DOCUMENT AND ENTITY INFORMATION
DOCUMENT AND ENTITY INFORMATION - shares | 6 Months Ended | |
Jun. 30, 2018 | Jul. 31, 2018 | |
Document And Entity Information [Abstract] | ||
Entity Registrant Name | CIMAREX ENERGY CO | |
Entity Central Index Key | 1,168,054 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus (i.e. Q1,Q2,Q3,FY) | Q2 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 95,356,074 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 410,823 | $ 400,534 |
Accounts receivable, net of allowance: | ||
Trade | 128,984 | 100,356 |
Oil and gas sales | 304,255 | 344,552 |
Gas gathering, processing, and marketing | 11,416 | 15,266 |
Oil and gas well equipment and supplies | 53,375 | 49,722 |
Derivative instruments | 72,943 | 15,151 |
Prepaid expenses | 7,419 | 8,518 |
Other current assets | 927 | 1,536 |
Total current assets | 990,142 | 935,635 |
Oil and gas properties at cost, using the full cost method of accounting: | ||
Proved properties | 18,112,548 | 17,513,460 |
Unproved properties and properties under development, not being amortized | 532,715 | 476,903 |
Gross oil and gas properties | 18,645,263 | 17,990,363 |
Less—accumulated depreciation, depletion, amortization, and impairment | (15,000,443) | (14,748,833) |
Net oil and gas properties | 3,644,820 | 3,241,530 |
Fixed assets, net of accumulated depreciation of $312,927 and $290,114, respectively | 238,964 | 210,922 |
Goodwill | 620,232 | 620,232 |
Derivative instruments | 2,330 | 2,086 |
Other assets | 34,905 | 32,234 |
Total assets | 5,531,393 | 5,042,639 |
Accounts payable: | ||
Trade | 74,596 | 68,883 |
Gas gathering, processing, and marketing | 20,643 | 29,503 |
Accrued liabilities: | ||
Exploration and development | 146,886 | 115,762 |
Taxes other than income | 24,392 | 23,687 |
Other | 199,093 | 212,400 |
Derivative instruments | 90,480 | 42,066 |
Revenue payable | 180,869 | 187,273 |
Total current liabilities | 736,959 | 679,574 |
Long-term debt: | ||
Principal | 1,500,000 | 1,500,000 |
Less—unamortized debt issuance costs and discount | (12,261) | (13,080) |
Long-term debt, net | 1,487,739 | 1,486,920 |
Deferred income taxes | 201,350 | 101,618 |
Asset retirement obligation | 159,568 | 158,421 |
Derivative instruments | 11,511 | 4,268 |
Other liabilities | 47,768 | 43,560 |
Total liabilities | 2,644,895 | 2,474,361 |
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, 95,392,547 and 95,437,434 shares issued, respectively | 954 | 954 |
Additional paid-in capital | 2,770,532 | 2,764,384 |
Retained earnings (accumulated deficit) | 112,811 | (199,259) |
Accumulated other comprehensive income | 2,201 | 2,199 |
Total stockholders’ equity | 2,886,498 | 2,568,278 |
Total liabilities and stockholders' equity | $ 5,531,393 | $ 5,042,639 |
CONDENSED CONSOLIDATED BALANCE3
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Accumulated depreciation on fixed assets | $ 312,927 | $ 290,114 |
Preferred stock, par value (USD per share) | $ 0.01 | $ 0.01 |
Preferred stock authorized (shares) | 15,000,000 | 15,000,000 |
Preferred stock issued (shares) | 0 | 0 |
Common stock, par value (USD per share) | $ 0.01 | $ 0.01 |
Common stock authorized (shares) | 200,000,000 | 200,000,000 |
Common stock issued (shares) | 95,392,547 | 95,437,434 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Revenues: | ||||
Revenues | $ 556,274 | $ 456,452 | $ 1,123,408 | $ 903,628 |
Costs and expenses: | ||||
Depreciation, depletion, and amortization | 143,388 | 107,884 | 276,247 | 203,700 |
Asset retirement obligation | 2,053 | 960 | 3,113 | 2,580 |
Production | 79,215 | 62,578 | 150,486 | 124,999 |
Transportation, processing, and other operating | 51,933 | 58,624 | 97,098 | 113,647 |
Gas gathering and other | 9,467 | 8,647 | 19,290 | 17,074 |
Taxes other than income | 27,930 | 17,477 | 58,118 | 38,790 |
General and administrative | 19,739 | 19,762 | 43,060 | 37,796 |
Stock compensation | 3,095 | 6,293 | 9,825 | 12,581 |
Loss (gain) on derivative instruments, net | 21,699 | (22,509) | 17,540 | (66,370) |
Other operating expense, net | 5,252 | 266 | 5,455 | 882 |
Total costs and expenses | 363,771 | 259,982 | 680,232 | 485,679 |
Operating income | 192,503 | 196,470 | 443,176 | 417,949 |
Other (income) and expense: | ||||
Interest expense | 16,895 | 20,095 | 33,678 | 41,147 |
Capitalized interest | (4,850) | (5,442) | (9,660) | (12,083) |
Loss on early extinguishment of debt | 0 | 28,169 | 0 | 28,169 |
Other, net | (2,605) | (2,231) | (7,172) | (4,441) |
Income before income tax | 183,063 | 155,879 | 426,330 | 365,157 |
Income tax expense | 42,066 | 58,617 | 99,015 | 136,923 |
Net income | $ 140,997 | $ 97,262 | $ 327,315 | $ 228,234 |
Earnings per share to common stockholders: | ||||
Basic (USD per share) | $ 1.48 | $ 1.02 | $ 3.44 | $ 2.40 |
Diluted (USD per share) | 1.48 | 1.02 | 3.44 | 2.40 |
Dividends declared (USD per share) | $ 0.16 | $ 0.08 | $ 0.32 | $ 0.16 |
Comprehensive income: | ||||
Net income | $ 140,997 | $ 97,262 | $ 327,315 | $ 228,234 |
Other comprehensive income: | ||||
Change in fair value of investments, net of tax of $57, $128, $1, and $359, respectively | 192 | 224 | 2 | 626 |
Total comprehensive income | 141,189 | 97,486 | 327,317 | 228,860 |
Oil sales | ||||
Revenues: | ||||
Revenues | 342,184 | 232,453 | 693,907 | 456,519 |
Gas and NGL sales | ||||
Revenues: | ||||
Revenues | 202,202 | 213,360 | 405,920 | 425,731 |
Gas gathering and other | ||||
Revenues: | ||||
Revenues | 11,810 | 10,735 | 23,262 | 21,360 |
Gas marketing | ||||
Revenues: | ||||
Revenues | $ 78 | $ (96) | $ 319 | $ 18 |
CONDENSED CONSOLIDATED STATEME5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Income Statement [Abstract] | ||||
Change in fair value investments, tax | $ 57 | $ 128 | $ 1 | $ 359 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Cash flows from operating activities: | ||
Net income | $ 327,315 | $ 228,234 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, depletion, and amortization | 276,247 | 203,700 |
Asset retirement obligation | 3,113 | 2,580 |
Deferred income taxes | 99,732 | 136,929 |
Stock compensation | 9,825 | 12,581 |
Loss (gain) on derivative instruments, net | 17,540 | (66,370) |
Settlements on derivative instruments | (19,919) | (5,717) |
Loss on early extinguishment of debt | 0 | 28,169 |
Changes in non-current assets and liabilities | 713 | 1,076 |
Other, net | 2,179 | 3,445 |
Changes in operating assets and liabilities: | ||
Accounts receivable | 15,012 | (61,145) |
Other current assets | 1,886 | (11,104) |
Accounts payable and other current liabilities | (29,304) | 32,422 |
Net cash provided by operating activities | 704,339 | 504,800 |
Cash flows from investing activities: | ||
Oil and gas capital expenditures | (650,807) | (582,172) |
Other capital expenditures | (56,112) | (18,209) |
Sales of oil and gas assets | 34,842 | 9,163 |
Sales of other assets | 525 | 394 |
Net cash used by investing activities | (671,552) | (590,824) |
Cash flows from financing activities: | ||
Borrowings of long-term debt | 0 | 748,110 |
Repayments of long-term debt | 0 | (750,000) |
Call premium, financing, and underwriting fees | 0 | (29,035) |
Dividends paid | (22,801) | (15,153) |
Employee withholding taxes paid upon the net settlement of equity-classified stock awards | (946) | (1,215) |
Proceeds from exercise of stock options | 1,249 | 36 |
Net cash used by financing activities | (22,498) | (47,257) |
Net change in cash and cash equivalents | 10,289 | (133,281) |
Cash and cash equivalents at beginning of period | 400,534 | 652,876 |
Cash and cash equivalents at end of period | $ 410,823 | $ 519,595 |
CONDENSED CONSOLIDATED STATEME7
CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY - 6 months ended Jun. 30, 2018 - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Accumulated Other Comprehensive Income |
Balance at beginning of period (shares) at Dec. 31, 2017 | 95,437 | ||||
Balance at beginning of period at Dec. 31, 2017 | $ 2,568,278 | $ 954 | $ 2,764,384 | $ (199,259) | $ 2,199 |
Increase (Decrease) in Stockholders' Equity | |||||
Dividends paid on stock awards subsequently forfeited | 46 | 29 | 17 | ||
Dividends | (15,262) | (15,262) | |||
Dividends in excess of retained earnings | (15,250) | (15,250) | |||
Net income | 327,315 | 327,315 | |||
Unrealized change in fair value of investments, net of tax | 2 | 2 | |||
Issuance of restricted stock awards (shares) | 29 | ||||
Common stock reacquired and retired (shares) | (8) | ||||
Common stock reacquired and retired | (946) | (946) | |||
Restricted stock forfeited and retired (shares) | (82) | ||||
Exercise of stock options (shares) | 17 | ||||
Exercise of stock options | 1,249 | 1,249 | |||
Stock-based compensation | 21,066 | 21,066 | |||
Balance at end of period (shares) at Jun. 30, 2018 | 95,393 | ||||
Balance at end of period at Jun. 30, 2018 | $ 2,886,498 | $ 954 | $ 2,770,532 | $ 112,811 | $ 2,201 |
BASIS OF PRESENTATION
BASIS OF PRESENTATION | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
