Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Jan. 31, 2018 | Jun. 30, 2017 | |
Document And Entity Information [Abstract] | |||
Entity Registrant Name | CIMAREX ENERGY CO | ||
Entity Central Index Key | 1,168,054 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-Known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Fiscal Period Focus | FY | ||
Document Fiscal Year Focus | 2,017 | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 95,438,121 | ||
Entity Public Float | $ 8,820 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 400,534 | $ 652,876 |
Accounts receivable, net of allowance: | ||
Trade | 100,356 | 42,287 |
Oil and gas sales | 344,552 | 217,395 |
Gas gathering, processing, and marketing | 15,266 | 14,888 |
Oil and gas well equipment and supplies | 49,722 | 33,342 |
Derivative instruments | 15,151 | 0 |
Prepaid expenses | 8,518 | 7,335 |
Other current assets | 1,536 | 1,181 |
Total current assets | 935,635 | 969,304 |
Oil and gas properties at cost, using the full cost method of accounting: | ||
Proved properties | 17,513,460 | 16,225,495 |
Unproved properties and properties under development, not being amortized | 476,903 | 478,277 |
Gross oil and gas properties | 17,990,363 | 16,703,772 |
Less—accumulated depreciation, depletion, amortization, and impairment | (14,748,833) | (14,349,505) |
Net oil and gas properties | 3,241,530 | 2,354,267 |
Fixed assets, net of accumulated depreciation of $290,114 and $246,901, respectively | 210,922 | 205,465 |
Goodwill | 620,232 | 620,232 |
Derivative instruments | 2,086 | 0 |
Deferred income taxes | 0 | 55,835 |
Other assets | 32,234 | 32,621 |
Total assets | 5,042,639 | 4,237,724 |
Accounts payable: | ||
Trade | 68,883 | 49,163 |
Gas gathering, processing, and marketing | 29,503 | 25,323 |
Accrued liabilities: | ||
Exploration and development | 115,762 | 82,320 |
Taxes other than income | 23,687 | 18,766 |
Other | 212,400 | 177,695 |
Derivative instruments | 42,066 | 49,370 |
Revenue payable | 187,273 | 119,715 |
Total current liabilities | 679,574 | 522,352 |
Long-term debt: | ||
Principal | 1,500,000 | 1,500,000 |
Less—unamortized debt issuance costs and discount | (13,080) | (12,061) |
Long-term debt, net | 1,486,920 | 1,487,939 |
Deferred income taxes | 101,618 | 0 |
Asset retirement obligation | 158,421 | 140,770 |
Derivative instruments | 4,268 | 2,570 |
Other liabilities | 43,560 | 41,104 |
Total liabilities | 2,474,361 | 2,194,735 |
Commitments and contingencies (Note 10) | ||
Stockholders’ equity: | ||
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued | 0 | 0 |
Common stock, $0.01 par value, 200,000,000 shares authorized, 95,437,434 and 95,123,525 shares issued, respectively | 954 | 951 |
Additional paid-in capital | 2,764,384 | 2,763,452 |
Retained earnings (accumulated deficit) | (199,259) | (722,359) |
Accumulated other comprehensive income | 2,199 | 945 |
Total stockholders' equity | 2,568,278 | 2,042,989 |
Total liabilities and stockholders' equity | $ 5,042,639 | $ 4,237,724 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Fixed assets, accumulated depreciation | $ 290,114 | $ 246,901 |
Preferred stock, par value (USD per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 15,000,000 | 15,000,000 |
Preferred stock, shares issued | 0 | 0 |
Common stock, par value (USD per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 200,000,000 | 200,000,000 |
Common stock, shares issued | 95,437,434 | 95,123,525 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues: | |||
Oil sales | $ 981,646 | $ 632,934 | $ 809,664 |
Gas sales | 516,936 | 388,786 | 428,227 |
NGL sales | 375,421 | 199,498 | 179,647 |
Gas gathering and other | 43,751 | 36,033 | 34,688 |
Gas marketing | 495 | 94 | 393 |
Total revenues | 1,918,249 | 1,257,345 | 1,452,619 |
Costs and expenses: | |||
Impairment of oil and gas properties | 0 | 757,670 | 4,033,295 |
Depreciation, depletion, and amortization | 446,031 | 392,348 | 731,460 |
Asset retirement obligation | 15,624 | 7,828 | 9,121 |
Production | 262,180 | 232,002 | 299,374 |
Transportation, processing, and other operating | 231,640 | 190,725 | 182,362 |
Gas gathering and other | 35,840 | 31,785 | 38,138 |
Taxes other than income | 89,864 | 61,946 | 84,764 |
General and administrative | 79,996 | 73,901 | 74,688 |
Stock compensation | 26,256 | 24,523 | 19,559 |
(Gain) loss on derivative instruments, net | (21,210) | 55,749 | (11,246) |
Other operating expense, net | 1,314 | 755 | 856 |
Total costs and expenses | 1,167,535 | 1,829,232 | 5,462,371 |
Operating income (loss) | 750,714 | (571,887) | (4,009,752) |
Other (income) and expense: | |||
Interest expense | 74,821 | 83,272 | 85,746 |
Capitalized interest | (22,948) | (21,248) | (30,589) |
Loss on early extinguishment of debt | 28,187 | 0 | 0 |
Other, net | (11,342) | (10,707) | (13,576) |
Income (loss) before income tax | 681,996 | (623,204) | (4,051,333) |
Income tax expense (benefit) | 187,667 | (214,401) | (1,471,729) |
Net income (loss) | $ 494,329 | $ (408,803) | $ (2,579,604) |
Earnings (loss) per share to common stockholders: | |||
Basic (USD per share) | $ 5.19 | $ (4.38) | $ (27.75) |
Diluted (USD per share) | 5.19 | (4.38) | (27.75) |
Dividends declared (USD per share) | $ 0.32 | $ 0.32 | $ 0.64 |
Comprehensive income (loss): | |||
Net income (loss) | $ 494,329 | $ (408,803) | $ (2,579,604) |
Other comprehensive income (loss): | |||
Change in fair value of investments, net of tax of $106, $289, and ($380), respectively | 1,254 | 504 | (661) |
Total comprehensive income (loss) | $ 495,583 | $ (408,299) | $ (2,580,265) |
CONSOLIDATED STATEMENTS OF OPE5
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Statement [Abstract] | |||
Change in fair value investments, tax | $ 106 | $ 289 | $ (380) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash flows from operating activities: | |||
Net income (loss) | $ 494,329 | $ (408,803) | $ (2,579,604) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Impairment of oil and gas properties | 0 | 757,670 | 4,033,295 |
Depreciation, depletion, and amortization | 446,031 | 392,348 | 731,460 |
Asset retirement obligation | 15,624 | 7,828 | 9,121 |
Deferred income taxes | 190,479 | (213,286) | (1,486,439) |
Stock compensation | 26,256 | 24,523 | 19,559 |
(Gain) loss on derivative instruments, net | (21,210) | 55,749 | (11,246) |
Settlements on derivative instruments | (1,633) | 7,437 | 0 |
Loss on early extinguishment of debt | 28,187 | 0 | 0 |
Changes in non-current assets and liabilities | 1,891 | 3,867 | 23,230 |
Other, net | 5,677 | 1,805 | 4,206 |
Changes in operating assets and liabilities: | |||
Accounts receivable | (186,157) | (49,340) | 186,699 |
Other current assets | (17,931) | 20,880 | 37,954 |
Accounts payable and other current liabilities | 115,021 | 25,171 | (242,507) |
Net cash provided by operating activities | 1,096,564 | 625,849 | 725,728 |
Cash flows from investing activities: | |||
Oil and gas capital expenditures | (1,233,126) | (699,558) | (979,044) |
Other capital expenditures | (45,352) | (22,228) | (70,592) |
Sales of oil and gas assets | 11,680 | 21,487 | 39,853 |
Sales of other assets | 901 | 7,889 | 1,178 |
Net cash used by investing activities | (1,265,897) | (692,410) | (1,008,605) |
Cash flows from financing activities: | |||
Borrowings of long-term debt | 748,110 | 0 | 0 |
Repayments of long-term debt | (750,000) | 0 | 0 |
Proceeds from sale of common stock | 0 | 0 | 752,100 |
Financing and underwriting fees | (29,312) | (101) | (24,633) |
Dividends paid | (30,532) | (38,024) | (58,281) |
Employee withholding taxes paid upon the net settlement of equity-classified stock awards | (21,669) | (26,624) | (21,240) |
Proceeds from exercise of stock options | 394 | 4,804 | 8,451 |
Net cash (used) provided by financing activities | (83,009) | (59,945) | 656,397 |
Net change in cash and cash equivalents | (252,342) | (126,506) | 373,520 |
Cash and cash equivalents at beginning of period | 652,876 | 779,382 | 405,862 |
Cash and cash equivalents at end of period | $ 400,534 | $ 652,876 | $ 779,382 |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Accumulated Other Comprehensive Income (Loss) |
Balance at beginning of period (shares) at Dec. 31, 2014 | 87,592 | ||||
Balance at beginning of period at Dec. 31, 2014 | $ 4,331,967 | $ 876 | $ 1,997,080 | $ 2,332,909 | $ 1,102 |
Increase (Decrease) in Stockholders' Equity | |||||
Dividends paid on stock awards subsequently forfeited | 109 | 109 | |||
Dividends | (59,422) | (59,422) | |||
Net income (loss) | (2,579,604) | (2,579,604) | |||
Unrealized change in fair value of investments, net of tax | (661) | (661) | |||
Issuance of common stock (shares) | 6,900 | ||||
Issuance of common stock | 729,537 | $ 69 | 729,468 | ||
Issuance of restricted stock awards (shares) | 471 | ||||
Issuance of restricted stock awards | 0 | $ 5 | (5) | ||
Common stock reacquired and retired (shares) | (194) | ||||
Common stock reacquired and retired | (21,240) | $ (2) | (21,238) | ||
Restricted stock forfeited and retired (shares) | (90) | ||||
Restricted stock forfeited and retired | 0 | $ (1) | 1 | ||
Exercise of stock options (shares) | 142 | ||||
Exercise of stock options | 8,451 | $ 1 | 8,450 | ||
Stock-based compensation | 36,232 | 36,232 | |||
Stock-based compensation tax benefit | 12,988 | 12,988 | |||
Balance at end of period (shares) at Dec. 31, 2015 | 94,821 | ||||
Balance at end of period at Dec. 31, 2015 | 2,458,357 | $ 948 | 2,762,976 | (306,008) | 441 |
Increase (Decrease) in Stockholders' Equity | |||||
Dividends paid on stock awards subsequently forfeited | 37 | 2 | 35 | ||
Dividends | (7,583) | (7,583) | |||
Dividends in excess of retained earnings | (22,805) | (22,805) | |||
Net income (loss) | (408,803) | (408,803) | |||
Unrealized change in fair value of investments, net of tax | 504 | 504 | |||
Issuance of restricted stock awards (shares) | 479 | ||||
Issuance of restricted stock awards | 0 | $ 5 | (5) | ||
Common stock reacquired and retired (shares) | (208) | ||||
Common stock reacquired and retired | (26,625) | $ (3) | (26,622) | ||
Restricted stock forfeited and retired (shares) | (32) | ||||
Restricted stock forfeited and retired | 0 | ||||
Exercise of stock options (shares) | 64 | ||||
Exercise of stock options | 4,804 | $ 1 | 4,803 | ||
Stock-based compensation | 45,103 | 45,103 | |||
Balance at end of period (shares) at Dec. 31, 2016 | 95,124 | ||||
Balance at end of period at Dec. 31, 2016 | 2,042,989 | $ 951 | 2,763,452 | (722,359) | 945 |
Increase (Decrease) in Stockholders' Equity | |||||
Dividends paid on stock awards subsequently forfeited | 43 | 11 | 32 | ||
Dividends in excess of retained earnings | (30,489) | (30,489) | |||
Net income (loss) | 494,329 | 494,329 | |||
Unrealized change in fair value of investments, net of tax | 1,254 | 1,254 | |||
Issuance of restricted stock awards (shares) | 552 | ||||
Issuance of restricted stock awards | 0 | $ 5 | (5) | ||
Common stock reacquired and retired (shares) | (204) | ||||
Common stock reacquired and retired | (21,669) | $ (2) | (21,667) | ||
Restricted stock forfeited and retired (shares) | (41) | ||||
Restricted stock forfeited and retired | 0 | ||||
Exercise of stock options (shares) | 6 | ||||
Exercise of stock options | 394 | 394 | |||
Stock-based compensation | 48,321 | 48,321 | |||
Other | (26) | (26) | |||
Balance at end of period (shares) at Dec. 31, 2017 | 95,437 | ||||
Balance at end of period at Dec. 31, 2017 | 2,568,278 | $ 954 | 2,764,384 | (199,259) | $ 2,199 |
Increase (Decrease) in Stockholders' Equity | |||||
Cumulative effect adjustment of adopting ASU 2016-09 (Note 6) | $ 33,132 | $ 4,393 | $ 28,739 |
BASIS OF PRESENTATION AND SUMMA
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, and New Mexico. Basis of Presentation Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Our significant accounting policies are discussed below. The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in consolidation. Certain amounts in the prior year financial statements have been reclassified to conform to the 2017 financial statement presentation. Segment Information We have determined that our business is comprised of only one segment because our gathering, processing, and marketing activities are ancillary to our production operations. Use of Estimates The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Areas of significance requiring the use of management’s judgments include the estimation of proved oil and gas reserves used in calculating depletion, the estimation of future net revenues used in computing ceiling test limitations, the estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, and contingencies. We analyze our estimates and base them on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions, and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. Cash and Cash Equivalents Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities of three months or less. Cash equivalents are stated at cost, which approximates market value. Oil and Gas Well Equipment and Supplies Our oil and gas well equipment and supplies are valued at the lower of cost and net realizable value, where net realizable value is estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Declines in the price of oil and gas well equipment and supplies in future periods could cause us to recognize impairments on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity. Oil and Gas Properties We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the acquisition, exploration, and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. Expenditures for maintenance and repairs are charged to production expense in the period incurred. Under the full cost method of accounting, we are required to perform quarterly ceiling test calculations to test our oil and gas properties for possible impairment. If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes. We currently do not have any unproven properties that are being amortized. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures. At December 31, 2017 , the carrying value of our oil and gas properties subject to the test did not exceed the calculated value of the ceiling limitation and, therefore, we did not recognize an impairment. However, a decline of approximately 19% or more in the value of the ceiling limitation would have resulted in an impairment. For the years ended December 31, 2016 and 2015 , full year impairments totaled $757.7 million ( $481.4 million , net of tax) and $4.03 billion ( $2.56 billion , net of tax), respectively. These impairments resulted primarily from the impact of decreases in the trailing twelve-month average prices for oil, gas, and NGLs utilized in determining the future net revenues from proved reserves. The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes. If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters. The calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet. Any impairment of oil and gas properties is not reversible at a later date. Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities, commodity prices, and impairment of oil and gas properties will cause corresponding changes in depletion expense in periods subsequent to these changes. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized. Significant unproved properties are evaluated individually. Unproved properties that are not considered individually significant are aggregated for evaluation purposes and related costs are transferred to the costs to be amortized quarterly based on the application of historical factors. Fixed Assets Fixed assets consist primarily of gathering and plant facilities, vehicles, airplanes, office furniture, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from 3 to 30 years . Goodwill Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. In performing the goodwill test, we compare the fair value of our reporting unit with its carrying amount. If the carrying amount of the reporting unit were to exceed its fair value, an impairment charge would be recognized in the amount of this excess, limited to the total amount of goodwill allocated to that reporting unit. We evaluate our goodwill for impairment in the fourth quarter of each year and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. We have historically tested goodwill for impairment as of December 31 each year; however, in 2017 we elected to change the date of our annual goodwill impairment test to October 31. We do not believe a change in the goodwill impairment testing date represents a material change to a method of applying an accounting principle because the change in impairment testing date does not have a material effect on our financial statements in light of the internal controls and requirements to assess goodwill impairment upon certain triggering events. Based upon our assessment as of October 31, 2017, goodwill was not impaired. