PDC Energy (PDCE) 10-K 27 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document Document - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 15, 2018	Jun. 30, 2017
Entity Information [Line Items]
Entity Registrant Name	PDC ENERGY, INC.
Entity Central Index Key	77,877
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		65,965,374
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 2,824,081,178

Consolidated Balance Sheets (Au

Consolidated Balance Sheets (Audited) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 180,675	$ 244,100
Accounts receivable, net	197,598	143,392
Fair value of derivatives	14,338	8,791
Prepaid expenses and other current assets	8,613	3,542
Total current assets	401,224	399,825
Properties and equipment, net	3,933,467	4,002,994
Assets held-for-sale, net	40,084	5,272
Fair value of derivatives	0	2,386
Goodwill	0	62,041
Other assets	45,116	13,324
Total Assets	4,419,891	4,485,842
Current liabilities:
Accounts payable	150,067	66,322
Production tax liability	37,654	24,767
Fair value of derivatives	79,302	53,595
Funds held for distribution	95,811	71,339
Accrued interest payable	11,815	15,930
Other accrued expenses	42,987	38,625
Total current liabilities	417,636	270,578
Long-term debt	1,151,932	1,043,954
Deferred income taxes	191,992	400,867
Asset retirement obligations	71,006	82,612
Fair value of derivatives	22,343	27,595
Other liabilities	57,333	37,482
Total liabilities	1,912,242	1,863,088
Shareholders' Equity:
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,955,080 and 65,704,568 issued as of December 31, 2017 and 2016, respectively	659	657
Additional paid-in capital	2,503,294	2,489,557
Retained earnings	6,704	134,208
Treasury shares - at cost, 55,927 and 28,763 as of December 31, 2017 and 2016, respectively	(3,008)	(1,668)
Total stockholders' equity	2,507,649	2,622,754
Total Liabilities and Stockholders' Equity	$ 4,419,891	$ 4,485,842

Balance Sheet Parentheticals (P

Balance Sheet Parentheticals (Parentheticals) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Balance Sheet Parentheticals [Abstract]
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	150,000,000	150,000,000
Common Stock, Shares, Issued	65,955,080	65,704,568
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	50,000,000	50,000,000
Preferred Stock, Shares Issued	0	0
Treasury Stock, Shares	55,927	28,763

Consolidated Statements of Oper

Consolidated Statements of Operations (Audited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Crude oil, natural gas, and NGLs sales									$ 913,084	$ 497,353	$ 378,713
Commodity price risk management gain (loss), net									(3,936)	(125,681)	203,183
Other income									12,468	11,243	13,430
Total revenues					$ 108,097	$ 163,890	$ 20,097	$ 90,831	921,616	382,915	595,326
Costs, expenses and other:
Lease operating expenses									89,641	59,950	56,992
Production taxes									60,717	31,410	18,443
Transportation, gathering, and processing expenses									33,220	18,415	10,151
Exploration, geologic, and geophysical expense									47,334	4,669	1,102
Impairment of properties and equipment									285,887	9,973	161,620
Impairment of goodwill									75,121	0	0
General and administrative expense									120,370	112,470	89,959
Depreciation, depletion and amortization									469,084	416,874	303,258
Provision for uncollectible notes receivable									(40,203)	44,038	0
Accretion of asset retirement obligations									6,306	7,080	6,293
Gain on sale of properties and equipment									766	43	385
Other expenses									13,157	10,193	11,717
Total costs, expenses and other					178,608	179,178	163,379	193,864	1,159,868	715,029	659,150
Loss from operations					(70,511)	(15,288)	(143,282)	(103,033)	(238,252)	(332,114)	(63,824)
Loss on extinguishment of debt									24,747	0	0
Interest expense									(78,694)	(61,972)	(47,571)
Interest income									2,261	963	4,807
Loss before income taxes					(90,636)	(35,341)	(153,777)	(113,369)	(339,432)	(393,123)	(106,588)
Income tax benefit									211,928	147,195	38,308
Net loss					$ (55,639)	$ (23,309)	$ (95,450)	$ (71,530)	$ (127,504)	$ (245,928)	$ (68,280)
Earnings per share attributable to shareholders:
Diluted	$ 1.17	$ (4.44)	$ 0.62	$ 0.70	$ (0.94)	$ (0.48)	$ (2.04)	$ (1.72)	$ (1.94)	$ (5.01)	$ (1.74)
Basic	$ 1.18	$ (4.44)	$ 0.63	$ 0.70	$ (0.94)	$ (0.48)	$ (2.04)	$ (1.72)	$ (1.94)	$ (5.01)	$ (1.74)
Weighted-average common shares outstanding:
Basic									65,837	49,052	39,153
Diluted									65,837	49,052	39,153

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Audited) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Gain (Loss) on Extinguishment of Debt, before Write off of Debt Issuance Cost	$ 24,747,000	$ 0	$ 0
Cash flows from operating activities:
Net loss	(127,504,000)	(245,928,000)	(68,280,000)
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Net change in fair value of unsettled commodity derivatives	17,260,000	333,770,000	35,791,000
Depreciation, depletion and amortization	469,084,000	416,874,000	303,258,000
Provision for uncollectible notes receivable	(40,203,000)	44,038,000	0
Impairment of properties and equipment	285,887,000	9,973,000	161,620,000
Impairment of goodwill	75,121,000	0	0
Capitalized Exploratory Well Cost, Charged to Expense	41,297,000	0	0
Accretion of asset retirement obligations	6,306,000	7,080,000	6,293,000
Stock-based compensation	19,353,000	19,502,000	20,068,000
Gain on sale of properties and equipment	(766,000)	(43,000)	(385,000)
Amortization of debt discount and issuance costs	12,907,000	16,167,000	7,040,000
Deferred income taxes	(203,685,000)	(137,249,000)	(41,415,000)
Other	(2,265,000)	(2,603,000)	3,216,000
Total adjustments to net loss to reconcile to net cash from operating activities:	709,573,000	712,715,000	489,054,000
Changes in current assets and liabilities:
Accounts receivable	(60,546,000)	(32,627,000)	24,815,000
Other assets	(5,886,000)	2,303,000	(2,264,000)
Production tax liability	31,316,000	9,223,000	(1,629,000)
Accounts payable and accrued expenses	31,378,000	(162,000)	(30,310,000)
Funds held for distribution	24,472,000	36,510,000	2,699,000
Asset retirement obligations	(10,176,000)	(4,109,000)	(4,458,000)
Other liabilities	(4,064,000)	8,338,000	1,446,000
Total changes in assets and liabilities	6,494,000	19,476,000	(9,701,000)
Net cash from operating activities	588,563,000	486,263,000	411,073,000
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(737,208,000)	(436,884,000)	(599,546,000)
Capital expenditures for other properties and equipment	(5,094,000)	(3,464,000)	(5,122,000)
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition	(15,628,000)	(1,073,723,000)	0
Proceeds from sale of properties and equipment	9,991,000	4,945,000	405,000
Sale of promissory note	40,203,000	0	0
Increase (Decrease) in Restricted Cash	(9,250,000)	0	0
Sale of short-term investments	49,890,000	0	0
Purchase of short-term investments	(49,890,000)	0	0
Net cash from investing activities	(716,986,000)	(1,509,126,000)	(604,263,000)
Cash flows from financing activities:
Proceeds from issuance of equity, net of issuance costs	0	855,074,000	202,851,000
Proceeds from issuance of senior notes	592,366,000	392,172,000	0
Proceeds from issuance of convertible senior notes	0	193,935,000	0
Proceeds from revolving credit facility	0	85,000,000	397,000,000
Repayment of revolving credit facility	0	(122,000,000)	(416,000,000)
Redemption of senior notes	(519,375,000)	0	0
Redemption of convertible notes	0	(115,000,000)	0
Payment of debt issuance costs	(50,000)	(15,556,000)	(974,000)
Purchase of treasury shares	(6,672,000)	(6,935,000)	(6,055,000)
Other	(1,271,000)	(577,000)	1,152,000
Net cash from financing activities	64,998,000	1,266,113,000	177,974,000
Net change in cash and cash equivalents	(63,425,000)	243,250,000	(15,216,000)
Cash and cash equivalents, beginning of year	244,100,000	850,000	16,066,000
Cash and cash equivalents, end of year	$ 180,675,000	$ 244,100,000	$ 850,000

Consolidated Statement of Equit

Consolidated Statement of Equity (Statement) - USD ($) $ in Thousands	Total	Parent [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued			35,927,985			(21,643)
Shares issued pursuant to sale of equity			4,002,000
Issuance of stock awards, net of forfeitures			244,791
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract]
Retirement of treasury shares						127,159
Issuance of treasury shares						(120,864)
Non-employee directors' deferred compensation plan						(4,872)
Stockholders' Equity Beginning, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2014		$ 1,137,359	$ 359	$ 689,209	$ 448,702	$ (911)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to sale of equity			40	202,811
Purchase of treasury shares		202,851
Issuance of stock awards, net of forfeitures		3	3
Share-based Compensation expense	$ 20,068	21,568		21,568
Issuance of treasury shares		(6,055)				(6,055)
Retirement of treasury shares		0		(6,206)		6,206
Non-employee directors' deferred compensation plan		(249)				(249)
Net income (Loss) attributable to shareholders	(68,280)	(68,280)			(68,280)
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2015		1,287,197	$ 402	907,382	380,422	$ (1,009)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued			40,174,776			(20,220)
Shares issued pursuant to sale of equity			15,007,500
Exercise of stock options			46,084
Issuance of stock awards, net of forfeitures			411,731
Stock Issued During Period, Value, Conversion of Convertible Securities			792,406
Stock Issued During Period, Value, Acquisitions			9,386,768
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract]
Purchase of treasury shares						(116,085)
Issuance of treasury shares			(114,697)			114,697
Non-employee directors' deferred compensation plan						(7,155)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to sale of equity		855,083	$ 150	854,933
Purchase of treasury shares		(6,935)				$ (6,935)
Issuance of stock awards, net of forfeitures		0	3	(3)
Share-based Compensation expense	19,502	19,502		19,502
Issuance of treasury shares		0		(6,661)		6,661
Non-employee directors' deferred compensation plan		(385)				(385)
Net income (Loss) attributable to shareholders	(245,928)	(245,928)			(245,928)
Cumulative Effect on Retained Earnings, Net of Tax					(286)
Stock Issued During Period, Value, Conversion of Convertible Securities		0	8	(8)
Stock Issued During Period, Value, Acquisitions		690,702	94	690,608
Adjustments to Additional Paid in Capital, Convertible Debt with Conversion Feature		23,518		23,518
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2016		2,622,754	$ 657	2,489,557	134,208	$ (1,668)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' Equity, Other		0		286
Shares, Issued			65,704,568			(28,763)
Issuance of stock awards, net of forfeitures			250,512
Purchase of treasury shares						(107,357)
Issuance of treasury shares						83,228
Non-employee directors' deferred compensation plan						(3,035)
Purchase of treasury shares		(6,672)				$ (6,672)
Issuance of stock awards, net of forfeitures		0	$ 2	(2)
Share-based Compensation expense	19,353	19,353		19,353
Issuance of treasury shares		0		(5,517)		5,517
Non-employee directors' deferred compensation plan		(185)				(185)
Net income (Loss) attributable to shareholders	$ (127,504)	(127,504)			(127,504)
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2017		2,507,649	$ 659	2,503,294	$ 6,704	$ (3,008)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' Equity, Other		$ (97)		$ (97)
Shares, Issued			65,955,080			(55,927)

NATURE OF OPERATIONS AND BASIS

NATURE OF OPERATIONS AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2017
NATURE OF OPERATIONS AND BASIS OF PRESENTATION [Abstract]
Nature of Operations [Text Block]	NATURE OF OPERATIONS AND BASIS OF PRESENTATION PDC Energy, Inc. ("PDC", the "Company," "we," "us," or "our") is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas, and NGLs, with primary operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas . Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are currently focused in the Wolfcamp zones. We also have operations in the Utica Shale in Southeastern Ohio; however, in 2017, we began actively marketing the Utica Shale properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification during the third quarter of 2017. In February 2018, we entered into a PSA for the sale of these properties for net cash proceeds of approximately $40.0 million , subject to the terms and conditions of the agreement. As of December 31, 2017 , we owned an interest in approximately 2,800 productive gross wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Beginning in 2017, our gas marketing segment does not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all periods presented. The audited consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of our two affiliated partnerships. All intercompany accounts and transactions have been eliminated in consolidation. The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas, and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill; valuation and allocations of purchased businesses and assets; estimates of fair value of our fixed rate debt instruments; and valuation of deferred income tax assets. Certain immaterial reclassifications have been made to our prior period balance sheet and statement of operations to conform to the current period presentation. The reclassifications had no impact on previously reported cash flows, net earnings, earnings per share, or stockholders' equity.

RECENT ACCOUNTING STANDARDS

RECENT ACCOUNTING STANDARDS	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. Commodity Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas, and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes. All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We use the normal purchase, normal sale exception for our crude oil and natural gas contracts. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose for issuing or holding the derivative. Net settlements and changes in the fair value of commodity derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Net settlements and changes in the fair value of commodity derivative instruments related to our Gas Marketing segment are recorded in other income and other expenses. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows. The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells, and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have three units-of-production fields: the Wattenberg Field, the Delaware Basin, and the Utica Shale. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations, and common cost environments in these areas. We calculate quarterly depreciation, depletion, and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statement of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leasehold, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability, or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded. Proved Property Impairment. Upon a triggering event, including when general industry conditions warrant review, we assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity will be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas, and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices, or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis. The impairment recorded is the amount by which the net capitalized costs exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A. Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired, or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates, and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment. Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. The following table presents the estimated useful lives of our other property and equipment: Transportation, pipeline, and other equipment 2 - 30 years Buildings 20 - 40 years Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto, and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $6.6 million , $3.8 million , and $4.5 million in 2017 , 2016 , and 2015 , respectively. Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $5.0 million , $4.5 million , and $5.1 million in 2017 , 2016 , and 2015 , respectively. Goodwill. Goodwill represents the excess of the purchase price over the fair value of net assets acquired, including the additional value resulting from the creation of the deferred tax liability, and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that could contribute to a purchase price in excess of the fair value of the net tangible and intangible assets acquired is the acquisition of an element of a workforce and the expected value from operations of the acquisition to be derived in the future, such as production from future development of additional producing zones. We evaluate goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit to the carrying value. We determine the fair value of the goodwill at the impairment evaluation date by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value is based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third parties, earnings multiples, or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held-for-sale. Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem, and property taxes, to be paid to the states and counties in which we produce crude oil, natural gas, and NGLs. These taxes are expensed and included in the statements of operations line item production taxes. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $50.5 million and $29.0 million in December 31, 2017 and 2016 , respectively. Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2017 and 2016 , we had no valuation allowance. Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes, and the 2026 Senior Notes are included in long-term debt on the consolidated balance sheets and the debt issuance costs for the revolving credit facility are included in other assets on the consolidated balance sheets. Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations. Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below. Crude oil, natural gas, and NGLs sales. Crude oil, natural gas, and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred, and collection of revenue is reasonably assured. Our crude oil, natural gas, and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when the purchasers of these commodities also provide transportation, gathering, or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when the purchasers do not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering, and processing expenses. There is a new revenue standard effective for annual reporting periods beginning after December 15, 2017. See Recently Issued Accounting Standards below. Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices, and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties, and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. No amounts for stock-based compensation were capitalized in 2017 , 2016 , or 2015 . Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas, and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices, or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. Recently Adopted Accounting Standards. In January 2017, the FASB issued an accounting update to simplify the measurement of goodwill. The update eliminates the two-step process that required identification of potential impairment and a separate measure of actual impairment. The annual and/or interim assessments are still required to be completed. The guidance is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the second quarter of 2017. Our annual evaluation of goodwill for impairment was expected to occur in the fourth quarter of 2017; however, we experienced an impairment triggering event as of September 30, 2017 and implemented the new guidance as part of the impairment evaluation. See the footnote titled Goodwill for a detailed description of the results of our impairment testing. In August 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the fourth quarter of 2017. Adoption of this standard did not have an impact on our consolidated financial statements or related disclosures. In January 2017, the FASB issued an accounting update clarifying the definition of a business, with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This guidance is to be applied using a prospective method and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the fourth quarter of 2017. Adoption of this standard did not have an impact on our consolidated financial statements or related disclosures. In May 2017, the FASB issued an accounting update clarifying when to account for a change to the terms or conditions of a share-based payment award as a modification. The guidance is effective for fiscal years beginning on or after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the fourth quarter of 2017. Adoption of this standard did not have an impact on our consolidated financial statements or related disclosures. Recently Issued Accounting Standards In May 2014, the FASB and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The standard has been updated and now includes technical corrections. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations, and (5) recognize revenue when or as each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period; we are adopting the standard effective January 1, 2018. The revenue standard can be adopted under the full retrospective method or modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard will have on our consolidated financial statements, we have performed a comprehensive review of our significant revenue streams. The focus of this review included, among other things, the identification of the significant contracts and other arrangements we have with our customers to identify performance obligations and principal versus agent considerations, and factors affecting the determination of the transaction price. We are also reviewing our current accounting policies, procedures, and controls with respect to these contracts and arrangements to determine what changes, if any, may be required by the adoption of the revenue standard. We have determined that we will adopt the standard under the modified retrospective method. Based upon our review, we currently estimate that adoption of the standard would have reduced our crude oil, natural gas, and NGLs sales by approximately $11.3 million in 2017 with corresponding decreases in transportation, gathering, and processing expenses and no impact on net earnings. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are currently evaluating the impact these changes may have on our consolidated financial statements. In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements. In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements.

BUSINESS COMBINATIONS BUSINESS

BUSINESS COMBINATIONS BUSINESS COMBINATIONS (Notes)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Schedule of Intangible Assets and Goodwill [Table Text Block]	The following table presents the changes in goodwill from the preliminary allocation at December 31, 2016, and the final allocation determined during the third quarter of 2017: Amount (in thousands) Preliminary purchase price allocation $ 62,041 Adjustments 13,080 Final purchase price allocation $ 75,121
Business Acquisition, Pro Forma Information [Table Text Block]		Pro Forma Information. The results of operations for the Delaware Basin acquisition have been included in our consolidated financial statements since the December 6, 2016 closing date, including approximately $5.6 million of total revenue and $1.7 million of loss from operations in our statements of operations for the year ended December 31, 2016. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2016 and December 31, 2015, assuming the acquisition had been completed as of January 1, 2015. This pro forma financial information includes proceeds from the sale of 9,085,000 shares of our common stock, the 2021 Convertible Notes, and the 2024 Senior Notes in September 2016, the shares issued to the sellers, and other acquisition costs. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results. Years Ended December 31, 2016 2015 (in thousands, except per share amounts) Total revenue $ 412,746 $ 598,932 Net loss $ (270,942 ) $ (138,904 ) Earnings per share: Basic and diluted $ (4.22 ) $ (2.41 )
Business Combination Disclosure [Text Block]		BUSINESS COMBINATIONS Delaware Basin Acquisition. On December 6, 2016, we closed on an acquisition which was accounted for as a business combination. The acquisition consisted of the purchase of stock of an entity and assets of other entities under common control. The transaction was for the purchase of approximately 57,900 net acres, approximately 30 completed and producing wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion , after preliminary post-closing adjustments. The total consideration to sellers was comprised of approximately $ 946.0 million in cash, including the payment of $ 40.0 million of debt of the sellers at closing and other purchase price adjustments, and 9.4 million shares of our common stock valued at approximately $ 690.7 million at the time the acquisition closed. The purchase accounting for the entity, the stock of which we acquired, reflected oil and gas assets for which we did not receive a fair value step-up of the tax basis. As a result, a significant deferred income tax liability was calculated based on the acquired allocated fair value of the assets in excess of the tax basis of assets inside the entity. This calculation resulted in approximately $ 375.0 million of non-cash basis needing to be allocated to the acquired assets. No deferred tax liability was established for the calculated goodwill as it did not qualify as tax goodwill. The final fair value allocation of the assets acquired and liabilities assumed in the acquisition are presented below and include customary post-closing adjustments. The most significant item to be completed during the final purchase price allocation in the third quarter of 2017 was the final allocation of value to the unproved oil and gas properties associated with the acquired acreage. Adjustments to the preliminary purchase price primarily stem from additional information we obtained about facts and circumstances that existed at the acquisition date that impact the underlying value of certain assets acquired and liabilities assumed, including detailed lease terms, location of the acreage, and intent to develop the acreage as of the date of closing. There were a significant number of leases acquired with complex lease terms and evaluation of these terms and the timing of the lease expirations impacted the manner in which the final purchase price was allocated. Our final determination of the value of goodwill has been adjusted for all post-closing adjustments. The details of the final purchase price and the allocation of the purchase price for the transaction, are presented below (in thousands): Year Ended December 31, 2016 Acquisition costs: Cash, net of cash acquired $ 905,962 Retirement of seller's debt 40,000 Total cash consideration 945,962 Common stock 690,702 Other purchase price adjustments 426 Total acquisition costs $ 1,637,090 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current Assets $ 6,401 Crude oil and natural gas properties - proved 216,000 Crude oil and natural gas properties - unproved 1,697,000 Infrastructure, pipeline, and other 33,153 Construction in progress 12,323 Goodwill 75,121 Total assets acquired 2,039,998 Liabilities assumed: Current liabilities (24,496 ) Asset retirement obligations (3,705 ) Deferred tax liabilities, net (374,707 ) Total liabilities assumed (402,908 ) Total identifiable net assets acquired $ 1,637,090 The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, lease terms and expirations, and a market-based weighted-average cost of capital rate. Within the unproven properties, the allocation of the value to the underlying leases also required significant judgment and was based on a combination of comparable market transactions, the terms and conditions associated with the individual leases, our ability and intent to develop specific leases, and our initial assessment of the underlying relative value of the leases given our knowledge of the geology at the time of closing. These inputs require significant judgments and estimates by management at the time of the valuation and were the most sensitive and subject to change. This acquisition was accounted for under the acquisition method. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. Pro Forma Information. The results of operations for the Delaware Basin acquisition have been included in our consolidated financial statements since the December 6, 2016 closing date, including approximately $5.6 million of total revenue and $1.7 million of loss from operations in our statements of operations for the year ended December 31, 2016. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2016 and December 31, 2015, assuming the acquisition had been completed as of January 1, 2015. This pro forma financial information includes proceeds from the sale of 9,085,000 shares of our common stock, the 2021 Convertible Notes, and the 2024 Senior Notes in September 2016, the shares issued to the sellers, and other acquisition costs. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results. Years Ended December 31, 2016 2015 (in thousands, except per share amounts) Total revenue $ 412,746 $ 598,932 Net loss $ (270,942 ) $ (138,904 ) Earnings per share: Basic and diluted $ (4.22 ) $ (2.41 ) Goodwill. Goodwill was calculated as the excess of the purchase price over the fair value of net assets acquired, including the additional value resulting from the creation of the deferred tax liability, and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired were the acquisition of an element of a workforce and the expected value from operations of the Delaware Basin acquisition to be derived in the future, such as production from future development of additional producing zones. The amount of the final goodwill that was recorded in the third quarter of 2017 related to the Delaware Basin acquisition was $75.1 million , which was higher than the initial estimated amount recorded as of December 31, 2016. The increase primarily related to finalization of the aggregate acreage position acquired and the related lease terms and a final settlement with the sellers in connection with a revised valuation of certain acquired leases and the retirement of estimated environmental remediation liabilities. Any value assigned to goodwill was not expected to be deductible for income tax purposes. The following table presents the changes in goodwill from the preliminary allocation at December 31, 2016, and the final allocation determined during the third quarter of 2017: Amount (in thousands) Preliminary purchase price allocation $ 62,041 Adjustments 13,080 Final purchase price allocation $ 75,121 See the footnote titled Goodwill for the details regarding the impairment of goodwill related to the Delaware Basin acquisition.

