,603 |
| | | 2,592,244 |
|
|
Property, Plant and Equipment | | | | | |
Oil and Gas Properties (Successful Efforts Method) | | 49,592,091 |
| | | 50,613,241 |
|
Other Property, Plant and Equipment | | 4,008,564 |
| | | 3,986,610 |
|
Total Property, Plant and Equipment | | 53,600,655 |
| | | 54,599,851 |
|
Less: Accumulated Depreciation, Depletion and Amortization | | (27,893,577 | ) | | | (30,389,130 | ) |
Total Property, Plant and Equipment, Net | | 25,707,078 |
| | | 24,210,721 |
|
Other Assets | | 197,752 |
| | | 167,505 |
|
Total Assets | $ | 29,459,433 |
| | $ | 26,970,470 |
|
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
Current Liabilities | | | | | |
Accounts Payable | $ | 1,511,826 |
| | $ | 1,471,953 |
|
Accrued Taxes Payable | | 118,411 |
| | | 93,618 |
|
Dividends Payable | | 96,120 |
| | | 91,546 |
|
Liabilities from Price Risk Management Activities | | 61,817 |
| | | — |
|
Current Portion of Long-Term Debt | | 6,579 |
| | | 6,579 |
|
Other | | 232,538 |
| | | 155,591 |
|
Total | | 2,027,291 |
| | | 1,819,287 |
|
| | | | | |
| | | | | |
Long-Term Debt | | 6,979,779 |
| | | 6,648,911 |
|
Other Liabilities | | 1,282,142 |
| | | 971,335 |
|
Deferred Income Taxes | | 5,188,640 |
| | | 4,587,902 |
|
Commitments and Contingencies | | | | | |
| | | | | |
Stockholders' Equity | | | | | |
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 576,950,272 Shares and 550,150,823 Shares Issued at December 31, 2016 and 2015, respectively | | 205,770 |
| | | 205,502 |
|
Additional Paid in Capital | | 5,420,385 |
| | | 2,923,461 |
|
Accumulated Other Comprehensive Loss | | (19,010 | ) | | | (33,338 | ) |
Retained Earnings | | 8,398,118 |
| | | 9,870,816 |
|
Common Stock Held in Treasury, 250,155 Shares and 292,179 Shares at December 31, 2016 and 2015, respectively | | (23,682 | ) | | | (23,406 | ) |
Total Stockholders' Equity | | 13,981,581 |
| | | 12,943,035 |
|
Total Liabilities and Stockholders' Equity | $ | 29,459,433 |
| | $ | 26,970,470 |
|
|
| | | | | | | |
EOG RESOURCES, INC. Summary Statements of Cash Flows (Unaudited; in thousands) |
| Twelve Months Ended |
| December 31, |
| 2016 | | 2015 |
Cash Flows from Operating Activities | | | | | |
Reconciliation of Net Loss to Net Cash Provided by Operating Activities: | | | | | |
Net Loss | $ | (1,096,686 | ) | | $ | (4,524,515 | ) |
Items Not Requiring (Providing) Cash | | | | | |
Depreciation, Depletion and Amortization | | 3,553,417 |
| | | 3,313,644 |
|
Impairments | | 620,267 |
| | | 6,613,546 |
|
Stock-Based Compensation Expenses | | 128,090 |
| | | 130,577 |
|
Deferred Income Taxes | | (515,206 | ) | | | (2,482,307 | ) |
(Gains) Losses on Asset Dispositions, Net | | (205,835 | ) | | | 8,798 |
|
Other, Net | | 61,690 |
| | | 11,896 |
|
Dry Hole Costs | | 10,657 |
| | | 14,746 |
|
Mark-to-Market Commodity Derivative Contracts | | | | | |
Total Losses (Gains) | | 99,608 |
| | | (61,924 | ) |
Net Cash (Payments for) Received from Settlements of Commodity Derivative Contracts | | (22,219 | ) | | | 730,114 |
|
Excess Tax Benefits from Stock-Based Compensation | | (29,357 | ) | | | (26,058 | ) |
Other, Net | | 10,971 |
| | | 12,532 |
|
Changes in Components of Working Capital and Other Assets and Liabilities | | | | | |
Accounts Receivable | | (232,799 | ) | | | 641,412 |
|
Inventories | | 170,694 |
| | | 58,450 |
|
Accounts Payable | | (74,048 | ) | | | (1,409,197 | ) |
Accrued Taxes Payable | | 92,782 |
| | | 11,798 |
|
Other Assets | | (40,636 | ) | | | 118,143 |
|
Other Liabilities | | (16,225 | ) | | | (66,257 | ) |
Changes in Components of Working Capital Associated with Investing and Financing Activities | | (156,102 | ) | | | 499,767 |
|
Net Cash Provided by Operating Activities | | 2,359,063 |
| | | 3,595,165 |
|
| | | | | |
Investing Cash Flows | | | | | |
Additions to Oil and Gas Properties | | (2,489,756 | ) | | | (4,725,150 | ) |
