HOUSTON, Aug. 6, 2015 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported second quarter 2015 net income of $5.3 million, or $0.01 per share. This compares to second quarter 2014 net income of $706.4 million, or $1.29 per share.
Adjusted non-GAAP net income for the second quarter 2015 was $153.1 million, or $0.28 per share, compared to the same prior year period adjusted non-GAAP net income of $796.0 million, or $1.45 per share. Adjusted non-GAAP net income is calculated by matching realizations to settlement months and making certain other adjustments in order to exclude one-time items. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP.)
Higher cash settlements from commodity derivative contracts and lower operating expenses were offset by lower commodity price realizations, resulting in decreases in adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the second quarter 2015 compared to the second quarter 2014. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Operational Highlights
In the second quarter 2015, total crude oil and condensate production increased by one percent compared to the second quarter 2014, excluding production related to EOG's Canadian operations which were divested in December 2014. On the same basis, overall total company production decreased three percent compared to the same prior year period. Total capital expenditures decreased 40 percent compared to the prior year.
In the second quarter 2015, EOG continued to improve well productivity and reduce completed well costs and operating costs. The integration of the latest high-density completion designs in combination with improved wellbore placement resulted in increased well productivity. EOG achieved significant well and operating cost reductions through operational efficiencies and service cost reductions. The combination of increased well productivity and lower costs is enabling the company to make higher returns at lower oil prices.
"EOG's return-driven culture is responding extremely well to low oil prices, and we are excited about the company's continued improvement," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "The company is generating good returns in all our key assets with $50 oil. Our goal is to continue our progress and remain the industry leader in capital returns."
2015 Capital Plan Update
As a result of productivity improvements and cost reductions, EOG is maintaining full year 2015 oil production guidance and reducing full year 2015 capital spending guidance by $200 million, excluding acquisitions. The company is choosing to refrain from growing oil production into an over-supplied market. EOG's focus in 2015 is on capital efficiency to improve returns and quickly transition the company to be successful in a lower commodity price environment.
North Dakota Bakken
EOG increased its net resource potential in the Bakken and Three Forks plays in the second quarter 2015 from approximately 400 million barrels of oil equivalent (MMBoe) to 1.0 billion barrels of oil equivalent (BnBoe) and grew total net drillable locations from 580 to 1,540. Successful down-spacing and advances in completion technology have generated excellent well results and led to the expanded resource potential. As a result, EOG has decades of high-return drilling potential ready to be developed.
"Our team's outstanding technical and operational advances have enabled us to more than double prior estimates for our position in the Bakken and Three Forks," said Thomas. "EOG's Bakken and Three Forks assets along with the company's Eagle Ford and Delaware Basin positions continue to grow in both size and quality. With these premier assets, EOG is uniquely positioned for high-return growth in a low oil price environment."
In the second quarter 2015, the company continued to make well productivity gains. EOG completed an industry record Bakken well using enhanced high-density completion techniques. The Riverview 102-32H came on line producing 3,395 barrels of oil per day (Bopd) and 6.0 million cubic feet per day (MMcfd) of rich natural gas.
South Texas Eagle Ford
EOG continued to realize strong rates of return and capital efficiencies in the Eagle Ford, EOG's largest play. High-density completions, enhanced wellbore targeting and lower completed well costs are dramatically improving EOG's results across the entire Eagle Ford oil window.
During the second quarter 2015 in the eastern Eagle Ford in Gonzales County, the Otto Unit 3H and 9H, a two-well pattern, had average initial production rates per well of 4,405 Bopd, 515 barrels per day (Bpd) of NGLs and 3.4 MMcfd of natural gas. Also in Gonzales County, the Lefevre Unit 17H – 19H (three-well pattern) had average initial production rates per well of 4,150 Bopd, 405 Bpd of NGLs and 2.7 MMcfd of natural gas.
In McMullen County in the western Eagle Ford, EOG completed the Naylor Jones Unit 11 1H and 2H two-well pattern, which had average initial production rates per well of 3,150 Bopd, 170 Bpd of NGLs and 1.1 MMcfd of natural gas.
Delaware Basin
In the Delaware Basin, EOG continued to actively test and develop its positions in the Leonard, the Second Bone Spring Sand and the upper Wolfcamp, as well as significantly reduce completed well costs and operating costs.
In the Leonard, EOG completed the Gem 36 State Com #1H in Lea County, N.M., which had initial production rates of 2,200 Bopd, 460 Bpd of NGLs and 2.6 MMcfd of natural gas.