FAIR VALUE MEASUREMENTS AND DIS

FAIR VALUE MEASUREMENTS AND DISCLOSURES	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value, Measurement Inputs, Disclosure [Text Block]	FAIR VALUE OF FINANCIAL INSTRUMENTS Commodity Derivative Financial Instruments Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. Commodity Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors, and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars and propane fixed-price swaps are included in Level 3. Our basis swaps are included in Level 2 and Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: As of December 31, 2017 2016 Significant Other Significant Total Significant Other Significant Total (in thousands) Total assets $ 12,949 $ 1,389 $ 14,338 $ 6,350 $ 4,827 $ 11,177 Total liabilities 90,569 11,076 101,645 66,789 14,401 81,190 Net liability $ (77,620 ) $ (9,687 ) $ (87,307 ) $ (60,439 ) $ (9,574 ) $ (70,013 ) The following table presents a reconciliation of our Level 3 commodity derivative instruments measured at fair value: 2017 2016 2015 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ (9,574 ) $ 91,288 $ 62,356 Changes in fair value included in consolidated statements of operations line item: Commodity price risk management gain (loss), net 6,241 (28,550 ) 65,164 Settlements included in consolidated statements of operations line items: Commodity price risk management ( loss) , net (6,354 ) (72,312 ) (36,232 ) Fair value of Level 3 instruments, net asset (liability) end of period $ (9,687 ) $ (9,574 ) $ 91,288 Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: Commodity price risk management gain (loss), net $ (866 ) $ (12,905 ) $ 43,540 Total $ (866 ) $ (12,905 ) $ 43,540 The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements. Non-Derivative Financial Assets and Liabilities The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. We utilize fair value on a nonrecurring basis to review our crude oil and natural gas properties and goodwill for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. The fair value of the goodwill is determined using either a qualitative method or a quantitative method, both of which utilize market data, a Level 3 input, in the derivation of the value estimation. The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of December 31, 2017 : Estimated Fair Value % of Par (in millions) Senior notes: 2021 Convertible Notes $ 195.6 97.8 % 2024 Senior Notes 416.0 104.0 % 2026 Senior Notes 616.5 102.8 % The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the related vehicle lease.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	DERIVATIVE FINANCIAL INSTRUMENTS Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas, and NGLs. To manage a portion of our exposure to price volatility from producing crude oil, natural gas, and propane, which is an element of our NGLs, we enter into commodity derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases. We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2017 , we had commodity derivatives positions covering approximately 11.9 MMBbls and 6.6 MMBbls of crude oil production for 2018 and 2019, respectively. As of the same date, we had hedged approximately 56.5 Bcf of natural gas and 1.1 MMBbls of propane for 2018. Our commodity derivative contracts have been entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount. As of December 31, 2017 , our derivative instruments were comprised of collars, fixed-price commodity swaps, and basis protection swaps. • Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; • Fixed-price commodity swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty; • Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty. See Item 7a. - Quantitative and Qualitative Disclosures About Market Risk - Derivative Positions Table found elsewhere in this report for a detailed list of our basis protection swaps. We have elected not to designate any of our derivative instruments as cash flow hedges, and therefore do not qualify for the use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations. The following table presents the balance sheet location and fair value amounts of our commodity derivative instruments on the consolidated balance sheets as of December 31, 2017 and 2016 : Derivative instruments: Consolidated balance sheet line item 2017 2016 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 7,340 $ 8,490 Basis protection derivative contracts Fair value of derivatives 6,998 301 14,338 8,791 Non-current Commodity derivative contracts Fair value of derivatives — 1,123 Basis protection derivative contracts Fair value of derivatives — 1,263 — 2,386 Total derivative assets $ 14,338 $ 11,177 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 77,999 53,565 Basis protection derivative contracts Fair value of derivatives 234 30 Rollfactor derivative contracts Fair value of derivatives 1,069 — 79,302 53,595 Non-current Commodity derivative contracts Fair value of derivatives 22,343 27,595 Total derivative liabilities $ 101,645 $ 81,190 The following table presents the impact of our derivative instruments on our consolidated statements of operations: Year Ended December 31, Consolidated statements of operations line item 2017 2016 2015 (in thousands) Commodity price risk management gain (loss), net Net settlements $ 13,324 $ 208,103 $ 238,935 Net change in fair value of unsettled derivatives (17,260 ) (333,784 ) (35,752 ) Total commodity price risk management gain (loss), net $ (3,936 ) $ (125,681 ) $ 203,183 All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. The following table reflects the impact of netting agreements on gross derivative assets and liabilities: As of December 31, 2017 Derivative instruments, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 14,338 $ (14,173 ) $ 165 Liability derivatives: Derivative instruments, at fair value $ 101,645 $ (14,173 ) $ 87,472 As of December 31, 2016 Derivative instruments, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 11,177 $ (10,930 ) $ 247 Liability derivatives: Derivative instruments, at fair value $ 81,190 $ (10,930 ) $ 70,260

CONCENTRATION OF RISK

CONCENTRATION OF RISK	12 Months Ended
	Dec. 31, 2017
Concentration Risks, Types, No Concentration Percentage [Abstract]
Concentration Risk Disclosure [Text Block]	CONCENTRATION OF RISK Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: As of December 31, 2017 2016 (in thousands) Crude oil, natural gas, and NGLs sales $ 154,260 $ 97,520 Joint interest billings (1) 34,576 20,118 Derivative counterparties (18 ) 10,266 Income tax receivable 6,015 11,505 Other 5,893 6,173 Allowance for doubtful accounts (3,128 ) (2,190 ) Accounts receivable, net $ 197,598 $ 143,392 _________ (1) The December 31, 2017 amount includes $13.9 million of pre-closing contracted completion costs of wells associated with the Bayswater Acquisition, which closed in January 2018. Upon closing, the $13.9 million was capitalized and included in properties and equipment, net on the consolidated balance sheet. Our accounts receivable primarily relate to sales of our crude oil, natural gas, and NGLs production, receivable balances from other third parties that own working interests in the properties we operate, and derivative counterparties. For the years ended December 31, 2017 and 2016 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2017 and 2016, none of our customers represented 10 percent or greater of our accounts receivable balance. Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues: Year Ended December 31, Customer 2017 2016 2015 DCP Midstream, LP 19.6 % 20.2 % 13.2 % Suncor Energy Marketing, Inc. 16.4 % 22.3 % 14.3 % Aka Energy Group, LLC — % 13.4 % — % Concord Energy, LLC — % 13.4 % 23.2 % Bridger Energy, LLC — % 11.5 % — % Shell Trading Company — % — % 13.8 % Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil, natural gas, and NGLs. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our commodity derivative contracts; however, an insignificant portion of our commodity derivative instruments may be with other counterparties. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2017 , taking into account the estimated likelihood of nonperformance. Note Receivable. In October 2014, we sold our entire 50 percent ownership interest in PDC Mountaineer, LLC to an unrelated third-party. As part of the consideration, we received a promissory note (the “Promissory Note”) for a principal sum of $ 39.0 million , bearing variable interest rates. The interest was to be paid quarterly, in arrears and at the option of the issuer could be paid-in-kind (“PIK Interest”). Any such PIK Interest would be subject to the then current interest rate. We regularly analyzed the Promissory Note for evidence of collectibility, evaluating factors such as the creditworthiness of the issuer of the Promissory Note and the value of the issuer's assets. Based upon this analysis, during the quarter ended March 31, 2016, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $ 44.0 million accumulated outstanding balance, including interest. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Promissory Note and began accounting for the interest on the Promissory Note under the cash basis method. We performed this analysis as of March 31, 2017 and evaluated preliminary 2016 year-end financial statements of the note issuer which were available at such time, related information about the operations of the issuer, and existing market conditions for natural gas. Based upon this evaluation, it was determined that collection of the Promissory Note and the PIK Interest continued to be doubtful and the full valuation allowance on the Promissory Note remained appropriate as of that date. This evaluation assumed that repayment of the Promissory Note would be made exclusively from the existing operations of the issuer of the Promissory Note based on the latest available information. In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately $ 40.2 million in cash. The sales agreement transferred all of our legal rights to collect from the issuer of the Promissory Note. Accordingly, we reversed $ 40.2 million of the provision for uncollectible notes receivable during the second quarter of 2017. Other Accrued Expenses. The following table presents the components of other accrued expenses: As of December 31, 2017 2016 (in thousands) Employee benefits $ 22,383 $ 22,282 Asset retirement obligations 15,801 9,775 Environmental expenses 1,374 3,238 Other 3,429 3,330 Other accrued expenses $ 42,987 $ 38,625

PROPERTIES AND EQUIPMENT

PROPERTIES AND EQUIPMENT	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure [Text Block]	PROPERTIES AND EQUIPMENT The following table presents the components of properties and equipment, net of accumulated DD&A: As of December 31, 2017 2016 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 4,356,922 $ 3,499,718 Unproved 1,097,317 1,874,671 Total crude oil and natural gas properties 5,454,239 5,374,389 Infrastructure, pipeline, and other 109,359 62,093 Land and buildings 10,960 6,392 Construction in progress 196,024 122,591 Properties and equipment, at cost 5,770,582 5,565,465 Accumulated DD&A (1,837,115 ) (1,562,471 ) Properties and equipment, net $ 3,933,467 $ 4,002,994 Acreage Exchanges. In the fourth quarter of 2017, we completed two significant acreage exchanges that consolidated certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transactions, we exchanged leasehold acreage with a limited number of wells that were in the process of being drilled and completed. Upon closing, we received an aggregate of approximately 15,900 net acres in exchange for an aggregate of approximately 16,200 net acres with minimal cash exchanged between the parties. The differences in net acres are primarily due to variances in working and net revenue interests and in midstream contracts. The assets exchanged were all in the same unit-of-production for property considerations, so it was concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair value and determining gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were recorded at the previous historical cost of the assets we exchanged. In September 2016, we closed on an acreage exchange transaction with Noble Energy, Inc. and certain of its subsidiaries ("Noble") to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the parties. The assets exchanged were all in the same unit of production for property considerations, so it was concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair value and determining gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were recorded at the previous historical cost of the assets we exchanged. Delaware Basin Acreage Acquisition. On December 30, 2016, we closed the purchase of approximately 4,600 net bolt-on acres in Reeves and Culberson Counties, Texas, for consideration to the sellers of approximately $120.6 million in cash, subject to post-closing adjustments. The transaction was accounted for as an acquisition of assets. Classification of Assets as Held-for-Sale. During the third quarter of 2017, as part of our plan to divest the Utica Shale properties, we engaged an investment banking firm and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification beginning in the third quarter of 2017. In February 2018, we entered into a PSA for the sale of these properties for net cash proceeds of approximately $40.0 million , subject to certain customary closing adjustments. Based upon multiple offers received for the sale of our Utica Shale properties, we recorded an impairment charge of $2.1 million in 2017 to reflect their fair value. Assets held-for-sale as of December 31, 2017 included $ 36.8 million and $3.3 million , representing of our Utica Shale properties and field office facilities and a parcel of land, respectively. Assets held-for-sale as of December 31, 2016 of $5.3 million represented field office facilities and a parcel of land at that time. The following table presents balance sheet data related to assets held-for-sale, which include the Utica Shale properties, field office facilities, and a parcel of land that are being marketed for sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities that are expected to be assumed by the purchasers: December 31, 2017 December 31, 2016 (in thousands) Assets Properties and equipment, net $ 40,583 $ 5,272 Total assets $ 40,583 $ 5,272 Liabilities Asset retirement obligation $ 499 $ — Total liabilities $ 499 $ — Net assets $ 40,084 $ 5,272 Impairment of Properties and Equipment The following table presents impairment charges recorded for properties and equipment: Year Ended December 31, 2017 2016 2015 (in thousands) Impairment of proved and unproved properties $ 285,465 $ 5,562 $ 154,608 Amortization of individually insignificant unproved properties 422 1,379 7,012 Land and buildings — 3,032 — Total impairment of properties and equipment $ 285,887 $ 9,973 $ 161,620 During the third quarter of 2017, we recorded a charge related to two exploratory dry holes we had drilled in the western area of our Culberson County acreage in the Delaware Basin. We then assessed the impact of the dry holes and various factors related thereto, including (i) the operational and geologic data obtained, (ii) the current increased cost environment for drilling and completion services in the Delaware Basin, (iii) our decreased future commodity price outlook, and (iv) the terms of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during the third quarter of 2017. The amount of the impairment was based on the value assigned to individual lease acres in the final purchase price allocation of the Delaware Basin acquisition. This allocation had included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. We recorded approximately $29 million of additional lease impairments in the Delaware Basin and an impairment charge of $2.1 million related to the Utica Shale properties that are classified as held-for-sale during 2017. Due to the aforementioned events and circumstances, we also evaluated our proved property for possible impairment and concluded that no further impairments were necessary. Future deterioration of commodity prices or other operating circumstances could result in additional impairment charges to our properties and equipment. During 2015, due to a significant decline in commodity prices and decreases in our net realized sales prices, we experienced triggering events that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessments, we recorded impairment charges of $150.3 million in 2015 to write-down our Utica Shale proved and unproved properties. Of these impairment charges, $24.7 million were recorded in 2015 to write-down certain capitalized well costs on our Utica Shale proved producing properties. We also recorded impairment charges of $125.6 million to write-down our Utica Shale lease acquisition costs. The impairment charges, which are included in the consolidated statements of operations line item impairment of properties and equipment, represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair values. Suspended Well Costs. We have spud three wells in the Delaware Basin for which we are unable to make a final determination regarding whether proved reserves can be associated with the wells as of December 31, 2017 as the wells had not been completed as of that date. Therefore, we have classified the capitalized costs of the wells as suspended well costs as of December 31, 2017 while we continue to conduct completion and testing operations to determine the existence of proved reserves. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the consolidated balance sheet: 2017 (in thousands, except for number of wells) Beginning balance $ — Additions to capitalized exploratory well costs pending the determination of proved reserves 51,776 Reclassifications to proved properties (36,328 ) Balance at December 31, $ 15,448 Number of wells pending determination at December 31, 3 We did not have any suspended well costs as of December 31, 2016 or 2015. Exploration Expenses. The following table presents the major components of exploration, geologic, and geophysical expense: Year Ended December 31, 2017 2016 2015 (in thousands) Exploratory dry hole costs $ 41,297 $ — $ — Geological and geophysical costs, including seismic purchases 3,881 3,472 — Operating, personnel and other 2,156 1,197 1,102 Total exploration, geologic, and geophysical expense $ 47,334 $ 4,669 $ 1,102 Exploratory dry hole costs. During the third quarter of 2017 , two exploratory dry hole wells, associated lease costs, and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.3 million . The conclusion to expense these items was based on our determination that the acreage on which these wells were drilled was exploratory in nature and, following drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable.

GOODWILL (Notes)

GOODWILL (Notes)	12 Months Ended
	Dec. 31, 2017
Goodwill [Line Items]
Goodwill Disclosure [Text Block]	Goodwill represents the excess of the purchase price over the fair value of net assets acquired, including the additional value resulting from the creation of the deferred tax liability, and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that could contribute to a purchase price in excess of the fair value of the net tangible and intangible assets acquired is the acquisition of an element of a workforce and the expected value from operations of the acquisition to be derived in the future, such as production from future development of additional producing zones. We evaluate goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit to the carrying value. We determine the fair value of the goodwill at the impairment evaluation date by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value is based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. GOODWILL The final goodwill that resulted from the purchase price allocation of the business combination in the Delaware Basin in December 2016 was determined to be $ 75.1 million . With the creation of goodwill from this transaction, we expected to perform our evaluation of goodwill for impairment annually in the fourth quarter. However, primarily due to a combination of increases in per well development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin subsequent to the acquisition, in conjunction with the then current lower future commodity price outlook, we determined that a triggering event had occurred in the third quarter of 2017. In addition to the factors mentioned above, we also considered our impairments of certain unproven leasehold costs during the third quarter of 2017 and the impact of these items on our internal expectations for acceptable rates of return. We evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. We determined the fair value of the goodwill at September 30, 2017 by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value was based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. The quantitative test resulted in a determination that a full impairment charge of $ 75.1 million was required; therefore, the charge was recorded in the third quarter of 2017.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2017
Long-term Debt, Unclassified [Abstract]
Long-term Debt [Text Block]	LONG-TERM DEBT Long-term debt consists of the following: As of December 31, 2017 2016 (in thousands) Senior notes: 1.125% Convertible Notes due 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (30,328 ) (37,475 ) Unamortized debt issuance costs (3,615 ) (4,584 ) 1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs 166,057 157,941 6.125% Senior Notes due 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (6,570 ) (7,544 ) 6.125% Senior Notes due 2024, net of unamortized debt issuance costs 393,430 392,456 5.75% Senior Notes due 2026: Principal amount 600,000 — Unamortized debt issuance costs (7,555 ) — 5.75% Senior Notes due 2026, net of unamortized debt issuance costs 592,445 — 7.75% Senior notes redeemed 2017: Principal amount — 500,000 Unamortized debt issuance costs — (6,443 ) 7.75% Senior notes redeemed 2017, net of unamortized debt issuance costs — 493,557 Total senior notes 1,151,932 1,043,954 Revolving credit facility — — Total long-term debt, net of unamortized discount and debt issuance costs 1,151,932 1,043,954 Less current portion of long-term debt — — Long-term debt $ 1,151,932 $ 1,043,954 Senior Notes 2026 Senior Notes. In November 2017, we issued $600.0 million aggregate principal amount 5.75% senior notes due May 15, 2026, in a private placement to qualified institutional buyers. The 2026 Senior Notes are governed by an indenture dated November 29, 2017 between us and the U.S. Bank National Association, as trustee. The maturity for the payment of principal is May 15, 2026 . Interest at the rate of 5.75% per year is payable in cash semiannually in arrears on each May 15 and November 15 , commencing on May 15, 2018. Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2026 Senior Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to all our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. The 2026 Senior Notes are redeemable after May 15, 2021 , at fixed redemption prices beginning at 104.313 percent of the principal amount redeemed. At any time prior to May 15, 2021 , we may redeem all or part of the 2026 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at May 15, 2021 and remaining interest payments on the 2026 Senior Notes at the time of redemption. At any time prior to May 15, 2021 we may redeem up to 35 percent of the outstanding 2026 Senior Notes with proceeds from certain equity offerings at a redemption price of 105.75 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2026 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. Upon the occurrence of a "change of control," as defined in the indenture for the 2026 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase. The indenture governing the 2026 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. 2021 Convertible Notes. In September 2016 , we issued $200.0 million of 1.125% convertible senior notes due 2021 in a public offering. The 2021 Convertible Notes are governed by an indenture dated September 14, 2016 between us and the U.S. Bank National Association, as trustee. The maturity for the payment of principal is September 15, 2021 . Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September 15 , commencing on March 15, 2017. The 2021 Convertible Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the 2021 Convertible Notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. The proceeds from the issuance of the 2021 Convertible Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin, to pay related fees and expenses, and for general corporate purposes. The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, in each case at an initial conversion rate of 11.7113 shares of our common stock per $1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $85.39 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash, or a combination of cash and shares of our common stock. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares. We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest to, but excluding, the fundamental change repurchase date. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible. We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments excluding the conversion feature for similar terms and priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. As of December 31, 2017 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using an effective interest rate of 5.8% . Based upon the December 31, 2017 stock price of $51.54 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount. 2024 Senior Notes. In September 2016 , we issued $400.0 million aggregate principal amount of 6.125% senior notes due September 2024 in a private placement to qualified institutional buyers. In May 2017, in accordance with the registration rights agreement that we entered into with the initial purchasers when we issued the 2024 Senior Notes, we filed a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical terms, and we completed the exchange offer in September 2017. The proceeds from the issuance of the 2024 Senior Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin (see the footnotes titled Business Combination and Properties and Equipment) , to pay related fees and expenses, and for general corporate purposes. The 2024 Senior Notes began accruing interest from the date of issuance and interest is payable semi-annually in arrears on March 15 and September 15 . Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2024 Senior Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to all our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. The 2024 Senior Notes are redeemable after September 15, 2019, at fixed redemption prices beginning at 104.594 percent of the principal amount redeemed. At any time prior to September 15, 2019, we may redeem all or part of the 2024 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at September 15, 2019 and remaining interest payments on the 2024 Senior Notes at the time of redemption. At any time prior to September 15, 2019 , we may redeem up to 35 percent of the outstanding 2024 Senior Notes with proceeds from certain equity offerings at a redemption price of 106.125 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2024 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. Upon the occurrence of a "change of control," as defined in the indenture for the 2024 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase. The indenture governing the 2024 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. 2022 Senior Notes. In October 2012 , we issued $500 million aggregate principal amount of 7.75% senior notes due October 15, 2022 (the "2022 Senior Notes") in a private placement to qualified institutional buyers. On November 14, 2017, we issued a notice to redeem the notes on December 13, 2017 for a total redemption price of $519.4 million , including a $19.4 million make-whole premium. The make-whole provision was based upon terms set forth in the related indenture. On December 14, 2017, upon the redemption of the 2022 Senior Notes, the $19.4 million make-whole premium and the remaining unamortized debt issuance costs of $5.4 million were recognized as a $24.7 million pre-tax loss on debt extinguishment in the consolidated statements of operations. The amount paid to bond holders for the make-whole premium has been included as a financing activity in our statement of cash flows. Our wholly-owned subsidiary PDC Permian, Inc. has been a guarantor of our obligations under the 2026 Senior Notes since the issuance of those notes. In January 2017, pursuant to the filing of the supplemental indentures for the 2021 Convertible Notes, 2024 Senior Notes, and the 2022 Senior Notes, PDC Permian, Inc. became a guarantor of our obligations under each of those notes. As of December 31, 2017 , we were in compliance with all covenants related to the 2021 Convertible Notes, 2024 Convertible Notes, and the 2026 Senior Notes, and expect to remain in compliance throughout the foreseeable future. Revolving Credit Facility Our revolving credit facility matures in May 2020 . The revolving credit facility is available for working capital requirements, capital investments, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, but allows the borrowing base to exceed this capacity. The amount available under the revolving credit facility is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests, excluding proved reserves attributable to our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility. In May and October 2017, we entered into the Fifth and Sixth Amendments, respectively, to the Third Amended and Restated Credit Agreement to amend the revolving credit facility to reflect increases in the borrowing base. The Fifth amendment reflected an increase of the borrowing base from $700 million to $950 million and the Sixth Amendment amended the revolving credit facility to allow the borrowing base to increase above the borrowing capacity of $1.0 billion . In addition, the Fifth Amendment made changes to certain of the covenants in the existing agreement as well as other administrative changes. We elected to increase the borrowing base to $1.1 billion for our November 2017 borrowing base redetermination and have elected to maintain a $700 million commitment level as of the date of this report. The weighted-average borrowing rate on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 2.7 percent per annum for the year ended December 31, 2016 . We did not borrow any amounts under our revolving credit facility during 2017. We capitalized $6.2 million and $8.8 million of debt issuance costs as of December 31, 2017 and 2016 , respectively, related to our revolving credit facility which is included in other assets on the consolidated balance sheets. We had no outstanding balance on our revolving credit facility as of December 31, 2017 or 2016 . The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus an applicable margin and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium), or at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin, and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of December 31, 2017, the applicable margin is 1.25 percent and the unused commitment fee is 0.50 percent. No principal payments are generally required until the credit agreement expires in May 2020 , or in the event that the borrowing base falls below the outstanding balance. The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of December 31, 2017 , we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. As defined by the revolving credit facility, our leverage ratio was 1.9 and our current ratio was 3.2 as of December 31, 2017 . In May 2017, we replaced our $11.7 million irrevocable standby letter of credit that we held in favor of a third-party transportation service provider to secure a firm transportation obligation with a $9.3 million deposit, which is classified as restricted cash and is included in other assets on the consolidated balance sheets. As of December 31, 2017 , the available funds under our revolving credit facility were $700 million based on our elected commitment level.

CAPITAL LEASES CAPITAL LEASES (

CAPITAL LEASES CAPITAL LEASES (Notes)	12 Months Ended
	Dec. 31, 2017
Capital Leases [Abstract]
Capital Leases in Financial Statements of Lessee Disclosure [Text Block]	CAPITAL LEASES We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. These leases are being accounted for as capital leases, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90 percent of the fair value of the leased vehicles at inception of the lease. The following table presents leased vehicles under capital leases: As of December 31, 2017 2016 (in thousands) Vehicles $ 6,249 $ 2,975 Accumulated depreciation (1,882 ) (776 ) $ 4,367 $ 2,199 Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following: For the Twelve Months Ending December 31, Amount (in thousands) 2018 $ 2,075 2019 1,623 2020 1,507 5,205 Less executory cost (235 ) Less amount representing interest (537 ) Present value of minimum lease payments $ 4,433 Short-term capital lease obligations $ 1,672 Long-term capital lease obligations 2,761 $ 4,433 Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES The table below presents the components of our provision for income taxes from continuing operations for the years presented: Year Ended December 31, 2017 2016 2015 (in thousands) Current: Federal $ 8,443 $ 9,646 $ (2,944 ) State (200 ) 300 (163 ) Total current income tax (expense) benefit 8,243 9,946 (3,107 ) Deferred: Federal 193,809 118,427 37,352 State 9,876 18,822 4,063 Total deferred income tax benefit 203,685 137,249 41,415 Income tax benefit from continuing operations $ 211,928 $ 147,195 $ 38,308 The following table presents a reconciliation of the statutory rate to the effective tax rate related to our benefit for income taxes from continuing operations: Year Ended December, 31, 2017 2016 2015 Statutory tax rate 35.0 % 35.0 % 35.0 % State income tax, net 1.8 2.6 2.7 Effect of state income tax rate changes — 0.6 (0.3 ) Percentage depletion — — 0.3 Non-deductible compensation (0.3 ) (0.5 ) (1.2 ) Federal tax reform rate reduction 33.7 — — Non-deductible goodwill impairment (7.7 ) — — Other (0.1 ) (0.3 ) (0.6 ) Effective tax rate 62.4 % 37.4 % 35.9 % Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2017 and 2016 are presented below. The 2017 amounts include the reduction of our deferred tax assets and liabilities to a projected combined federal and state deferred tax rate of 23.9 percent as a result of the 2017 Tax Act. Also in 2017, deferred tax liability for properties and equipment was reduced by $94.1 million as a result of recording an impairment charge related to a portion of the Delaware Basin assets. The 2016 amounts include the $403.7 million effect of including the deferred tax liability for the difference in the book and tax basis of the oil and gas properties acquired in a 2016 business combination and $23.8 million of acquired deferred tax assets: As of December 31, 2017 2016 (in thousands) Deferred tax assets: Deferred compensation $ 6,059 $ 9,338 Asset retirement obligations 21,760 34,359 Federal NOL carryforward 19,386 29,988 State NOL and tax credit carryforwards, net 7,815 5,189 Federal tax - credit carryforwards 4,366 5,184 Allowance for note receivable — 17,292 Net change in fair value of unsettled derivatives 20,929 26,262 Other 2,453 4,716 Total gross deferred tax assets 82,768 132,328 Deferred tax liabilities: Properties and equipment 267,498 518,964 Convertible debt 7,262 14,231 Total gross deferred tax liabilities 274,760 533,195 Net deferred tax liability $ 191,992 $ 400,867 The 2017 Tax Act, enacted into law in December 2017, reduces the corporate income tax rate to 21 percent , effective January 1, 2018. Consequently, we have decreased our deferred tax assets and deferred tax liabilities by $43.8 million and $158.2 million , respectively, with a corresponding income tax benefit of $114.4 million . Our accounting for the deferred income tax effects of the 2017 Tax Act is complete. Prior to the decrease of deferred tax assets for the federal rate change noted above, the deferred tax assets would have decreased primarily due to the utilization of the deferred tax benefit of an allowance for note receivable, partially offset by a decrease in the value of unsettled derivatives and an increase in federal and state net operating loss (“NOL”) and tax credit carryforwards. In addition to the decrease of deferred tax liabilities for the tax rate change and our impairment in the Delaware Basin, deferred tax liabilities also decreased for the amortization of the discount and debt issuance costs for the 2021 Convertible Notes, which were issued in 2016. These decreases were partially offset by accelerated deductions on properties and equipment and deductions for lease expirations. During the year ending December 31, 2017 , we generated a federal NOL of $28 million , of which $10.1 million will be utilized as a carryback leaving a federal NOL carryforward of $17.9 million that will begin to expire in 2037. We have a marginal gas well credit of $ 1.2 million that can be carried forward five years and we have alternative minimum tax credits of $3.2 million that may be carried forward, and pursuant to the new tax law will be refunded over the next four years. Also, we acquired a federal NOL of $60.1 million as a component of our 2016 acquisition in the Delaware Basin that will begin to expire in 2034 and is subject to an annual limitation of $15.1 million as a result of the acquisition, which constitutes a change of ownership as defined under IRS Code Section 382. As of December 31, 2017 , we have state NOL carryforwards of $158.0 million that begin to expire in 2030 and state credit carryforwards of $2.4 million that begin to expire in 2022 . Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2017 . The statutes of limitations for most of our state tax jurisdictions are open from 2013 forward. The IRS partially accepted our recently-filed 2016 tax return. The 2016 tax return is currently going through the IRS CAP post-filing review process, with no significant tax adjustments currently proposed. We are currently participating in the CAP Program for the review of our 2017 and 2018 tax years. Participation in the CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. As of December 31, 2017 , we were current with our income tax filings in all applicable state jurisdictions.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	ASSET RETIREMENT OBLIGATIONS The following table presents the changes in carrying amounts of the asset retirement obligations associated with our crude oil and natural gas properties and midstream assets: 2017 2016 (in thousands) Beginning balance $ 92,387 $ 89,492 Obligations incurred with development activities 3,638 4,894 Accretion expense 6,306 7,080 Revisions in estimated cash flows (2,860 ) — Obligations discharged with asset retirements (12,165 ) (9,079 ) Balance at December 31 87,306 92,387 Less liabilities held-for-sale (499 ) — Less current portion (15,801 ) (9,775 ) Long-term portion $ 71,006 $ 82,612 Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2017, the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 6.5 percent to 7.5 percent. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors, and changes to our credit-adjusted risk-free rate as market conditions warrant. The revisions in estimated cash flows during 2017 were primarily due to changes in estimates of costs for materials and services related to the plugging and abandonment of vertical and horizontal wells and the shortening of the estimated expected lives of vertical wells in the Wattenberg Field.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2017
Employee Benefits and Share-based Compensation, Noncash [Abstract]
Compensation and Employee Benefit Plans [Text Block]	EMPLOYEE BENEFIT PLANS We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Additionally, our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was $6.2 million , $4.8 million , and $4.9 million for 2017 , 2016 , and 2015 , respectively.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	COMMITMENTS AND CONTINGENCIES Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties, and produced by our affiliated partnerships and other third-party working, royalty, and overriding royalty interest owners, whose volumes we market on their behalf. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. The following table presents gross volume information related to our long-term firm transportation, sales, and processing agreements for pipeline capacity: Year Ending December 31, Area 2018 2019 2020 2021 2022 and Total Expiration Natural gas (MMcf) Wattenberg Field 3,541 23,934 31,110 31,025 121,922 211,532 April 30, 2026 Delaware Basin 14,600 14,600 14,640 — — 43,840 December 31, 2020 Gas Marketing 7,117 7,117 7,136 7,056 4,495 32,921 August 31, 2022 Utica Shale (1) 2,738 2,738 2,745 2,738 4,326 15,285 July 31, 2023 Total 27,996 48,389 55,631 40,819 130,743 303,578 Crude oil (MBbls) Wattenberg Field 3,638 4,239 1,808 — — 9,685 June 30, 2020 Dollar commitment (in thousands) $ 23,176 $ 43,855 $ 42,496 $ 33,226 $ 118,927 $ 261,680 (1) In February 2018, we entered into a PSA to sell the Utica Shale properties. This commitment would be assumed by the purchaser of the Utica Shale properties. In anticipation of our future drilling activities in the Wattenberg Field, we entered into two facilities expansion agreements in 2016 and 2017 with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider is expected to construct two new 200 MMcfd cryogenic plants. We will be bound to the volume requirements in these agreements on the first day of the calendar month following after the actual in-service date of the plants, which in the above table is scheduled to be in the third quarter of 2018 for the first plant and the second quarter of 2019 for the second plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016, to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. Any shortfall of these volume commitments may be offset by additional third party producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. We currently expect that our future development plans will meet both baseline and incremental volumes, and we believe that the contractual target profit margin will be achieved without additional payment from us. In April 2017, we entered into a transportation service agreement for delivery of 40,000 dekatherms per day of our Delaware Basin natural gas production to the Waha market hub in West Texas. For the years 2017, 2016, and 2015, commitments for long-term transportation volumes for Wattenberg Field crude oil, Delaware Basin natural gas, and Utica Shale natural gas were $10.0 million , $10.0 million , and $4.7 million , respectively, and were recorded in transportation, gathering and processing expense in our consolidated statements of operations. Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations, or liquidity. Action Regarding Partnerships. In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al ., filed in the United States District Court for the District of Colorado. The complaint states that it is a derivative action brought by a number of limited partner investors seeking to assert claims on behalf of our two affiliated partnerships, Rockies Region 2006 LP and Rockies Region 2007 LP, against PDC and alleging claims for breach of fiduciary duty and breach of contract. The plaintiffs also included claims against two of our senior officers for alleged breach of fiduciary duty. The lawsuit accuses PDC, as the managing general partner of the two partnerships, of, among other things, failing to maximize the productivity of the partnerships’ crude oil and natural gas wells. We filed a motion to dismiss the lawsuit on February 1, 2018, on the grounds that the complaint is deficient, including because the plaintiffs failed to allege that PDC refused a demand to take action on their claims. That motion is still pending. We are unable to estimate any potential damages as a result of this recent lawsuit. Action Regarding Firm Transportation Contracts. In June 2016, a group of 42 independent West Virginia natural gas producers filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. (“Dominion”), certain entities affiliated with Dominion, and our subsidiary Riley Natural Gas ("RNG") as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. The case has been transferred to the Business Court Division of the Circuit Court of Marshall County, West Virginia. RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defenses. Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures designed to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of December 31, 2017 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual. Clean Air Act Agreement and Related Consent Decree. In August 2015, we received a Clean Air Act Section 114 Information Request (the “Information Request”) from the U.S. Environmental Protection Agency (“EPA”). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado (“DJ Basin”). The Information Request focused on historical operation and design information for 46 of our production facilities and requested sampling and analyses at the identified 46 facilities. We responded to the Information Request with the requested data in January 2016. In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. 25-7-115(2) from the Colorado Department of Public Health and Environment’s Air Quality Control Commission’s Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. In June 2017, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to resolve the lawsuit. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1 million in supplemental environmental projects) which have been accrued in other accrued expenses on our consolidated balance sheet as of December 31, 2017 ; (ii) injunctive relief with an estimated cost of approximately $18 million, primarily representing capital enhancements to our operations; and (iii) mitigation with an estimated cost of $1.7 million. We continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. In addition, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space, and general office equipment. The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2017 : Year Ending December 31, 2018 2019 2020 2021 2022 Thereafter Total (in thousands) Minimum Lease Payments $ 3,865 $ 3,865 $ 3,932 $ 3,998 $ 4,078 $ 3,515 $ 23,253 Operating lease expense for 2017 , 2016 , and 2015 was $17.2 million , $10.2 million , and $9.8 million , respectively.