Additions to Other Property, Plant and Equipment | | (93,039 | ) | | | (288,013 | ) |
Proceeds from Sales of Assets | | 1,119,215 |
| | | 192,807 |
|
Net Cash Received from Yates Acquisition | | 54,534 |
| | | — |
|
Changes in Components of Working Capital Associated with Investing Activities | | 156,102 |
| | | (499,900 | ) |
Net Cash Used in Investing Activities | | (1,252,944 | ) | | | (5,320,256 | ) |
| | | | | |
Financing Cash Flows | | | | | |
Net Commercial Paper (Repayments) Borrowings | | (259,718 | ) | | | 259,718 |
|
Long-Term Debt Borrowings | | 991,097 |
| | | 990,225 |
|
Long-Term Debt Repayments | | (563,829 | ) | | | (500,000 | ) |
Dividends Paid | | (372,845 | ) | | | (367,005 | ) |
Excess Tax Benefits from Stock-Based Compensation | | 29,357 |
| | | 26,058 |
|
Treasury Stock Purchased | | (82,125 | ) | | | (48,791 | ) |
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | | 23,296 |
| | | 22,690 |
|
Debt Issuance Costs | | (1,602 | ) | | | (5,951 | ) |
Repayment of Capital Lease Obligation | | (6,353 | ) | | | (6,156 | ) |
Other, Net | | — |
| | | 133 |
|
Net Cash (Used in) Provided by Financing Activities | | (242,722 | ) | | | 370,921 |
|
| | | | | |
Effect of Exchange Rate Changes on Cash | | 17,992 |
| | | (14,537 | ) |
| | | | | |
Increase (Decrease) in Cash and Cash Equivalents | | 881,389 |
| | | (1,368,707 | ) |
Cash and Cash Equivalents at Beginning of Period | | 718,506 |
| | | 2,087,213 |
|
Cash and Cash Equivalents at End of Period | $ | 1,599,895 |
| | $ | 718,506 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EOG RESOURCES, INC. Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) To Net Loss (GAAP) (Unaudited; in thousands, except per share data) |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
The following chart adjusts the three-month and twelve-month periods ended December 31, 2016 and 2015 reported Net Loss (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2016 and 2015, to add back impairment charges related to certain of EOG's assets in 2016 and 2015, to add back an early leasehold termination payment as the result of a legal settlement in 2015, to eliminate the impact of the Texas margin tax rate reduction in 2015, to add back severance costs associated with EOG's North American operations in 2015, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, and to add back acquisition costs and state apportionment change related to the Yates transaction in 2016. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. |
| | | | | | | | | | | | |
| | Three Months Ended | | | Three Months Ended |
| | December 31, 2016 | | | December 31, 2015 |
| | | | | | | | | | | | |
| | Before Tax | | | Income Tax Impact | | | After Tax | | | Diluted Earnings per Share | | | Before Tax | | | Income Tax Impact | | | After Tax | | | Diluted Earnings per Share |
Reported Net Loss (GAAP) | $ | (194,010 | ) | | $ | 51,658 |
| | $ | (142,352 | ) | | $ | (0.25 | ) | | $ | (398,826 | ) | | $ | 114,530 |
| | $ | (284,296 | ) | | $ | (0.52 | ) |
Adjustments: | | | | | | | | | | | | | | | | | | | | | | | |
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts | | 65,787 |
| | | (23,583 | ) | | | 42,204 |
| | | 0.07 |
| | | (4,970 | ) | | | 1,772 |
| | | (3,198 | ) | | | (0.01 | ) |
Net Cash Received from Settlements of Commodity Derivative Contracts | | — |
| | | 29 |
| | | 29 |
| | | — |
| | | 69,093 |
| | | (24,632 | ) | | | 44,461 |
| | | 0.08 |
|
Add: Net (Gains) Losses on Asset Dispositions | | (104,034 | ) | | | 36,856 |
| | | (67,178 | ) | | | (0.12 | ) | | | 3,656 |
| | | (735 | ) | | | 2,921 |
| | | 0.01 |
|
Add: Impairments | | 217,839 |
| | | (76,728 | ) | | | 141,111 |
| | | 0.25 |
| | | 94,484 |
| | | (16,335 | ) | | | 78,149 |
| | | 0.15 |
|
Add: Legal Settlement - Early Leasehold Termination | | — |
| | | — |
| | | — |
| | | — |
| | | 19,355 |
| | | (6,900 | ) | | | 12,455 |
| | | 0.02 |
|
Add: Voluntary Retirement Expense | | — |