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors become unfavorable. Revenue Recognition Oil, Gas, and NGL Sales Revenue is recognized from the sales of oil, gas, and NGLs when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured. There is a ready market for our products and sales occur soon after production. Gas Gathering When we transport and/or process third-party gas associated with our equity gas, we recognize revenue for the fees charged to third-parties for such services. Gas Marketing When we market and sell gas for working interest owners we act as agent under short-term sales and supply agreements and earn a fee for such services. Revenues from such services are recognized as gas is delivered. Gas Imbalances We use the sales method of accounting for gas imbalances. Revenue from the sale of gas is recorded on the basis of gas actually sold by us. If our aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented. General and Administrative Expenses General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting. Derivatives Our derivative contracts are recorded on the balance sheet at fair value. Our firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment. See Note 4 for additional information regarding our derivative instruments. Income Taxes We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. We classify all deferred tax assets and liabilities as non-current. We routinely assess the realizability of our deferred tax assets. We routinely assess the realizability of our deferred tax assets. Numerous judgments and assumptions are inherent in this assessment, including the determination of future taxable income, which is affected by factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. If we conclude that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. We regularly assess and, if required, establish accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions where the company operates. See Note 9 for additional information regarding our income taxes, including the impact of H.R.1, commonly referred to as the Tax Cuts and Jobs Act, which the U.S. enacted on December 22, 2017. Contingencies A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and determine when we should record losses for these items based on information available to us. See Note 10 for additional information regarding our contingencies. Asset Retirement Obligations We recognize the present value of the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This liability includes costs related to the abandonment of wells, the removal of facilities and equipment, and site restorations. In periods subsequent to the initial measurement of an asset retirement obligation at present value, a period-to-period increase in the carrying amount of the liability is recognized as accretion expense, which represents the effect of the passage of time on the amount of the liability. An equivalent amount is added to the carrying amount of the liability. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are included as a component of the DD&A calculations. The current portion of our asset retirement obligations is recorded in “Accrued liabilities — Other” in the accompanying consolidated balance sheets and cash payments for settlements of retirement obligations are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note 8 for additional information regarding our asset retirement obligations. Stock-based Compensation We recognize compensation cost related to all stock-based awards in the financial statements based on their estimated grant date fair value. We grant various types of stock-based awards including stock options, restricted stock (including awards with service-based vesting and market condition-based vesting provisions), and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant date market value of the award utilizing a statistical analysis. Compensation cost is recognized ratably over the applicable vesting period. To the extent compensation cost relates to employees directly involved in oil and gas acquisition, exploration, and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized as stock compensation expense. See Note 6 for additional information regarding our stock-based compensation. Earnings (Loss) per Share We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and, therefore, should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Our unvested share-based payment awards, consisting of restricted stock and units, qualify as participating securities. See Note 7 for additional information regarding our earnings per share. Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) , which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition , and most industry-specific guidance throughout the Industry Topics of the Codification. Entities can choose to adopt the standard using either the full retrospective approach or a modified retrospective approach. We will adopt the standard effective January 1, 2018, utilizing the modified retrospective approach, which will be applied to contracts that were not completed as of January 1, 2018. The new standard will not have an impact on net income (loss) or cash flows from operations; however, certain costs previously classified as Transportation, processing, and other operating expenses in the statement of operations will be reflected as deductions from revenue under the new standard. Had Topic 606 been in effect for the fourth quarter of 2017, Revenue and Transportation, processing and other operating expenses for the quarter would have each been reduced by an estimated range of $15.0 million to $16.0 million . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) . The key provision of this ASU is that a lessee must recognize (i) liabilities to make lease payments and (ii) right-of-use assets on its balance sheet. The ASU permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than twelve months. Under current GAAP, a determination of whether a lease is a capital or operating lease is made at lease inception and no assets or liabilities are recognized for operating leases. Under this ASU, the determination to be made at the inception of a contract is whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. An entity may make a policy election to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and comprehensive income and cash flows, however, both types of leases require the recognition of assets and liabilities on the balance sheet. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are in the process of evaluating the potential impact of adopting this guidance, but believe the primary effect will be to record assets and liabilities for contracts currently accounted for as operating leases. We do not intend to adopt the standard early. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842 . This ASU provides an optional transition practical expedient to not evaluate under Topic 842 (discussed above) existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. Under the full cost method of accounting, we capitalize to oil and gas properties all property acquisition, exploration, and development costs, which include the costs of land easements. We plan to elect this practical expedient and continue to apply our current accounting policy to account for land easements that existed before our adoption of Topic 842 and will evaluate new or modified land easements under Topic 842 upon our adoption of Topic 842. We are in the process of evaluating the potential impact of adopting this guidance, and do not intend to adopt the standard early. |
CAPITAL STOCK
CAPITAL STOCK | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
CAPITAL STOCK | CAPITAL STOCK Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At December 31, 2017 , there were 95.4 million shares of common stock and no shares of preferred stock outstanding. See our Consolidated Statements of Stockholders’ Equity for detailed capital stock activity. In May 2015, we completed an underwritten public offering of 6.9 million shares of common stock, which included 0.9 million shares of common stock issued pursuant to an overallotment option to purchase additional shares granted to the underwriters. The stock was sold to the public at $109.00 per share, with a par value of $0.01 , and we received net proceeds of $729.5 million from the sale, after deducting underwriting fees. Dividends A cash dividend has been paid to stockholders in every quarter since the first quarter of 2006. A quarterly dividend of $0.08 per share was declared in each quarter of 2017 and 2016 and a quarterly dividend of $0.16 per share was declared in each quarter of 2015. We typically declare dividends in one quarter and pay them in the next quarter. Dividends declared are recorded as a reduction of retained earnings to the extent retained earnings are available at the close of the period prior to the date of the declared dividend. Dividends in excess of retained earnings are recorded as a reduction of additional paid-in capital. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors. |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2017 | |
Long-term Debt, Unclassified [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT Long-term debt at December 31, 2017 and 2016 consisted of the following: December 31, 2017 December 31, 2016 (in thousands) Principal Unamortized Debt Issuance Costs and Discount (1) Long-term Debt, net Principal Unamortized Debt Issuance Costs Long-term Debt, net 5.875% Senior Notes $ — $ — $ — $ 750,000 $ (5,691 ) $ 744,309 4.375% Senior Notes 750,000 (5,383 ) 744,617 750,000 (6,370 ) 743,630 3.90% Senior Notes 750,000 (7,697 ) 742,303 — — — Total long-term debt $ 1,500,000 $ (13,080 ) $ 1,486,920 $ 1,500,000 $ (12,061 ) $ 1,487,939 ________________________________________ (1) At December 31, 2017 , the unamortized debt issuance costs and discount related to the 3.90% notes were $5.9 million and $1.8 million , respectively. The 4.375% notes were issued at par. Bank Debt In October 2015, we entered into a new senior unsecured revolving credit facility (“Credit Facility”) which matures October 16, 2020. The Credit Facility has aggregate commitments of $1.0 billion , with an option to increase aggregate commitments to $1.25 billion at any time. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. As of December 31, 2017 , we had no bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, leaving an unused borrowing availability of $997.5 million . At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.125 - 2.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.125 - 1.0% , based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of 0.125 - 0.35% , based on the credit rating for our senior unsecured long-term debt. The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65% . As of December 31, 2017 , we were in compliance with all of the financial covenants. At December 31, 2017 and 2016 , we had $3.4 million and $4.5 million , respectively, of unamortized debt issuance costs associated with our Credit Facility which were recorded as deferred assets and included in Other assets, net in our balance sheets. The costs are being amortized to interest expense ratably over the life of the Credit Facility. Senior Notes On April 10, 2017, we completed a cash tender offer to purchase any of our 5.875% notes for cash consideration of $1,031.67 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with $253.5 million aggregate principal amount of the notes validly tendered. We settled these tendered notes for $268.1 million , including accrued interest. On May 12, 2017, we completed a redemption of the 5.875% notes remaining outstanding for $1,029.38 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the redemption date, settling the notes for $512.0 million , including accrued interest. We recognized a loss on early extinguishment of debt related to these transactions of $28.2 million , composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs. The original maturity date of the 5.875% notes was May 1, 2022 . On April 10, 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes due May 15, 2027 at 99.748% of par to yield 3.93% per annum. We received $741.8 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs. The notes bear an annual interest rate of 3.90% and interest is payable semiannually on May 15 and November 15, with the first payment occurring November 15, 2017. Along with cash on hand, we used the proceeds to fund the settlement of the tendered and redeemed 5.875% notes. In June 2014, we issued $750 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024 and interest is payable semiannually on June 1 and December 1. Each of our senior unsecured notes is governed by an indenture containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of December 31, 2017 . The effective interest rate on the 4.375% notes and the 3.90% notes, including the amortization of debt issuance costs and discount, as applicable, is 4.50% and 4.01% , respectively. |
DERIVATIVE INSTRUMENTS
DERIVATIVE INSTRUMENTS | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedges, Assets [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS We periodically use derivative instruments to mitigate volatility in commodity prices. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future cash flow from favorable price changes. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. As of December 31, 2017 , we have entered into oil and gas collars and oil basis swaps. Under our collars, we receive the difference between the published index price and a floor price if the index price is below the floor price or we pay the difference between the ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, we have fixed the minimum and maximum prices we can receive on the underlying production. Our basis swaps are settled based on the difference between a published index price minus a fixed differential and the applicable local index price under which the underlying production is sold. By using a basis swap, we have fixed the differential between the published index price and certain of our physical pricing points. For our Permian oil production, the basis swaps fix the price differential between the WTI NYMEX (Cushing Oklahoma) price and the WTI Midland price. For our Permian and Mid-Continent gas production, the contract prices in our collars are consistent with the index prices used to sell our production. The following tables summarize our outstanding derivative contracts as of December 31, 2017 : Oil Collars: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: WTI (1) Volume (Bbls) 2,610,000 2,093,000 1,748,000 1,196,000 7,647,000 Weighted Avg Price - Floor $ 47.28 $ 47.26 $ 46.68 $ 48.00 $ 47.25 Weighted Avg Price - Ceiling $ 56.33 $ 55.61 $ 54.90 $ 55.10 $ 55.62 2019: WTI (1) Volume (Bbls) 630,000 637,000 — — 1,267,000 Weighted Avg Price - Floor $ 48.00 $ 48.00 $ — $ — $ 48.00 Weighted Avg Price - Ceiling $ 56.09 $ 56.09 $ — $ — $ 56.09 ________________________________________ (1) The index price for these collars is West Texas Intermediate (“WTI”) as quoted on the New York Mercantile Exchange (“NYMEX”). Gas Collars: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: PEPL (1) Volume (MMBtu) 11,700,000 9,100,000 6,440,000 3,680,000 30,920,000 Weighted Avg Price - Floor $ 2.57 $ 2.47 $ 2.43 $ 2.43 $ 2.49 Weighted Avg Price - Ceiling $ 2.93 $ 2.81 $ 2.67 $ 2.66 $ 2.81 Perm EP (2) Volume (MMBtu) 8,100,000 6,370,000 4,600,000 2,760,000 21,830,000 Weighted Avg Price - Floor $ 2.52 $ 2.39 $ 2.34 $ 2.33 $ 2.42 Weighted Avg Price - Ceiling $ 2.84 $ 2.67 $ 2.53 $ 2.52 $ 2.68 2019: PEPL (1) Volume (MMBtu) 2,700,000 2,730,000 — — 5,430,000 Weighted Avg Price - Floor $ 2.40 $ 2.40 $ — $ — $ 2.40 Weighted Avg Price - Ceiling $ 2.67 $ 2.67 $ — $ — $ 2.67 Perm EP (2) Volume (MMBtu) 1,800,000 1,820,000 — — 3,620,000 Weighted Avg Price - Floor $ 2.30 $ 2.30 $ — $ — $ 2.30 Weighted Avg Price - Ceiling $ 2.49 $ 2.49 $ — $ — $ 2.49 ________________________________________ (1) The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC. (2) The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC. Oil Basis Swaps: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: WTI Midland (1) Volume (Bbls) 1,170,000 1,183,000 1,196,000 736,000 4,285,000 Weighted Avg Differential (2) $ (0.72 ) $ (0.72 ) $ (0.72 ) $ (0.58 ) $ (0.69 ) 2019: WTI Midland (1) Volume (Bbls) 450,000 455,000 — — 905,000 Weighted Avg Differential (2) $ (0.47 ) $ (0.47 ) $ — $ — $ (0.47 ) ________________________________________ (1) The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude. (2) The index price we receive under these basis swaps is WTI as quoted on the NYMEX less the weighted average differential shown in the table. The following tables summarize our derivative contracts entered into subsequent to December 31, 2017 through February 22, 2018: Oil Collars: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: WTI (1) Volume (Bbls) — 546,000 552,000 552,000 1,650,000 Weighted Avg Price - Floor $ — $ 50.00 $ 50.00 $ 50.00 $ 50.00 Weighted Avg Price - Ceiling $ — $ 66.82 $ 66.82 $ 66.82 $ 66.82 2019: WTI (1) Volume (Bbls) 540,000 546,000 552,000 — 1,638,000 Weighted Avg Price - Floor $ 50.00 $ 50.00 $ 50.00 $ — $ 50.00 Weighted Avg Price - Ceiling $ 66.82 $ 66.82 $ 66.82 $ — $ 66.82 ________________________________________ (1) The index price for these collars is WTI as quoted on the NYMEX. Gas Collars: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: PEPL (1) Volume (MMBtu) — 1,820,000 1,840,000 1,840,000 5,500,000 Weighted Avg Price - Floor $ — $ 1.98 $ 1.98 $ 1.98 $ 1.98 Weighted Avg Price - Ceiling $ — $ 2.16 $ 2.16 $ 2.16 $ 2.16 Perm EP (2) Volume (MMBtu) — 1,820,000 1,840,000 1,840,000 5,500,000 Weighted Avg Price - Floor $ — $ 1.65 $ 1.65 $ 1.65 $ 1.65 Weighted Avg Price - Ceiling $ — $ 1.80 $ 1.80 $ 1.80 $ 1.80 2019: PEPL (1) Volume (MMBtu) 1,800,000 1,820,000 1,840,000 — 