In the Second Bone Spring Sand, EOG completed several wells with excellent results. In Lea County, N.M., EOG completed the Dragon 36 State #501H and #502H in a two-well pattern, which had average initial production rates per well of 1,415 Bopd, 115 Bpd of NGLs and 0.9 MMcfd of natural gas. Also in Lea County, N.M., EOG completed the Frazier 34 State Com #501H with an initial flow rate of 1,705 Bopd, 145 Bpd of NGLs and 1.1 MMcfd of natural gas.
In the Wolfcamp in Lea County, N.M., EOG completed the Hearns 27 State Com #703H, which had an initial production rate of 2,830 Bopd, 170 Bpd of NGLs and 1.1 MMcfd of natural gas.
Hedging Activity
For the period August 1 through December 31, 2015, EOG has crude oil financial price swap contracts in place for 10,000 Bopd at a weighted average price of $89.98 per barrel.
For the period September 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 million British thermal units per day at a weighted average price of $4.51 per million British thermal units, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)
Capital Structure
At June 30, 2015, EOG's total debt outstanding was $6.4 billion for a debt-to-total capitalization ratio of 27 percent. Taking into account cash on the balance sheet of $1.4 billion at June 30, EOG's net debt was $5.0 billion for a net debt-to-total capitalization ratio of 22 percent. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP.)
Conference Call August 7, 2015
EOG's second quarter 2015 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, August 7, 2015. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through August 21, 2015.
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
For Further Information Contact: |
Investors |
|
Cedric W. Burgher |
||
(713) 571-4658 |
||
David J. Streit |
||
(713) 571-4902 |
||
Kimberly M. Ehmer |
||
(713) 571-4676 |
||
Media |
||
K Leonard |
||
(713) 571-3870 |
EOG RESOURCES, INC. |
|||||||||||
Financial Report |
|||||||||||
(Unaudited; in millions, except per share data) |
|||||||||||
Three Months Ended |
Six Months Ended |
||||||||||
June 30, |
June 30, |
||||||||||
2015 |
2014 |
2015 |
2014 |
||||||||
Net Operating Revenues |
$ |
2,469.7 |
$ |
4,187.6 |
$ |
4,788.2 |
$ |
8,271.2 |
|||
Net Income (Loss) |
$ |
5.3 |
$ |
706.4 |
$ |
(164.5) |
$ |
1,367.3 |
|||
Net Income (Loss) Per Share |
|||||||||||
Basic |
$ |
0.01 |
$ |
1.30 |
$ |
(0.30) |
$ |
2.52 |
|||
Diluted |
$ |
0.01 |
$ |
1.29 |
$ |
(0.30) |
$ |
2.49 |
|||
Average Number of Common Shares |
|||||||||||
Basic |
545.5 |
543.1 |
545.2 |
542.7 |
|||||||
Diluted |
549.7 |
548.7 |
545.2 |
548.0 |
|||||||
Summary Income Statements |
|||||||||||
(Unaudited; in thousands, except per share data) |
|||||||||||
Three Months Ended |
Six Months Ended |
||||||||||
June 30, |
June 30, |
||||||||||
2015 |
2014 |
2015 |
2014 |
||||||||
Net Operating Revenues |
|||||||||||
Crude Oil and Condensate |
$ |
1,452,756 |
$ |
2,618,975 |
$ |
2,713,000 |
$ |
5,016,077 |
|||
Natural Gas Liquids |
103,930 |
247,973 |
215,920 |
494,208 |
|||||||
Natural Gas |
274,038 |
509,091 |
561,820 |
1,065,784 |
|||||||
Gains (Losses) on Mark-to-Market Commodity |
|||||||||||
Derivative Contracts |
(48,493) |
(229,270) |
27,715 |
(385,006) |
|||||||
Gathering, Processing and Marketing |
678,356 |
1,027,795 |
1,248,626 |
2,043,206 |
|||||||
Gains (Losses) on Asset Dispositions, Net |
(5,564) |
3,856 |
(3,957) |
15,354 |
|||||||
Other, Net |
14,678 |
9,136 |
25,115 |
21,604 |
|||||||
Total |
2,469,701 |
4,187,556 |
4,788,239 |
8,271,227 |
|||||||
Operating Expenses |
|||||||||||
Lease and Well |
289,664 |
346,458 |
651,145 |
667,292 |
|||||||
Transportation Costs |
209,833 |
240,579 |
438,145 |
483,816 |
|||||||
Gathering and Processing Costs |