| | | (57 | ) | | | (57 | ) | | | — |
| | | — |
| | | — |
| | | — |
| | | — |
|
Add: Acquisition - State Apportionment Change | | — |
| | | 16,424 |
| | | 16,424 |
| | | 0.03 |
| | | — |
| | | — |
| | | — |
| | | — |
|
Add: Acquisition Costs | | 2,173 |
| | | 955 |
| | | 3,128 |
| | | 0.01 |
| | | — |
| | | — |
| | | — |
| | | — |
|
Adjustments to Net Income (Loss) | | 181,765 |
| | | (46,104 | ) | | | 135,661 |
| | | 0.24 |
| | | 181,618 |
| | | (46,830 | ) | | | 134,788 |
| | | 0.25 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Adjusted Net Income (Loss) (Non-GAAP) | $ | (12,245 | ) | | $ | 5,554 |
| | $ | (6,691 | ) | | $ | (0.01 | ) | | $ | (217,208 | ) | | $ | 67,700 |
| | $ | (149,508 | ) | | $ | (0.27 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
Average Number of Common Shares (GAAP) | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | | | | | | | | | | 567,337 |
| | | | | | | | | | | | 546,432 |
|
Diluted | | | | | | | | | | | 567,337 |
| | | | | | | | | | | | 546,432 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Average Number of Common Shares (Non-GAAP) | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | | | | | | | | | | 567,337 |
| | | | | | | | | | | | 546,432 |
|
Diluted | | | | | | | | | | | 567,337 |
| | | | | | | | | | | | 546,432 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Twelve Months Ended | | | | | | Twelve Months Ended |
| | December 31, 2016 | | | | | | December 31, 2015 |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Before Tax | | | Income Tax Impact | | | After Tax | | | Diluted Earnings per Share | | | Before Tax | | | Income Tax Impact | | | After Tax | | | Diluted Earnings per Share |
Reported Net Loss (GAAP) | $ | (1,557,505 | ) | | $ | 460,819 |
| | $ | (1,096,686 | ) | | $ | (1.98 | ) | | $ | (6,921,556 | ) | | $ | 2,397,041 |
| | $ | (4,524,515 | ) | | $ | (8.29 | ) |
Adjustments: | | | | | | | | | | | | | | | | | | | | | | | |
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts | | 99,608 |
| | | (35,640 | ) | | | 63,968 |
| | | 0.12 |
| | | (61,924 | ) | | | 22,076 |
| | | (39,848 | ) | | | (0.07 | ) |
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | | (22,219 | ) | | | 7,950 |
| | | (14,269 | ) | | | (0.03 | ) | | | 730,114 |
| | | (260,286 | ) | | | 469,828 |
| | | 0.86 |
|
Add: Net (Gains) Losses on Asset Dispositions | | (205,835 | ) | | | 61,491 |
| | | (144,344 | ) | | | (0.26 | ) | | | 8,798 |
| | | (4,183 | ) | | | 4,615 |
| | | 0.01 |
|
Add: Impairments | | 320,617 |
| | | (113,368 | ) | | | 207,249 |
| | | 0.37 |
| | | 6,307,592 |
| | | (2,182,220 | ) | | | 4,125,372 |
| | | 7.56 |
|
Add: Legal Settlement - Early Leasehold Termination | | — |
| | | — |
| | | — |
| | | — |
| | | 19,355 |
| | | (6,900 | ) | | | 12,455 |
| | | 0.02 |
|
Less: Texas Margin Tax Rate Reduction | | — |
| | | — |
| | | — |
| | | — |
| | | — |
| | | (19,500 | ) | | | (19,500 | ) | | | (0.04 | ) |
Add: Severance Costs | | — |
| | | — |
| | | — |
| | | — |
| | | 8,505 |
| | | (3,032 | ) | | | 5,473 |
| | | 0.01 |
|
Add: Trinidad Tax Settlement | | — |
| | | 43,000 |
| | | 43,000 |
| | | 0.08 |
| | | — |
| | | — |
| | | — |
| | | — |
|
Add: Voluntary Retirement Expense | | 42,054 |
| | | (15,047 | ) | | | 27,007 |
| | | 0.05 |
| | | — |
| | | — |
| | | — |
| | | — |
|
Add: Acquisition - State Apportionment Change | | — |
| | | 16,424 |
| | | 16,424 |
| | | 0.03 |
| | | — |
| | | — |
| | | — |
| | | — |
|
Add: Acquisition Costs | | 5,100 |
| | | (88 | ) | | | 5,012 |
| | | 0.01 |
| | | — |
| | | — |
| | | — |
| | | — |
|
Adjustments to Net Income (Loss) | | 239,325 |
| | | (35,278 | ) | | | 204,047 |
| | | 0.37 |
| | | 7,012,440 |
| | | (2,454,045 | ) | | | 4,558,395 |
| | | 8.35 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Adjusted Net Income (Loss) (Non-GAAP) | $ | (1,318,180 | ) | | $ | 425,541 |
| | $ | (892,639 | ) | | $ | (1.61 | ) | | $ | 90,884 |