BASIS OF PRESENTATION | BASIS OF PRESENTATION The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. (“Cimarex,” “we,” or “us”) pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in Annual Reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the financial statements, summary of significant accounting policies, and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2017 . In the opinion of management, the accompanying financial statements reflect all adjustments necessary to fairly present our financial position, results of operations, and cash flows for the periods and as of the dates shown. Certain amounts in the prior year financial statements have been reclassified to conform to the 2018 financial statement presentation. Use of Estimates 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. 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 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. Under the full cost method of accounting, we are required to perform a quarterly ceiling test calculation 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. The calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. We did not recognize a ceiling test impairment during the six months ended June 30, 2018 and 2017 because the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation. If pricing conditions deteriorate, including the further widening of local market basis differentials, 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. 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. Revenue Recognition Oil, Gas, and NGL Sales Effective January 1, 2018, we adopted the provisions of Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”), utilizing the modified retrospective approach, which we applied to contracts that were not completed as of that date. Because we utilized the modified retrospective approach, there was no impact to prior periods’ reported amounts. Application of ASC 606 has no impact on our net income or cash flows from operations; however, certain costs classified as Transportation, processing, and other operating expenses in the statement of operations under prior accounting standards are now reflected as deductions from revenue under ASC 606. The following tables present the impact on our Oil sales, Gas sales, and NGL sales and on our Transportation, processing, and other operating costs from the application of ASC 606 in the current reporting period: Three Months Ended 2018 2017 (in thousands) Pre- Impact of Post- As Reported Oil sales $ 342,184 $ — $ 342,184 $ 232,453 Gas sales 84,727 (3,940 ) 80,787 132,474 NGL sales 125,126 (3,711 ) 121,415 80,886 Total oil, gas, and NGL sales $ 552,037 $ (7,651 ) $ 544,386 $ 445,813 Transportation, processing, and other operating costs $ 59,584 $ (7,651 ) $ 51,933 $ 58,624 Six Months Ended 2018 2017 (in thousands) Pre- Impact of Post- As Reported Oil sales $ 693,907 $ — $ 693,907 $ 456,519 Gas sales 197,404 (6,896 ) 190,508 264,419 NGL sales 230,739 (15,327 ) 215,412 161,312 Total oil, gas, and NGL sales $ 1,122,050 $ (22,223 ) $ 1,099,827 $ 882,250 Transportation, processing, and other operating costs $ 119,321 $ (22,223 ) $ 97,098 $ 113,647 Revenue is recognized from the sales of oil, gas, and NGLs when the customer obtains control of the product, when we have no further obligations to perform related to the sale, and when collectability is probable. All of our sales of oil, gas, and NGLs are made under contracts with customers, which typically include variable consideration based on monthly pricing tied to local indices and monthly volumes delivered. The nature of our contracts with customers does not require us to constrain that variable consideration or to estimate the amount of transaction price attributable to future performance obligations for accounting purposes. As of June 30, 2018 , we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas, and/or NGLs. Our contracts with customers typically require payment within one month of delivery. Our gas and NGLs are sold under a limited number of contract structure types common in our industry. Under these contracts the gas and its components, including NGLs, may be sold to a single purchaser or the residue gas and NGLs may be sold to separate purchasers. Regardless of the contract structure type, the terms of these contracts compensate us for the value of the residue gas and NGLs at current market prices for each product, and are disaggregated in the tables above on that basis. Our oil typically is sold at specific delivery points under contract terms that also are common in our industry. 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 may earn a fee for such services. Revenues from such services are recognized as gas is delivered. 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. Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) . The key provision of this ASU is that a lessee must recognize on its balance sheet: (i) liabilities to make lease payments and (ii) right-of-use assets. The ASU permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than 12 months. Under current generally accepted accounting principles, 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 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 evaluating the potential impact of adopting this guidance and do not intend to adopt the standard early. |
LONG-TERM DEBT
LONG-TERM DEBT | 6 Months Ended |
Jun. 30, 2018 | |
Long-term Debt, Unclassified [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT Long-term debt at June 30, 2018 and December 31, 2017 consisted of the following: June 30, 2018 December 31, 2017 (in thousands) Principal Unamortized Debt Issuance Costs and Discount (1) Long-term Debt, net Principal Unamortized Debt Issuance Costs and Discount (1) Long-term Debt, net 4.375% Senior Notes $ 750,000 $ (4,906 ) $ 745,094 $ 750,000 $ (5,383 ) $ 744,617 3.90% Senior Notes 750,000 (7,355 ) 742,645 750,000 (7,697 ) 742,303 Total long-term debt $ 1,500,000 $ (12,261 ) $ 1,487,739 $ 1,500,000 $ (13,080 ) $ 1,486,920 ________________________________________ (1) At June 30, 2018 , the unamortized debt issuance costs and discount related to the 3.90% notes were $5.7 million and $1.7 million , respectively. 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 We have a senior unsecured revolving credit facility (“Credit Facility”) that matures October 16, 2020. The Credit Facility has aggregate commitments of $1.0 billion , with an option for us to increase the 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 June 30, 2018 , 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 June 30, 2018 , we were in compliance with all of the financial covenants. At June 30, 2018 and December 31, 2017 , we had $2.7 million and $3.4 million , respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as assets and included in Other assets on our Condensed Consolidated Balance Sheets. These costs are being amortized to interest expense ratably over the life of the Credit Facility. Senior Notes In April 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes at 99.748% of par to yield 3.93% per annum. These notes are due May 15, 2027 and interest is payable semiannually on May 15 and November 15. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.01% . 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. The effective interest rate on these notes, including the amortization of debt issuance costs, is 4.50% . Our senior unsecured notes are governed by indentures containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of June 30, 2018 . |
DERIVATIVE INSTRUMENTS
DERIVATIVE INSTRUMENTS | 6 Months Ended |
Jun. 30, 2018 | |
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 June 30, 2018 , 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 June 30, 2018 (subsequent to June 30, 2018 through August 6, 2018, we have not entered into any additional derivative contracts): Oil Collars First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: WTI (1) Volume (Bbls) — — 3,220,000 2,668,000 5,888,000 Weighted Avg Price - Floor $ — $ — $ 49.80 $ 51.03 $ 50.36 Weighted Avg Price - Ceiling $ — $ — $ 60.49 $ 61.74 $ 61.06 2019: WTI (1) Volume (Bbls) 2,070,000 2,093,000 1,472,000 736,000 6,371,000 Weighted Avg Price - Floor $ 51.83 $ 51.83 $ 53.50 $ 57.00 $ 52.81 Weighted Avg Price - Ceiling $ 63.77 $ 63.77 $ 67.13 $ 68.04 $ 65.04 ________________________________________ (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) — — 11,960,000 9,200,000 21,160,000 Weighted Avg Price - Floor $ — $ — $ 2.19 $ 2.12 $ 2.16 Weighted Avg Price - Ceiling $ — $ — $ 2.48 $ 2.42 $ 2.45 Perm EP (2) Volume (MMBtu) — — 9,200,000 7,360,000 16,560,000 Weighted Avg Price - Floor $ — $ — $ 1.92 $ 1.81 $ 1.87 Weighted Avg Price - Ceiling $ — $ — $ 2.14 $ 2.03 $ 2.09 Waha (3) Volume (MMBtu) — — 920,000 920,000 1,840,000 Weighted Avg Price - Floor $ — $ — $ 1.35 $ 1.35 $ 1.35 Weighted Avg Price - Ceiling $ — $ — $ 1.56 $ 1.56 $ 1.56 2019: PEPL (1) Volume (MMBtu) 8,100,000 8,190,000 5,520,000 2,760,000 24,570,000 Weighted Avg Price - Floor $ 2.08 $ 2.08 $ 1.92 $ 1.90 $ 2.02 Weighted Avg Price - Ceiling $ 2.39 $ 2.39 $ 2.26 $ 2.33 $ 2.36 Perm EP (2) Volume (MMBtu) 6,300,000 6,370,000 4,600,000 1,840,000 19,110,000 Weighted Avg Price - Floor $ 1.73 $ 1.73 $ 1.50 $ 1.35 $ 1.64 Weighted Avg Price - Ceiling $ 1.95 $ 1.95 $ 1.74 $ 1.55 $ 1.86 Waha (3) Volume (MMBtu) 900,000 910,000 920,000 920,000 3,650,000 Weighted Avg Price - Floor $ 1.35 $ 1.35 $ 1.35 $ 1.35 $ 1.35 Weighted Avg Price - Ceiling $ 1.56 $ 1.56 $ 1.56 $ 1.56 $ 1.56 ________________________________________ (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. (3) The index price for these collars is Waha West Texas Natural Gas Index (“Waha”) 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) — — 2,484,000 2,024,000 4,508,000 Weighted Avg Differential (2) $ — $ — $ (3.89 ) $ (4.56 ) $ (4.19 ) 2019: WTI Midland (1) Volume (Bbls) 1,710,000 1,729,000 1,288,000 552,000 5,279,000 Weighted Avg Differential (2) $ (5.17 ) $ (5.17 ) $ (6.84 ) $ (10.73 ) $ (6.16 ) ________________________________________ (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 Loss (gain) on derivative instruments, net for the periods indicated. Three Months Ended Six Months Ended (in thousands) 2018 2017 2018 2017 Change in fair value of derivative instruments, net: Gas contracts $ 14,566 $ (5,748 ) $ 2,777 $ (27,939 ) Oil contracts (397 ) (16,418 ) (5,156 ) (44,148 ) 14,169 (22,166 ) (2,379 ) (72,087 ) Cash (receipts) payments on derivative instruments, net: Gas contracts (9,918 ) (1,308 ) (15,037 ) 1,136 Oil contracts 17,448 965 34,956 4,581 7,530 (343 ) 19,919 5,717 Loss (gain) on derivative instruments, net $ 21,699 $ (22,509 ) $ 17,540 $ (66,370 ) Derivative Fair Value Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs and are subject to 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 June 30, 2018 and December 31, 2017 , as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts. June 30, 2018 (in thousands) Balance Sheet Location Asset Liability Oil contracts Current assets — Derivative instruments $ 57,768 $ — Gas contracts Current assets — Derivative instruments 15,175 — Oil contracts Non-current assets — Derivative instruments 1,106 — Gas contracts Non-current assets — Derivative instruments 1,224 — Oil contracts Current liabilities — Derivative instruments — 88,814 Gas contracts Current liabilities — Derivative instruments — 1,666 Oil contracts Non-current liabilities — Derivative instruments — 11,237 Gas contracts Non-current liabilities — Derivative instruments — 274 Total gross amounts presented in the balance sheet 75,273 101,991 Less: gross amounts not offset in the balance sheet (68,377 ) (68,377 ) Net amount $ 6,896 $ 33,614 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 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 | 6 Months Ended |
Jun. 30, 2018 | |
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 June 30, 2018 and December 31, 2017 : June 30, 2018 December 31, 2017 (in thousands) Book Value Fair Value Book Value Fair Value Financial Assets (Liabilities): 4.375% Notes due 2024 $ (750,000 ) $ (758,228 ) $ (750,000 ) $ (797,010 ) 3.90% Notes due 2027 $ (750,000 ) $ (721,763 ) $ (750,000 ) $ (767,813 ) Derivative instruments — assets $ 75,273 $ 75,273 $ 17,237 $ 17,237 Derivative instruments — liabilities $ (101,991 ) $ (101,991 ) $ (46,334 ) $ (46,334 ) 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 3 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 June 30, 2018 were accrued operating expenses of approximately $59.6 million . Included in “Accrued liabilities — Other” at December 31, 2017 were: (i) accrued operating expenses of approximately $61.3 million and (ii) accrued general and administrative, primarily payroll-related, costs of approximately $54.6 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 June 30, 2018 and December 31, 2017 , the allowance for doubtful accounts was $2.7 million and $2.2 million , respectively. |
CAPITAL STOCK
CAPITAL STOCK | 6 Months Ended |
Jun. 30, 2018 | |
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 June 30, 2018 , there were 95.4 million shares of common stock and no shares of preferred stock outstanding. Dividends In May 2018 , our Board of Directors declared a cash dividend of $0.16 per share. The dividend is payable on or before August 31, 2018 to stockholders of record on August 15, 2018 . 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. The $15.3 million dividend declared during the first quarter 2018 was recorded as a reduction of additional paid-in capital, while the $15.3 million dividend declared during the second quarter 2018 was recorded as a reduction of retained earnings. Nonforfeitable dividends paid on stock awards that subsequently forfeit are reclassified out of retained earnings or additional paid-in capital, as applicable, to compensation expense in the period in which the forfeitures occur. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors. |
STOCK-BASED COMPENSATION
STOCK-BASED COMPENSATION | 6 Months Ended |
Jun. 30, 2018 | |
Retirement Benefits [Abstract] | |
STOCK-BASED COMPENSATION | STOCK-BASED COMPENSATION We have recognized stock-based compensation cost as shown below for the periods indicated. Three Months Ended Six Months Ended (in thousands) 2018 2017 2018 2017 Restricted stock awards: Performance stock awards $ 3,809 $ 6,438 $ 10,538 $ 12,840 Service-based stock awards 4,247 4,208 9,319 9,132 8,056 10,646 19,857 21,972 Stock option awards 637 579 1,254 1,245 Total stock compensation cost 8,693 11,225 21,111 23,217 Less amounts capitalized to oil and gas properties (5,598 ) (4,932 ) (11,286 ) (10,636 ) Stock compensation expense $ 3,095 $ 6,293 $ 9,825 $ 12,581 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 decrease in total stock compensation cost in the 2018 periods as compared to the 2017 periods is primarily due to performance stock award forfeitures during the three months ended June 30, 2018 . Our accounting policy is to account for forfeitures in compensation cost when they occur. |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 6 Months Ended |
Jun. 30, 2018 | |
Asset Retirement Obligation [Abstract] | |
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 plugging and abandonment of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is accreted each period. If there is a change in the estimated cost or timing of retirement, 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 depreciation and depletion calculations. The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the six months ended June 30, 2018 : (in thousands) Six Months Ended Asset retirement obligation at January 1, 2018 $ 169,469 Liabilities incurred 3,921 Liability settlements and disposals (10,103 ) Accretion expense 3,712 Revisions of estimated liabilities 999 Asset retirement obligation at June 30, 2018 167,998 Less current obligation (8,430 ) Long-term asset retirement obligation $ 159,568 |
EARNINGS PER SHARE
EARNINGS PER SHARE | 6 Months Ended |
Jun. 30, 2018 | |
Earnings Per Share [Abstract] | |
EARNINGS PER SHARE | EARNINGS PER SHARE The calculations of basic and diluted net earnings per common share under the two-class method are presented below for the periods indicated: Three Months Ended June 30, 2018 2017 (in thousands, except per share information) Income (Numerator) Shares (Denominator) Per-Share Amount Income (Numerator) Shares (Denominator) Per-Share Amount Net income $ 140,997 $ 97,262 Less: net income attributable to participating securities (1,892 ) (1,643 ) Basic earnings per share Income available to common stockholders 139,105 93,728 $ 1.48 95,619 93,402 $ 1.02 Effects of dilutive securities Options (1) — 31 1 33 Diluted earnings per share Income available to common stockholders and assumed conversions $ 139,105 93,759 $ 1.48 $ 95,620 93,435 $ 1.02 Six Months Ended June 30, 2018 2017 (in thousands, except per share information) Income (Numerator) Shares (Denominator) Per-Share Amount Income (Numerator) Shares (Denominator) Per-Share Amount Net income $ 327,315 $ 228,234 Less: net income attributable to participating securities (4,546 ) (3,898 ) Basic earnings per share Income available to common stockholders 322,769 93,713 $ 3.44 224,336 93,396 $ 2.40 Effects of dilutive securities Options (1) 1 35 1 35 Diluted earnings per share Income available to common stockholders and assumed conversions $ 322,770 93,748 $ 3.44 $ 224,337 93,431 $ 2.40 ________________________________________ (1) Inclusion of certain shares would have an anti-dilutive effect; therefore, 292.1 thousand and 295.6 thousand shares were excluded from the calculations for the three and six months ended June 30, 2018 and 300.5 thousand and 255.0 thousand shares were excluded from the calculations for the three and six months ended June 30, 2017 . |
INCOME TAXES
INCOME TAXES | 6 Months Ended |
Jun. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES The components of our provision for income taxes are as follows: Three Months Ended Six Months Ended (in thousands) 2018 2017 2018 2017 Current tax benefit $ (717 ) $ — $ (717 ) $ (6 ) Deferred tax expense 42,783 58,617 99,732 136,929 $ 42,066 $ 58,617 $ 99,015 $ 136,923 Combined federal and state effective income tax rate 23.0 % 37.6 % 23.2 % 37.5 % At December 31, 2017 , we had a U.S. net tax operating loss carryforward of approximately $1,377.7 million , which will expire in tax years 2031 through 2037. We believe that the carryforward will be utilized before it expires. We also had an alternative minimum tax credit carryforward of approximately $3.0 million and other credits of $0.9 million . At June 30, 2018 , we had no unrecognized tax benefits that would impact our effective tax rate and 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 . Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 21% in 2018 and 35% in 2017 primarily due to state income taxes and non-deductible expenses. As a result of the enactment of H.R.1, known as the Tax Cuts and Jobs Act, on December 22, 2017, we remeasured our 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 . 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. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 6 Months Ended |