34,997 |
32,470 |
71,006 |
66,394 |
|||||||
Exploration Costs |
43,755 |
42,208 |
83,204 |
90,266 |
|||||||
Dry Hole Costs |
(551) |
5,558 |
14,119 |
13,906 |
|||||||
Impairments |
68,519 |
39,035 |
137,955 |
152,396 |
|||||||
Marketing Costs |
670,169 |
1,043,515 |
1,308,831 |
2,049,819 |
|||||||
Depreciation, Depletion and Amortization |
909,227 |
996,602 |
1,822,015 |
1,943,093 |
|||||||
General and Administrative |
82,324 |
90,932 |
166,621 |
173,794 |
|||||||
Taxes Other Than Income |
122,138 |
205,469 |
228,567 |
401,442 |
|||||||
Total |
2,430,075 |
3,042,826 |
4,921,608 |
6,042,218 |
|||||||
Operating Income (Loss) |
39,626 |
1,144,730 |
(133,369) |
2,229,009 |
|||||||
Other Income (Expense), Net |
9,380 |
7,950 |
(611) |
4,612 |
|||||||
Income (Loss) Before Interest Expense and Income Taxes |
49,006 |
1,152,680 |
(133,980) |
2,233,621 |
|||||||
Interest Expense, Net |
60,484 |
51,867 |
113,829 |
102,019 |
|||||||
Income (Loss) Before Income Taxes |
(11,478) |
1,100,813 |
(247,809) |
2,131,602 |
|||||||
Income Tax Provision (Benefit) |
(16,746) |
394,460 |
(83,329) |
764,321 |
|||||||
Net Income (Loss) |
$ |
5,268 |
$ |
706,353 |
$ |
(164,480) |
$ |
1,367,281 |
|||
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1250 |
$ |
0.3350 |
$ |
0.2500 |
|||
EOG RESOURCES, INC. |
|||||||||||
Operating Highlights |
|||||||||||
(Unaudited) |
|||||||||||
Three Months Ended |
Six Months Ended |
||||||||||
June 30, |
June 30, |
||||||||||
2015 |
2014 |
2015 |
2014 |
||||||||
Wellhead Volumes and Prices |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||||||||
United States |
276.5 |
274.6 |
287.5 |
266.4 |
|||||||
Trinidad |
0.7 |
1.0 |
0.9 |
1.0 |
|||||||
Other International (B) |
0.3 |
5.7 |
0.2 |
6.5 |
|||||||
Total |
277.5 |
281.3 |
288.6 |
273.9 |
|||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
57.47 |
$ |
102.66 |
$ |
51.91 |
$ |
101.66 |
|||
Trinidad |
49.53 |
94.25 |
44.03 |
92.09 |
|||||||
Other International (B) |
62.40 |
94.61 |
56.67 |
92.01 |
|||||||
Composite |
57.45 |
102.47 |
51.89 |
101.40 |
|||||||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||||||||
United States |
73.4 |
78.5 |
75.4 |
74.7 |
|||||||
Other International (B) |
0.1 |
0.7 |
0.1 |
0.7 |
|||||||
Total |
73.5 |
79.2 |
75.5 |
75.4 |
|||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
15.55 |
$ |
34.35 |
$ |
15.83 |
$ |
36.12 |
|||
Other International (B) |
7.81 |
40.90 |
5.80 |
44.15 |
|||||||
Composite |
15.54 |
34.41 |
15.82 |
36.20 |
|||||||
Natural Gas Volumes (MMcfd) (A) |
|||||||||||
United States |
891 |
925 |
898 |
910 |
|||||||
Trinidad |
334 |
380 |
336 |
384 |
|||||||
Other International (B) |
32 |
78 |
31 |
74 |
|||||||
Total |
1,257 |
1,383 |
1,265 |
1,368 |
|||||||
Average Natural Gas Prices ($/Mcf) (C) |
|||||||||||
United States |
$ |
2.11 |
$ |
4.14 |
$ |
2.19 |
$ |
4.54 |
|||
Trinidad |
3.05 |
3.69 |
3.07 |
3.66 |
|||||||
Other International (B) |
3.49 |
4.68 |
3.39 |
4.75 |
|||||||
Composite |
2.40 |
4.04 |
2.45 |
4.31 |
|||||||
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||||||||
United States |
498.3 |
507.2 |
512.6 |
492.7 |
|||||||
Trinidad |
56.5 |
64.5 |
56.8 |
65.0 |
|||||||
Other International (B) |
5.7 |
19.3 |
5.5 |
19.6 |
|||||||
Total |
560.5 |
591.0 |
574.9 |
577.3 |
|||||||
Total MMBoe (D) |
51.0 |
53.8 |
104.1 |
104.5 |
(A) |
Thousand barrels per day or million cubic feet per day, as applicable. |
(B) |
Other International includes EOG's Canada, United Kingdom, China and Argentina operations. |
(C) |
Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. |
(D) |
Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. |
|||||
Summary Balance Sheets |
|||||
(Unaudited; in thousands, except share data) |
|||||
