x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Oklahoma | 73-0767549 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
20 N. Broadway, Oklahoma City, Oklahoma | 73102 | |
(Address of principal executive offices) | (Zip Code) |
Large accelerated filer | x | Accelerated filer | ¨ | |||
Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ | |||
Emerging growth company | ¨ | |||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨ |
Item 1. | ||
Item 2. | ||
Item 3. | ||
Item 4. | ||
Item 1. | ||
Item 1A. | ||
Item 2. | ||
Item 3. | ||
Item 4. | ||
Item 5. | ||
Item 6. | ||
• | our strategy; |
• | our business and financial plans; |
• | our future operations; |
• | our crude oil and natural gas reserves and related development plans; |
• | technology; |
• | future crude oil, natural gas liquids, and natural gas prices and differentials; |
• | the timing and amount of future production of crude oil and natural gas and flaring activities; |
• | the amount, nature and timing of capital expenditures; |
• | estimated revenues, expenses and results of operations; |
• | drilling and completing of wells; |
• | competition; |
• | marketing of crude oil and natural gas; |
• | transportation of crude oil, natural gas liquids, and natural gas to markets; |
• | property exploitation or property acquisitions and dispositions; |
• | costs of exploiting and developing our properties and conducting other operations; |
• | our financial position; |
• | general economic conditions; |
• | credit markets; |
• | our liquidity and access to capital; |
• | the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes; |
• | our future operating and financial results; |
• | our future commodity or other hedging arrangements; and |
• | the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us. |
ITEM 1. | Financial Statements |
June 30, 2017 | December 31, 2016 | |||||||
In thousands, except par values and share data | (Unaudited) | |||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 17,190 | $ | 16,643 | ||||
Receivables: | ||||||||
Crude oil and natural gas sales | 385,975 | 404,750 | ||||||
Affiliated parties | 58 | 99 | ||||||
Joint interest and other, net | 402,391 | 364,850 | ||||||
Derivative assets | 17,809 | 4,061 | ||||||
Inventories | 97,003 | 111,987 | ||||||
Prepaid expenses and other | 13,616 | 10,843 | ||||||
Total current assets | 934,042 | 913,233 | ||||||
Net property and equipment, based on successful efforts method of accounting | 12,921,875 | 12,881,227 | ||||||
Other noncurrent assets | 15,340 | 17,316 | ||||||
Total assets | $ | 13,871,257 | $ | 13,811,776 | ||||
Liabilities and shareholders’ equity | ||||||||
Current liabilities: | ||||||||
Accounts payable trade | $ | 689,772 | $ | 476,342 | ||||
Revenues and royalties payable | 238,530 | 217,425 | ||||||
Payables to affiliated parties | 218 | 148 | ||||||
Accrued liabilities and other | 159,391 | 176,770 | ||||||
Derivative liabilities | 4,817 | 59,489 | ||||||
Current portion of long-term debt | 2,250 | 2,219 | ||||||
Total current liabilities | 1,094,978 | 932,393 | ||||||
Long-term debt, net of current portion | 6,553,740 | 6,577,697 | ||||||
Other noncurrent liabilities: | ||||||||
Deferred income tax liabilities, net | 1,853,321 | 1,890,305 | ||||||
Asset retirement obligations, net of current portion | 100,470 | 94,436 | ||||||
Other noncurrent liabilities | 14,413 | 14,949 | ||||||
Total other noncurrent liabilities | 1,968,204 | 1,999,690 | ||||||
Commitments and contingencies (Note 7) | ||||||||
Shareholders’ equity: | ||||||||
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding | — | — | ||||||
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 375,206,922 shares issued and outstanding at June 30, 2017; 374,492,357 shares issued and outstanding at December 31, 2016 | 3,752 | 3,745 | ||||||
Additional paid-in capital | 1,385,233 | 1,375,290 | ||||||
Accumulated other comprehensive income (loss) | 67 | (260 | ) | |||||
Retained earnings | 2,865,283 | 2,923,221 | ||||||
Total shareholders’ equity | 4,254,335 | 4,301,996 | ||||||
Total liabilities and shareholders’ equity | $ | 13,871,257 | $ | 13,811,776 |
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
In thousands, except per share data | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Revenues: | ||||||||||||||||
Crude oil and natural gas sales | $ | 626,548 | $ | 525,711 | $ | 1,260,398 | $ | 929,302 | ||||||||
Gain (loss) on crude oil and natural gas derivatives, net | 28,022 | (82,257 | ) | 74,880 | (40,145 | ) | ||||||||||
Crude oil and natural gas service operations | 6,916 | 7,757 | 11,636 | 15,227 | ||||||||||||
Total revenues | 661,486 | 451,211 | 1,346,914 | 904,384 | ||||||||||||
Operating costs and expenses: | ||||||||||||||||
Production expenses | 82,474 | 74,083 | 155,328 | 152,724 | ||||||||||||
Production taxes | 41,965 | 39,141 | 83,198 | 69,634 | ||||||||||||
Exploration expenses | 3,204 | 1,674 | 8,202 | 4,739 | ||||||||||||
Crude oil and natural gas service operations | 4,478 | 3,576 | 7,315 | 6,618 | ||||||||||||
Depreciation, depletion, amortization and accretion | 395,770 | 441,761 | 777,926 | 905,752 | ||||||||||||
Property impairments | 123,316 | 66,112 | 174,689 | 145,039 | ||||||||||||
General and administrative expenses | 39,186 | 36,246 | 86,407 | 68,654 | ||||||||||||
Net (gain) loss on sale of assets and other | 134 | (100,835 | ) | 5,669 | (99,127 | ) | ||||||||||
Total operating costs and expenses | 690,527 | 561,758 | 1,298,734 | 1,254,033 | ||||||||||||
Income (loss) from operations | (29,041 | ) | (110,547 | ) | 48,180 | (349,649 | ) | |||||||||
Other income (expense): | ||||||||||||||||
Interest expense | (72,744 | ) | (81,922 | ) | (143,916 | ) | (162,875 | ) | ||||||||
Other | 373 | 435 | 815 | 819 | ||||||||||||
(72,371 | ) | (81,487 | ) | (143,101 | ) | (162,056 | ) | |||||||||
Loss before income taxes | (101,412 | ) | (192,034 | ) | (94,921 | ) | (511,705 | ) | ||||||||
Benefit for income taxes | 37,855 | 72,632 | 31,833 | 193,978 | ||||||||||||
Net loss | $ | (63,557 | ) | $ | (119,402 | ) | $ | (63,088 | ) | $ | (317,727 | ) | ||||
Basic net loss per share | $ | (0.17 | ) | $ | (0.32 | ) | $ | (0.17 | ) | $ | (0.86 | ) | ||||
Diluted net loss per share | $ | (0.17 | ) | $ | (0.32 | ) | $ | (0.17 | ) | $ | (0.86 | ) | ||||
Comprehensive loss: | ||||||||||||||||
Net loss | $ | (63,557 | ) | $ | (119,402 | ) | $ | (63,088 | ) | $ | (317,727 | ) | ||||
Other comprehensive income, net of tax: | ||||||||||||||||
Foreign currency translation adjustments | 189 | 25 | 327 | 451 | ||||||||||||
Total other comprehensive income, net of tax | 189 | 25 | 327 | 451 | ||||||||||||
Comprehensive loss | $ | (63,368 | ) | $ | (119,377 | ) | $ | (62,761 | ) | $ | (317,276 | ) |
In thousands, except share data | Shares outstanding | Common stock | Additional paid-in capital | Accumulated other comprehensive income (loss) | Retained earnings | Total shareholders’ equity | |||||||||||||||||
Balance at December 31, 2016 | 374,492,357 | $ | 3,745 | $ | 1,375,290 | $ | (260 | ) | $ | 2,923,221 | $ | 4,301,996 | |||||||||||
Cumulative effect adjustment from adoption of ASU 2016-09 (unaudited) (see Note 2) | — | — | — | — | 5,150 | 5,150 | |||||||||||||||||
Net loss (unaudited) | — | — | — | — | (63,088 | ) | (63,088 | ) | |||||||||||||||
Other comprehensive income, net of tax (unaudited) | — | — | — | 327 | — | 327 | |||||||||||||||||
Stock-based compensation (unaudited) | — | — | 20,561 | — | — | 20,561 | |||||||||||||||||
Restricted stock: | |||||||||||||||||||||||
Granted (unaudited) | 1,464,944 | 14 | — | — | — | 14 | |||||||||||||||||
Repurchased and canceled (unaudited) | (230,377 | ) | (2 | ) | (10,618 | ) | — | — | (10,620 | ) | |||||||||||||
Forfeited (unaudited) | (520,002 | ) | (5 | ) | — | — | — | (5 | ) | ||||||||||||||
Balance at June 30, 2017 (unaudited) | 375,206,922 | $ | 3,752 | $ | 1,385,233 | $ | 67 | $ | 2,865,283 | $ | 4,254,335 |
Six months ended June 30, | ||||||||
In thousands | 2017 | 2016 | ||||||
Cash flows from operating activities | ||||||||
Net loss | $ | (63,088 | ) | $ | (317,727 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
Depreciation, depletion, amortization and accretion | 774,810 | 908,021 | ||||||
Property impairments | 174,689 | 145,039 | ||||||
Non-cash (gain) loss on derivatives, net | (68,420 | ) | 114,972 | |||||
Stock-based compensation | 20,571 | 21,046 | ||||||
Benefit for deferred income taxes | (31,834 | ) | (193,990 | ) | ||||
Dry hole costs | 157 | 206 | ||||||
(Gain) loss on sale of assets, net | 2,859 | (97,016 | ) | |||||
Other, net | 5,089 | 4,752 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (19,347 | ) | (34,939 | ) | ||||
Inventories | 14,984 | (8,745 | ) | |||||
Other current assets | (2,225 | ) | (2,125 | ) | ||||
Accounts payable trade | 105,441 | (53,859 | ) | |||||
Revenues and royalties payable | 21,105 | (742 | ) | |||||
Accrued liabilities and other | (17,968 | ) | 15,347 | |||||
Other noncurrent assets and liabilities | (251 | ) | (2,519 | ) | ||||
Net cash provided by operating activities | 916,572 | 497,721 | ||||||
Cash flows from investing activities | ||||||||
Exploration and development | (877,115 | ) | (625,126 | ) | ||||
Purchase of producing crude oil and natural gas properties | (812 | ) | — | |||||
Purchase of other property and equipment | (9,372 | ) | (4,867 | ) | ||||
Proceeds from sale of assets | 7,979 | 112,199 | ||||||
Net cash used in investing activities | (879,320 | ) | (517,794 | ) | ||||
Cash flows from financing activities | ||||||||
Credit facility borrowings | 540,000 | 638,000 | ||||||
Repayment of credit facility | (565,000 | ) | (606,000 | ) | ||||