Jun. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES Commitments At June 30, 2018 , we had estimated commitments of approximately: (i) $154.4 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $14.4 million to finish gathering system construction in progress. At June 30, 2018 , we had firm sales contracts to deliver approximately 330.7 Bcf of gas over the next 6.6 years . If we do not deliver this gas, our estimated financial commitment, calculated using the July 2018 index price, would be approximately $659.9 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 9.5 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 June 30, 2018 , would be approximately $351.0 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 June 30, 2018 , would be approximately $7.4 million . Of this total, we have accrued a liability of $2.5 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points. At June 30, 2018 , we have various firm transportation agreements for gas pipeline capacity with end dates ranging from 2018 - 2025 under which we will have to pay an estimated $26.6 million over the remaining terms of the agreements. These agreements were entered into to support our residue gas marketing efforts, and we believe we have sufficient reserves that will utilize this firm transportation. At June 30, 2018 , we have various future commitments under operating lease arrangements for commercial real estate, consisting primarily of office space, and compressor equipment. The commitments under the commercial real estate operating leases, which have lease terms expiring within the next 8.2 years , total approximately $80.9 million . The commitments under the compressor equipment operating leases, which have lease terms expiring within the next 2 - 24 months, total approximately $9.3 million . All of the noted commitments were routine and made in the ordinary course of our business. Litigation We have various litigation matters related to the ordinary course of our business. We assess the probability of estimable amounts related to these matters in accordance with guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, we believe the resolution of them, 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. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 6 Months Ended |
Jun. 30, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Three Months Ended Six Months Ended (in thousands) 2018 2017 2018 2017 Cash paid during the period for: Interest expense (net of capitalized amounts of $9,233, $11,659, $9,389, and $11,962, respectively) $ 22,954 $ 28,115 $ 23,343 $ 28,772 Income taxes $ — $ 1 $ — $ 3 Cash received for income tax refunds $ 717 $ — $ 718 $ 21 |
BASIS OF PRESENTATION (Policies
BASIS OF PRESENTATION (Policies) | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | BASIS OF PRESENTATION The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. (“Cimarex,” “we,” or “us”) pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in Annual Reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the financial statements, summary of significant accounting policies, and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2017 . In the opinion of management, the accompanying financial statements reflect all adjustments necessary to fairly present our financial position, results of operations, and cash flows for the periods and as of the dates shown. Certain amounts in the prior year financial statements have been reclassified to conform to the 2018 financial statement presentation. |
Use of Estimates | Use of Estimates 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. |
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 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. Under the full cost method of accounting, we are required to perform a quarterly ceiling test calculation 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. The calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. We did not recognize a ceiling test impairment during the six months ended June 30, 2018 and 2017 because the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation. If pricing conditions deteriorate, including the further widening of local market basis differentials, 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. 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. |
Revenue Recognition | Revenue Recognition Oil, Gas, and NGL Sales Effective January 1, 2018, we adopted the provisions of Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”), utilizing the modified retrospective approach, which we applied to contracts that were not completed as of that date. Because we utilized the modified retrospective approach, there was no impact to prior periods’ reported amounts. Application of ASC 606 has no impact on our net income or cash flows from operations; however, certain costs classified as Transportation, processing, and other operating expenses in the statement of operations under prior accounting standards are now reflected as deductions from revenue under ASC 606. The following tables present the impact on our Oil sales, Gas sales, and NGL sales and on our Transportation, processing, and other operating costs from the application of ASC 606 in the current reporting period: Three Months Ended 2018 2017 (in thousands) Pre- Impact of Post- As Reported Oil sales $ 342,184 $ — $ 342,184 $ 232,453 Gas sales 84,727 (3,940 ) 80,787 132,474 NGL sales 125,126 (3,711 ) 121,415 80,886 Total oil, gas, and NGL sales $ 552,037 $ (7,651 ) $ 544,386 $ 445,813 Transportation, processing, and other operating costs $ 59,584 $ (7,651 ) $ 51,933 $ 58,624 Six Months Ended 2018 2017 (in thousands) Pre- Impact of Post- As Reported Oil sales $ 693,907 $ — $ 693,907 $ 456,519 Gas sales 197,404 (6,896 ) 190,508 264,419 NGL sales 230,739 (15,327 ) 215,412 161,312 Total oil, gas, and NGL sales $ 1,122,050 $ (22,223 ) $ 1,099,827 $ 882,250 Transportation, processing, and other operating costs $ 119,321 $ (22,223 ) $ 97,098 $ 113,647 Revenue is recognized from the sales of oil, gas, and NGLs when the customer obtains control of the product, when we have no further obligations to perform related to the sale, and when collectability is probable. All of our sales of oil, gas, and NGLs are made under contracts with customers, which typically include variable consideration based on monthly pricing tied to local indices and monthly volumes delivered. The nature of our contracts with customers does not require us to constrain that variable consideration or to estimate the amount of transaction price attributable to future performance obligations for accounting purposes. As of June 30, 2018 , we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas, and/or NGLs. Our contracts with customers typically require payment within one month of delivery. Our gas and NGLs are sold under a limited number of contract structure types common in our industry. Under these contracts the gas and its components, including NGLs, may be sold to a single purchaser or the residue gas and NGLs may be sold to separate purchasers. Regardless of the contract structure type, the terms of these contracts compensate us for the value of the residue gas and NGLs at current market prices for each product, and are disaggregated in the tables above on that basis. Our oil typically is sold at specific delivery points under contract terms that also are common in our industry. 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 may earn a fee for such services. Revenues from such services are recognized as gas is delivered. 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. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) . The key provision of this ASU is that a lessee must recognize on its balance sheet: (i) liabilities to make lease payments and (ii) right-of-use assets. The ASU permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than 12 months. Under current generally accepted accounting principles, 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 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 evaluating the potential impact of adopting this guidance and do not intend to adopt the standard early. |
BASIS OF PRESENTATION (Tables)