June 30, |
December 31, |
||||
2015 |
2014 |
||||
ASSETS |
|||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
1,367,395 |
$ |
2,087,213 |
|
Accounts Receivable, Net |
1,304,848 |
1,779,311 |
|||
Inventories |
661,162 |
706,597 |
|||
Assets from Price Risk Management Activities |
106,821 |
465,128 |
|||
Income Taxes Receivable |
48,448 |
71,621 |
|||
Deferred Income Taxes |
39,613 |
19,618 |
|||
Other |
209,431 |
286,533 |
|||
Total |
3,737,718 |
5,416,021 |
|||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
48,936,092 |
46,503,532 |
|||
Other Property, Plant and Equipment |
3,840,210 |
3,750,958 |
|||
Total Property, Plant and Equipment |
52,776,302 |
50,254,490 |
|||
Less: Accumulated Depreciation, Depletion and Amortization |
(22,801,124) |
(21,081,846) |
|||
Total Property, Plant and Equipment, Net |
29,975,178 |
29,172,644 |
|||
Other Assets |
171,200 |
174,022 |
|||
Total Assets |
$ |
33,884,096 |
$ |
34,762,687 |
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
|||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,864,483 |
$ |
2,860,548 |
|
Accrued Taxes Payable |
164,366 |
140,098 |
|||
Dividends Payable |
91,500 |
91,594 |
|||
Deferred Income Taxes |
- |
110,743 |
|||
Current Portion of Long-Term Debt |
6,579 |
6,579 |
|||
Other |
150,653 |
174,746 |
|||
Total |
2,277,581 |
3,384,308 |
|||
Long-Term Debt |
6,393,885 |
5,903,354 |
|||
Other Liabilities |
986,758 |
939,497 |
|||
Deferred Income Taxes |
6,798,629 |
6,822,946 |
|||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and |
205,496 |
205,492 |
|||
Additional Paid in Capital |
2,857,588 |
2,837,150 |
|||
Accumulated Other Comprehensive Loss |
(28,003) |
(23,056) |
|||
Retained Earnings |
14,414,926 |
14,763,098 |
|||
Common Stock Held in Treasury, 256,101 Shares at June 30, 2015 |
|||||
and 733,517 Shares at December 31, 2014 |
(22,764) |
(70,102) |
|||
Total Stockholders' Equity |
17,427,243 |
17,712,582 |
|||
Total Liabilities and Stockholders' Equity |
$ |
33,884,096 |
$ |
34,762,687 |
|
EOG RESOURCES, INC. |
|||||
Summary Statements of Cash Flows |
|||||
(Unaudited; in thousands) |
|||||
Six Months Ended |
|||||
June 30, |
|||||
2015 |
2014 |
||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: |
|||||
Net Income (Loss) |
$ |
(164,480) |
$ |
1,367,281 |
|
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
1,822,015 |
1,943,093 |
|||
Impairments |
137,955 |
152,396 |
|||
Stock-Based Compensation Expenses |
61,650 |
65,144 |
|||
Deferred Income Taxes |
(154,803) |
479,109 |
|||
(Gains) Losses on Asset Dispositions, Net |
3,957 |
(15,354) |
|||
Other, Net |
6,787 |
984 |
|||
Dry Hole Costs |
14,119 |
13,906 |
|||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total (Gains) Losses |
(27,715) |
385,006 |
|||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
561,142 |
(120,900) |
|||
Excess Tax Benefits from Stock-Based Compensation |
(16,393) |
(63,759) |
|||
Other, Net |
6,346 |
7,223 |
|||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
298,183 |
(249,336) |
|||
Inventories |
37,609 |
(109,756) |
|||
Accounts Payable |
(999,644) |
347,539 |
|||
Accrued Taxes Payable |
64,124 |
115,668 |
|||
Other Assets |
76,114 |
(141,453) |
|||
Other Liabilities |
(48,848) |
57,101 |
|||
Changes in Components of Working Capital Associated with Investing and Financing |
169,802 |
(31,644) |
|||
Net Cash Provided by Operating Activities |
1,847,920 |
4,202,248 |
|||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(2,611,848) |
(3,724,486) |
|||
Additions to Other Property, Plant and Equipment |
(201,597) |
(402,972) |
|||
Proceeds from Sales of Assets |
116,166 |
74,512 |
|||
Changes in Restricted Cash |
- |
(91,238) |
|||
Changes in Components of Working Capital Associated with Investing Activities |