Repayment of other debt | (1,099 | ) | (1,064 | ) | ||||
Debt issuance costs | — | (40 | ) | |||||
Repurchase of restricted stock for tax withholdings | (10,620 | ) | (5,735 | ) | ||||
Net cash (used in) provided by financing activities | (36,719 | ) | 25,161 | |||||
Effect of exchange rate changes on cash | 14 | 9 | ||||||
Net change in cash and cash equivalents | 547 | 5,097 | ||||||
Cash and cash equivalents at beginning of period | 16,643 | 11,463 | ||||||
Cash and cash equivalents at end of period | $ | 17,190 | $ | 16,560 |
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
In thousands, except per share data | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Net loss (numerator) | $ | (63,557 | ) | $ | (119,402 | ) | $ | (63,088 | ) | $ | (317,727 | ) | ||||
Weighted average shares (denominator): | ||||||||||||||||
Weighted average shares - basic | 371,111 | 370,435 | 370,972 | 370,248 | ||||||||||||
Non-vested restricted stock (1) | — | — | — | — | ||||||||||||
Weighted average shares - diluted | 371,111 | 370,435 | 370,972 | 370,248 | ||||||||||||
Net loss per share: | ||||||||||||||||
Basic | $ | (0.17 | ) | $ | (0.32 | ) | $ | (0.17 | ) | $ | (0.86 | ) | ||||
Diluted | $ | (0.17 | ) | $ | (0.32 | ) | $ | (0.17 | ) | $ | (0.86 | ) |
(1) | For the three and six months ended June 30, 2017, the Company had a net loss and therefore the potential dilutive effect of approximately 1,933,200 and 2,546,200 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations. The Company also had net losses for the three and six months ended June 30, 2016, and therefore approximately 1,940,700 and 1,486,200 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share for those periods. |
In thousands | June 30, 2017 | December 31, 2016 | ||||||
Tubular goods and equipment | $ | 15,723 | $ | 15,243 | ||||
Crude oil | 81,280 | 96,744 | ||||||
Total | $ | 97,003 | $ | 111,987 |
Six months ended June 30, | ||||||||
In thousands | 2017 | 2016 | ||||||
Supplemental cash flow information: | ||||||||
Cash paid for interest | $ | 138,346 | $ | 156,358 | ||||
Cash paid for income taxes | 2 | — | ||||||
Cash received for income tax refunds | 148 | 20 | ||||||
Non-cash investing activities: | ||||||||
Asset retirement obligation additions and revisions, net | 3,771 | 1,042 |
Collars | |||||||||||||||||||
Natural Gas - NYMEX Henry Hub | Swaps Weighted Average Price | Floors | Ceilings | ||||||||||||||||
Weighted Average Price | Weighted Average Price | ||||||||||||||||||
Period and Type of Contract | MMBtus | Range | Range | ||||||||||||||||
July 2017 - December 2017 | |||||||||||||||||||
Swaps - Henry Hub | 66,240,000 | $ | 3.39 | ||||||||||||||||
Collars - Henry Hub | 33,120,000 | $2.40 - $3.00 | $ | 2.47 | $2.92 - $3.88 | $ | 3.08 | ||||||||||||
January 2018 - March 2018 | |||||||||||||||||||
Swaps - Henry Hub | 6,300,000 | $ | 3.28 |
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
In thousands | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Cash received (paid) on derivatives: | ||||||||||||||||
Natural gas fixed price swaps | $ | 6,709 | $ | 38,778 | $ | 12,187 | $ | 77,967 | ||||||||
Natural gas collars | (3,050 | ) | — | (9,456 | ) | — | ||||||||||
Cash received on derivatives, net | 3,659 | 38,778 | 2,731 | 77,967 | ||||||||||||
Non-cash gain (loss) on derivatives: | ||||||||||||||||
Crude oil written call options | — | 6 | — | 38 | ||||||||||||
Natural gas fixed price swaps | 12,520 | (101,308 | ) | 35,416 | (98,915 | ) | ||||||||||
Natural gas collars | 11,843 | (19,733 | ) | 36,733 | (19,235 | ) | ||||||||||
Non-cash gain (loss) on derivatives, net | 24,363 | (121,035 | ) | 72,149 | (118,112 | ) | ||||||||||
Gain (loss) on crude oil and natural gas derivatives, net | $ | 28,022 | $ | (82,257 | ) | $ | 74,880 | $ | (40,145 | ) |
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
In thousands | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Cash received on diesel fuel derivatives | $ | 185 | $ | — | $ | 919 | $ | — | ||||||||
Non-cash gain (loss) on diesel fuel derivatives | (1,098 | ) | 4,200 | (3,729 | ) | 3,140 | ||||||||||
Gain (loss) on diesel fuel derivatives, net | $ | (913 | ) | $ | 4,200 | $ | (2,810 | ) | $ | 3,140 |
In thousands | June 30, 2017 | December 31, 2016 | ||||||
Commodity derivative assets: | ||||||||
Gross amounts of recognized assets | $ | 19,746 | $ | 4,061 | ||||
Gross amounts offset on balance sheet | (1,937 | ) | — | |||||
Net amounts of assets on balance sheet | 17,809 | 4,061 | ||||||
Commodity derivative liabilities: | ||||||||
Gross amounts of recognized liabilities | (6,754 | ) | (59,489 | ) | ||||
Gross amounts offset on balance sheet | 1,937 | — | ||||||
Net amounts of liabilities on balance sheet | $ | (4,817 | ) | $ | (59,489 | ) |
In thousands | June 30, 2017 | December 31, 2016 | ||||||
Derivative assets | $ | 17,809 | $ | 4,061 | ||||
Noncurrent derivative assets | — | — | ||||||
Net amounts of assets on balance sheet | 17,809 | 4,061 | ||||||
Derivative liabilities | (4,817 | ) | (59,489 | ) | ||||
Noncurrent derivative liabilities | — | — | ||||||
Net amounts of liabilities on balance sheet | (4,817 | ) | (59,489 | ) | ||||
Total derivative assets (liabilities), net | $ | 12,992 | $ | (55,428 | ) |
• | Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. |
• | Level 2: Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. |
• | Level 3: Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. |
Fair value measurements at June 30, 2017 using: | ||||||||||||||||
In thousands | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Derivative assets (liabilities): | ||||||||||||||||
Swaps | $ | — | $ | 19,390 | $ | — | $ | 19,390 | ||||||||
Collars | — | (6,398 | ) | — | (6,398 | ) | ||||||||||
Total | $ | — | $ | 12,992 | $ | — | $ | 12,992 | ||||||||
Fair value measurements at December 31, 2016 using: | ||||||||||||||||
In thousands | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Derivative liabilities: | ||||||||||||||||
Swaps | $ | — | $ | (12,297 | ) | $ | — | $ | (12,297 | ) | ||||||
Collars | — | (43,131 | ) | — | (43,131 | ) | ||||||||||
Total | $ | — | $ | (55,428 | ) | $ | — | $ | (55,428 | ) |
Unobservable Input | Assumption | |
Future production | Future production estimates for each property | |
Forward commodity prices | Forward NYMEX strip prices through 2021 (adjusted for differentials), escalating 3% per year thereafter | |
Operating costs | Estimated costs for the current year, escalating 3% per year thereafter | |
Productive life of field | Ranging from 0 to 39 years | |
Discount rate | 10% |
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
In thousands | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Proved property impairments | $ | 81,469 | $ | — | $ | 82,340 | $ | — | ||||||||
Unproved property impairments | 41,847 | 66,112 | 92,349 | 145,039 | ||||||||||||
Total | $ | 123,316 | $ | 66,112 | $ | 174,689 | $ | 145,039 |
June 30, 2017 | December 31, 2016 | |||||||||||||||
In thousands | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||
Debt: | ||||||||||||||||
Revolving credit facility | $ | 880,000 | $ | 880,000 | $ | 905,000 | $ | 905,000 | ||||||||
Term loan | 499,175 | 500,000 | 498,865 | 500,000 | ||||||||||||
Note payable | 11,083 | 11,100 | 12,176 | 10,200 | ||||||||||||
5% Senior Notes due 2022 | 1,997,376 | 1,962,300 | 1,997,188 | 2,020,400 | ||||||||||||
4.5% Senior Notes due 2023 | 1,485,585 | 1,434,800 | 1,484,524 | 1,474,800 | ||||||||||||
3.8% Senior Notes due 2024 | 991,495 | 917,200 | 990,964 | 929,400 | ||||||||||||
4.9% Senior Notes due 2044 | 691,276 | 587,700 | 691,199 | 607,600 | ||||||||||||
Total debt | $ | 6,555,990 | $ | 6,293,100 | $ | 6,579,916 | $ | 6,447,400 |
In thousands | June 30, 2017 | December 31, 2016 | ||||||
Revolving credit facility | $ | 880,000 | $ | 905,000 | ||||
Term loan | 499,175 | 498,865 | ||||||
Note payable | 11,083 | 12,176 | ||||||
5% Senior Notes due 2022 | 1,997,376 | 1,997,188 | ||||||
4.5% Senior Notes due 2023 | 1,485,585 | 1,484,524 | ||||||
3.8% Senior Notes due 2024 | 991,495 | 990,964 | ||||||
4.9% Senior Notes due 2044 | 691,276 | 691,199 | ||||||
Total debt | $ | 6,555,990 | $ | 6,579,916 | ||||
Less: Current portion of long-term debt | 2,250 | 2,219 | ||||||
Long-term debt, net of current portion | $ | 6,553,740 | $ | 6,577,697 |
2022 Notes (1) | 2023 Notes | 2024 Notes | 2044 Notes | |||||
Face value (in thousands) | $2,000,000 | $1,500,000 | $1,000,000 | $700,000 | ||||
Maturity date | Sep 15, 2022 | April 15, 2023 | June 1, 2024 | June 1, 2044 | ||||
Interest payment dates | March 15, Sep 15 | April 15, Oct 15 | June 1, Dec 1 | June 1, Dec 1 | ||||
Make-whole redemption period (2) | — | Jan 15, 2023 | Mar 1, 2024 | Dec 1, 2043 |
(1) | The Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. |
(2) | At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after these dates, the Company may redeem all or a portion of its senior notes at a redemption price equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption. |
Number of non-vested shares | Weighted average grant-date fair value | ||||||
Non-vested restricted shares outstanding at December 31, 2016 | 3,913,634 | $ | 37.12 | ||||
Granted | 1,464,944 | 45.06 | |||||
Vested | (785,487 | ) | 58.66 | ||||
Forfeited | (520,002 | ) | 37.47 | ||||
Non-vested restricted shares outstanding at June 30, 2017 | 4,073,089 | $ | 35.78 |
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
In thousands | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Beginning accumulated other comprehensive loss, net of tax | $ | (122 | ) | $ | (2,928 | ) | $ | (260 | ) | $ | (3,354 | ) | ||||