5,460,000 Weighted Avg Price - Floor $ 1.98 $ 1.98 $ 1.98 $ — $ 1.98 Weighted Avg Price - Ceiling $ 2.16 $ 2.16 $ 2.16 $ — $ 2.16 Perm EP (2) Volume (MMBtu) 1,800,000 1,820,000 1,840,000 — 5,460,000 Weighted Avg Price - Floor $ 1.65 $ 1.65 $ 1.65 $ — $ 1.65 Weighted Avg Price - Ceiling $ 1.80 $ 1.80 $ 1.80 $ — $ 1.80 ________________________________________ (1) The index price for these collars is PEPL as quoted in Platt’s Inside FERC. (2) The index price for these collars is Perm EP as quoted in Platt’s Inside FERC. Oil Basis Swaps: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: WTI Midland (1) Volume (Bbls) — 91,000 92,000 92,000 275,000 Weighted Avg Differential (2) $ — $ (0.70 ) $ (0.70 ) $ (0.70 ) $ (0.70 ) 2019: WTI Midland (1) Volume (Bbls) 90,000 91,000 92,000 — 273,000 Weighted Avg Differential (2) $ (0.70 ) $ (0.70 ) $ (0.70 ) $ — $ (0.70 ) ________________________________________ (1) The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude. (2) The index price we receive under these basis swaps is WTI as quoted on the NYMEX less the weighted average differential shown in the table. Derivative Gains and Losses Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. The following table presents the components of (Gain) loss on derivative instruments, net for the periods indicated. Years Ended December 31, (in thousands) 2017 2016 2015 Change in fair value of derivative instruments, net: Gas contracts $ (40,226 ) $ 27,462 $ (4,472 ) Oil contracts 17,383 35,724 (6,774 ) (22,843 ) 63,186 (11,246 ) Cash (receipts) payments on derivative instruments, net: Gas contracts (4,557 ) (6,467 ) — Oil contracts 6,190 (970 ) — 1,633 (7,437 ) — (Gain) loss on derivative instruments, net $ (21,210 ) $ 55,749 $ (11,246 ) Derivative Fair Value Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs and are subject to enforceable master netting arrangements, which allow us to offset recognized asset and liability fair value amounts on contracts with the same counterparty. Our accounting policy is to not offset asset and liability positions in our balance sheets. The following tables present the amounts and classifications of our derivative assets and liabilities as of December 31, 2017 and 2016 , as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts. December 31, 2017 (in thousands) Balance Sheet Location Asset Liability Gas contracts Current assets — Derivative instruments $ 15,151 $ — Gas contracts Non-current assets — Derivative instruments 2,086 — Oil contracts Current liabilities — Derivative instruments — 42,066 Oil contracts Non-current liabilities — Derivative instruments — 4,268 Total gross amounts presented in the balance sheet 17,237 46,334 Less: gross amounts not offset in the balance sheet (17,237 ) (17,237 ) Net amount $ — $ 29,097 December 31, 2016 (in thousands) Balance Sheet Location Asset Liability Oil contracts Current liabilities — Derivative instruments $ — $ 27,892 Gas contracts Current liabilities — Derivative instruments — 21,478 Oil contracts Non-current liabilities — Derivative instruments — 1,059 Gas contracts Non-current liabilities — Derivative instruments — 1,511 Total gross amounts presented in the balance sheet — 51,940 Less: gross amounts not offset in the balance sheet — — Net amount $ — $ 51,940 We are exposed to financial risks associated with our derivative contracts from non-performance by our counterparties. We mitigate our exposure to any single counterparty by contracting with a number of financial institutions, each of which have a high credit rating and is a member of our bank credit facility. Our member banks do not require us to post collateral for our derivative liability positions. Because some of the member banks have discontinued derivative activities, in the future we may enter into derivative instruments with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability. The following table provides fair value measurement information for certain assets and liabilities as of December 31, 2017 and 2016 . December 31, 2017 December 31, 2016 (in thousands) Book Value Fair Value Book Value Fair Value Financial Assets (Liabilities): 5.875% Notes due 2022 $ — $ — $ (750,000 ) $ (782,835 ) 4.375% Notes due 2024 $ (750,000 ) $ (797,010 ) $ (750,000 ) $ (779,453 ) 3.90% Notes due 2027 $ (750,000 ) $ (767,813 ) $ — $ — Derivative instruments — assets $ 17,237 $ 17,237 $ — $ — Derivative instruments — liabilities $ (46,334 ) $ (46,334 ) $ (51,940 ) $ (51,940 ) Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The fair value (Level 1) of our fixed rate notes was based on their last traded value before period end. The fair value of our derivative instruments (Level 2) was estimated using option pricing models. These models use certain variables including forward price and volatility curves and the strike prices for the instruments. The fair value estimates are adjusted relative to non-performance risk as appropriate. See Note 4 for further information on the fair value of our derivative instruments. Other Financial Instruments The carrying amounts of our cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. Included in “Accrued liabilities — other” at December 31, 2017 are: (i) accrued operating expenses of approximately $61.3 million and (ii) accrued general and administrative, primarily payroll-related, costs of approximately $54.6 million . Included in “Accrued liabilities — other” at December 31, 2016 are: (i) accrued operating expenses of approximately $53.9 million and (ii) accrued general and administrative, primarily payroll-related, costs of approximately $43.5 million . Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. We conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary. We routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At December 31, 2017 and 2016 , the allowance for doubtful accounts totaled $2.2 million and $1.6 million , respectively. Major Customers In 2017 , our major customers were Energy Transfer Partners, L.P. (“Energy Transfer Partners”) and Plains All American Pipeline, L.P. (“Plains All American”), which accounted for 21% and 13% , respectively, of our consolidated revenues that year. In 2017, the revenue totals for Energy Transfer Partners include revenue from Sunoco Logistics Partners L.P. (“Sunoco”) since the two entities merged in 2017. Sunoco was our major customer in 2016 , accounting for 20% of our consolidated revenues that year. In 2015 , our major customers were Sunoco and Enterprise Products Partners L.P., which accounted for 21% and 17% , respectively, of our consolidated revenues that year. If any one of our major customers was to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production with some delay. If multiple significant customers were to discontinue purchasing our production, we believe there would be challenges initially, but ample markets to handle the disruption. |
STOCK-BASED AND OTHER COMPENSAT
STOCK-BASED AND OTHER COMPENSATION | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
STOCK-BASED AND OTHER COMPENSATION | STOCK-BASED AND OTHER COMPENSATION Equity Incentive Plan Our 2014 Equity Incentive Plan (the “2014 Plan”) was approved by stockholders in May 2014 and our previous plan was terminated at that time. Outstanding awards under the previous plan were not impacted. A total of 6.6 million shares of common stock may be issued under the 2014 Plan, including shares available from the previous plan. The 2014 Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, dividend equivalents, and other stock-based awards. Stock-based Compensation Cost We have recognized non-cash stock-based compensation cost as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts. Years Ended December 31, (in thousands) 2017 2016 2015 Restricted stock awards: Performance stock awards $ 26,020 $ 24,183 $ 18,991 Service-based stock awards 19,746 18,391 14,547 45,766 42,574 33,538 Stock option awards 2,599 2,565 2,803 Total stock compensation cost 48,365 45,139 36,341 Less amounts capitalized to oil and gas properties (22,109 ) (20,616 ) (16,782 ) Stock compensation expense $ 26,256 $ 24,523 $ 19,559 Periodic stock compensation expense will fluctuate based on the grant date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards. The increase in total stock compensation cost in 2017 as compared to 2016 is primarily due to awards granted either during or subsequent to 2016 . These increases were partially offset by awards vesting prior to or during 2017 . We adopted Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) on January 1, 2017. ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, accounting for forfeitures, and classification on the statement of cash flows. Pursuant to ASU 2016-09, we made an accounting policy election to account for forfeitures in compensation cost when they occur, rather than including an estimate of the number of awards that are expected to vest in our compensation cost. The amendments within ASU 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment that increased beginning deferred income tax assets by $33.1 million , reduced beginning accumulated deficit by $28.7 million , and increased beginning additional paid-in capital by $4.4 million . The amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to the payment of employee tax withholdings on the net settlement of equity-classified awards were adopted using a retrospective method. In accordance with this method, we adjusted the statement of cash flows for the year ended December 31, 2016 by increasing both net cash provided by operating activities and net cash used by financing activities by $26.6 million for the payment of employee tax withholdings on the net settlement of equity-classified awards. There were no cash flows related to excess tax benefits during the year ended December 31, 2016 . For the year ended December 31, 2015 , we adjusted the statement of cash flows for the payment of employee tax withholdings on the net settlement of equity-classified awards as well as for the classification of excess tax benefits by increasing net cash provided by operating activities and decreasing net cash provided by financing activities by $34.2 million . Restricted Stock The following table provides information about restricted stock awards granted during the last three years. Years Ended December 31, 2017 2016 2015 Number of Shares Weighted Average Grant Date Fair Value Number of Shares Weighted Average Grant Date Fair Value Number of Shares Weighted Average Grant Date Fair Value Performance stock awards 300,525 $ 89.46 269,915 $ 117.63 263,939 $ 87.12 Service-based stock awards 251,312 $ 94.04 208,724 $ 114.61 207,180 $ 114.80 Total restricted stock awards 551,837 $ 91.55 478,639 $ 116.31 471,119 $ 99.29 Performance stock awards were granted to eligible executives and are subject to service and market condition-based vesting determined by our stock price performance relative to a defined peer group’s stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. In accordance with Internal Revenue Code Section 162(m), certain of the amounts awarded may not be deductible for tax purposes. Service-based stock awards granted to other eligible employees and non-employee directors have vesting schedules ranging from one to five years . The majority of our service-based stock awards cliff vest five years from the grant date. Compensation cost for the performance stock awards is based on the grant date fair value of the award utilizing a Monte Carlo simulation model. Compensation cost for the service-based stock awards is based upon the grant date market value of the award. Such costs are recognized ratably over the applicable vesting period. The following table provides information on restricted stock activity during the year. Service-based Performance (subject to market conditions) Number of Shares Weighted Average Grant Date Fair Value Number of Shares Weighted Average Grant Date Fair Value Outstanding as of January 1, 2017 934,723 $ 96.57 809,270 $ 96.41 Vested (234,468 ) $ 63.49 (275,416 ) $ 84.50 Granted 251,312 $ 94.04 300,525 $ 89.46 Forfeited (41,316 ) $ 105.83 — $ — Outstanding as of December 31, 2017 910,251 $ 103.98 834,379 $ 97.83 The total fair value of restricted stock that vested was $54.4 million in 2017 , $67.9 million in 2016 , and $52.2 million in 2015 . Unrecognized compensation cost related to unvested restricted stock at December 31, 2017 was $105.6 million . We expect to recognize that cost over a weighted average period of 2.8 years . Restricted Units As of December 31, 2017 and 2016 , we had 8,838 restricted units outstanding. These represent restricted units held by a non-employee director who has elected to defer payment of common stock represented by the units until termination of his service on the Board of Directors. Stock Options Options outstanding as of December 31, 2017 expire seven to ten years from the grant date and have service-based vesting whereby the awards vest in increments of one-third on each of the first three anniversary dates of the grant. The exercise price for an option under the 2014 Plan is the closing price of our common stock as reported by the New York Stock Exchange (“NYSE”) on the date of grant. The previous plans provided that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the NYSE on the date of grant. Compensation cost related to stock options is based on the grant date fair value of the award and is recognized ratably over the applicable vesting period. We estimate the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the expected years until exercise. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates. The following summarizes information regarding options granted, including the assumptions used to determine the fair value of those options. Years Ended December 31, 2017 2016 2015 Options granted 96,100 89,850 69,000 Weighted average grant date fair value $ 28.37 $ 33.38 $ 37.56 Weighted average exercise price $ 92.37 $ 114.07 $ 115.28 Total fair value (in thousands) $ 2,727 $ 2,999 $ 2,592 Expected years until exercise 4.5 4.0 5.0 Expected stock volatility 35.0 % 36.7 % 36.6 % Dividend yield 0.3 % 0.3 % 0.6 % Risk-free interest rate 1.7 % 1.0 % 1.6 % Information about outstanding stock options is summarized below. Number of Options Weighted Average Exercise Price Weighted Average Remaining Term Aggregate Intrinsic Value (in thousands) Outstanding as of January 1, 2017 307,810 $ 101.72 Exercised (5,768 ) $ 68.33 Granted 96,100 $ 92.37 Canceled (1,665 ) $ 139.02 Forfeited (13,789 ) $ 88.92 Outstanding as of December 31, 2017 382,688 $ 100.17 4.4 years $ 9,553 Exercisable as of December 31, 2017 209,782 $ 98.55 3.2 years $ 6,020 The following table provides information regarding options exercised and the grant date fair value of options vested. Years Ended December 31, (in thousands) 2017 2016 2015 Cash received from option exercises $ 394 $ 4,804 $ 8,451 Tax benefit from option exercises included in paid-in-capital $ — $ — $ 4,442 Intrinsic value of options exercised $ 257 $ 2,994 $ 7,467 Grant date fair value of options vested $ 2,227 $ 2,486 $ 2,734 The following summary reflects the status of non-vested stock options as of December 31, 2017 and changes during the year. Number of Options Weighted Average Grant Date Fair Value Weighted Average Exercise Price Non-vested as of January 1, 2017 148,361 $ 35.58 $ 117.55 Vested (57,766 ) $ 38.55 $ 128.59 Granted 96,100 $ 28.37 $ 92.37 Forfeited (13,789 ) $ 29.41 $ 88.92 Non-vested as of December 31, 2017 172,906 $ 31.08 $ 102.15 As of December 31, 2017 , there was $4.1 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost over a weighted average period of 1.9 years . Other Compensation We maintain and sponsor a contributory 401(k) plan for our employees. Employer contributions related to the plan were $10.4 million , $6.7 million , and $6.4 million for 2017 , 2016 , and 2015 , respectively. Included in the 2017 amount are accrued employer discretionary contributions. No such employer discretionary contributions occurred in 2016 and 2015. |
EARNINGS (LOSS) PER SHARE
EARNINGS (LOSS) PER SHARE | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
