PDC Energy (PDCE) 10-K 28 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document Document - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 15, 2019	Jun. 30, 2018
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, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Amendment Flag	false
Amendment Description
Entity Common Stock, Shares Outstanding		66,148,128
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Shell Company	false
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Current Reporting Status	Yes
Entity Public Float			$ 3,971,039,266

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 1,398	$ 180,675
Accounts receivable, net	181,434	197,598
Fair value of derivatives	84,492	14,338
Prepaid expenses and other current assets	7,136	8,613
Total current assets	274,460	401,224
Properties and equipment, net	4,002,862	3,933,467
Assets held-for-sale	140,705	40,583
Fair value of derivatives	93,722	0
Other assets	32,396	45,116
Total Assets	4,544,145	4,420,390
Current liabilities:
Accounts payable	181,864	150,067
Production tax liability	60,719	37,654
Fair value of derivatives	3,364	79,302
Funds held for distribution	105,784	95,811
Accrued interest payable	14,150	11,815
Other accrued expenses	75,133	42,987
Total current liabilities	441,014	417,636
Long-term debt	1,194,876	1,151,932
Deferred income taxes	198,096	191,992
Asset retirement obligations	85,312	71,006
Liabilities held-for-sale	4,111	499
Fair value of derivatives	1,364	22,343
Other liabilities	92,664	57,333
Total liabilities	2,017,437	1,912,741
Shareholders' Equity:
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,148,609 and 65,955,080 issued as of December 31, 2018 and 2017, respectively	661	659
Additional paid-in capital	2,519,423	2,503,294
Retained earnings	8,727	6,704
Treasury shares - at cost, 45,220 and 55,927 as of December 31, 2018 and 2017, respectively	(2,103)	(3,008)
Total stockholders' equity	2,526,708	2,507,649
Total Liabilities and Stockholders' Equity	$ 4,544,145	$ 4,420,390

Balance Sheet Parentheticals (P

Balance Sheet Parentheticals (Parentheticals) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
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	66,148,609	65,955,080
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	45,220	55,927

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Results of Operations, Revenue from Oil and Gas Producing Activities									$ 1,389,961	$ 913,084	$ 497,353
Commodity price risk management gain (loss), net									145,237	(3,936)	(125,681)
Other income									13,461	12,468	11,243
Total revenues	$ 794,811	$ 280,717	$ 212,531	$ 260,600	$ 189,516	$ 183,235	$ 275,158	$ 273,707	1,548,659	921,616	382,915
Costs, expenses and other:
Lease operating expenses									130,957	89,641	59,950
Production taxes									90,357	60,717	31,410
Transportation, gathering and processing expenses									37,403	33,220	18,415
Exploration, geologic and geophysical expense									6,204	47,334	4,669
Impairment of properties and equipment									458,397	285,887	9,973
Impairment of goodwill									0	75,121	0
General and administrative expense									170,504	120,370	112,470
Depreciation, depletion and amortization									559,793	469,084	416,874
Accretion of asset retirement obligations									5,075	6,306	7,080
(Gain) loss on sale of properties and equipment									394	(766)	(43)
Provision for uncollectible notes receivable									0	40,203	(44,038)
Other expenses									11,829	13,157	10,193
Total costs, expenses and other	538,626	270,593	400,770	260,924	208,016	579,326	190,522	182,004	1,470,913	1,159,868	715,029
Income (loss) from operations	256,185	10,124	(188,239)	(324)	(18,500)	(396,091)	84,636	91,703	77,746	(238,252)	(332,114)
Loss on extinguishment of debt									0	24,747	0
Interest expense									(70,730)	(78,694)	(61,972)
Interest income									413	2,261	963
Income (loss) before income taxes	238,024	(7,310)	(205,580)	(17,705)	62,808	(414,887)	65,787	72,476	7,429	(339,432)	(393,123)
Income tax (expense) benefit									(5,406)	211,928	147,195
Net income (loss)	$ 178,853	$ (3,434)	$ (160,257)	$ (13,139)	$ 77,637	$ (292,537)	$ 41,250	$ 46,146	$ 2,023	$ (127,504)	$ (245,928)
Earnings per share attributable to shareholders:
Basic	$ 2.71	$ (0.05)	$ (2.43)	$ (0.20)	$ 1.18	$ (4.44)	$ 0.63	$ 0.70	$ 0.03	$ (1.94)	$ (5.01)
Diluted	$ 2.71	$ (0.05)	$ (2.43)	$ (0.20)	$ 1.17	$ (4.44)	$ 0.62	$ 0.70	$ 0.03	$ (1.94)	$ (5.01)
Weighted-average common shares outstanding:
Basic									66,059	65,837	49,052
Diluted									66,303	65,837	49,052

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 2,023	$ (127,504)	$ (245,928)
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Net change in fair value of unsettled commodity derivatives	(260,775)	17,260	333,770
Depreciation, depletion and amortization	559,793	469,084	416,874
Impairment of properties and equipment	458,397	285,887	9,973
Impairment of goodwill	0	75,121	0
Exploratory dry hole costs	113	41,297	0
Provision for uncollectible notes receivable	0	40,203	(44,038)
Loss on extinguishment of debt	0	24,747	0
Accretion of asset retirement obligations	5,075	6,306	7,080
Non-cash stock-based compensation	21,782	19,353	19,502
(Gain) loss on sale of properties and equipment	394	(766)	(43)
Amortization of debt discount and issuance costs	12,769	12,907	16,167
Deferred income taxes	6,105	(203,685)	(137,249)
Other	2,763	2,265	2,603
Total adjustments to net income (loss) to reconcile to net cash from operating activities:	806,416	709,573	712,715
Changes in current assets and liabilities:
Accounts receivable	12,025	(60,546)	(32,627)
Other assets	(81)	3,364	2,303
Production tax liability	35,225	31,316	9,223
Accounts payable and accrued expenses	16,261	31,378	(162)
Funds held for future distribution	9,973	24,472	36,510
Asset retirement obligations	(13,341)	(10,176)	(4,109)
Other liabilities	20,801	(4,064)	8,338
Total changes in assets and liabilities	80,863	15,744	19,476
Net cash from operating activities	889,302	597,813	486,263
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(946,350)	(737,208)	(436,884)
Capital expenditures for other properties and equipment	(11,055)	(5,094)	(3,464)
Acquisition of crude oil and natural gas properties	(180,026)	(15,628)	(1,073,723)
Proceeds from sale of properties and equipment	3,562	9,991	4,945
Proceeds from divestiture	44,693	0	0
Sale of promissory note	0	40,203	0
Restricted cash	1,249	(9,250)	0
Sale of short-term investments	0	49,890	0
Purchase of short-term investments	0	(49,890)	0
Net cash from investing activities	(1,087,927)	(716,986)	(1,509,126)
Proceeds from revolving credit facility	1,072,500	0	85,000
Repayment of revolving credit facility	(1,040,000)	0	(122,000)
Proceeds from issuance of equity, net of issuance costs	0	0	855,074
Proceeds from issuance of senior notes	0	592,366	392,172
Proceeds from issuance of convertible senior notes	0	0	193,935
Redemption of senior notes	0	(519,375)	0
Redemption of convertible notes	0	0	(115,000)
Payment of debt issuance costs	(7,704)	(50)	(15,556)
Purchase of treasury shares	(5,147)	(6,672)	(6,935)
Other	(1,550)	(1,271)	(577)
Net cash from financing activities	18,099	64,998	1,266,113
Net change in cash, cash equivalents and restricted cash	(180,526)	(54,175)	243,250
Cash, cash equivalents and restricted cash, beginning of year	189,925	244,100	850
Cash, cash equivalents and restricted cash, end of year	$ 9,399	$ 189,925	$ 244,100

Consolidated Statement of Equit

Consolidated Statement of Equity - 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			40,174,776			(20,220)
Shares issued pursuant to sale of equity			15,007,500
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
Stock Issued During Period, Value, New Issues		$ 855,083	$ 150	$ 854,933
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)
Stockholders' Equity Beginning, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2015		1,287,197	$ 402	907,382	$ 380,422	$ (1,009)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Purchase of treasury shares	$ (6,935)	(6,935)				(6,935)
Issuance of stock awards, net of forfeitures		0	$ 3	(3)
Stock Issued During Period, Shares, Restricted Stock Award, Gross			46,084
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)
Stock Issued During Period, Value, Conversion of Convertible Securities		0	$ 8	(8)
Stock Issued During Period, Value, Acquisitions		690,702	94	690,608
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]
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt, Subsequent Adjustments		23,518		23,518
Stockholders' Equity, Other		0		286	(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			0			83,228
Non-employee directors' deferred compensation plan						(3,035)
Purchase of treasury shares	(6,672)	(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)
Cumulative Effect on Retained Earnings, Net of Tax					0
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)
Issuance of stock awards, net of forfeitures			193,529
Purchase of treasury shares						(102,647)
Issuance of treasury shares						104,068
Non-employee directors' deferred compensation plan						9,286
Purchase of treasury shares	(5,147)	(5,147)				$ (5,147)
Issuance of stock awards, net of forfeitures		0	$ 2	(2)
Share-based Compensation expense	21,782	21,782		21,782
Issuance of treasury shares		0		(5,561)		5,561
Non-employee directors' deferred compensation plan		491				491
Net income (Loss) attributable to shareholders	$ 2,023	2,023			2,023
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2018		2,526,708	$ 661	2,519,423	$ 8,727	$ (2,103)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' Equity, Other		$ (90)		$ (90)
Shares, Issued			66,148,609			(45,220)

NATURE OF OPERATIONS AND BASIS

NATURE OF OPERATIONS AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2018
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 operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused in the rural areas of the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the first quarter of 2018. As of December 31, 2018 , we owned an interest in approximately 2,900 productive gross wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. 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 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 and exchanged 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 to conform to the current period presentation. The reclassifications had no impact on previously reported results.

BUSINESS COMBINATIONS BUSINESS

BUSINESS COMBINATIONS BUSINESS COMBINATIONS (Notes)	12 Months Ended
	Dec. 31, 2018
Business Acquisition [Line Items]
Business Combination Disclosure [Text Block]	BUSINESS COMBINATIONS In January 2018, we closed the acquisition of properties from Bayswater Exploration and Production LLC (the "Bayswater Asset Acquisition") for approximately $200.0 million in cash, after post-closing adjustments, including $21.0 million deposited into an escrow account in 2017. The $21.0 million deposit was included in other assets on our December 31, 2017 consolidated balance sheet. We acquired approximately 7,400 net acres, approximately 220 gross drilling locations and 24 operated horizontal wells that were either DUCs or in-process wells at the time of closing. The final purchase price and allocation of the assets acquired and the liabilities assumed in the acquisition are presented below. Adjustments made subsequent to the preliminary purchase price stem from final settlement of the proceeds from operating activities and 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. Such adjustments primarily relate to sales, operating expenses and capital costs from the effective date through closing. The details of the final purchase price and allocation of the purchase price for the transaction, are presented below (in thousands): December 31, 2018 Acquisition costs: Cash $ 168,560 Deposit made in prior period 21,000 Total cash consideration 189,560 Other purchase price adjustments 10,422 Total acquisition costs $ 199,982 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current assets $ 468 Crude oil and natural gas properties - proved 205,834 Other assets 2,796 Total assets acquired 209,098 Liabilities assumed: Current liabilities (4,429 ) Asset retirement obligations (4,687 ) Total liabilities assumed (9,116 ) Total identifiable net assets acquired $ 199,982 This transaction was accounted for under the acquisition method. Accordingly, we conducted assessments of the 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. 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. The allocation of the value to the underlying leases also requires significant judgment and is based on a combination of comparable market transactions, the term 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. The results of operations for the Bayswater Asset Acquisition for the year ended December 31, 2018 have been included in our consolidated financial statements, including approximately $70.8 million of total revenue, $39.3 million of income from operations and $0.59 of diluted earnings per share. Pro forma results of operations for the Bayswater Asset Acquisition showing results as if the acquisition had been completed as of January 1, 2017 would not have been material to our consolidated financial statements for the year ended December 31, 2017 .

Revenue Recognition Revenue Rec

Revenue Recognition Revenue Recognition (Notes)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	REVENUE RECOGNITION On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $11.3 million in 2017 with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for 2018 , we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the New Revenue Standard to have a significant impact on our net income going forward. Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the New Revenue Standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. As discussed above, we enter into agreements for the sale, transportation, gathering and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based upon first-of-the-month index prices, as in each case this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2018 , 2017 and 2016 (in thousands): Year Ended December 31, Revenue by Commodity and Operating Region 2018 2017 (1) 2016 (1) Crude oil Wattenberg Field $ 783,158 $ 529,562 $ 329,168 Delaware Basin 252,107 82,677 3,918 Utica Shale (2) 2,696 12,814 15,769 Total $ 1,037,961 $ 625,053 $ 348,855 Natural gas Wattenberg Field $ 130,073 $ 131,792 $ 86,633 Delaware Basin 32,010 21,251 1,039 Utica Shale (2) 1,109 5,216 3,904 Total $ 163,192 $ 158,259 $ 91,576 NGLs Wattenberg Field $ 132,820 $ 104,298 $ 52,919 Delaware Basin 55,148 20,756 645 Utica Shale (2) 840 4,718 3,358 Total $ 188,808 $ 129,772 $ 56,922 Revenue by Operating Region Wattenberg Field $ 1,046,051 $ 765,652 $ 468,720 Delaware Basin 339,265 124,684 5,602 Utica Shale (2) 4,645 22,748 23,031 Total $ 1,389,961 $ 913,084 $ 497,353 ________________________________________ (1) As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017 and 2016 have not been restated. Such changes would not have been material. (2) In March 2018, we completed the disposition of our Utica Shale properties. Contract Assets. Contract assets include material contributions in aid of construction, which are common in purchase and processing agreements with midstream service providers that are our customers. Generally, the intent of the payments is to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are classified as long-term assets and included in other assets on our consolidated balance sheet. The contract assets will be amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer. The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for year ended December 31, 2018 : Amount (in thousands) Beginning balance, January 1, 2018 $ 3,746 Additions 2,884 Amortized as a reduction to crude oil, natural gas and NGLs sales (3,096 ) Ending balance, December 31, 2018 $ 3,534 Customer Accounts Receivable. Our accounts receivable include amounts billed and currently due from sales of our crude oil, natural gas and NGLs production. Our gross accounts receivable balance from crude oil, natural gas and NGLs sales at December 31, 2018 and 2017 was $155.8 million and $154.3 million , respectively. We did not record an allowance for doubtful accounts for these receivables at December 31, 2018 or 2017.
Disaggregation of Revenue [Table Text Block]	REVENUE RECOGNITION On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $11.3 million in 2017 with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for 2018 , we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the New Revenue Standard to have a significant impact on our net income going forward. Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the New Revenue Standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. As discussed above, we enter into agreements for the sale, transportation, gathering and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based upon first-of-the-month index prices, as in each case this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2018 , 2017 and 2016 (in thousands): Year Ended December 31, Revenue by Commodity and Operating Region 2018 2017 (1) 2016 (1) Crude oil Wattenberg Field $ 783,158 $ 529,562 $ 329,168 Delaware Basin 252,107 82,677 3,918 Utica Shale (2) 2,696 12,814 15,769 Total $ 1,037,961 $ 625,053 $ 348,855 Natural gas Wattenberg Field $ 130,073 $ 131,792 $ 86,633 Delaware Basin 32,010 21,251 1,039 Utica Shale (2) 1,109 5,216 3,904 Total $ 163,192 $ 158,259 $ 91,576 NGLs Wattenberg Field $ 132,820 $ 104,298 $ 52,919 Delaware Basin 55,148 20,756 645 Utica Shale (2) 840 4,718 3,358 Total $ 188,808 $ 129,772 $ 56,922 Revenue by Operating Region Wattenberg Field $ 1,046,051 $ 765,652 $ 468,720 Delaware Basin 339,265 124,684 5,602 Utica Shale (2) 4,645 22,748 23,031 Total $ 1,389,961 $ 913,084 $ 497,353 ________________________________________ (1) As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017 and 2016 have not been restated. Such changes would not have been material. (2) In March 2018, we completed the disposition of our Utica Shale properties. Contract Assets. Contract assets include material contributions in aid of construction, which are common in purchase and processing agreements with midstream service providers that are our customers. Generally, the intent of the payments is to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are classified as long-term assets and included in other assets on our consolidated balance sheet. The contract assets will be amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer. The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for year ended December 31, 2018 : Amount (in thousands) Beginning balance, January 1, 2018 $ 3,746 Additions 2,884 Amortized as a reduction to crude oil, natural gas and NGLs sales (3,096 ) Ending balance, December 31, 2018 $ 3,534 Customer Accounts Receivable. Our accounts receivable include amounts billed and currently due from sales of our crude oil, natural gas and NGLs production. Our gross accounts receivable balance from crude oil, natural gas and NGLs sales at December 31, 2018 and 2017 was $155.8 million and $154.3 million , respectively. We did not record an allowance for doubtful accounts for these receivables at December 31, 2018 or 2017. Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2018 , 2017 and 2016 (in thousands): Year Ended December 31, Revenue by Commodity and Operating Region 2018 2017 (1) 2016 (1) Crude oil Wattenberg Field $ 783,158 $ 529,562 $ 329,168 Delaware Basin 252,107 82,677 3,918 Utica Shale (2) 2,696 12,814 15,769 Total $ 1,037,961 $ 625,053 $ 348,855 Natural gas Wattenberg Field $ 130,073 $ 131,792 $ 86,633 Delaware Basin 32,010 21,251 1,039 Utica Shale (2) 1,109 5,216 3,904 Total $ 163,192 $ 158,259 $ 91,576 NGLs Wattenberg Field $ 132,820 $ 104,298 $ 52,919 Delaware Basin 55,148 20,756 645 Utica Shale (2) 840 4,718 3,358 Total $ 188,808 $ 129,772 $ 56,922 Revenue by Operating Region Wattenberg Field $ 1,046,051 $ 765,652 $ 468,720 Delaware Basin 339,265 124,684 5,602 Utica Shale (2) 4,645 22,748 23,031 Total $ 1,389,961 $ 913,084 $ 497,353 ________________________________________ (1) As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017 and 2016 have not been restated. Such changes would not have been material. (2) In March 2018, we completed the disposition of our Utica Shale properties.