Foreign currency translation adjustments | 189 | 25 | 327 | 451 | ||||||||||||
Income taxes (1) | — | — | — | — | ||||||||||||
Other comprehensive income, net of tax | 189 | 25 | 327 | 451 | ||||||||||||
Ending accumulated other comprehensive income (loss), net of tax | $ | 67 | $ | (2,903 | ) | $ | 67 | $ | (2,903 | ) |
(1) | A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive income. |
Three months ended June 30, | Six months ended June 30, | |||||||||||||||||||||||||||
$ in thousands | 2017 | Tax rate % | 2016 | Tax rate % | 2017 | Tax rate % | 2016 | Tax rate % | ||||||||||||||||||||
Expected income tax benefit based on US statutory tax rate of 35% | $ | 35,494 | 35 | % | $ | 67,212 | 35 | % | $ | 33,222 | 35 | % | $ | 179,097 | 35 | % | ||||||||||||
State income taxes, net of federal benefit | 3,043 | 3 | % | 5,761 | 3 | % | 2,848 | 3 | % | 15,351 | 3 | % | ||||||||||||||||
Tax deficiency from stock-based compensation (1) | (473 | ) | (1 | %) | — | — | % | (3,773 | ) | (4 | %) | — | — | % | ||||||||||||||
Canadian valuation allowance (2) | (112 | ) | — | % | (217 | ) | — | % | (257 | ) | — | % | (294 | ) | — | % | ||||||||||||
Effect of differing statutory tax rate in Canada | (55 | ) | — | % | (90 | ) | — | % | (122 | ) | — | % | (124 | ) | — | % | ||||||||||||
Other, net | (42 | ) | — | % | (34 | ) | — | % | (85 | ) | — | % | (52 | ) | — | % | ||||||||||||
Benefit for income taxes | $ | 37,855 | 37 | % | $ | 72,632 | 38 | % | $ | 31,833 | 34 | % | $ | 193,978 | 38 | % |
(1) | The Company recognized $0.5 million and $3.8 million of tax deficiencies from stock-based compensation as income tax expense for the three and six months ended June 30, 2017, respectively, in accordance with ASU 2016-09 as discussed in Note 2. Basis of Presentation and Significant Accounting Policies–Adoption of new accounting pronouncements. |
(2) | Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit. |
ITEM 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Boe production per day | 2Q 2017 | 1Q 2017 | % Change from 1Q 2017 | 2Q 2016 | % Change from 2Q 2016 | ||||||||||
Bakken | 119,861 | 108,992 | 10 | % | 125,028 | (4 | %) | ||||||||
SCOOP | 61,107 | 62,178 | (2 | %) | 64,669 | (6 | %) | ||||||||
STACK | 31,934 | 29,216 | 9 | % | 14,610 | 119 | % | ||||||||
All other | 13,311 | 13,369 | — | % | 15,016 | (11 | %) | ||||||||
Total | 226,213 | 213,755 | 6 | % | 219,323 | 3 | % |
• | Volumes of crude oil and natural gas produced; |
• | Crude oil and natural gas prices realized; and |
• | Per unit operating and administrative costs. |
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
Average daily production: | ||||||||||||||||
Crude oil (Bbl per day) | 125,381 | 133,044 | 122,308 | 139,756 | ||||||||||||
Natural gas (Mcf per day) | 604,991 | 517,677 | 586,263 | 511,837 | ||||||||||||
Crude oil equivalents (Boe per day) | 226,213 | 219,323 | 220,018 | 225,063 | ||||||||||||
Average sales prices: | ||||||||||||||||
Crude oil ($/Bbl) | $ | 41.91 | $ | 38.38 | $ | 43.26 | $ | 31.76 | ||||||||
Natural gas ($/Mcf) | $ | 2.63 | $ | 1.31 | $ | 2.81 | $ | 1.33 | ||||||||
Crude oil equivalents ($/Boe) | $ | 30.31 | $ | 26.36 | $ | 31.56 | $ | 22.73 | ||||||||
Crude oil sales price discount to NYMEX ($/Bbl) | $ | (6.31 | ) | $ | (7.21 | ) | $ | (6.69 | ) | $ | (7.51 | ) | ||||
Natural gas sales price discount to NYMEX ($/Mcf) | $ | (0.56 | ) | $ | (0.65 | ) | $ | (0.43 | ) | $ | (0.69 | ) | ||||
Production expenses ($/Boe) | $ | 3.99 | $ | 3.72 | $ | 3.89 | $ | 3.74 | ||||||||
Production taxes (% of oil and gas revenues) | 6.7 | % | 7.4 | % | 6.6 | % | 7.5 | % | ||||||||
DD&A ($/Boe) | $ | 19.14 | $ | 22.15 | $ | 19.48 | $ | 22.16 | ||||||||
Total general and administrative expenses ($/Boe) (1) | $ | 1.89 | $ | 1.82 | $ | 2.16 | $ | 1.68 | ||||||||
Net loss (in thousands) | $ | (63,557 | ) | $ | (119,402 | ) | $ | (63,088 | ) | $ | (317,727 | ) | ||||
Diluted net loss per share | $ | (0.17 | ) | $ | (0.32 | ) | $ | (0.17 | ) | $ | (0.86 | ) |
(1) | Represents cash general and administrative expenses per Boe and non-cash equity compensation expenses per Boe. See Operating Costs and Expenses—General and Administrative Expenses below for additional discussion of these components. |
Three months ended June 30, | ||||||||
In thousands, except sales price data | 2017 | 2016 | ||||||
Crude oil and natural gas sales | $ | 626,548 | $ | 525,711 | ||||
Gain (loss) on crude oil and natural gas derivatives, net | 28,022 | (82,257 | ) | |||||
Crude oil and natural gas service operations | 6,916 | 7,757 | ||||||
Total revenues | 661,486 | 451,211 | ||||||
Operating costs and expenses (1) | (690,527 | ) | (561,758 | ) | ||||
Other expenses, net | (72,371 | ) | (81,487 | ) | ||||
Loss before income taxes | (101,412 | ) | (192,034 | ) | ||||
Benefit for income taxes | 37,855 | 72,632 | ||||||
Net loss | $ | (63,557 | ) | $ | (119,402 | ) | ||
Production volumes: | ||||||||
Crude oil (MBbl) | 11,410 | 12,107 | ||||||
Natural gas (MMcf) | 55,054 | 47,109 | ||||||
Crude oil equivalents (MBoe) | 20,585 | 19,958 | ||||||
Sales volumes: | ||||||||
Crude oil (MBbl) | 11,499 | 12,090 | ||||||
Natural gas (MMcf) | 55,054 | 47,109 | ||||||
Crude oil equivalents (MBoe) | 20,674 | 19,941 | ||||||
Average sales prices: | ||||||||
Crude oil ($/Bbl) | $ | 41.91 | $ | 38.38 | ||||
Natural gas ($/Mcf) | 2.63 | 1.31 | ||||||
Crude oil equivalents ($/Boe) | 30.31 | 26.36 |
Three months ended June 30, | Volume increase (decrease) | Volume percent increase (decrease) | ||||||||||||||||
2017 | 2016 | |||||||||||||||||
Volume | Percent | Volume | Percent | |||||||||||||||
Crude oil (MBbl) | 11,410 | 55 | % | 12,107 | 61 | % | (697 | ) | (6 | %) | ||||||||
Natural gas (MMcf) | 55,054 | 45 | % | 47,109 | 39 | % | 7,945 | 17 | % | |||||||||
Total (MBoe) | 20,585 | 100 | % | 19,958 | 100 | % | 627 | 3 | % | |||||||||
Three months ended June 30, | Volume increase (decrease) | Volume percent increase (decrease) | ||||||||||||||||
2017 | 2016 | |||||||||||||||||
MBoe | Percent | MBoe | Percent | |||||||||||||||
North Region | 11,850 | 58 | % | 12,448 | 62 | % | (598 | ) | (5 | %) | ||||||||
South Region | 8,735 | 42 | % | 7,510 | 38 | % | 1,225 | 16 | % | |||||||||
Total | 20,585 | 100 | % | 19,958 | 100 | % | 627 | 3 | % |
Three months ended June 30, | ||||||||
In thousands | 2017 | 2016 | ||||||
Geological and geophysical costs | $ | 3,204 | $ | 1,468 | ||||
Exploratory dry hole costs | — | 206 | ||||||
Exploration expenses | $ | 3,204 | $ | 1,674 |
Three months ended June 30, | ||||||||
$/Boe | 2017 | 2016 | ||||||
Crude oil and natural gas | $ | 18.78 | $ | 21.69 | ||||
Other equipment | 0.29 | 0.38 | ||||||
Asset retirement obligation accretion | 0.07 | 0.08 | ||||||
Depreciation, depletion, amortization and accretion | $ | 19.14 | $ | 22.15 |
Three months ended June 30, | ||||||||
$/Boe | 2017 | 2016 | ||||||
General and administrative expenses | $ | 1.45 | $ | 1.22 | ||||
Non-cash equity compensation | 0.44 | 0.60 | ||||||
Total general and administrative expenses | $ | 1.89 | $ | 1.82 |
Six months ended June 30, | ||||||||
In thousands, except sales price data | 2017 | 2016 | ||||||
Crude oil and natural gas sales | $ | 1,260,398 | $ | 929,302 | ||||
Gain (loss) on crude oil and natural gas derivatives, net | 74,880 | (40,145 | ) | |||||
Crude oil and natural gas service operations | 11,636 | 15,227 | ||||||
Total revenues | 1,346,914 | 904,384 | ||||||
Operating costs and expenses (1) | (1,298,734 | ) | (1,254,033 | ) | ||||
Other expenses, net | (143,101 | ) | (162,056 | ) | ||||
Loss before income taxes | (94,921 | ) | (511,705 | ) | ||||
Benefit for income taxes | 31,833 | 193,978 | ||||||
Net loss | $ | (63,088 | ) | $ | (317,727 | ) | ||
Production volumes: | ||||||||
Crude oil (MBbl) | 22,138 | 25,436 | ||||||
Natural gas (MMcf) | 106,114 | 93,154 | ||||||
Crude oil equivalents (MBoe) | 39,823 | 40,961 | ||||||
Sales volumes: | ||||||||
Crude oil (MBbl) | 22,253 | 25,356 | ||||||
Natural gas (MMcf) | 106,114 | 93,154 | ||||||
Crude oil equivalents (MBoe) | 39,938 | 40,882 | ||||||
Average sales prices: | ||||||||
Crude oil ($/Bbl) | $ | 43.26 | $ | 31.76 | ||||
Natural gas ($/Mcf) | 2.81 | 1.33 | ||||||
Crude oil equivalents ($/Boe) | 31.56 | 22.73 |
Six months ended June 30, | Volume increase (decrease) | Volume percent increase (decrease) | ||||||||||||||||
2017 | 2016 | |||||||||||||||||
Volume | Percent | Volume | Percent | |||||||||||||||
Crude oil (MBbl) | 22,138 | 56 | % | 25,436 | 62 | % | (3,298 | ) | (13 | %) | ||||||||
Natural gas (MMcf) | 106,114 | 44 | % | 93,154 | 38 | % | 12,960 | 14 | % | |||||||||
Total (MBoe) | 39,823 | 100 | % | 40,961 | 100 | % | (1,138 | ) | (3 | %) | ||||||||
Six months ended June 30, | Volume increase (decrease) | Volume percent increase (decrease) | ||||||||||||||||
2017 | 2016 | |||||||||||||||||
MBoe | Percent | MBoe | Percent | |||||||||||||||
North Region | 22,597 | 57 | % | 26,240 | 64 | % | (3,643 | ) | (14 | %) | ||||||||
South Region | 17,226 | 43 | % | 14,721 | 36 | % | 2,505 | 17 | % | |||||||||
Total | 39,823 | 100 | % | 40,961 | 100 | % | (1,138 | ) | (3 | %) |
Six months ended June 30, | ||||||||
In thousands | 2017 | 2016 | ||||||
Geological and geophysical costs | $ | 8,045 | $ | 4,533 | ||||
Exploratory dry hole costs | 157 | 206 | ||||||
Exploration expenses | $ | 8,202 | $ | 4,739 |
Six months ended June 30, | ||||||||
$/Boe | 2017 | 2016 | ||||||
Crude oil and natural gas | $ | 19.10 | $ | 21.71 | ||||
Other equipment | 0.31 | 0.37 | ||||||
Asset retirement obligation accretion | 0.07 | 0.08 | ||||||
Depreciation, depletion, amortization and accretion | $ | 19.48 | $ | 22.16 |