EARNINGS (LOSS) PER SHARE | EARNINGS (LOSS) PER SHARE The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below. Years Ended December 31, (in thousands, except per share data) 2017 2016 2015 Basic: Net income (loss) $ 494,329 $ (408,803 ) $ (2,579,604 ) Participating securities’ share in earnings (1) (8,551 ) — — Net income (loss) available to common stockholders $ 485,778 $ (408,803 ) $ (2,579,604 ) Diluted: Net income (loss) $ 494,329 $ (408,803 ) $ (2,579,604 ) Participating securities’ share in earnings (1) (8,548 ) — — Net income (loss) available to common stockholders $ 485,781 $ (408,803 ) $ (2,579,604 ) Shares: Basic shares outstanding 93,466 93,379 92,992 Dilutive effect of stock options (2) 43 — — Fully diluted common stock 93,509 93,379 92,992 Earnings (loss) per share to common stockholders (3): Basic $ 5.19 $ (4.38 ) $ (27.75 ) Diluted $ 5.19 $ (4.38 ) $ (27.75 ) ________________________________________ (1) Participating securities are not included in undistributed earnings when a loss exists. (2) Inclusion of certain shares would have an anti-dilutive effect; therefore, 302.9 thousand , 2.1 million , and 2.1 million shares were excluded from the calculations for the years ended December 31, 2017 , 2016 , and 2015 , respectively. (3) Earnings (loss) per share are based on actual figures rather than the rounded figures presented. |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2017 and 2016 . (in thousands) 2017 2016 Asset retirement obligation at January 1, $ 154,523 $ 164,105 Liabilities incurred 17,996 3,914 Liability settlements and disposals (12,947 ) (24,108 ) Accretion expense 7,534 7,595 Revisions of estimated liabilities 2,363 3,017 Asset retirement obligation at December 31, 169,469 154,523 Less current obligation 11,048 13,753 Long-term asset retirement obligation $ 158,421 $ 140,770 Liabilities incurred in 2017 includes $10.5 million for the estimated liability to decommission two offshore properties in the Gulf of Mexico in which we were a prior lessee. In January 2018, the Bureau of Safety and Environmental Enforcement (“BSEE”) notified us and other prior lessees that the current lessee of the properties had filed a petition for relief under the bankruptcy code and, as a result, had defaulted on its obligation to decommission the properties. Consequently, BSEE ordered us and other prior lessees to decommission all wells, pipelines, platforms, and other facilities related to these properties. Our estimate of our liability may change as we refine our understanding of the extent of our obligations under the orders from BSEE and obtain additional information on decommissioning costs. During 2017 and 2016 , the liability settlements and disposals included $0.5 million and $14.9 million , respectively, related to properties that were sold. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES The components of the provision for income taxes are as follows: Years Ended December 31, (in thousands) 2017 2016 2015 Current taxes: Federal (benefit) expense $ (2,810 ) $ — $ 14,417 State (benefit) expense (2 ) (1,115 ) 293 (2,812 ) (1,115 ) 14,710 Deferred taxes: Federal expense (benefit) 173,859 (201,529 ) (1,386,086 ) State expense (benefit) 16,620 (11,757 ) (100,353 ) 190,479 (213,286 ) (1,486,439 ) $ 187,667 $ (214,401 ) $ (1,471,729 ) Federal income tax expense (benefit) for the years presented differs from the amounts that would be provided by applying the U.S. federal income tax rate, primarily due to the effect of state income taxes, non-deductible expenses, revisions, and changes in tax laws and tax rates enacted in the period. Reconciliations of the income tax expense (benefit) calculated at the federal statutory rate of 35% to the total income tax expense (benefit) are as follows: Years Ended December 31, (in thousands) 2017 2016 2015 Provision at statutory rate $ 238,699 $ (218,122 ) $ (1,417,967 ) Effect of state taxes 10,074 (10,237 ) (64,794 ) Revision of previous balances — 7,181 5,997 Tax credits and other permanent differences 5,442 5,296 5,035 Change in valuation allowance, net 486 1,481 — Stock-based compensation (5,888 ) — — Impact of reduction in federal statutory rate (61,146 ) — — Income tax expense (benefit) $ 187,667 $ (214,401 ) $ (1,471,729 ) The company recorded a $33.1 million increase to the net operating loss deferred tax asset and corresponding increase to retained earnings in the first quarter of 2017 upon adoption of ASU 2016-09 for deductions taken for employee stock awards on the company’s tax returns in excess of amounts expensed through the company’s statement of operations. Pursuant to ASU 2016-09, excess tax benefits for employee share-based payments of $5.9 million were recognized in income tax expense in 2017 . As a result of the enactment of H.R.1 on December 22, 2017 , the company remeasured the deferred tax assets and liabilities as of December 31, 2017 to reflect the reduction in the U.S. income tax rate from 35% to 21% for years after 2017 . As a result of this remeasurement, we recorded an income tax benefit of $61.1 million and a corresponding $61.1 million decrease in net deferred tax liabilities as of December 31, 2017 . We believe the accounting for the effects of H.R.1 recognized in the December 31, 2017 financial statements is materially complete. However, evolving analyses and interpretations of the law may cause a change to the amounts presented. Any such changes that may arise will be recognized in the period determined, but no later than December 31, 2018 . As a result of H.R.1, we expect our effective tax rate in future periods will be lower than in periods prior to enactment. In addition, the limitations on utilization of net operating losses and deductibility of interest and executive compensation may result in the payment of cash taxes earlier than expected. The components of net deferred taxes are as follows: December 31, (in thousands) 2017 2016 Assets: Stock compensation and other accrued amounts $ 31,044 $ 58,306 Net operating loss carryforward, net of valuation allowance 313,738 399,912 Credit carryforward 3,995 6,016 348,777 464,234 Liabilities: Property, plant and equipment (450,395 ) (408,399 ) Net deferred tax (liabilities) assets $ (101,618 ) $ 55,835 At December 31, 2017 , we had a U.S. net tax operating loss carryforward of approximately $1,377.7 million , which would expire in years 2031 through 2037 . We believe that the carryforward will be utilized before it expires. We recorded a $3.5 million increase to the net operating loss carryforward at December 31, 2017 , for certain state losses and a corresponding increase in the state net operating loss valuation allowance of $4.0 million . The net decrease in the state net operating losses after reduction for the valuation allowance was $0.5 million . The total valuation allowance on state net operating losses at December 31, 2017 was $103.7 million because it is not more likely than not that these additional state net operating losses will be utilized before they expire. There are no other valuation allowances. We also had an alternative minimum tax credit carryforward of approximately $3.0 million and enhanced oil recovery and marginal well credits of $0.9 million . At December 31, 2017 and 2016 , we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax positions. The tax years 2014 through 2016 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open to examination for tax years 2013 through 2016 . We do not anticipate the need for any significant income tax payments in the near term. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES Lease Commitments We have various commitments for office space under operating lease arrangements. During the years ended December 31, 2017 , 2016 , and 2015 , rent expense for these operating leases approximated $13.1 million , $12.9 million , and $13.2 million , respectively. Shown below are future minimum cash payments required under these leases as of December 31, 2017 . (in thousands) 2018 $ 9,742 2019 10,702 2020 10,836 2021 11,053 2022 11,222 Later years 32,645 Total future minimum lease payments $ 86,200 We have various commitments for compressor equipment under operating lease arrangements totaling $8.5 million with lease terms expiring in the next 2 - 24 months . Other Commitments At December 31, 2017 , we had estimated commitments of approximately: (i) $252.6 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $33.3 million to finish gathering system construction in progress. At December 31, 2017 , we had firm sales contracts to deliver approximately 217.6 Bcf of gas over the next 7.1 years . If we do not deliver this gas, our estimated financial commitment, calculated using the January 2018 index price, would be approximately $476.7 million . The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations. In connection with gas gathering and processing agreements, we have volume commitments over the next 8.3 years . If we do not deliver the committed gas or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of December 31, 2017 , would be approximately $298.3 million . However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations. We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of December 31, 2017 , would be approximately $11.4 million . However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations. At December 31, 2017 , we have various firm transportation agreements for pipeline capacity with end dates ranging from 2018 - 2025 under which we will have to pay an estimated $36.5 million over the remaining terms of the agreements. These agreements were entered into to support our residue marketing efforts, and we believe we have sufficient reserves that will utilize this firm transportation. All of the noted commitments were routine and made in the normal course of our business. Litigation In the normal course of business, we are involved with various litigation matters. When a loss contingency exists, we assess whether it is probable that an asset has been impaired or a liability has been incurred and, if so, we determine if the amount of loss can be reasonably estimated, all in accordance with guidance established by the FASB, and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them, we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals. H.B. Krug, et al. v. Helmerich & Payne, Inc. In 2008, we recorded litigation expense of $119.6 million for the H.B. Krug, et al. v. Helmerich & Payne, Inc. trial court verdict, and began accruing additional post-judgment interest and costs for this case. On December 31, 2013, the Oklahoma Supreme Court reversed the trial court’s $119.6 million verdict and affirmed an alternative jury verdict for $3.65 million . The Supreme Court also remanded the case back to the trial court for consideration of potential prejudgment interest, attorney’s fees, and cost awards. Accordingly, on December 31, 2013 we reduced the previously recognized litigation expense, which included related interest and costs, and the associated long-term liability by $142.8 million . On April 1, 2014, Cimarex paid the Plaintiffs $15.8 million in satisfaction of the $3.65 million damages award, the post-judgment interest award, and the payment in lieu of bond, all of which are now final and not appealable. On June 24, 2014, the trial court ruled the Plaintiffs were not entitled to prejudgment interest but were entitled to attorney’s fees and costs, the amount of which will be determined at a subsequent hearing. On November 3, 2015, the Oklahoma Supreme Court affirmed the trial court’s denial of prejudgment interest. The only remaining issue is the amount of Plaintiffs’ award of attorney’s fees, which is subject to future trial, and appellate court proceedings and, therefore, cannot be determined at this time. |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS Helmerich & Payne, Inc. (“H&P”) provides contract drilling services to Cimarex. Cimarex incurred drilling costs of approximately $52.6 million , $18.3 million , and $7.9 million related to these services during the years ended December 31, 2017 , 2016 , and 2015 , respectively. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Elements [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Years Ended December 31, (in thousands) 2017 2016 2015 Cash paid during the period for: Interest expense (net of capitalized amounts of $23,113, $20,308, and $28,819, respectively) $ 52,245 $ 59,282 $ 51,966 Income taxes $ 3 $ 13 $ 558 Cash received for income tax refunds $ 111 $ 1,450 $ 1,503 |
BASIS OF PRESENTATION AND SUM20
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of presentation | Basis of Presentation Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Our significant accounting policies are discussed below. The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in consolidation. |
Segment Information | Segment Information We have determined that our business is comprised of only one segment because our gathering, processing, and marketing activities are ancillary to our production operations. |
Use of Estimates | Use of Estimates The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Areas of significance requiring the use of management’s judgments include the estimation of proved oil and gas reserves used in calculating depletion, the estimation of future net revenues used in computing ceiling test limitations, the estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, and contingencies. We analyze our estimates and base them on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions, and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities of three months or less. Cash equivalents are stated at cost, which approximates market value. |
Oil and Gas Properties | Oil and Gas Well Equipment and Supplies Our oil and gas well equipment and supplies are valued at the lower of cost and net realizable value, where net realizable value is estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Declines in the price of oil and gas well equipment and supplies in future periods could cause us to recognize impairments on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity. Oil and Gas Properties We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the acquisition, exploration, and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. Expenditures for maintenance and repairs are charged to production expense in the period incurred. Under the full cost method of accounting, we are required to perform quarterly ceiling test calculations to test our oil and gas properties for possible impairment. If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes. We currently do not have any unproven properties that are being amortized. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures. At December 31, 2017 , the carrying value of our oil and gas properties subject to the test did not exceed the calculated value of the ceiling limitation and, therefore, we did not recognize an impairment. However, a decline of approximately 19% or more in the value of the ceiling limitation would have resulted in an impairment. For the years ended December 31, 2016 and 2015 , full year impairments totaled $757.7 million ( $481.4 million , net of tax) and $4.03 billion ( $2.56 billion , net of tax), respectively. These impairments resulted primarily from the impact of decreases in the trailing twelve-month average prices for oil, gas, and NGLs utilized in determining the future net revenues from proved reserves. The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes. If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters. The calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet. Any impairment of oil and gas properties is not reversible at a later date. Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities, commodity prices, and impairment of oil and gas properties will cause corresponding changes in depletion expense in periods subsequent to these changes. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized. Significant unproved properties are evaluated individually. Unproved properties that are not considered individually significant are aggregated for evaluation purposes and related costs are transferred to the costs to be amortized quarterly based on the application of historical factors. |
Fixed assets | Fixed Assets Fixed assets consist primarily of gathering and plant facilities, vehicles, airplanes, office furniture, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from 3 to 30 years . |
Goodwill | Goodwill Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. In performing the goodwill test, we compare the fair value of our reporting unit with its carrying amount. If the carrying amount of the reporting unit were to exceed its fair value, an impairment charge would be recognized in the amount of this excess, limited to the total amount of goodwill allocated to that reporting unit. We evaluate our goodwill for impairment in the fourth quarter of each year and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. We have historically tested goodwill for impairment as of December 31 each year; however, in 2017 we elected to change the date of our annual goodwill impairment test to October 31. We do not believe a change in the goodwill impairment testing date represents a material change to a method of applying an accounting principle because the change in impairment testing date does not have a material effect on our financial statements in light of the internal controls and requirements to assess goodwill impairment upon certain triggering events. Based upon our assessment as of October 31, 2017, goodwill was not impaired. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors become unfavorable. |
Revenue Recognition | Revenue Recognition Oil, Gas, and NGL Sales Revenue is recognized from the sales of oil, gas, and NGLs when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured. There is a ready market for our products and sales occur soon after production. Gas Gathering When we transport and/or process third-party gas associated with our equity gas, we recognize revenue for the fees charged to third-parties for such services. Gas Marketing When we market and sell gas for working interest owners we act as agent under short-term sales and supply agreements and earn a fee for such services. Revenues from such services are recognized as gas is delivered. Gas Imbalances We use the sales method of accounting for gas imbalances. Revenue from the sale of gas is recorded on the basis of gas actually sold by us. If our aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented. |