BASIS OF PRESENTATION (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Components of Oil, Gas, and NGL Sales | The following tables present the impact on our Oil sales, Gas sales, and NGL sales and on our Transportation, processing, and other operating costs from the application of ASC 606 in the current reporting period: Three Months Ended 2018 2017 (in thousands) Pre- Impact of Post- As Reported Oil sales $ 342,184 $ — $ 342,184 $ 232,453 Gas sales 84,727 (3,940 ) 80,787 132,474 NGL sales 125,126 (3,711 ) 121,415 80,886 Total oil, gas, and NGL sales $ 552,037 $ (7,651 ) $ 544,386 $ 445,813 Transportation, processing, and other operating costs $ 59,584 $ (7,651 ) $ 51,933 $ 58,624 Six Months Ended 2018 2017 (in thousands) Pre- Impact of Post- As Reported Oil sales $ 693,907 $ — $ 693,907 $ 456,519 Gas sales 197,404 (6,896 ) 190,508 264,419 NGL sales 230,739 (15,327 ) 215,412 161,312 Total oil, gas, and NGL sales $ 1,122,050 $ (22,223 ) $ 1,099,827 $ 882,250 Transportation, processing, and other operating costs $ 119,321 $ (22,223 ) $ 97,098 $ 113,647 |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Long-term Debt, Unclassified [Abstract] | |
Schedule of Debt | Long-term debt at June 30, 2018 and December 31, 2017 consisted of the following: June 30, 2018 December 31, 2017 (in thousands) Principal Unamortized Debt Issuance Costs and Discount (1) Long-term Debt, net Principal Unamortized Debt Issuance Costs and Discount (1) Long-term Debt, net 4.375% Senior Notes $ 750,000 $ (4,906 ) $ 745,094 $ 750,000 $ (5,383 ) $ 744,617 3.90% Senior Notes 750,000 (7,355 ) 742,645 750,000 (7,697 ) 742,303 Total long-term debt $ 1,500,000 $ (12,261 ) $ 1,487,739 $ 1,500,000 $ (13,080 ) $ 1,486,920 ________________________________________ (1) At June 30, 2018 , the unamortized debt issuance costs and discount related to the 3.90% notes were $5.7 million and $1.7 million , respectively. 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) | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments and Hedges, Assets [Abstract] | |
Schedule of Outstanding Hedging Contracts Relative to Future Production | The following tables summarize our outstanding derivative contracts as of June 30, 2018 (subsequent to June 30, 2018 through August 6, 2018, we have not entered into any additional derivative contracts): Oil Collars First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018: WTI (1) Volume (Bbls) — — 3,220,000 2,668,000 5,888,000 Weighted Avg Price - Floor $ — $ — $ 49.80 $ 51.03 $ 50.36 Weighted Avg Price - Ceiling $ — $ — $ 60.49 $ 61.74 $ 61.06 2019: WTI (1) Volume (Bbls) 2,070,000 2,093,000 1,472,000 736,000 6,371,000 Weighted Avg Price - Floor $ 51.83 $ 51.83 $ 53.50 $ 57.00 $ 52.81 Weighted Avg Price - Ceiling $ 63.77 $ 63.77 $ 67.13 $ 68.04 $ 65.04 ________________________________________ (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) — — 11,960,000 9,200,000 21,160,000 Weighted Avg Price - Floor $ — $ — $ 2.19 $ 2.12 $ 2.16 Weighted Avg Price - Ceiling $ — $ — $ 2.48 $ 2.42 $ 2.45 Perm EP (2) Volume (MMBtu) — — 9,200,000 7,360,000 16,560,000 Weighted Avg Price - Floor $ — $ — $ 1.92 $ 1.81 $ 1.87 Weighted Avg Price - Ceiling $ — $ — $ 2.14 $ 2.03 $ 2.09 Waha (3) Volume (MMBtu) — — 920,000 920,000 1,840,000 Weighted Avg Price - Floor $ — $ — $ 1.35 $ 1.35 $ 1.35 Weighted Avg Price - Ceiling $ — $ — $ 1.56 $ 1.56 $ 1.56 2019: PEPL (1) Volume (MMBtu) 8,100,000 8,190,000 5,520,000 2,760,000 24,570,000 Weighted Avg Price - Floor $ 2.08 $ 2.08 $ 1.92 $ 1.90 $ 2.02 Weighted Avg Price - Ceiling $ 2.39 $ 2.39 $ 2.26 $ 2.33 $ 2.36 Perm EP (2) Volume (MMBtu) 6,300,000 6,370,000 4,600,000 1,840,000 19,110,000 Weighted Avg Price - Floor $ 1.73 $ 1.73 $ 1.50 $ 1.35 $ 1.64 Weighted Avg Price - Ceiling $ 1.95 $ 1.95 $ 1.74 $ 1.55 $ 1.86 Waha (3) Volume (MMBtu) 900,000 910,000 920,000 920,000 3,650,000 Weighted Avg Price - Floor $ 1.35 $ 1.35 $ 1.35 $ 1.35 $ 1.35 Weighted Avg Price - Ceiling $ 1.56 $ 1.56 $ 1.56 $ 1.56 $ 1.56 ________________________________________ (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. (3) The index price for these collars is Waha West Texas Natural Gas Index (“Waha”) 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) — — 2,484,000 2,024,000 4,508,000 Weighted Avg Differential (2) $ — $ — $ (3.89 ) $ (4.56 ) $ (4.19 ) 2019: WTI Midland (1) Volume (Bbls) 1,710,000 1,729,000 1,288,000 552,000 5,279,000 Weighted Avg Differential (2) $ (5.17 ) $ (5.17 ) $ (6.84 ) $ (10.73 ) $ (6.16 ) ________________________________________ (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) Losses from Settlements and Changes of Derivative Contracts | The following table presents the components of Loss (gain) on derivative instruments, net for the periods indicated. Three Months Ended Six Months Ended (in thousands) 2018 2017 2018 2017 Change in fair value of derivative instruments, net: Gas contracts $ 14,566 $ (5,748 ) $ 2,777 $ (27,939 ) Oil contracts (397 ) (16,418 ) (5,156 ) (44,148 ) 14,169 (22,166 ) (2,379 ) (72,087 ) Cash (receipts) payments on derivative instruments, net: Gas contracts (9,918 ) (1,308 ) (15,037 ) 1,136 Oil contracts 17,448 965 34,956 4,581 7,530 (343 ) 19,919 5,717 Loss (gain) on derivative instruments, net $ 21,699 $ (22,509 ) $ 17,540 $ (66,370 ) |
Schedule of Derivative Assets and Liabilities | The following tables present the amounts and classifications of our derivative assets and liabilities as of June 30, 2018 and December 31, 2017 , as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts. June 30, 2018 (in thousands) Balance Sheet Location Asset Liability Oil contracts Current assets — Derivative instruments $ 57,768 $ — Gas contracts Current assets — Derivative instruments 15,175 — Oil contracts Non-current assets — Derivative instruments 1,106 — Gas contracts Non-current assets — Derivative instruments 1,224 — Oil contracts Current liabilities — Derivative instruments — 88,814 Gas contracts Current liabilities — Derivative instruments — 1,666 Oil contracts Non-current liabilities — Derivative instruments — 11,237 Gas contracts Non-current liabilities — Derivative instruments — 274 Total gross amounts presented in the balance sheet 75,273 101,991 Less: gross amounts not offset in the balance sheet (68,377 ) (68,377 ) Net amount $ 6,896 $ 33,614 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 |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
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 June 30, 2018 and December 31, 2017 : June 30, 2018 December 31, 2017 (in thousands) Book Value Fair Value Book Value Fair Value Financial Assets (Liabilities): 4.375% Notes due 2024 $ (750,000 ) $ (758,228 ) $ (750,000 ) $ (797,010 ) 3.90% Notes due 2027 $ (750,000 ) $ (721,763 ) $ (750,000 ) $ (767,813 ) Derivative instruments — assets $ 75,273 $ 75,273 $ 17,237 $ 17,237 Derivative instruments — liabilities $ (101,991 ) $ (101,991 ) $ (46,334 ) $ (46,334 ) |
STOCK-BASED COMPENSATION (Table
STOCK-BASED COMPENSATION (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Retirement Benefits [Abstract] | |
Schedule of Recognition of Non-Cash Stock-Based Compensation Costs | We have recognized stock-based compensation cost as shown below for the periods indicated. Three Months Ended Six Months Ended (in thousands) 2018 2017 2018 2017 Restricted stock awards: Performance stock awards $ 3,809 $ 6,438 $ 10,538 $ 12,840 Service-based stock awards 4,247 4,208 9,319 9,132 8,056 10,646 19,857 21,972 Stock option awards 637 579 1,254 1,245 Total stock compensation cost 8,693 11,225 21,111 23,217 Less amounts capitalized to oil and gas properties (5,598 ) (4,932 ) (11,286 ) (10,636 ) Stock compensation expense $ 3,095 $ 6,293 $ 9,825 $ 12,581 |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Asset Retirement Obligation [Abstract] | |
Schedule of Asset Retirement Obligations | The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the six months ended June 30, 2018 : (in thousands) Six Months Ended Asset retirement obligation at January 1, 2018 $ 169,469 Liabilities incurred 3,921 Liability settlements and disposals (10,103 ) Accretion expense 3,712 Revisions of estimated liabilities 999 Asset retirement obligation at June 30, 2018 167,998 Less current obligation (8,430 ) Long-term asset retirement obligation $ 159,568 |
EARNINGS PER SHARE (Tables)
EARNINGS PER SHARE (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
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 per common share under the two-class method are presented below for the periods indicated: Three Months Ended June 30, 2018 2017 (in thousands, except per share information) Income (Numerator) Shares (Denominator) Per-Share Amount Income (Numerator) Shares (Denominator) Per-Share Amount Net income $ 140,997 $ 97,262 Less: net income attributable to participating securities (1,892 ) (1,643 ) Basic earnings per share Income available to common stockholders 139,105 93,728 $ 1.48 95,619 93,402 $ 1.02 Effects of dilutive securities Options (1) — 31 1 33 Diluted earnings per share Income available to common stockholders and assumed conversions $ 139,105 93,759 $ 1.48 $ 95,620 93,435 $ 1.02 Six Months Ended June 30, 2018 2017 (in thousands, except per share information) Income (Numerator) Shares (Denominator) Per-Share Amount Income (Numerator) Shares (Denominator) Per-Share Amount Net income $ 327,315 $ 228,234 Less: net income attributable to participating securities (4,546 ) (3,898 ) Basic earnings per share Income available to common stockholders 322,769 93,713 $ 3.44 224,336 93,396 $ 2.40 Effects of dilutive securities Options (1) 1 35 1 35 Diluted earnings per share Income available to common stockholders and assumed conversions $ 322,770 93,748 $ 3.44 $ 224,337 93,431 $ 2.40 ________________________________________ (1) Inclusion of certain shares would have an anti-dilutive effect; therefore, 292.1 thousand and 295.6 thousand shares were excluded from the calculations for the three and six months ended June 30, 2018 and 300.5 thousand and 255.0 thousand shares were excluded from the calculations for the three and six months ended June 30, 2017 . |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of the Provision for Income Taxes | The components of our provision for income taxes are as follows: Three Months Ended Six Months Ended (in thousands) 2018 2017 2018 2017 Current tax benefit $ (717 ) $ — $ (717 ) $ (6 ) Deferred tax expense 42,783 58,617 99,732 136,929 $ 42,066 $ 58,617 $ 99,015 $ 136,923 Combined federal and state effective income tax rate 23.0 % 37.6 % 23.2 % 37.5 % |