COMMON STOCK

COMMON STOCK	12 Months Ended
	Dec. 31, 2017
COMMON STOCK [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Text Block]	COMMON STOCK Issuance of Equity Securities In December 2016, we issued 9.4 million shares of our common stock as partial consideration for 100 percent of the common stock of Arris Petroleum and for the acquisition of certain Delaware Basin properties. Pursuant to the terms of previously disclosed lock-up agreements, the resale of these shares was restricted. The lock-up period ended in June 2017. We have registered the 9.4 million shares of our common stock for resale under the Securities Act of 1933. Sales of Equity Securities The following table provides a summary of our public offerings of common stock in 2016 and 2015: Date Shares Issued Price per Share Net Proceeds (in millions) September 2016 9,085,000 $ 61.51 $ 558.5 March 2016 5,922,500 50.11 296.6 March 2015 4,002,000 50.73 202.9 Stock-Based Compensation Plans 2010 Long-Term Equity Compensation Plan. In June 2010 , our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). The plan was amended in June 2013. In accordance with the 2010 Plan, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares, or any combination. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited, paid out in the form of cash, or withheld for the payment of taxes. Awards may be issued to our employees in the form of stock appreciation rights ("SARs"), restricted stock, restricted stock units ("RSUs"), performance shares, and performance units ("PSUs"), and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock, and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after June 5, 2023. As of December 31, 2017 , 689,206 shares remain available for issuance pursuant to the 2010 Plan. The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: Year Ended December 31, 2017 2016 2015 (in thousands) Stock-based compensation expense $ 19,353 $ 19,502 $ 20,068 Income tax benefit (7,372 ) (7,296 ) (7,636 ) Net stock-based compensation expense $ 11,981 $ 12,206 $ 12,432 SARs The SARs vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the holders of the SARs will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. The Compensation Committee has awarded SARs to our executive officers in 2017, 2016, and 2015. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: Year Ended December 31, 2017 2016 2015 Expected term of award (in years) 6.0 years 6.0 years 5.2 years Risk-free interest rate 2.0 % 1.8 % 1.4 % Expected volatility 53.3 % 54.5 % 58.0 % Weighted-average grant date fair value per share $ 38.58 $ 26.96 $ 22.23 The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future. The following table presents the changes in our SARs for all periods presented (in thousands, except per share data): Year Ended December 31, 2017 2016 2015 Number of Weighted-Average Average Remaining Contractual (in years) Aggregate Intrinsic Number of Weighted-Average Aggregate Intrinsic Number of Weighted-Average Aggregate Intrinsic Outstanding at January 1, 244,078 $ 41.36 6.9 $ 7,620 326,453 $ 38.99 $ 4,697 279,011 $ 38.77 $ 1,472 Awarded 54,142 74.57 — — 58,709 51.63 — 68,274 39.63 — Exercised — — — — (141,084 ) 40.16 2,770 (20,832 ) 38.05 473 Outstanding at December 31 298,220 47.39 6.5 2,490 244,078 41.36 7,620 326,453 38.99 4,697 Exercisable at December 31 223,865 43.28 5.9 2,267 174,919 38.72 5,924 222,489 37.70 3,489 We expect all SARs outstanding as of December 31, 2017 to vest. Total compensation cost related to SARs granted and not yet recognized in our consolidated statements of operations as of December 31, 2017 was $1.9 million . The cost is expected to be recognized over a weighted-average period of 1.8 years. Restricted Stock Unit Awards Time-Based Awards. The fair value of the time-based RSUs is amortized ratably over the requisite service period, primarily three years. The time-based RSUs generally vest ratably on each anniversary following the grant date that a participant is continuously employed. The following table presents the changes in non-vested time-based RSUs during 2017 : Shares Weighted-Average Non-vested at December 31, 2016 479,642 $ 56.09 Granted 273,941 65.14 Vested (266,809 ) 57.67 Forfeited (14,642 ) 62.92 Non-vested at December 31, 2017 472,132 60.23 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2017 2016 2015 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 16,303 $ 18,973 $ 17,077 Total intrinsic value of time-based awards non-vested 24,334 34,812 28,029 Market price per common share as of December 31, 51.54 72.58 53.38 Weighted-average grant date fair value per share 65.14 58.52 48.88 Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2017 was $18.5 million . This cost is expected to be recognized over a weighted-average period of 1.8 years. Market-Based Awards. The fair value of the market-based PSUs is amortized ratably over the requisite service period, primarily three years. The market-based PSUs vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. In January 2017, the Compensation Committee awarded a total of 28,069 market-based PSUs to our executive officers. In addition to continuous employment, the vesting of these PSUs is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends, as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2019 and can result in a payout between 0 percent and 200 percent of the target PSUs awarded. As of December 31, 2017, we had approximately 52,000 non-vested market based PSUs that could result in a payout between 0 and approximately 105,000 shares of our common stock. The weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions: Year Ended December 31, 2017 2016 2015 Expected term of award (in years) 3 years 3 years 3 years Risk-free interest rate 1.4 % 1.2 % 0.9 % Expected volatility 51.4 % 52.3 % 53.0 % Weighted-average grant date fair value per share $ 94.02 $ 72.54 $ 66.16 The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. The following table presents the change in non-vested market-based awards during 2017 : Shares Weighted-Average Non-vested at December 31, 2016 48,420 $ 64.97 Granted 28,069 94.02 Vested (24,140 ) 57.35 Non-vested at December 31, 2017 52,349 84.06 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2017 2016 2015 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ 2,687 $ 6,562 $ 4,293 Total intrinsic value of market-based awards non-vested 2,698 3,514 3,819 Market price per common share as of December 31, 51.54 72.58 53.38 Weighted-average grant date fair value per share 94.02 72.54 66.16 Total compensation cost related to non-vested market-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2017 was $2.4 million . This cost is expected to be recognized over a weighted-average period of 1.8 years. Treasury Share Purchases In accordance with our stock-based compensation plans, employees may surrender shares of our common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2010 Plan are withheld for reissuance for new grants. For shares reissued for new grants under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2017 , we acquired 107,357 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 83,228 shares were reissued and 34,526 are available for reissuance pursuant to our 2010 Plan. During the year ended December 31, 2016 , we acquired 116,085 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 114,697 were reissued and 10,397 are available for reissuance pursuant to our 2010 Plan. As of December 31, 2017 and 2016 , we had 21,401 and 18,366 , respectively, shares of treasury stock related to a rabbi trust. Preferred stock We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01, in one or more series, with such rights, preferences, privileges, and restrictions as shall be fixed by our Board of Directors at the time of issuance. As of December 31, 2017 , no preferred shares had been issued

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Earnings Per Share [Text Block]	EARNINGS PER SHARE Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes, and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. The following table presents a reconciliation of the weighted-average diluted shares outstanding: Year Ended December 31, 2017 2016 2015 (in thousands) Weighted-average common shares outstanding - basic 65,837 49,052 39,153 Weighted-average common shares and equivalents outstanding - diluted 65,837 49,052 39,153 For 2017, 2016, and 2015, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same because the effect of the common share equivalents was anti-dilutive. The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: Year Ended December 31, 2017 2016 2015 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: Restricted stock 590 689 831 Convertible notes — 292 562 Other equity-based awards 75 109 101 Total anti-dilutive common share equivalents 665 1,090 1,494 In September 2016 , we issued the 2021 Convertible Notes, which gave the holders the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes would be included in the diluted earnings per share calculation using the treasury stock method if the average market share price had exceeded the $85.39 conversion price during the periods presented. In November 2010, we issued the 2016 Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The 2016 Convertible Notes matured and were redeemed in May 2016 . Prior to maturity, the 2016 Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method when the average market share price exceeded the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the years ended December 31, 2016 and 2015 as the effect would have been anti-dilutive to our earnings per share.

SUBSIDIARY GUARANTOR SUBSIDIARY

SUBSIDIARY GUARANTOR SUBSIDIARY GUARANTOR (Notes)	12 Months Ended
	Dec. 31, 2017
Guarantor Obligations [Line Items]
Guarantees [Text Block]	SUBSIDIARY GUARANTOR PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the condensed consolidating financial information separately for: (i) PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries; (ii) PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes; (iii) Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor, and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and (iv) Parent and subsidiaries on a consolidated basis ("Consolidated"). The Guarantor was 100 percent owned by the Parent beginning in December 2016. The senior notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the consolidating financial information follows the same accounting policies as described in the notes to the consolidated financial statements. The following consolidating financial statements have been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column. Consolidating Balance Sheets December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets: Cash and cash equivalents $ 180,675 $ — $ — $ 180,675 Accounts receivable, net 160,490 37,108 — 197,598 Fair value of derivatives 14,338 — — 14,338 Prepaid expenses and other current assets 8,284 329 — 8,613 Total current assets 363,787 37,437 — 401,224 Properties and equipment, net 1,891,314 2,042,153 — 3,933,467 Assets held-for-sale, net 40,084 — — 40,084 Intercompany receivable 250,279 — (250,279 ) — Investment in subsidiaries 1,617,537 — (1,617,537 ) — Other assets 42,547 2,569 — 45,116 Total Assets $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 85,000 $ 65,067 $ — $ 150,067 Production tax liability 35,902 1,752 — 37,654 Fair value of derivatives 79,302 — — 79,302 Funds held for distribution 83,898 11,913 — 95,811 Accrued interest payable 11,812 3 — 11,815 Other accrued expenses 42,543 444 — 42,987 Total current liabilities 338,457 79,179 — 417,636 Intercompany payable — 250,279 (250,279 ) — Long-term debt 1,151,932 — — 1,151,932 Deferred income taxes 62,857 129,135 — 191,992 Asset retirement obligations 65,301 5,705 — 71,006 Fair value of derivatives 22,343 — — 22,343 Other liabilities 57,009 324 — 57,333 Total liabilities 1,697,899 464,622 (250,279 ) 1,912,242 Stockholders' equity Common shares 659 — — 659 Additional paid-in capital 2,503,294 1,766,775 (1,766,775 ) 2,503,294 Retained earnings 6,704 (149,238 ) 149,238 6,704 Treasury shares (3,008 ) — — (3,008 ) Total stockholders' equity 2,507,649 1,617,537 (1,617,537 ) 2,507,649 Total Liabilities and Stockholders' Equity $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Consolidating Balance Sheets December 31, 2016 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets: Cash and cash equivalents $ 240,487 $ 3,613 $ — $ 244,100 Accounts receivable, net 134,589 8,803 — 143,392 Fair value of derivatives 8,791 — — 8,791 Prepaid expenses and other current assets 3,442 100 — 3,542 Total current assets 387,309 12,516 — 399,825 Properties and equipment, net 1,884,147 2,118,847 — 4,002,994 Assets held-for-sale, net 5,272 — — 5,272 Intercompany receivable 9,415 — (9,415 ) — Investment in subsidiaries 1,765,092 — (1,765,092 ) — Fair value of derivatives 2,386 — — 2,386 Goodwill — 62,041 — 62,041 Other assets 13,153 171 — 13,324 Total Assets $ 4,066,774 $ 2,193,575 $ (1,774,507 ) $ 4,485,842 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 38,748 $ 27,574 $ — $ 66,322 Production tax liability 24,401 366 — 24,767 Fair value of derivatives 53,595 — — 53,595 Funds held for distribution 65,022 6,317 — 71,339 Accrued interest payable 15,930 — — 15,930 Other accrued expenses 37,425 1,200 — 38,625 Total current liabilities 235,121 35,457 — 270,578 Intercompany payable — 9,415 (9,415 ) — Long-term debt 1,043,954 — — 1,043,954 Deferred income taxes 20,971 379,896 — 400,867 Asset retirement obligations 78,897 3,715 — 82,612 Fair value of derivatives 27,595 — — 27,595 Other liabilities 37,482 — — 37,482 Total liabilities 1,444,020 428,483 (9,415 ) 1,863,088 Stockholders' equity Common shares 657 — — 657 Additional paid-in capital 2,489,557 1,766,775 (1,766,775 ) 2,489,557 Retained earnings 134,208 (1,683 ) 1,683 134,208 Treasury shares (1,668 ) — — (1,668 ) Total stockholders' equity 2,622,754 1,765,092 (1,765,092 ) 2,622,754 Total Liabilities and Stockholders' Equity $ 4,066,774 $ 2,193,575 $ (1,774,507 ) $ 4,485,842 Consolidating Statements of Operations Year Ended December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas, and NGLs sales $ 788,400 $ 124,684 $ — $ 913,084 Commodity price risk management gain (loss), net (3,936 ) — — (3,936 ) Other income 11,901 567 — 12,468 Total revenues 796,365 125,251 — 921,616 Costs, expenses and other Lease operating expenses 68,031 21,610 — 89,641 Production taxes 53,236 7,481 — 60,717 Transportation, gathering, and processing expenses 23,301 9,919 — 33,220 Exploration, geologic, and geophysical expense 1,092 46,242 — 47,334 Impairment of properties and equipment 4,951 280,936 — 285,887 Impairment of goodwill — 75,121 — 75,121 General and administrative expense 107,518 12,852 — 120,370 Depreciation, depletion and amortization 403,984 65,100 — 469,084 Provision for uncollectible notes receivable (40,203 ) — — (40,203 ) Accretion of asset retirement obligations 5,965 341 — 6,306 Gain on sale of properties and equipment (766 ) — — (766 ) Other expenses 13,157 — — 13,157 Total costs, expenses and other 640,266 519,602 — 1,159,868 Income (loss) from operations 156,099 (394,351 ) — (238,252 ) Loss on extinguishment of debt (24,747 ) — — (24,747 ) Interest expense (79,919 ) 1,225 — (78,694 ) Interest income 2,261 — — 2,261 Income (loss) before income taxes 53,694 (393,126 ) — (339,432 ) Income tax (expense) benefit (33,643 ) 245,571 — 211,928 Equity in loss of subsidiary (147,555 ) — 147,555 — Net loss $ (127,504 ) $ (147,555 ) $ 147,555 $ (127,504 ) Net losses of the Guarantor for the year ended 2017 are primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions, and the impairment of goodwill. Consolidating Statements of Operations Year Ended December 31, 2016 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas, and NGLs sales $ 491,750 $ 5,603 $ — $ 497,353 Commodity price risk management gain (loss), net (125,681 ) — — (125,681 ) Other income 11,241 2 — 11,243 Total revenues 377,310 5,605 — 382,915 Costs, expenses and other Lease operating expenses 58,401 1,549 — 59,950 Production taxes 31,132 278 — 31,410 Transportation, gathering, and processing expenses 18,263 152 — 18,415 Exploration, geologic, and geophysical expense 1,197 3,472 — 4,669 Impairment of properties and equipment 9,973 — — 9,973 General and administrative expense 112,166 304 — 112,470 Depreciation, depletion and amortization 415,321 1,553 — 416,874 Provision for uncollectible notes receivable 44,038 — — 44,038 Accretion of asset retirement obligations 7,070 10 — 7,080 Gain on sale of properties and equipment (43 ) — — (43 ) Other expenses 10,193 — — 10,193 Total costs, expenses and other 707,711 7,318 — 715,029 Loss from operations (330,401 ) (1,713 ) — (332,114 ) Interest expense (62,002 ) 30 — (61,972 ) Interest income 963 — — 963 Loss before income taxes (391,440 ) (1,683 ) — (393,123 ) Income tax benefit 147,195 — — 147,195 Equity in loss of subsidiary (1,683 ) — 1,683 — Net loss $ (245,928 ) $ (1,683 ) $ 1,683 $ (245,928 ) Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 537,704 $ 50,859 $ — $ 588,563 Cash flows from investing activities: Capital expenditures for development of crude oil and natural properties (439,897 ) (297,311 ) — (737,208 ) Capital expenditures for other properties and equipment (3,539 ) (1,555 ) — (5,094 ) Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition (21,000 ) 5,372 — (15,628 ) Proceeds from sale of properties and equipment 10,084 (93 ) — 9,991 Sale of promissory note 40,203 — — 40,203 Restricted cash (9,250 ) — — (9,250 ) Sale of short-term investments 49,890 — — 49,890 Purchase of short-term investments (49,890 ) — — (49,890 ) Intercompany transfers (239,191 ) — 239,191 — Net cash from investing activities (662,590 ) (293,587 ) 239,191 (716,986 ) Cash flows from financing activities: Proceeds from issuance of senior notes 592,366 — — 592,366 Redemption of senior notes (519,375 ) — — (519,375 ) Purchase of treasury stock (6,672 ) — — (6,672 ) Payment of debt issuance costs (50 ) — — (50 ) Other (1,195 ) (76 ) — (1,271 ) Intercompany transfers — 239,191 (239,191 ) — Net cash from financing activities 65,074 239,115 (239,191 ) 64,998 Net change in cash and cash equivalents (59,812 ) (3,613 ) — (63,425 ) Cash and cash equivalents, beginning of period 240,487 3,613 — 244,100 Cash and cash equivalents, end of period $ 180,675 $ — $ — $ 180,675 Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2016 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 492,893 $ (6,630 ) $ — $ 486,263 Cash flows from investing activities: Capital expenditures for development of crude oil and natural properties (436,361 ) (523 ) — (436,884 ) Capital expenditures for other properties and equipment (2,282 ) (1,182 ) — (3,464 ) Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition (1,076,256 ) 2,533 — (1,073,723 ) Proceeds from sale of properties and equipment 4,945 — — 4,945 Intercompany transfers (9,415 ) — 9,415 — Net cash from investing activities (1,519,369 ) 828 9,415 (1,509,126 ) Cash flows from financing activities: Proceeds from issuance of equity, net of issuance costs 855,074 — — 855,074 Proceeds from issuance of senior notes 392,172 — — 392,172 Proceeds from issuance of convertible senior notes 193,935 — — 193,935 Proceeds from revolving credit facility 85,000 — — 85,000 Repayment of revolving credit facility (122,000 ) — — (122,000 ) Redemption of convertible notes (115,000 ) — — (115,000 ) Payment of debt issuance costs (15,556 ) — — (15,556 ) Purchase of treasury shares (6,935 ) — — (6,935 ) Other (577 ) — — (577 ) Intercompany transfers — 9,415 (9,415 ) — Net cash from financing activities 1,266,113 9,415 (9,415 ) 1,266,113 Net change in cash and cash equivalents 239,637 3,613 — 243,250 Cash and cash equivalents, beginning of period 850 — — 850 Cash and cash equivalents, end of period $ 240,487 $ 3,613 $ — $ 244,100 The condensed consolidating financial statements for the year ended December 31, 2016 represent one month of activity for the Guarantor as the Delaware Basin acquisition occurred in December 2016.

SUBSEQUENT EVENT SUBSEQUENT EVE

SUBSEQUENT EVENT SUBSEQUENT EVENT (Notes)	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events [Text Block]	SUBSEQUENT EVENTS Bayswater Acquisition. On January 5, 2018, we closed the Bayswater Acquisition for approximately $186 million , subject to certain customary post-closing adjustments. After adjustments, we acquired approximately 7,400 net acres, approximately 220 gross drilling locations, and 24 operated horizontal wells that were either drilled uncompleted wells or in-process wells at the time of closing, for approximately $186 million , subject to certain customary post-closing adjustments. In addition to the approximately $186 million of cash paid at closing, we invested approximately $15 million during December 2017 to complete 12 of the 24 wells. Upon executing the PSA, we paid a $21.0 million deposit toward the purchase price into an escrow account, which is included in other assets on our December 31, 2017 consolidated balance sheet. Utica Shale Divestiture. In February 2018, we entered into a PSA for the sale of the Utica Shale properties for net cash proceeds of approximately $40.0 million , subject to certain customary closing adjustments. These properties were classified as held-for-sale as they met the criteria for such classification beginning in the third quarter of 2017. See the footnote titled Properties and Equipment for further details regarding the assets held-for-sale. Saddle Butte Rockies Midstream Amendment Payment. On January 31, 2018, we received a payment of approximately $24 million from Saddle Butte for the execution of an Amendment to an existing crude oil purchase and sale agreement, signed in December 2017. The Amendment was effective contingent upon certain events which occurred in late January 2018. The Amendment, among other things, dedicates the majority of our Wattenberg Field acreage for crude oil production to be gathered by Saddle Butte's gathering lines and extends the term through December 2029.