(169,903) |
31,620 |
|||
Net Cash Used in Investing Activities |
(2,867,182) |
(4,112,564) |
|||
Financing Cash Flows |
|||||
Long-Term Debt Borrowings |
990,225 |
496,220 |
|||
Long-Term Debt Repayments |
(500,000) |
(500,000) |
|||
Settlement of Foreign Currency Swap |
- |
(31,573) |
|||
Dividends Paid |
(183,130) |
(119,684) |
|||
Excess Tax Benefits from Stock-Based Compensation |
16,393 |
63,759 |
|||
Treasury Stock Purchased |
(26,362) |
(89,524) |
|||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
14,484 |
10,433 |
|||
Debt Issuance Costs |
(1,585) |
(895) |
|||
Repayment of Capital Lease Obligation |
(3,053) |
(2,958) |
|||
Other, Net |
101 |
24 |
|||
Net Cash Provided by (Used in) Financing Activities |
307,073 |
(174,198) |
|||
Effect of Exchange Rate Changes on Cash |
(7,629) |
(3,555) |
|||
Decrease in Cash and Cash Equivalents |
(719,818) |
(88,069) |
|||
Cash and Cash Equivalents at Beginning of Period |
2,087,213 |
1,318,209 |
|||
Cash and Cash Equivalents at End of Period |
$ |
1,367,395 |
$ |
1,230,140 |
EOG RESOURCES, INC. |
Quantitative Reconciliation of Adjusted Net Income (Non-GAAP) |
to Net Income (Loss) (GAAP) |
(Unaudited; in thousands, except per share data) |
The following chart adjusts the three-month and six-month periods ended June 30, 2015 and 2014 reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the impact of the Texas margin tax rate reduction in 2015, to eliminate the net (gains) losses on asset dispositions in North America, to add back severance costs associated with EOG's North American operations in 2015 and to add back impairment charges related to certain of EOG's North American assets in 2014. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry. |
Three Months Ended |
Six Months Ended |
||||||||||
June 30, |
June 30, |
||||||||||
2015 |
2014 |
2015 |
2014 |
||||||||
Reported Net Income (Loss) (GAAP) |
$ |
5,268 |
$ |
706,353 |
$ |
(164,480) |
$ |
1,367,281 |
|||
Commodity Derivative Contracts Impact |
|||||||||||
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts |
48,493 |
229,270 |
(27,715) |
385,006 |
|||||||
Net Cash Received from (Payments for) Settlements of Commodity |
193,435 |
(86,867) |
561,142 |
(120,900) |
|||||||
Subtotal |
241,928 |
142,403 |
533,427 |
264,106 |
|||||||
After-Tax MTM Impact |
155,680 |
91,359 |
343,260 |
169,437 |
|||||||
Less: Texas Margin Tax Rate Reduction |
(19,500) |
- |
(19,500) |
- |
|||||||
Less: Net (Gains) Losses on Asset Dispositions, Net of Tax |
6,134 |
(1,663) |
5,123 |
(9,040) |
|||||||
Add: Severance Costs, Net of Tax |
5,473 |
- |
5,473 |
- |
|||||||
Add: Impairments of Certain North American Assets, Net of Tax |
- |
- |
- |
36,058 |
|||||||
Adjusted Net Income (Non-GAAP) |
$ |
153,055 |
$ |
796,049 |
$ |
169,876 |
$ |
1,563,736 |
|||
Net Income (Loss) Per Share (GAAP) |
|||||||||||
Basic |
$ |
0.01 |
$ |
1.30 |
$ |
(0.30) |
$ |
2.52 |
|||
Diluted |
$ |
0.01 |
$ |
1.29 |
$ |
(0.30) |
$ |
2.49 |
|||
Adjusted Net Income Per Share (Non-GAAP) |
|||||||||||
Basic |
$ |
0.28 |
$ |
1.47 |
$ |
0.31 |
$ |
2.88 |
|||
Diluted |
$ |
0.28 |
$ |
1.45 |
$ |
0.31 |
$ |
2.85 |
|||
Adjusted Net Income Per Diluted Share (Non-GAAP) - Percentage Decrease |
-81 |
% |
-89 |
% |
|||||||
Average Number of Common Shares (GAAP) |
|||||||||||
Basic |
545,504 |
543,099 |
545,245 |
542,675 |
|||||||
Diluted |
549,683 |
548,676 |
545,245 |
548,046 |
|||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||
Basic |
545,504 |
543,099 |
545,245 |
542,675 |
|||||||
Diluted |
549,683 |
548,676 |
549,505 |
548,046 |
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 six-month periods ended June 30, 2015 and 2014 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. |