| | $ | (57,004 | ) | | $ | 33,880 |
| | $ | 0.06 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Average Number of Common Shares (GAAP) | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | | | | | | | | | | 553,384 |
| | | | | | | | | | | | 545,697 |
|
Diluted | | | | | | | | | | | 553,384 |
| | | | | | | | | | | | 545,697 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Average Number of Common Shares (Non-GAAP) | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | | | | | | | | | | 553,384 |
| | | | | | | | | | | | 545,697 |
|
Diluted | | | | | | | | | | | 553,384 |
| | | | | | | | | | | | 549,610 |
|
|
| | | | | | | | | | | | | | | |
EOG RESOURCES, INC. Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) To Net Cash Provided by Operating Activities (GAAP) (Unaudited; in thousands) |
|
The following chart reconciles the three-month and twelve-month periods ended December 31, 2016 and 2015 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. |
|
| Three Months Ended | | Twelve Months Ended |
| December 31, | | December 31, |
| 2016 | | 2015 | | 2016 | | 2015 |
|
Net Cash Provided by Operating Activities (GAAP) | $ | 804,745 |
| | $ | 615,813 |
| | $ | 2,359,063 |
| | $ | 3,595,165 |
|
| | | | | | | | | | | |
Adjustments: | | | | | | | | | | | |
Exploration Costs (excluding Stock-Based Compensation Expenses) | | 33,931 |
| | | 28,758 |
| | | 104,199 |
| | | 124,011 |
|
Excess Tax Benefits from Stock-Based Compensation | | 7,286 |
| | | 1,839 |
| | | 29,357 |
| | | 26,058 |
|
Changes in Components of Working Capital and Other Assets and Liabilities | | | | | | | | | | | |
Accounts Receivable | | 220,939 |
| | | (193,101 | ) | | | 232,799 |
| | | (641,412 | ) |
Inventories | | (33,131 | ) | | | (31,443 | ) | | | (170,694 | ) | | | (58,450 | ) |
Accounts Payable | | (127,165 | ) | | | 98,986 |
| | | 74,048 |
| | | 1,409,197 |
|
Accrued Taxes Payable | | 21,214 |
| | | 65,777 |
| | | (92,782 | ) | | | (11,798 | ) |
Other Assets | | 28,110 |
| | | 28,822 |
| | | 40,636 |
| | | (118,143 | ) |
Other Liabilities | | 53,024 |
| | | 50,574 |
| | | 16,225 |
| | | 66,257 |
|
Changes in Components of Working Capital Associated with Investing and Financing Activities | | 36,342 |
| | | 19,436 |
| | | 156,102 |
| | | (499,767 | ) |
| | | | | | | | | | | |
Discretionary Cash Flow (Non-GAAP) | $ | 1,045,295 |
| | $ | 685,461 |
| | $ | 2,748,953 |
| | $ | 3,891,118 |
|
| | | | | | | | | | | |
Discretionary Cash Flow (Non-GAAP) - Percentage Increase/Decrease | | 52 | % | | | | | | -29 | % | | | |
|
| | | | | | | | | | | | | | | |
EOG RESOURCES, INC. Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) (Non-GAAP) to Net Loss (GAAP) (Unaudited; in thousands) |
| | | | | | | | | | | |
The following chart adjusts the three-month and twelve-month periods ended December 31, 2016 and 2015 reported Net Loss (GAAP) to Earnings Before Interest Expense, Income Taxes (Income Tax Benefit), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense, Income Taxes (Income Tax Benefit), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. |
| | | | | | | | | | | |
| Three Months Ended | | Twelve Months Ended |
| December 31, | | December 31, |
| 2016 | | 2015 | | 2016 | | 2015 |
| | | | | | | | | | | |
Net Loss (GAAP) | $ | (142,352 | ) | | $ | (284,296 | ) | | $ | (1,096,686 | ) | | $ | (4,524,515 | ) |
| | | | | | | | | | | |
Adjustments: | | | | | | | | | | | |
Interest Expense, Net | | 71,325 |
| | | 62,993 |
| | | 281,681 |
| | | 237,393 |
|
Income Tax Benefit | | (51,658 | ) | | | (114,530 | ) | | | (460,819 | ) | | | (2,397,041 | ) |
Depreciation, Depletion and Amortization | | 862,524 |
| | | 769,457 |
| | | 3,553,417 |
| | | 3,313,644 |
|
Exploration Costs | | 39,110 |
| | | 34,946 |
| | | 124,953 |
| | | 149,494 |
|
Dry Hole Costs | | 193 |
| | | 429 |
| | | 10,657 |
| | | 14,746 |
|
Impairments | | 297,946 |
| | | 168,171 |