SUPPLEMENTAL CASH FLOW INFORM28
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Schedule of Supplemental Cash Flow Information | Three Months Ended Six Months Ended (in thousands) 2018 2017 2018 2017 Cash paid during the period for: Interest expense (net of capitalized amounts of $9,233, $11,659, $9,389, and $11,962, respectively) $ 22,954 $ 28,115 $ 23,343 $ 28,772 Income taxes $ — $ 1 $ — $ 3 Cash received for income tax refunds $ 717 $ — $ 718 $ 21 |
BASIS OF PRESENTATION - Narrati
BASIS OF PRESENTATION - Narrative (Details) | 6 Months Ended |
Jun. 30, 2018 | |
Oil and Gas Properties | |
Discount rate for calculating present value of estimated future net revenues from proved reserves (as a percent) | 10.00% |
Minimum | |
Oil and Gas Delivery Commitments and Contracts [Line Items] | |
Oil and gas delivery commitments and contracts, period | 1 month |
BASIS OF PRESENTATION - Compone
BASIS OF PRESENTATION - Components of Oil, Gas, and NGL Sales (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | $ 556,274 | $ 456,452 | $ 1,123,408 | $ 903,628 |
Transportation, processing, and other operating costs | 51,933 | 58,624 | 97,098 | 113,647 |
Total | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | 544,386 | 445,813 | 1,099,827 | 882,250 |
Oil sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | 342,184 | 232,453 | 693,907 | 456,519 |
Gas sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | 80,787 | 132,474 | 190,508 | 264,419 |
NGL sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | 121,415 | $ 80,886 | 215,412 | $ 161,312 |
Pre- ASC 606 Adoption | ||||
Disaggregation of Revenue [Line Items] | ||||
Transportation, processing, and other operating costs | 59,584 | 119,321 | ||
Pre- ASC 606 Adoption | Total | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | 552,037 | 1,122,050 | ||
Pre- ASC 606 Adoption | Oil sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | 342,184 | 693,907 | ||
Pre- ASC 606 Adoption | Gas sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | 84,727 | 197,404 | ||
Pre- ASC 606 Adoption | NGL sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | 125,126 | 230,739 | ||
Accounting Standards Update 2014-09 | Impact of ASC 606 | ||||
Disaggregation of Revenue [Line Items] | ||||
Transportation, processing, and other operating costs | (7,651) | (22,223) | ||
Accounting Standards Update 2014-09 | Impact of ASC 606 | Total | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | (7,651) | (22,223) | ||
Accounting Standards Update 2014-09 | Impact of ASC 606 | Oil sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | 0 | 0 | ||
Accounting Standards Update 2014-09 | Impact of ASC 606 | Gas sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | (3,940) | (6,896) | ||
Accounting Standards Update 2014-09 | Impact of ASC 606 | NGL sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total oil, gas, and NGL sales | $ (3,711) | $ (15,327) |
LONG-TERM DEBT - Long-Term Debt
LONG-TERM DEBT - Long-Term Debt Outstanding (Details) - USD ($) | Jun. 30, 2018 | Dec. 31, 2017 | Apr. 10, 2017 | Jun. 30, 2014 |
Debt Instrument | ||||
Principal | $ 1,500,000,000 | $ 1,500,000,000 | ||
Unamortized debt issuance costs and discount | (12,261,000) | (13,080,000) | ||
Long-term debt, net | 1,487,739,000 | 1,486,920,000 | ||
4.375% Senior Notes | ||||
Debt Instrument | ||||
Principal | 750,000,000 | 750,000,000 | $ 750,000,000 | |
Unamortized debt issuance costs and discount | (4,906,000) | (5,383,000) | ||
Long-term debt, net | $ 745,094,000 | 744,617,000 | ||
Interest rate (as a percent) | 4.375% | 4.375% | ||
3.90% Senior Notes | ||||
Debt Instrument | ||||
Principal | $ 750,000,000 | 750,000,000 | $ 750,000,000 | |
Unamortized debt issuance costs and discount | (7,355,000) | (7,697,000) | ||
Long-term debt, net | $ 742,645,000 | 742,303,000 | ||
Interest rate (as a percent) | 3.90% | 3.90% | ||
Unamortized debt issuance costs | $ 5,700,000 | 5,900,000 | ||
Unamortized discount | $ 1,700,000 | $ 1,800,000 |
LONG-TERM DEBT - Bank Debt Narr
LONG-TERM DEBT - Bank Debt Narrative (Details) - USD ($) | 6 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | |
Line of Credit Facility [Line Items] | ||
Unamortized debt issuance costs and discount | $ 12,261,000 | $ 13,080,000 |
Revolving Credit Facility | ||
Line of Credit Facility [Line Items] | ||
Credit facility amount | 1,000,000,000 | |
Credit facility, increase amount option | 1,250,000,000 | |
Borrowings outstanding | 0 | |
Letters of credit outstanding under the credit facility | 2,500,000 | |
Unused borrowing availability | $ 997,500,000 | |
Debt-to-capital ratio (as a percent) | 65.00% | |
Unamortized debt issuance costs and discount | $ 2,700,000 | $ 3,400,000 |
Minimum | Revolving Credit Facility | ||
Line of Credit Facility [Line Items] | ||
Commitment fee rate (as a percent) | 0.125% | |
Maximum | Revolving Credit Facility | ||
Line of Credit Facility [Line Items] | ||
Commitment fee rate (as a percent) | 0.35% | |
London Interbank Offered Rate (LIBOR) | Minimum | Revolving Credit Facility | ||
Line of Credit Facility [Line Items] | ||
Interest rate margin (as a percent) | 1.125% | |
London Interbank Offered Rate (LIBOR) | Maximum | Revolving Credit Facility | ||
Line of Credit Facility [Line Items] | ||
Interest rate margin (as a percent) | 2.00% | |
Base Rate | Minimum | Revolving Credit Facility | ||
Line of Credit Facility [Line Items] | ||
Interest rate margin (as a percent) | 0.125% | |
Base Rate | Maximum | Revolving Credit Facility | ||
Line of Credit Facility [Line Items] | ||
Interest rate margin (as a percent) | 1.00% |
LONG-TERM DEBT - Senior Notes N
LONG-TERM DEBT - Senior Notes Narrative (Details) - USD ($) | Apr. 10, 2017 | Jun. 30, 2018 | Dec. 31, 2017 | Jun. 30, 2014 |
Debt Instrument | ||||
Principal amount | $ 1,500,000,000 | $ 1,500,000,000 | ||
3.90% Senior Notes | ||||
Debt Instrument | ||||
Principal amount | $ 750,000,000 | $ 750,000,000 | 750,000,000 | |
Interest rate (as a percent) | 3.90% | 3.90% | ||
Issuance price relative to par value (as a percent) | 99.748% | |||
Effective rate (as a percent) | 3.93% | 4.01% | ||
4.375% Senior Notes | ||||
Debt Instrument | ||||
Principal amount | $ 750,000,000 | $ 750,000,000 | $ 750,000,000 | |
Interest rate (as a percent) | 4.375% | 4.375% | ||
Effective rate (as a percent) | 4.50% |
DERIVATIVE INSTRUMENTS - Outsta
DERIVATIVE INSTRUMENTS - Outstanding Derivative Contracts (Details) - Outstanding at end of period | 6 Months Ended |
Jun. 30, 2018MMBTU$ / bbl$ / MMBTUbbl | |
Derivative Contract Oil Collar WTI Index | 2018 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 5,888,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | $ / bbl | 50.36 |
Weighted Avg Price - Ceiling (USD per Bbl) | $ / bbl | 61.06 |
Derivative Contract Oil Collar WTI Index | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 3,220,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | $ / bbl | 49.80 |
Weighted Avg Price - Ceiling (USD per Bbl) | $ / bbl | 60.49 |
Derivative Contract Oil Collar WTI Index | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 2,668,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | $ / bbl | 51.03 |
Weighted Avg Price - Ceiling (USD per Bbl) | $ / bbl | 61.74 |
Derivative Contract Oil Collar WTI Index | 2019 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 6,371,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | $ / bbl | 52.81 |
Weighted Avg Price - Ceiling (USD per Bbl) | $ / bbl | 65.04 |
Derivative Contract Oil Collar WTI Index | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 2,070,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | $ / bbl | 51.83 |
Weighted Avg Price - Ceiling (USD per Bbl) | $ / bbl | 63.77 |
Derivative Contract Oil Collar WTI Index | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 2,093,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | $ / bbl | 51.83 |
Weighted Avg Price - Ceiling (USD per Bbl) | $ / bbl | 63.77 |
Derivative Contract Oil Collar WTI Index | Third Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 1,472,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | $ / bbl | 53.50 |
Weighted Avg Price - Ceiling (USD per Bbl) | $ / bbl | 67.13 |
Derivative Contract Oil Collar WTI Index | Fourth Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 736,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | $ / bbl | 57 |
Weighted Avg Price - Ceiling (USD per Bbl) | $ / bbl | 68.04 |