Three Months Ended |
Six Months Ended |
||||||||||
June 30, |
June 30, |
||||||||||
2015 |
2014 |
2015 |
2014 |
||||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
887,373 |
$ |
1,934,575 |
$ |
1,847,920 |
$ |
4,202,248 |
|||
Adjustments: |
|||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
37,870 |
36,659 |
69,967 |
76,783 |
|||||||
Excess Tax Benefits from Stock-Based Compensation |
7,535 |
36,337 |
16,393 |
63,759 |
|||||||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||||||||
Accounts Receivable |
54,917 |
105,019 |
(298,183) |
249,336 |
|||||||
Inventories |
(99,781) |
40,808 |
(37,609) |
109,756 |
|||||||
Accounts Payable |
321,769 |
14,271 |
999,644 |
(347,539) |
|||||||
Accrued Taxes Payable |
(62,019) |
24,133 |
(64,124) |
(115,668) |
|||||||
Other Assets |
(16,938) |
128,917 |
(76,114) |
141,453 |
|||||||
Other Liabilities |
16,993 |
(86,270) |
48,848 |
(57,101) |
|||||||
Changes in Components of Working Capital Associated with Investing and |
|||||||||||
Financing Activities |
90,190 |
(36,639) |
(169,802) |
31,644 |
|||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
1,237,909 |
$ |
2,197,810 |
$ |
2,336,940 |
$ |
4,354,671 |
|||
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease |
-44 |
% |
-46 |
% |
EOG RESOURCES, INC. |
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, |
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, |
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) |
(Non-GAAP) to Income (Loss) Before Interest Expense and Income Taxes (GAAP) |
(Unaudited; in thousands) |
The following chart adjusts the three-month and six-month periods ended June 30, 2015 and 2014 reported Income (Loss) Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions in North America. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income (Loss) Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry. |
Three Months Ended |
Six Months Ended |
||||||||||
June 30, |
June 30, |
||||||||||
2015 |
2014 |
2015 |
2014 |
||||||||
Income (Loss) Before Interest Expense and Income Taxes (GAAP) |
$ |
49,006 |
$ |
1,152,680 |
$ |
(133,980) |
$ |
2,233,621 |
|||
Adjustments: |
|||||||||||
Depreciation, Depletion and Amortization |
909,227 |
996,602 |
1,822,015 |
1,943,093 |
|||||||
Exploration Costs |
43,755 |
42,208 |
83,204 |
90,266 |
|||||||
Dry Hole Costs |
(551) |
5,558 |
14,119 |
13,906 |
|||||||
Impairments |
68,519 |
39,035 |
137,955 |
152,396 |
|||||||
EBITDAX (Non-GAAP) |
1,069,956 |
2,236,083 |
1,923,313 |
4,433,282 |
|||||||
Total (Gains) Losses on MTM Commodity Derivative |
|||||||||||
Contracts |
48,493 |
229,270 |
(27,715) |
385,006 |
|||||||
Net Cash Received from (Payments for) Settlements of |
|||||||||||
Commodity Derivative Contracts |
193,435 |
(86,867) |
561,142 |
(120,900) |
|||||||
(Gains) Losses on Asset Dispositions, Net |
5,564 |
(3,856) |
3,957 |
(15,354) |
|||||||
Adjusted EBITDAX (Non-GAAP) |
$ |
1,317,448 |
$ |
2,374,630 |
$ |
2,460,697 |
$ |
4,682,034 |
|||
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease |
-45 |
% |
-47 |
% |
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 |
|||||
June 30, |
December 31, |
|||||
2015 |
2014 |
|||||
Total Stockholders' Equity - (a) |
$ |
17,427 |
$ |
17,713 |
||
Current and Long-Term Debt (GAAP) - (b) |
6,400 |
5,910 |
||||
Less: Cash |
(1,367) |
(2,087) |
||||
Net Debt (Non-GAAP) - (c) |
5,033 |
3,823 |
||||
Total Capitalization (GAAP) - (a) + (b) |
$ |
23,827 |
$ |
23,623 |
||
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
22,460 |
$ |
21,536 |
||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
27 |
% |
25 |
% |
||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
22 |
% |
18 |
% |
EOG RESOURCES, INC. |
||||||