FAIR VALUE MEASUREMENTS AND DIS

FAIR VALUE MEASUREMENTS AND DISCLOSURES	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurement and Measurement Inputs, Recurring and Nonrecurring [Text Block]	FAIR VALUE OF 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. 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. 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, 2018 2017 Significant Other Significant Total Significant Other Significant Total (in thousands) Total assets $ 118,521 $ 59,693 $ 178,214 $ 12,949 $ 1,389 $ 14,338 Total liabilities (3,364 ) (1,364 ) (4,728 ) (90,569 ) (11,076 ) (101,645 ) Net asset (liability) $ 115,157 $ 58,329 $ 173,486 $ (77,620 ) $ (9,687 ) $ (87,307 ) The following table presents a reconciliation of our Level 3 commodity derivative instruments measured at fair value: Year Ended December 31, 2018 2017 2016 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ (9,687 ) $ (9,574 ) $ 91,288 Changes in fair value included in consolidated statements of operations line item: Commodity price risk management gain (loss), net 63,257 6,241 (28,550 ) Settlements included in consolidated statements of operations line items: Commodity price risk management ( loss) , net 4,759 (6,354 ) (72,312 ) Fair value of Level 3 instruments, net asset (liability) end of period $ 58,329 $ (9,687 ) $ (9,574 ) 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 ) Total $ — $ (866 ) $ (12,905 ) 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, 2018 and 2017: As of December 31, 2018 2017 Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par (in millions) Senior notes: 2021 Convertible Notes $ 175.4 87.7 % $ 195.6 97.8 % 2024 Senior Notes 370.2 92.5 % 416.0 104.0 % 2026 Senior Notes 532.4 88.7 % 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.

CONCENTRATION OF RISK

CONCENTRATION OF RISK	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (in thousands) Crude oil, natural gas and NGLs sales $ 155,756 $ 154,260 Joint interest billings 19,580 34,576 Derivative counterparties 3,937 (18 ) Income tax receivable — 6,015 Other 6,542 5,893 Allowance for doubtful accounts (4,381 ) (3,128 ) Accounts receivable, net $ 181,434 $ 197,598 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, 2018 and 2017 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2018 , two of our customers represent 10 percent or greater of our accounts receivable balance. As of December 31, 2017 , 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 2018 2017 2016 DCP Midstream, LP 12.5 % 19.6 % 20.2 % Suncor Energy Marketing, Inc. — % 16.4 % 22.3 % Aka Energy Group, LLC — % — % 13.4 % Concord Energy, LLC — % — % 13.4 % Bridger Energy, LLC — % — % 11.5 % 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. 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, 2018 . Note Receivable. Note Receivable. In 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 . 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. In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately $40.2 million in cash. 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, 2018 2017 (in thousands) Employee benefits $ 25,811 $ 22,383 Asset retirement obligations 25,598 15,801 Environmental expenses 3,038 1,374 Other 20,686 3,429 Other accrued expenses $ 75,133 $ 42,987 Other Liabilities. The following table presents the components of other liabilities as of: As of December 31, 2018 2017 (in thousands) Production taxes $ 61,310 $ 50,476 Deferred oil gathering credit 22,710 — Other 8,644 6,857 Other liabilities $ 92,664 $ 57,333 Deferred Oil Gathering Credit. In January 2018, we received a payment of $24.1 million from a midstream service provider 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 crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The payment will be amortized using the straight-line method over the life of the amendment. Amortization charges totaling approximately $1.4 million for 2018 related to the deferred oil gathering credit are included as a reduction to transportation, gathering and processing expenses in our consolidated statements of operations.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2018
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, 2018 , we had commodity derivatives positions covering approximately 11.0 MMBbls and 8.6 MMBbls of crude oil production for 2019 and 2020, respectively. As of the same date, we had hedged approximately 26.4 Bcf of natural gas for 2019. 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, 2018 , 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. As of December 31, 2018 , we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. Collars Fixed-Price Swaps Commodity/ Index/ Maturity Period Quantity (Crude oil - MBls Natural Gas - BBtu) Weighted-Average Contract Price Quantity (Crude Oil - MBbls Gas and Basis- BBtu) Weighted- Average Contract Price Fair Value December 31, 2018 (1) (in thousands) Floors Ceilings Crude Oil NYMEX 2019 2,600 $ 56.54 $ 68.13 8,400 $ 53.86 $ 82,305 2020 3,600 55.00 71.68 5,000 62.07 92,359 Total Crude Oil 6,200 13,400 $ 174,664 Natural Gas NYMEX 2019 — — — 26,008 2.91 1,408 Dominion South 2019 — — — 372 3.13 30 Columbia 2019 — — — 3 2.40 — Total Natural Gas — 26,383 $ 1,438 Basis Protection - Natural Gas CIG 2019 — — — 25,924 (0.78 ) (2,616 ) Total Basis Protection - Natural Gas — 25,924 $ (2,616 ) Commodity Derivatives Fair Value $ 173,486 (1) Approximately 33.5 percent of the fair value of our commodity derivative assets and 28.9 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). 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, 2018 and 2017 : Derivative instruments: Consolidated balance sheet line item 2018 2017 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 84,492 $ 7,340 Basis protection derivative contracts Fair value of derivatives — 6,998 84,492 14,338 Non-current Commodity derivative contracts Fair value of derivatives 93,722 — 93,722 — Total derivative assets $ 178,214 $ 14,338 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 748 77,999 Basis protection derivative contracts Fair value of derivatives 2,616 234 Rollfactor derivative contracts Fair value of derivatives — 1,069 3,364 79,302 Non-current Commodity derivative contracts Fair value of derivatives 1,364 22,343 Total derivative liabilities $ 4,728 $ 101,645 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 2018 2017 2016 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (115,538 ) $ 13,324 $ 208,103 Net change in fair value of unsettled derivatives 260,775 (17,260 ) (333,784 ) Total commodity price risk management gain (loss), net $ 145,237 $ (3,936 ) $ (125,681 ) 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, 2018 Derivative instruments, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 178,214 $ (3,985 ) $ 174,229 Liability derivatives: Derivative instruments, at fair value $ 4,728 $ (3,985 ) $ 743 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

PROPERTIES AND EQUIPMENT

PROPERTIES AND EQUIPMENT	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 5,452,613 $ 4,356,922 Unproved 492,594 1,097,317 Total crude oil and natural gas properties 5,945,207 5,454,239 Infrastructure and other 60,612 109,359 Land and buildings 11,243 10,960 Construction in progress 356,095 196,024 Properties and equipment, at cost 6,373,157 5,770,582 Accumulated DD&A (2,370,295 ) (1,837,115 ) Properties and equipment, net $ 4,002,862 $ 3,933,467 Acreage Exchanges. In November 2018, we completed a nonmonetary acreage exchange that resulted in our acquisition of approximately 12,300 net acres that consolidated our position in the core area of the Wattenberg Field. We recognized a gain of approximately $6.0 million related to the exchange based on the fair value of the assets surrendered. Also during 2018, we completed another nonmonetary acreage exchange in the Wattenberg Field, resulting in us acquiring approximately 2,500 net acres and $3.7 million in cash. It was concluded that this transaction lacked commercial substance, and accordingly, the trade was recorded at the previous historical cost of the assets exchanged, less cash received. In 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 approximately 15,900 net acres in exchange for 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. Classification of Assets and Liabilities as Held-for-Sale. During the fourth quarter of 2018, as part of our plan to divest certain of our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets, we began actively marketing the assets for sale; therefore, these assets are classified as held-for-sale as they met the criteria for such classification at December 31, 2018 . We currently expect to execute agreements on the sales of these assets in the first half of 2019. Our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets do not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we will not account for it as a discontinued operation. Also included in the assets held-for-sale are certain non-core Delaware Basin crude oil and natural gas properties. During 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 were classified as held-for-sale as they met the criteria for such classification at December 31, 2017. In March 2018, we completed the Utica Shale Divestiture for net cash proceeds of approximately $ 39.0 million . We recorded a loss on sale of properties and equipment of $ 1.4 million for 2018 , which included post-closing adjustments. The Utica Shale Divestiture did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for it as a discontinued operation. The following table presents balance sheet data related to assets and liabilities held-for-sale: As of December 31, 2018 2017 (in thousands) Assets Properties and equipment, net $ 137,448 $ 40,583 Other assets 3,257 — Total assets $ 140,705 $ 40,583 Liabilities Asset retirement obligation $ 4,111 $ 499 Total liabilities $ 4,111 $ 499 Impairment of Properties and Equipment The following table presents impairment charges recorded for properties and equipment: Year Ended December 31, 2018 2017 2016 (in thousands) Impairment of proved and unproved properties $ 458,397 $ 285,465 $ 5,562 Amortization of individually insignificant unproved properties — 422 1,379 Land and buildings — — 3,032 Total impairment of properties and equipment $ 458,397 $ 285,887 $ 9,973 During 2018 , we recorded impairment charges totaling $458.4 million as we identified current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin and made the determination that we would no longer pursue plans to develop these properties. The impaired non-focus leasehold typically has a higher gas to oil ratio and a greater degree of geologic complexity than our other Delaware Basin properties and is further impacted by widening crude oil and natural gas differentials and increased well development costs. We continue to explore options for our non-focus areas and monitor them for possible future impairment based on similar analyses. We determined the fair value of the properties 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 impairment charges noted above include the correction of two errors in the timing of the reporting of certain impairments. In 2018, we corrected an error in our calculation of unproved properties and goodwill originally recorded in 2017, resulting in an additional impairment charge of $6.3 million being recorded during the three months ended March 31, 2018. Further, during the fourth quarter of 2018, we corrected for an additional $8.4 million impairment of unproved properties relating to the three months ended September 30, 2018. This correction had no impact on the year ended December 31, 2018. We evaluated these errors under the guidance of Accounting Standards Codification 250, Accounting Changes and Error Corrections ("ASC 250"). Based on the guidance in ASC 250, we determined that the errors did not have a material impact on our previously-issued financial statements or those of the period of correction. During 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 the operational and geologic data obtained, the current increased cost environment for drilling and completion services in the Delaware Basin, our decreased future commodity price outlook and 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 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 were 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. Suspended Well Costs. 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 sheets: As of December 31, 2018 2017 (in thousands, except for number of wells) Beginning balance $ 15,448 $ — Additions to capitalized exploratory well costs pending the determination of proved reserves 35,127 51,776 Reclassifications to proved properties (38,387 ) (36,328 ) Balance at December 31, $ 12,188 $ 15,448 Number of wells pending determination 2 3 Exploration Expenses. The following table presents the major components of exploration, geologic and geophysical expense: Year Ended December 31, 2018 2017 2016 (in thousands) Exploratory dry hole costs $ 113 $ 41,297 $ — Geological and geophysical costs, including seismic purchases 3,401 3,881 3,472 Operating, personnel and other 2,690 2,156 1,197 Total exploration, geologic and geophysical expense $ 6,204 $ 47,334 $ 4,669 Exploratory dry hole costs. During 2017, two exploratory dry holes, 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, 2018
Goodwill [Line Items]
Goodwill Disclosure [Text Block]	GOODWILL Goodwill that resulted from the purchase price allocation of a business combination in the Delaware Basin in December 2016 was determined to be $ 75.1 million . In 2017, 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 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 2017.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2018
Long-term Debt, Unclassified [Abstract]
Long-term Debt [Text Block]	LONG-TERM DEBT Long-term debt consists of the following: As of December 31, 2018 2017 (in thousands) Senior notes: 1.125% Convertible Notes due 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (22,766 ) (30,328 ) Unamortized debt issuance costs (2,640 ) (3,615 ) 1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs 174,594 166,057 6.125% Senior Notes due 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (5,590 ) (6,570 ) 6.125% Senior Notes due 2024, net of unamortized debt issuance costs 394,410 393,430 5.75% Senior Notes due 2026: Principal amount 600,000 600,000 Unamortized debt issuance costs (6,628 ) (7,555 ) 5.75% Senior Notes due 2026, net of unamortized debt issuance costs 593,372 592,445 Total senior notes 1,162,376 1,151,932 Revolving credit facility 32,500 — Total long-term debt, net of unamortized discount and debt issuance costs 1,194,876 1,151,932 Less current portion of long-term debt — — Long-term debt $ 1,194,876 $ 1,151,932 Senior Notes 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. 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 . 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 thereof. 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, 2018 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using the effective interest method. Based upon the December 31, 2018 stock price of $29.76 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 . 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, to pay related fees and expenses, and for general corporate purposes. 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 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. 2026 Senior Notes. In November 2017, we issued $600.0 million aggregate principal amount 5.75% senior notes due May 15, 2026. The 2026 Senior Notes are governed by an indenture dated November 29, 2017 . 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 . 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 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 2021 Convertible Notes, the 2024 Senior Notes and 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 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. Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes. The indentures governing the 2024 Senior Notes and 2026 Senior Notes contain 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. As of December 31, 2018 , we were in compliance with all covenants related to the 2021 Convertible Notes, 2024 Convertible Notes and the 2026 Senior Notes. Revolving Credit Facility In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”). The Restated Credit Agreement amends and restates our Third Amended and Restated Credit Agreement dated as of May 21, 2013, as amended. Among other things, the Restated Credit Agreement provides for a maximum credit amount of $2.5 billion , an initial borrowing base of $1.3 billion and an initial elected commitment amount of $700 million . The amount we may borrow under the Restated Credit Agreement is subject to certain limitations under our Notes. In addition, the Restated Credit Agreement extends the maturity date of the facility to May 2023 , reflects improved covenant flexibility and certain reductions in interest rates applicable to borrowings under the facility and includes a $25 million swingline facility. In October 2018, we increased the commitment level on our revolving credit facility to the current borrowing base amount of $1.3 billion . The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual 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 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 greatest of the administrative agent's prime rate, the federal funds rate plus a premium 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, 2018 , the applicable interest margin is 0.25 percent for the alternate base rate option or 1.25 percent for the LIBOR option, and the unused commitment fee is 0.375 percent . Principal payments are generally not required until the revolving credit facility expires in May 2023 , unless 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, 2018 , we were in compliance with all the revolving credit facility covenants. As of December 31, 2018 and 2017 , debt issuance costs related to our revolving credit facility were $11.5 million and $6.2 million , respectively, and are included in other assets on the consolidated balance sheets. As of December 31, 2018 and 2017 , availability under our revolving credit facility was $1.3 billion and $ 700 million , respectively. As of December 31, 2018 , the weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment, was 4.5 percent .