SUPPLEMENTAL INFORMATION - NATU

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Information - Oil and Gas Exploration and Production Industries Disclosures [Text Block]	NATURAL GAS INFORMATION - UNAUDITED Net Proved Reserves All of our crude oil, natural gas, and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas, and NGL reserves. As of December 31, 2017 , 2016 , and 2015 , all of our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder Scott Company, L.P. and beginning in 2016, Netherland, Sewell & Associates, Inc. prepared the reserve reports for the Delaware Basin. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. Proved reserves are those quantities of crude oil, natural gas, and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement to be drilled within five years of each location’s initial booking date. The indicated index prices for our reserves, by commodity, are presented below. Average Benchmark Prices (1) As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) (2) 2017 $ 51.34 $ 2.98 $ 51.34 2016 42.75 2.48 42.75 2015 50.28 2.59 50.28 The netted back price used to estimate our reserves, by commodity, are presented below. Price Used to Estimate Reserves (3) As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) (2) 2017 $ 48.68 $ 2.31 $ 20.21 2016 38.67 1.85 11.97 2015 42.10 2.05 12.23 ___________ (1) Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. (2) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. (3) These prices are based on the index prices and are net of basin differentials, any transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity. The following tables present the changes in our estimated quantities of proved reserves: Crude Oil, Condensate (MBbls) Natural Gas (MMcf) NGLs (MBbls) Total (MBoe) Proved Reserves: Proved reserves, January 1, 2015 100,515 536,972 60,119 250,129 Revisions of previous estimates (43,268 ) (154,775 ) (24,407 ) (93,471 ) Extensions, discoveries, and other additions 48,707 311,709 30,835 131,494 Acquisition of reserves 17 215 23 76 Dispositions (12 ) (82 ) (8 ) (34 ) Production (6,984 ) (33,302 ) (2,835 ) (15,369 ) Proved reserves, December 31, 2015 98,975 660,737 63,727 272,825 Revisions of previous estimates (22,097 ) (80,426 ) (7,130 ) (42,631 ) Extensions, discoveries, and other additions 494 4,094 355 1,531 Acquisition of reserves 50,126 305,224 32,586 133,583 Dispositions (601 ) (4,202 ) (424 ) (1,725 ) Production (8,728 ) (51,730 ) (4,826 ) (22,176 ) Proved reserves, December 31, 2016 118,169 833,697 84,288 341,407 Revisions of previous estimates 28,334 96,119 8,104 52,457 Extensions, discoveries, and other additions 2,923 11,541 1,158 6,005 Acquisition of reserves 18,971 289,223 19,604 86,778 Dispositions (653 ) (4,597 ) (481 ) (1,900 ) Production (12,902 ) (71,689 ) (6,981 ) (31,830 ) Proved reserves, December 31, 2017 154,842 1,154,294 105,692 452,917 Proved Developed Reserves, as of: December 31, 2015 26,257 175,367 15,011 70,496 December 31, 2016 30,013 264,452 24,196 98,284 December 31, 2017 46,862 365,332 35,220 142,971 Proved Undeveloped Reserves, as of: December 31, 2015 72,718 485,370 48,716 202,329 December 31, 2016 88,156 569,245 60,092 243,122 December 31, 2017 107,980 788,962 70,472 309,946 Developed Undeveloped Total (MBoe) Proved reserves, January 1, 2015 74,905 175,224 250,129 Undeveloped reserves converted to developed 29,090 (29,090 ) — Revisions of previous estimates (26,875 ) (66,596 ) (93,471 ) Extensions, discoveries, and other additions 8,703 122,791 131,494 Acquisition of reserves 76 — 76 Dispositions (34 ) — (34 ) Production (15,369 ) — (15,369 ) Proved reserves, December 31, 2015 70,496 202,329 272,825 Undeveloped reserves converted to developed 32,192 (32,192 ) — Revisions of previous estimates 6,112 (48,743 ) (42,631 ) Extensions, discoveries, and other additions 1,531 — 1,531 Acquisition of reserves 10,229 123,354 133,583 Dispositions (99 ) (1,626 ) (1,725 ) Production (22,176 ) — (22,176 ) Proved reserves, December 31, 2016 98,285 243,122 341,407 Undeveloped reserves converted to developed 54,648 (54,648 ) — Revisions of previous estimates 18,291 34,166 52,457 Extensions, discoveries, and other additions 2,292 3,713 6,005 Acquisition of reserves 1,305 85,473 86,778 Dispositions (20 ) (1,880 ) (1,900 ) Production (31,830 ) — (31,830 ) Proved reserves, December 31, 2017 142,971 309,946 452,917 2017 Activity. During 2017, we increased proved reserves by 33 percent or 111.5 MMBoe, relative to December 31, 2016. This proved reserve increase was primarily a result of an increase in acquisitions and reserve additions on proved acreage in our Delaware Basin properties from our 2017 development plan. In 2017, we produced 31.8 MMboe. Extensions, discoveries, and other additions for 2017 of 6.0 MMBoe includes the addition of five newly drilled wells and seven proved undeveloped ("PUD") locations in the Delaware Basin. Acquisitions of reserves of 86.8 MMBoe includes proved developed producing properties and PUD locations obtained in our Wattenberg Field from acreage exchange transactions. We had minimal dispositions of 1.9 MMBoe related to the acreage disposed of in an acreage exchange. In relation to our acreage exchange transactions, we primarily divested proved acreage with future locations that were not in our proved five-year development plan as of December 31, 2016, as we do not add non-operated PUD locations to our proved five-year development plan until drilling has started as our certainty threshold is not achieved until such time. We estimated 52.5 MMBoe in upward revisions from the following changes: • Negative revisions of 57.7 MMBoe were due to Wattenberg Field PUD locations being dropped from our proved five- year development plan and being replaced by PUD locations on newly-acquired properties. • Positive revisions of 93.9 MMBoe for infill drilling within a proven area, with 37.3 MMBoe in our Wattenberg Field and 56.6 MMBoe in our Delaware Basin. • Net negative revisions of 2.2 MMBoe were due to an increase in operating costs, partially offset by an increase in prices for crude oil, natural gas, and NGLs. • Negative revisions of 0.7 MMBoe were due to locations being removed due to the SEC five-year development rule. • Net positive revisions of 19.2 MMBoe includes performance revisions and other items. At December 31, 2016, we projected a PUD reserve conversion rate of 26 percent for 2017. As a result of drilling plans being extended in our Delaware Basin in the first half of 2017, our actual reserve conversion rate was 23 percent, resulting in 54.6 MMBoe of reserves recorded as PUDs at December 31, 2016, being converted to proved developed reserves as of December 31, 2017. Based on economic conditions on December 31, 2017, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2017, our 2018 PUD reserve conversion rate is expected to be approximately 16 percent . Our lower 2018 PUD conversion rate is a result of our Bayswater Acquisition that closed on January 5, 2018. We anticipate drilling acquired Bayswater locations in 2018 that are not included within our December 31, 2017 reserves. The Bayswater Acquisition is more fully described in the footnote titled Subsequent Events to the consolidated financial statements included elsewhere in this report. The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities. 2016 Activity. During 2016, we increased proved reserves by 25 percent or 68.6 MMBoe, relative to December 31, 2015. This proved reserve increase was primarily a result of the development of longer lateral length well bores in the Wattenberg Field, which was driven by technology advancements, together with the ability to consolidate our leasehold position to drill longer length laterals with increased working interests. We also acquired proved developed reserves and undeveloped reserves in the Delaware Basin. Extensions, discoveries, and other additions for 2016 of 1.5 MMBoe includes the addition of five wells in the Utica Shale. Acquisitions of reserves of 133.6 MMBoe includes proved developed producing properties and PUD locations acquired in our Delaware Basin acquisitions, and new proved locations obtained from an acreage exchange transaction. Because of the preferential economics of the more concentrated acreage in the Wattenberg Field, we rescheduled the timing of anticipated development in the field. This resulted in a downward revision to our proved reserves in the revisions of previous estimates category. The net downward revisions were 42.6 MMBoe. The revision was most notably attributed to a 61.0 MMBoe decrease in reserves due to 2015 PUD locations being removed from our five year development plan and being replaced by PUD locations reflected in purchases of reserves. Infill reserve additions of 16.8 MMBoe in the Wattenberg Field were included as a positive revision of previous estimates. Infill reserve additions for years prior to 2016 for the Wattenberg Field were reported in extensions, discoveries, and other additions, including infill reserves in an existing proved field. Revisions also include a 0.5 MMBoe decrease on production due to pricing. The remaining 2.1 MMBoe in positive revisions of previous estimates includes performance revisions and other items. We had minimal dispositions of 1.7 MMBoe related to the acreage we traded in the acreage exchange. At December 31, 2015, we projected a PUD reserve conversion rate of 19 percent for 2016. As a result of revisions to our drilling plan during the last two months of 2016, our actual reserve conversion rate was 16 percent , resulting in 32.2 MMBoe of reserves recorded as PUDs at December 31, 2015, being converted to proved developed reserves as of December 31, 2016. Based on economic conditions on December 31, 2016, our then-current development plan provided for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2016, our 2017 PUD reserve conversion rate was expected to be approximately 26 percent. 2015 Activity. Overall, our proved reserves increased by 23 MMBoe as of December 31, 2015 as compared to December 31, 2014. In 2015, we produced 15.4 MMBoe. At December 31, 2014, we projected a PUD conversion rate of 16 percent for 2015. Our actual conversion rate was 17 percent, resulting in 29 MMBoe of reserves booked as PUDs at December 31, 2014 being converted to proved developed reserves during 2015. As shown, we acquired and divested minimal volumes of proved reserves in 2015. Extensions, discoveries, and other additions, including infill reserves, of approximately 131 MMBoe in 2015 were all added in the Wattenberg Field and primarily related to horizontal Niobrara projects being added to our development plan. The reserve additions associated with these projects were largely the result of data generated from our downspacing testing. This led to increased well density of our PUD locations year-over-year and extended the field by enabling us to book more reserves per section in the Niobrara. In general, at December 31, 2014, Niobrara PUD locations were booked at an equivalent of eight wells per section and at December 31, 2015, such locations were booked at an equivalent of 16 wells per section. Additionally, due to more efficient drilling leading to shorter spud-to-spud times, we have increased the number of wells drilled per drilling rig utilized during the course of the year. We had 791 gross PUD horizontal drilling locations at December 31, 2015, which was an increase from 774 locations at December 31, 2014. Approximately 9 MMBoe of the extensions, discoveries, and other additions to our developed reserves related to wells drilled that were not related to reserves booked as of the prior year-end. We recorded net downward revisions of previous estimates of proved reserves of approximately 93 MMBoe. The revision was a result of multiple factors, most notably a decrease of approximately 56 MMBoe for adjustments to our development plans in the Wattenberg Field resulting from the booking of further-downspaced PUD locations. This downspacing delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. Also contributing to the downward revision was a decrease of approximately 33 MMBoe due to the significant decrease in SEC commodity prices utilized in the December 31, 2015 reserve report, including approximately 11 MMBoe specifically related to the removal of vertical re-fracs and re-completions from the proved developed reserves which no longer fall within our economic parameters. There was an additional negative revision of approximately 22 MMBoe primarily related to geology findings and leasehold factors. Partially offsetting these decreases was an upward revision approximately 18 MMBoe related to well performance and forecast adjustments. Results of Operations for Crude Oil and Natural Gas Producing Activities The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to gas marketing and other income. Comprehensive income (loss) includes net income (loss), as well as other changes in stockholders' equity that result from transactions and economic events other than those with shareholders. There was no difference between our net income (loss) and comprehensive income (loss) for any of the periods presented in the results of operations for crude oil and natural gas producing activities shown. Year Ended December 31, 2017 2016 2015 (in thousands) Revenue: Crude oil, natural gas and NGLs sales $ 913,084 $ 497,353 $ 378,713 Commodity price risk management gain (loss), net (3,936 ) (125,681 ) 203,183 909,148 371,672 581,896 Expenses: Lease operating expenses 89,641 59,950 56,992 Production taxes 60,717 31,410 18,443 Transportation, gathering and processing expenses 33,220 18,415 10,151 Exploration expense 47,334 4,669 1,102 Impairment of properties and equipment 285,887 9,973 161,620 Depreciation, depletion, and amortization 462,482 413,105 298,760 Accretion of asset retirement obligations 6,306 7,080 6,293 Gain on sale of properties and equipment (766 ) (43 ) (385 ) 984,821 544,559 552,976 Results of operations for crude oil and natural gas producing (75,673 ) (172,887 ) 28,920 Provision for income taxes 47,247 64,733 (10,394 ) Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs $ (28,426 ) $ (108,154 ) $ 18,526 Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes, and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration, and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration, and Development Activities Costs incurred in crude oil and natural gas property acquisition, exploration, and development are presented below. Year Ended December 31, 2017 2016 2015 (in thousands) Acquisition of properties: (1) Proved properties $ 172 $ 268,567 $ 3,561 Unproved properties 18,914 1,843,985 15 Development costs (2) 688,165 383,336 552,104 Exploration costs: (3) Exploratory drilling 80,103 — — Geological and geophysical 3,881 4,669 — Total costs incurred (4) $ 791,235 $ 2,500,557 $ 555,680 __________ (1) Property acquisition costs represent costs incurred to purchase, lease, or otherwise acquire a property. Proved properties include approximately $40.9 million of infrastructure and pipeline costs in 2016. (2) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended December 31, 2017 , 2016 , and 2015 , $463.4 million , $204.6 million , and $207.8 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $32.8 million of infrastructure and pipeline costs in 2017. (3) Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. (4) During the year ended 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved, undeveloped and development costs of $24.6 million. We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017. Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: As of December 31, 2017 2016 (in thousands) Proved crude oil and natural gas properties $ 4,356,922 $ 3,499,718 Unproved crude oil and natural gas properties 1,097,317 1,874,671 Uncompleted wells, equipment and facilities 265,526 150,424 Capitalized costs 5,719,765 5,524,813 Less accumulated DD&A (1,803,847 ) (1,534,678 ) Capitalized costs, net $ 3,915,918 $ 3,990,135 Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion, and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits, and allowances related to the properties. The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas, and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. As of December 31, 2017 2016 2015 (in thousands) Future estimated cash flows $ 12,340,407 $ 7,122,525 $ 6,297,298 Future estimated production costs* (3,245,627 ) (1,624,167 ) (1,493,040 ) Future estimated development costs (2,893,335 ) (2,219,914 ) (2,036,685 ) Future estimated income tax expense (748,494 ) (597,476 ) (508,332 ) Future net cash flows 5,452,951 2,680,968 2,259,241 10% annual discount for estimated timing of cash flows (2,572,846 ) (1,260,339 ) (1,162,377 ) Standardized measure of discounted future estimated net cash flows $ 2,880,105 $ 1,420,629 $ 1,096,864 ___________ * Represents future estimated lease operating expenses, production taxes, transportation, gathering, and processing expenses. The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: Year Ended December 31, 2017 2016 2015 (in thousands) Beginning of period $ 1,420,629 $ 1,096,864 $ 2,306,465 Sales of crude oil, natural gas and NGLs production, net of production costs (729,506 ) (387,576 ) (293,127 ) Net changes in prices and production costs (1) 841,713 (205,760 ) (1,752,921 ) Extensions, discoveries, and improved recovery, less related costs 47,240 15,128 489,178 Sales of reserves (2,613 ) (3,745 ) (463 ) Purchases of reserves 224,483 487,636 374 Development costs incurred during the period 419,047 268,672 368,840 Revisions of previous quantity estimates 484,431 (320,286 ) (1,286,462 ) Changes in estimated income taxes (138,560 ) (13,630 ) 902,994 Net changes in future development costs 25,183 391,145 112,958 Accretion of discount 167,487 133,747 345,007 Timing and other 120,571 (41,566 ) (95,979 ) End of period $ 2,880,105 $ 1,420,629 $ 1,096,864 __________ (1) Our weighted-average price, net of production costs per Boe, in our 2017 reserve report increased to $20.08 as compared to $15.73 for 2016 and $17.30 for 2015. The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

SUPPLEMENTAL INFORMATION - QUAR

SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Quarterly Financial Information [Text Block]	QUARTERLY FINANCIAL INFORMATION - UNAUDITED Quarterly financial data for the years ended December 31, 2017 and 2016 is presented below. The quarterly consolidated statements of operations below reflect our revised presentation. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. 2017 Quarter Ended March 31 June 30 September 30 December 31 (in thousands, except per share data) Total revenues $ 273,707 $ 275,158 $ 183,235 $ 189,516 Total costs, expenses and other 182,004 190,522 579,326 208,016 Income (loss) from operations 91,703 84,636 (396,091 ) (18,500 ) Income (loss) before income taxes 72,476 65,787 (414,887 ) (62,808 ) Net income (loss) (1) $ 46,146 $ 41,250 $ (292,537 ) $ 77,637 Earnings per share: Basic $ 0.70 $ 0.63 $ (4.44 ) $ 1.18 Diluted 0.70 0.62 (4.44 ) 1.17 ________ (1) Net income of $77.6 million for the quarter ended December 31, 2017 is primarily due to an income tax benefit of $114.4 million resulting from a decrease in deferred tax assets and liabilities related to the 2017 Tax Act. 2016 Quarter Ended March 31 June 30 September 30 December 31 (in thousands, except per share data) Total revenues $ 90,831 $ 20,097 $ 163,890 $ 108,097 Total costs, expenses and other 193,864 163,379 179,178 178,608 Loss from operations (103,033 ) (143,282 ) (15,288 ) (70,511 ) Loss before income taxes (113,369 ) (153,777 ) (35,341 ) (90,636 ) Net loss $ (71,530 ) $ (95,450 ) $ (23,309 ) $ (55,639 ) Earnings per share: Basic $ (1.72 ) $ (2.04 ) $ (0.48 ) $ (0.94 ) Diluted (1.72 ) (2.04 ) (0.48 ) (0.94 )

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Goodwill [Line Items]
Cash and Cash Equivalents, Policy [Policy Text Block]	We consider all highly liquid investments with original maturities of three months or less to be cash equivalents.
Derivative Financial Instruments, Policy [Policy Text Block]	We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas, and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes. All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We use the normal purchase, normal sale exception for our crude oil and natural gas contracts. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose for issuing or holding the derivative. Net settlements and changes in the fair value of commodity derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Net settlements and changes in the fair value of commodity derivative instruments related to our Gas Marketing segment are recorded in other income and other expenses. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows. The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.
Natugal Gas and Crude Oil Properties, Policy [Policy Text Block]	We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells, and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have three units-of-production fields: the Wattenberg Field, the Delaware Basin, and the Utica Shale. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations, and common cost environments in these areas. We calculate quarterly depreciation, depletion, and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statement of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leasehold, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability, or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded
Proved and Unproved Property, Impairment [Policy Text Block]	The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired, or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates, and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment.
Property, Plant and Equipment, Policy [Policy Text Block]	Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto, and any resulting gain or loss is reflected in income Upon a triggering event, including when general industry conditions warrant review, we assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity will be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas, and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices, or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis. The impairment recorded is the amount by which the net capitalized costs exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A.
Interest Capitalization, Policy [Policy Text Block]	Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset
Assets Held For Sale, Policy [Policy Text Block]	Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third parties, earnings multiples, or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held-for-sale.
Production Tax Liability, Policy [Policy Text Block]	Production tax liability represents estimated taxes, primarily severance, ad valorem, and property taxes, to be paid to the states and counties in which we produce crude oil, natural gas, and NGLs. These taxes are expensed and included in the statements of operations line item production taxes.
Income Tax, Policy [Policy Text Block]	We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2017 and 2016 , we had no valuation allowance.
Debt Issuance Costs, Policy [Policy Text Block]	Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes, and the 2026 Senior Notes are included in long-term debt on the consolidated balance sheets and the debt issuance costs for the revolving credit facility are included in other assets on the consolidated balance sheets.
Asset Retirement Obligation [Policy Text Block]	We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations
Treasury Shares, Policy [Policy Text Block]	We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.
Revenue Recognition, Policy [Policy Text Block]	Crude oil, natural gas, and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred, and collection of revenue is reasonably assured. Our crude oil, natural gas, and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when the purchasers of these commodities also provide transportation, gathering, or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when the purchasers do not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering, and processing expenses. There is a new revenue standard effective for annual reporting periods beginning after December 15, 2017. See Recently Issued Accounting Standards below.
Accounting for Acquisitions using Purchase Accounting [Policy Text Block]	We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices, and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties, and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Stock-Based Compensation, Policy [Policy Text Block]	Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations.
Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block]	We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Issued Accounting Standards In May 2014, the FASB and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The standard has been updated and now includes technical corrections. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations, and (5) recognize revenue when or as each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period; we are adopting the standard effective January 1, 2018. The revenue standard can be adopted under the full retrospective method or modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard will have on our consolidated financial statements, we have performed a comprehensive review of our significant revenue streams. The focus of this review included, among other things, the identification of the significant contracts and other arrangements we have with our customers to identify performance obligations and principal versus agent considerations, and factors affecting the determination of the transaction price. We are also reviewing our current accounting policies, procedures, and controls with respect to these contracts and arrangements to determine what changes, if any, may be required by the adoption of the revenue standard. We have determined that we will adopt the standard under the modified retrospective method. Based upon our review, we currently estimate that adoption of the standard would have reduced our crude oil, natural gas, and NGLs sales by approximately $11.3 million in 2017 with corresponding decreases in transportation, gathering, and processing expenses and no impact on net earnings. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are currently evaluating the impact these changes may have on our consolidated financial statements. In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements. In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements.
New Accounting Pronouncement, Early Adoption [Table Text Block]	Recently Adopted Accounting Standards. In January 2017, the FASB issued an accounting update to simplify the measurement of goodwill. The update eliminates the two-step process that required identification of potential impairment and a separate measure of actual impairment. The annual and/or interim assessments are still required to be completed. The guidance is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the second quarter of 2017. Our annual evaluation of goodwill for impairment was expected to occur in the fourth quarter of 2017; however, we experienced an impairment triggering event as of September 30, 2017 and implemented the new guidance as part of the impairment evaluation. See the footnote titled Goodwill for a detailed description of the results of our impairment testing. In August 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the fourth quarter of 2017. Adoption of this standard did not have an impact on our consolidated financial statements or related disclosures. In January 2017, the FASB issued an accounting update clarifying the definition of a business, with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This guidance is to be applied using a prospective method and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the fourth quarter of 2017. Adoption of this standard did not have an impact on our consolidated financial statements or related disclosures. In May 2017, the FASB issued an accounting update clarifying when to account for a change to the terms or conditions of a share-based payment award as a modification. The guidance is effective for fiscal years beginning on or after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the fourth quarter of 2017. Adoption of this standard did not have an impact on our consolidated financial statements or related disclosures.
Earnings Per Share, Policy [Policy Text Block]	Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes, and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.
Goodwill Disclosure [Text Block]	Goodwill represents the excess of the purchase price over the fair value of net assets acquired, including the additional value resulting from the creation of the deferred tax liability, and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that could contribute to a purchase price in excess of the fair value of the net tangible and intangible assets acquired is the acquisition of an element of a workforce and the expected value from operations of the acquisition to be derived in the future, such as production from future development of additional producing zones. We evaluate goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit to the carrying value. We determine the fair value of the goodwill at the impairment evaluation date by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value is based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. GOODWILL The final goodwill that resulted from the purchase price allocation of the business combination in the Delaware Basin in December 2016 was determined to be $ 75.1 million . With the creation of goodwill from this transaction, we expected to perform our evaluation of goodwill for impairment annually in the fourth quarter. However, primarily due to a combination of increases in per well development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin subsequent to the acquisition, in conjunction with the then current lower future commodity price outlook, we determined that a triggering event had occurred in the third quarter of 2017. In addition to the factors mentioned above, we also considered our impairments of certain unproven leasehold costs during the third quarter of 2017 and the impact of these items on our internal expectations for acceptable rates of return. We evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. We determined the fair value of the goodwill at September 30, 2017 by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value was based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. The quantitative test resulted in a determination that a full impairment charge of $ 75.1 million was required; therefore, the charge was recorded in the third quarter of 2017.
Consolidation, Policy [Policy Text Block]	All intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates, Policy [Policy Text Block]	The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas, and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill; valuation and allocations of purchased businesses and assets; estimates of fair value of our fixed rate debt instruments; and valuation of deferred income tax assets

SUMMARY OF SIGNIFICANT ACCOUN28

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Property, Plant and Equipment, Estimated Useful Lives [Table Text Block]	Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. The following table presents the estimated useful lives of our other property and equipment: Transportation, pipeline, and other equipment 2 - 30 years Buildings 20 - 40 years

BUSINESS COMBINATIONS BUSINES29

BUSINESS COMBINATIONS BUSINESS COMBINATIONS (Tables)	12 Months Ended
	Dec. 31, 2016
Business Combinations Abstract [Abstract]
Business Combination, Segment Allocation [Table Text Block]	Year Ended December 31, 2016 Acquisition costs: Cash, net of cash acquired $ 905,962 Retirement of seller's debt 40,000 Total cash consideration 945,962 Common stock 690,702 Other purchase price adjustments 426 Total acquisition costs $ 1,637,090 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current Assets $ 6,401 Crude oil and natural gas properties - proved 216,000 Crude oil and natural gas properties - unproved 1,697,000 Infrastructure, pipeline, and other 33,153 Construction in progress 12,323 Goodwill 75,121 Total assets acquired 2,039,998 Liabilities assumed: Current liabilities (24,496 ) Asset retirement obligations (3,705 ) Deferred tax liabilities, net (374,707 ) Total liabilities assumed (402,908 ) Total identifiable net assets acquired $ 1,637,090
Business Acquisition, Pro Forma Information [Table Text Block]	Pro Forma Information. The results of operations for the Delaware Basin acquisition have been included in our consolidated financial statements since the December 6, 2016 closing date, including approximately $5.6 million of total revenue and $1.7 million of loss from operations in our statements of operations for the year ended December 31, 2016. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2016 and December 31, 2015, assuming the acquisition had been completed as of January 1, 2015. This pro forma financial information includes proceeds from the sale of 9,085,000 shares of our common stock, the 2021 Convertible Notes, and the 2024 Senior Notes in September 2016, the shares issued to the sellers, and other acquisition costs. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results. Years Ended December 31, 2016 2015 (in thousands, except per share amounts) Total revenue $ 412,746 $ 598,932 Net loss $ (270,942 ) $ (138,904 ) Earnings per share: Basic and diluted $ (4.22 ) $ (2.41 )

FAIR VALUE MEASUREMENTS AND D30

FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: As of December 31, 2017 2016 Significant Other Significant Total Significant Other Significant Total (in thousands) Total assets $ 12,949 $ 1,389 $ 14,338 $ 6,350 $ 4,827 $ 11,177 Total liabilities 90,569 11,076 101,645 66,789 14,401 81,190 Net liability $ (77,620 ) $ (9,687 ) $ (87,307 ) $ (60,439 ) $ (9,574 ) $ (70,013 )
Fair Value Assets and Liabilities Unobservable Input Reconciliation [Table Text Block]	The following table presents a reconciliation of our Level 3 commodity derivative instruments measured at fair value: 2017 2016 2015 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ (9,574 ) $ 91,288 $ 62,356 Changes in fair value included in consolidated statements of operations line item: Commodity price risk management gain (loss), net 6,241 (28,550 ) 65,164 Settlements included in consolidated statements of operations line items: Commodity price risk management ( loss) , net (6,354 ) (72,312 ) (36,232 ) Fair value of Level 3 instruments, net asset (liability) end of period $ (9,687 ) $ (9,574 ) $ 91,288 Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: Commodity price risk management gain (loss), net $ (866 ) $ (12,905 ) $ 43,540 Total $ (866 ) $ (12,905 ) $ 43,540
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of December 31, 2017 : Estimated Fair Value % of Par (in millions) Senior notes: 2021 Convertible Notes $ 195.6 97.8 % 2024 Senior Notes 416.0 104.0 % 2026 Senior Notes 616.5 102.8 %

DERIVATIVE FINANCIAL INSTRUME31

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	The following table presents the balance sheet location and fair value amounts of our commodity derivative instruments on the consolidated balance sheets as of December 31, 2017 and 2016 : Derivative instruments: Consolidated balance sheet line item 2017 2016 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 7,340 $ 8,490 Basis protection derivative contracts Fair value of derivatives 6,998 301 14,338 8,791 Non-current Commodity derivative contracts Fair value of derivatives — 1,123 Basis protection derivative contracts Fair value of derivatives — 1,263 — 2,386 Total derivative assets $ 14,338 $ 11,177 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 77,999 53,565 Basis protection derivative contracts Fair value of derivatives 234 30 Rollfactor derivative contracts Fair value of derivatives 1,069 — 79,302 53,595 Non-current Commodity derivative contracts Fair value of derivatives 22,343 27,595 Total derivative liabilities $ 101,645 $ 81,190 The following table presents the impact of our derivative instruments on our consolidated statements of operations: Year Ended December 31, Consolidated statements of operations line item 2017 2016 2015 (in thousands) Commodity price risk management gain (loss), net Net settlements $ 13,324 $ 208,103 $ 238,935 Net change in fair value of unsettled derivatives (17,260 ) (333,784 ) (35,752 ) Total commodity price risk management gain (loss), net $ (3,936 ) $ (125,681 ) $ 203,183 All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. The following table reflects the impact of netting agreements on gross derivative assets and liabilities: As of December 31, 2017 Derivative instruments, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 14,338 $ (14,173 ) $ 165 Liability derivatives: Derivative instruments, at fair value $ 101,645 $ (14,173 ) $ 87,472 As of December 31, 2016 Derivative instruments, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 11,177 $ (10,930 ) $ 247 Liability derivatives: Derivative instruments, at fair value $ 81,190 $ (10,930 ) $ 70,260

CONCENTRATION OF RISK Accounts

CONCENTRATION OF RISK Accounts Receivable, net of Allowance for Doubtful Accounts (Tables)	12 Months Ended
	Dec. 31, 2017
Concentration Risks, Types, No Concentration Percentage [Abstract]
Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Current [Text Block]	Other Accrued Expenses. The following table presents the components of other accrued expenses: As of December 31, 2017 2016 (in thousands) Employee benefits $ 22,383 $ 22,282 Asset retirement obligations 15,801 9,775 Environmental expenses 1,374 3,238 Other 3,429 3,330 Other accrued expenses $ 42,987 $ 38,625
Accounts Receivable [Table Text Block]	Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: As of December 31, 2017 2016 (in thousands) Crude oil, natural gas, and NGLs sales $ 154,260 $ 97,520 Joint interest billings (1) 34,576 20,118 Derivative counterparties (18 ) 10,266 Income tax receivable 6,015 11,505 Other 5,893 6,173 Allowance for doubtful accounts (3,128 ) (2,190 ) Accounts receivable, net $ 197,598 $ 143,392
Individual Customers Constituting 10% or more of Total Revenue [Table Text Block]	Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues: Year Ended December 31, Customer 2017 2016 2015 DCP Midstream, LP 19.6 % 20.2 % 13.2 % Suncor Energy Marketing, Inc. 16.4 % 22.3 % 14.3 % Aka Energy Group, LLC — % 13.4 % — % Concord Energy, LLC — % 13.4 % 23.2 % Bridger Energy, LLC — % 11.5 % — % Shell Trading Company — % — % 13.8 %

PROPERTIES AND EQUIPMENT Proper

PROPERTIES AND EQUIPMENT Properties and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization [Table Text Block]	The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the consolidated balance sheet: 2017 (in thousands, except for number of wells) Beginning balance $ — Additions to capitalized exploratory well costs pending the determination of proved reserves 51,776 Reclassifications to proved properties (36,328 ) Balance at December 31, $ 15,448 Number of wells pending determination at December 31, 3
Property, Plant and Equipment [Table Text Block]	The following table presents the components of properties and equipment, net of accumulated DD&A: As of December 31, 2017 2016 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 4,356,922 $ 3,499,718 Unproved 1,097,317 1,874,671 Total crude oil and natural gas properties 5,454,239 5,374,389 Infrastructure, pipeline, and other 109,359 62,093 Land and buildings 10,960 6,392 Construction in progress 196,024 122,591 Properties and equipment, at cost 5,770,582 5,565,465 Accumulated DD&A (1,837,115 ) (1,562,471 ) Properties and equipment, net $ 3,933,467 $ 4,002,994
Impairment of natural gas and crude oil properties [Table Text Block]	The following table presents impairment charges recorded for properties and equipment: Year Ended December 31, 2017 2016 2015 (in thousands) Impairment of proved and unproved properties $ 285,465 $ 5,562 $ 154,608 Amortization of individually insignificant unproved properties 422 1,379 7,012 Land and buildings — 3,032 — Total impairment of properties and equipment $ 285,887 $ 9,973 $ 161,620

PROPERTIES AND EQUIPMENT Explor

PROPERTIES AND EQUIPMENT Exploration, Geologic, and Geophysical Expense (Tables)	12 Months Ended
	Dec. 31, 2017
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	Exploration Expenses. The following table presents the major components of exploration, geologic, and geophysical expense: Year Ended December 31, 2017 2016 2015 (in thousands) Exploratory dry hole costs $ 41,297 $ — $ — Geological and geophysical costs, including seismic purchases 3,881 3,472 — Operating, personnel and other 2,156 1,197 1,102 Total exploration, geologic, and geophysical expense $ 47,334 $ 4,669 $ 1,102 Costs incurred in crude oil and natural gas property acquisition, exploration, and development are presented below. Year Ended December 31, 2017 2016 2015 (in thousands) Acquisition of properties: (1) Proved properties $ 172 $ 268,567 $ 3,561 Unproved properties 18,914 1,843,985 15 Development costs (2) 688,165 383,336 552,104 Exploration costs: (3) Exploratory drilling 80,103 — — Geological and geophysical 3,881 4,669 — Total costs incurred (4) $ 791,235 $ 2,500,557 $ 555,680 __________ (1) Property acquisition costs represent costs incurred to purchase, lease, or otherwise acquire a property. Proved properties include approximately $40.9 million of infrastructure and pipeline costs in 2016. (2) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended December 31, 2017 , 2016 , and 2015 , $463.4 million , $204.6 million , and $207.8 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $32.8 million of infrastructure and pipeline costs in 2017. (3) Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. (4) During the year ended 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved, undeveloped and development costs of $24.6 million. We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017.