Derivative Contract Gas Collar PEPL Index | 2018 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 21,160,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 2.16 |
Weighted Avg Price - Ceiling (USD per Bbl) | 2.45 |
Derivative Contract Gas Collar PEPL Index | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 11,960,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 2.19 |
Weighted Avg Price - Ceiling (USD per Bbl) | 2.48 |
Derivative Contract Gas Collar PEPL Index | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 9,200,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 2.12 |
Weighted Avg Price - Ceiling (USD per Bbl) | 2.42 |
Derivative Contract Gas Collar PEPL Index | 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 24,570,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 2.02 |
Weighted Avg Price - Ceiling (USD per Bbl) | 2.36 |
Derivative Contract Gas Collar PEPL Index | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 8,100,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 2.08 |
Weighted Avg Price - Ceiling (USD per Bbl) | 2.39 |
Derivative Contract Gas Collar PEPL Index | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 8,190,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 2.08 |
Weighted Avg Price - Ceiling (USD per Bbl) | 2.39 |
Derivative Contract Gas Collar PEPL Index | Third Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 5,520,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.92 |
Weighted Avg Price - Ceiling (USD per Bbl) | 2.26 |
Derivative Contract Gas Collar PEPL Index | Fourth Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 2,760,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.90 |
Weighted Avg Price - Ceiling (USD per Bbl) | 2.33 |
Derivative Contract Gas Collar Perm EP | 2018 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 16,560,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.87 |
Weighted Avg Price - Ceiling (USD per Bbl) | 2.09 |
Derivative Contract Gas Collar Perm EP | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 9,200,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.92 |
Weighted Avg Price - Ceiling (USD per Bbl) | 2.14 |
Derivative Contract Gas Collar Perm EP | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 7,360,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.81 |
Weighted Avg Price - Ceiling (USD per Bbl) | 2.03 |
Derivative Contract Gas Collar Perm EP | 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 19,110,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.64 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.86 |
Derivative Contract Gas Collar Perm EP | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 6,300,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.73 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.95 |
Derivative Contract Gas Collar Perm EP | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 6,370,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.73 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.95 |
Derivative Contract Gas Collar Perm EP | Third Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 4,600,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.50 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.74 |
Derivative Contract Gas Collar Perm EP | Fourth Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 1,840,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.35 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.55 |
Derivative Contract Gas Collar Waha | 2018 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 1,840,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.35 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.56 |
Derivative Contract Gas Collar Waha | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 920,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.35 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.56 |
Derivative Contract Gas Collar Waha | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 920,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.35 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.56 |
Derivative Contract Gas Collar Waha | 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 3,650,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.35 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.56 |
Derivative Contract Gas Collar Waha | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 900,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.35 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.56 |
Derivative Contract Gas Collar Waha | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 910,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.35 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.56 |
Derivative Contract Gas Collar Waha | Third Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 920,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.35 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.56 |
Derivative Contract Gas Collar Waha | Fourth Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (MMBtu) | MMBTU | 920,000 |
Weighted Average Price | |
Weighted Avg Price - Floor (USD per Bbl) | 1.35 |
Weighted Avg Price - Ceiling (USD per Bbl) | 1.56 |
Derivative Contract Oil Basis Swaps WTI Midland Index | 2018 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 4,508,000 |
Weighted Average Price | |
Weighted Avg Differential (USD per Bbl) | $ / bbl | (4.19) |
Derivative Contract Oil Basis Swaps WTI Midland Index | Third Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 2,484,000 |
Weighted Average Price | |
Weighted Avg Differential (USD per Bbl) | $ / bbl | (3.89) |
Derivative Contract Oil Basis Swaps WTI Midland Index | Fourth Quarter - 2018 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 2,024,000 |
Weighted Average Price | |
Weighted Avg Differential (USD per Bbl) | $ / bbl | (4.56) |
Derivative Contract Oil Basis Swaps WTI Midland Index | 2019 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 5,279,000 |
Weighted Average Price | |
Weighted Avg Differential (USD per Bbl) | $ / bbl | (6.16) |
Derivative Contract Oil Basis Swaps WTI Midland Index | First Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 1,710,000 |
Weighted Average Price | |
Weighted Avg Differential (USD per Bbl) | $ / bbl | (5.17) |
Derivative Contract Oil Basis Swaps WTI Midland Index | Second Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 1,729,000 |
Weighted Average Price | |
Weighted Avg Differential (USD per Bbl) | $ / bbl | (5.17) |
Derivative Contract Oil Basis Swaps WTI Midland Index | Third Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 1,288,000 |
Weighted Average Price | |
Weighted Avg Differential (USD per Bbl) | $ / bbl | (6.84) |
Derivative Contract Oil Basis Swaps WTI Midland Index | Fourth Quarter - 2019 | |
Fair values of derivative assets and liabilities | |
Volume (Bbls) | bbl | 552,000 |
Weighted Average Price | |
Weighted Avg Differential (USD per Bbl) | $ / bbl | (10.73) |
DERIVATIVE INSTRUMENTS - (Gain)
DERIVATIVE INSTRUMENTS - (Gain) Loss on Derivative Instruments (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Derivative [Line Items] | ||||
Change in fair value of derivative instruments, net: | $ 14,169 | $ (22,166) | $ (2,379) | $ (72,087) |
Cash (receipts) payments on derivative instruments, net: | 7,530 | (343) | 19,919 | 5,717 |
Loss (gain) on derivative instruments, net | 21,699 | (22,509) | 17,540 | (66,370) |
Gas contracts | ||||
Derivative [Line Items] | ||||
Change in fair value of derivative instruments, net: | 14,566 | (5,748) | 2,777 | (27,939) |
Cash (receipts) payments on derivative instruments, net: | (9,918) | (1,308) | (15,037) | 1,136 |
Oil contracts | ||||
Derivative [Line Items] | ||||
Change in fair value of derivative instruments, net: | (397) | (16,418) | (5,156) | (44,148) |
Cash (receipts) payments on derivative instruments, net: | $ 17,448 | $ 965 | $ 34,956 | $ 4,581 |
DERIVATIVE INSTRUMENTS - Deriva
DERIVATIVE INSTRUMENTS - Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Asset | ||
Total gross amounts presented in the balance sheet | $ 72,943 | $ 15,151 |
Liability | ||
Total gross amounts presented in the balance sheet | 90,480 | 42,066 |
Not Designated as Hedging Instrument | ||
Asset | ||
Total gross amounts presented in the balance sheet | 75,273 | 17,237 |
Less: gross amounts not offset in the balance sheet | (68,377) | (17,237) |
Net amount | 6,896 | 0 |
Liability | ||
Total gross amounts presented in the balance sheet | 101,991 | 46,334 |
Less: gross amounts not offset in the balance sheet | (68,377) | (17,237) |
Net amount | 33,614 | 29,097 |
Not Designated as Hedging Instrument | Oil contracts | Current assets — Derivative instruments | ||
Asset | ||
Total gross amounts presented in the balance sheet | 57,768 | |
Not Designated as Hedging Instrument | Oil contracts | Non-current assets — Derivative instruments | ||
Asset | ||
Total gross amounts presented in the balance sheet | 1,106 | |
Not Designated as Hedging Instrument | Oil contracts | Current liabilities — Derivative instruments | ||
Liability | ||
Total gross amounts presented in the balance sheet | 88,814 | 42,066 |
Not Designated as Hedging Instrument | Oil contracts | Non-current liabilities — Derivative instruments | ||
Liability | ||