CAPITAL LEASES CAPITAL LEASES (

CAPITAL LEASES CAPITAL LEASES (Notes)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (in thousands) Vehicles $ 7,941 $ 6,249 Accumulated depreciation (3,368 ) (1,882 ) $ 4,573 $ 4,367 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) 2019 $ 2,111 2020 2,236 2021 698 2022 381 2023 134 5,560 Less executory cost (278 ) Less amount representing interest (603 ) Present value of minimum lease payments $ 4,679 Short-term capital lease obligations $ 1,779 Long-term capital lease obligations 2,900 $ 4,679 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.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2018
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: Year Ended December 31, 2018 2017 (in thousands) Beginning balance $ 87,306 $ 92,387 Obligations incurred with development activities 2,793 3,638 Obligations incurred with acquisition 4,332 — Accretion expense 5,075 6,306 Revisions in estimated cash flows 30,166 (2,860 ) Obligations discharged with asset retirements (14,651 ) (12,165 ) Balance at December 31 115,021 87,306 Less liabilities held-for-sale (4,111 ) (499 ) Less current portion (25,598 ) (15,801 ) Long-term portion $ 85,312 $ 71,006 Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging and abandonment costs considering federal and state regulatory requirements in effect. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. Short-term asset retirement obligations are included in other accrued expenses on the consolidated balance sheets. The revisions in estimated cash flows during 2018 were primarily due to changes in estimates of costs for materials and services related to the plugging and abandonment of wells and the shortening of the estimated expected lives of wells.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2018
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 and water delivery and disposal commitments: Year Ending December 31, Area 2019 2020 2021 2022 2022 and Total Expiration Natural gas (MMcf) Wattenberg Field 23,934 31,110 31,025 31,025 90,897 207,991 April 30, 2026 Delaware Basin 48,147 37,430 21,307 — — 106,884 December 31, 2021 Gas Marketing 7,117 7,136 7,056 4,495 — 25,804 August 31, 2022 Total 79,198 75,676 59,388 35,520 90,897 340,679 Crude oil (MBbls) Wattenberg Field 9,713 5,918 5,475 5,475 3,180 29,761 April 30, 2023 Delaware Basin 7,359 8,784 8,030 8,030 8,030 40,233 December 31, 2023 Total 17,072 14,702 13,505 13,505 11,210 69,994 Water (MBbls) Wattenberg Field 3,103 6,207 6,207 6,207 12,413 34,137 December 31, 2024 Delaware Basin 3,650 3,660 3,650 3,650 1,770 16,380 June 26, 2023 Total 6,753 9,867 9,857 9,857 14,183 50,517 Dollar commitment (in thousands) $ 106,844 $ 78,209 $ 74,409 $ 67,354 $ 102,925 $ 429,741 Wattenberg Field. In anticipation of our future drilling activities in the Wattenberg Field, we have entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider completed and turned on line the first of the two 200 MMcfd cryogenic plants in August 2018. The second plant is currently scheduled to be completed in the second quarter of 2019. We are bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service date of the relevant 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 in these volume commitments may be offset by other 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. Delaware Basin . In May 2018, we entered into a firm sales agreement that is effective from June 2018 through December 2023 with an integrated marketing company for our crude oil production in the Delaware Basin. Contracted volumes are currently 14,600 barrels of crude oil per day and increase over time to 26,400 barrels of crude oil per day. These agreements are expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices. Commodity Sales . For 2018 , amounts related to long-term transportation volumes, net to our interest, for Wattenberg Field crude oil and Delaware Basin natural gas were $27.3 million and in accordance with the guidance in the New Revenue Standard, were netted against our crude oil and natural gas sales in our consolidated statements of operations. In addition, for 2018 , $1.6 million related to long-term transportation volumes were recorded in transportation, gathering and processing expense in our consolidated statements of operations. For each of 2017 and 2016 , amounts related to long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $10.0 million and were recorded in transportation, gathering and processing expense in our consolidated statements of operations. In March 2018, we completed the disposition of our Utica Shale properties. 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 (collectively, the "Partnerships"), against PDC and includes claims for breach of fiduciary duty and breach of contract. The plaintiffs also included claims against two of our senior officers and three independent members of our Board of Directors for alleged breach of fiduciary duty. The lawsuit accuses PDC, as the managing general partner of the Partnerships, of, among other things, failing to maximize the productivity of the Partnerships’ crude oil and natural gas wells and improperly assigning the Partnerships only interests in the wells, as opposed to leasehold interests in surrounding acreage. In late April 2018, the plaintiffs filed an amendment to their complaint, which alleges additional facts and purports to add direct class action claims in addition to the original derivative claims. We filed a motion to dismiss this amended complaint and the claims against the individuals named as defendants on July 31, 2018. On February 19, 2019, the court granted the motion to dismiss, in part. It dismissed all claims against the individuals named as defendants. It also held that that the plaintiffs were time-barred from using the failure to assign acreage assignments to support their claims for breach of fiduciary duty against PDC. This action has been stayed as a result of the partnership bankruptcy proceedings described in Partnership Bankruptcy Filings below. We are currently unable to estimate any potential damages resulting from this lawsuit. Partnership Bankruptcy Filings. On October 30, 2018, the Partnerships filed petitions under Chapter 11 of the Bankruptcy Code (the "Chapter 11 Proceedings") in the United States Bankruptcy Court for the Northern District of Texas, Dallas Division (the "Bankruptcy Court"). The Partnerships intend to enter into a transaction with us, pursuant to which the Partnerships will sell substantially all of their assets to us through a Chapter 11 plan of liquidation (the "Chapter 11 Plan") and provide a release of any claims, including those asserted in Dufresne, et al. v. PDC Energy, et al. (the "Dufresne Case"). The Partnerships remain in possession of their assets and continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. In addition, a third-party (the “Responsible Party”) has been designated for the Partnerships. The Responsible Party is expected to oversee all actions for the Partnerships in connection with the Chapter 11 Proceedings, including actions relating to the anticipated transactions with us and seeking approval of the Chapter 11 Plan. In late November and early December, 2018 the plaintiffs in the Dufresne Case filed several pleadings in the Bankruptcy Court, including one to dismiss the bankruptcy on grounds that PDC had no authority to hire the Responsible Party, the Responsible Party had no authority to cause the Partnerships to file bankruptcy, and the bankruptcy was filed solely for the purpose to gain a litigation advantage in and dismiss the Dufresne Case. The parties have agreed to mediate their disputes with respect to the Dufresne Case and the bankruptcy cases. As a result, on December 17, 2018 the Bankruptcy Court entered an agreed order staying the bankruptcy motions and the Dufresne Case until March 20, 2019 to allow the parties to mediate their disputes. We do not believe that the Partnership's Chapter 11 Proceedings will have a material adverse effect on our financial position, results of operations or liquidity, but we cannot predict the outcome of such proceedings. Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures 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, 2018 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 consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual. On October 23, 2018, we agreed to an Administrative Order by Consent ("AOC") with the Colorado Oil and Gas Conservation Commission relating to a historical release discovered during the decommissioning of a location in Weld County, Colorado, pursuant to which, among other things, we agreed to a penalty of approximately $130,000 , of which 20 percent would be suspended subject to compliance with certain corrective actions identified in the AOC. In addition to the penalty, we agreed to timely complete certain corrective actions set forth in the AOC relating to procedures for completing future work on buried or partially buried produced water vessels, and to reestablish vegetation and otherwise reclaim the location. Clean Air Act Agreement and Related Consent Decree. In June 2017, following our receipt of a 2015 Clean Air Act information request from the EPA and a 2015 compliance advisory from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Pollution Control Division, 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 and the compliance advisory. 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) of which the cash fines and the full cost of supplemental environmental projects were paid in the first and third quarters of 2018, respectively, (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. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. We are in the process of implementing the consent degree program. Over the course of its execution, we have identified certain immaterial deficiencies in our implementation of the program. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $100,000 . In addition, in December 2018, we were named as a nominal defendant in a derivative action filed in the Delaware chancery court. The complaint, which seeks unspecified monetary damages and various forms of equitable relief, alleges that certain current and former members of our board of directors violated their fiduciary duties, committed waste and were unjustly enriched by, among other things, failing to implement adequate environmental safeguards in connection with the issues that gave rise to the Department of Justice lawsuit and consent decree. We believe that this lawsuit is without merit but cannot predict its outcome. 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. 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, 2018 : Year Ending December 31, 2019 2020 2021 2022 2023 Thereafter Total (in thousands) Minimum Lease Payments $ 6,273 $ 6,365 $ 6,290 $ 5,229 $ 1,385 $ 2,256 $ 27,798 Operating lease expense for 2018 , 2017 and 2016 was $26.7 million , $17.2 million and $10.2 million , respectively.

COMMON STOCK

COMMON STOCK	12 Months Ended
	Dec. 31, 2018
COMMON STOCK [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Text Block]	COMMON STOCK Stock-Based Compensation Plans 2018 Equity Incentive Plan . In May 2018, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the “2018 Plan”). The 2018 Plan provides for a reserve of 1,800,000 shares of our common stock that may be issued pursuant to awards under the 2018 Plan and a term that expires in March 2028. As of December 31, 2018 , no shares have been issued under the 2018 plan. Shares issued may be either authorized but unissued shares, treasury shares or any combination. Additionally, the 2018 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or paid out in the form of cash. However, shares tendered or withheld to satisfy the exercise price of options or tax withholding obligations, and shares covering the portion of exercised stock-settled stock appreciation rights ("SARs") (regardless of the number of shares actually delivered), count against the share limit. Awards may be issued in the form of options, SARs, restricted stock, restricted stock units ("RSUs"), performance stock units ("PSUs") and other stock-based awards. Awards may vest over periods of continued service or the satisfaction of performance conditions set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee"), with a minimum one-year vesting period applicable to most awards. With regard to SARs and options, awards have a maximum exercisable period of ten years. 2010 Long-Term Equity Compensation Plan . Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was most recently approved by stockholders in 2013 (as the same has been amended and restated from time to time, the "2010 Plan"), will remain outstanding and we may use the 2010 Plan to grant awards. However, the share reserve of the 2010 Plan is nearly depleted. As of December 31, 2018 , there were 284,152 shares available for grant under 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, 2018 2017 2016 (in thousands) Stock-based compensation expense $ 21,782 $ 19,353 $ 19,502 Income tax benefit (5,210 ) (7,372 ) (7,296 ) Net stock-based compensation expense $ 16,572 $ 11,981 $ 12,206 Stock Appreciation Rights The SARs vest ratably over a three-year period and may generally 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 executive officers 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 awarded SARs to our executive officers in 2017 and 2016 . There were no SARs awarded to our executive officers in 2018 . 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 Expected term of award (in years) 6.0 years 6.0 years Risk-free interest rate 2.0 % 1.8 % Expected volatility 53.3 % 54.5 % Weighted-average grant date fair value per share $ 38.58 $ 26.96 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, 2018 2017 2016 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, 298,220 $ 47.39 6.5 $ 2,490 244,078 $ 41.36 $ 7,620 326,453 $ 38.99 $ 4,697 Awarded — — — — 54,142 74.57 — 58,709 51.63 — Exercised — — — — — — — (141,084 ) 40.16 2,770 Modified 63,969 42.83 — — — — — — — — Expired (71,931 ) 46.34 — — — — — — — — Outstanding at December 31, 290,258 46.64 4.6 125 298,220 47.39 2,490 244,078 41.36 7,620 Exercisable at December 31, 260,101 44.88 4.3 125 223,865 43.28 2,267 174,919 38.72 5,924 We expect all SARs outstanding as of December 31, 2018 to vest. The SARS modified during 2018 were related to one employee and the total compensation cost associated with the modification was not material to our consolidated statement of operations. Total compensation cost related to SARs granted and not yet recognized in our consolidated statements of operations as of December 31, 2018 was $0.5 million . The cost is expected to be recognized over a weighted-average period of 0.5 years . Restricted Stock Units 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 2018 : Shares Weighted-Average Non-vested at December 31, 2017 472,132 $ 60.23 Granted 446,743 50.69 Vested (249,317 ) 58.95 Forfeited (51,151 ) 56.45 Non-vested at December 31, 2018 618,407 54.16 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, 2018 2017 2016 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 12,282 $ 16,303 $ 18,973 Total intrinsic value of time-based awards non-vested 18,404 24,334 34,812 Market price per common share as of December 31, 29.76 51.54 72.58 Weighted-average grant date fair value per share 50.69 65.14 58.52 Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2018 was $20.7 million . This cost is expected to be recognized over a weighted-average period of 1.8 years. Performance Stock Units 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 shares 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 February 2018 , the Compensation Committee awarded a total of 90,778 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 over a three-year period ending on December 31, 2020, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between 0 percent and 200 percent of the target PSUs awarded. 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, 2018 2017 2016 Expected term of award (in years) 3 years 3 years 3 years Risk-free interest rate 2.4 % 1.4 % 1.2 % Expected volatility 42.3 % 51.4 % 52.3 % 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 2018 : Shares Weighted-Average Non-vested at December 31, 2017 52,349 $ 84.06 Granted 90,778 69.98 Vested (18,941 ) 72.54 Forfeited (21,272 ) 78.65 Non-vested at December 31, 2018 102,914 74.88 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, 2018 2017 2016 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ 620 $ 2,687 $ 6,562 Total intrinsic value of market-based awards non-vested 3,063 2,698 3,514 Market price per common share as of December 31, 29.76 51.54 72.58 Weighted-average grant date fair value per share 69.98 94.02 72.54 Total compensation cost related to non-vested market-based awards not yet recognized in our consolidated statements of operations as of December 31, 2018 was $4.7 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 settle 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, 2018 , we acquired 102,647 shares for payment of tax liabilities and reissued 104,068 shares. As of December 31, 2018 , 33,105 shares were available for reissuance pursuant to our 2010 Plan. During the year ended December 31, 2017 , we acquired 107,357 shares for payment of tax liabilities and reissued 83,228 shares. As of December 31, 2017 , 34,526 shares were available for reissuance pursuant to our 2010 Plan. In addition to the shares available for reissuance as of December 31, 2018 and 2017 , we had 12,115 shares and 21,401 shares, respectively, 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, 2018 , no preferred shares had been issued