Crude Oil and Natural Gas Financial |
||||||
Commodity Derivative Contracts |
||||||
Presented below is a comprehensive summary of EOG's crude oil and natural gas derivative contracts at August 6, 2015, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. |
||||||
Crude Oil Derivative Contracts |
||||||
Weighted |
||||||
Volume |
Average Price |
|||||
(Bbld) |
($/Bbl) |
|||||
2015 |
||||||
January 1, 2015 through June 30, 2015 (closed) |
47,000 |
$ |
91.22 |
|||
July 2015 (closed) |
10,000 |
89.98 |
||||
August 1, 2015 through December 31, 2015 |
10,000 |
89.98 |
||||
Natural Gas Derivative Contracts |
||||||
Weighted |
||||||
Volume |
Average Price |
|||||
(MMBtud) |
($/MMBtu) |
|||||
2015 (1) |
||||||
January 1, 2015 through February 28, 2015 (closed) |
235,000 |
$ |
4.47 |
|||
March 2015 (closed) |
225,000 |
4.48 |
||||
April 2015 (closed) |
195,000 |
4.49 |
||||
May 2015 (closed) |
235,000 |
4.13 |
||||
June 2015 (closed) |
275,000 |
3.97 |
||||
July 2015 (closed) |
275,000 |
3.98 |
||||
August 2015 (closed) |
175,000 |
4.51 |
||||
September 1, 2015 through December 31, 2015 |
175,000 |
4.51 |
(1) |
EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. All such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period September 1, 2015 through December 31, 2015. |
$/Bbl Dollars per barrel |
||
$/MMBtu Dollars per million British thermal units |
||
Bbld Barrels per day |
||
MMBtu Million British thermal units |
||
MMBtud Million British thermal units per day |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. |
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income |
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of |
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), |
Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively |
(Unaudited; in millions, except ratio data) |
The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for comparative purposes within the industry. |
2014 |
2013 |
2012 |
||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||
Net Interest Expense (GAAP) |
$ |
201 |
$ |
235 |
||||
Tax Benefit Imputed (based on 35%) |
(70) |
(82) |
||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
131 |
$ |
153 |
||||
Net Income (GAAP) - (b) |
$ |
2,915 |
$ |
2,197 |
||||
Add: After-Tax Mark-to-Market Commodity Derivative Contracts Impact |
(515) |
182 |
||||||
Add: Impairments of Certain Assets, Net of Tax |
553 |
4 |
||||||
Add: Tax Expense Related to the Repatriation of Accumulated |
250 |
- |
||||||
Less: Net Gains on Asset Dispositions, Net of Tax |
(487) |
(137) |
||||||
Adjusted Net Income (Non-GAAP) - (c) |
$ |
2,716 |
$ |
2,246 |
||||
Total Stockholders' Equity - (d) |
$ |
17,713 |
$ |
15,418 |
$ |
13,285 |
||
Average Total Stockholders' Equity * - (e) |
$ |
16,566 |
$ |
14,352 |
||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
5,910 |
$ |
5,913 |
$ |
6,312 |
||
Less: Cash |
(2,087) |
(1,318) |
(876) |
|||||
Net Debt (Non-GAAP) - (g) |
$ |
3,823 |
$ |
4,595 |
$ |
5,436 |
||
Total Capitalization (GAAP) - (d) + (f) |
$ |
23,623 |
$ |
21,331 |
$ |
19,597 |
||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
21,536 |
$ |
20,013 |
$ |
18,721 |
||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
20,775 |
$ |
19,367 |
||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
14.7 |
% |
12.1 |
% |
||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
13.7 |
% |
12.4 |
% |
||||
Return on Equity (ROE) (Non-GAAP) |
||||||||
ROE (GAAP Net Income) - (b) / (e) |
17.6 |
% |
15.3 |
% |
||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) |
16.4 |
% |
15.6 |
% |
||||
* Average for the current and immediately preceding year |
EOG RESOURCES, INC. |
Third Quarter and Full Year 2015 Forecast and Benchmark Commodity Pricing |