General and Administrative Expenses | General and Administrative Expenses General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting. |
Derivatives | Derivatives Our derivative contracts are recorded on the balance sheet at fair value. Our firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment. See Note 4 for additional information regarding our derivative instruments. |
Income Taxes | Income Taxes We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. We classify all deferred tax assets and liabilities as non-current. We routinely assess the realizability of our deferred tax assets. We routinely assess the realizability of our deferred tax assets. Numerous judgments and assumptions are inherent in this assessment, including the determination of future taxable income, which is affected by factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. If we conclude that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. We regularly assess and, if required, establish accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions where the company operates. See Note 9 for additional information regarding our income taxes, including the impact of H.R.1, commonly referred to as the Tax Cuts and Jobs Act, which the U.S. enacted on December 22, 2017. |
Contingencies | Contingencies A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and determine when we should record losses for these items based on information available to us. See Note 10 for additional information regarding our contingencies. |
Asset Retirement Obligations | Asset Retirement Obligations We recognize the present value of the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This liability includes costs related to the abandonment of wells, the removal of facilities and equipment, and site restorations. In periods subsequent to the initial measurement of an asset retirement obligation at present value, a period-to-period increase in the carrying amount of the liability is recognized as accretion expense, which represents the effect of the passage of time on the amount of the liability. An equivalent amount is added to the carrying amount of the liability. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are included as a component of the DD&A calculations. The current portion of our asset retirement obligations is recorded in “Accrued liabilities — Other” in the accompanying consolidated balance sheets and cash payments for settlements of retirement obligations are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note 8 for additional information regarding our asset retirement obligations. |
Stock-based Compensation | Stock-based Compensation We recognize compensation cost related to all stock-based awards in the financial statements based on their estimated grant date fair value. We grant various types of stock-based awards including stock options, restricted stock (including awards with service-based vesting and market condition-based vesting provisions), and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant date market value of the award utilizing a statistical analysis. Compensation cost is recognized ratably over the applicable vesting period. To the extent compensation cost relates to employees directly involved in oil and gas acquisition, exploration, and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized as stock compensation expense. See Note 6 for additional information regarding our stock-based compensation. |
Earnings (loss) per Share | Earnings (Loss) per Share We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and, therefore, should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Our unvested share-based payment awards, consisting of restricted stock and units, qualify as participating securities. See Note 7 for additional information regarding our earnings per share. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) , which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition , and most industry-specific guidance throughout the Industry Topics of the Codification. Entities can choose to adopt the standard using either the full retrospective approach or a modified retrospective approach. We will adopt the standard effective January 1, 2018, utilizing the modified retrospective approach, which will be applied to contracts that were not completed as of January 1, 2018. The new standard will not have an impact on net income (loss) or cash flows from operations; however, certain costs previously classified as Transportation, processing, and other operating expenses in the statement of operations will be reflected as deductions from revenue under the new standard. Had Topic 606 been in effect for the fourth quarter of 2017, Revenue and Transportation, processing and other operating expenses for the quarter would have each been reduced by an estimated range of $15.0 million to $16.0 million . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) . The key provision of this ASU is that a lessee must recognize (i) liabilities to make lease payments and (ii) right-of-use assets on its balance sheet. The ASU permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than twelve months. Under current GAAP, a determination of whether a lease is a capital or operating lease is made at lease inception and no assets or liabilities are recognized for operating leases. Under this ASU, the determination to be made at the inception of a contract is whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. An entity may make a policy election to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and comprehensive income and cash flows, however, both types of leases require the recognition of assets and liabilities on the balance sheet. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are in the process of evaluating the potential impact of adopting this guidance, but believe the primary effect will be to record assets and liabilities for contracts currently accounted for as operating leases. We do not intend to adopt the standard early. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842 . This ASU provides an optional transition practical expedient to not evaluate under Topic 842 (discussed above) existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. Under the full cost method of accounting, we capitalize to oil and gas properties all property acquisition, exploration, and development costs, which include the costs of land easements. We plan to elect this practical expedient and continue to apply our current accounting policy to account for land easements that existed before our adoption of Topic 842 and will evaluate new or modified land easements under Topic 842 upon our adoption of Topic 842. We are in the process of evaluating the potential impact of adopting this guidance, and do not intend to adopt the standard early. |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Long-term Debt, Unclassified [Abstract] | |
Schedule of Long-Term Debt | Long-term debt at December 31, 2017 and 2016 consisted of the following: December 31, 2017 December 31, 2016 (in thousands) Principal Unamortized Debt Issuance Costs and Discount (1) Long-term Debt, net Principal Unamortized Debt Issuance Costs Long-term Debt, net 5.875% Senior Notes $ — $ — $ — $ 750,000 $ (5,691 ) $ 744,309 4.375% Senior Notes 750,000 (5,383 ) 744,617 750,000 (6,370 ) 743,630 3.90% Senior Notes 750,000 (7,697 ) 742,303 — — — Total long-term debt $ 1,500,000 $ (13,080 ) $ 1,486,920 $ 1,500,000 $ (12,061 ) $ 1,487,939 ________________________________________ (1) At December 31, 2017 , the unamortized debt issuance costs and discount related to the 3.90% notes were $5.9 million and $1.8 million , respectively. The 4.375% notes were issued at par. |
DERIVATIVE INSTRUMENTS (Tables)
DERIVATIVE INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedges, Assets [Abstract] | |
Schedule of Outstanding Hedging Contracts | The following tables summarize our outstanding derivative contracts as of December 31, 2017 : Oil Collars: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: WTI (1) Volume (Bbls) 2,610,000 2,093,000 1,748,000 1,196,000 7,647,000 Weighted Avg Price - Floor $ 47.28 $ 47.26 $ 46.68 $ 48.00 $ 47.25 Weighted Avg Price - Ceiling $ 56.33 $ 55.61 $ 54.90 $ 55.10 $ 55.62 2019: WTI (1) Volume (Bbls) 630,000 637,000 — — 1,267,000 Weighted Avg Price - Floor $ 48.00 $ 48.00 $ — $ — $ 48.00 Weighted Avg Price - Ceiling $ 56.09 $ 56.09 $ — $ — $ 56.09 ________________________________________ (1) The index price for these collars is West Texas Intermediate (“WTI”) as quoted on the New York Mercantile Exchange (“NYMEX”). Gas Collars: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: PEPL (1) Volume (MMBtu) 11,700,000 9,100,000 6,440,000 3,680,000 30,920,000 Weighted Avg Price - Floor $ 2.57 $ 2.47 $ 2.43 $ 2.43 $ 2.49 Weighted Avg Price - Ceiling $ 2.93 $ 2.81 $ 2.67 $ 2.66 $ 2.81 Perm EP (2) Volume (MMBtu) 8,100,000 6,370,000 4,600,000 2,760,000 21,830,000 Weighted Avg Price - Floor $ 2.52 $ 2.39 $ 2.34 $ 2.33 $ 2.42 Weighted Avg Price - Ceiling $ 2.84 $ 2.67 $ 2.53 $ 2.52 $ 2.68 2019: PEPL (1) Volume (MMBtu) 2,700,000 2,730,000 — — 5,430,000 Weighted Avg Price - Floor $ 2.40 $ 2.40 $ — $ — $ 2.40 Weighted Avg Price - Ceiling $ 2.67 $ 2.67 $ — $ — $ 2.67 Perm EP (2) Volume (MMBtu) 1,800,000 1,820,000 — — 3,620,000 Weighted Avg Price - Floor $ 2.30 $ 2.30 $ — $ — $ 2.30 Weighted Avg Price - Ceiling $ 2.49 $ 2.49 $ — $ — $ 2.49 ________________________________________ (1) The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC. (2) The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC. Oil Basis Swaps: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: WTI Midland (1) Volume (Bbls) 1,170,000 1,183,000 1,196,000 736,000 4,285,000 Weighted Avg Differential (2) $ (0.72 ) $ (0.72 ) $ (0.72 ) $ (0.58 ) $ (0.69 ) 2019: WTI Midland (1) Volume (Bbls) 450,000 455,000 — — 905,000 Weighted Avg Differential (2) $ (0.47 ) $ (0.47 ) $ — $ — $ (0.47 ) ________________________________________ (1) The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude. (2) The index price we receive under these basis swaps is WTI as quoted on the NYMEX less the weighted average differential shown in the table. The following tables summarize our derivative contracts entered into subsequent to December 31, 2017 through February 22, 2018: Oil Collars: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: WTI (1) Volume (Bbls) — 546,000 552,000 552,000 1,650,000 Weighted Avg Price - Floor $ — $ 50.00 $ 50.00 $ 50.00 $ 50.00 Weighted Avg Price - Ceiling $ — $ 66.82 $ 66.82 $ 66.82 $ 66.82 2019: WTI (1) Volume (Bbls) 540,000 546,000 552,000 — 1,638,000 Weighted Avg Price - Floor $ 50.00 $ 50.00 $ 50.00 $ — $ 50.00 Weighted Avg Price - Ceiling $ 66.82 $ 66.82 $ 66.82 $ — $ 66.82 ________________________________________ (1) The index price for these collars is WTI as quoted on the NYMEX. Gas Collars: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: PEPL (1) Volume (MMBtu) — 1,820,000 1,840,000 1,840,000 5,500,000 Weighted Avg Price - Floor $ — $ 1.98 $ 1.98 $ 1.98 $ 1.98 Weighted Avg Price - Ceiling $ — $ 2.16 $ 2.16 $ 2.16 $ 2.16 Perm EP (2) Volume (MMBtu) — 1,820,000 1,840,000 1,840,000 5,500,000 Weighted Avg Price - Floor $ — $ 1.65 $ 1.65 $ 1.65 $ 1.65 Weighted Avg Price - Ceiling $ — $ 1.80 $ 1.80 $ 1.80 $ 1.80 2019: PEPL (1) Volume (MMBtu) 1,800,000 1,820,000 1,840,000 — 5,460,000 Weighted Avg Price - Floor $ 1.98 $ 1.98 $ 1.98 $ — $ 1.98 Weighted Avg Price - Ceiling $ 2.16 $ 2.16 $ 2.16 $ — $ 2.16 Perm EP (2) Volume (MMBtu) 1,800,000 1,820,000 1,840,000 — 5,460,000 Weighted Avg Price - Floor $ 1.65 $ 1.65 $ 1.65 $ — $ 1.65 Weighted Avg Price - Ceiling $ 1.80 $ 1.80 $ 1.80 $ — $ 1.80 ________________________________________ (1) The index price for these collars is PEPL as quoted in Platt’s Inside FERC. (2) The index price for these collars is Perm EP as quoted in Platt’s Inside FERC. Oil Basis Swaps: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: WTI Midland (1) Volume (Bbls) — 91,000 92,000 92,000 275,000 Weighted Avg Differential (2) $ — $ (0.70 ) $ (0.70 ) $ (0.70 ) $ (0.70 ) 2019: WTI Midland (1) Volume (Bbls) 90,000 91,000 92,000 — 273,000 Weighted Avg Differential (2) $ (0.70 ) $ (0.70 ) $ (0.70 ) $ — $ (0.70 ) ________________________________________ (1) The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude. (2) The index price we receive under these basis swaps is WTI as quoted on the NYMEX less the weighted average differential shown in the table. |
Schedule of Net (Gains) and Losses from Settlements and Changes of Derivative Contracts | The following table presents the components of (Gain) loss on derivative instruments, net for the periods indicated. Years Ended December 31, (in thousands) 2017 2016 2015 Change in fair value of derivative instruments, net: Gas contracts $ (40,226 ) $ 27,462 $ (4,472 ) Oil contracts 17,383 35,724 (6,774 ) (22,843 ) 63,186 (11,246 ) Cash (receipts) payments on derivative instruments, net: Gas contracts (4,557 ) (6,467 ) — Oil contracts 6,190 (970 ) — 1,633 (7,437 ) — (Gain) loss on derivative instruments, net $ (21,210 ) $ 55,749 $ (11,246 ) |
Schedule of Amounts and Classifications of Entity's Derivative Assets and Liabilities as well as the Potential Effect of Netting Arrangements on Contracts with the Same Counterparty | The following tables present the amounts and classifications of our derivative assets and liabilities as of December 31, 2017 and 2016 , as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts. December 31, 2017 (in thousands) Balance Sheet Location Asset Liability Gas contracts Current assets — Derivative instruments $ 15,151 $ — Gas contracts Non-current assets — Derivative instruments 2,086 — Oil contracts Current liabilities — Derivative instruments — 42,066 Oil contracts Non-current liabilities — Derivative instruments — 4,268 Total gross amounts presented in the balance sheet 17,237 46,334 Less: gross amounts not offset in the balance sheet (17,237 ) (17,237 ) Net amount $ — $ 29,097 December 31, 2016 (in thousands) Balance Sheet Location Asset Liability Oil contracts Current liabilities — Derivative instruments $ — $ 27,892 Gas contracts Current liabilities — Derivative instruments — 21,478 Oil contracts Non-current liabilities — Derivative instruments — 1,059 Gas contracts Non-current liabilities — Derivative instruments — 1,511 Total gross amounts presented in the balance sheet — 51,940 Less: gross amounts not offset in the balance sheet — — Net amount $ — $ 51,940 |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value Measurement Information for Certain Assets and Liabilities | The following table provides fair value measurement information for certain assets and liabilities as of December 31, 2017 and 2016 . December 31, 2017 December 31, 2016 (in thousands) Book Value Fair Value Book Value Fair Value Financial Assets (Liabilities): 5.875% Notes due 2022 $ — $ — $ (750,000 ) $ (782,835 ) 4.375% Notes due 2024 $ (750,000 ) $ (797,010 ) $ (750,000 ) $ (779,453 ) 3.90% Notes due 2027 $ (750,000 ) $ (767,813 ) $ — $ — Derivative instruments — assets $ 17,237 $ 17,237 $ — $ — Derivative instruments — liabilities $ (46,334 ) $ (46,334 ) $ (51,940 ) $ (51,940 ) |
STOCK-BASED AND OTHER COMPENS24
STOCK-BASED AND OTHER COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Options, Restricted Stock and Unit Awards | |
Schedule of Recognition of Non-Cash Stock-Based Compensation Cost | We have recognized non-cash stock-based compensation cost as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts. Years Ended December 31, (in thousands) 2017 2016 2015 Restricted stock awards: Performance stock awards $ 26,020 $ 24,183 $ 18,991 Service-based stock awards 19,746 18,391 14,547 45,766 42,574 33,538 Stock option awards 2,599 2,565 2,803 Total stock compensation cost 48,365 45,139 36,341 Less amounts capitalized to oil and gas properties (22,109 ) (20,616 ) (16,782 ) Stock compensation expense $ 26,256 $ 24,523 $ 19,559 |
Restricted Stock | |
Options, Restricted Stock and Unit Awards | |
Schedule of Restricted Stock Rollforward | The following table provides information on restricted stock activity during the year. Service-based Performance (subject to market conditions) Number of Shares Weighted Average Grant Date Fair Value Number of Shares Weighted Average Grant Date Fair Value Outstanding as of January 1, 2017 934,723 $ 96.57 809,270 $ 96.41 Vested (234,468 ) $ 63.49 (275,416 ) $ 84.50 Granted 251,312 $ 94.04 300,525 $ 89.46 Forfeited (41,316 ) $ 105.83 — $ — Outstanding as of December 31, 2017 910,251 $ 103.98 834,379 $ 97.83 |
Restricted Stock and Units | |
Options, Restricted Stock and Unit Awards | |
Schedule of Restricted Stock Awards Granted | The following table provides information about restricted stock awards granted during the last three years. Years Ended December 31, 2017 2016 2015 Number of Shares Weighted Average Grant Date Fair Value Number of Shares Weighted Average Grant Date Fair Value Number of Shares Weighted Average Grant Date Fair Value Performance stock awards 300,525 $ 89.46 269,915 $ 117.63 263,939 $ 87.12 Service-based stock awards 251,312 $ 94.04 208,724 $ 114.61 207,180 $ 114.80 Total restricted stock awards 551,837 $ 91.55 478,639 $ 116.31 471,119 $ 99.29 |
Employee Stock Option | |
Options, Restricted Stock and Unit Awards | |