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES The table below presents the components of our provision for income tax (expense) benefit for the years presented: Year Ended December 31, 2018 2017 2016 (in thousands) Current: Federal $ 886 $ 8,443 $ 9,646 State (188 ) (200 ) 300 Total current income tax benefit 698 8,243 9,946 Deferred: Federal (1,986 ) 193,809 118,427 State (4,118 ) 9,876 18,822 Total deferred income tax (expense) benefit (6,104 ) 203,685 137,249 Income tax (expense) benefit $ (5,406 ) $ 211,928 $ 147,195 The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes: Year Ended December 31, 2018 2017 2016 Federal statutory tax rate 21.0 % 35.0 % 35.0 % State income tax, net (6.4 ) 1.8 2.6 Federal tax credits (52.1 ) — — Effect of state income tax rate changes 6.7 — 0.6 Change in valuation allowance 45.5 — — Non-deductible compensation 21.8 (0.3 ) (0.5 ) Non-deductible government relations 31.8 — — Other non-deductible items 4.9 — — Federal tax reform rate reduction — 33.7 — Non-deductible goodwill impairment — (7.7 ) — Other (0.4 ) (0.1 ) (0.3 ) Effective tax rate 72.8 % 62.4 % 37.4 % Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2018 and 2017 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. As of December 31, 2018 2017 (in thousands) Deferred tax assets: Deferred compensation $ 9,963 $ 6,059 Asset retirement obligations 27,166 21,760 Federal NOL carryforward 54,736 19,386 State NOL and tax credit carryforwards, net 13,223 7,815 Federal tax - credit carryforwards 7,756 4,366 Net change in fair value of unsettled derivatives — 20,929 Prepaid revenue 5,288 — Other 4,647 2,453 Valuation allowance (3,380 ) — Total gross deferred tax assets 119,399 82,768 Deferred tax liabilities: Properties and equipment 270,565 267,498 Net change in fair value of unsettled derivatives 41,496 — Convertible debt 5,434 7,262 Total gross deferred tax liabilities 317,495 274,760 Net deferred tax liability $ 198,096 $ 191,992 During the year ending December 31, 2018 , we generated a federal net operating loss ("NOL") of $169.1 million and have prior year federal NOL carryforwards of $31.5 million that will begin to expire in 2036. 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. We have a marginal gas well credit of $5.1 million that can be carried forward 20 years and we have alternative minimum tax credits of $2.7 million that may be carried forward, and pursuant to the new tax law will be refunded over the next three years. As of December 31, 2018 , we have state NOL carryforwards of $284.6 million that begin to expire in 2030 and state credit carryforwards of $3.3 million that begin to expire in 2022 . Due to the potential non-utilization of our state tax credit carryforwards before their expiration, we have recorded a valuation allowance for the future tax benefit of these credit carryforwards. Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2018 . The statutes of limitations for most of our state tax jurisdictions are open for tax year 2014 forward. The IRS partially accepted our 2017 tax return. The 2017 tax return is in the IRS CAP Program post-filing review process, with no significant tax adjustments currently proposed. We are currently participating in the CAP Program for the review of our 2018 through 2019 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, 2018 , we were current with our income tax filings in all applicable state jurisdictions.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2018
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 our weighted-average basic and diluted shares outstanding: Year Ended December 31, 2018 2017 2016 (in thousands) Weighted-average common shares outstanding - basic 66,059 65,837 49,052 Dilutive effect of: RSUs and PSUs 173 — — Other equity-based awards 71 — — Weighted-average common shares and equivalents outstanding - diluted 66,303 65,837 49,052 For 2017 and 2016 , 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, 2018 2017 2016 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: RSUs and PSUs 145 590 689 Convertible notes — — 292 Other equity-based awards 109 75 109 Total anti-dilutive common share equivalents 254 665 1,090 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.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION Supplemental Cash Flow (Notes)	12 Months Ended
	Dec. 31, 2018
Supplemental Cash Flow Elements [Abstract]
Cash Flow, Supplemental Disclosures [Text Block]	SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Year Ended December 31, 2018 2017 2016 (in thousands) Supplemental cash flow information: Cash payments (receipts) for: Interest, net of capitalized interest $ 55,586 $ 69,880 $ 43,406 Income taxes (6,719 ) (13,925 ) 167 Non-cash investing activities: Issuance of common stock for acquisition of crude oil and natural gas properties — — 690,702 Change in accounts payable related to capital expenditures 36,328 50,761 (40,448 ) Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal 37,136 839 4,894 Purchase of properties and equipment under capital leases 1,940 3,497 1,404

SUBSIDIARY GUARANTOR SUBSIDIARY

SUBSIDIARY GUARANTOR SUBSIDIARY GUARANTOR (Notes)	12 Months Ended
	Dec. 31, 2018
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 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, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets: Cash and cash equivalents $ 1,398 $ — $ — $ 1,398 Accounts receivable, net 146,529 34,905 — 181,434 Fair value of derivatives 84,492 — — 84,492 Prepaid expenses and other current assets 6,725 411 — 7,136 Total current assets 239,144 35,316 — 274,460 Properties and equipment, net 2,270,711 1,732,151 — 4,002,862 Assets held-for-sale — 140,705 — 140,705 Intercompany receivable 451,601 — (451,601 ) — Investment in subsidiaries 1,316,945 — (1,316,945 ) — Fair value of derivatives 93,722 — — 93,722 Other assets 30,084 2,312 — 32,396 Total Assets $ 4,402,207 $ 1,910,484 $ (1,768,546 ) $ 4,544,145 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 110,847 $ 71,017 $ — $ 181,864 Production tax liability 53,309 7,410 — 60,719 Fair value of derivatives 3,364 — — 3,364 Funds held for distribution 90,183 15,601 — 105,784 Accrued interest payable 14,143 7 — 14,150 Other accrued expenses 73,689 1,444 — 75,133 Total current liabilities 345,535 95,479 — 441,014 Intercompany payable — 451,601 (451,601 ) — Long-term debt 1,194,876 — — 1,194,876 Deferred income taxes 162,368 35,728 — 198,096 Asset retirement obligations 79,904 5,408 — 85,312 Liabilities held-for-sale — 4,111 — 4,111 Fair value of derivatives 1,364 — — 1,364 Other liabilities 91,452 1,212 — 92,664 Total liabilities 1,875,499 593,539 (451,601 ) 2,017,437 Stockholders' equity Common shares 661 — — 661 Additional paid-in capital 2,519,423 1,766,775 (1,766,775 ) 2,519,423 Retained earnings 8,727 (449,830 ) 449,830 8,727 Treasury shares (2,103 ) — — (2,103 ) Total stockholders' equity 2,526,708 1,316,945 (1,316,945 ) 2,526,708 Total Liabilities and Stockholders' Equity $ 4,402,207 $ 1,910,484 $ (1,768,546 ) $ 4,544,145 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 40,583 — — 40,583 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 $ 4,206,047 $ 2,082,159 $ (1,867,816 ) $ 4,420,390 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 Liabilities held-for-sale 499 — — 499 Fair value of derivatives 22,343 — — 22,343 Other liabilities 57,009 324 — 57,333 Total liabilities 1,698,398 464,622 (250,279 ) 1,912,741 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 $ 4,206,047 $ 2,082,159 $ (1,867,816 ) $ 4,420,390 Consolidating Statements of Operations Year Ended December 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 1,050,696 $ 339,265 $ — $ 1,389,961 Commodity price risk management gain, net 145,237 — — 145,237 Other income 10,744 2,717 — 13,461 Total revenues 1,206,677 341,982 — 1,548,659 Costs, expenses and other Lease operating expenses 92,228 38,729 — 130,957 Production taxes 67,819 22,538 — 90,357 Transportation, gathering and processing expenses 16,607 20,796 — 37,403 Exploration, geologic and geophysical expense 1,234 4,970 — 6,204 Impairment of properties and equipment 27 458,370 — 458,397 General and administrative expense 152,798 17,706 — 170,504 Depreciation, depletion and amortization 389,841 169,952 — 559,793 Accretion of asset retirement obligations 4,617 458 — 5,075 (Gain) loss on sale of properties and equipment (4,387 ) 4,781 — 394 Other expenses 11,829 — — 11,829 Total costs, expenses and other 732,613 738,300 — 1,470,913 Income (loss) from operations 474,064 (396,318 ) — 77,746 Interest expense (73,251 ) 2,521 — (70,730 ) Interest income 413 — — 413 Income (loss) before income taxes 401,226 (393,797 ) — 7,429 Income tax (expense) benefit (98,611 ) 93,205 — (5,406 ) Equity in loss of subsidiary (300,592 ) — 300,592 — Net income (loss) $ 2,023 $ (300,592 ) $ 300,592 $ 2,023 Net loss for the Guarantor for the year ended 2018 is primarily the result of impairment of certain unproved Delaware Basin leasehold positions. 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 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 Accretion of asset retirement obligations 5,965 341 — 6,306 Gain on sale of properties and equipment (766 ) — — (766 ) Provision for uncollectible notes receivable (40,203 ) — — (40,203 ) 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 loss for the Guarantor for the year ended 2017 is 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 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 Accretion of asset retirement obligations 7,070 10 — 7,080 Gain on sale of properties and equipment (43 ) — — (43 ) Provision for uncollectible notes receivable 44,038 — — 44,038 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 ) Consolidating Statements of Cash Flows Year Ended December 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 625,206 $ 264,096 $ — $ 889,302 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (482,534 ) (463,816 ) — (946,350 ) Capital expenditures for other properties and equipment (9,806 ) (1,249 ) — (11,055 ) Acquisition of crude oil and natural gas properties (179,955 ) (71 ) — (180,026 ) Proceeds from sale of properties and equipment 1,929 1,633 — 3,562 Proceeds from divestiture 44,693 — — 44,693 Restricted cash 1,249 — — 1,249 Intercompany transfers (199,584 ) — 199,584 — Net cash from investing activities (824,008 ) (463,503 ) 199,584 (1,087,927 ) Cash flows from financing activities: Proceeds from revolving credit facility 1,072,500 — — 1,072,500 Repayment of revolving credit facility (1,040,000 ) — — (1,040,000 ) Payment of debt issuance costs (7,704 ) — — (7,704 ) Purchase of treasury stock (5,147 ) — — (5,147 ) Other (1,373 ) (177 ) — (1,550 ) Intercompany transfers — 199,584 (199,584 ) — Net cash from financing activities 18,276 199,407 (199,584 ) 18,099 Net change in cash and cash equivalents (180,526 ) — — (180,526 ) Cash and cash equivalents, beginning of period 189,925 — — 189,925 Cash and cash equivalents, end of period $ 9,399 $ — $ — $ 9,399 Consolidating Statements of Cash Flows Year Ended December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 546,954 $ 50,859 $ — $ 597,813 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas 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 (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 ) Sales of short-term investments 49,890 — — 49,890 Purchases 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 ) Payment of debt issuance costs (50 ) — — (50 ) Purchase of treasury stock (6,672 ) — — (6,672 ) 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 (50,562 ) (3,613 ) — (54,175 ) Cash and cash equivalents, beginning of period 240,487 3,613 — 244,100 Cash and cash equivalents, end of period $ 189,925 $ — $ — $ 189,925 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 gas 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 (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 revolving credit facility 85,000 — — 85,000 Repayment of revolving credit facility (122,000 ) — — (122,000 ) 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 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 closed in December 2016.