Six months ended June 30, | ||||||||
$/Boe | 2017 | 2016 | ||||||
General and administrative expenses | $ | 1.65 | $ | 1.16 | ||||
Non-cash equity compensation | 0.51 | 0.52 | ||||||
Total general and administrative expenses | $ | 2.16 | $ | 1.68 |
In millions | Amount | ||
Exploration and development drilling | $ | 1,720 | |
Land costs | 115 | ||
Capital facilities, workovers and other corporate assets | 105 | ||
Seismic | 10 | ||
Total 2017 capital budget, excluding acquisitions | $ | 1,950 |
In millions | 1Q 2017 | 2Q 2017 | YTD 2017 | ||||||
Exploration and development drilling | $ | 329.8 | $ | 471.0 | $ | 800.8 | |||
Land costs | 68.8 | 49.8 | 118.6 | ||||||
Capital facilities, workovers and other corporate assets | 27.4 | 29.3 | 56.7 | ||||||
Seismic | 1.0 | 1.8 | 2.8 | ||||||
Capital expenditures, excluding acquisitions | 427.0 | 551.9 | 978.9 | ||||||
Acquisitions of producing properties | 0.1 | 0.7 | 0.8 | ||||||
Acquisitions of non-producing properties | 13.3 | 5.1 | 18.4 | ||||||
Total acquisitions | 13.4 | 5.8 | 19.2 | ||||||
Total capital expenditures | $ | 440.4 | $ | 557.7 | $ | 998.1 |
ITEM 3. | Quantitative and Qualitative Disclosures About Market Risk |
ITEM 1. | Legal Proceedings |
ITEM 1A. | Risk Factors |
ITEM 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
(a) | Recent Sales of Unregistered Securities – Not applicable. |
(b) | Use of Proceeds – Not applicable. |
Period | Total number of shares purchased (1) | Average price paid per share (1) | Total number of shares purchased as part of publicly announced plans or programs | Maximum number of shares that may yet be purchased under the plans or programs | |||||||||
April 1, 2017 to April 30, 2017 | 5,956 | $ | 45.82 | — | — | ||||||||
May 1, 2017 to May 31, 2017 | 100,358 | (2) | $ | 42.14 | (2) | — | — | ||||||
June 1, 2017 to June 30, 2017 | — | — | — | — | |||||||||
Total | 106,314 | $ | 42.35 | — | — |
(1) | In connection with restricted stock grants under the Company's 2013 Long-Term Incentive Plan, we adopted a policy that enables employees to surrender shares to cover their tax liability. Shares indicated as having been purchased represent shares surrendered by employees to cover tax liabilities unless otherwise noted. The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares unless otherwise noted. We paid the associated taxes to the applicable taxing authorities. |
(2) | Of this amount, 12,141 shares represent shares surrendered by employees to cover tax liabilities at an average price per share of $42.04. Additionally, the amount includes 88,217 shares of our common stock purchased by Harold G. Hamm, our Chairman of the Board, Chief Executive Officer, and principal shareholder in open-market transactions at an average price per share of $42.16. |
ITEM 3. | Defaults Upon Senior Securities |
ITEM 4. | Mine Safety Disclosures |
ITEM 6. | Exhibits |
CONTINENTAL RESOURCES, INC. | ||||
Date: | August 8, 2017 | By: | /s/ John D. Hart | |
John D. Hart | ||||
Sr. Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer) |
3.1 | Conformed version of Third Amended and Restated Certificate of Incorporation of Continental Resources, Inc. as amended by amendment filed on June 15, 2015 filed as Exhibit 3.1 to the Company’s Form 10-Q for the quarterly period ended June 30, 2015 (Commission File No. 001-32886) filed August 5, 2015 and incorporated herein by reference. |
3.2 | Third Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed November 6, 2012 and incorporated herein by reference. |
10.1*† | Resignation and Stock Acceleration Agreement between Continental Resources, Inc. and Glen Brown dated April 7, 2017. |
31.1* | Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241). |
31.2* | Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241). |
32** | Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350). |
101.INS** | XBRL Instance Document |
101.SCH** | XBRL Taxonomy Extension Schema Document |
101.CAL** | XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF** | XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB** | XBRL Taxonomy Extension Label Linkbase Document |
101.PRE** | XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed herewith |
** | Furnished herewith |
† | Management contract or compensatory plan or arrangement filed pursuant to Item 601(b)(10)(iii) of Regulation S-K. |
1. | I have reviewed this report on Form 10-Q for the period ended June 30, 2017 of Continental Resources, Inc. (“Registrant”); |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report; |
4. | The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and |
5. | The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors: |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting. |
/s/ Harold G. Hamm |
Harold G. Hamm |
Chairman of the Board and Chief Executive Officer |
1. | I have reviewed this report on Form 10-Q for the period ended June 30, 2017 of Continental Resources, Inc. (“Registrant”); |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report; |
4. | The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and |
5. | The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors: |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting. |
/s/ John D. Hart |
John D. Hart |
Sr. Vice President, Chief Financial Officer and Treasurer |
/s/ Harold G. Hamm | /s/ John D. Hart | |
Harold G. Hamm | John D. Hart | |
Chairman of the Board and Chief Executive Officer | Sr. Vice President, Chief Financial Officer and Treasurer | |
August 8, 2017 | August 8, 2017 |
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Document and Entity Information - shares |
6 Months Ended | |
---|---|---|
Jun. 30, 2017 |
Jul. 31, 2017 |
|
Document Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2017 | |
Document Fiscal Year Focus | 2017 | |
Document Fiscal Period Focus | Q2 | |
Trading Symbol | CLR | |
Entity Registrant Name | CONTINENTAL RESOURCES, INC | |
Entity Central Index Key | 0000732834 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 375,219,152 |
Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Statement of Financial Position [Abstract] | ||
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 25,000,000 | 25,000,000 |
Preferred stock, shares issued | ||
Preferred stock, shares outstanding | ||
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 1,000,000,000 | 1,000,000,000 |
Common Stock, Shares, Issued | 375,206,922 | 374,492,357 |
Common Stock, Shares, Outstanding | 375,206,922 | 374,492,357 |
Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Revenues: | ||||
Crude oil and natural gas sales | $ 626,548 | $ 525,711 | $ 1,260,398 | $ 929,302 |
Gain (loss) on crude oil and natural gas derivatives, net | 28,022 | (82,257) | 74,880 | (40,145) |
Crude oil and natural gas service operations | 6,916 | 7,757 | 11,636 | 15,227 |
Total revenues | 661,486 | 451,211 | 1,346,914 | 904,384 |
Operating costs and expenses: | ||||
Production expenses | 82,474 | 74,083 | 155,328 | 152,724 |
Production taxes | 41,965 | 39,141 | 83,198 | 69,634 |
Exploration expenses | 3,204 | 1,674 | 8,202 | 4,739 |
Crude oil and natural gas service operations | 4,478 | 3,576 | 7,315 | 6,618 |
Depreciation, depletion, amortization and accretion | 395,770 | 441,761 | 777,926 | 905,752 |
Property impairments | 123,316 | 66,112 | 174,689 | 145,039 |
General and administrative expenses | 39,186 | 36,246 | 86,407 | 68,654 |
Net (gain) loss on sale of assets and other | 134 | (100,835) | 5,669 | (99,127) |
Total operating costs and expenses | 690,527 | 561,758 | 1,298,734 | 1,254,033 |
Income (loss) from operations | (29,041) | (110,547) | 48,180 | (349,649) |
Other income (expense): | ||||
Interest expense | (72,744) | (81,922) | (143,916) | (162,875) |
Other | 373 | 435 | 815 | 819 |
Total other income (expense) | (72,371) | (81,487) | (143,101) | (162,056) |
Loss before income taxes | (101,412) | (192,034) | (94,921) | (511,705) |
Benefit for income taxes | 37,855 | 72,632 | 31,833 | 193,978 |
Net loss | (63,557) | (119,402) | (63,088) | (317,727) |
Foreign currency translation adjustments | 189 | 25 | 327 | 451 |
Total other comprehensive income, net of tax | 189 | 25 | 327 | 451 |
Comprehensive loss | $ (63,368) | $ (119,377) | $ (62,761) | $ (317,276) |
Basic net income (loss) per share (in dollars per share) | $ (0.17) | $ (0.32) | $ (0.17) | $ (0.86) |
Diluted net income (loss) per share (in dollars per share) | $ (0.17) | $ (0.32) | $ (0.17) | $ (0.86) |
Condensed Consolidated Statements of Shareholders Equity - 6 months ended Jun. 30, 2017 - USD ($) $ in Thousands |
Total |
Common Stock [Member] |
Additional Paid-In Capital [Member] |
Accumulated Other Comprehensive Loss [Member] |
Retained Earnings [Member] |
---|---|---|---|---|---|
Balance at Dec. 31, 2016 | $ 4,301,996 | $ 3,745 | $ 1,375,290 | $ (260) | $ 2,923,221 |
Balance, shares at Dec. 31, 2016 | 374,492,357 | 374,492,357 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Adoption of ASU 2016-09 cumulative effect on retained earnings | $ 5,150 | 5,150 | |||
Net income (unaudited) | (63,088) | (63,088) | |||
Other comprehensive income, net of tax (unaudited) | 327 | 327 | |||
Stock-based compensation (unaudited) | 20,561 | 20,561 | |||
Restricted stock: | |||||
Granted (unaudited) | $ 14 | $ 14 | |||
Granted (unaudited), shares | 1,464,944 | 1,464,944 | |||
Repurchased and canceled (unaudited) | $ (10,620) | $ (2) | (10,618) | ||
Repurchased and canceled (unaudited), shares | (230,377) | (230,377) | |||
Forfeited (unaudited), shares | (520,002) | (520,002) | |||
Forfeitures (unaudited) | $ (5) | $ (5) | |||
Balance at Jun. 30, 2017 | $ 4,254,335 | $ 3,752 | $ 1,385,233 | $ 67 | $ 2,865,283 |