| | | 620,267 |
| | | 6,613,546 |
|
EBITDAX (Non-GAAP) | | 1,077,088 |
| | | 637,170 |
| | | 3,033,470 |
| | | 3,407,267 |
|
Total (Gains) Losses on MTM Commodity Derivative Contracts | | 65,787 |
| | | (4,970 | ) | | | 99,608 |
| | | (61,924 | ) |
Net Cash Received from (Payments for)Settlements of Commodity Derivative Contracts | | — |
| | | 69,093 |
| | | (22,219 | ) | | | 730,114 |
|
(Gains) Losses on Asset Dispositions, Net | | (104,034 | ) | | | 3,656 |
| | | (205,835 | ) | | | 8,798 |
|
| | | | | | | | | | | |
Adjusted EBITDAX (Non-GAAP) | $ | 1,038,841 |
| | $ | 704,949 |
| | $ | 2,905,024 |
| | $ | 4,084,255 |
|
| | | | | | | | | | | |
Adjusted EBITDAX (Non-GAAP) - Percentage Increase/Decrease | | 47 | % | | | | | | -29 | % | | | |
|
| | | | | | | |
EOG RESOURCES, INC. Quantitative Reconciliation of Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as Used in the Calculation of The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) (Unaudited; in millions, except ratio data) |
| | |
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. |
| | |
| At | | At |
| December 31, | | December 31, |
| 2016 | | 2015 |
| | |
Total Stockholders' Equity - (a) | $ | 13,982 |
| | $ | 12,943 |
|
| | | | | |
Current and Long-Term Debt (GAAP) - (b) | | 6,986 |
| | | 6,655 |
|
Less: Cash | | (1,600 | ) | | | (719 | ) |
Net Debt (Non-GAAP) - (c) | | 5,386 |
| | | 5,936 |
|
| | | | | |
Total Capitalization (GAAP) - (a) + (b) | $ | 20,968 |
| | $ | 19,598 |
|
| | | | | |
Total Capitalization (Non-GAAP) - (a) + (c) | $ | 19,368 |
| | $ | 18,879 |
|
| | | | | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | | 33 | % | | | 34 | % |
| | | | | |
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | | 28 | % | | | 31 | % |
|
| | | | | | | | | | | | | | | |
EOG RESOURCES, INC. |
Reserves Supplemental Data |
(Unaudited) |
| | | | | | | |
2016 NET PROVED RESERVES RECONCILIATION SUMMARY |
| United States | | Trinidad | | Other 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 EQUIVALANTS (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 21, 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 States | | Trinidad | | Other 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 States | | Trinidad | | Other 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 Cost 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 (MMBbl) | | | | | | | |
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 data) |
| |
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 | |
| |
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 $/Bbl. |
| | | | |
Crude Oil Price Swap Contracts |
| | Volume (Bbld) | | Weighted Average Price ($/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 $/MMBtu. |
| | | | |
Natural Gas Price Swap Contracts |
| | Volume (MMBtud) | | Weighted Average Price ($/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 $/MMbtu. |
|
Natural Gas Option Contracts |
| Call Options Sold | | Put Options Purchased |
| Volume (MMBtud) | | Weighted
Average Price
($/MMBtu) | | Volume (MMBtud) | | Weighted
Average Price
($/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 |
|
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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 Tax | | Income Tax Impact | | After 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 Tax | | Income Tax Impact | | After 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 Tax | | Income Tax Impact | | After 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. 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 |
|
|
|
| | | | | | | | | | | | | | | | | | | |
| Estimated Ranges (Unaudited) |
| 1Q 2017 | | Full Year 2017 |
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 | | | | | | | | | | | |
This regulatory filing also includes additional resources:
eog8kpressrelease022717.pdf
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