SUPPLEMENTAL INFORMATION - NATU

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES	12 Months Ended
	Dec. 31, 2018
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 NGLs reserves. As of December 31, 2018 , 2017 and 2016 (as applicable), 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 that they be scheduled 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) (2) Natural Gas (per Mcf) (2) NGLs (per Bbl) (3) 2018 $ 65.56 $ 3.10 $ 65.56 2017 51.34 2.98 51.34 2016 42.75 2.48 42.75 The netted back price used to estimate our reserves, by commodity, are presented below. Price Used to Estimate Reserves (4) As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) 2018 $ 61.14 $ 2.15 $ 23.04 2017 48.68 2.31 20.21 2016 38.67 1.85 11.97 ___________ (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) Our benchmark prices for crude oil and natural gas are WTI and Henry Hub, respectively. (3) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. (4) These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and 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, 2016 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 Revisions of previous estimates 26,548 94,738 12,674 55,011 Extensions, discoveries and other additions 8,786 61,750 8,868 27,946 Acquisition of reserves 19,644 148,674 15,936 60,360 Dispositions (2,507 ) (35,750 ) (2,656 ) (11,121 ) Production (16,964 ) (88,017 ) (8,527 ) (40,160 ) Proved reserves, December 31, 2018 190,349 1,335,689 131,987 544,953 Proved Developed Reserves, as of: December 31, 2016 30,013 264,452 24,196 98,284 December 31, 2017 46,862 365,332 35,220 142,971 December 31, 2018 61,821 443,151 43,856 179,535 Proved Undeveloped Reserves, as of: December 31, 2016 88,156 569,245 60,092 243,122 December 31, 2017 107,980 788,962 70,472 309,946 December 31, 2018 128,528 892,538 88,131 365,418 Developed Undeveloped Total (MBoe) Proved reserves, January 1, 2016 70,496 202,329 272,825 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 ) Undeveloped reserves converted to developed 32,192 (32,192 ) — Proved reserves, December 31, 2016 98,285 243,122 341,407 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 ) Undeveloped reserves converted to developed 54,648 (54,648 ) — Proved reserves, December 31, 2017 142,971 309,946 452,917 Revisions of previous estimates 6,284 48,727 55,011 Extensions, discoveries and other additions 7,874 20,072 27,946 Acquisition of reserves 8,758 51,602 60,360 Dispositions (4,486 ) (6,635 ) (11,121 ) Production (40,160 ) — (40,160 ) Undeveloped reserves converted to developed 58,294 (58,294 ) — Proved reserves, December 31, 2018 179,535 365,418 544,953 2018 Activity. During 2018, we increased proved reserves by 92.0 MMBoe, or 20 percent , relative to December 31, 2017. The increase in proved reserves was primarily a result of acreage exchange transactions and acquisitions in the Wattenberg Field and reserve additions on proved acreage resulting from our 2018 development activities. In 2018, we produced 40.2 MMboe. Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 11.4 MMBoe due to an increase in prices for crude oil, natural gas and NGLs, offset by net negative revisions of 5.1 MMBoe for an increase in operating costs, performance revisions and other items. Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 71.7 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 26.8 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2018 acreage exchanges, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and type curve revisions, which resulted in further upward revisions of 3.8 MMBoe of PUD reserves. Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed activity for 2018 included the addition 7.9 MMBoe of developed reserves related to 17 gross ( 9.2 net) newly-drilled wells. Extensions, Discoveries and Other Additions-PUDs. PUD activity was comprised primarily of 20.1 MMBoe of PUD reserves related to 16 gross ( 15.0 net) PUD locations in the Delaware Basin. Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps and an acquisition were 8.8 MMBoe during 2018. Acquisitions of Reserves-PUDs. We acquired 47.6 MMBoe and 4.0 MMBoe of PUD reserves in 2018 in acreage swaps and an acquisition, respectively. Dispositions-Proved Developed Reserves . Dispositions of 4.5 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps. Dispositions-PUDs. Dispositions of 6.6 MMBoe reflect that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2017 in the acreage swap transactions. At December 31, 2017, we projected a PUD reserve conversion rate of 16 percent for 2018. During 2018, a larger number of wells were turned-in-line than we anticipated, resulting in an actual conversion rate of 19 percent . We converted 58.3 MMBoe of PUD reserves at December 31, 2017 to proved developed reserves as of December 31, 2018. Based on economic conditions on December 31, 2018, 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, 2018, our 2019 PUD reserve conversion rate is expected to be approximately 16 percent . 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. 2017 Activity. During 2017, we increased proved reserves by 111.5 MMBoe, or 33 percent , relative to December 31, 2016. The increase in proved reserves was primarily a result of an increase in acquisitions and reserve additions on proved acreage in the Delaware Basin from our 2017 development plan. In 2017, we produced 31.8 MMboe. Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 17.7 MMBoe due to an increase in prices for crude oil, natural gas and NGLs and net positive revisions of 0.6 MMBoe reflecting changes in operating costs, performance revisions and other items. Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 89.8 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 58.5 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2017 acreage swaps, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and other, which resulted in further upward revisions of 2.9 MMBoe of PUD reserves. Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2017 included the addition of 2.3 MMBoe of developed reserves related to newly-drilled wells. Extensions, Discoveries and Other Additions-PUDs. PUD activity was comprised primarily of 3.7 MMBoe of PUD reserves related to PUD locations in the Delaware Basin. Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps were 1.3 MMBoe during 2017. Acquisitions of Reserves-PUDs. We acquired 85.5 MMBoe of PUD reserves in 2017 in acreage swaps. Dispositions-Proved Developed Reserves . Dispositions were related to acreage surrendered in various acreage swaps. Dispositions-PUDs. Dispositions of PUDs were 1.9 MMBoe, reflecting the fact that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2016 in the acreage swap transactions. 2016 Activity. During 2016, we increased proved reserves by 68.6 MMBoe, or 25 percent , 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. Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 2.6 MMBoe due to a decrease in operating costs and a net positive revision of 3.5 MMBoe for performance revisions and other items. These net positive revisions were partially offset by a decrease in prices for crude oil, natural gas and NGLs. Revisions of Previous Estimates-PUDs. Downward revisions to our PUD reserves were related to a decrease of 61.0 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2016 acreage swaps, resulted in these locations being reclassified from proved to unproved status. Partially offsetting this decrease was a positive revision of 10.8 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. All other changes were due to commodity pricing, lease operating expenses and other, which resulted in further downward revisions of 1.5 MMBoe of PUD reserves. Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2016 included the addition 1.5 MMBoe of developed reserves related to newly-drilled wells. Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps and an acquisition were 10.2 MMBoe during 2016. Acquisitions of Reserves-PUDs. We acquired 98.1 MMBoe and 25.3 MMBoe of PUD reserves in 2016 in acreage swaps and an acquisition, respectively. Dispositions-Proved Developed Reserves . Dispositions of 0.1 MMBoe were related to acreage surrendered in various acreage swaps. Dispositions-PUDs. Dispositions of PUDs were 1.6 MMBoe, reflecting the fact that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2015 in the acreage swap transactions. 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. Year Ended December 31, 2018 2017 2016 (in thousands) Revenue: Crude oil, natural gas and NGLs sales $ 1,389,961 $ 913,084 $ 497,353 Commodity price risk management gain (loss), net 145,237 (3,936 ) (125,681 ) 1,535,198 909,148 371,672 Expenses: Lease operating expenses 130,957 89,641 59,950 Production taxes 90,357 60,717 31,410 Transportation, gathering and processing expenses 37,403 33,220 18,415 Exploration expense 6,204 47,334 4,669 Impairment of properties and equipment 458,397 285,887 9,973 Depreciation, depletion and amortization 551,265 462,482 413,105 Accretion of asset retirement obligations 5,075 6,306 7,080 (Gain) loss on sale of properties and equipment 394 (766 ) (43 ) 1,280,052 984,821 544,559 Results of operations for crude oil and natural gas producing 255,146 (75,673 ) (172,887 ) Income tax (expense) benefit (185,667 ) 47,247 64,733 Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs $ 69,479 $ (28,426 ) $ (108,154 ) 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, 2018 2017 2016 (in thousands) Acquisition of properties: (1) Proved properties $ 205,253 $ 172 $ 268,567 Unproved properties 5,477 18,914 1,843,985 Development costs (2) 970,970 688,165 383,336 Exploration costs: (3) Exploratory drilling 36,704 80,103 — Geological and geophysical 3,401 3,881 4,669 Total costs incurred (4) $ 1,221,805 $ 791,235 $ 2,500,557 __________ (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, 2018 , 2017 and 2016 , $438.4 million , $463.4 million and $204.6 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $74.6 million and $32.8 million of infrastructure and pipeline costs in 2018 and 2017 , respectively. (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 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, 2018 2017 (in thousands) Proved crude oil and natural gas properties $ 5,452,613 $ 4,356,922 Unproved crude oil and natural gas properties 492,594 1,097,317 Uncompleted wells, equipment and facilities 332,264 265,526 Capitalized costs 6,277,471 5,719,765 Less accumulated DD&A (2,341,897 ) (1,803,847 ) Capitalized costs, net $ 3,935,574 $ 3,915,918 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, 2018 2017 2016 (in thousands) Future estimated cash flows $ 17,554,880 $ 12,340,407 $ 7,122,525 Future estimated production costs* (4,782,948 ) (3,245,627 ) (1,624,167 ) Future estimated development costs (3,632,822 ) (2,893,335 ) (2,219,914 ) Future estimated income tax expense (1,404,121 ) (748,494 ) (597,476 ) Future net cash flows 7,734,989 5,452,951 2,680,968 10% annual discount for estimated timing of cash flows (3,287,273 ) (2,572,846 ) (1,260,339 ) Standardized measure of discounted future estimated net cash flows $ 4,447,716 $ 2,880,105 $ 1,420,629 ___________ * Represents future estimated lease operating expenses, production taxes and 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, 2018 2017 2016 (in thousands) Beginning of period $ 2,880,105 $ 1,420,629 $ 1,096,864 Sales of crude oil, natural gas and NGLs production, net of production costs (1,131,244 ) (729,506 ) (387,576 ) Net changes in prices and production costs (1) 936,077 841,713 (205,760 ) Extensions, discoveries and improved recovery, less related costs 190,084 47,240 15,128 Sales of reserves (42,362 ) (2,613 ) (3,745 ) Purchases of reserves 467,807 224,483 487,636 Development costs incurred during the period 462,088 419,047 268,672 Revisions of previous quantity estimates 631,198 484,431 (320,286 ) Changes in estimated income taxes (232,002 ) (138,560 ) (13,630 ) Net changes in future development costs (123,663 ) 25,183 391,145 Accretion of discount 583,744 167,487 133,747 Timing and other (174,116 ) 120,571 (41,566 ) End of period $ 4,447,716 $ 2,880,105 $ 1,420,629 __________ (1) Our weighted-average price, net of production costs per Boe, in our 2018 reserve report increased to $23.44 as compared to $20.08 for 2017 and $15.73 for 2016 . 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, 2018
Quarterly Financial Data [Abstract]
Quarterly Financial Information [Text Block]	QUARTERLY FINANCIAL INFORMATION - UNAUDITED Quarterly financial data for the years ended December 31, 2018 and 2017 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. 2018 Quarter Ended March 31 (1) June 30 September 30 (1) December 31 (1) (in thousands, except per share data) Total revenues $ 260,600 $ 212,531 $ 280,717 $ 794,811 Total costs, expenses and other 260,924 400,770 270,593 538,626 Income (loss) from operations (324 ) (188,239 ) 10,124 256,185 Income (loss) before income taxes (17,705 ) (205,580 ) (7,310 ) 238,024 Net income (loss) $ (13,139 ) $ (160,257 ) $ (3,434 ) $ 178,853 Earnings per share: Basic $ (0.20 ) $ (2.43 ) $ (0.05 ) $ 2.71 Diluted (0.20 ) (2.43 ) (0.05 ) 2.71 2017 Quarter Ended March 31 June 30 September 30 (1) December 31 (2) (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) $ 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) Impairment charges, which are included in total costs, expenses and other above, reflect the correction of two errors in the timing of the reporting of certain impairments. In 2018, we corrected an error in our calculation of unproved properties and goodwill originally recorded in 2017, resulting in an additional impairment charge of $6.3 million being recorded during the three months ended March 31, 2018. Further, during the fourth quarter of 2018, we corrected for an additional $8.4 million impairment of unproved properties relating to the three months ended September 30, 2018. See the footnote titled Properties and Equipment to our consolidated financial statements included elsewhere in this report. (2) 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.

SCHEDULE II - VALUATION AND QUA

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Notes)	12 Months Ended
	Dec. 31, 2018
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
SEC Schedule, 12-09, Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]	Schedule II -VALUATION AND QUALIFYING ACCOUNTS Description Beginning Charged to Deductions (1) Ending (in thousands) 2018: Allowance for doubtful accounts $ 3,128 $ 1,276 $ 23 $ 4,381 Allowance for expirations of unproved crude oil and natural gas properties 251,159 388,068 96,518 542,709 2017: Allowance for uncollectible notes $ 44,038 $ — $ 44,038 $ — Allowance for doubtful accounts 2,190 1,108 170 3,128 Allowance for expirations of unproved crude oil and natural gas properties 359 263,817 13,017 251,159 2016: Allowance for uncollectible notes $ — $ 44,038 $ — $ 44,038 Allowance for doubtful accounts 2,009 1,309 1,128 2,190 Allowance for expirations of unproved crude oil and natural gas properties 144 215 — 359 ____________ (1) For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. 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 actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
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. 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 have elected the normal purchase, normal sale exception for our crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assets and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of 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 two unit-of-production fields: the Wattenberg Field and the Delaware Basin. 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 for 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 an insignificant portion of a field, the proceeds are credited to accumulated DD&A. Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leaseholds 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 resulting accounting treatment is recorded
Property, Plant and Equipment, Policy [Policy Text Block]	Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities 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 carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values 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. 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, the proceeds are applied and any resulting gain or loss is reflected in income
Proved and Unproved Property, Impairment [Policy Text Block]	Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. 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, Estimated Useful Lives [Policy Text Block]	Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years . We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value 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.
Internal Use Software, Policy [Policy Text Block]	Certain internal-use software costs incurred during the development stage are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expenses as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project.
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, 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 once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year.
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 rate 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.
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 we have transferred control of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2018 , 2017 and 2016 , the impact of any natural gas imbalances was not significant. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas, or NGLs has been transferred to the purchasers of these commodities that are providing 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 index 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 control of the crude oil, natural gas, or NGLs is not transferred to the purchaser and the purchaser does 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.
Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block]	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.
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. If applicable, 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 and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, 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
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Issued Accounting Standards In February 2016, the FASB issued an accounting update and subsequent amendments 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 (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the ROU asset and corresponding liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. We will make accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset, as provided by practical expedients. In January 2018, the FASB also issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that if elected, would not require an organization to reconsider accounting for existing land easements that are not accounted for under the previous lease accounting standard. We will elect this practical expedient and accordingly, existing land easements will not be assessed. All new or modified land easements entered into after January 1, 2019 will be evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We will adopt the New Lease standard and subsequent amendments effective January 1, 2019 under the modified retrospective approach for all active contracts as of December 31, 2018 . Based upon our implementation progress to date, we expect the adoption of the New Lease Standard to result in increases to total assets and total liabilities of approximately $20.0 million at January 1, 2019, with no adjustment to the opening balance of retained earnings.
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.
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 and exchanged businesses and assets; estimates of fair value of our fixed rate debt instruments; and valuation of deferred income tax assets
Asset Exchange [Policy Text Block]	Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement .
New Accounting Pronouncement, Early Adoption [Table Text Block]	Recently Adopted Accounting Standards. In May 2014, the Financial Accounting Standards Board ("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 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. We adopted the standard effective January 1, 2018 under the modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard had on our consolidated financial statements, we 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 also reviewed our current accounting policies, procedures and controls with respect to these contracts and arrangements to determine what changes, if any, would be required by the adoption of the revenue standard. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. See the footnote below titled Revenue Recognition for further details regarding the changes in our revenue recognition resulting from the adoption of this standard. 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 the 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. Adoption of this standard impacted our consolidated statements of cash flows. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the consolidated balance sheets at December 31, 2018 and 2017 , which sum to the total of cash, cash equivalents and restricted cash in the consolidated statements of cash flows: December 31, 2018 December 31, 2017 (in thousands) Cash and cash equivalents $ 1,398 $ 180,675 Restricted cash 8,001 9,250 Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 9,399 $ 189,925 Restricted cash is included in other assets on the consolidated balance sheets at December 31, 2018 and December 31, 2017 . We did not have any cash classified as restricted cash at December 31, 2016 . In August 2018, the FASB issued an accounting update to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. 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 third quarter of 2018. As of December 31, 2018 , capitalized costs for internal-use software were not material. In November 2018, the FASB issued an accounting update and amendments to clarify the interaction between collaborative contractual arrangements and the revenue recognition standard. The amendments in this update specify that transactions between participants in a collaborative arrangement should be accounted for under the revenue recognition standard when the counterparty is a customer and the guidance precludes entities from presenting consideration from a transaction in a collaborative arrangement as revenue from contracts with customers if the counterparty is not a customer for that transaction. The guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal periods, with early adoption permitted. We have elected to early adopt this standard in the fourth quarter of 2018. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary as adoption of this standard did not have an impact on our consolidated financial statements.
Goodwill Disclosure [Text Block]	GOODWILL Goodwill that resulted from the purchase price allocation of a business combination in the Delaware Basin in December 2016 was determined to be $ 75.1 million . In 2017, 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 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 2017.
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. 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 have elected the normal purchase, normal sale exception for our crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assets and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of 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 two unit-of-production fields: the Wattenberg Field and the Delaware Basin. 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 for 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 an insignificant portion of a field, the proceeds are credited to accumulated DD&A. Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leaseholds 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 resulting accounting treatment is recorded. Proved Property Impairment. Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities 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 carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values 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. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. 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 such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years . We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value 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. 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, the proceeds are applied and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $8.5 million , $6.6 million and $3.8 million in 2018 , 2017 and 2016 , respectively. Internal-Use Software. Certain internal-use software costs incurred during the development stage are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expenses as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2018 , capitalized costs for internal-use software were not material. We did not have any capitalized internal-use software costs at December 31, 2017 . 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 $9.2 million , $5.0 million and $4.5 million in 2018 , 2017 and 2016 , respectively. 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, 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 once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. 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 $61.3 million and $50.5 million in December 31, 2018 and 2017 , 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 rate 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. 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. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2018 , 2017 and 2016 , the impact of any natural gas imbalances was not significant. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas, or NGLs has been transferred to the purchasers of these commodities that are providing 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 index 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 control of the crude oil, natural gas, or NGLs is not transferred to the purchaser and the purchaser does 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. 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. 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. If applicable, 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. Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . 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 and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, 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. Recently Adopted Accounting Standards. In May 2014, the Financial Accounting Standards Board ("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 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. We adopted the standard effective January 1, 2018 under the modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard had on our consolidated financial statements, we 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 also reviewed our current accounting policies, procedures and controls with respect to these contracts and arrangements to determine what changes, if any, would be required by the adoption of the revenue standard. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. See the footnote below titled Revenue Recognition for further details regarding the changes in our revenue recognition resulting from the adoption of this standard. 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 the 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. Adoption of this standard impacted our consolidated statements of cash flows. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the consolidated balance sheets at December 31, 2018 and 2017 , which sum to the total of cash, cash equivalents and restricted cash in the consolidated statements of cash flows: December 31, 2018 December 31, 2017 (in thousands) Cash and cash equivalents $ 1,398 $ 180,675 Restricted cash 8,001 9,250 Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 9,399 $ 189,925 Restricted cash is included in other assets on the consolidated balance sheets at December 31, 2018 and December 31, 2017 . We did not have any cash classified as restricted cash at December 31, 2016 . In August 2018, the FASB issued an accounting update to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. 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 third quarter of 2018. As of December 31, 2018 , capitalized costs for internal-use software were not material. In November 2018, the FASB issued an accounting update and amendments to clarify the interaction between collaborative contractual arrangements and the revenue recognition standard. The amendments in this update specify that transactions between participants in a collaborative arrangement should be accounted for under the revenue recognition standard when the counterparty is a customer and the guidance precludes entities from presenting consideration from a transaction in a collaborative arrangement as revenue from contracts with customers if the counterparty is not a customer for that transaction. The guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal periods, with early adoption permitted. We have elected to early adopt this standard in the fourth quarter of 2018. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary as adoption of this standard did not have an impact on our consolidated financial statements. Recently Issued Accounting Standards In February 2016, the FASB issued an accounting update and subsequent amendments 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 (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the ROU asset and corresponding liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. We will make accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset, as provided by practical expedients. In January 2018, the FASB also issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that if elected, would not require an organization to reconsider accounting for existing land easements that are not accounted for under the previous lease accounting standard. We will elect this practical expedient and accordingly, existing land easements will not be assessed. All new or modified land easements entered into after January 1, 2019 will be evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We will adopt the New Lease standard and subsequent amendments effective January 1, 2019 under the modified retrospective approach for all active contracts as of December 31, 2018 . Based upon our implementation progress to date, we expect the adoption of the New Lease Standard to result in increases to total assets and total liabilities of approximately $20.0 million at January 1, 2019, with no adjustment to the opening balance of retained earnings.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Restrictions on Cash and Cash Equivalents [Table Text Block]	December 31, 2018 December 31, 2017 (in thousands) Cash and cash equivalents $ 1,398 $ 180,675 Restricted cash 8,001 9,250 Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 9,399 $ 189,925