PROPERTIES AND EQUIPMENT Assets

PROPERTIES AND EQUIPMENT Assets held-for-sale (Tables)	12 Months Ended
	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disclosure of Long Lived Assets Held-for-sale [Table Text Block]	The following table presents balance sheet data related to assets held-for-sale, which include the Utica Shale properties, field office facilities, and a parcel of land that are being marketed for sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities that are expected to be assumed by the purchasers: December 31, 2017 December 31, 2016 (in thousands) Assets Properties and equipment, net $ 40,583 $ 5,272 Total assets $ 40,583 $ 5,272 Liabilities Asset retirement obligation $ 499 $ — Total liabilities $ 499 $ — Net assets $ 40,084 $ 5,272

LONG-TERM DEBT LONG-TERM DEBT (

LONG-TERM DEBT LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2017
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	Long-term debt consists of the following: As of December 31, 2017 2016 (in thousands) Senior notes: 1.125% Convertible Notes due 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (30,328 ) (37,475 ) Unamortized debt issuance costs (3,615 ) (4,584 ) 1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs 166,057 157,941 6.125% Senior Notes due 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (6,570 ) (7,544 ) 6.125% Senior Notes due 2024, net of unamortized debt issuance costs 393,430 392,456 5.75% Senior Notes due 2026: Principal amount 600,000 — Unamortized debt issuance costs (7,555 ) — 5.75% Senior Notes due 2026, net of unamortized debt issuance costs 592,445 — 7.75% Senior notes redeemed 2017: Principal amount — 500,000 Unamortized debt issuance costs — (6,443 ) 7.75% Senior notes redeemed 2017, net of unamortized debt issuance costs — 493,557 Total senior notes 1,151,932 1,043,954 Revolving credit facility — — Total long-term debt, net of unamortized discount and debt issuance costs 1,151,932 1,043,954 Less current portion of long-term debt — — Long-term debt $ 1,151,932 $ 1,043,954

CAPITAL LEASES CAPITAL LEASES37

CAPITAL LEASES CAPITAL LEASES (Tables)	12 Months Ended
	Dec. 31, 2017
Capital Leases [Abstract]
Schedule of Capital Leased Assets [Table Text Block]	The following table presents leased vehicles under capital leases: As of December 31, 2017 2016 (in thousands) Vehicles $ 6,249 $ 2,975 Accumulated depreciation (1,882 ) (776 ) $ 4,367 $ 2,199
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]	Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following: For the Twelve Months Ending December 31, Amount (in thousands) 2018 $ 2,075 2019 1,623 2020 1,507 5,205 Less executory cost (235 ) Less amount representing interest (537 ) Present value of minimum lease payments $ 4,433 Short-term capital lease obligations $ 1,672 Long-term capital lease obligations 2,761 $ 4,433

INCOME TAXES Income Taxes (Tabl

INCOME TAXES Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The table below presents the components of our provision for income taxes from continuing operations for the years presented: Year Ended December 31, 2017 2016 2015 (in thousands) Current: Federal $ 8,443 $ 9,646 $ (2,944 ) State (200 ) 300 (163 ) Total current income tax (expense) benefit 8,243 9,946 (3,107 ) Deferred: Federal 193,809 118,427 37,352 State 9,876 18,822 4,063 Total deferred income tax benefit 203,685 137,249 41,415 Income tax benefit from continuing operations $ 211,928 $ 147,195 $ 38,308
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The following table presents a reconciliation of the statutory rate to the effective tax rate related to our benefit for income taxes from continuing operations: Year Ended December, 31, 2017 2016 2015 Statutory tax rate 35.0 % 35.0 % 35.0 % State income tax, net 1.8 2.6 2.7 Effect of state income tax rate changes — 0.6 (0.3 ) Percentage depletion — — 0.3 Non-deductible compensation (0.3 ) (0.5 ) (1.2 ) Federal tax reform rate reduction 33.7 — — Non-deductible goodwill impairment (7.7 ) — — Other (0.1 ) (0.3 ) (0.6 ) Effective tax rate 62.4 % 37.4 % 35.9 %
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	ax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2017 and 2016 are presented below. The 2017 amounts include the reduction of our deferred tax assets and liabilities to a projected combined federal and state deferred tax rate of 23.9 percent as a result of the 2017 Tax Act. Also in 2017, deferred tax liability for properties and equipment was reduced by $94.1 million as a result of recording an impairment charge related to a portion of the Delaware Basin assets. The 2016 amounts include the $403.7 million effect of including the deferred tax liability for the difference in the book and tax basis of the oil and gas properties acquired in a 2016 business combination and $23.8 million of acquired deferred tax assets: As of December 31, 2017 2016 (in thousands) Deferred tax assets: Deferred compensation $ 6,059 $ 9,338 Asset retirement obligations 21,760 34,359 Federal NOL carryforward 19,386 29,988 State NOL and tax credit carryforwards, net 7,815 5,189 Federal tax - credit carryforwards 4,366 5,184 Allowance for note receivable — 17,292 Net change in fair value of unsettled derivatives 20,929 26,262 Other 2,453 4,716 Total gross deferred tax assets 82,768 132,328 Deferred tax liabilities: Properties and equipment 267,498 518,964 Convertible debt 7,262 14,231 Total gross deferred tax liabilities 274,760 533,195 Net deferred tax liability $ 191,992 $ 400,867

ASSET RETIREMENT OBLIGATIONS As

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	The following table presents the changes in carrying amounts of the asset retirement obligations associated with our crude oil and natural gas properties and midstream assets: 2017 2016 (in thousands) Beginning balance $ 92,387 $ 89,492 Obligations incurred with development activities 3,638 4,894 Accretion expense 6,306 7,080 Revisions in estimated cash flows (2,860 ) — Obligations discharged with asset retirements (12,165 ) (9,079 ) Balance at December 31 87,306 92,387 Less liabilities held-for-sale (499 ) — Less current portion (15,801 ) (9,775 ) Long-term portion $ 71,006 $ 82,612

COMMITMENTS AND CONTINGENCIES C

COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Supply Commitment [Table Text Block]	The following table presents gross volume information related to our long-term firm transportation, sales, and processing agreements for pipeline capacity: Year Ending December 31, Area 2018 2019 2020 2021 2022 and Total Expiration Natural gas (MMcf) Wattenberg Field 3,541 23,934 31,110 31,025 121,922 211,532 April 30, 2026 Delaware Basin 14,600 14,600 14,640 — — 43,840 December 31, 2020 Gas Marketing 7,117 7,117 7,136 7,056 4,495 32,921 August 31, 2022 Utica Shale (1) 2,738 2,738 2,745 2,738 4,326 15,285 July 31, 2023 Total 27,996 48,389 55,631 40,819 130,743 303,578 Crude oil (MBbls) Wattenberg Field 3,638 4,239 1,808 — — 9,685 June 30, 2020 Dollar commitment (in thousands) $ 23,176 $ 43,855 $ 42,496 $ 33,226 $ 118,927 $ 261,680 (1) In February 2018, we entered into a PSA to sell the Utica Shale properties. This commitment would be assumed by the purchaser of the Utica Shale properties.
Schedule of Minimum Future Lease Payments under the Non-cancelable Operating Leases [Table Text Block]	The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2017 : Year Ending December 31, 2018 2019 2020 2021 2022 Thereafter Total (in thousands) Minimum Lease Payments $ 3,865 $ 3,865 $ 3,932 $ 3,998 $ 4,078 $ 3,515 $ 23,253

COMMON STOCK Common Stock (Tabl

COMMON STOCK Common Stock (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Schedule of Stock by Class [Table Text Block]	The following table provides a summary of our public offerings of common stock in 2016 and 2015: Date Shares Issued Price per Share Net Proceeds (in millions) September 2016 9,085,000 $ 61.51 $ 558.5 March 2016 5,922,500 50.11 296.6 March 2015 4,002,000 50.73 202.9
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]	The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: Year Ended December 31, 2017 2016 2015 (in thousands) Stock-based compensation expense $ 19,353 $ 19,502 $ 20,068 Income tax benefit (7,372 ) (7,296 ) (7,636 ) Net stock-based compensation expense $ 11,981 $ 12,206 $ 12,432
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]	he Compensation Committee has awarded SARs to our executive officers in 2017, 2016, and 2015. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: Year Ended December 31, 2017 2016 2015 Expected term of award (in years) 6.0 years 6.0 years 5.2 years Risk-free interest rate 2.0 % 1.8 % 1.4 % Expected volatility 53.3 % 54.5 % 58.0 % Weighted-average grant date fair value per share $ 38.58 $ 26.96 $ 22.23
Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity [Table Text Block]	The following table presents the changes in our SARs for all periods presented (in thousands, except per share data): Year Ended December 31, 2017 2016 2015 Number of Weighted-Average Average Remaining Contractual (in years) Aggregate Intrinsic Number of Weighted-Average Aggregate Intrinsic Number of Weighted-Average Aggregate Intrinsic Outstanding at January 1, 244,078 $ 41.36 6.9 $ 7,620 326,453 $ 38.99 $ 4,697 279,011 $ 38.77 $ 1,472 Awarded 54,142 74.57 — — 58,709 51.63 — 68,274 39.63 — Exercised — — — — (141,084 ) 40.16 2,770 (20,832 ) 38.05 473 Outstanding at December 31 298,220 47.39 6.5 2,490 244,078 41.36 7,620 326,453 38.99 4,697 Exercisable at December 31 223,865 43.28 5.9 2,267 174,919 38.72 5,924 222,489 37.70 3,489
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]	The following table presents the changes in non-vested time-based RSUs during 2017 : Shares Weighted-Average Non-vested at December 31, 2016 479,642 $ 56.09 Granted 273,941 65.14 Vested (266,809 ) 57.67 Forfeited (14,642 ) 62.92 Non-vested at December 31, 2017 472,132 60.23 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2017 2016 2015 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 16,303 $ 18,973 $ 17,077 Total intrinsic value of time-based awards non-vested 24,334 34,812 28,029 Market price per common share as of December 31, 51.54 72.58 53.38 Weighted-average grant date fair value per share 65.14 58.52 48.88
Restricted Stock Awards, Market-Based, Valuation assumptions [Table Text Block]	he weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions: Year Ended December 31, 2017 2016 2015 Expected term of award (in years) 3 years 3 years 3 years Risk-free interest rate 1.4 % 1.2 % 0.9 % Expected volatility 51.4 % 52.3 % 53.0 % Weighted-average grant date fair value per share $ 94.02 $ 72.54 $ 66.16
Schedule of Nonvested Performance-based Units Activity [Table Text Block]	The following table presents the change in non-vested market-based awards during 2017 : Shares Weighted-Average Non-vested at December 31, 2016 48,420 $ 64.97 Granted 28,069 94.02 Vested (24,140 ) 57.35 Non-vested at December 31, 2017 52,349 84.06 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2017 2016 2015 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ 2,687 $ 6,562 $ 4,293 Total intrinsic value of market-based awards non-vested 2,698 3,514 3,819 Market price per common share as of December 31, 51.54 72.58 53.38 Weighted-average grant date fair value per share 94.02 72.54 66.16

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation [Table Text Block]	The following table presents a reconciliation of the weighted-average diluted shares outstanding: Year Ended December 31, 2017 2016 2015 (in thousands) Weighted-average common shares outstanding - basic 65,837 49,052 39,153 Weighted-average common shares and equivalents outstanding - diluted 65,837 49,052 39,153
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: Year Ended December 31, 2017 2016 2015 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: Restricted stock 590 689 831 Convertible notes — 292 562 Other equity-based awards 75 109 101 Total anti-dilutive common share equivalents 665 1,090 1,494

SUBSIDIARY GUARANTOR SUBSIDIA43

SUBSIDIARY GUARANTOR SUBSIDIARY GUARANTOR (Tables)	12 Months Ended
	Dec. 31, 2017
Guarantor Obligations [Line Items]
Schedule of Guarantor Obligations [Table Text Block]	The following consolidating financial statements have been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column. Consolidating Balance Sheets December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets: Cash and cash equivalents $ 180,675 $ — $ — $ 180,675 Accounts receivable, net 160,490 37,108 — 197,598 Fair value of derivatives 14,338 — — 14,338 Prepaid expenses and other current assets 8,284 329 — 8,613 Total current assets 363,787 37,437 — 401,224 Properties and equipment, net 1,891,314 2,042,153 — 3,933,467 Assets held-for-sale, net 40,084 — — 40,084 Intercompany receivable 250,279 — (250,279 ) — Investment in subsidiaries 1,617,537 — (1,617,537 ) — Other assets 42,547 2,569 — 45,116 Total Assets $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 85,000 $ 65,067 $ — $ 150,067 Production tax liability 35,902 1,752 — 37,654 Fair value of derivatives 79,302 — — 79,302 Funds held for distribution 83,898 11,913 — 95,811 Accrued interest payable 11,812 3 — 11,815 Other accrued expenses 42,543 444 — 42,987 Total current liabilities 338,457 79,179 — 417,636 Intercompany payable — 250,279 (250,279 ) — Long-term debt 1,151,932 — — 1,151,932 Deferred income taxes 62,857 129,135 — 191,992 Asset retirement obligations 65,301 5,705 — 71,006 Fair value of derivatives 22,343 — — 22,343 Other liabilities 57,009 324 — 57,333 Total liabilities 1,697,899 464,622 (250,279 ) 1,912,242 Stockholders' equity Common shares 659 — — 659 Additional paid-in capital 2,503,294 1,766,775 (1,766,775 ) 2,503,294 Retained earnings 6,704 (149,238 ) 149,238 6,704 Treasury shares (3,008 ) — — (3,008 ) Total stockholders' equity 2,507,649 1,617,537 (1,617,537 ) 2,507,649 Total Liabilities and Stockholders' Equity $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Consolidating Balance Sheets December 31, 2016 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets: Cash and cash equivalents $ 240,487 $ 3,613 $ — $ 244,100 Accounts receivable, net 134,589 8,803 — 143,392 Fair value of derivatives 8,791 — — 8,791 Prepaid expenses and other current assets 3,442 100 — 3,542 Total current assets 387,309 12,516 — 399,825 Properties and equipment, net 1,884,147 2,118,847 — 4,002,994 Assets held-for-sale, net 5,272 — — 5,272 Intercompany receivable 9,415 — (9,415 ) — Investment in subsidiaries 1,765,092 — (1,765,092 ) — Fair value of derivatives 2,386 — — 2,386 Goodwill — 62,041 — 62,041 Other assets 13,153 171 — 13,324 Total Assets $ 4,066,774 $ 2,193,575 $ (1,774,507 ) $ 4,485,842 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 38,748 $ 27,574 $ — $ 66,322 Production tax liability 24,401 366 — 24,767 Fair value of derivatives 53,595 — — 53,595 Funds held for distribution 65,022 6,317 — 71,339 Accrued interest payable 15,930 — — 15,930 Other accrued expenses 37,425 1,200 — 38,625 Total current liabilities 235,121 35,457 — 270,578 Intercompany payable — 9,415 (9,415 ) — Long-term debt 1,043,954 — — 1,043,954 Deferred income taxes 20,971 379,896 — 400,867 Asset retirement obligations 78,897 3,715 — 82,612 Fair value of derivatives 27,595 — — 27,595 Other liabilities 37,482 — — 37,482 Total liabilities 1,444,020 428,483 (9,415 ) 1,863,088 Stockholders' equity Common shares 657 — — 657 Additional paid-in capital 2,489,557 1,766,775 (1,766,775 ) 2,489,557 Retained earnings 134,208 (1,683 ) 1,683 134,208 Treasury shares (1,668 ) — — (1,668 ) Total stockholders' equity 2,622,754 1,765,092 (1,765,092 ) 2,622,754 Total Liabilities and Stockholders' Equity $ 4,066,774 $ 2,193,575 $ (1,774,507 ) $ 4,485,842 Consolidating Statements of Operations Year Ended December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas, and NGLs sales $ 788,400 $ 124,684 $ — $ 913,084 Commodity price risk management gain (loss), net (3,936 ) — — (3,936 ) Other income 11,901 567 — 12,468 Total revenues 796,365 125,251 — 921,616 Costs, expenses and other Lease operating expenses 68,031 21,610 — 89,641 Production taxes 53,236 7,481 — 60,717 Transportation, gathering, and processing expenses 23,301 9,919 — 33,220 Exploration, geologic, and geophysical expense 1,092 46,242 — 47,334 Impairment of properties and equipment 4,951 280,936 — 285,887 Impairment of goodwill — 75,121 — 75,121 General and administrative expense 107,518 12,852 — 120,370 Depreciation, depletion and amortization 403,984 65,100 — 469,084 Provision for uncollectible notes receivable (40,203 ) — — (40,203 ) Accretion of asset retirement obligations 5,965 341 — 6,306 Gain on sale of properties and equipment (766 ) — — (766 ) Other expenses 13,157 — — 13,157 Total costs, expenses and other 640,266 519,602 — 1,159,868 Income (loss) from operations 156,099 (394,351 ) — (238,252 ) Loss on extinguishment of debt (24,747 ) — — (24,747 ) Interest expense (79,919 ) 1,225 — (78,694 ) Interest income 2,261 — — 2,261 Income (loss) before income taxes 53,694 (393,126 ) — (339,432 ) Income tax (expense) benefit (33,643 ) 245,571 — 211,928 Equity in loss of subsidiary (147,555 ) — 147,555 — Net loss $ (127,504 ) $ (147,555 ) $ 147,555 $ (127,504 ) Net losses of the Guarantor for the year ended 2017 are primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions, and the impairment of goodwill. Consolidating Statements of Operations Year Ended December 31, 2016 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas, and NGLs sales $ 491,750 $ 5,603 $ — $ 497,353 Commodity price risk management gain (loss), net (125,681 ) — — (125,681 ) Other income 11,241 2 — 11,243 Total revenues 377,310 5,605 — 382,915 Costs, expenses and other Lease operating expenses 58,401 1,549 — 59,950 Production taxes 31,132 278 — 31,410 Transportation, gathering, and processing expenses 18,263 152 — 18,415 Exploration, geologic, and geophysical expense 1,197 3,472 — 4,669 Impairment of properties and equipment 9,973 — — 9,973 General and administrative expense 112,166 304 — 112,470 Depreciation, depletion and amortization 415,321 1,553 — 416,874 Provision for uncollectible notes receivable 44,038 — — 44,038 Accretion of asset retirement obligations 7,070 10 — 7,080 Gain on sale of properties and equipment (43 ) — — (43 ) Other expenses 10,193 — — 10,193 Total costs, expenses and other 707,711 7,318 — 715,029 Loss from operations (330,401 ) (1,713 ) — (332,114 ) Interest expense (62,002 ) 30 — (61,972 ) Interest income 963 — — 963 Loss before income taxes (391,440 ) (1,683 ) — (393,123 ) Income tax benefit 147,195 — — 147,195 Equity in loss of subsidiary (1,683 ) — 1,683 — Net loss $ (245,928 ) $ (1,683 ) $ 1,683 $ (245,928 ) Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 537,704 $ 50,859 $ — $ 588,563 Cash flows from investing activities: Capital expenditures for development of crude oil and natural properties (439,897 ) (297,311 ) — (737,208 ) Capital expenditures for other properties and equipment (3,539 ) (1,555 ) — (5,094 ) Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition (21,000 ) 5,372 — (15,628 ) Proceeds from sale of properties and equipment 10,084 (93 ) — 9,991 Sale of promissory note 40,203 — — 40,203 Restricted cash (9,250 ) — — (9,250 ) Sale of short-term investments 49,890 — — 49,890 Purchase of short-term investments (49,890 ) — — (49,890 ) Intercompany transfers (239,191 ) — 239,191 — Net cash from investing activities (662,590 ) (293,587 ) 239,191 (716,986 ) Cash flows from financing activities: Proceeds from issuance of senior notes 592,366 — — 592,366 Redemption of senior notes (519,375 ) — — (519,375 ) Purchase of treasury stock (6,672 ) — — (6,672 ) Payment of debt issuance costs (50 ) — — (50 ) Other (1,195 ) (76 ) — (1,271 ) Intercompany transfers — 239,191 (239,191 ) — Net cash from financing activities 65,074 239,115 (239,191 ) 64,998 Net change in cash and cash equivalents (59,812 ) (3,613 ) — (63,425 ) Cash and cash equivalents, beginning of period 240,487 3,613 — 244,100 Cash and cash equivalents, end of period $ 180,675 $ — $ — $ 180,675 Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2016 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 492,893 $ (6,630 ) $ — $ 486,263 Cash flows from investing activities: Capital expenditures for development of crude oil and natural properties (436,361 ) (523 ) — (436,884 ) Capital expenditures for other properties and equipment (2,282 ) (1,182 ) — (3,464 ) Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition (1,076,256 ) 2,533 — (1,073,723 ) Proceeds from sale of properties and equipment 4,945 — — 4,945 Intercompany transfers (9,415 ) — 9,415 — Net cash from investing activities (1,519,369 ) 828 9,415 (1,509,126 ) Cash flows from financing activities: Proceeds from issuance of equity, net of issuance costs 855,074 — — 855,074 Proceeds from issuance of senior notes 392,172 — — 392,172 Proceeds from issuance of convertible senior notes 193,935 — — 193,935 Proceeds from revolving credit facility 85,000 — — 85,000 Repayment of revolving credit facility (122,000 ) — — (122,000 ) Redemption of convertible notes (115,000 ) — — (115,000 ) Payment of debt issuance costs (15,556 ) — — (15,556 ) Purchase of treasury shares (6,935 ) — — (6,935 ) Other (577 ) — — (577 ) Intercompany transfers — 9,415 (9,415 ) — Net cash from financing activities 1,266,113 9,415 (9,415 ) 1,266,113 Net change in cash and cash equivalents 239,637 3,613 — 243,250 Cash and cash equivalents, beginning of period 850 — — 850 Cash and cash equivalents, end of period $ 240,487 $ 3,613 $ — $ 244,100 The condensed consolidating financial statements for the year ended December 31, 2016 represent one month of activity for the Guarantor as the Delaware Basin acquisition occurred in December 2016.