(a) Third Quarter and Full Year 2015 Forecast |
The forecast items for the third quarter and full year 2015 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. |
(b) Benchmark Commodity Pricing |
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. |
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. |
Estimated Ranges |
||||||||||||||
(Unaudited) |
||||||||||||||
3Q 2015 |
Full Year 2015 |
|||||||||||||
Daily Production |
||||||||||||||
Crude Oil and Condensate Volumes (MBbld) |
||||||||||||||
United States |
269.0 |
- |
277.0 |
279.2 |
- |
284.2 |
||||||||
Trinidad |
0.6 |
- |
0.8 |
0.7 |
- |
0.9 |
||||||||
Other International |
0.1 |
- |
0.3 |
4.0 |
- |
6.5 |
||||||||
Total |
269.7 |
- |
278.1 |
283.9 |
- |
291.6 |
||||||||
Natural Gas Liquids Volumes (MBbld) |
||||||||||||||
Total |
72.0 |
- |
77.0 |
74.0 |
- |
77.0 |
||||||||
Natural Gas Volumes (MMcfd) |
||||||||||||||
United States |
845 |
- |
885 |
870 |
- |
890 |
||||||||
Trinidad |
330 |
- |
360 |
330 |
- |
345 |
||||||||
Other International |
27 |
- |
32 |
28 |
- |
30 |
||||||||
Total |
1,202 |
- |
1,277 |
1,228 |
- |
1,265 |
||||||||
Crude Oil Equivalent Volumes (MBoed) |
||||||||||||||
United States |
481.8 |
- |
501.5 |
498.2 |
- |
509.5 |
||||||||
Trinidad |
55.6 |
- |
60.8 |
55.7 |
- |
58.4 |
||||||||
Other International |
4.6 |
- |
5.6 |
8.7 |
- |
11.5 |
||||||||
Total |
542.0 |
- |
567.9 |
562.6 |
- |
579.4 |
||||||||
Operating Costs |
||||||||||||||
Unit Costs ($/Boe) |
||||||||||||||
Lease and Well |
$ |
5.70 |
- |
$ |
6.60 |
$ |
6.00 |
- |
$ |
6.40 |
||||
Transportation Costs |
$ |
4.30 |
- |
$ |
4.70 |
$ |
4.30 |
- |
$ |
4.50 |
||||
Depreciation, Depletion and Amortization |
$ |
17.60 |
- |
$ |
18.00 |
$ |
17.70 |
- |
$ |
17.90 |
||||
Expenses ($MM) |
||||||||||||||
Exploration, Dry Hole and Impairment |
$ |
140 |
- |
$ |
160 |
$ |
515 |
- |
$ |
555 |
||||
General and Administrative |
$ |
90 |
- |
$ |
100 |
$ |
345 |
- |
$ |
370 |
||||
Gathering and Processing |
$ |
32 |
- |
$ |
36 |
$ |
135 |
- |
$ |
145 |
||||
Capitalized Interest |
$ |
10 |
- |
$ |
11 |
$ |
42 |
- |
$ |
45 |
||||
Net Interest |
$ |
59 |
- |
$ |
60 |
$ |
230 |
- |
$ |
235 |
||||
Taxes Other Than Income (% of Wellhead Revenue) |
6.5 |
% |
- |
7.0 |
% |
6.5 |
% |
- |
6.7 |
% |
||||
Income Taxes |
||||||||||||||
Effective Rate |
25 |
% |
- |
35 |
% |
25 |
% |
- |
35 |
% |
||||
Current Taxes ($MM) |
$ |
60 |
- |
$ |
75 |
$ |
175 |
- |
$ |
200 |
||||
Capital Expenditures (Excluding Acquisitions, $MM) |
||||||||||||||
Exploration and Development, Excluding Facilities |
$ |
3,700 |
- |
$ |
3,800 |
|||||||||
Exploration and Development Facilities |
$ |
670 |
- |
$ |
710 |
|||||||||
Gathering, Processing and Other |
$ |
330 |
- |
$ |
390 |
|||||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) |
||||||||||||||
Crude Oil and Condensate ($/Bbl) |
||||||||||||||
Differentials |
||||||||||||||
United States - above (below) WTI |
$ |
(1.60) |
- |
$ |
0.40 |
$ |
(1.70) |
- |
$ |
(0.70) |
||||
Trinidad - above (below) WTI |
$ |
(10.50) |
- |
$ |
(9.50) |
$ |
(10.00) |
- |
$ |
(9.25) |
||||
Natural Gas Liquids |
||||||||||||||
Realizations as % of WTI |
24 |
% |
- |
28 |
% |
27 |
% |
- |
29 |
% |
||||
Natural Gas ($/Mcf) |
||||||||||||||
Differentials |
||||||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(0.80) |
- |
$ |
(0.35) |
$ |
(0.75) |
- |
$ |
(0.45) |
||||
Realizations |
||||||||||||||
Trinidad |
$ |
2.75 |
- |
$ |
3.25 |
$ |
2.90 |
- |
$ |
3.15 |
||||
Other International |
$ |
3.25 |
- |
$ |
3.75 |
$ |
3.35 |
- |
$ |
3.55 |
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-reports-second-quarter-2015-results-increases-potential-bakken-reserves-to-10-bnboe-300125222.html
SOURCE EOG Resources, Inc.