BUSINESS COMBINATIONS BUSINES_2

BUSINESS COMBINATIONS BUSINESS COMBINATIONS (Tables)	12 Months Ended
	Dec. 31, 2018
Business Acquisition [Line Items]
Business Combination, Segment Allocation [Table Text Block]	The details of the final purchase price and allocation of the purchase price for the transaction, are presented below (in thousands): December 31, 2018 Acquisition costs: Cash $ 168,560 Deposit made in prior period 21,000 Total cash consideration 189,560 Other purchase price adjustments 10,422 Total acquisition costs $ 199,982 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current assets $ 468 Crude oil and natural gas properties - proved 205,834 Other assets 2,796 Total assets acquired 209,098 Liabilities assumed: Current liabilities (4,429 ) Asset retirement obligations (4,687 ) Total liabilities assumed (9,116 ) Total identifiable net assets acquired $ 199,982

Revenue Recognition Revenue R_2

Revenue Recognition Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	REVENUE RECOGNITION On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $11.3 million in 2017 with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for 2018 , we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the New Revenue Standard to have a significant impact on our net income going forward. Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the New Revenue Standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. As discussed above, we enter into agreements for the sale, transportation, gathering and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based upon first-of-the-month index prices, as in each case this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2018 , 2017 and 2016 (in thousands): Year Ended December 31, Revenue by Commodity and Operating Region 2018 2017 (1) 2016 (1) Crude oil Wattenberg Field $ 783,158 $ 529,562 $ 329,168 Delaware Basin 252,107 82,677 3,918 Utica Shale (2) 2,696 12,814 15,769 Total $ 1,037,961 $ 625,053 $ 348,855 Natural gas Wattenberg Field $ 130,073 $ 131,792 $ 86,633 Delaware Basin 32,010 21,251 1,039 Utica Shale (2) 1,109 5,216 3,904 Total $ 163,192 $ 158,259 $ 91,576 NGLs Wattenberg Field $ 132,820 $ 104,298 $ 52,919 Delaware Basin 55,148 20,756 645 Utica Shale (2) 840 4,718 3,358 Total $ 188,808 $ 129,772 $ 56,922 Revenue by Operating Region Wattenberg Field $ 1,046,051 $ 765,652 $ 468,720 Delaware Basin 339,265 124,684 5,602 Utica Shale (2) 4,645 22,748 23,031 Total $ 1,389,961 $ 913,084 $ 497,353 ________________________________________ (1) As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017 and 2016 have not been restated. Such changes would not have been material. (2) In March 2018, we completed the disposition of our Utica Shale properties. Contract Assets. Contract assets include material contributions in aid of construction, which are common in purchase and processing agreements with midstream service providers that are our customers. Generally, the intent of the payments is to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are classified as long-term assets and included in other assets on our consolidated balance sheet. The contract assets will be amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer. The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for year ended December 31, 2018 : Amount (in thousands) Beginning balance, January 1, 2018 $ 3,746 Additions 2,884 Amortized as a reduction to crude oil, natural gas and NGLs sales (3,096 ) Ending balance, December 31, 2018 $ 3,534 Customer Accounts Receivable. Our accounts receivable include amounts billed and currently due from sales of our crude oil, natural gas and NGLs production. Our gross accounts receivable balance from crude oil, natural gas and NGLs sales at December 31, 2018 and 2017 was $155.8 million and $154.3 million , respectively. We did not record an allowance for doubtful accounts for these receivables at December 31, 2018 or 2017. Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2018 , 2017 and 2016 (in thousands): Year Ended December 31, Revenue by Commodity and Operating Region 2018 2017 (1) 2016 (1) Crude oil Wattenberg Field $ 783,158 $ 529,562 $ 329,168 Delaware Basin 252,107 82,677 3,918 Utica Shale (2) 2,696 12,814 15,769 Total $ 1,037,961 $ 625,053 $ 348,855 Natural gas Wattenberg Field $ 130,073 $ 131,792 $ 86,633 Delaware Basin 32,010 21,251 1,039 Utica Shale (2) 1,109 5,216 3,904 Total $ 163,192 $ 158,259 $ 91,576 NGLs Wattenberg Field $ 132,820 $ 104,298 $ 52,919 Delaware Basin 55,148 20,756 645 Utica Shale (2) 840 4,718 3,358 Total $ 188,808 $ 129,772 $ 56,922 Revenue by Operating Region Wattenberg Field $ 1,046,051 $ 765,652 $ 468,720 Delaware Basin 339,265 124,684 5,602 Utica Shale (2) 4,645 22,748 23,031 Total $ 1,389,961 $ 913,084 $ 497,353 ________________________________________ (1) As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017 and 2016 have not been restated. Such changes would not have been material. (2) In March 2018, we completed the disposition of our Utica Shale properties.
Capitalized Contract Cost [Table Text Block]	The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for year ended December 31, 2018 : Amount (in thousands) Beginning balance, January 1, 2018 $ 3,746 Additions 2,884 Amortized as a reduction to crude oil, natural gas and NGLs sales (3,096 ) Ending balance, December 31, 2018 $ 3,534

FAIR VALUE MEASUREMENTS AND D_2

FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 Significant Other Significant Total Significant Other Significant Total (in thousands) Total assets $ 118,521 $ 59,693 $ 178,214 $ 12,949 $ 1,389 $ 14,338 Total liabilities (3,364 ) (1,364 ) (4,728 ) (90,569 ) (11,076 ) (101,645 ) Net asset (liability) $ 115,157 $ 58,329 $ 173,486 $ (77,620 ) $ (9,687 ) $ (87,307 )
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: Year Ended December 31, 2018 2017 2016 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ (9,687 ) $ (9,574 ) $ 91,288 Changes in fair value included in consolidated statements of operations line item: Commodity price risk management gain (loss), net 63,257 6,241 (28,550 ) Settlements included in consolidated statements of operations line items: Commodity price risk management ( loss) , net 4,759 (6,354 ) (72,312 ) Fair value of Level 3 instruments, net asset (liability) end of period $ 58,329 $ (9,687 ) $ (9,574 ) 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 ) Total $ — $ (866 ) $ (12,905 )
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, 2018 and 2017: As of December 31, 2018 2017 Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par (in millions) Senior notes: 2021 Convertible Notes $ 175.4 87.7 % $ 195.6 97.8 % 2024 Senior Notes 370.2 92.5 % 416.0 104.0 % 2026 Senior Notes 532.4 88.7 % 616.5 102.8 %

CONCENTRATION OF RISK Accounts

CONCENTRATION OF RISK Accounts Receivable, net of Allowance for Doubtful Accounts (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (in thousands) Employee benefits $ 25,811 $ 22,383 Asset retirement obligations 25,598 15,801 Environmental expenses 3,038 1,374 Other 20,686 3,429 Other accrued expenses $ 75,133 $ 42,987 Other Liabilities. The following table presents the components of other liabilities as of: As of December 31, 2018 2017 (in thousands) Production taxes $ 61,310 $ 50,476 Deferred oil gathering credit 22,710 — Other 8,644 6,857 Other liabilities $ 92,664 $ 57,333 Deferred Oil Gathering Credit. In January 2018, we received a payment of $24.1 million from a midstream service provider 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 crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The payment will be amortized using the straight-line method over the life of the amendment. Amortization charges totaling approximately $1.4 million for 2018 related to the deferred oil gathering credit are included as a reduction to transportation, gathering and processing expenses in our consolidated statements of operations.
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, 2018 2017 (in thousands) Crude oil, natural gas and NGLs sales $ 155,756 $ 154,260 Joint interest billings 19,580 34,576 Derivative counterparties 3,937 (18 ) Income tax receivable — 6,015 Other 6,542 5,893 Allowance for doubtful accounts (4,381 ) (3,128 ) Accounts receivable, net $ 181,434 $ 197,598
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 2018 2017 2016 DCP Midstream, LP 12.5 % 19.6 % 20.2 % Suncor Energy Marketing, Inc. — % 16.4 % 22.3 % Aka Energy Group, LLC — % — % 13.4 % Concord Energy, LLC — % — % 13.4 % Bridger Energy, LLC — % — % 11.5 %

DERIVATIVE FINANCIAL INSTRUME_2

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	As of December 31, 2018 , we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. Collars Fixed-Price Swaps Commodity/ Index/ Maturity Period Quantity (Crude oil - MBls Natural Gas - BBtu) Weighted-Average Contract Price Quantity (Crude Oil - MBbls Gas and Basis- BBtu) Weighted- Average Contract Price Fair Value December 31, 2018 (1) (in thousands) Floors Ceilings Crude Oil NYMEX 2019 2,600 $ 56.54 $ 68.13 8,400 $ 53.86 $ 82,305 2020 3,600 55.00 71.68 5,000 62.07 92,359 Total Crude Oil 6,200 13,400 $ 174,664 Natural Gas NYMEX 2019 — — — 26,008 2.91 1,408 Dominion South 2019 — — — 372 3.13 30 Columbia 2019 — — — 3 2.40 — Total Natural Gas — 26,383 $ 1,438 Basis Protection - Natural Gas CIG 2019 — — — 25,924 (0.78 ) (2,616 ) Total Basis Protection - Natural Gas — 25,924 $ (2,616 ) Commodity Derivatives Fair Value $ 173,486 (1) Approximately 33.5 percent of the fair value of our commodity derivative assets and 28.9 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).
Derivatives Not Designated as Hedging Instruments [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, 2018 and 2017 : Derivative instruments: Consolidated balance sheet line item 2018 2017 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 84,492 $ 7,340 Basis protection derivative contracts Fair value of derivatives — 6,998 84,492 14,338 Non-current Commodity derivative contracts Fair value of derivatives 93,722 — 93,722 — Total derivative assets $ 178,214 $ 14,338 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 748 77,999 Basis protection derivative contracts Fair value of derivatives 2,616 234 Rollfactor derivative contracts Fair value of derivatives — 1,069 3,364 79,302 Non-current Commodity derivative contracts Fair value of derivatives 1,364 22,343 Total derivative liabilities $ 4,728 $ 101,645 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 2018 2017 2016 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (115,538 ) $ 13,324 $ 208,103 Net change in fair value of unsettled derivatives 260,775 (17,260 ) (333,784 ) Total commodity price risk management gain (loss), net $ 145,237 $ (3,936 ) $ (125,681 ) 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, 2018 Derivative instruments, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 178,214 $ (3,985 ) $ 174,229 Liability derivatives: Derivative instruments, at fair value $ 4,728 $ (3,985 ) $ 743 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

PROPERTIES AND EQUIPMENT Proper

PROPERTIES AND EQUIPMENT Properties and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
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 sheets: As of December 31, 2018 2017 (in thousands, except for number of wells) Beginning balance $ 15,448 $ — Additions to capitalized exploratory well costs pending the determination of proved reserves 35,127 51,776 Reclassifications to proved properties (38,387 ) (36,328 ) Balance at December 31, $ 12,188 $ 15,448 Number of wells pending determination 2 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, 2018 2017 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 5,452,613 $ 4,356,922 Unproved 492,594 1,097,317 Total crude oil and natural gas properties 5,945,207 5,454,239 Infrastructure and other 60,612 109,359 Land and buildings 11,243 10,960 Construction in progress 356,095 196,024 Properties and equipment, at cost 6,373,157 5,770,582 Accumulated DD&A (2,370,295 ) (1,837,115 ) Properties and equipment, net $ 4,002,862 $ 3,933,467
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, 2018 2017 2016 (in thousands) Impairment of proved and unproved properties $ 458,397 $ 285,465 $ 5,562 Amortization of individually insignificant unproved properties — 422 1,379 Land and buildings — — 3,032 Total impairment of properties and equipment $ 458,397 $ 285,887 $ 9,973

PROPERTIES AND EQUIPMENT Explor

PROPERTIES AND EQUIPMENT Exploration, Geologic, and Geophysical Expense (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 (in thousands) Exploratory dry hole costs $ 113 $ 41,297 $ — Geological and geophysical costs, including seismic purchases 3,401 3,881 3,472 Operating, personnel and other 2,690 2,156 1,197 Total exploration, geologic and geophysical expense $ 6,204 $ 47,334 $ 4,669 Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. Year Ended December 31, 2018 2017 2016 (in thousands) Acquisition of properties: (1) Proved properties $ 205,253 $ 172 $ 268,567 Unproved properties 5,477 18,914 1,843,985 Development costs (2) 970,970 688,165 383,336 Exploration costs: (3) Exploratory drilling 36,704 80,103 — Geological and geophysical 3,401 3,881 4,669 Total costs incurred (4) $ 1,221,805 $ 791,235 $ 2,500,557 __________ (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, 2018 , 2017 and 2016 , $438.4 million , $463.4 million and $204.6 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $74.6 million and $32.8 million of infrastructure and pipeline costs in 2018 and 2017 , respectively. (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 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, 2018
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 and liabilities held-for-sale: As of December 31, 2018 2017 (in thousands) Assets Properties and equipment, net $ 137,448 $ 40,583 Other assets 3,257 — Total assets $ 140,705 $ 40,583 Liabilities Asset retirement obligation $ 4,111 $ 499 Total liabilities $ 4,111 $ 499

LONG-TERM DEBT LONG-TERM DEBT (

LONG-TERM DEBT LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (in thousands) Senior notes: 1.125% Convertible Notes due 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (22,766 ) (30,328 ) Unamortized debt issuance costs (2,640 ) (3,615 ) 1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs 174,594 166,057 6.125% Senior Notes due 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (5,590 ) (6,570 ) 6.125% Senior Notes due 2024, net of unamortized debt issuance costs 394,410 393,430 5.75% Senior Notes due 2026: Principal amount 600,000 600,000 Unamortized debt issuance costs (6,628 ) (7,555 ) 5.75% Senior Notes due 2026, net of unamortized debt issuance costs 593,372 592,445 Total senior notes 1,162,376 1,151,932 Revolving credit facility 32,500 — Total long-term debt, net of unamortized discount and debt issuance costs 1,194,876 1,151,932 Less current portion of long-term debt — — Long-term debt $ 1,194,876 $ 1,151,932

CAPITAL LEASES CAPITAL LEASES_2

CAPITAL LEASES CAPITAL LEASES (Tables)	12 Months Ended
	Dec. 31, 2018
Capital Leases [Abstract]
Schedule of Capital Leased Assets [Table Text Block]	The following table presents leased vehicles under capital leases: As of December 31, 2018 2017 (in thousands) Vehicles $ 7,941 $ 6,249 Accumulated depreciation (3,368 ) (1,882 ) $ 4,573 $ 4,367
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) 2019 $ 2,111 2020 2,236 2021 698 2022 381 2023 134 5,560 Less executory cost (278 ) Less amount representing interest (603 ) Present value of minimum lease payments $ 4,679 Short-term capital lease obligations $ 1,779 Long-term capital lease obligations 2,900 $ 4,679

ASSET RETIREMENT OBLIGATIONS As

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
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: Year Ended December 31, 2018 2017 (in thousands) Beginning balance $ 87,306 $ 92,387 Obligations incurred with development activities 2,793 3,638 Obligations incurred with acquisition 4,332 — Accretion expense 5,075 6,306 Revisions in estimated cash flows 30,166 (2,860 ) Obligations discharged with asset retirements (14,651 ) (12,165 ) Balance at December 31 115,021 87,306 Less liabilities held-for-sale (4,111 ) (499 ) Less current portion (25,598 ) (15,801 ) Long-term portion $ 85,312 $ 71,006