Schedule of Options Granted, Weighted-Average Grant-Date Fair Value, Total Fair Value of the Options and Assumptions used to Determine Fair Market Value of those Options | The following summarizes information regarding options granted, including the assumptions used to determine the fair value of those options. Years Ended December 31, 2017 2016 2015 Options granted 96,100 89,850 69,000 Weighted average grant date fair value $ 28.37 $ 33.38 $ 37.56 Weighted average exercise price $ 92.37 $ 114.07 $ 115.28 Total fair value (in thousands) $ 2,727 $ 2,999 $ 2,592 Expected years until exercise 4.5 4.0 5.0 Expected stock volatility 35.0 % 36.7 % 36.6 % Dividend yield 0.3 % 0.3 % 0.6 % Risk-free interest rate 1.7 % 1.0 % 1.6 % |
Schedule of Outstanding Stock Options Rollforward | Information about outstanding stock options is summarized below. Number of Options Weighted Average Exercise Price Weighted Average Remaining Term Aggregate Intrinsic Value (in thousands) Outstanding as of January 1, 2017 307,810 $ 101.72 Exercised (5,768 ) $ 68.33 Granted 96,100 $ 92.37 Canceled (1,665 ) $ 139.02 Forfeited (13,789 ) $ 88.92 Outstanding as of December 31, 2017 382,688 $ 100.17 4.4 years $ 9,553 Exercisable as of December 31, 2017 209,782 $ 98.55 3.2 years $ 6,020 |
Schedule of Information regarding Options Exercised and Grant-Date Fair Value of Options Vested | The following table provides information regarding options exercised and the grant date fair value of options vested. Years Ended December 31, (in thousands) 2017 2016 2015 Cash received from option exercises $ 394 $ 4,804 $ 8,451 Tax benefit from option exercises included in paid-in-capital $ — $ — $ 4,442 Intrinsic value of options exercised $ 257 $ 2,994 $ 7,467 Grant date fair value of options vested $ 2,227 $ 2,486 $ 2,734 |
Schedule of Non-Vested Stock Options Rollforward | The following summary reflects the status of non-vested stock options as of December 31, 2017 and changes during the year. Number of Options Weighted Average Grant Date Fair Value Weighted Average Exercise Price Non-vested as of January 1, 2017 148,361 $ 35.58 $ 117.55 Vested (57,766 ) $ 38.55 $ 128.59 Granted 96,100 $ 28.37 $ 92.37 Forfeited (13,789 ) $ 29.41 $ 88.92 Non-vested as of December 31, 2017 172,906 $ 31.08 $ 102.15 |
EARNINGS (LOSS) PER SHARE (Tabl
EARNINGS (LOSS) PER SHARE (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Schedule of Calculations of Basic and Diluted Net Earnings (Loss) per Common Share | The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below. Years Ended December 31, (in thousands, except per share data) 2017 2016 2015 Basic: Net income (loss) $ 494,329 $ (408,803 ) $ (2,579,604 ) Participating securities’ share in earnings (1) (8,551 ) — — Net income (loss) available to common stockholders $ 485,778 $ (408,803 ) $ (2,579,604 ) Diluted: Net income (loss) $ 494,329 $ (408,803 ) $ (2,579,604 ) Participating securities’ share in earnings (1) (8,548 ) — — Net income (loss) available to common stockholders $ 485,781 $ (408,803 ) $ (2,579,604 ) Shares: Basic shares outstanding 93,466 93,379 92,992 Dilutive effect of stock options (2) 43 — — Fully diluted common stock 93,509 93,379 92,992 Earnings (loss) per share to common stockholders (3): Basic $ 5.19 $ (4.38 ) $ (27.75 ) Diluted $ 5.19 $ (4.38 ) $ (27.75 ) ________________________________________ (1) Participating securities are not included in undistributed earnings when a loss exists. (2) Inclusion of certain shares would have an anti-dilutive effect; therefore, 302.9 thousand , 2.1 million , and 2.1 million shares were excluded from the calculations for the years ended December 31, 2017 , 2016 , and 2015 , respectively. (3) Earnings (loss) per share are based on actual figures rather than the rounded figures presented. |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | |
Schedule of Change in the Carrying Amount of the Asset Retirement Obligation | The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2017 and 2016 . (in thousands) 2017 2016 Asset retirement obligation at January 1, $ 154,523 $ 164,105 Liabilities incurred 17,996 3,914 Liability settlements and disposals (12,947 ) (24,108 ) Accretion expense 7,534 7,595 Revisions of estimated liabilities 2,363 3,017 Asset retirement obligation at December 31, 169,469 154,523 Less current obligation 11,048 13,753 Long-term asset retirement obligation $ 158,421 $ 140,770 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of the Provision for Income Taxes | The components of the provision for income taxes are as follows: Years Ended December 31, (in thousands) 2017 2016 2015 Current taxes: Federal (benefit) expense $ (2,810 ) $ — $ 14,417 State (benefit) expense (2 ) (1,115 ) 293 (2,812 ) (1,115 ) 14,710 Deferred taxes: Federal expense (benefit) 173,859 (201,529 ) (1,386,086 ) State expense (benefit) 16,620 (11,757 ) (100,353 ) 190,479 (213,286 ) (1,486,439 ) $ 187,667 $ (214,401 ) $ (1,471,729 ) |
Schedule of Reconciliations of Income Tax (Benefit) Expense Calculated at Federal Statutory Rate of 35% to the Total Income Tax (Benefit) Expense | Reconciliations of the income tax expense (benefit) calculated at the federal statutory rate of 35% to the total income tax expense (benefit) are as follows: Years Ended December 31, (in thousands) 2017 2016 2015 Provision at statutory rate $ 238,699 $ (218,122 ) $ (1,417,967 ) Effect of state taxes 10,074 (10,237 ) (64,794 ) Revision of previous balances — 7,181 5,997 Tax credits and other permanent differences 5,442 5,296 5,035 Change in valuation allowance, net 486 1,481 — Stock-based compensation (5,888 ) — — Impact of reduction in federal statutory rate (61,146 ) — — Income tax expense (benefit) $ 187,667 $ (214,401 ) $ (1,471,729 ) |
Schedule of Components of Net Deferred Tax Liabilities | The components of net deferred taxes are as follows: December 31, (in thousands) 2017 2016 Assets: Stock compensation and other accrued amounts $ 31,044 $ 58,306 Net operating loss carryforward, net of valuation allowance 313,738 399,912 Credit carryforward 3,995 6,016 348,777 464,234 Liabilities: Property, plant and equipment (450,395 ) (408,399 ) Net deferred tax (liabilities) assets $ (101,618 ) $ 55,835 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Future Minimum Payments Required under Leases | Shown below are future minimum cash payments required under these leases as of December 31, 2017 . (in thousands) 2018 $ 9,742 2019 10,702 2020 10,836 2021 11,053 2022 11,222 Later years 32,645 Total future minimum lease payments $ 86,200 |
SUPPLEMENTAL CASH FLOW INFORM29
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Elements [Abstract] | |
Schedule of Supplemental Cash Flow Information | Years Ended December 31, (in thousands) 2017 2016 2015 Cash paid during the period for: Interest expense (net of capitalized amounts of $23,113, $20,308, and $28,819, respectively) $ 52,245 $ 59,282 $ 51,966 Income taxes $ 3 $ 13 $ 558 Cash received for income tax refunds $ 111 $ 1,450 $ 1,503 |
BASIS OF PRESENTATION AND SUM30
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2017USD ($) | Dec. 31, 2017USD ($)segments | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Basis of Presentation and Summary of Significant Accounting Policies [Line Items] | ||||
Number of reportable segments | segments | 1 | |||
Oil and Gas Properties | ||||
Discount rate for calculating present value of estimated future net revenues from proved reserves (as a percent) | 10.00% | |||
Ceiling limitation used in ceiling test sensitivity analysis | 19.00% | |||
Impairment of oil and gas properties | $ 0 | $ 757,670 | $ 4,033,295 | |
Impairment of oil and gas properties, after tax | $ 481,400 | $ 2,560,000 | ||
Maximum | ||||
Fixed assets, net | ||||
Fixed assets expected lives | 30 years | |||
Minimum | ||||
Fixed assets, net | ||||
Fixed assets expected lives | 3 years | |||
Difference between Revenue Guidance in Effect before and after Topic 606 | Maximum | Accounting Standards Update 2014-09 | ||||
Fixed assets, net | ||||
Effect on revenue | $ (16,000) | |||
Effect on expenses | (16,000) | |||
Difference between Revenue Guidance in Effect before and after Topic 606 | Minimum | Accounting Standards Update 2014-09 | ||||
Fixed assets, net | ||||
Effect on revenue | (15,000) | |||
Effect on expenses | $ (15,000) |
CAPITAL STOCK (Details)
CAPITAL STOCK (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||||
May 31, 2015 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Capital Stock [Line Items] | ||||||||||||||||
Common stock, shares authorized | 200,000,000 | 200,000,000 | 200,000,000 | 200,000,000 | ||||||||||||
Preferred stock, shares authorized | 15,000,000 | 15,000,000 | 15,000,000 | 15,000,000 | ||||||||||||
Preferred stock outstanding (shares) | 0 | 0 | ||||||||||||||
Issuance of common stock (shares) | 6,900,000 | |||||||||||||||
Price per share sold (USD per share) | $ 109 | |||||||||||||||
Par value (USD per share) | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | |||||||||||
Proceeds from sale of common stock, net of underwriting fees | $ 729.5 | |||||||||||||||
Dividends | ||||||||||||||||
Cash dividend declared (USD per share) | $ 0.08 | $ 0.08 | $ 0.08 | $ 0.08 | $ 0.08 | $ 0.08 | $ 0.08 | $ 0.08 | $ 0.16 | $ 0.16 | $ 0.16 | $ 0.16 | $ 0.32 | $ 0.32 | $ 0.64 | |
Common Stock | ||||||||||||||||
Capital Stock [Line Items] | ||||||||||||||||
Common stock outstanding (shares) | 95,400,000 | 95,400,000 | ||||||||||||||
Issuance of common stock (shares) | 6,900,000 | |||||||||||||||
Additional Shares Issued | ||||||||||||||||
Capital Stock [Line Items] | ||||||||||||||||
Issuance of common stock (shares) | 900,000 |
LONG-TERM DEBT - Summary (Detai
LONG-TERM DEBT - Summary (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Apr. 10, 2017 | Dec. 31, 2016 | Jun. 30, 2014 |
Debt Instrument | ||||
Principal | $ 1,500,000 | $ 1,500,000 | ||
Unamortized Debt Issuance Costs and Discount | (13,080) | (12,061) | ||
Long-term Debt, net | 1,486,920 | 1,487,939 | ||
5.875% Senior Notes | ||||
Debt Instrument | ||||
Principal | 0 | $ 253,500 | 750,000 | |
Unamortized Debt Issuance Costs and Discount | 0 | (5,691) | ||
Long-term Debt, net | $ 0 | 744,309 | ||
Interest rate (as a percent) | 5.875% | 5.875% | ||
4.375% Senior Notes | ||||
Debt Instrument | ||||
Principal | $ 750,000 | 750,000 | ||
Unamortized Debt Issuance Costs and Discount | (5,383) | (6,370) | ||
Long-term Debt, net | $ 744,617 | 743,630 | $ 750,000 | |
Interest rate (as a percent) | 4.375% | 4.375% | ||
3.90% Senior Notes | ||||
Debt Instrument | ||||
Principal | $ 750,000 | $ 750,000 | 0 | |
Unamortized Debt Issuance Costs and Discount | (7,697) | 0 | ||
Long-term Debt, net | $ 742,303 | $ 0 | ||
Interest rate (as a percent) | 3.90% | 3.90% | ||
Unamortized debt issuance costs | $ 5,900 | |||
Unamortized discount | $ 1,800 |
LONG-TERM DEBT - Narrative (Det
LONG-TERM DEBT - Narrative (Details) - USD ($) | May 12, 2017 | Apr. 10, 2017 | Jun. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Jun. 30, 2014 |
Debt Instrument | |||||||
Gross long-term debt | $ 1,500,000,000 | $ 1,500,000,000 | |||||
Gain (loss) on extinguishment of debt | (28,187,000) | 0 | $ 0 | ||||
Net long-term debt | 1,486,920,000 | 1,487,939,000 | |||||
Revolving Credit Facility | |||||||
Debt Instrument | |||||||
Credit facility amount | 1,000,000,000 | ||||||
Credit facility, increase amount option | 1,250,000,000 | ||||||
Unamortized debt issuance costs | $ 3,400,000 | 4,500,000 | |||||
Revolving Credit Facility | Minimum | |||||||
Debt Instrument | |||||||
Commitment fee percentage | 0.125% | ||||||
Revolving Credit Facility | Maximum | |||||||
Debt Instrument | |||||||
Commitment fee percentage | 0.35% | ||||||
Debt-to-capital ratio | 65.00% | ||||||
Line of Credit | |||||||
Debt Instrument | |||||||
Letters of credit outstanding under the credit facility | $ 2,500,000 | ||||||
Unused borrowing availability | $ 997,500,000 | ||||||
5.875% Senior Notes | |||||||
Debt Instrument | |||||||
Interest rate (as a percent) | 5.875% | 5.875% | |||||
Tender price per principal amount | $ 1,031.67 | ||||||
Denominator of tender price per principal amount | 1,000 | ||||||
Gross long-term debt | 253,500,000 | $ 0 | 750,000,000 | ||||
Settled tendered notes | $ 268,100,000 | ||||||
Redemption price per principal amount | $ 1,029.38 | ||||||
Denominator of redemption price per principal amount | 1,000 | ||||||
Repayments of debt | $ 512,000,000 | ||||||
Gain (loss) on extinguishment of debt | $ (28,200,000) | ||||||
Redemption premium of debt instrument | 22,600,000 | ||||||
Write-off of deferred debt issuance cost | $ 5,300,000 | ||||||
Net long-term debt | 0 | 744,309,000 | |||||
3.90% Senior Notes | |||||||
Debt Instrument | |||||||
Unamortized debt issuance costs | $ 5,900,000 | ||||||
Interest rate (as a percent) | 3.90% | 3.90% | |||||
Gross long-term debt | $ 750,000,000 | $ 750,000,000 | 0 | ||||
Issuance price as percentage of par value (as a percent) | 99.748% | ||||||
Effective rate | 3.93% | 4.01% | |||||
Proceeds from issuance of unsecured debt | $ 741,800,000 | ||||||
Net long-term debt | $ 742,303,000 | 0 | |||||
4.375% Senior Notes | |||||||
Debt Instrument | |||||||
Interest rate (as a percent) | 4.375% | 4.375% | |||||
Gross long-term debt | $ 750,000,000 | 750,000,000 | |||||
Effective rate | 4.50% | ||||||
Net long-term debt | $ 744,617,000 | $ 743,630,000 | $ 750,000,000 | ||||
London Interbank Offered Rate (LIBOR) | Revolving Credit Facility | Minimum | |||||||
Debt Instrument | |||||||
Interest rate margin (as a percent) | 1.125% | ||||||
London Interbank Offered Rate (LIBOR) | Revolving Credit Facility | Maximum | |||||||
Debt Instrument | |||||||
Interest rate margin (as a percent) | 2.00% | ||||||
Base Rate | Revolving Credit Facility | Minimum | |||||||
Debt Instrument | |||||||
Interest rate margin (as a percent) | 0.125% | ||||||
Base Rate | Revolving Credit Facility | Maximum | |||||||
Debt Instrument | |||||||
Interest rate margin (as a percent) | 1.00% |
DERIVATIVE INSTRUMENTS - Deriva
DERIVATIVE INSTRUMENTS - Derivative Contracts (Details) bbl / qtr in Thousands, MMBTU / D in Thousands | Dec. 31, 2017bblbbl / qtrMMBTU / D$ / bbl$ / MMBTU |
Derivative Contract Oil Collar W T I Index | 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 7,647 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 47.25 |
Ceiling, weighted average price (USD per unit) | 55.62 |
Derivative Contract Oil Collar W T I Index | First Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 2,610 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 47.28 |
Ceiling, weighted average price (USD per unit) | 56.33 |
Derivative Contract Oil Collar W T I Index | Second Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 2,093 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 47.26 |
Ceiling, weighted average price (USD per unit) | 55.61 |
Derivative Contract Oil Collar W T I Index | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 1,748 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 46.68 |
Ceiling, weighted average price (USD per unit) | 54.90 |
Derivative Contract Oil Collar W T I Index | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 1,196 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 48 |
Ceiling, weighted average price (USD per unit) | 55.10 |
Derivative Contract Oil Collar W T I Index | 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 1,267 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 48 |
Ceiling, weighted average price (USD per unit) | 56.09 |
Derivative Contract Oil Collar W T I Index | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 630 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 48 |
Ceiling, weighted average price (USD per unit) | 56.09 |
Derivative Contract Oil Collar W T I Index | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 637 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 48 |
Ceiling, weighted average price (USD per unit) | 56.09 |
Derivative Contract Gas Collar PEPL Index | 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 30,920 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.49 |
Ceiling, weighted average price (USD per unit) | 2.81 |
Derivative Contract Gas Collar PEPL Index | First Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 11,700 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.57 |
Ceiling, weighted average price (USD per unit) | 2.93 |
Derivative Contract Gas Collar PEPL Index | Second Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 9,100 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.47 |
Ceiling, weighted average price (USD per unit) | 2.81 |
Derivative Contract Gas Collar PEPL Index | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 6,440 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.43 |
Ceiling, weighted average price (USD per unit) | 2.67 |
Derivative Contract Gas Collar PEPL Index | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 3,680 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.43 |
Ceiling, weighted average price (USD per unit) | 2.66 |
Derivative Contract Gas Collar PEPL Index | 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 5,430 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.40 |
Ceiling, weighted average price (USD per unit) | 2.67 |
Derivative Contract Gas Collar PEPL Index | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 2,700 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.40 |
Ceiling, weighted average price (USD per unit) | 2.67 |