Balance, shares at Jun. 30, 2017 | 375,206,922 | 375,206,922 |
Organization and Nature of Business |
6 Months Ended |
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Jun. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Business | Organization and Nature of Business Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company's principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province), STACK (Sooner Trend Anadarko Canadian Kingfisher), and Arkoma Woodford areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations. A substantial portion of the Company’s operations are located in the North region, with that region comprising approximately 57% of the Company’s crude oil and natural gas production and approximately 66% of its crude oil and natural gas revenues for the six months ended June 30, 2017. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. In recent years, the Company has significantly expanded its operations in the South region with its increased activity in the SCOOP and STACK plays. The South region comprised approximately 43% of the Company's crude oil and natural gas production and approximately 34% of its crude oil and natural gas revenues for the six months ended June 30, 2017. For the six months ended June 30, 2017, crude oil accounted for approximately 56% of the Company’s total production and approximately 76% of its crude oil and natural gas revenues. |
Basis of Presentation and Significant Accounting Policies |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Basis of Presentation and Significant Accounting Policies | Basis of Presentation and Significant Accounting Policies Basis of presentation The condensed consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation. This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Quarterly Report on Form 10-Q ("Form 10-Q") together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures. The condensed consolidated financial statements as of June 30, 2017 and for the three and six month periods ended June 30, 2017 and 2016 are unaudited. The condensed consolidated balance sheet as of December 31, 2016 was derived from the audited balance sheet included in the 2016 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant of the estimates and assumptions that affect reported results are the estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these unaudited interim condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for an entire year. Earnings per share Basic and diluted net loss per share is computed by dividing net loss by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net loss per share for the three and six months ended June 30, 2017 and 2016.
Inventories Inventory is comprised of crude oil held in storage or as line fill in pipelines and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or market primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued at the lower of cost or market, with cost determined primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of June 30, 2017 and December 31, 2016 consisted of the following:
Adoption of new accounting pronouncements Stock-based compensation – In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company adopted the new standard on January 1, 2017 as required. The impact of adoption is described below. ASU 2016-09 removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. An excess tax benefit (tax deficiency) arises when stock-based compensation expense recognized in an entity’s tax return exceeds (is less than) the expense recognized in an entity’s financial statements. Under the new standard, effective January 1, 2017 excess tax benefits are recorded when they arise. This change was required to be applied on a modified retrospective basis by recording a cumulative effect adjustment to opening retained earnings upon adoption to account for previously unrecognized excess tax benefits. The Company's cumulative effect adjustment recorded under the new standard resulted in a $5.2 million increase in retained earnings and corresponding decrease in deferred income tax liabilities at January 1, 2017. Additionally, under ASU 2016-09 companies no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies are recognized as income tax benefit or expense in the income statement, effective January 1, 2017 on a prospective basis. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. The Company recognized $0.5 million ($0.00 per share) and $3.8 million ($0.01 per share) of tax deficiencies from stock-based compensation as income tax expense for the three and six months ended June 30, 2017, respectively, under the new standard, which are reflected in "Benefit for income taxes" in the unaudited condensed consolidated statements of comprehensive loss. ASU 2016-09 also removed the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activities in the statement of cash flows. Instead, ASU 2016-09 requires cash flows related to excess tax benefits and deficiencies be classified as operating activities in the same manner as other cash flows related to income taxes. The Company has elected to apply this guidance on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017, if applicable, will not be adjusted to conform to current period presentation. The Company has elected to continue its historical accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 does not have an impact on the amount of stock-based compensation expense to be recognized by the Company on non-vested restricted stock awards. Business combinations – In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under the new standard, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. The new standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. The standard is effective for interim and annual periods beginning after December 15, 2017 and shall be applied prospectively. The Company early adopted ASU 2017-01 as of January 1, 2017, which had no significant impact on the Company's financial statements as of and for the three and six months ended June 30, 2017. New accounting pronouncements not yet adopted Revenue recognition and presentation – In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate. ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company plans to adopt the standard on January 1, 2018 using the modified retrospective approach. The Company continues to evaluate the impact of the new standard on its financial statements, accounting policies and internal controls. Based on assessments performed to date, the standard is not expected to have a material effect on the timing of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures. Additionally, the standard is expected to impact the presentation of future revenues and expenses under the gross-versus-net presentation guidance. Historically, the Company has generally presented its revenues net of transportation costs. The new guidance is expected to result in future revenues and associated transportation expenses for certain of the Company's operated properties being reported on a gross basis. The Company expects changes from net to gross presentation will result in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company's results of operations, net income, or cash flows. For the three and six months ended June 30, 2017, the Company estimates it had approximately $50 million and $100 million, respectively, of transportation-related charges on operated properties included in "Crude oil and natural gas sales" on the unaudited condensed consolidated statements of comprehensive loss. The Company is not currently able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period. Leases – In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach. The Company continues to evaluate the impact of ASU 2016-02 and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time. |
Supplemental Cash Flow Information |
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Supplemental Cash Flow Elements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supplemental Cash Flow Information | Supplemental Cash Flow Information The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.
As of June 30, 2017 and December 31, 2016, the Company had $331.7 million and $223.6 million, respectively, of accrued capital expenditures included in "Net property and equipment" and "Accounts payable trade" in the condensed consolidated balance sheets. |
Derivative Instruments |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments | Derivative Instruments Crude oil and natural gas derivatives The Company may utilize crude oil and natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements. The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its crude oil and natural gas derivative instruments as hedges for accounting purposes and, as a result, marks such derivative instruments to fair value and recognizes the changes in fair value in the unaudited condensed consolidated statements of comprehensive loss under the caption “Gain (loss) on crude oil and natural gas derivatives, net”. The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 5. Fair Value Measurements. With respect to a crude oil or natural gas fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a crude oil or natural gas collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price. At June 30, 2017, the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations that are expected to be realized ratably over the respective 2017 and 2018 periods. At June 30, 2017 the Company had no outstanding crude oil derivative contracts.