Total gross amounts presented in the balance sheet | 11,237 | 4,268 |
Not Designated as Hedging Instrument | Gas contracts | Current assets — Derivative instruments | ||
Asset | ||
Total gross amounts presented in the balance sheet | 15,175 | 15,151 |
Not Designated as Hedging Instrument | Gas contracts | Non-current assets — Derivative instruments | ||
Asset | ||
Total gross amounts presented in the balance sheet | 1,224 | $ 2,086 |
Not Designated as Hedging Instrument | Gas contracts | Current liabilities — Derivative instruments | ||
Liability | ||
Total gross amounts presented in the balance sheet | 1,666 | |
Not Designated as Hedging Instrument | Gas contracts | Non-current liabilities — Derivative instruments | ||
Liability | ||
Total gross amounts presented in the balance sheet | $ 274 |
FAIR VALUE MEASUREMENTS - Narra
FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Other Financial Instruments | ||
Accrued operating expenses | $ 59.6 | $ 61.3 |
Accrued payroll related general and administrative expenses | 54.6 | |
Allowance for Trade Receivables | ||
Other Financial Instruments | ||
Aggregate allowance for doubtful accounts | $ 2.7 | $ 2.2 |
FAIR VALUE MEASUREMENTS - Summa
FAIR VALUE MEASUREMENTS - Summary (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Financial Assets (Liabilities): | ||
Derivative instruments — assets | $ 72,943 | $ 15,151 |
Derivative instruments — liabilities | (90,480) | (42,066) |
Book Value | ||
Financial Assets (Liabilities): | ||
Derivative instruments — assets | 75,273 | 17,237 |
Derivative instruments — liabilities | 101,991 | 46,334 |
Fair Value | ||
Financial Assets (Liabilities): | ||
Derivative instruments — assets | 75,273 | 17,237 |
Derivative instruments — liabilities | 101,991 | 46,334 |
4.375% Notes due 2024 | Book Value | ||
Financial Assets (Liabilities): | ||
Long-term debt | (750,000) | (750,000) |
4.375% Notes due 2024 | Fair Value | ||
Financial Assets (Liabilities): | ||
Long-term debt | (758,228) | (797,010) |
3.90% Notes due 2027 | Book Value | ||
Financial Assets (Liabilities): | ||
Long-term debt | (750,000) | (750,000) |
3.90% Notes due 2027 | Fair Value | ||
Financial Assets (Liabilities): | ||
Long-term debt | $ (721,763) | $ (767,813) |
CAPITAL STOCK - Narrative (Deta
CAPITAL STOCK - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | 3 Months Ended | 6 Months Ended | ||||
May 31, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |||||||
Common stock authorized (shares) | 200,000,000 | 200,000,000 | 200,000,000 | ||||
Preferred stock authorized (shares) | 15,000,000 | 15,000,000 | 15,000,000 | ||||
Common stock outstanding (shares) | 95,400,000 | 95,400,000 | |||||
Preferred stock outstanding (shares) | 0 | 0 | |||||
Dividends | |||||||
Dividends declared (USD per share) | $ 0.16 | $ 0.16 | $ 0.08 | $ 0.32 | $ 0.16 | ||
Dividend declared from APIC | $ 15,300 | $ 15,250 | |||||
Dividends declared from retained earnings | $ 15,300 | $ 15,262 |
STOCK-BASED COMPENSATION - Summ
STOCK-BASED COMPENSATION - Summary (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Options, Restricted Stock and Unit Awards | ||||
Stock compensation cost | $ 8,693 | $ 11,225 | $ 21,111 | $ 23,217 |
Less amounts capitalized to oil and gas properties | (5,598) | (4,932) | (11,286) | (10,636) |
Stock compensation expense | 3,095 | 6,293 | 9,825 | 12,581 |
Restricted stock awards: | ||||
Options, Restricted Stock and Unit Awards | ||||
Stock compensation cost | 8,056 | 10,646 | 19,857 | 21,972 |
Performance stock awards | ||||
Options, Restricted Stock and Unit Awards | ||||
Stock compensation cost | 3,809 | 6,438 | 10,538 | 12,840 |
Service-based stock awards | ||||
Options, Restricted Stock and Unit Awards | ||||
Stock compensation cost | 4,247 | 4,208 | 9,319 | 9,132 |
Stock option awards | ||||
Options, Restricted Stock and Unit Awards | ||||
Stock compensation cost | $ 637 | $ 579 | $ 1,254 | $ 1,245 |
ASSET RETIREMENT OBLIGATIONS -
ASSET RETIREMENT OBLIGATIONS - Summary (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligations | ||
Balance at beginning of year | $ 169,469 | |
Liabilities incurred | 3,921 | |
Liability settlements and disposals | (10,103) | |
Accretion expense | 3,712 | |
Revisions of estimated liabilities | 999 | |
Balance at end of year | 167,998 | |
Less current obligation | (8,430) | |
Long-term asset retirement obligation | $ 159,568 | $ 158,421 |
EARNINGS PER SHARE - Summary (D
EARNINGS PER SHARE - Summary (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Income (Numerator) | ||||
Net income | $ 140,997 | $ 97,262 | $ 327,315 | $ 228,234 |
Less: net income attributable to participating securities | (1,892) | (1,643) | (4,546) | (3,898) |
Basic EPS - Income available to common stockholders | 139,105 | 95,619 | 322,769 | 224,336 |
Diluted EPS - Income available to common stockholders and assumed conversions | $ 139,105 | $ 95,620 | $ 322,770 | $ 224,337 |
Shares (Denominator) | ||||
Basic EPS - Income available to common stockholders (shares) | 93,728,000 | 93,402,000 | 93,713,000 | 93,396,000 |
Effects of dilutive securities - options | $ 0 | $ 1 | $ 1 | $ 1 |
Effects of dilutive securities - options (shares) | 31,000 | 33,000 | 35,000 | 35,000 |
Diluted EPS - Income available to common stockholders and assumed conversions (shares) | 93,759,000 | 93,435,000 | 93,748,000 | 93,431,000 |
Per-Share Amount | ||||
Basic EPS - Income available to common stockholders (USD per share) | $ 1.48 | $ 1.02 | $ 3.44 | $ 2.40 |
Diluted EPS - Income available to common stockholders and assumed conversions (USD per share) | $ 1.48 | $ 1.02 | $ 3.44 | $ 2.40 |
Excluded antidilutive securities (shares) | 292,100 | 300,500 | 295,600 | 255,000 |
INCOME TAXES - Narrative (Detai
INCOME TAXES - Narrative (Details) - USD ($) | Jun. 30, 2018 | Dec. 31, 2017 |
Income Tax Disclosure [Abstract] | ||
U.S. net tax operating loss carryforward | $ 1,377,700,000 | |
Alternative minimum tax credit carryforward | 3,000,000 | |
Other tax credit carryforwards | $ 900,000 | |
Unrecognized tax benefits that would impact the entity's effective rate | $ 0 | |
Provisions for interest or penalties related to uncertain tax positions | $ 0 |
INCOME TAXES - Components of th
INCOME TAXES - Components of the Provision for Income Taxes (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Income Tax Expense (Benefit) | ||||
Current tax benefit | $ (717) | $ 0 | $ (717) | $ (6) |
Deferred tax expense | 42,783 | 58,617 | 99,732 | 136,929 |
Total income tax expense (benefits) | $ 42,066 | $ 58,617 | $ 99,015 | $ 136,923 |
Combined federal and state effective income tax rate | 23.00% | 37.60% | 23.20% | 37.50% |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - Narrative (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2018USD ($)Bcf | |
Minimum | |
Construction, Drilling and Purchase Commitments | |
Oil and gas delivery commitments and contracts, period | 1 month |
Drilling Commitments | |
Construction, Drilling and Purchase Commitments | |
Commitments for purchases and other expenditures | $ 154.4 |
Gathering System Construction | |
Construction, Drilling and Purchase Commitments | |
Commitments for purchases and other expenditures | $ 14.4 |
Natural Gas Sales Contracts | |
Construction, Drilling and Purchase Commitments | |
Oil and gas delivery commitments and contracts, remaining contractual volume (bcf) | Bcf | 330.7 |
Oil and gas delivery commitments and contracts, period | 6 years 7 months |
Maximum financial commitment resulting from inability to meet gas delivery commitments | $ 659.9 |
Gas Gathering And Processing Agreements | |
Construction, Drilling and Purchase Commitments | |
Oil and gas delivery commitments and contracts, period | 9 years 6 months |
Maximum financial commitment resulting from inability to meet gas delivery commitments | $ 351 |
Minimum Volume Agreement | |
Construction, Drilling and Purchase Commitments | |
Maximum financial commitment resulting from inability to meet gas delivery commitments | 7.4 |
Commitment liability | 2.5 |
Other Transportation And Delivery Commitments And Facilities Commitments | |
Construction, Drilling and Purchase Commitments | |
Maximum financial commitment resulting from inability to meet gas delivery commitments | $ 26.6 |
Office Space | |
Construction, Drilling and Purchase Commitments | |
Operating lease term | 8 years 2 months 1 day |
Future minimum payments due on operating leases | $ 80.9 |
Compressor Equipment | |
Construction, Drilling and Purchase Commitments | |
Future minimum payments due on operating leases | $ 9.3 |
Compressor Equipment | Minimum | |
Construction, Drilling and Purchase Commitments | |
Operating lease term | 2 months |
Compressor Equipment | Maximum | |
Construction, Drilling and Purchase Commitments | |
Operating lease term | 24 months |
SUPPLEMENTAL CASH FLOW INFORM46
SUPPLEMENTAL CASH FLOW INFORMATION - Summary (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Cash paid during the period for: | ||||
Interest expense (net of capitalized amounts of $9,233, $11,659, $9,389, and $11,962, respectively) | $ 22,954 | $ 28,115 | $ 23,343 | $ 28,772 |
Income taxes | 0 | 1 | 0 | 3 |
Cash received for income tax refunds | 717 | 0 | 718 | 21 |
Interest capitalized | $ 9,233 | $ 11,659 | $ 9,389 | $ 11,962 |