Derivative Contract Gas Collar PEPL Index | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 2,730 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.40 |
Ceiling, weighted average price (USD per unit) | 2.67 |
Derivative Contract Gas Collar Perm EP | 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 21,830 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.42 |
Ceiling, weighted average price (USD per unit) | 2.68 |
Derivative Contract Gas Collar Perm EP | First Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 8,100 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.52 |
Ceiling, weighted average price (USD per unit) | 2.84 |
Derivative Contract Gas Collar Perm EP | Second Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 6,370 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.39 |
Ceiling, weighted average price (USD per unit) | 2.67 |
Derivative Contract Gas Collar Perm EP | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 4,600 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.34 |
Ceiling, weighted average price (USD per unit) | 2.53 |
Derivative Contract Gas Collar Perm EP | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 2,760 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.33 |
Ceiling, weighted average price (USD per unit) | 2.52 |
Derivative Contract Gas Collar Perm EP | 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 3,620 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.30 |
Ceiling, weighted average price (USD per unit) | 2.49 |
Derivative Contract Gas Collar Perm EP | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,800 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.30 |
Ceiling, weighted average price (USD per unit) | 2.49 |
Derivative Contract Gas Collar Perm EP | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,820 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 2.30 |
Ceiling, weighted average price (USD per unit) | 2.49 |
WTI Midland Oil Basis Swaps | 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl | 4,285,000 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.69) |
WTI Midland Oil Basis Swaps | First Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl | 1,170,000 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.72) |
WTI Midland Oil Basis Swaps | Second Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl | 1,183,000 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.72) |
WTI Midland Oil Basis Swaps | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl | 1,196,000 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.72) |
WTI Midland Oil Basis Swaps | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl | 736,000 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.58) |
WTI Midland Oil Basis Swaps | 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl | 905,000 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.47) |
WTI Midland Oil Basis Swaps | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl | 450,000 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.47) |
WTI Midland Oil Basis Swaps | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl | 455,000 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.47) |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Collar W T I Index | 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 1,650 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | $ / bbl | 50 |
Ceiling, weighted average price (USD per unit) | $ / bbl | 66.82 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Collar W T I Index | Second Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 546 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | $ / bbl | 50 |
Ceiling, weighted average price (USD per unit) | $ / bbl | 66.82 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Collar W T I Index | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 552 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | $ / bbl | 50 |
Ceiling, weighted average price (USD per unit) | $ / bbl | 66.82 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Collar W T I Index | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 552 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | $ / bbl | 50 |
Ceiling, weighted average price (USD per unit) | $ / bbl | 66.82 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Collar W T I Index | 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 1,638 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | $ / bbl | 50 |
Ceiling, weighted average price (USD per unit) | $ / bbl | 66.82 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Collar W T I Index | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 540 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | $ / bbl | 50 |
Ceiling, weighted average price (USD per unit) | $ / bbl | 66.82 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Collar W T I Index | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 546 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | $ / bbl | 50 |
Ceiling, weighted average price (USD per unit) | $ / bbl | 66.82 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Collar W T I Index | Third Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 552 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | $ / bbl | 50 |
Ceiling, weighted average price (USD per unit) | $ / bbl | 66.82 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar PEPL Index | 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 5,500 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.98 |
Ceiling, weighted average price (USD per unit) | 2.16 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar PEPL Index | Second Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,820 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.98 |
Ceiling, weighted average price (USD per unit) | 2.16 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar PEPL Index | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,840 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.98 |
Ceiling, weighted average price (USD per unit) | 2.16 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar PEPL Index | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,840 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.98 |
Ceiling, weighted average price (USD per unit) | 2.16 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar PEPL Index | 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 5,460 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.98 |
Ceiling, weighted average price (USD per unit) | 2.16 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar PEPL Index | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,800 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.98 |
Ceiling, weighted average price (USD per unit) | 2.16 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar PEPL Index | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,820 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.98 |
Ceiling, weighted average price (USD per unit) | 2.16 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar PEPL Index | Third Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,840 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.98 |
Ceiling, weighted average price (USD per unit) | 2.16 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar Perm EP | 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 5,500 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.65 |
Ceiling, weighted average price (USD per unit) | 1.80 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar Perm EP | Second Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,820 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.65 |
Ceiling, weighted average price (USD per unit) | 1.80 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar Perm EP | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,840 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.65 |
Ceiling, weighted average price (USD per unit) | 1.80 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar Perm EP | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,840 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.65 |
Ceiling, weighted average price (USD per unit) | 1.80 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar Perm EP | 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 5,460 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.65 |
Ceiling, weighted average price (USD per unit) | 1.80 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar Perm EP | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,800 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.65 |
Ceiling, weighted average price (USD per unit) | 1.80 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar Perm EP | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,820 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.65 |
Ceiling, weighted average price (USD per unit) | 1.80 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Gas Collar Perm EP | Third Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | MMBTU / D | 1,840 |
Weighted Average Price | |
Floor, weighted average price (USD per unit) | 1.65 |
Ceiling, weighted average price (USD per unit) | 1.80 |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Basis Swaps W T I Midland Index | 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 275 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.70) |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Basis Swaps W T I Midland Index | Second Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 91 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.70) |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Basis Swaps W T I Midland Index | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 92 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.70) |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Basis Swaps W T I Midland Index | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 92 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.70) |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Basis Swaps W T I Midland Index | 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 273 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.70) |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Basis Swaps W T I Midland Index | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 90 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.70) |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Basis Swaps W T I Midland Index | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 91 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.70) |
Subsequent Derivative Contract As Of Balance Sheet Date | Derivative Contract Oil Basis Swaps W T I Midland Index | Third Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume | bbl / qtr | 92 |
Weighted Average Price | |
Weighted Avg Differential- Variable Price (USD per unit) | $ / bbl | (0.70) |
DERIVATIVE INSTRUMENTS - (Gains
DERIVATIVE INSTRUMENTS - (Gains) / Losses from Cash Settlements of Derivative Contracts (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Net (gains) and losses on derivative contracts | |||
Cash (receipts) payments on derivative instruments, net: | $ (1,633,000) | $ 7,437,000 | $ 0 |
(Gain) loss on derivative instruments, net | (21,210,000) | 55,749,000 | (11,246,000) |
Not Designated as Hedging Instrument | |||
Net (gains) and losses on derivative contracts | |||
Change in fair value of derivative instruments not designated as hedging instruments | (22,843,000) | 63,186,000 | (11,246,000) |
Cash (receipts) payments on derivative instruments, net: | 1,633,000 | (7,437,000) | 0 |
(Gain) loss on derivative instruments, net | (21,210,000) | 55,749,000 | (11,246,000) |
Not Designated as Hedging Instrument | Gas contracts | |||
Net (gains) and losses on derivative contracts | |||
Change in fair value of derivative instruments not designated as hedging instruments | (40,226,000) | 27,462,000 | (4,472,000) |
Cash (receipts) payments on derivative instruments, net: | (4,557,000) | (6,467,000) | 0 |
Not Designated as Hedging Instrument | Oil contracts | |||
Net (gains) and losses on derivative contracts | |||
Change in fair value of derivative instruments not designated as hedging instruments | 17,383,000 | 35,724,000 | (6,774,000) |
Cash (receipts) payments on derivative instruments, net: | $ 6,190,000 | $ (970,000) | $ 0 |
DERIVATIVE INSTRUMENTS - Deri36
DERIVATIVE INSTRUMENTS - Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Asset | ||
Derivative instruments - assets | $ 15,151 | $ 0 |
Liability | ||
Derivative instruments - liabilities | 42,066 | 49,370 |
Not Designated as Hedging Instrument | ||
Asset | ||
Derivative instruments - assets | 17,237 | 0 |
Less: gross amounts not offset in the balance sheet | (17,237) | 0 |
Net amount | 0 | 0 |
Liability | ||
Derivative instruments - liabilities | 46,334 | 51,940 |
Less: gross amounts not offset in the balance sheet | (17,237) | 0 |
Net amount | 29,097 | 51,940 |
Not Designated as Hedging Instrument | Gas contracts | Current Assets | ||
Asset | ||
Derivative instruments - assets | 15,151 | |
Not Designated as Hedging Instrument | Gas contracts | Non-Current Assets | ||
Asset | ||
Derivative instruments - assets | 2,086 | |
Not Designated as Hedging Instrument | Gas contracts | Current Liabilities | ||
Liability | ||
Derivative instruments - liabilities | 21,478 | |
Not Designated as Hedging Instrument | Gas contracts | Non-Current Liabilities | ||
Liability | ||
Derivative instruments - liabilities | 1,511 | |
Not Designated as Hedging Instrument | Oil contracts | Current Liabilities | ||
Liability | ||
Derivative instruments - liabilities | 42,066 | 27,892 |
Not Designated as Hedging Instrument | Oil contracts | Non-Current Liabilities | ||
Liability | ||
Derivative instruments - liabilities | $ 4,268 | $ 1,059 |
FAIR VALUE MEASUREMENTS - Asset
FAIR VALUE MEASUREMENTS - Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Apr. 10, 2017 | Dec. 31, 2016 | Jun. 30, 2014 |
Financial Assets (Liabilities): | ||||
Derivative instruments - assets | $ 15,151 | $ 0 | ||
Derivative instruments - liabilities | (42,066) | (49,370) | ||
Level 2: Fair Value Inputs | Carrying Amount | ||||
Financial Assets (Liabilities): | ||||
Derivative instruments - assets | 17,237 | 0 | ||
Derivative instruments - liabilities | (46,334) | (51,940) | ||
Level 2: Fair Value Inputs | Fair Value | ||||
Financial Assets (Liabilities): | ||||
Derivative instruments - assets | 17,237 | 0 | ||
Derivative instruments - liabilities | $ (46,334) | (51,940) | ||
Senior Notes 5.875% | ||||
Financial Assets (Liabilities): | ||||
Interest rate (as a percent) | 5.875% | 5.875% | ||
Senior Notes 5.875% | Carrying Amount | ||||
Financial Assets (Liabilities): | ||||
Long-term debt | $ 0 | (750,000) | ||
Senior Notes 5.875% | Fair Value | ||||
Financial Assets (Liabilities): | ||||
Long-term debt | $ 0 | (782,835) | ||
Senior Notes 4.375% | ||||
Financial Assets (Liabilities): | ||||
Interest rate (as a percent) | 4.375% | 4.375% | ||
Senior Notes 4.375% | Carrying Amount | ||||
Financial Assets (Liabilities): | ||||
Long-term debt | $ (750,000) | (750,000) | ||
Senior Notes 4.375% | Fair Value | ||||
Financial Assets (Liabilities): | ||||
Long-term debt | $ (797,010) | (779,453) | ||
3.90% Senior Notes | ||||
Financial Assets (Liabilities): | ||||
Interest rate (as a percent) | 3.90% | 3.90% | ||
3.90% Senior Notes | Carrying Amount | ||||
Financial Assets (Liabilities): | ||||
Long-term debt | $ (750,000) | 0 | ||
3.90% Senior Notes | Fair Value | ||||
Financial Assets (Liabilities): | ||||
Long-term debt | $ (767,813) | $ 0 |
FAIR VALUE MEASUREMENTS - Other
FAIR VALUE MEASUREMENTS - Other Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Other Financial Instruments | ||
Accrued payroll related general and administrative expenses | $ 54.6 | $ 43.5 |
Accrued operating expenses | 61.3 | 53.9 |
Allowance for Trade Receivables | ||
Other Financial Instruments | ||
Aggregate allowance for doubtful accounts | $ 2.2 | $ 1.6 |
FAIR VALUE MEASUREMENTS - Conce
FAIR VALUE MEASUREMENTS - Concentration (Details) - Net Sales Revenue - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Energy Transfer Partners, L.P. | |||
Concentration Risk | |||
Percentage of sales to revenue, major customers (as a percent) | 21.00% | ||
Plains All American Pipeline, L.P. | |||
Concentration Risk | |||
Percentage of sales to revenue, major customers (as a percent) | 13.00% | ||
Sunoco Logistics Partners L.P. | |||
Concentration Risk | |||
Percentage of sales to revenue, major customers (as a percent) | 20.00% | 21.00% | |
Enterprise Products Partners L.P. | |||
Concentration Risk | |||
Percentage of sales to revenue, major customers (as a percent) | 17.00% |
STOCK-BASED AND OTHER COMPENS40
STOCK-BASED AND OTHER COMPENSATION - Summary (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Mar. 31, 2017 | |
Options, Restricted Stock and Unit Awards | ||||
Total stock compensation cost | $ 48,365 | $ 45,139 | $ 36,341 | |
Less amounts capitalized to oil and gas properties | (22,109) | (20,616) | (16,782) | |
Stock compensation expense | 26,256 | 24,523 | 19,559 | |
Cumulative effect adjustment | 33,132 | |||
Net cash provided by operating activities | 1,096,564 | 625,849 | 725,728 | |
Net cash (used) provided by financing activities | $ (83,009) | (59,945) | 656,397 | |
Maximum number of shares of common stock that may be issued under the Stock Incentive Plan | 6,600,000 | |||