SUPPLEMENTAL INFORMATION - NA44

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Supplemental Information on Natural Gas and Crude Oil Exploration, Development and Production Activities (Tables) - bbl	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reserve Quantities [Line Items]
Production	(31,830,000)	(22,176,000)	(15,369,000)
Index price for reserves, by commodity [Table Text Block]	The indicated index prices for our reserves, by commodity, are presented below. Average Benchmark Prices (1) As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) (2) 2017 $ 51.34 $ 2.98 $ 51.34 2016 42.75 2.48 42.75 2015 50.28 2.59 50.28
Schedule of Prices Used to Estimate Natural Gas and Crude Oil Reserves [Table Text Block]	The netted back price used to estimate our reserves, by commodity, are presented below. Price Used to Estimate Reserves (3) As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) (2) 2017 $ 48.68 $ 2.31 $ 20.21 2016 38.67 1.85 11.97 2015 42.10 2.05 12.23
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]	The following tables present the changes in our estimated quantities of proved reserves: Crude Oil, Condensate (MBbls) Natural Gas (MMcf) NGLs (MBbls) Total (MBoe) Proved Reserves: Proved reserves, January 1, 2015 100,515 536,972 60,119 250,129 Revisions of previous estimates (43,268 ) (154,775 ) (24,407 ) (93,471 ) Extensions, discoveries, and other additions 48,707 311,709 30,835 131,494 Acquisition of reserves 17 215 23 76 Dispositions (12 ) (82 ) (8 ) (34 ) Production (6,984 ) (33,302 ) (2,835 ) (15,369 ) Proved reserves, December 31, 2015 98,975 660,737 63,727 272,825 Revisions of previous estimates (22,097 ) (80,426 ) (7,130 ) (42,631 ) Extensions, discoveries, and other additions 494 4,094 355 1,531 Acquisition of reserves 50,126 305,224 32,586 133,583 Dispositions (601 ) (4,202 ) (424 ) (1,725 ) Production (8,728 ) (51,730 ) (4,826 ) (22,176 ) Proved reserves, December 31, 2016 118,169 833,697 84,288 341,407 Revisions of previous estimates 28,334 96,119 8,104 52,457 Extensions, discoveries, and other additions 2,923 11,541 1,158 6,005 Acquisition of reserves 18,971 289,223 19,604 86,778 Dispositions (653 ) (4,597 ) (481 ) (1,900 ) Production (12,902 ) (71,689 ) (6,981 ) (31,830 ) Proved reserves, December 31, 2017 154,842 1,154,294 105,692 452,917 Proved Developed Reserves, as of: December 31, 2015 26,257 175,367 15,011 70,496 December 31, 2016 30,013 264,452 24,196 98,284 December 31, 2017 46,862 365,332 35,220 142,971 Proved Undeveloped Reserves, as of: December 31, 2015 72,718 485,370 48,716 202,329 December 31, 2016 88,156 569,245 60,092 243,122 December 31, 2017 107,980 788,962 70,472 309,946 Developed Undeveloped Total (MBoe) Proved reserves, January 1, 2015 74,905 175,224 250,129 Undeveloped reserves converted to developed 29,090 (29,090 ) — Revisions of previous estimates (26,875 ) (66,596 ) (93,471 ) Extensions, discoveries, and other additions 8,703 122,791 131,494 Acquisition of reserves 76 — 76 Dispositions (34 ) — (34 ) Production (15,369 ) — (15,369 ) Proved reserves, December 31, 2015 70,496 202,329 272,825 Undeveloped reserves converted to developed 32,192 (32,192 ) — Revisions of previous estimates 6,112 (48,743 ) (42,631 ) Extensions, discoveries, and other additions 1,531 — 1,531 Acquisition of reserves 10,229 123,354 133,583 Dispositions (99 ) (1,626 ) (1,725 ) Production (22,176 ) — (22,176 ) Proved reserves, December 31, 2016 98,285 243,122 341,407 Undeveloped reserves converted to developed 54,648 (54,648 ) — Revisions of previous estimates 18,291 34,166 52,457 Extensions, discoveries, and other additions 2,292 3,713 6,005 Acquisition of reserves 1,305 85,473 86,778 Dispositions (20 ) (1,880 ) (1,900 ) Production (31,830 ) — (31,830 ) Proved reserves, December 31, 2017 142,971 309,946 452,917
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]	The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to gas marketing and other income. Comprehensive income (loss) includes net income (loss), as well as other changes in stockholders' equity that result from transactions and economic events other than those with shareholders. There was no difference between our net income (loss) and comprehensive income (loss) for any of the periods presented in the results of operations for crude oil and natural gas producing activities shown. Year Ended December 31, 2017 2016 2015 (in thousands) Revenue: Crude oil, natural gas and NGLs sales $ 913,084 $ 497,353 $ 378,713 Commodity price risk management gain (loss), net (3,936 ) (125,681 ) 203,183 909,148 371,672 581,896 Expenses: Lease operating expenses 89,641 59,950 56,992 Production taxes 60,717 31,410 18,443 Transportation, gathering and processing expenses 33,220 18,415 10,151 Exploration expense 47,334 4,669 1,102 Impairment of properties and equipment 285,887 9,973 161,620 Depreciation, depletion, and amortization 462,482 413,105 298,760 Accretion of asset retirement obligations 6,306 7,080 6,293 Gain on sale of properties and equipment (766 ) (43 ) (385 ) 984,821 544,559 552,976 Results of operations for crude oil and natural gas producing (75,673 ) (172,887 ) 28,920 Provision for income taxes 47,247 64,733 (10,394 ) Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs $ (28,426 ) $ (108,154 ) $ 18,526
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	Exploration Expenses. The following table presents the major components of exploration, geologic, and geophysical expense: Year Ended December 31, 2017 2016 2015 (in thousands) Exploratory dry hole costs $ 41,297 $ — $ — Geological and geophysical costs, including seismic purchases 3,881 3,472 — Operating, personnel and other 2,156 1,197 1,102 Total exploration, geologic, and geophysical expense $ 47,334 $ 4,669 $ 1,102 Costs incurred in crude oil and natural gas property acquisition, exploration, and development are presented below. Year Ended December 31, 2017 2016 2015 (in thousands) Acquisition of properties: (1) Proved properties $ 172 $ 268,567 $ 3,561 Unproved properties 18,914 1,843,985 15 Development costs (2) 688,165 383,336 552,104 Exploration costs: (3) Exploratory drilling 80,103 — — Geological and geophysical 3,881 4,669 — Total costs incurred (4) $ 791,235 $ 2,500,557 $ 555,680 __________ (1) Property acquisition costs represent costs incurred to purchase, lease, or otherwise acquire a property. Proved properties include approximately $40.9 million of infrastructure and pipeline costs in 2016. (2) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended December 31, 2017 , 2016 , and 2015 , $463.4 million , $204.6 million , and $207.8 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $32.8 million of infrastructure and pipeline costs in 2017. (3) Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. (4) During the year ended 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved, undeveloped and development costs of $24.6 million. We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017.
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]	Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: As of December 31, 2017 2016 (in thousands) Proved crude oil and natural gas properties $ 4,356,922 $ 3,499,718 Unproved crude oil and natural gas properties 1,097,317 1,874,671 Uncompleted wells, equipment and facilities 265,526 150,424 Capitalized costs 5,719,765 5,524,813 Less accumulated DD&A (1,803,847 ) (1,534,678 ) Capitalized costs, net $ 3,915,918 $ 3,990,135
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]	The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas, and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. As of December 31, 2017 2016 2015 (in thousands) Future estimated cash flows $ 12,340,407 $ 7,122,525 $ 6,297,298 Future estimated production costs* (3,245,627 ) (1,624,167 ) (1,493,040 ) Future estimated development costs (2,893,335 ) (2,219,914 ) (2,036,685 ) Future estimated income tax expense (748,494 ) (597,476 ) (508,332 ) Future net cash flows 5,452,951 2,680,968 2,259,241 10% annual discount for estimated timing of cash flows (2,572,846 ) (1,260,339 ) (1,162,377 ) Standardized measure of discounted future estimated net cash flows $ 2,880,105 $ 1,420,629 $ 1,096,864 ___________ * Represents future estimated lease operating expenses, production taxes, transportation, gathering, and processing expenses.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: Year Ended December 31, 2017 2016 2015 (in thousands) Beginning of period $ 1,420,629 $ 1,096,864 $ 2,306,465 Sales of crude oil, natural gas and NGLs production, net of production costs (729,506 ) (387,576 ) (293,127 ) Net changes in prices and production costs (1) 841,713 (205,760 ) (1,752,921 ) Extensions, discoveries, and improved recovery, less related costs 47,240 15,128 489,178 Sales of reserves (2,613 ) (3,745 ) (463 ) Purchases of reserves 224,483 487,636 374 Development costs incurred during the period 419,047 268,672 368,840 Revisions of previous quantity estimates 484,431 (320,286 ) (1,286,462 ) Changes in estimated income taxes (138,560 ) (13,630 ) 902,994 Net changes in future development costs 25,183 391,145 112,958 Accretion of discount 167,487 133,747 345,007 Timing and other 120,571 (41,566 ) (95,979 ) End of period $ 2,880,105 $ 1,420,629 $ 1,096,864 __________ (1) Our weighted-average price, net of production costs per Boe, in our 2017 reserve report increased to $20.08 as compared to $15.73 for 2016 and $17.30 for 2015.

NATURE OF OPERATIONS AND BASI45

NATURE OF OPERATIONS AND BASIS OF PRESENTATION Additional Information (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)	Dec. 31, 2017Wells
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Proceeds from Sale of Property Held-for-sale | $	$ 40
Oil and gas producing wells, gross | Wells		2,800

SUMMARY OF SIGNIFICANT ACCOUN46

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Detail (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Significant Accounting Plicies [Line Items]
Non-Oil and gas Depreciation, Depletion and Amortization	$ 6,600	$ 3,800	$ 4,500
Capitalized Interest	5,000	4,500	5,100
Production Tax Liability	50,500	29,000
Allocated Share-based Compensation Expense	19,353	19,502	$ 20,068
Revolving Credit Facility [Member]
Significant Accounting Plicies [Line Items]
Amortization of Debt Issuance Costs	$ 6,200	$ 8,800

BUSINESS COMBINATIONS BUSINES47

BUSINESS COMBINATIONS BUSINESS COMBINATIONS (Details) shares in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)aWellsshares	Dec. 31, 2016USD ($)aWells	Dec. 31, 2017USD ($)Wells
Business Acquisition [Line Items]
Oil and gas producing wells, gross | Wells			2,800
Goodwill	$ 62,041,000	$ 62,041,000	$ 0
Delaware Basin Acquisition [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 946,000,000	945,962,000
Payments for Deposits Applied to Debt Retirements		$ 40,000,000
Oil and gas producing wells, gross | Wells	30	30
Gas and Oil Area, Developed, Gross | a	57,900	57,900
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 1,637,090,000	$ 1,637,090,000
Stock Issued During Period, Shares, Acquisitions | shares	9.4
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual		5,600,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual		(1,700,000)
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable		690,702,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities	$ 374,707,000	$ 374,707,000
Delaware Basin Acquisition, Reeves and Culberson Counties, Texas [Member]
Business Acquisition [Line Items]
Gas and Oil Area, Developed, Gross | a	4,600	4,600
Payments to Acquire Oil and Gas Property		$ 120,600,000
Delaware Basin [Member]
Business Acquisition [Line Items]
Goodwill	$ 75,121,000	75,121,000
Goodwill, Other Increase (Decrease)		13,080,000
preliminary [Member] | Delaware Basin [Member]
Business Acquisition [Line Items]
Goodwill	62,041,000	62,041,000
Final [Member] | Delaware Basin [Member]
Business Acquisition [Line Items]
Goodwill	$ 75,121,000	$ 75,121,000

BUSINESS COMBINATIONS Pro Form

BUSINESS COMBINATIONS Pro Form Detail (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Delaware Basin [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Net Income (Loss)	$ (270,942)	$ (138,904)
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ (4.22)	$ (2.41)
Business Acquisition, Pro Forma Revenue	$ 412,746	$ 598,932
Delaware Basin Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	5,600,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual	$ (1,700,000)

BUSINESS COMBINATIONS Fair Valu

BUSINESS COMBINATIONS Fair Value of Net Assets (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2017
Fair Value of Net Assets [Line Items]
Goodwill	$ 62,041	$ 62,041	$ 0
Delaware Basin Acquisition [Member]
Fair Value of Net Assets [Line Items]
Payments to Acquire Business Two, Net of Cash Acquired		905,962
Payments for Deposits Applied to Debt Retirements		40,000
Payments to Acquire Businesses, Gross	946,000	945,962
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable		690,702
Goodwill, Purchase Accounting Adjustments		(426)
Business Combination, Contingent Consideration, Asset, Current	6,401	6,401
Business Acquisitions Purchase Price Allocation Proved Natural Gas Properties	216,000	216,000
business acquisition purchase price allocation unproved properties	1,697,000	1,697,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Equipment	33,153	33,153
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	12,323	12,323
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	2,039,998	2,039,998
Business Combination, Contingent Consideration, Liability, Current	24,496	24,496
Business Acquisition Purchase Price Allocation Asset Retirement Obligation	3,705	3,705
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities	374,707	374,707
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities	402,908	402,908
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 1,637,090	$ 1,637,090

FAIR VALUE MEASUREMENTS AND D50

FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 14,338	$ 11,177
Liabilities, Fair Value Disclosure	(101,645)	(81,190)
Fair Value | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	12,949	6,350
Liabilities, Fair Value Disclosure	(90,569)	(66,789)
Net Asset Fair Value	(77,620)	(60,439)
Fair Value | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	1,389	4,827
Liabilities, Fair Value Disclosure	(11,076)	(14,401)
Net Asset Fair Value	(9,687)	(9,574)
Fair Value | Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Asset Fair Value	$ (87,307)	$ (70,013)
1.125% Convertible Senior Notes due 2021 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.125%
7.75% senior notes fair value	$ 195,600
7.75% senior notes fair value as percentage of par	97.80%
6.125% Senior Notes due 2024 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.125%
7.75% senior notes fair value	$ 416,000
7.75% senior notes fair value as percentage of par	104.00%
7.75% Senior Notes due 2022 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.75%
7.75% senior notes fair value	$ 616,500
5.75% Senior Notes due 2026 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
7.75% senior notes fair value as percentage of par	102.80%

FAIR VALUE MEASUREMENTS AND D51

FAIR VALUE MEASUREMENTS AND DISCLOSURES Reconciliation of Level 3 Fair Value Measurements (Details) - Derivative Financial Instrument Net Assets [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured With Unobservable Input Reconcilition, Recurring Basis, Net Asset Value	$ (9,687)	$ (9,574)	$ 91,288	$ 62,356
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	(866)	(12,905)	43,540
Commodity Price Risk Management, net
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Assets, Gain (Loss) Included in Earnings	6,241	(28,550)	65,164
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	(6,354)	(72,312)	(36,232)
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	$ (866)	$ (12,905)	$ 43,540

DERIVATIVE FINANCIAL INSTRUME52

DERIVATIVE FINANCIAL INSTRUMENTS Fair Value of Derivative and Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 101,645	$ 81,190
Derivative Asset, Fair Value, Gross Asset	14,338	11,177
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	6,998	301
Derivative Asset, Fair Value, Gross Asset	14,338	8,791
Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	2,386
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	79,302	53,595
Commodity Contract [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	7,340	8,490
Commodity Contract [Member] | Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	0	1,123
Commodity Contract [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	77,999	53,565
Commodity Contract [Member] | Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	22,343	27,595
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	0	1,263
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	234	30
Rollfactor Derivative Contracts Related to Natural Gas and Crude Oil Sales [Member] [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	$ 1,069	$ 0

DERIVATIVE FINANCIAL INSTRUME53

DERIVATIVE FINANCIAL INSTRUMENTS Impact of Derivative Instruments on Statement of Operations (Details) - Commodity Price Risk Management, net - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Net settlements	$ 13,324	$ 208,103	$ 238,935
Net change in fair value of unsettled derivatives	(17,260)	(333,784)	(35,752)
Total Derivative Gain (Loss)	$ (3,936)	$ (125,681)	$ 203,183

DERIVATIVE FINANCIAL INSTRUME54

DERIVATIVE FINANCIAL INSTRUMENTS Effect of Master Netting Agreements (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 14,338	$ 11,177
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(14,173)	(10,930)
Derivative Asset	165	247
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	101,645	81,190
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(14,173)	(10,930)
Derivative Liability	$ 87,472	$ 70,260

DERIVATIVE FINANCIAL INSTRUME55

DERIVATIVE FINANCIAL INSTRUMENTS Additional Information (Details)	Dec. 31, 2019MMBbls	Dec. 31, 2018MMBblsMBbls
Propane [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged (MBbls)		1,095,000
Crude Oil [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged (MBbls)	6,600,000	11,884,000
Natural Gas [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged (MBbls) | MBbls		56,510,000

CONCENTRATION OF RISK Account56

CONCENTRATION OF RISK Accounts Receivable, Net of Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	Dec. 31, 2017		Dec. 31, 2016
Concentration Risk [Line Items]
Income Taxes Receivable	$ 6,015		$ 11,505
Allowance for Doubtful Accounts Receivable, Current	(3,128)		(2,190)
Accounts Receivable, Net, Current	197,598		143,392
Natural gas, NGLs and crude oil sales
Concentration Risk [Line Items]
Accounts Receivable, Gross	154,260		97,520
Joint interest billing
Concentration Risk [Line Items]
Accounts Receivable, Gross	34,576	[1]	20,118
Derivative Counterparties
Concentration Risk [Line Items]
Accounts Receivable, Gross	(18)		10,266
Other Accounts Receivable
Concentration Risk [Line Items]
Accounts Receivable, Gross	$ 5,893		$ 6,173
[1]	(1) The December 31, 2017 amount includes $13.9 million of pre-closing contracted completion costs of wells associated with the Bayswater Acquisition, which closed in January 2018. Upon closing, the $13.9 million was capitalized and included in properties and equipment, net on the consolidated balance sheet.

CONCENTRATION OF RISK Customer

CONCENTRATION OF RISK Customer Constituting 10% or more of Total Revenue (Details)	12 Months Ended
	Dec. 31, 2017Rate	Dec. 31, 2016Rate	Dec. 31, 2015Rate
Suncor Energy Marketing, Inc.
Concentration Risk [Line Items]
Percentage of Revenue	16.40%	22.30%	14.30%
DCP Midstream, LP
Concentration Risk [Line Items]
Percentage of Revenue	19.60%	20.20%	13.20%
Aka Energy Group. LLC [Member]
Concentration Risk [Line Items]
Percentage of Revenue	0.00%	13.40%	0.00%
Concord Energy
Concentration Risk [Line Items]
Percentage of Revenue	0.00%	13.40%	23.20%
Bridger Energy, LLC [Member]
Concentration Risk [Line Items]
Percentage of Revenue	0.00%	11.50%	0.00%
Shell Trading Company
Concentration Risk [Line Items]
Percentage of Revenue	0.00%	0.00%	13.80%

CONCENTRATION OF RISK Notes Rec

CONCENTRATION OF RISK Notes Receivable (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Oct. 14, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Provision for Doubtful Accounts		$ (40,203)	$ 44,038	$ 0
Proceeds from Sale of Notes Receivable		$ 40,200
Notes Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes, Loans and Financing Receivable, Gross, Noncurrent					$ 39,000
Provision for Doubtful Accounts	$ 44,000

CONCENTRATION OF RISK Other acc

CONCENTRATION OF RISK Other accrued expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Risks and Uncertainties [Abstract]
Accrued Employee Benefits	$ 22,383	$ 22,282
Asset Retirement Obligation, Current	15,801	9,775
Accrued Environmental Liabilities	1,374	3,238
Other Accrued Liabilities	3,429	3,330
Other Accrued Liabilities, Noncurrent	$ 42,987	$ 38,625

PROPERTIES AND EQUIPMENT Prop60

PROPERTIES AND EQUIPMENT Properties and Equipment (Details)	12 Months Ended
	Dec. 31, 2017USD ($)Wells	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Property, Plant and Equipment [Line Items]
Exploratory Wells Drilled, Net Nonproductive	$ 41,297,000	$ 0	$ 0
Capitalized Exploratory Well Costs	15,448,000	0
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves	51,776,000
Properties and equipment, net	3,933,467,000	4,002,994,000
Assets	4,419,891,000	4,485,842,000
Asset retirement obligations	71,006,000	82,612,000
Liabilities	1,912,242,000	1,863,088,000
Proved Natural Gas and Crude Oil Properties	4,356,922,000	3,499,718,000
Unproved Natural Gas and Crude Oil Properties	1,097,317,000	1,874,671,000
Total Natural Gas and Crude Oil Properties	5,454,239,000	5,374,389,000
Transportation and Other Equipment	109,359,000	62,093,000
Land and Buildings	10,960,000	6,392,000
Construction in Progress	196,024,000	122,591,000
Property and Equipment, at cost	5,770,582,000	5,565,465,000
Accumulated Depreciation, Depletion and Amortization	(1,837,115,000)	(1,562,471,000)
Property and Equipment, Net	3,933,467,000	4,002,994,000
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves	$ (36,328,000)
Wells to be completed | Wells	3
Geological and geophysical	$ 3,881,000	3,472,000	0
Other expenses	2,156,000	1,197,000	1,102,000
Exploration, geologic, and geophysical expense	47,334,000	4,669,000	1,102,000
Exploration and Production Equipment [Member]
Property, Plant and Equipment [Line Items]
Exploration, geologic, and geophysical expense	47,334,000	4,669,000	$ 1,102,000
Utica Shale [Member]
Property, Plant and Equipment [Line Items]
Assets Held-for-sale, Not Part of Disposal Group	36,800,000
Field Office Facilities [Member]
Property, Plant and Equipment [Line Items]
Assets Held-for-sale, Not Part of Disposal Group	3,300,000	5,300,000
Utica Shale [Member]
Property, Plant and Equipment [Line Items]
Properties and equipment, net		5,272,000
Assets	40,583,000	5,272,000
Asset retirement obligations	499,000	0
Liabilities	499,000	0
Property and Equipment, at cost	40,583,000
Property and Equipment, Net	$ 40,084,000	$ 5,272,000

PROPERTIES AND EQUIPMENT Impair

PROPERTIES AND EQUIPMENT Impairment of Natural Gas and Crude Oil Properties (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impairment of natural gas and crude oil properties [Line Items]
Delaware Basin Unproved Property Impairment	$ 251,600,000
Impairment of other properties	13,400
Continuing Operations:
Impairment of proved and unproved properties	285,465,000	$ 5,562,000	$ 154,608,000
Amortization of Individually Insignificant Unproved Properties	422,000	1,379,000	7,012,000
Impairment of Long-Lived Assets to be Disposed of	0	3,032,000	0
Results of Operations, Impairment of Oil and Gas Properties	$ 285,887,000	$ 9,973,000	161,620,000
Capitalized Well Costs
Continuing Operations:
Impairment of proved and unproved properties			24,700,000
Lease Acquisition Costs
Continuing Operations:
Impairment of proved and unproved properties			150,300,000
Unproved Properties
Continuing Operations:
Impairment of proved and unproved properties			$ 125,600,000

PROPERTIES AND EQUIPMENT Prop62

PROPERTIES AND EQUIPMENT Properties and Equipment Acreage exchange (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)	Dec. 31, 2017a	Dec. 31, 2016a
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property Held-for-sale | $	$ 40
Third Party 2 acreage to PDC [Member]
Property, Plant and Equipment [Line Items]
Gas and Oil Area, Developed, Gross		15,900
PDC acreage to Third Party 2 [Member]
Property, Plant and Equipment [Line Items]
Gas and Oil Area, Developed, Gross		16,200
PDC acres transferred to Noble [Member] [Member]
Property, Plant and Equipment [Line Items]
Gas and Oil Area, Developed, Gross			13,500
PDC acres transferred to Noble [Member]
Property, Plant and Equipment [Line Items]
Gas and Oil Area, Developed, Gross			11,700

LONG-TERM DEBT SCHEDULE OF LONG

LONG-TERM DEBT SCHEDULE OF LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 14, 2017	Dec. 31, 2016	Dec. 14, 2016	Sep. 14, 2016
Debt Instrument [Line Items]
Total senior notes	$ 1,151,932		$ 1,043,954
Total debt, net of discount and unamortized debt issuance costs	1,151,932		1,043,954
Less current portion of long-term debt	0		0
Long-term debt	1,151,932		1,043,954
1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Principal amount	(200,000)		(200,000)
Unamortized Discount	30,328		37,475
Unamortized Debt Issuance Costs	(3,615)		(4,584)	$ (4,800)
Convertible Debt	166,057		157,941
6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Costs	(6,570)		(7,544)		$ (7,800)
Principal amount	(400,000)		(400,000)
Senior Long Term Notes	393,430		392,456
5.75% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Principal amount	(600,000)		0
Unamortized Debt Issuance Costs	(7,555)		0
Convertible Debt	592,445		0
7.75% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Costs	0	$ (5,400)	(6,443)
Principal amount	0		(500,000)
Senior Long Term Notes	0		493,557
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 0		$ 0

LONG-TERM DEBT ADDITIONAL INFOR

LONG-TERM DEBT ADDITIONAL INFORMATION (Details) - USD ($)

May 15, 2026

Oct. 15, 2022

Sep. 15, 2021

Mar. 15, 2021

May 21, 2020

Sep. 15, 2019

Sep. 12, 2016

Oct. 03, 2012

Jun. 30, 2021

Sep. 30, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 14, 2017

Jun. 30, 2017

Dec. 14, 2016

Sep. 14, 2016

Nov. 15, 2010

Debt Instrument [Line Items]

Effective Income Tax Rate Reconciliation, Deduction, Other, Percent

(7.70%)

0.00%

0.00%

Line of Credit Facility, Commitment Fee Percentage

1.25%

Line of Credit Facility, Unused Capacity, Commitment Fee Percentage

0.50%

Debt Instrument, Maturity Date

May 15, 2026

Sep. 15, 2021

Redemption of senior notes

$ 519,375,000

$ 0

$ 0

Loss on extinguishment of debt

(24,747,000)

$ 0

0

3.25% Convertible Note, Conversion Price

$ 85.39

Debt Issuance Costs ($)

$ 50,000

$ 15,556,000

$ 974,000

Security Deposit

$ 9,300,000

5.75% Senior Notes due 2026 [Member]

Debt Instrument [Line Items]

Debt Instrument, Issuance Date

Nov. 29, 2017

Debt Instrument, Interest Rate, Stated Percentage

5.75%

Debt Instrument, Redemption Period, End Date

May 15, 2021

3.25% Convertible Senior Notes due 2016 [Member]

Debt Instrument [Line Items]

3.25% Convertible Note, Conversion Price

$ 42.40

6.125% Senior Notes due 2024 [Member]

Debt Instrument [Line Items]

Debt Instrument, Issuance Date

Sep. 12, 2016

Debt Instrument, Interest Rate, Stated Percentage

6.125%

Debt Instrument, Redemption Period, End Date

Sep. 15, 2019

1.125% Convertible Senior Notes due 2021 [Member]

Debt Instrument [Line Items]

Debt Instrument, Issuance Date

Sep. 12, 2016

Debt Instrument, Interest Rate, Stated Percentage

1.125%

Convertible Senior Note, Shares Issued Upon Conversion

1171.13%

Convertible Note Principal Amount

$ 1,000

3.25% Convertible Note, Conversion Price

$ 85.39

Debt Instrument, Call Date, Latest

Mar. 15, 2021

7.75% Senior Notes due 2022 [Member]

Debt Instrument [Line Items]

Debt Instrument, Issuance Date

Oct. 3, 2012

Debt Instrument, Maturity Date

Oct. 15, 2022

Debt Instrument, Interest Rate, Stated Percentage

7.75%

Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Expiration Date

May 21, 2020

Amortization of Debt Issuance Costs

$ 6,200,000

8,800,000

RNG Credit Facility [Member]

Debt Instrument [Line Items]

Letters of Credit Outstanding, Amount ($)

11,700,000

Maximum [Member] | Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Maximum Borrowing Capacity ($)

1,000,000,000

$ 950,000,000

Minimum [Member] | Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Maximum Borrowing Capacity ($)

700,000,000

5.75% Senior Notes due 2026 [Member]

Debt Instrument [Line Items]

3.25% convertible senior notes fair value

600,000,000

0

Debt Issuance Costs, Gross

7,600,000

Unamortized Debt Issuance Costs

(7,555,000)

0

7.75% Senior Notes due 2022 [Member]

Debt Instrument [Line Items]

Redemption Premium

(19,400,000)

Unamortized Debt Issuance Costs

0

(6,443,000)

$ (5,400,000)

Loss on extinguishment of debt

(24,700,000)

Senior Notes ($)

$ 0

$ 500,000,000

First Payment [Member] | 5.75% Senior Notes due 2026 [Member]

Debt Instrument [Line Items]

Debt Instrument, Frequency of Periodic Payment

May 15

First Payment [Member] | 6.125% Senior Notes due 2024 [Member]

Debt Instrument [Line Items]

Debt Instrument, Frequency of Periodic Payment

March 15

First Payment [Member] | 1.125% Convertible Senior Notes due 2021 [Member]

Debt Instrument [Line Items]

Debt Instrument, Frequency of Periodic Payment

March 15

Second Payment [Member] | 5.75% Senior Notes due 2026 [Member]

Debt Instrument [Line Items]

Debt Instrument, Frequency of Periodic Payment

November 15

Second Payment [Member] | 6.125% Senior Notes due 2024 [Member]

Debt Instrument [Line Items]

Debt Instrument, Frequency of Periodic Payment

September 15

Second Payment [Member] | 1.125% Convertible Senior Notes due 2021 [Member]