Crude oil and natural gas derivative gains and losses Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
Diesel fuel derivatives The Company has entered into diesel fuel swap derivative contracts to economically hedge against the variability in cash flows associated with future purchases of diesel fuel for use in drilling activities. The Company has hedged approximately six million gallons of diesel fuel over the period from July 2017 to December 2017 at a weighted average price of $1.45 per gallon. With respect to these diesel fuel swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is greater than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is less than the swap price. The diesel fuel swap contracts are settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel. The Company recognizes its diesel fuel derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value is based upon various factors, including commodity exchange prices, over-the-counter quotations, the risk-free interest rate, and time to expiration. The Company has not designated its diesel fuel derivative instruments as hedges for accounting purposes and, as a result, marks the derivative instruments to fair value and recognizes the changes in fair value in the unaudited condensed consolidated statements of comprehensive loss under the caption “Operating costs and expenses—Net (gain) loss on sale of assets and other.” Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of diesel fuel derivatives which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
Balance sheet offsetting of derivative assets and liabilities The Company’s derivative contracts are recorded at fair value in the condensed consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”, “Derivative liabilities”, and “Noncurrent derivative liabilities”, as applicable. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed consolidated balance sheets. The following table presents the gross amounts of recognized crude oil, natural gas, and diesel fuel derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value.
The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets.
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Fair Value Measurements |
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Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | Fair Value Measurements The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness. The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of June 30, 2017 and December 31, 2016.
Assets Measured at Fair Value on a Nonrecurring Basis Certain assets are reported at fair value on a nonrecurring basis in the condensed consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets. Asset Impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on the Company's estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips adjusted for differentials, operating costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method.
Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management. For the three and six months ended June 30, 2017 the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Impairments of proved properties amounted to $81.5 million and $82.3 million for the three and six months ended June 30, 2017, respectively. The 2017 year to date impairments reflect fair value adjustments primarily concentrated in the Arkoma Woodford field ($81.2 million, all in the second quarter) and various non-core areas in the North and South regions ($1.1 million, including $0.3 million in the second quarter). The impaired properties were written down to their estimated fair value at the time of impairment of approximately $72 million. For the three and six months ended June 30, 2016, estimated future net cash flows were determined to be in excess of cost basis, therefore no impairment was recorded for the Company’s proved crude oil and natural gas properties for those periods. Certain unproved crude oil and natural gas properties were impaired during the three and six months ended June 30, 2017 and 2016, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the unaudited condensed consolidated statements of comprehensive loss.
Financial Instruments Not Recorded at Fair Value The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements.
The fair values of revolving credit facility borrowings and the term loan approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy. The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy. The fair values of the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”) are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy. The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments. |
Long-Term Debt |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Debt | Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $35.1 million and $37.3 million at June 30, 2017 and December 31, 2016, respectively, consists of the following.
Revolving Credit Facility The Company has an unsecured revolving credit facility, maturing on May 16, 2019, with aggregate commitments totaling $2.75 billion at June 30, 2017, which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at June 30, 2017 was 2.85%. The Company had approximately $1.87 billion of borrowing availability on its revolving credit facility at June 30, 2017 and incurs commitment fees based on currently assigned credit ratings of 0.30% per annum on the daily average amount of unused borrowing availability under its revolving credit facility. The revolving credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the revolving credit facility covenants at June 30, 2017. Senior Notes The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at June 30, 2017.
The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements. The indentures governing the Company's senior notes contain covenants that, among other things, limit the Company's ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, and consolidate, merge or transfer certain assets. The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at June 30, 2017. Three of the Company’s subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes. Term Loan In November 2015, the Company borrowed $500 million under a three-year term loan agreement, the proceeds of which were used to repay a portion of the borrowings then outstanding on the Company's revolving credit facility. The term loan matures in full on November 4, 2018 and bears interest at a variable market-based interest rate plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The interest rate on the term loan at June 30, 2017 was 2.64%. The term loan contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00, consistent with the covenant requirement in the Company's revolving credit facility. The Company was in compliance with the term loan covenants at June 30, 2017. Note Payable In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under a 10-year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022. Accordingly, approximately $2.3 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of June 30, 2017. |
Commitments and Contingencies |
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Jun. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Included below is a discussion of various future commitments of the Company as of June 30, 2017. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets. Drilling commitments – As of June 30, 2017, the Company has drilling rig contracts with various terms extending to February 2020 to ensure rig availability in its key operating areas. Future commitments as of June 30, 2017 total approximately $144 million, of which $55 million is expected to be incurred in the remainder of 2017, $59 million in 2018, $29 million in 2019, and $1 million in 2020. Transportation and processing commitments – The Company has entered into transportation and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2028, require the Company to pay per-unit transportation or processing charges regardless of the amount of capacity used. Future commitments remaining as of June 30, 2017 under the arrangements amount to approximately $1.2 billion, of which $115 million is expected to be incurred in the remainder of 2017, $245 million in 2018, $233 million in 2019, $101 million in 2020, $89 million in 2021, and $424 million thereafter. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. Litigation – In November 2010, a putative class action was filed in the District Court of Blaine county, Oklahoma by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. The Petition alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. On November 3, 2014, plaintiffs filed an Amended Petition that did not add any substantive claims, but sought a “hybrid class action” in which they sought certification of certain claims for injunctive relief, reserving the right to seek a further class certification on money damages in the future. Plaintiffs filed an Amended Motion for Class Certification on January 9, 2015, that modified the proposed class to royalty owners in Oklahoma production from July 1, 1993, to the present (instead of 1980 to the present) and sought certification of over 45 separate “issues” for injunctive or declaratory relief, again, reserving the right to seek a further class certification of money damages in the future. The Company responded to the petition, its amendment, and the motions for class certification denying the allegations and raising a number of affirmative defenses and legal arguments to each of the claims and filings. Certain discovery was undertaken and the “hybrid” motion was briefed by plaintiffs and the Company. A hearing on the “hybrid” class certification was held on June 1 and 2, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company appealed the trial court’s class certification order. On February 8, 2017, the Oklahoma Court of Civil Appeals reversed the trial court’s ruling on certification and remanded the case for further proceedings. The plaintiffs filed a Petition for Rehearing which is pending before the Oklahoma Court of Civil Appeals. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the ultimate resolution of the action will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the existence and the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. It is reasonably possible one or more events may occur in the near term that could impact the Company’s ability to estimate the potential effect this matter could have, if any, on its financial condition, results of operations or cash flows. Plaintiffs have alleged underpayments in excess of $200 million that they may claim as damages, which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes the case meets the requirements for a class action and continues to vigorously defend the case. An unsuccessful mediation was conducted on December 7, 2015. The parties continue to negotiate a possible resolution to the case. However, it is unclear and unforeseeable whether the parties' efforts will result in settlement and the Company will continue to defend the case on all merits and certification issues and, absent settlement, intends to defend the case to a final judgment. The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of both June 30, 2017 and December 31, 2016, the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $6.5 million for various matters, none of which are believed to be individually significant. Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims. |
Stock-Based Compensation |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock-Based Compensation | Stock-Based Compensation On January 1, 2017, the Company adopted ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. See Note 2. Basis of Presentation and Significant Accounting Policies—Adoption of new accounting pronouncements for a discussion of the impact of adoption. The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive loss, was $9.1 million and $11.8 million for the three months ended June 30, 2017 and 2016, respectively, and $20.6 million and $21.0 million for the six months ended June 30, 2017 and 2016, respectively. In May 2013, the Company adopted the 2013 Plan and reserved 19,680,072 shares of common stock that may be issued pursuant to the plan. As of June 30, 2017, the Company had 14,551,387 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan. Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock or to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one to three years. A summary of changes in non-vested restricted shares outstanding for the six months ended June 30, 2017 is presented below.