COMMITMENTS AND CONTINGENCIES C

COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Tables)	12 Months Ended
	Dec. 31, 2018
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 and water delivery and disposal commitments: Year Ending December 31, Area 2019 2020 2021 2022 2022 and Total Expiration Natural gas (MMcf) Wattenberg Field 23,934 31,110 31,025 31,025 90,897 207,991 April 30, 2026 Delaware Basin 48,147 37,430 21,307 — — 106,884 December 31, 2021 Gas Marketing 7,117 7,136 7,056 4,495 — 25,804 August 31, 2022 Total 79,198 75,676 59,388 35,520 90,897 340,679 Crude oil (MBbls) Wattenberg Field 9,713 5,918 5,475 5,475 3,180 29,761 April 30, 2023 Delaware Basin 7,359 8,784 8,030 8,030 8,030 40,233 December 31, 2023 Total 17,072 14,702 13,505 13,505 11,210 69,994 Water (MBbls) Wattenberg Field 3,103 6,207 6,207 6,207 12,413 34,137 December 31, 2024 Delaware Basin 3,650 3,660 3,650 3,650 1,770 16,380 June 26, 2023 Total 6,753 9,867 9,857 9,857 14,183 50,517 Dollar commitment (in thousands) $ 106,844 $ 78,209 $ 74,409 $ 67,354 $ 102,925 $ 429,741
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, 2018 : Year Ending December 31, 2019 2020 2021 2022 2023 Thereafter Total (in thousands) Minimum Lease Payments $ 6,273 $ 6,365 $ 6,290 $ 5,229 $ 1,385 $ 2,256 $ 27,798

COMMON STOCK Common Stock (Tabl

COMMON STOCK Common Stock (Tables)	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
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, 2018 2017 2016 (in thousands) Stock-based compensation expense $ 21,782 $ 19,353 $ 19,502 Income tax benefit (5,210 ) (7,372 ) (7,296 ) Net stock-based compensation expense $ 16,572 $ 11,981 $ 12,206
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]	he Compensation Committee awarded SARs to our executive officers in 2017 and 2016 . There were no SARs awarded to our executive officers in 2018 . 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 Expected term of award (in years) 6.0 years 6.0 years Risk-free interest rate 2.0 % 1.8 % Expected volatility 53.3 % 54.5 % Weighted-average grant date fair value per share $ 38.58 $ 26.96
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, 2018 2017 2016 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, 298,220 $ 47.39 6.5 $ 2,490 244,078 $ 41.36 $ 7,620 326,453 $ 38.99 $ 4,697 Awarded — — — — 54,142 74.57 — 58,709 51.63 — Exercised — — — — — — — (141,084 ) 40.16 2,770 Modified 63,969 42.83 — — — — — — — — Expired (71,931 ) 46.34 — — — — — — — — Outstanding at December 31, 290,258 46.64 4.6 125 298,220 47.39 2,490 244,078 41.36 7,620 Exercisable at December 31, 260,101 44.88 4.3 125 223,865 43.28 2,267 174,919 38.72 5,924
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 2018 : Shares Weighted-Average Non-vested at December 31, 2017 472,132 $ 60.23 Granted 446,743 50.69 Vested (249,317 ) 58.95 Forfeited (51,151 ) 56.45 Non-vested at December 31, 2018 618,407 54.16 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, 2018 2017 2016 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 12,282 $ 16,303 $ 18,973 Total intrinsic value of time-based awards non-vested 18,404 24,334 34,812 Market price per common share as of December 31, 29.76 51.54 72.58 Weighted-average grant date fair value per share 50.69 65.14 58.52
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, 2018 2017 2016 Expected term of award (in years) 3 years 3 years 3 years Risk-free interest rate 2.4 % 1.4 % 1.2 % Expected volatility 42.3 % 51.4 % 52.3 %
Schedule of Nonvested Performance-based Units Activity [Table Text Block]	The following table presents the change in non-vested market-based awards during 2018 : Shares Weighted-Average Non-vested at December 31, 2017 52,349 $ 84.06 Granted 90,778 69.98 Vested (18,941 ) 72.54 Forfeited (21,272 ) 78.65 Non-vested at December 31, 2018 102,914 74.88 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, 2018 2017 2016 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ 620 $ 2,687 $ 6,562 Total intrinsic value of market-based awards non-vested 3,063 2,698 3,514 Market price per common share as of December 31, 29.76 51.54 72.58 Weighted-average grant date fair value per share 69.98 94.02 72.54

INCOME TAXES Income Taxes (Tabl

INCOME TAXES Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
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 tax (expense) benefit for the years presented: Year Ended December 31, 2018 2017 2016 (in thousands) Current: Federal $ 886 $ 8,443 $ 9,646 State (188 ) (200 ) 300 Total current income tax benefit 698 8,243 9,946 Deferred: Federal (1,986 ) 193,809 118,427 State (4,118 ) 9,876 18,822 Total deferred income tax (expense) benefit (6,104 ) 203,685 137,249 Income tax (expense) benefit $ (5,406 ) $ 211,928 $ 147,195
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes: Year Ended December 31, 2018 2017 2016 Federal statutory tax rate 21.0 % 35.0 % 35.0 % State income tax, net (6.4 ) 1.8 2.6 Federal tax credits (52.1 ) — — Effect of state income tax rate changes 6.7 — 0.6 Change in valuation allowance 45.5 — — Non-deductible compensation 21.8 (0.3 ) (0.5 ) Non-deductible government relations 31.8 — — Other non-deductible items 4.9 — — Federal tax reform rate reduction — 33.7 — Non-deductible goodwill impairment — (7.7 ) — Other (0.4 ) (0.1 ) (0.3 ) Effective tax rate 72.8 % 62.4 % 37.4 %
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, 2018 and 2017 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. As of December 31, 2018 2017 (in thousands) Deferred tax assets: Deferred compensation $ 9,963 $ 6,059 Asset retirement obligations 27,166 21,760 Federal NOL carryforward 54,736 19,386 State NOL and tax credit carryforwards, net 13,223 7,815 Federal tax - credit carryforwards 7,756 4,366 Net change in fair value of unsettled derivatives — 20,929 Prepaid revenue 5,288 — Other 4,647 2,453 Valuation allowance (3,380 ) — Total gross deferred tax assets 119,399 82,768 Deferred tax liabilities: Properties and equipment 270,565 267,498 Net change in fair value of unsettled derivatives 41,496 — Convertible debt 5,434 7,262 Total gross deferred tax liabilities 317,495 274,760 Net deferred tax liability $ 198,096 $ 191,992

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation [Table Text Block]	The following table presents our weighted-average basic and diluted shares outstanding: Year Ended December 31, 2018 2017 2016 (in thousands) Weighted-average common shares outstanding - basic 66,059 65,837 49,052 Dilutive effect of: RSUs and PSUs 173 — — Other equity-based awards 71 — — Weighted-average common shares and equivalents outstanding - diluted 66,303 65,837 49,052
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, 2018 2017 2016 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: RSUs and PSUs 145 590 689 Convertible notes — — 292 Other equity-based awards 109 75 109 Total anti-dilutive common share equivalents 254 665 1,090

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION Supplemental Cash Flow (Tables)	12 Months Ended
	Dec. 31, 2018
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	Year Ended December 31, 2018 2017 2016 (in thousands) Supplemental cash flow information: Cash payments (receipts) for: Interest, net of capitalized interest $ 55,586 $ 69,880 $ 43,406 Income taxes (6,719 ) (13,925 ) 167 Non-cash investing activities: Issuance of common stock for acquisition of crude oil and natural gas properties — — 690,702 Change in accounts payable related to capital expenditures 36,328 50,761 (40,448 ) Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal 37,136 839 4,894 Purchase of properties and equipment under capital leases 1,940 3,497 1,404

SUBSIDIARY GUARANTOR SUBSIDIA_2

SUBSIDIARY GUARANTOR SUBSIDIARY GUARANTOR (Tables)	12 Months Ended
	Dec. 31, 2018
Guarantor Obligations [Line Items]
Schedule of Guarantor Obligations [Table Text Block]	SUBSIDIARY GUARANTOR PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the 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, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets: Cash and cash equivalents $ 1,398 $ — $ — $ 1,398 Accounts receivable, net 146,529 34,905 — 181,434 Fair value of derivatives 84,492 — — 84,492 Prepaid expenses and other current assets 6,725 411 — 7,136 Total current assets 239,144 35,316 — 274,460 Properties and equipment, net 2,270,711 1,732,151 — 4,002,862 Assets held-for-sale — 140,705 — 140,705 Intercompany receivable 451,601 — (451,601 ) — Investment in subsidiaries 1,316,945 — (1,316,945 ) — Fair value of derivatives 93,722 — — 93,722 Other assets 30,084 2,312 — 32,396 Total Assets $ 4,402,207 $ 1,910,484 $ (1,768,546 ) $ 4,544,145 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 110,847 $ 71,017 $ — $ 181,864 Production tax liability 53,309 7,410 — 60,719 Fair value of derivatives 3,364 — — 3,364 Funds held for distribution 90,183 15,601 — 105,784 Accrued interest payable 14,143 7 — 14,150 Other accrued expenses 73,689 1,444 — 75,133 Total current liabilities 345,535 95,479 — 441,014 Intercompany payable — 451,601 (451,601 ) — Long-term debt 1,194,876 — — 1,194,876 Deferred income taxes 162,368 35,728 — 198,096 Asset retirement obligations 79,904 5,408 — 85,312 Liabilities held-for-sale — 4,111 — 4,111 Fair value of derivatives 1,364 — — 1,364 Other liabilities 91,452 1,212 — 92,664 Total liabilities 1,875,499 593,539 (451,601 ) 2,017,437 Stockholders' equity Common shares 661 — — 661 Additional paid-in capital 2,519,423 1,766,775 (1,766,775 ) 2,519,423 Retained earnings 8,727 (449,830 ) 449,830 8,727 Treasury shares (2,103 ) — — (2,103 ) Total stockholders' equity 2,526,708 1,316,945 (1,316,945 ) 2,526,708 Total Liabilities and Stockholders' Equity $ 4,402,207 $ 1,910,484 $ (1,768,546 ) $ 4,544,145 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 40,583 — — 40,583 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 $ 4,206,047 $ 2,082,159 $ (1,867,816 ) $ 4,420,390 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 Liabilities held-for-sale 499 — — 499 Fair value of derivatives 22,343 — — 22,343 Other liabilities 57,009 324 — 57,333 Total liabilities 1,698,398 464,622 (250,279 ) 1,912,741 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 $ 4,206,047 $ 2,082,159 $ (1,867,816 ) $ 4,420,390 Consolidating Statements of Operations Year Ended December 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 1,050,696 $ 339,265 $ — $ 1,389,961 Commodity price risk management gain, net 145,237 — — 145,237 Other income 10,744 2,717 — 13,461 Total revenues 1,206,677 341,982 — 1,548,659 Costs, expenses and other Lease operating expenses 92,228 38,729 — 130,957 Production taxes 67,819 22,538 — 90,357 Transportation, gathering and processing expenses 16,607 20,796 — 37,403 Exploration, geologic and geophysical expense 1,234 4,970 — 6,204 Impairment of properties and equipment 27 458,370 — 458,397 General and administrative expense 152,798 17,706 — 170,504 Depreciation, depletion and amortization 389,841 169,952 — 559,793 Accretion of asset retirement obligations 4,617 458 — 5,075 (Gain) loss on sale of properties and equipment (4,387 ) 4,781 — 394 Other expenses 11,829 — — 11,829 Total costs, expenses and other 732,613 738,300 — 1,470,913 Income (loss) from operations 474,064 (396,318 ) — 77,746 Interest expense (73,251 ) 2,521 — (70,730 ) Interest income 413 — — 413 Income (loss) before income taxes 401,226 (393,797 ) — 7,429 Income tax (expense) benefit (98,611 ) 93,205 — (5,406 ) Equity in loss of subsidiary (300,592 ) — 300,592 — Net income (loss) $ 2,023 $ (300,592 ) $ 300,592 $ 2,023 Net loss for the Guarantor for the year ended 2018 is primarily the result of impairment of certain unproved Delaware Basin leasehold positions. 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 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 Accretion of asset retirement obligations 5,965 341 — 6,306 Gain on sale of properties and equipment (766 ) — — (766 ) Provision for uncollectible notes receivable (40,203 ) — — (40,203 ) 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 loss for the Guarantor for the year ended 2017 is 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 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 Accretion of asset retirement obligations 7,070 10 — 7,080 Gain on sale of properties and equipment (43 ) — — (43 ) Provision for uncollectible notes receivable 44,038 — — 44,038 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 ) Consolidating Statements of Cash Flows Year Ended December 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 625,206 $ 264,096 $ — $ 889,302 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (482,534 ) (463,816 ) — (946,350 ) Capital expenditures for other properties and equipment (9,806 ) (1,249 ) — (11,055 ) Acquisition of crude oil and natural gas properties (179,955 ) (71 ) — (180,026 ) Proceeds from sale of properties and equipment 1,929 1,633 — 3,562 Proceeds from divestiture 44,693 — — 44,693 Restricted cash 1,249 — — 1,249 Intercompany transfers (199,584 ) — 199,584 — Net cash from investing activities (824,008 ) (463,503 ) 199,584 (1,087,927 ) Cash flows from financing activities: Proceeds from revolving credit facility 1,072,500 — — 1,072,500 Repayment of revolving credit facility (1,040,000 ) — — (1,040,000 ) Payment of debt issuance costs (7,704 ) — — (7,704 ) Purchase of treasury stock (5,147 ) — — (5,147 ) Other (1,373 ) (177 ) — (1,550 ) Intercompany transfers — 199,584 (199,584 ) — Net cash from financing activities 18,276 199,407 (199,584 ) 18,099 Net change in cash and cash equivalents (180,526 ) — — (180,526 ) Cash and cash equivalents, beginning of period 189,925 — — 189,925 Cash and cash equivalents, end of period $ 9,399 $ — $ — $ 9,399 Consolidating Statements of Cash Flows Year Ended December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 546,954 $ 50,859 $ — $ 597,813 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas 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 (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 ) Sales of short-term investments 49,890 — — 49,890 Purchases 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 ) Payment of debt issuance costs (50 ) — — (50 ) Purchase of treasury stock (6,672 ) — — (6,672 ) 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 (50,562 ) (3,613 ) — (54,175 ) Cash and cash equivalents, beginning of period 240,487 3,613 — 244,100 Cash and cash equivalents, end of period $ 189,925 $ — $ — $ 189,925 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 gas 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 (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 revolving credit facility 85,000 — — 85,000 Repayment of revolving credit facility (122,000 ) — — (122,000 ) 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 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 closed in December 2016.