Restricted Stock and Units | ||||
Options, Restricted Stock and Unit Awards | ||||
Total stock compensation cost | $ 45,766 | $ 42,574 | $ 33,538 | |
Restricted Stock | ||||
Options, Restricted Stock and Unit Awards | ||||
Restricted stock granted (in shares) | 551,837 | 478,639 | 471,119 | |
Restricted stock granted, weighted average grant-date fair value (in dollars per share) | $ 91.55 | $ 116.31 | $ 99.29 | |
Performance Based Restricted Stock | ||||
Options, Restricted Stock and Unit Awards | ||||
Total stock compensation cost | $ 26,020 | $ 24,183 | $ 18,991 | |
Restricted stock granted (in shares) | 300,525 | 269,915 | 263,939 | |
Restricted stock granted, weighted average grant-date fair value (in dollars per share) | $ 89.46 | $ 117.63 | $ 87.12 | |
Vesting period | 3 years | |||
Performance Based Restricted Stock | Minimum | ||||
Options, Restricted Stock and Unit Awards | ||||
Award vesting percentage | 50.00% | |||
Performance Based Restricted Stock | Maximum | ||||
Options, Restricted Stock and Unit Awards | ||||
Award vesting percentage | 100.00% | |||
Service Based Restricted Stock | ||||
Options, Restricted Stock and Unit Awards | ||||
Total stock compensation cost | $ 19,746 | $ 18,391 | $ 14,547 | |
Restricted stock granted (in shares) | 251,312 | 208,724 | 207,180 | |
Restricted stock granted, weighted average grant-date fair value (in dollars per share) | $ 94.04 | $ 114.61 | $ 114.80 | |
Service Based Restricted Stock | Minimum | ||||
Options, Restricted Stock and Unit Awards | ||||
Vesting period | 1 year | |||
Service Based Restricted Stock | Maximum | ||||
Options, Restricted Stock and Unit Awards | ||||
Vesting period | 5 years | |||
Service Based Restricted Stock | Average | ||||
Options, Restricted Stock and Unit Awards | ||||
Vesting period | 5 years | |||
Employee Stock Option | ||||
Options, Restricted Stock and Unit Awards | ||||
Total stock compensation cost | $ 2,599 | $ 2,565 | $ 2,803 | |
Vesting period | 3 years | |||
Retained Earnings | ||||
Options, Restricted Stock and Unit Awards | ||||
Cumulative effect adjustment | $ 28,739 | |||
Additional Paid-in Capital | ||||
Options, Restricted Stock and Unit Awards | ||||
Cumulative effect adjustment | 4,393 | |||
Accounting Standards Update 2016-09 | ||||
Options, Restricted Stock and Unit Awards | ||||
Cumulative effect adjustment | $ 33,100 | |||
Net cash provided by operating activities | 26,600 | 34,200 | ||
Net cash (used) provided by financing activities | $ (26,600) | $ (34,200) | ||
Accounting Standards Update 2016-09 | Retained Earnings | ||||
Options, Restricted Stock and Unit Awards | ||||
Cumulative effect adjustment | 28,700 | |||
Accounting Standards Update 2016-09 | Additional Paid-in Capital | ||||
Options, Restricted Stock and Unit Awards | ||||
Cumulative effect adjustment | $ 4,400 |
STOCK-BASED AND OTHER COMPENS41
STOCK-BASED AND OTHER COMPENSATION - RSA and RSU Activity (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Restricted Stock | |||
Restricted stock and unit activity | |||
Granted (in shares) | 551,837 | 478,639 | 471,119 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Granted | $ 91.55 | $ 116.31 | $ 99.29 |
Fair value of resticted stock vested | $ 54.4 | $ 67.9 | $ 52.2 |
Performance Based Restricted Stock | |||
Restricted stock and unit activity | |||
Outstanding at the beginning of the period (in shares) | 809,270 | ||
Vested (in shares) | (275,416) | ||
Granted (in shares) | 300,525 | 269,915 | 263,939 |
Forfeited (in shares) | 0 | ||
Outstanding at the end of the period (in shares) | 834,379 | 809,270 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Outstanding beginning of period | $ 96.41 | ||
Vested | 84.50 | ||
Granted | 89.46 | $ 117.63 | $ 87.12 |
Forfeited | 0 | ||
Outstanding end of period | $ 97.83 | $ 96.41 | |
Service Based Restricted Stock | |||
Restricted stock and unit activity | |||
Outstanding at the beginning of the period (in shares) | 934,723 | ||
Vested (in shares) | (234,468) | ||
Granted (in shares) | 251,312 | 208,724 | 207,180 |
Forfeited (in shares) | (41,316) | ||
Outstanding at the end of the period (in shares) | 910,251 | 934,723 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Outstanding beginning of period | $ 96.57 | ||
Vested | 63.49 | ||
Granted | 94.04 | $ 114.61 | $ 114.80 |
Forfeited | 105.83 | ||
Outstanding end of period | $ 103.98 | $ 96.57 | |
Restricted Stock and Units | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Unrecognized compensation cost of unvested restricted stock | $ 105.6 | ||
Unrecognized compensation cost of unvested restricted stock, period for recognition | 2 years 9 months |
STOCK-BASED AND OTHER COMPENS42
STOCK-BASED AND OTHER COMPENSATION - Options, Assumptions (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Grant-Date Fair value | |||
Cash received from option exercises | $ 394 | $ 4,804 | $ 8,451 |
Restricted Stock and Units | |||
Weighted Average Exercise Price - Non-Vested Stock Options | |||
Unrecognized compensation cost of unvested restricted stock | $ 105,600 | ||
Unrecognized compensation cost of unvested restricted stock, period for recognition | 2 years 9 months | ||
Restricted Stock Units | |||
Options, Restricted Stock and Unit Awards | |||
Restricted stock units outstanding (in shares) | 8,838 | 8,838 | |
Employee Stock Option | |||
Options, Restricted Stock and Unit Awards | |||
Vesting period | 3 years | ||
Assumptions used to determine the fair market value of options | |||
Granted (in shares) | 96,100 | 89,850 | 69,000 |
Granted (in dollars per share) | $ 28.37 | $ 33.38 | $ 37.56 |
Weighted average exercise price (in dollars per share) | $ 92.37 | $ 114.07 | $ 115.28 |
Total fair value of options granted | $ 2,727 | $ 2,999 | $ 2,592 |
Expected years until exercise | 4 years 6 months | 4 years | 5 years |
Expected stock volatility (as a percent) | 35.00% | 36.70% | 36.60% |
Dividend yield (as a percent) | 0.30% | 0.30% | 0.60% |
Risk-free interest rate (as a percent) | 1.70% | 1.00% | 1.60% |
Outstanding Stock Options | |||
Outstanding balance at beginning of period (in shares) | 307,810 | ||
Exercised (shares) | (5,768) | ||
Granted (in shares) | 96,100 | 89,850 | 69,000 |
Canceled (in shares) | (1,665) | ||
Forfeited (in shares) | (13,789) | ||
Outstanding balance at end of period (in shares) | 382,688 | 307,810 | |
Exercisable at end of period (in shares) | 209,782 | ||
Weighted Average Exercise Price | |||
Outstanding balance at beginning of period (in dollars per share) | $ 101.72 | ||
Exercised (in dollars per share) | 68.33 | ||
Granted (in dollars per share) | 92.37 | ||
Canceled (in dollars per share) | 139.02 | ||
Forfeited (in dollars per share) | 88.92 | ||
Outstanding at end of period (in dollars per share) | 100.17 | $ 101.72 | |
Exercisable at end of period (in dollars per share) | $ 98.55 | ||
Weighted Average Remaining Term | |||
Weighted average remaining term, outstanding at end of period | 4 years 5 months | ||
Weighted average remaining term, exercisable at end of period | 3 years 2 months | ||
Aggregate Intrinsic Value | |||
Aggregate intrinsic value outstanding at end of period | $ 9,553 | ||
Aggregate intrinsic value exercisable at the end of the period | 6,020 | ||
Grant-Date Fair value | |||
Cash received from option exercises | 394 | $ 4,804 | $ 8,451 |
Tax benefit from option exercises included in paid-in-capital | 0 | 0 | 4,442 |
Intrinsic value of options exercised | 257 | 2,994 | 7,467 |
Grant date fair value of options vested | $ 2,227 | $ 2,486 | $ 2,734 |
Non-vested Stock Options | |||
Non-vested at the beginning of the period (in shares) | 148,361 | ||
Vested (in shares) | (57,766) | ||
Granted (in shares) | 96,100 | 89,850 | 69,000 |
Forfeited (in shares) | (13,789) | ||
Non-vested at the end of the period (in shares) | 172,906 | 148,361 | |
Weighted Average Grant Date Fair Value - Non-Vested Stock Options | |||
Non-vested at beginning of period (in dollars per share) | $ 35.58 | ||
Vested (in dollars per share) | 38.55 | ||
Granted (in dollars per share) | 28.37 | $ 33.38 | $ 37.56 |
Forfeited (in dollars per share) | 29.41 | ||
Non-vested at end of period (in dollars per share) | 31.08 | 35.58 | |
Weighted Average Exercise Price - Non-Vested Stock Options | |||
Non-vested at the beginning of the period (in dollars per share) | 117.55 | ||
Vested (in dollars per share) | 128.59 | ||
Granted (in dollars per share) | 92.37 | ||
Forfeited (in dollars per share) | 88.92 | ||
Non-vested at the end of the period (in dollars per share) | $ 102.15 | $ 117.55 | |
Unrecognized compensation cost of unvested restricted stock | $ 4,100 | ||
Unrecognized compensation cost of unvested restricted stock, period for recognition | 1 year 11 months | ||
Maximum | Employee Stock Option | |||
Options, Restricted Stock and Unit Awards | |||
Term of options from grant to expiration | 10 years | ||
Minimum | Employee Stock Option | |||
Options, Restricted Stock and Unit Awards | |||
Term of options from grant to expiration | 7 years |
STOCK-BASED AND OTHER COMPENS43
STOCK-BASED AND OTHER COMPENSATION - 401(K) Plan (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Retirement Benefits [Abstract] | |||
Annual costs related to the plan | $ 10.4 | $ 6.7 | $ 6.4 |
EARNINGS (LOSS) PER SHARE (Deta
EARNINGS (LOSS) PER SHARE (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Basic: | |||
Net income (loss) | $ 494,329 | $ (408,803) | $ (2,579,604) |
Participating securities' share in earnings | (8,551) | 0 | 0 |
Net income (loss) available to common stockholders | 485,778 | (408,803) | (2,579,604) |
Diluted: | |||
Net income (loss) | 494,329 | (408,803) | (2,579,604) |
Participating securities' share in earnings | (8,548) | 0 | 0 |
Net income (loss) available to common stockholders | $ 485,781 | $ (408,803) | $ (2,579,604) |
Shares: | |||
Basic shares outstanding (shares) | 93,466,000 | 93,379,000 | 92,992,000 |
Dilutive effect of stock options (shares) | 43,000 | 0 | 0 |
Fully diluted common stock (shares) | 93,509,000 | 93,379,000 | 92,992,000 |
Earnings (loss) per share to common stockholders | |||
Basic (USD per share) | $ 5.19 | $ (4.38) | $ (27.75) |
Diluted (USD per share) | $ 5.19 | $ (4.38) | $ (27.75) |
Excluded antidilutive securities (shares) | 302,900 | 2,100,000 | 2,100,000 |
ASSET RETIREMENT OBLIGATIONS -
ASSET RETIREMENT OBLIGATIONS - Summary (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligations | ||
Balance at beginning of year | $ 154,523 | $ 164,105 |
Liabilities incurred | 17,996 | 3,914 |
Liability settlements and disposals | (12,947) | (24,108) |
Accretion expense | 7,534 | 7,595 |
Revisions of estimated liabilities | 2,363 | 3,017 |
Balance at end of year | 169,469 | 154,523 |
Less current obligation | 11,048 | 13,753 |
Long-term asset retirement obligation | 158,421 | 140,770 |
Noncurrent decommissioning liability | 10,500 | |
Liability settlements and disposals related to properties that were sold | $ 500 | $ 14,900 |
INCOME TAXES - Components of th
INCOME TAXES - Components of the Provision for Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Current taxes: | |||
Federal (benefit) expense | $ (2,810) | $ 0 | $ 14,417 |
State (benefit) expense | (2) | (1,115) | 293 |
Current taxes (benefit) | (2,812) | (1,115) | 14,710 |
Deferred taxes: | |||
Federal expense (benefit) | 173,859 | (201,529) | (1,386,086) |
State expense (benefit) | 16,620 | (11,757) | (100,353) |
Deferred income taxes | 190,479 | (213,286) | (1,486,439) |
Income tax expense (benefit) | $ 187,667 | $ (214,401) | $ (1,471,729) |
INCOME TAXES - Reconciliations
INCOME TAXES - Reconciliations of the Income Tax (Benefit) Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliations of the income tax (benefit) expense | |||
Provision at statutory rate | $ 238,699 | $ (218,122) | $ (1,417,967) |
Effect of state taxes | 10,074 | (10,237) | (64,794) |
Revision of previous balances | 0 | 7,181 | 5,997 |
Tax credits and other permanent differences | 5,442 | 5,296 | 5,035 |
Change in valuation allowance, net | 486 | 1,481 | 0 |
Stock-based compensation | (5,888) | 0 | 0 |
Impact of reduction in federal statutory rate | (61,146) | 0 | 0 |
Income tax expense (benefit) | $ 187,667 | $ (214,401) | $ (1,471,729) |
INCOME TAXES - Components of Ne
INCOME TAXES - Components of Net Deferred Taxes (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Assets: | ||
Stock compensation and other accrued amounts | $ 31,044 | $ 58,306 |
Net operating loss carryforward, net of valuation allowance | 313,738 | 399,912 |
Credit carryforward | 3,995 | 6,016 |
Gross deferred tax assets | 348,777 | 464,234 |
Liabilities: | ||
Property, plant and equipment | (450,395) | (408,399) |
Net deferred tax (liabilities) assets | $ (101,618) | |
Net deferred tax (liabilities) assets | $ 55,835 |
INCOME TAXES - Narrative (Detai
INCOME TAXES - Narrative (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Mar. 31, 2017 | |
Operating Loss Carryforwards [Line Items] | ||||
U.S. net tax operating loss carryforward | $ 1,377,700,000 | |||
Income Tax Items [Abstract] | ||||
Alternative minimum tax credit carryforward | 3,000,000 | |||
Oil recovery and marginal well tax credit carryforward | 900,000 | |||
Unrecognized tax benefits that would impact the entity's effective rate | 0 | $ 0 | ||
Provisions for interest or penalties related to uncertain tax positions | 0 | 0 | ||
Cumulative effect adjustment | 33,132,000 | |||
Stock-based compensation | (5,888,000) | $ 0 | $ 0 | |
Income tax expense (benefit) related to TCJA | (61,100,000) | |||
Decrease in deferred tax liability related to TCJA | (61,100,000) | |||
State | ||||
Operating Loss Carryforwards [Line Items] | ||||
Net operating loss carryforward | 3,500,000 | |||
Income Tax Items [Abstract] | ||||
Valuation allowance against net operating losses | 4,000,000 | |||
Net valuation allowance, deferred tax asset change in amount | 500,000 | |||
Total valuation allowance on net operating losses | $ 103,700,000 | |||
Accounting Standards Update 2016-09 | ||||
Income Tax Items [Abstract] | ||||
Cumulative effect adjustment | $ 33,100,000 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - Minimum Lease (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Long-term Purchase Commitment [Line Items] | |||
Rental expense | $ 13,100 | $ 12,900 | $ 13,200 |
Future minimum payments under leases | |||
2,018 | 9,742 | ||
2,019 | 10,702 | ||
2,020 | 10,836 | ||
2,021 | 11,053 | ||
2,022 | 11,222 | ||
Later years | 32,645 | ||
Total future minimum lease payments | 86,200 | ||
Compressor Equipment | |||
Long-term Purchase Commitment [Line Items] | |||
Commitments for purchases and other expenditures | $ 8,500 | ||
Compressor Equipment | Minimum | |||
Long-term Purchase Commitment [Line Items] | |||
Delivery term | 2 months | ||
Compressor Equipment | Maximum | |||
Long-term Purchase Commitment [Line Items] | |||
Delivery term | 24 months |
COMMITMENTS AND CONTINGENCIES51
COMMITMENTS AND CONTINGENCIES - Other Commitments (Details) $ in Millions | Dec. 31, 2017USD ($) |
Drilling Commitments | |
Construction, Drilling and Purchase Commitments | |
Commitments for purchases and other expenditures | $ 252.6 |
Other Transportation, Delivery And Facilities Commitments | |
Construction, Drilling and Purchase Commitments | |
Other commitments | $ 33.3 |
COMMITMENTS AND CONTINGENCIES52
COMMITMENTS AND CONTINGENCIES - Other Commitments - Delivery, Operating Leases (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($)Bcf | |
Natural Gas Sales Contracts | |
Construction, Drilling and Purchase Commitments | |
Volume of gas deliverable (in Bcf) | Bcf | 217.6 |
Delivery term | 85 months |
Maximum financial commitment resulting from inability to meet gas delivery commitments | $ 476.7 |
Gas Gathering And Processing Agreements | |
Construction, Drilling and Purchase Commitments | |
Delivery term | 8 years 4 months |
Maximum financial commitment resulting from inability to meet gas delivery commitments | $ 298.3 |
Minimum Volume Agreement | |
Construction, Drilling and Purchase Commitments | |
Maximum financial commitment resulting from inability to meet gas delivery commitments | 11.4 |
Other Transportation, Delivery And Facilities Commitments | |
Construction, Drilling and Purchase Commitments | |
Maximum financial commitment resulting from inability to meet gas delivery commitments | $ 36.5 |
COMMITMENTS AND CONTINGENCIES53
COMMITMENTS AND CONTINGENCIES - Litigation (Details) - Helmerich and Payne Case - USD ($) $ in Thousands | Apr. 01, 2014 | Dec. 13, 2013 | Dec. 31, 2008 | Dec. 31, 2013 |
Loss Contingencies | ||||
Accrued litigation expense | $ 119,600 | |||
Damages awarded | $ 3,650 | |||
Reduction in previously recognized litigation expense and associated long-term liability | $ (142,800) | |||
Payments to plaintiff | $ 15,800 |
RELATED PARTY TRANSACTIONS - Na
RELATED PARTY TRANSACTIONS - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Helmerich and Payne | |||
Related Party Transactions | |||
Contract drilling services costs | $ 52.6 | $ 18.3 | $ 7.9 |
SUPPLEMENTAL CASH FLOW INFORM55
SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash paid during the period for: | |||
Interest expense (net of capitalized amounts of $23,113, $20,308, and $28,819, respectively) | $ 52,245 | $ 59,282 | $ 51,966 |
Income taxes | 3 | 13 | 558 |
Cash received for income tax refunds | 111 | 1,450 | 1,503 |
Interest capitalized | $ 23,113 | $ 20,308 | $ 28,819 |