The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during the six months ended June 30, 2017 was approximately $36.1 million. As of June 30, 2017, there was approximately $81 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.6 years. |
Accumulated Other Comprehensive Income (Notes) |
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Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | Accumulated Other Comprehensive Income (Loss) Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive income (loss)" within shareholders’ equity in the condensed consolidated balance sheets and "Other comprehensive income, net of tax" in the unaudited condensed consolidated statements of comprehensive loss. The following table summarizes the change in accumulated other comprehensive income (loss) for the three and six months ended June 30, 2017 and 2016:
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Income Taxes (Notes) |
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Income Tax Disclosure [Text Block] | Income Taxes Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at period-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company's benefit for income taxes totaled $37.9 million and $31.8 million for the three and six months ended June 30, 2017, respectively. The Company's benefit for income taxes totaled $72.6 million and $194.0 million for the three and six months ended June 30, 2016, respectively. These amounts differ from the amounts computed by applying the United States statutory federal income tax rate to net loss before income taxes. The sources and tax effects of the differences are reflected in the table below:
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Property Dispositions (Notes) |
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Jun. 30, 2017 | |
Property Dispositions [Abstract] | |
Mergers, Acquisitions and Dispositions Disclosures [Text Block] | Property Disposition In April 2016, the Company sold approximately 132,000 net acres of undeveloped leasehold acreage located in Wyoming to a third party for cash proceeds of $110.0 million. In connection with the transaction, the Company recognized a pre-tax gain of $96.9 million. The disposed properties represented an immaterial portion of the Company’s total acreage and included no production or proved reserves. |
Subsequent Events (Notes) |
6 Months Ended |
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Jun. 30, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Events [Text Block] | Subsequent Events Subsequent to June 30, 2017, the Company reached agreements to sell certain non-core properties and facilities in Oklahoma for aggregate proceeds totaling approximately $147.5 million. The sold properties include, in the aggregate, approximately 32,600 net acres of leasehold and producing properties with production totaling approximately 1,800 barrels of oil equivalent per day. The disposed properties represented an immaterial portion of the Company’s proved reserves. In connection with the transactions, the Company expects to recognize pre-tax gains totaling approximately $65 million, which will be reflected in third quarter 2017 results. The Company intends to use the proceeds from the sales to reduce outstanding debt. |
Basis of Presentation and Significant Accounting Policies (Policies) |
6 Months Ended |
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Jun. 30, 2017 | |
Accounting Policies [Abstract] | |
Description of the Company | The Company's principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province), STACK (Sooner Trend Anadarko Canadian Kingfisher), and Arkoma Woodford areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations. A substantial portion of the Company’s operations are located in the North region, with that region comprising approximately 57% of the Company’s crude oil and natural gas production and approximately 66% of its crude oil and natural gas revenues for the six months ended June 30, 2017. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. In recent years, the Company has significantly expanded its operations in the South region with its increased activity in the SCOOP and STACK plays. The South region comprised approximately 43% of the Company's crude oil and natural gas production and approximately 34% of its crude oil and natural gas revenues for the six months ended June 30, 2017. For the six months ended June 30, 2017, crude oil accounted for approximately 56% of the Company’s total production and approximately 76% of its crude oil and natural gas revenues. |
Basis of Presentation | Basis of presentation The condensed consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation. This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Quarterly Report on Form 10-Q ("Form 10-Q") together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures. The condensed consolidated financial statements as of June 30, 2017 and for the three and six month periods ended June 30, 2017 and 2016 are unaudited. The condensed consolidated balance sheet as of December 31, 2016 was derived from the audited balance sheet included in the 2016 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant of the estimates and assumptions that affect reported results are the estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these unaudited interim condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for an entire year. |
Earnings Per Share | Earnings per share Basic and diluted net loss per share is computed by dividing net loss by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. |
Inventories | Inventories Inventory is comprised of crude oil held in storage or as line fill in pipelines and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or market primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued at the lower of cost or market, with cost determined primarily using a weighted average cost method applied to specific classes of inventory items. |
New Accounting Pronouncements | Adoption of new accounting pronouncements Stock-based compensation – In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company adopted the new standard on January 1, 2017 as required. The impact of adoption is described below. ASU 2016-09 removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. An excess tax benefit (tax deficiency) arises when stock-based compensation expense recognized in an entity’s tax return exceeds (is less than) the expense recognized in an entity’s financial statements. Under the new standard, effective January 1, 2017 excess tax benefits are recorded when they arise. This change was required to be applied on a modified retrospective basis by recording a cumulative effect adjustment to opening retained earnings upon adoption to account for previously unrecognized excess tax benefits. The Company's cumulative effect adjustment recorded under the new standard resulted in a $5.2 million increase in retained earnings and corresponding decrease in deferred income tax liabilities at January 1, 2017. Additionally, under ASU 2016-09 companies no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies are recognized as income tax benefit or expense in the income statement, effective January 1, 2017 on a prospective basis. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. The Company recognized $0.5 million ($0.00 per share) and $3.8 million ($0.01 per share) of tax deficiencies from stock-based compensation as income tax expense for the three and six months ended June 30, 2017, respectively, under the new standard, which are reflected in "Benefit for income taxes" in the unaudited condensed consolidated statements of comprehensive loss. ASU 2016-09 also removed the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activities in the statement of cash flows. Instead, ASU 2016-09 requires cash flows related to excess tax benefits and deficiencies be classified as operating activities in the same manner as other cash flows related to income taxes. The Company has elected to apply this guidance on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017, if applicable, will not be adjusted to conform to current period presentation. The Company has elected to continue its historical accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 does not have an impact on the amount of stock-based compensation expense to be recognized by the Company on non-vested restricted stock awards. Business combinations – In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under the new standard, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. The new standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. The standard is effective for interim and annual periods beginning after December 15, 2017 and shall be applied prospectively. The Company early adopted ASU 2017-01 as of January 1, 2017, which had no significant impact on the Company's financial statements as of and for the three and six months ended June 30, 2017. New accounting pronouncements not yet adopted Revenue recognition and presentation – In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate. ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company plans to adopt the standard on January 1, 2018 using the modified retrospective approach. The Company continues to evaluate the impact of the new standard on its financial statements, accounting policies and internal controls. Based on assessments performed to date, the standard is not expected to have a material effect on the timing of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures. Additionally, the standard is expected to impact the presentation of future revenues and expenses under the gross-versus-net presentation guidance. Historically, the Company has generally presented its revenues net of transportation costs. The new guidance is expected to result in future revenues and associated transportation expenses for certain of the Company's operated properties being reported on a gross basis. The Company expects changes from net to gross presentation will result in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company's results of operations, net income, or cash flows. For the three and six months ended June 30, 2017, the Company estimates it had approximately $50 million and $100 million, respectively, of transportation-related charges on operated properties included in "Crude oil and natural gas sales" on the unaudited condensed consolidated statements of comprehensive loss. The Company is not currently able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period. Leases – In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach. The Company continues to evaluate the impact of ASU 2016-02 and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time. |
Basis of Presentation and Significant Accounting Policies (Tables) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Components of Inventories | The components of inventory as of June 30, 2017 and December 31, 2016 consisted of the following:
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Calculation of Basic and Diluted Weighted Average Shares and Net Income Per Share | The following table presents the calculation of basic and diluted weighted average shares outstanding and net loss per share for the three and six months ended June 30, 2017 and 2016.
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Supplemental Cash Flow Information (Tables) |
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Supplemental Cash Flow Elements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Supplemental Cash Flow Information | The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.
As of June 30, 2017 and December 31, 2016, the Company had $331.7 million and $223.6 million, respectively, of accrued capital expenditures included in "Net property and equipment" and "Accounts payable trade" in the condensed consolidated balance sheets. |
Derivative Instruments (Tables) |
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Summary of Outstanding Contracts with Respect to Natural Gas | At June 30, 2017, the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations that are expected to be realized ratably over the respective 2017 and 2018 periods. At June 30, 2017 the Company had no outstanding crude oil derivative contracts.
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Realized and Unrealized Gains and Losses on Derivative Instruments | Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
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Gross Amounts of Recognized Derivative Assets and Liabilities | The following table presents the gross amounts of recognized crude oil, natural gas, and diesel fuel derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value.
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Reconciles Net Amounts Derivative Assets and Liabilities | The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets.
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Diesel Fuel [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Realized and Unrealized Gains and Losses on Derivative Instruments | Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of diesel fuel derivatives which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
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Fair Value Measurements (Tables) |
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Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Valuation of Financial Instruments by Pricing Levels | The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of June 30, 2017 and December 31, 2016.
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Quantitative Information about Significant Unobservable Inputs | The following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method.
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Property Impairments | The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the unaudited condensed consolidated statements of comprehensive loss.
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Fair Values of Financial Instruments not Recorded at Fair Value | The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements.