Debt Instrument [Line Items]

Debt Instrument, Frequency of Periodic Payment

September 15

Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Debt, Weighted Average Interest Rate

2.70%

Maximum Borrowing Base [Member] | Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Maximum Borrowing Capacity ($)

$ 1,100,000,000

1.125% Convertible Senior Notes due 2021 [Member]

Debt Instrument [Line Items]

3.25% convertible senior notes fair value

200,000,000

$ 200,000,000

Liability component of gross proceeds of Convertible Notes

160,500,000

Unamortized Debt Issuance Costs

$ (3,615,000)

(4,584,000)

$ (4,800,000)

Debt Instrument, Interest Rate, Effective Percentage

5.80%

Share Price

$ 51.54

3.25% Convertible Debt, Equity Component ($)

39,500,000

6.125% Senior Notes due 2024 [Member]

Debt Instrument [Line Items]

Unamortized Debt Issuance Costs

$ (6,570,000)

(7,544,000)

$ (7,800,000)

Senior Notes ($)

$ 400,000,000

$ 400,000,000

2026 Senior notes redemption price, after to May 15, 2021 [Member] | 5.75% Senior Notes due 2026 [Member]

Debt Instrument [Line Items]

Debt Instrument, Redemption Price, Percentage

104.313%

2026 Senior notes redemption price, prior to May 15, 2021 [Member] | 5.75% Senior Notes due 2026 [Member]

Debt Instrument [Line Items]

Debt Instrument, Redemption Price, Percentage

105.75%

2024 Senior notes redemption price, prior to September 15, 2019 [Member] | 6.125% Senior Notes due 2024 [Member]

Debt Instrument [Line Items]

Debt Instrument, Redemption Price, Percentage

104.594%

2024 Senior notes redemption price, after September 15, 2019. [Member] | 6.125% Senior Notes due 2024 [Member]

Debt Instrument [Line Items]

Debt Instrument, Redemption Price, Percentage

106.125%

CAPITAL LEASES Leased Vehicles

CAPITAL LEASES Leased Vehicles under capital leases (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Capital Leased Assets [Line Items]
Vehicles	$ 6,249	$ 2,975
Accumulated depreciation	(1,882)	(776)
Total leased assets, Net	$ 4,367	$ 2,199

CAPITAL LEASES Future Minimum L

CAPITAL LEASES Future Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2017USD ($)
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	$ 5,205
Less Executory Costs	235
Less Amounts Representing Interest	537
Present Value of Minimum Lease Payments	4,433
Short-term Capital Lease Obligations	1,672
Long-term Capital Lease Obligations	2,761
Total Capital Lease Obligations	4,433
2018 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	2,075
2019 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	1,623
2020 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	$ 1,507

INCOME TAXES Provision for Inco

INCOME TAXES Provision for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Current Federal Tax Benefit (Expense)	$ 8,443	$ 9,646	$ (2,944)
Current State and Local Tax Benefit (Expense)	(200)	300	(163)
Current Income Tax Benefit (Expense)	8,243	9,946	(3,107)
Deferred Federal Income Tax Benefit (Expense)	193,809	118,427	37,352
Deferred State and Local Income Tax Benefit (Expense)	9,876	18,822	4,063
Deferred Income Tax Benefit (Expense)	203,685	137,249	41,415
Provision for income taxes	$ 211,928	$ 147,195	$ 38,308

INCOME TAXES Reconciliation of

INCOME TAXES Reconciliation of Statutory Rate to Effective Rate (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Statutory tax rate	35.00%			35.00%	35.00%
State income tax, net	1.80%			2.60%	2.70%
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount			$ 0	$ 0.006	$ (0.003)
Percentage depletion	0.00%			0.00%	0.30%
Non-deductible compensation	(0.30%)			(0.50%)	(1.20%)
Effective Income Tax Rate Reconciliation, Deduction, Percent		33.70%		0.00%	0.00%
Effective Income Tax Rate Reconciliation, Deduction, Other, Percent		(7.70%)		0.00%	0.00%
Other	(0.10%)			(0.30%)	0.60%
Effective Income Tax Rate Reconciliation, Percent	(62.40%)	21.00%		37.40%	35.90%

INCOME TAXES Tax Effects of Tem

INCOME TAXES Tax Effects of Temporary differences that Give Rise to Significant Portions of the Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Components of Deferred Tax Assets [Abstract]
Deferred compensation	$ 6,059	$ 9,338
Asset retirement obligations	21,760	34,359
deferred tax assets, federal tax	19,386	29,988
State NOL and tax credit carryforwards, net	7,815	5,189
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	4,366	5,184
Deferred tax assets, Allowance for note receivable	0	17,292
Deferred Tax Assets, Derivative Instruments	20,929	26,262
Other	2,453	4,716
Deferred tax assets	82,768	132,328
Components of Deferred Tax Liabilities [Abstract]
properties and equipment	267,498	518,964
Convertible debt	7,262	14,231
Total gross deferred tax liabilities	274,760	533,195
Net deferred tax liability	$ 191,992	$ 400,867

INCOME TAXES Additional Informa

INCOME TAXES Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards:
Combined federal and state deferred tax rate			23.90%
Reclassification of prepaid well costs to PP&E				$ 94,100,000
Deferred Tax Liabilities, Property, Plant and Equipment	$ 267,498,000	$ 267,498,000	$ 267,498,000	267,498,000	$ 518,964,000
Effective Income Tax Rate Reconciliation, Deduction, Percent			33.70%		0.00%	0.00%
Deferred Tax Assets, Net	43,800,000	$ 43,800,000	$ 43,800,000	43,800,000
Increase (Decrease) in Deferred Liabilities				158,200,000
Effective Income Tax Rate Reconciliation, Percent		(62.40%)	21.00%		37.40%	35.90%
Deferred Tax Liabilities, Net	191,992,000	$ 191,992,000	$ 191,992,000	191,992,000	$ 400,867,000
Income Tax Expense (Benefit)				(203,685,000)	(137,249,000)	$ (41,415,000)
Deferred Tax Assets, Operating Loss Carryforwards	28,000,000	28,000,000	28,000,000	28,000,000
Deferred tax asset, operating loss carryforward, annual limitation	15,100,000	15,100,000	15,100,000	15,100,000
Deferred tax asset, NOL carryback	10,100,000	10,100,000	10,100,000	10,100,000
Operating Loss Carryforwards	17,900,000	17,900,000	17,900,000	17,900,000
Alternative minimum tax - credit carryforward	4,366,000	4,366,000	4,366,000	4,366,000	5,184,000
Gas Well Credit [Member]
Operating Loss Carryforwards:
Tax Credit Carryforward, Amount	1,200,000	1,200,000	1,200,000	1,200,000
State NOL Carryforwards
Operating Loss Carryforwards:
State NOL carryforwards	$ 158,000,000	158,000,000	158,000,000	158,000,000
Year Carryforwards Expire	Dec. 31, 2030
State Credit Carryforwards
Operating Loss Carryforwards:
State credit carryforwards	$ 2,400,000	2,400,000	2,400,000	2,400,000
Year Carryforwards Expire	Dec. 31, 2022
Delaware Basin Acquisition [Member]
Operating Loss Carryforwards:
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent					403,700,000
Deferred Tax Assets, Net					$ 23,800,000
Deferred Tax Assets, Operating Loss Carryforwards	$ 60,100,000	$ 60,100,000	$ 60,100,000	60,100,000
2017 Tax Act [Domain]
Operating Loss Carryforwards:
Income Tax Expense (Benefit)				$ 114,400,000

ASSET RETIREMENT OBLIGATIONS 71

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation Of Changes In Asset Retirement Obligations [Line Items]
Disposal Group, Including Discontinued Operation, Other Liabilities	$ (499)	$ 0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance beginning of year, January 1	92,387	89,492
Revisions in estimated cash flows	(2,860)	0
Obligations incurred with development activities and assumed with acquisitions	3,638	4,894
Accretion of asset retirement obligations	6,306	7,080	$ 6,293
Obligations discharged with disposal of properties and asset retirements	(12,165)	(9,079)
Balance end of year, December 31	87,306	92,387	$ 89,492
Less: Current portion	(15,801)	(9,775)
Long-term portion	$ 71,006	$ 82,612

EMPLOYEE BENEFIT PLANS Employee

EMPLOYEE BENEFIT PLANS Employee Benefit Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Postretirement Benefit Expense	$ 6.2	$ 4.8	$ 4.9

COMMITMENTS AND CONTINGENCIES73

COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MBblsMMcf
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	303,578
Dollar Commitment ($ in thousands) | $	$ 261,680
First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	27,996
Dollar Commitment ($ in thousands) | $	$ 23,176
Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	48,389
Dollar Commitment ($ in thousands) | $	$ 43,855
Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	55,631
Dollar Commitment ($ in thousands) | $	$ 42,496
Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	40,819
Dollar Commitment ($ in thousands) | $	$ 33,226
commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	130,743
Dollar Commitment ($ in thousands) | $	$ 118,927
Appalachiain Basin
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	32,921
Appalachiain Basin | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
Appalachiain Basin | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
Appalachiain Basin | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,136
Appalachiain Basin | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,056
Appalachiain Basin | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	4,495
Appalachiain Basin | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Aug. 31, 2022
Utica Shale
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	15,285	[1]
Utica Shale | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,738	[1]
Utica Shale | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,738	[1]
Utica Shale | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,745	[1]
Utica Shale | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,738	[1]
Utica Shale | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	4,326	[1]
Utica Shale | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Jul. 31, 2023
Wattenberg Field
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	211,532
Wattenberg Field | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	3,541
Wattenberg Field | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	23,934
Wattenberg Field | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	31,110
Wattenberg Field | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	31,025
Wattenberg Field | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	121,922
Wattenberg Field | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Apr. 30, 2026
Delaware Basin [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	43,840
Delaware Basin [Member] | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	14,600
Delaware Basin [Member] | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	14,600
Delaware Basin [Member] | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	14,640
Delaware Basin [Member] | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	0
Delaware Basin [Member] | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	0
Delaware Basin [Member] | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Dec. 31, 2020
Crude Oil (Bbls) | Wattenberg Field
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	9,685
Crude Oil (Bbls) | Wattenberg Field | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	3,638
Crude Oil (Bbls) | Wattenberg Field | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	4,239
Crude Oil (Bbls) | Wattenberg Field | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	1,808
Crude Oil (Bbls) | Wattenberg Field | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	0
Crude Oil (Bbls) | Wattenberg Field | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	0
Crude Oil (Bbls) | Wattenberg Field | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Jun. 30, 2020
First facilities agreement with midstream provider [Member]
Supply Commitment [Line Items]
incremental volume commitment	51.5
Second facilities agreement with midstream provider [Member]
Supply Commitment [Line Items]
incremental volume commitment	33.5
[1]	(1) In February 2018, we entered into a PSA to sell the Utica Shale properties. This commitment would be assumed by the purchaser of the Utica Shale properties.

COMMITMENTS AND CONTINGENCIES M

COMMITMENTS AND CONTINGENCIES Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2016USD ($)
Minimum Future Lease Payments under Non-cancelable Operating Leases [Line Items]
2,016	$ 3,865
2,017	3,865
2,018	3,932
2,019	3,998
2,020	4,078
Thereafter	3,515
Total	$ 23,253

COMMITMENTS AND CONTINGENCIES A

COMMITMENTS AND CONTINGENCIES Additional information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Operating Lease Expense	$ 17.2	$ 10.2	$ 9.8

COMMITMENTS AND CONTINGENCIES L

COMMITMENTS AND CONTINGENCIES Long-term fIrm transportation costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Transportation, gathering, and processing expenses	$ 33,220	$ 18,415	$ 10,151
Utica Shale natural gas and Wattenberg Field crude oil [Member]
Loss Contingencies [Line Items]
Transportation, gathering, and processing expenses	$ 10,000	$ 10,000	$ 4,700

COMMON STOCK Stockholders' Equi

COMMON STOCK Stockholders' Equity Note (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 0.01		$ 0.01
Common shares	$ 657		$ 659
Additional paid-in capital	$ 2,489,557		$ 2,503,294
March 2015 Common Stock Issuance
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues		4,002,000
Sale of Stock, Price Per Share	$ 50.73
Proceeds from Issuance of Common Stock	$ 296,600	$ 202,900

COMMON STOCK Stock based compen

COMMON STOCK Stock based compensation plans (Details) - shares	Dec. 31, 2017	Dec. 31, 2016	Jun. 29, 2010
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Common Stock, Shares Authorized	150,000,000	150,000,000	3,000,000
Common stock shares remain avaliable for issuance	689,206

COMMON STOCK Stocked Based Comp

COMMON STOCK Stocked Based Compensation Summary (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 19,353	$ 19,502	$ 20,068
Income tax benefit	(7,372)	(7,296)	(7,636)
Net stock-based compensation expense	$ 11,981	$ 12,206	$ 12,432

COMMON STOCK SARs Fair Value As

COMMON STOCK SARs Fair Value Assumptions (Details) - Stock Appreciation Rights (SARs) [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	The SARs vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the holders of the SARs will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance.
Expected term of award	6 years	6 years	5 years 2 months
Risk-free interest rate	2.00%	1.80%	1.40%
Expected Volatility	53.30%	54.50%	58.00%
Weighted-average grant date fair value per share	$ 38.58	$ 26.96	$ 22.23

COMMON STOCK Schedule of Change

COMMON STOCK Schedule of Changes in SARs (Details) - Stock Appreciation Rights (SARs) [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Number of SARs
Outstanding beginning of year, January 1,	244,078	326,453	279,011
Awarded	54,142	58,709	68,274
Exercised	0	(141,084)	(20,832)
Outstanding end of year, December 31,	298,220	244,078	326,453
Exercisable at December 31,				223,865	174,919	222,489
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Outstanding beginning of year, January 1,	$ 41.36	$ 38.99	$ 38.77
Awarded	74.57	51.63	39.63
Exercised	0	40.16	38.05
Outstanding end of year, December 31,	$ 47.39	$ 41.36	$ 38.99
Exercisable at December 31,				$ 43.28	$ 38.72	$ 37.70
Weighted-Average Remaining Contractual Term (in years)
Outstanding at December 31,	6 years 5 months 14 days	6 years 10 months 19 days
Exercisable at December 31,	5 years 10 months 8 days
Share based compesation aggregate intrinsic valu [Roll Forward]
Outstanding beginning of year, January 1,	$ 2,490	$ 7,620	$ 4,697	$ 2,490	$ 7,620	$ 4,697	$ 1,472
Awarded	0	0	0
Exercised	0	2,770	473
Outstanding end of year, December 31,	$ 2,490	$ 7,620	$ 4,697
Exercisable at December 31,				2,267	$ 5,924	$ 3,489
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized				$ 1,900
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 9 months 20 days

COMMON STOCK Schedule of Chan82

COMMON STOCK Schedule of Changes in Restricted Stock - TIme Based Awards (Details) - Restricted Stock [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	The fair value of the time-based RSUs is amortized ratably over the requisite service period, primarily three years. The time-based RSUs generally vest ratably on each anniversary following the grant date that a participant is continuously employed.
Number of Shares
Outstanding beginning of year, January 1,	479,642
Granted	273,941
Vested	(266,809)
Forfeited	(14,642)
Outstanding end of year, December 31,	472,132	479,642
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 56.09
Weighted-average grant date fair value per share	65.14	$ 58.52	$ 48.88
Vested	57.67
Forfeited	62.92
Outstanding at end of year, December 31,	$ 60.23	$ 56.09
Total intrinsic value of time based awards vested	$ 16,303	$ 18,973	$ 17,077
Total intrinsic value of time-based awards non-vested	$ 24,334	$ 34,812	$ 28,029
Market price per common share as of December 31,	$ 51.54	$ 72.58	$ 53.38
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 18,500
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 9 months 23 days

COMMON STOCK Restricted Stock -

COMMON STOCK Restricted Stock - Market Based Awards Fair Value Assumptions (Details) - Restricted Stock - Market Based Awards [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	$ 2,687	$ 6,562	$ 4,293
Expected term of award	3 years	3 years	3 years
Risk-free interest rate	1.40%	1.20%	0.90%
Expected Volatility	51.40%	52.30%	53.00%
Weighted-average grant date fair value per share	$ 94.02	$ 72.54	$ 66.16

COMMON STOCK Schedule of Chan84

COMMON STOCK Schedule of Changes in Restricted Stock - Market Based Awards (Details) - Restricted Stock - Market Based Awards [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	$ 2,687	$ 6,562	$ 4,293
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	The fair value of the market-based PSUs is amortized ratably over the requisite service period, primarily three years. The market-based PSUs vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.
Time based shares granted to executives	28,069
Number of Shares
Outstanding beginning of year, January 1,	48,420
Granted	28,069
Vested	(24,140)
Outstanding end of year, December 31,	52,349	48,420
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 64.97
Weighted-average grant date fair value per share	94.02	$ 72.54	$ 66.16
Vested	57.35
Outstanding at end of year, December 31,	$ 84.06	$ 64.97
Total intrinsic value of market-based awards non-vested	$ 2,698	$ 3,514	$ 3,819
Market price per common share as of December 31,	$ 51.54	$ 72.58	$ 53.38
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 2,400
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 9 months

COMMON STOCK Treasury Shares (D

COMMON STOCK Treasury Shares (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Held in Employee Trust, Shares	21,401	18,366
Treasury Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Treasury Stock, Shares, Acquired	107,357	116,085
Treasury stock acquired and reissued	83,228	114,697
Treasury stock acquired, and available for reissuance	34,526	10,397

COMMON STOCK Preferred Stock (D

COMMON STOCK Preferred Stock (Details) - shares	Dec. 31, 2017	Dec. 31, 2016	Jun. 23, 2008
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred Stock, Shares Authorized	50,000,000	50,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred Stock, Shares Authorized			50,000,000
Preferred Stock, Shares Issued	0

COMMON STOCK Stock Issuance (De

COMMON STOCK Stock Issuance (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
September 2016 Common Stock Issuance [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues	9,085,000
Sale of Stock, Price Per Share	$ 61.51
Proceeds from Issuance of Common Stock	$ 558.5
March 2016 Common Stock Issuance [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues	5,922,500
Sale of Stock, Price Per Share	$ 50.11
March 2015 Common Stock Issuance
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues		4,002,000
Sale of Stock, Price Per Share	$ 50.73
Proceeds from Issuance of Common Stock	$ 296.6	$ 202.9

EARNINGS PER SHARE Earnings Per

EARNINGS PER SHARE Earnings Per Share (Details)	Nov. 15, 2010shares$ / shares	Dec. 31, 2017shares	Dec. 31, 2016shares$ / shares	Dec. 31, 2015shares
Reconciliation of Weighted-Average Diluted Shares Outstanding
Weighted average common shares outstanding - basic		65,837,000	49,052,000	39,153,000
Weighted Average Number of Shares Outstanding - Diluted		65,837,000	49,052,000	39,153,000
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		665,000	1,090,000	1,494,000
Convertible Senior Note Due 2016
3.25% Convertible Note, Number of Shares Convertible			2,300,000
3.25% Convertible Note, Conversion Price | $ / shares			$ 85.39
Restricted Stock [Member]
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		590,000	689,000	831,000
3.25% Convertible Note [Member]
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		0	292,000	562,000
Other Equity-Based Awards
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		75,000	109,000	101,000
3.25% Convertible Senior Notes due 2016 [Member]
Convertible Senior Note Due 2016
3.25% Convertible Note, Number of Shares Convertible	2,700,000
3.25% Convertible Note, Conversion Price | $ / shares	$ 42.40

SUBSIDIARY GUARANTOR SUBSIDIA89

SUBSIDIARY GUARANTOR SUBSIDIARY GUARANTOR BALANCE SHEET (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 180,675	$ 244,100
Accounts receivable, net	197,598	143,392
Fair value of derivatives	14,338	8,791
Prepaid expenses and other current assets	8,613	3,542
Total current assets	401,224	399,825
Properties and equipment, net	3,933,467	4,002,994
Assets held-for-sale, net	40,084	5,272
Intercompany receivable	0	0
Investment in subsidiaries	0	0
Fair value of derivatives	0	2,386
Goodwill	0	62,041
Other assets	45,116	13,324
Total Assets	4,419,891	4,485,842
Current liabilities:
Accounts payable	150,067	66,322
Production tax liability	37,654	24,767
Fair value of derivatives	79,302	53,595
Funds held for distribution	95,811	71,339
Accrued interest payable	11,815	15,930
Other accrued expenses	42,987	38,625
Total current liabilities	417,636	270,578
Intercompany payable	0	0
Long-term debt	1,151,932	1,043,954
Deferred income taxes	191,992	400,867
Asset retirement obligations	71,006	82,612
Fair value of derivatives	22,343	27,595
Other liabilities	57,333	37,482
Total liabilities	1,912,242	1,863,088
Shareholders' Equity:
Common shares	659	657
Additional paid-in capital	2,503,294	2,489,557
Retained earnings	6,704	134,208
Treasury shares	3,008	1,668
Total stockholders' equity	2,507,649	2,622,754
Total Liabilities and Stockholders' Equity	4,419,891	4,485,842
Parent [Member]
Current assets:
Cash and cash equivalents	180,675	240,487
Accounts receivable, net	160,490	134,589
Fair value of derivatives	14,338	8,791
Prepaid expenses and other current assets	8,284	3,442
Total current assets	363,787	387,309
Properties and equipment, net	1,891,314	1,884,147
Assets held-for-sale, net	40,084	5,272
Intercompany receivable	250,279	9,415
Investment in subsidiaries	1,617,537	1,765,092
Fair value of derivatives		2,386
Goodwill		0
Other assets	42,547	13,153
Total Assets	4,205,548	4,066,774
Current liabilities:
Accounts payable	85,000	38,748
Production tax liability	35,902	24,401
Fair value of derivatives	79,302	53,595
Funds held for distribution	83,898	65,022
Accrued interest payable	11,812	15,930
Other accrued expenses	42,543	37,425
Total current liabilities	338,457	235,121
Intercompany payable	0	0
Long-term debt	1,151,932	1,043,954
Deferred income taxes	62,857	20,971
Asset retirement obligations	65,301	78,897
Fair value of derivatives	22,343	27,595
Other liabilities	57,009	37,482
Total liabilities	1,697,899	1,444,020
Shareholders' Equity:
Common shares	659	657
Additional paid-in capital	2,503,294	2,489,557
Retained earnings	6,704	(134,208)
Treasury shares	3,008	1,668
Total stockholders' equity	2,507,649	2,622,754
Total Liabilities and Stockholders' Equity	4,205,548	4,066,774
Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	0	3,613
Accounts receivable, net	37,108	8,803
Fair value of derivatives	0	0
Prepaid expenses and other current assets	329	100
Total current assets	37,437	12,516
Properties and equipment, net	2,042,153	2,118,847
Assets held-for-sale, net	0	0
Intercompany receivable	0	0
Investment in subsidiaries	0	0
Fair value of derivatives		0
Goodwill		62,041
Other assets	2,569	171
Total Assets	2,082,159	2,193,575
Current liabilities:
Accounts payable	65,067	27,574
Production tax liability	1,752	366
Fair value of derivatives	0	0
Funds held for distribution	11,913	6,317
Accrued interest payable	3	0
Other accrued expenses	444	1,200
Total current liabilities	79,179	35,457
Intercompany payable	250,279	9,415
Long-term debt	0	0
Deferred income taxes	129,135	379,896
Asset retirement obligations	5,705	3,715
Fair value of derivatives	0	0
Other liabilities	324	0
Total liabilities	464,622	428,483
Shareholders' Equity:
Common shares	0	0
Additional paid-in capital	1,766,775	1,766,775
Retained earnings	(149,238)	1,683
Treasury shares	0	0
Total stockholders' equity	1,617,537	1,765,092
Total Liabilities and Stockholders' Equity	2,082,159	2,193,575
Consolidation, Eliminations [Member]
Current assets:
Cash and cash equivalents	0	0
Accounts receivable, net	0	0
Fair value of derivatives	0	0
Prepaid expenses and other current assets	0	0
Total current assets	0	0
Properties and equipment, net	0	0
Assets held-for-sale, net	0	0
Intercompany receivable	(250,279)	(9,415)
Investment in subsidiaries	(1,617,537)	(1,765,092)
Fair value of derivatives		0
Goodwill		0
Other assets	0	0
Total Assets	(1,867,816)	(1,774,507)
Current liabilities:
Accounts payable	0	0
Production tax liability	0	0
Fair value of derivatives	0	0
Funds held for distribution	0	0
Accrued interest payable	0	0
Other accrued expenses	0	0
Total current liabilities	0	0
Intercompany payable	(250,279)	(9,415)
Long-term debt	0	0
Deferred income taxes	0	0
Asset retirement obligations	0	0
Fair value of derivatives	0	0
Other liabilities	0	0
Total liabilities	(250,279)	(9,415)
Shareholders' Equity:
Common shares	0	0
Additional paid-in capital	(1,766,775)	(1,766,775)
Retained earnings	149,238	(1,683)
Treasury shares	0	0
Total stockholders' equity	(1,617,537)	(1,765,092)
Total Liabilities and Stockholders' Equity	$ (1,867,816)	$ (1,774,507)

SUBSIDIARY GUARANTOR SUBSIDIA90

SUBSIDIARY GUARANTOR SUBSIDIARY GUARANTOR INCOME STATEMENT (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues [Abstract]
Crude oil, natural gas, and NGLs sales					$ 913,084	$ 497,353	$ 378,713
Commodity price risk management gain (loss), net					(3,936)	(125,681)	203,183
Other income					12,468	11,243	13,430
Total revenues	$ 108,097	$ 163,890	$ 20,097	$ 90,831	921,616	382,915	595,326
Costs and Expenses [Abstract]
Lease operating expenses					89,641	59,950	56,992
Production taxes					60,717	31,410	18,443
Transportation, gathering, and processing expenses					33,220	18,415	10,151
Exploration, geologic, and geophysical expense					47,334	4,669	1,102
Impairment of properties and equipment					285,887	9,973	161,620
Impairment of goodwill					75,121	0	0
General and administrative expense					120,370	112,470	89,959
Depreciation, depletion and amortization					469,084	416,874	303,258
Provision for uncollectible notes receivable					(40,203)	44,038	0
Accretion of asset retirement obligations					6,306	7,080	6,293
Gain on sale of properties and equipment					(766)	(43)	(385)
Other expenses					13,157	10,193	11,717
Total costs, expenses and other	178,608	179,178	163,379	193,864	1,159,868	715,029	659,150
Income (loss) from operations	(70,511)	(15,288)	(143,282)	(103,033)	(238,252)	(332,114)	(63,824)
Loss on extinguishment of debt					(24,747)	0	0
Interest expense					(78,694)	(61,972)	(47,571)
Interest income					2,261	963	4,807
Income (loss) before income taxes	(90,636)	(35,341)	(153,777)	(113,369)	(339,432)	(393,123)	(106,588)
Income tax benefit					211,928	147,195	38,308
Equity in loss of subsidiary					0	0
Net loss	$ (55,639)	$ (23,309)	$ (95,450)	$ (71,530)	(127,504)	(245,928)	$ (68,280)
Parent [Member]
Revenues [Abstract]
Crude oil, natural gas, and NGLs sales					788,400	491,750
Commodity price risk management gain (loss), net					(3,936)	(125,681)
Other income					11,901	11,241
Total revenues					796,365	377,310
Costs and Expenses [Abstract]
Lease operating expenses					68,031	58,401
Production taxes					53,236	31,132
Transportation, gathering, and processing expenses					23,301	18,263
Exploration, geologic, and geophysical expense					1,092	1,197
Impairment of properties and equipment					4,951	9,973
Impairment of goodwill					0
General and administrative expense					107,518	112,166
Depreciation, depletion and amortization					403,984	415,321
Provision for uncollectible notes receivable					(40,203)	44,038
Accretion of asset retirement obligations					5,965	7,070
Gain on sale of properties and equipment					(766)	(43)
Other expenses					13,157	10,193
Total costs, expenses and other					640,266	707,711
Income (loss) from operations					156,099	(330,401)
Loss on extinguishment of debt					(24,747)
Interest expense					(79,919)	(62,002)
Interest income					2,261	963
Income (loss) before income taxes					53,694	(391,440)
Income tax benefit					(33,643)	147,195
Equity in loss of subsidiary					(147,555)	(1,683)
Net loss					(127,504)	(245,928)
Guarantor Subsidiaries [Member]
Revenues [Abstract]
Crude oil, natural gas, and NGLs sales					124,684	5,603
Commodity price risk management gain (loss), net					0	0
Other income					567	2
Total revenues					125,251	5,605
Costs and Expenses [Abstract]
Lease operating expenses					21,610	1,549
Production taxes					7,481	278
Transportation, gathering, and processing expenses					9,919	152
Exploration, geologic, and geophysical expense					46,242	3,472
Impairment of properties and equipment					280,936	0
Impairment of goodwill					75,121
General and administrative expense					12,852	304
Depreciation, depletion and amortization					65,100	1,553
Provision for uncollectible notes receivable					0	0
Accretion of asset retirement obligations					341	10
Gain on sale of properties and equipment					0	0
Other expenses					0	0
Total costs, expenses and other					519,602	7,318
Income (loss) from operations					(394,351)	(1,713)
Loss on extinguishment of debt					0
Interest expense					1,225	30
Interest income					0	0
Income (loss) before income taxes					(393,126)	(1,683)
Income tax benefit					245,571	0
Equity in loss of subsidiary					0	0
Net loss					(147,555)	(1,683)
Consolidation, Eliminations [Member]
Revenues [Abstract]
Crude oil, natural gas, and NGLs sales					0	0
Commodity price risk management gain (loss), net					0	0
Other income					0	0
Total revenues					0	0
Costs and Expenses [Abstract]
Lease operating expenses					0	0
Production taxes					0	0
Transportation, gathering, and processing expenses					0	0
Exploration, geologic, and geophysical expense					0	0
Impairment of properties and equipment					0	0
Impairment of goodwill					0
General and administrative expense					0	0
Depreciation, depletion and amortization					0	0
Provision for uncollectible notes receivable					0	0
Accretion of asset retirement obligations					0	0
Gain on sale of properties and equipment					0	0
Other expenses					0	0
Total costs, expenses and other					0	0
Income (loss) from operations					0	0
Loss on extinguishment of debt					0
Interest expense					0	0
Interest income					0	0
Income (loss) before income taxes					0	0
Income tax benefit					0	0
Equity in loss of subsidiary					147,555	1,683
Net loss					$ 147,555	$ 1,683

SUBSIDIARY GUARANTOR SUBSIDIA91

SUBSIDIARY GUARANTOR SUBSIDIARY GUARANTOR CASH FLOWS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net Cash Provided by (Used in) Operating Activities [Abstract]
Cash flows from operating activities	$ 588,563,000	$ 486,263,000	$ 411,073,000
Net Cash Provided by (Used in) Investing Activities [Abstract]
Capital expenditures for development of crude oil and natural gas properties	(737,208,000)	(436,884,000)	(599,546,000)
Capital expenditures for other properties and equipment	(5,094,000)	(3,464,000)	(5,122,000)
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition	(15,628,000)	(1,073,723,000)	0
Proceeds from sale of properties and equipment	9,991,000	4,945,000	405,000
Sale of promissory note	40,203,000	0	0
Increase (Decrease) in Restricted Cash	9,250,000	0	0
Sale of short-term investments	49,890,000	0	0
Purchase of short-term investments	(49,890,000)	0	0
Intercompany transfers	0	0
Net cash from investing activities	(716,986,000)	(1,509,126,000)	(604,263,000)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from issuance of equity, net of issuance costs	0	855,074,000	202,851,000
Proceeds from issuance of senior notes	592,366,000	392,172,000	0
Proceeds from issuance of convertible senior notes	0	193,935,000	0
Proceeds from revolving credit facility	0	85,000,000	397,000,000
Repayment of revolving credit facility	0	(122,000,000)	(416,000,000)
Redemption of convertible notes	0	(115,000,000)	0
Redemption of senior notes	(519,375,000)	0	0
Payment of debt issuance costs	(50,000)	(15,556,000)	(974,000)
Purchase of treasury shares	(6,672,000)	(6,935,000)	(6,055,000)
Other	(1,271,000)	(577,000)	1,152,000
Intercompany transfers	0	0
Net cash from financing activities	64,998,000	1,266,113,000	177,974,000
Net change in cash and cash equivalents	(63,425,000)	243,250,000	(15,216,000)
Cash and cash equivalents, beginning of year	244,100,000	850,000	16,066,000
Cash and cash equivalents, end of year	180,675,000	244,100,000	850,000
Parent [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Cash flows from operating activities	537,704,000	492,893,000
Net Cash Provided by (Used in) Investing Activities [Abstract]
Capital expenditures for development of crude oil and natural gas properties	(439,897,000)	436,361,000
Capital expenditures for other properties and equipment	(3,539,000)	(2,282,000)
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition	(21,000,000)	1,076,256,000
Proceeds from sale of properties and equipment	10,084,000	4,945,000
Sale of promissory note	40,203,000
Increase (Decrease) in Restricted Cash	9,250,000
Sale of short-term investments	49,890,000
Purchase of short-term investments	(49,890,000)
Intercompany transfers	(239,191,000)	(9,415,000)
Net cash from investing activities	(662,590,000)	(1,519,369,000)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from issuance of equity, net of issuance costs		855,074,000
Proceeds from issuance of senior notes	592,366,000	392,172,000
Proceeds from issuance of convertible senior notes		193,935,000
Proceeds from revolving credit facility		85,000,000
Repayment of revolving credit facility		(122,000,000)
Redemption of convertible notes		(115,000,000)
Redemption of senior notes	(519,375,000)
Payment of debt issuance costs	(50,000)	(15,556,000)
Purchase of treasury shares	(6,672,000)	(6,935,000)
Other	(1,195,000)	(577,000)
Intercompany transfers	0	0
Net cash from financing activities	65,074,000	1,266,113,000
Net change in cash and cash equivalents	(59,812,000)	239,637,000
Cash and cash equivalents, beginning of year	240,487,000	850,000
Cash and cash equivalents, end of year	180,675,000	240,487,000	850,000
Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Cash flows from operating activities	50,859,000	(6,630,000)
Net Cash Provided by (Used in) Investing Activities [Abstract]
Capital expenditures for development of crude oil and natural gas properties	(297,311,000)	523,000
Capital expenditures for other properties and equipment	(1,555,000)	(1,182,000)
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition	5,372,000	(2,533,000)
Proceeds from sale of properties and equipment	(93,000)	0
Sale of promissory note	0
Increase (Decrease) in Restricted Cash	0
Sale of short-term investments	0
Purchase of short-term investments	0
Intercompany transfers	0	0
Net cash from investing activities	(293,587,000)	828,000
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from issuance of equity, net of issuance costs		0
Proceeds from issuance of senior notes	0	0
Proceeds from issuance of convertible senior notes		0
Proceeds from revolving credit facility		0
Repayment of revolving credit facility		0
Redemption of convertible notes		0
Redemption of senior notes	0
Payment of debt issuance costs	0	0
Purchase of treasury shares	0	0
Other	(76,000)	0
Intercompany transfers	239,191,000	9,415,000
Net cash from financing activities	239,115,000	9,415,000
Net change in cash and cash equivalents	(3,613,000)	3,613,000
Cash and cash equivalents, beginning of year	3,613,000	0
Cash and cash equivalents, end of year	0	3,613,000	0
Consolidation, Eliminations [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Cash flows from operating activities	0	0
Net Cash Provided by (Used in) Investing Activities [Abstract]
Capital expenditures for development of crude oil and natural gas properties	0	0
Capital expenditures for other properties and equipment	0	0
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition	0	0
Proceeds from sale of properties and equipment	0	0
Sale of promissory note	0
Increase (Decrease) in Restricted Cash	0
Sale of short-term investments	0
Purchase of short-term investments	0
Intercompany transfers	239,191,000	9,415,000
Net cash from investing activities	239,191,000	9,415,000
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from issuance of equity, net of issuance costs		0
Proceeds from issuance of senior notes	0	0
Proceeds from issuance of convertible senior notes		0
Proceeds from revolving credit facility		0
Repayment of revolving credit facility		0
Redemption of convertible notes		0
Redemption of senior notes	0
Payment of debt issuance costs	0	0
Purchase of treasury shares	0	0
Other	0	0
Intercompany transfers	(239,191,000)	(9,415,000)
Net cash from financing activities	(239,191,000)	(9,415,000)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents, beginning of year	0	0
Cash and cash equivalents, end of year	$ 0	$ 0	$ 0

SUBSEQUENT EVENT SUBSEQUENT E92

SUBSEQUENT EVENT SUBSEQUENT EVENT (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)aWells
Subsequent Event [Line Items]
Investment in wells to be drilled.		$ 15
Wells to be completed | Wells		3
Proceeds from Sale of Property Held-for-sale	$ 40
Saddle Butte Rockies Midstream Amendment Payment	$ 24
Bayswater Acquisition [Member]
Subsequent Event [Line Items]
Payments to Acquire Businesses, Gross		$ 186
Wells to be completed		12
Gas and Oil Area, Developed, Net | a		7,400
Oil and gas drilling locations, gross | Wells		220
Drilled Uncompleted Wells		24
Other Payments to Acquire Businesses		$ 21

SUPPLEMENTAL INFORMATION - NA93

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Prices Used to Estimate Reserves (Unaudited) (Details) - USD ($)		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Crude Oil (Bbls)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	[1]	$ 48.68	$ 38.67	$ 42.10
Natural Gas (Mcf)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	[1]	2.31	1.85	2.05
Natural Gas Liquids (Bbls)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	[1],[2]	$ 20.21	$ 11.97	$ 12.23
[1]	These prices are based on the index prices and are net of basin differentials, any transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.
[2]	For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes.

SUPPLEMENTAL INFORMATION - NA94

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Changes in Estimated Proved Reserves (Unaudited) (Details) Mcf in Thousands	12 Months Ended
	Dec. 31, 2017RateMcfbbl	Dec. 31, 2016RateMcfbbl	Dec. 31, 2015RateMcfbbl	Dec. 31, 2014Mcfbbl
Reserve Quantities [Line Items]
Proved Reserves	452,917,000	341,407,000	272,825,000	250,129,000
Production	(31,830,000)	(22,176,000)	(15,369,000)
Undeveloped Reserves Converted to Developed	0	0	0
Purchases of Reserves	86,778,000	133,583,000	76,000
Dispositions	(1,900,000)	(1,725,000)	(34,000)
Negative revisions due to PUD locations dropped from 5 year development plan	57,700,000
Extensions, Discoveries, and Other Additions	6,005,000	1,531,000	131,494,000
Revisions of Previous Estimates	52,457,000	(42,631,000)	(93,471,000)
Estimated PUD conversion rate	16.00%
Increase or Decrease in Proved Reserves	111,500,000	0	22,700,000
Crude Oil (Bbls)
Reserve Quantities [Line Items]
Proved Reserves	154,842,000	118,169,000	98,975,000	100,515,000
Production	(12,902,000)	(8,728,000)	(6,984,000)
Purchases of Reserves	18,971,000	50,126,000	17,000
Dispositions	(653,000)	(601,000)	(12,000)
Extensions, Discoveries, and Other Additions	2,923,000	494,000	48,707,000
Revisions of Previous Estimates	28,334,000	(22,097,000)	(43,268,000)
Proved Developed Reserves	46,862,000	30,013,000	26,257,000
Proved Undeveloped Reserve	107,980,000	88,156,000	72,718,000
Natural Gas (Mcf)
Reserve Quantities [Line Items]
Proved Reserves | Mcf	1,154,294	833,697	660,737	536,972
Production | Mcf	(71,689)	(51,730)	(33,302)
Purchases of Reserves | Mcf	289,223	305,224	215
Dispositions | Mcf	(4,597)	(4,202)	(82)
Extensions, Discoveries, and Other Additions | Mcf	11,541	4,094	311,709
Revisions of Previous Estimates | Mcf	96,119	(80,426)	(154,775)
Proved Developed Reserves | Mcf	365,332	264,452	175,367
Proved Undeveloped Reserve | Mcf	788,962	569,245	485,370
Natural Gas Liquids (Bbls)
Reserve Quantities [Line Items]
Proved Reserves	105,692,000	84,288,000	63,727,000	60,119,000
Production	(6,981,000)	(4,826,000)	(2,835,000)
Purchases of Reserves	19,604,000	32,586,000	23,000
Dispositions	(481,000)	(424,000)	(8,000)
Extensions, Discoveries, and Other Additions	1,158,000	355,000	30,835,000
Revisions of Previous Estimates	8,104,000	(7,130,000)	(24,407,000)
Proved Developed Reserves	35,220,000	24,196,000	15,011,000
Proved Undeveloped Reserve	70,472,000	60,092,000	48,716,000
Crude Oil Equivalent (Boe)
Reserve Quantities [Line Items]
Proved Reserves	452,917,000	341,407,000	272,825,000	250,129,000
Production	(31,830,000)	(22,176,000)	(15,369,000)
Purchases of Reserves	86,778,000	133,583,000	76,000
Dispositions	(1,900,000)	(1,725,000)	(34,000)
Extensions, Discoveries, and Other Additions	6,005,000	1,531,000	131,494,000
Revisions of Previous Estimates	52,457,000	(42,631,000)	(93,471,000)
Proved Developed Reserves	142,971,000	98,284,000	70,496,000
Proved Undeveloped Reserve	309,946,000	243,122,000	202,329,000
Year-over-Year Activity [Domain]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves percent increase or decrease | Rate	32.6619%	2500.00%
Undeveloped Reserves Converted to Developed		32,200,000	29,090,000
Estimated PUD conversion rate for following year | Rate		26.00%
Extensions, Discoveries, and Other Additions	93,900,000		131,494,000
Revisions of Previous Estimates			93,471,000
Estimated PUD conversion rate | Rate		19.00%	16.00%
Actual PUD conversion rate | Rate	23.00%		17.00%

SUPPLEMENTAL INFORMATION - NA95

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Schedule of Developed and Undeveloped Reserves (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2017Ratebbl	Dec. 31, 2016Ratebbl	Dec. 31, 2015Ratebbl	Dec. 31, 2014bbl
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	452,917,000	341,407,000	272,825,000	250,129,000
Undeveloped Reserves Converted to Developed	0	0	0
Revisions of Previous Estimates	52,457,000	(42,631,000)	(93,471,000)
Extensions, Discoveries, and Other Additions	6,005,000	1,531,000	131,494,000
Purchases of Reserves	86,778,000	133,583,000	76,000
Dispositions	(1,900,000)	(1,725,000)	(34,000)
Negative revisions due to PUD locations dropped from 5 year development plan	57,700,000
Production	(31,830,000)	(22,176,000)	(15,369,000)
Estimated PUD conversion rate	16.00%
Increase or Decrease in Proved Reserves	111,500,000	0	22,700,000
Proved Undeveloped Reserves [Member]
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	309,946,000	243,122,000	202,329,000	175,224,000
Undeveloped Reserves Converted to Developed	(54,648,000)	(32,192,000)	(29,090,000)
Revisions of Previous Estimates	34,166,000	(48,743,000)	(66,596,000)
Extensions, Discoveries, and Other Additions	3,713,000	0	122,791,000
Purchases of Reserves	85,473,000	123,354,000	0
Dispositions	(1,880,000)	(1,626,000)	0
Production	0	0	0
Proved Developed Reserves [Member]
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	142,971,000	98,285,000	70,496,000	74,905,000
Undeveloped Reserves Converted to Developed	54,648,000	32,192,000	29,090,000
Revisions of Previous Estimates	18,291,000	6,112,000	(26,875,000)
Extensions, Discoveries, and Other Additions	2,292,000	1,531,000	8,703,000
Purchases of Reserves	1,305,000	10,229,000	76,000
Dispositions	(20,000)	(99,000)	(34,000)
Production	(31,830,000)	(22,176,000)	(15,369,000)
Crude Oil Equivalent (Boe)
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	452,917,000	341,407,000	272,825,000	250,129,000
Revisions of Previous Estimates	52,457,000	(42,631,000)	(93,471,000)
Extensions, Discoveries, and Other Additions	6,005,000	1,531,000	131,494,000
Purchases of Reserves	86,778,000	133,583,000	76,000
Dispositions	(1,900,000)	(1,725,000)	(34,000)
Production	(31,830,000)	(22,176,000)	(15,369,000)
Crude Oil [Member]
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	154,842,000	118,169,000	98,975,000	100,515,000
Revisions of Previous Estimates	28,334,000	(22,097,000)	(43,268,000)
Extensions, Discoveries, and Other Additions	2,923,000	494,000	48,707,000
Purchases of Reserves	18,971,000	50,126,000	17,000
Dispositions	(653,000)	(601,000)	(12,000)
Production	(12,902,000)	(8,728,000)	(6,984,000)
Year-over-Year Activity [Domain]
Schedule of Developed and Undeveloped Reserves [Line Items]
Undeveloped Reserves Converted to Developed		32,200,000	29,090,000
Revisions of Previous Estimates			93,471,000
Extensions, Discoveries, and Other Additions	93,900,000		131,494,000
Wells Per Section			16
Gross PUD horizontal locations			791	774
Proved developed and undeveloped reserves percent increase or decrease | Rate	32.6619%	2500.00%
Estimated PUD conversion rate | Rate		19.00%	16.00%
Actual PUD conversion rate | Rate	23.00%		17.00%
Change in drilling plans			(56,000,000)
Upward (Downward) Revision due to change in SEC pricing			(33,000,000)
Upward (Downward) Revision due to removal of re-fracs			(11,000,000)
Upward (downward) revision due to geological findings			(22,000,000)

SUPPLEMENTAL INFORMATION - NA96

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Results of Operations for Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)bbl	Dec. 31, 2016USD ($)bbl	Dec. 31, 2015USD ($)bbl
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Estimated PUD conversion rate	16.00%
Extensions, Discoveries, and Other Additions | bbl	6,005,000	1,531,000	131,494,000
Purchases of Reserves | bbl	86,778,000	133,583,000	76,000
Revisions of Previous Estimates | bbl	52,457,000	(42,631,000)	(93,471,000)
Production | bbl	(31,830,000)	(22,176,000)	(15,369,000)
Infill Reserve Additions | bbl		16.8
Dispositions | bbl	(1,900,000)	(1,725,000)	(34,000)
Lease operating expenses	$ 89,641	$ 59,950	$ 56,992
Production taxes	60,717	31,410	18,443
Transportation, gathering, and processing expenses	33,220	18,415	10,151
Results of Operations for Crude Oil and Natural Gas Producing Activities
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Natural gas, NGL and crude oil sales	913,084	497,353	378,713
Commodity price risk management	(3,936)	(125,681)	203,183
Total Revenues from Oil and Gas Producing Activities	909,148	371,672	581,896
Lease operating expenses	89,641	59,950	56,992
Production taxes	60,717	31,410	18,443
Transportation, gathering, and processing expenses	33,220	18,415	10,151
Exploration Expense	47,334	4,669	1,102
Impairment of Oil and Gas Properties	285,887	9,973	161,620
Depreciation, Depletion and Amortization	462,482	413,105	298,760
Accretion of Asset Retirement Obligations	6,306	7,080	6,293
(Gain) loss on Sale of Properties and Equipment	(766)	(43)	(385)
Total Expense from Oil and Gas Producing Activities	984,821	544,559	552,976
Results of Operations of Natural Gas and Crude Oil Producing Activities, Income before Income Taxes	(75,673)	(172,887)	28,920
Provision for Income Taxes	47,247	64,733	(10,394)
Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs	$ (28,426)	$ (108,154)	$ 18,526
2015 PUD Reserves [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Production | bbl		61
Proved Developed Reserves [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Extensions, Discoveries, and Other Additions | bbl	2,292,000	1,531,000	8,703,000
Purchases of Reserves | bbl	1,305,000	10,229,000	76,000
Revisions of Previous Estimates | bbl	18,291,000	6,112,000	(26,875,000)
Production | bbl	(31,830,000)	(22,176,000)	(15,369,000)
Dispositions | bbl	(20,000)	(99,000)	(34,000)

SUPPLEMENTAL INFORMATION - NA97

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Costs Incurred in Natural Gas and Crude Oil Property Acquisition, Exploration and Development Activities (Unadited) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved Properties	[1]	$ 172	$ 268,567	$ 3,561
Unproved Properties	[1]	18,914	1,843,985	15
Development Costs	[2]	688,165	383,336	552,104
Exploratory drilling	[3]	80,103	0	0
Geological and geophysical	[3]	3,881	4,669	0
Total Costs Incurred	[4]	$ 791,235	2,500,557	555,680
Cost Incurred to Convert PUDs to PDNP			$ 463,400	$ 204,600	$ 207,800
[1]	Property acquisition costs represent costs incurred to purchase, lease, or otherwise acquire a property. Proved properties include approximately $40.9 million of infrastructure and pipeline costs in 2016.
[2]	Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended December 31, 2017, 2016, and 2015, $463.4 million, $204.6 million, and $207.8 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $32.8 million of infrastructure and pipeline costs in 2017.
[3]	Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells.
[4]	During the year ended 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved, undeveloped and development costs of $24.6 million. We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017.

SUPPLEMENTAL INFORMATION - NA98

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Capitalized Costs Related to Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved natural gas and crude oil properties	$ 4,356,922	$ 3,499,718
Unproved natural gas and crude oil properties	1,097,317	1,874,671
Uncompleted Wells, Equipment and Facilities	265,526	150,424
Capitalized Costs	5,719,765	5,524,813
Less accumulated DD&A	(1,803,847)	(1,534,678)
Capitalized Costs, Net	$ 3,915,918	$ 3,990,135

SUPPLEMENTAL INFORMATION - NA99

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves (Unaudited) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)bbl	Dec. 31, 2016USD ($)bbl	Dec. 31, 2015USD ($)bbl
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | bbl	(1,900,000)	(1,725,000)	(34,000)
Future Estimated Cash Flows	$ 12,340,407	$ 7,122,525	$ 6,297,298
Future Estimated Production Costs	(3,245,627)	(1,624,167)	(1,493,040)
Future Estimated Development Costs	(2,893,335)	(2,219,914)	(2,036,685)
Future Estimated Income Tax Expense	(748,494)	(597,476)	(508,332)
Future Net Cash Flows	5,452,951	2,680,968	2,259,241
10% Annual Discount for Estimated Timing of Cash Flows	(2,572,846)	(1,260,339)	(1,162,377)
Standardized Measure of Disconted Future Estimated Net Cash Flows	$ 2,880,105	$ 1,420,629	$ 1,096,864
Crude Oil [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | bbl	(653,000)	(601,000)	(12,000)

SUPPLEMENTAL INFORMATION - N100

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Unuadited) (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2013
Principal Sources of Change:
Sales of natural gas, NGL and crude oil production, net of production costs		$ (729,506,000)	$ (387,576,000)	$ (293,127,000)
Net changes in prices and production costs	[1]	841,713,000	(205,760,000)	(1,752,921,000)
Extensions, discoveries and improved recovery, less related costs		47,240,000	15,128,000	489,178,000
Sales of reserves		(2,613,000)	(3,745,000)	(463,000)
Purchases of reserves		224,483,000	487,636,000	374,000
Development costs incurred during the period		419,047,000	268,672,000	368,840,000
Revisions of previous quantity estimates		484,431,000	(320,286,000)	(1,286,462,000)
Changes in estimated income taxes		(138,560,000)	(13,630,000)	902,994,000
Net change in future development costs		25,183,000	391,145,000	112,958,000
Accretion of discount		167,487,000	133,747,000	345,007,000
Timing and other		120,571,000	(41,566,000)	(95,979,000)
Total		2,880,105,000	1,420,629,000	1,096,864,000	$ 2,306,465,000
Notes to Changes in SMOG [Abstract]
Weighted-Average price, net of production cost		$ 20.08	$ 15.73	$ 17.30
[1]	Our weighted-average price, net of production costs per Boe, in our 2017 reserve report increased to $20.08 as compared to $15.73 for 2016 and $17.30 for 2015.

SUPPLEMENTAL INFORMATION - N101

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Index price of reserves (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
oil and gas index price for reserves [Line Items]
Effective Income Tax Rate Reconciliation, Percent		(62.40%)	21.00%	37.40%	35.90%
Crude Oil (Bbls)
oil and gas index price for reserves [Line Items]
oil and gas index price for reserves	[1]	$ 51.34	$ 51.34	$ 42.75	$ 50.28
Natural Gas Liquids (Bbls)
oil and gas index price for reserves [Line Items]
oil and gas index price for reserves	[1]	51.34	51.34	42.75	50.28
Natural Gas (Mcf)
oil and gas index price for reserves [Line Items]
oil and gas index price for reserves	[1]	$ 2.98	$ 2.98	$ 2.48	$ 2.59
[1]	Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months.

SUPPLEMENTAL INFORMATION - Q102

SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION QUARTERLY FINANCIAL INFORMATION (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Total revenues					$ 108,097	$ 163,890	$ 20,097	$ 90,831	$ 921,616	$ 382,915	$ 595,326
Costs, expenses and other:
Total cost, expenses and other					178,608	179,178	163,379	193,864	1,159,868	715,029	659,150
Income from operations					(70,511)	(15,288)	(143,282)	(103,033)	(238,252)	(332,114)	(63,824)
Income (loss) from continuing operations before income taxes					(90,636)	(35,341)	(153,777)	(113,369)	(339,432)	(393,123)	(106,588)
Net loss					$ (55,639)	$ (23,309)	$ (95,450)	$ (71,530)	$ (127,504)	$ (245,928)	$ (68,280)
Basic
Net income (loss) attributable to shareholders	$ 1.18	$ (4.44)	$ 0.63	$ 0.70	$ (0.94)	$ (0.48)	$ (2.04)	$ (1.72)	$ (1.94)	$ (5.01)	$ (1.74)
Diluted
Net income (loss) attributable to shareholders	$ 1.17	$ (4.44)	$ 0.62	$ 0.70	$ (0.94)	$ (0.48)	$ (2.04)	$ (1.72)	$ (1.94)	$ (5.01)	$ (1.74)

SCHEDULE II- VALUATION AND QUAL

SCHEDULE II- VALUATION AND QUALIFYING ACCOUNTS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
allowance for uncollectible notes [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance, January 1		$ 44,038	$ 0
Charged to Cost and Expense		0	44,038
Deductions	[1]	44,038	0
Ending Balance, December 31		0	44,038	$ 0
Allowance for Doubtful Accounts [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance, January 1		2,190	2,009	486
Charged to Cost and Expense		1,108	1,309	1,700
Deductions	[1]	170	1,128	177
Ending Balance, December 31		3,128	2,190	2,009
Valuation Allowance for Unproved Natural Gas and Crude Oil Properties [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance, January 1		359	144	9,293
Charged to Cost and Expense		263,817	215	7,012
Deductions	[1]	13,017	0	16,161
Ending Balance, December 31		$ 251,159	$ 359	$ 144
[1]	For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent either actual expired or abandoned unproved crude oil and natural gas properties or an accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.