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Long-Term Debt (Tables) |
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Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods of Outstanding Senior Note Obligations | The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at June 30, 2017.
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Schedule of Long-term Debt Instruments [Table Text Block] | Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $35.1 million and $37.3 million at June 30, 2017 and December 31, 2016, respectively, consists of the following.
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Stock-Based Compensation (Tables) |
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Summary of Changes in Non-vested Shares of Restricted Stock Outstanding | A summary of changes in non-vested restricted shares outstanding for the six months ended June 30, 2017 is presented below.
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Accumulated Other Comprehensive Income (Tables) |
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Accumulated Other Comprehensive Income [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The following table summarizes the change in accumulated other comprehensive income (loss) for the three and six months ended June 30, 2017 and 2016:
|
Income Taxes (Tables) |
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Effective Tax Rate Reconciliation Table [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | he sources and tax effects of the differences are reflected in the table below:
|
Basis of Presentation and Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Accounting Policies [Abstract] | ||
Tubular goods and equipment | $ 15,723 | $ 15,243 |
Crude oil | 81,280 | 96,744 |
Total | $ 97,003 | $ 111,987 |
Basis of Presentation and Significant Accounting Policies - Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands |
3 Months Ended | 6 Months Ended | ||||
---|---|---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|||
Accounting Policies [Abstract] | ||||||
Weighted Average Number Diluted Shares Outstanding Adjustment | 1,933,200 | 1,940,700 | 2,546,200 | 1,486,200 | ||
Net loss (numerator) | ||||||
Net loss (numerator) | $ (63,557) | $ (119,402) | $ (63,088) | $ (317,727) | ||
Weighted average shares - basic | 371,111,000 | 370,435,000 | 370,972,000 | 370,248,000 | ||
Non-vested restricted stock (1) | [1] | 0 | 0 | 0 | 0 | |
Weighted average shares - diluted | 371,111,000 | 370,435,000 | 370,972,000 | 370,248,000 | ||
Net loss per share: | ||||||
Basic (in dollars per share) | $ (0.17) | $ (0.32) | $ (0.17) | $ (0.86) | ||
Diluted (in dollars per share) | $ (0.17) | $ (0.32) | $ (0.17) | $ (0.86) | ||
|
Basis of Presentation and Significant Accounting Policies Basis of Presentation and Significant Accounting Policies - New Accounting Pronouncements (Details) - USD ($) $ / shares in Units, $ in Thousands |
3 Months Ended | 6 Months Ended |
---|---|---|
Jun. 30, 2017 |
Jun. 30, 2017 |
|
Accounting Policies [Abstract] | ||
Adoption of ASU 2016-09 cumulative effect on retained earnings | $ 5,150 | |
Share-based Compensation, Tax Deficiency from Compensation Expense | $ 500 | $ 3,800 |
Tax Deficiency from Compensation Expense, Per Share | $ 0.00 | $ 0.01 |
Results of Operations, Transportation Costs | $ 50,000 | $ 100,000 |
Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands |
6 Months Ended | 12 Months Ended | |
---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Dec. 31, 2016 |
|
Supplemental Cash Flow Elements [Abstract] | |||
Cash paid for interest | $ 138,346 | $ 156,358 | |
Cash paid for income taxes | 2 | 0 | |
Cash received for income tax refunds | 148 | 20 | |
Noncash Investing and Financing Items [Abstract] | |||
Accrued capital expenditures | 331,700 | $ 223,600 | |
Increase (Decrease) in Asset Retirement Obligations | $ 3,771 | $ 1,042 |
Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) - Natural Gas [Member] |
6 Months Ended |
---|---|
Jun. 30, 2017
MMBTU
$ / MMBTU
| |
July 2017 to December 2017 Swaps | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume, MMBtus | MMBTU | 66,240,000 |
Swaps Weighted Average Price | 3.39 |
July 2017 to December 2017 Collars | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume, MMBtus | MMBTU | 33,120,000 |
Floors, Weighted Average Price | 2.47 |
Ceilings, Weighted Average Price | 3.08 |
January 2018 to March 2018 Swaps | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume, MMBtus | MMBTU | 6,300,000 |
Swaps Weighted Average Price | 3.28 |
Minimum [Member] | July 2017 to December 2017 Collars | |
Derivative [Line Items] | |
Derivative, Floor Price | 2.40 |
Derivative, Cap Price | 2.92 |
Maximum [Member] | July 2017 to December 2017 Collars | |
Derivative [Line Items] | |
Derivative, Floor Price | 3.00 |
Derivative, Cap Price | 3.88 |
Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Gross amounts of recognized assets | $ 19,746 | $ 4,061 |
Gross amounts offset on balance sheet | (1,937) | 0 |
Net amounts of assets on balance sheet | 17,809 | 4,061 |
Gross amounts of recognized liabilities | (6,754) | (59,489) |
Gross amounts offset on balance sheet | 1,937 | 0 |
Net amounts of liabilities on balance sheet | $ (4,817) | $ (59,489) |
Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Derivative assets | $ 17,809 | $ 4,061 |
Noncurrent derivative assets | 0 | 0 |
Net amounts of assets on balance sheet | 17,809 | 4,061 |
Derivative liabilities | (4,817) | (59,489) |
Noncurrent derivative liabilities | 0 | 0 |
Net amounts of liabilities on balance sheet | (4,817) | (59,489) |
Total derivative assets, net | $ 12,992 | $ (55,428) |
Derivative Instruments Summary of Outstanding Contracts with Respect to Diesel Fuel (Details) $ in Thousands, gal in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017
USD ($)
$ / gal
|
Jun. 30, 2016
USD ($)
|
Jun. 30, 2017
USD ($)
$ / gal
gal
|
Jun. 30, 2016
USD ($)
|
|
Derivative [Line Items] | ||||
Non-cash gain (loss) on derivatives, net | $ 68,420 | $ (114,972) | ||
Gain (loss) on derivatives, net | $ 28,022 | $ (82,257) | 74,880 | (40,145) |
Diesel Fuel [Member] | ||||
Derivative [Line Items] | ||||
Cash received (paid) on derivatives, net | 185 | 0 | 919 | 0 |
Non-cash gain (loss) on derivatives, net | (1,098) | 4,200 | (3,729) | 3,140 |
Gain (loss) on derivatives, net | $ (913) | $ 4,200 | $ (2,810) | $ 3,140 |
Diesel Fuel [Member] | July 2017 to December 2017 Swaps [Member] | ||||
Derivative [Line Items] | ||||
Diesel Fuel Derivative Volume, gallons | gal | 6 | |||
Swaps Weighted Average Price | $ / gal | 1.45 | 1.45 |
Fair Value Measurements - Additional Information (Detail) |
6 Months Ended |
---|---|
Jun. 30, 2017 | |
Fair Value Measurements [Line Items] | |
Operating cost escalation assumption used in impairment assessment | 3.00% |
Discount factor utilized as standardized measure for future net cash flows | 10.00% |
Minimum [Member] | |
Fair Value Measurements [Line Items] | |
Productive life of field (in years) | 0 years |
Maximum [Member] | |
Fair Value Measurements [Line Items] | |
Productive life of field (in years) | 39 years |
Forward Commodity Prices [Member] | |
Fair Value Measurements [Line Items] | |
Forward commodity price escalation assumption used in impairment assessment | 3.00% |
Fair Value Measurements - Property Impairments (Detail) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proved property impairments | $ 81,469 | $ 0 | $ 82,340 | $ 0 |
Unproved property impairments | 41,847 | 66,112 | 92,349 | 145,039 |
Oil and gas property fair value after impairment | 72,000 | 72,000 | ||
Property impairments | 123,316 | $ 66,112 | 174,689 | $ 145,039 |
Arkoma Woodford [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proved property impairments | 81,200 | 81,200 | ||
Non-core [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proved property impairments | $ 300 | $ 1,100 |
Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions |
1 Months Ended | 6 Months Ended | |
---|---|---|---|
Nov. 30, 2010 |
Jun. 30, 2017 |
Dec. 31, 2016 |
|
Long-term Purchase Commitment [Line Items] | |||
Total future drilling commitments at balance sheet date | $ 144.0 | ||
Drilling commitments due remainder of current year | 55.0 | ||
Drilling commitments Year Two | 59.0 | ||
Drilling Commitments Year Three | 29.0 | ||
Drilling Commitments Year Four | $ 1.0 | ||
Pipeline commitments, end date | 2028 | ||
Future Drilling Commitments End Date | 2020-02 | ||
Purchase Obligation, total | $ 1,200.0 | ||
Purchase Obligation, due in remainder of current year | 115.0 | ||
Purchase Obligation, due second year | 245.0 | ||
Purchase Obligation, due third year | 233.0 | ||
Purchase Obligation, due fourth year | 101.0 | ||
Purchase Obligation, due fifth year | 89.0 | ||
Purchase Obligation, due after fifth year | 424.0 | ||
Damages sought in litigation matter | $ 200.0 | ||
Legal proceedings recorded as a liability under other noncurrent liabilities | $ (6.5) | $ (6.5) |
Stock Based Compensation - Stock Based Compensation Expenses (Detail) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||||
Non-cash equity compensation | $ 9.1 | $ 11.8 | $ 20.6 | $ 21.0 |
Stock-Based Compensation - Additional Information (Detail) $ in Millions |
6 Months Ended |
---|---|
Jun. 30, 2017
USD ($)
shares
| |
Restricted stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Stock available to grant | shares | 14,551,387 |
Fair value at vesting date | $ | $ 36.1 |
Unrecognized compensation expense related to non-vested | $ | $ 81.0 |
Unrecognized compensation expense related to non-vested, period for recognition, in years | 1 year 7 months 17 days |
Restricted stock [Member] | Minimum [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Grants vest over periods, in years | 1 year |
Restricted stock [Member] | Maximum [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Grants vest over periods, in years | 3 years |
2013 Plan [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Common stock available for issue | shares | 19,680,072 |
Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock Outstanding (Detail) |
6 Months Ended |
---|---|
Jun. 30, 2017
$ / shares
shares
| |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Non-vested shares, beginning balance | shares | 3,913,634 |
Granted (unaudited), shares | shares | 1,464,944 |
Vested shares | shares | (785,487) |
Forfeited (unaudited), shares | shares | (520,002) |
Non-vested shares, ending balance | shares | 4,073,089 |
Non-vested, weighted average grant-date fair value, beginning of period | $ / shares | $ 37.12 |
Granted, weighted average grant-date fair value | $ / shares | 45.06 |
Vested, weighted average grant-date fair value | $ / shares | 58.66 |
Forfeited, weighted average grant-date fair value | $ / shares | 37.47 |
Non-vested, weighted average grant-date fair value, end of period | $ / shares | $ 35.78 |
Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
Mar. 31, 2017 |
Dec. 31, 2016 |
Mar. 31, 2016 |
Dec. 31, 2015 |
|
Accumulated Other Comprehensive Income [Abstract] | ||||||||
Accumulated other comprehensive income (loss) | $ 67 | $ (2,903) | $ 67 | $ (2,903) | $ (122) | $ (260) | $ (2,928) | $ (3,354) |
Foreign currency translation adjustments | 189 | 25 | 327 | 451 | ||||
Translation Adjustment Functional to Reporting Currency, Tax Benefit (Expense) | 0 | 0 | 0 | 0 | ||||
Total other comprehensive income, net of tax | $ 189 | $ 25 | $ 327 | $ 451 |
Income Taxes (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
||||||
Income Taxes [Abstract] | |||||||||
Share-based Compensation, Tax Deficiency from Compensation Expense | $ 500 | $ 3,800 | |||||||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | $ 35,494 | $ 67,212 | $ 33,222 | $ 179,097 | |||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35.00% | 35.00% | 35.00% | 35.00% | |||||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount | $ 3,043 | $ 5,761 | $ 2,848 | $ 15,351 | |||||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | 3.00% | 3.00% | 3.00% | 3.00% | |||||
Effective Income Tax Rate Reconciliation, Tax Benefit (Deficiency), Amount | [1] | $ (473) | $ 0 | $ (3,773) | $ 0 | ||||
Effective Income Tax Rate Reconciliation, Tax Benefit (Deficiency), Percent | (1.00%) | 0.00% | (4.00%) | 0.00% | |||||
Effective Income Tax Rate Reconciliation, Valuation Allowance, Amount | [2] | $ (112) | $ (217) | $ (257) | $ (294) | ||||
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent | 0.00% | 0.00% | 0.00% | 0.00% | |||||
Effective Income Tax Rate Reconciliation, Tax Settlement, Foreign, Amount | $ (55) | $ (90) | $ (122) | $ (124) | |||||
Effective Income Tax Rate Reconciliation, Tax Settlement, Foreign, Percent | 0.00% | 0.00% | 0.00% | 0.00% | |||||
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount | $ (42) | $ (34) | $ (85) | $ (52) | |||||
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent | 0.00% | 0.00% | 0.00% | 0.00% | |||||
Benefit for income taxes | $ 37,855 | $ 72,632 | $ 31,833 | $ 193,978 | |||||
Effective Income Tax Rate Reconciliation, Percent | 37.00% | 38.00% | 34.00% | 38.00% | |||||
|
Property Dispositions (Details) $ in Millions |
3 Months Ended | |
---|---|---|
Jun. 30, 2016
USD ($)
|
Apr. 29, 2016
a
|
|
Property Dispositions [Abstract] | ||
Non-producing leasehold | a | 132,000 | |
Proceeds from Sale of Oil and Gas Property and Equipment | $ 110.0 | |
Gain (Loss) on Disposition of Unproved Property | $ 96.9 |
Subsequent Events (Details) $ in Millions |
3 Months Ended | ||
---|---|---|---|
Sep. 30, 2017
USD ($)
a
Boe
|
Jun. 30, 2016
USD ($)
|
Apr. 29, 2016
a
|
|
Subsequent Event [Line Items] | |||
Proceeds from Sale of Oil and Gas Property and Equipment | $ 110.0 | ||
Leasehold | a | 132,000 | ||
Subsequent Event [Member] | |||
Subsequent Event [Line Items] | |||
Proceeds from Sale of Oil and Gas Property and Equipment | $ 147.5 | ||
Leasehold | a | 32,600 | ||
Production, Barrels of Oil Equivalents | Boe | 1,800 | ||
Gain (Loss) on Disposition of Assets | $ 65.0 |
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