SUPPLEMENTAL INFORMATION - NA_2

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Supplemental Information on Natural Gas and Crude Oil Exploration, Development and Production Activities (Tables)	12 Months Ended
	Dec. 31, 2018
Reserve Quantities [Line Items]
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) (2) Natural Gas (per Mcf) (2) NGLs (per Bbl) (3) 2018 $ 65.56 $ 3.10 $ 65.56 2017 51.34 2.98 51.34 2016 42.75 2.48 42.75
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 (4) As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) 2018 $ 61.14 $ 2.15 $ 23.04 2017 48.68 2.31 20.21 2016 38.67 1.85 11.97 ___________ (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) Our benchmark prices for crude oil and natural gas are WTI and Henry Hub, respectively. (3) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. (4) These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity.
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, 2016 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 Revisions of previous estimates 26,548 94,738 12,674 55,011 Extensions, discoveries and other additions 8,786 61,750 8,868 27,946 Acquisition of reserves 19,644 148,674 15,936 60,360 Dispositions (2,507 ) (35,750 ) (2,656 ) (11,121 ) Production (16,964 ) (88,017 ) (8,527 ) (40,160 ) Proved reserves, December 31, 2018 190,349 1,335,689 131,987 544,953 Proved Developed Reserves, as of: December 31, 2016 30,013 264,452 24,196 98,284 December 31, 2017 46,862 365,332 35,220 142,971 December 31, 2018 61,821 443,151 43,856 179,535 Proved Undeveloped Reserves, as of: December 31, 2016 88,156 569,245 60,092 243,122 December 31, 2017 107,980 788,962 70,472 309,946 December 31, 2018 128,528 892,538 88,131 365,418 Developed Undeveloped Total (MBoe) Proved reserves, January 1, 2016 70,496 202,329 272,825 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 ) Undeveloped reserves converted to developed 32,192 (32,192 ) — Proved reserves, December 31, 2016 98,285 243,122 341,407 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 ) Undeveloped reserves converted to developed 54,648 (54,648 ) — Proved reserves, December 31, 2017 142,971 309,946 452,917 Revisions of previous estimates 6,284 48,727 55,011 Extensions, discoveries and other additions 7,874 20,072 27,946 Acquisition of reserves 8,758 51,602 60,360 Dispositions (4,486 ) (6,635 ) (11,121 ) Production (40,160 ) — (40,160 ) Undeveloped reserves converted to developed 58,294 (58,294 ) — Proved reserves, December 31, 2018 179,535 365,418 544,953
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. Year Ended December 31, 2018 2017 2016 (in thousands) Revenue: Crude oil, natural gas and NGLs sales $ 1,389,961 $ 913,084 $ 497,353 Commodity price risk management gain (loss), net 145,237 (3,936 ) (125,681 ) 1,535,198 909,148 371,672 Expenses: Lease operating expenses 130,957 89,641 59,950 Production taxes 90,357 60,717 31,410 Transportation, gathering and processing expenses 37,403 33,220 18,415 Exploration expense 6,204 47,334 4,669 Impairment of properties and equipment 458,397 285,887 9,973 Depreciation, depletion and amortization 551,265 462,482 413,105 Accretion of asset retirement obligations 5,075 6,306 7,080 (Gain) loss on sale of properties and equipment 394 (766 ) (43 ) 1,280,052 984,821 544,559 Results of operations for crude oil and natural gas producing 255,146 (75,673 ) (172,887 ) Income tax (expense) benefit (185,667 ) 47,247 64,733 Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs $ 69,479 $ (28,426 ) $ (108,154 )
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, 2018 2017 2016 (in thousands) Exploratory dry hole costs $ 113 $ 41,297 $ — Geological and geophysical costs, including seismic purchases 3,401 3,881 3,472 Operating, personnel and other 2,690 2,156 1,197 Total exploration, geologic and geophysical expense $ 6,204 $ 47,334 $ 4,669 Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. Year Ended December 31, 2018 2017 2016 (in thousands) Acquisition of properties: (1) Proved properties $ 205,253 $ 172 $ 268,567 Unproved properties 5,477 18,914 1,843,985 Development costs (2) 970,970 688,165 383,336 Exploration costs: (3) Exploratory drilling 36,704 80,103 — Geological and geophysical 3,401 3,881 4,669 Total costs incurred (4) $ 1,221,805 $ 791,235 $ 2,500,557 __________ (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, 2018 , 2017 and 2016 , $438.4 million , $463.4 million and $204.6 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $74.6 million and $32.8 million of infrastructure and pipeline costs in 2018 and 2017 , respectively. (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 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, 2018 2017 (in thousands) Proved crude oil and natural gas properties $ 5,452,613 $ 4,356,922 Unproved crude oil and natural gas properties 492,594 1,097,317 Uncompleted wells, equipment and facilities 332,264 265,526 Capitalized costs 6,277,471 5,719,765 Less accumulated DD&A (2,341,897 ) (1,803,847 ) Capitalized costs, net $ 3,935,574 $ 3,915,918
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, 2018 2017 2016 (in thousands) Future estimated cash flows $ 17,554,880 $ 12,340,407 $ 7,122,525 Future estimated production costs* (4,782,948 ) (3,245,627 ) (1,624,167 ) Future estimated development costs (3,632,822 ) (2,893,335 ) (2,219,914 ) Future estimated income tax expense (1,404,121 ) (748,494 ) (597,476 ) Future net cash flows 7,734,989 5,452,951 2,680,968 10% annual discount for estimated timing of cash flows (3,287,273 ) (2,572,846 ) (1,260,339 ) Standardized measure of discounted future estimated net cash flows $ 4,447,716 $ 2,880,105 $ 1,420,629 ___________ * Represents future estimated lease operating expenses, production taxes and 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, 2018 2017 2016 (in thousands) Beginning of period $ 2,880,105 $ 1,420,629 $ 1,096,864 Sales of crude oil, natural gas and NGLs production, net of production costs (1,131,244 ) (729,506 ) (387,576 ) Net changes in prices and production costs (1) 936,077 841,713 (205,760 ) Extensions, discoveries and improved recovery, less related costs 190,084 47,240 15,128 Sales of reserves (42,362 ) (2,613 ) (3,745 ) Purchases of reserves 467,807 224,483 487,636 Development costs incurred during the period 462,088 419,047 268,672 Revisions of previous quantity estimates 631,198 484,431 (320,286 ) Changes in estimated income taxes (232,002 ) (138,560 ) (13,630 ) Net changes in future development costs (123,663 ) 25,183 391,145 Accretion of discount 583,744 167,487 133,747 Timing and other (174,116 ) 120,571 (41,566 ) End of period $ 4,447,716 $ 2,880,105 $ 1,420,629 __________ (1) Our weighted-average price, net of production costs per Boe, in our 2018 reserve report increased to $23.44 as compared to $20.08 for 2017 and $15.73 for 2016 .

SUPPLEMENTAL INFORMATION - QU_2

SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2018
Document Information [Line Items]
Quarterly Financial Information [Table Text Block]	2018 Quarter Ended March 31 (1) June 30 September 30 (1) December 31 (1) (in thousands, except per share data) Total revenues $ 260,600 $ 212,531 $ 280,717 $ 794,811 Total costs, expenses and other 260,924 400,770 270,593 538,626 Income (loss) from operations (324 ) (188,239 ) 10,124 256,185 Income (loss) before income taxes (17,705 ) (205,580 ) (7,310 ) 238,024 Net income (loss) $ (13,139 ) $ (160,257 ) $ (3,434 ) $ 178,853 Earnings per share: Basic $ (0.20 ) $ (2.43 ) $ (0.05 ) $ 2.71 Diluted (0.20 ) (2.43 ) (0.05 ) 2.71 2017 Quarter Ended March 31 June 30 September 30 (1) December 31 (2) (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) $ 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) Impairment charges, which are included in total costs, expenses and other above, reflect the correction of two errors in the timing of the reporting of certain impairments. In 2018, we corrected an error in our calculation of unproved properties and goodwill originally recorded in 2017, resulting in an additional impairment charge of $6.3 million being recorded during the three months ended March 31, 2018. Further, during the fourth quarter of 2018, we corrected for an additional $8.4 million impairment of unproved properties relating to the three months ended September 30, 2018. See the footnote titled Properties and Equipment to our consolidated financial statements included elsewhere in this report. (2) 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.

SCHEDULE II - VALUATION AND Q_2

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Tables)	12 Months Ended
	Dec. 31, 2018
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Summary of Valuation Allowance [Table Text Block]	Description Beginning Charged to Deductions (1) Ending (in thousands) 2018: Allowance for doubtful accounts $ 3,128 $ 1,276 $ 23 $ 4,381 Allowance for expirations of unproved crude oil and natural gas properties 251,159 388,068 96,518 542,709 2017: Allowance for uncollectible notes $ 44,038 $ — $ 44,038 $ — Allowance for doubtful accounts 2,190 1,108 170 3,128 Allowance for expirations of unproved crude oil and natural gas properties 359 263,817 13,017 251,159 2016: Allowance for uncollectible notes $ — $ 44,038 $ — $ 44,038 Allowance for doubtful accounts 2,009 1,309 1,128 2,190 Allowance for expirations of unproved crude oil and natural gas properties 144 215 — 359 ____________ (1) For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. 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 actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.

NATURE OF OPERATIONS AND BASI_2

NATURE OF OPERATIONS AND BASIS OF PRESENTATION Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)Wells
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Proceeds from Sale of Property Held-for-sale | $	$ 39
Oil and gas producing wells, gross | Wells	2,900
Number of Operating Segments	2

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Detail (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Significant Accounting Policies [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 20,000	$ 11,300
Non-Oil and gas Depreciation, Depletion and Amortization	8,500	6,600	$ 3,800
Capitalized Interest	9,200	5,000	$ 4,500
Production Tax Liability	61,310	50,476
Cash and cash equivalents	1,398	180,675
Restricted Cash	8,001	9,250
Restricted Cash and Cash Equivalents	$ 9,399	$ 189,925
Minimum [Member]
Significant Accounting Policies [Line Items]
Property, Plant and Equipment, Useful Life	2 years
Maximum [Member]
Significant Accounting Policies [Line Items]
Property, Plant and Equipment, Useful Life	35 years

BUSINESS COMBINATIONS BUSINES_3

BUSINESS COMBINATIONS BUSINESS COMBINATIONS (Details) $ / shares in Units, a in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)aWells$ / shares	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Business Acquisition [Line Items]
Oil and gas producing wells, gross | Wells	2,900
Issuance of common stock for acquisition of crude oil and natural gas properties	$ 0	$ 0	$ 690,702
Escrow Deposit Disbursements Related to Property Acquisition	21,000
Bayswater Acquisition [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	189,560
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 199,982
Acquired Acreage | a	7,400
Oil and gas drilling locations, gross | Wells	220
Productive Oil Wells, Number of Wells, Net | Wells	24
Business Acquisition, Pro Forma Revenue	$ 70,800
Business Acquisition, Pro Forma Net Income (Loss)	$ 39,300
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares	$ 0.59

BUSINESS COMBINATIONS Fair Valu

BUSINESS COMBINATIONS Fair Value of Net Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value of Net Assets [Line Items]
Issuance of common stock for acquisition of crude oil and natural gas properties	$ 0	$ 0	$ 690,702
Business Acquisition Purchase Price Allocation Asset Retirement Obligation	$ 4,332	$ 0

BUSINESS COMBINATIONS Busines_4

BUSINESS COMBINATIONS Business Combinations Table (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Escrow Deposit Disbursements Related to Property Acquisition	$ 21,000
Business Acquisition Purchase Price Allocation Asset Retirement Obligation	(4,332)	$ 0
Bayswater Acquisition [Member]
Business Acquisition [Line Items]
Payments to Acquire Business Two, Net of Cash Acquired	168,560
Payments to Acquire Businesses, Gross	189,560
Goodwill, Purchase Accounting Adjustments	10,422
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	199,982
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets	468
Business Acquisitions Purchase Price Allocation Proved Natural Gas Properties	205,834
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets	2,796
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	209,098
Business Combination, Contingent Consideration, Liability, Current	(4,429)
Business Acquisition Purchase Price Allocation Asset Retirement Obligation	(4,687)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities	$ (9,116)

Revenue Recognition Revenue fro

Revenue Recognition Revenue from Contract with Customer (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Accounts Receivable, Gross	$ 155.8	$ 154.3

Revenue Recognition Revenue R_3

Revenue Recognition Revenue Recognition Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenue Recognition and Deferred Revenue [Abstract]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 20	$ 11.3

Revenue Recognition Revenue by

Revenue Recognition Revenue by Commodity and Location (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue from Contract with Customer, Excluding Assessed Tax	$ 1,389,961	$ 913,084	$ 497,353
Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	4,645	22,748	23,031
Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	339,265	124,684	5,602
Wattenberg Field [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	1,046,051	765,652	468,720
Crude Oil [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	1,037,961	625,053	348,855
Crude Oil [Member] | Wattenberg Field [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	783,158	529,562	329,168
Crude Oil [Member] | Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	252,107	82,677	3,918
Crude Oil [Member] | Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	2,696	12,814	15,769
Natural Gas [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	163,192	158,259	91,576
Natural Gas [Member] | Wattenberg Field [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	130,073	131,792	86,633
Natural Gas [Member] | Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	32,010	21,251	1,039
Natural Gas [Member] | Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	1,109	5,216	3,904
Crude Oil and NGL [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	188,808	129,772	56,922
Crude Oil and NGL [Member] | Wattenberg Field [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	132,820	104,298	52,919
Crude Oil and NGL [Member] | Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	55,148	20,756	645
Crude Oil and NGL [Member] | Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 840	$ 4,718	$ 3,358

Revenue Recognition Contract As

Revenue Recognition Contract Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Capitalized Contract Cost [Line Items]
Capitalized Contract Cost, Gross	$ 2,884	$ 3,746
Capitalized Contract Cost, Amortization	(3,096)
Capitalized Contract Cost, Net	$ 3,534

FAIR VALUE MEASUREMENTS AND D_3

FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 178,214	$ 14,338
Liabilities, Fair Value Disclosure	4,728	101,645
Net Asset Fair Value	173,486	(87,307)
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	118,521	12,949
Liabilities, Fair Value Disclosure	3,364	90,569
Net Asset Fair Value	115,157	(77,620)
Fair Value | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	59,693	1,389
Liabilities, Fair Value Disclosure	1,364	11,076
Net Asset Fair Value	58,329	(9,687)
1.125% Convertible Senior Notes due 2021 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes fair value	$ 175,400	$ 195,600
Notes fair value as percentage of par	87.70%	97.80%
6.125% Senior Notes due 2024 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes fair value	$ 370,200	$ 416,000
Notes fair value as percentage of par	92.50%	104.00%
5.75% Senior Notes due 2026 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes fair value	$ 532,400	$ 616,500
Notes fair value as percentage of par	88.70%	102.80%

FAIR VALUE MEASUREMENTS AND D_4

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ 58,329	$ (9,687)	$ (9,574)	$ 91,288
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	0	(866)	(12,905)
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	63,257	6,241	(28,550)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	4,759	(6,354)	(72,312)
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	$ 0	$ (866)	$ (12,905)

CONCENTRATION OF RISK Account_2

CONCENTRATION OF RISK Accounts Receivable, Net of Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Concentration Risk [Line Items]
Accounts Receivable, Gross	$ 155,800	$ 154,300
Income Taxes Receivable	0	6,015
Allowance for Doubtful Accounts Receivable, Current	(4,381)	(3,128)
Accounts Receivable, Net, Current	181,434	197,598
Natural gas, NGLs and crude oil sales
Concentration Risk [Line Items]
Accounts Receivable, Gross	155,756	154,260
Joint interest billing
Concentration Risk [Line Items]
Accounts Receivable, Gross	19,580	34,576
Derivative Counterparties
Concentration Risk [Line Items]
Accounts Receivable, Gross	3,937	(18)
Other Accounts Receivable
Concentration Risk [Line Items]
Accounts Receivable, Gross	$ 6,542	$ 5,893

DERIVATIVE FINANCIAL INSTRUME_3

DERIVATIVE FINANCIAL INSTRUMENTS Fair Value of Derivative and Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 4,728	$ 101,645
Derivative Asset, Fair Value, Gross Asset	178,214	14,338
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	0	6,998
Derivative Asset, Fair Value, Gross Asset	84,492	14,338
Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	93,722	0
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,364	79,302
Commodity Contract [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	84,492	7,340
Commodity Contract [Member] | Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	93,722	0
Commodity Contract [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	748	77,999
Commodity Contract [Member] | Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,364	22,343
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	2,616	234
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	$ 0	$ 1,069

CONCENTRATION OF RISK Customer

CONCENTRATION OF RISK Customer Constituting 10% or more of Total Revenue (Details)	12 Months Ended
	Dec. 31, 2018Rate	Dec. 31, 2017Rate	Dec. 31, 2016Rate
Suncor Energy Marketing, Inc.
Concentration Risk [Line Items]
Percentage of Revenue	0.00%	16.40%	22.30%
DCP Midstream, LP
Concentration Risk [Line Items]
Percentage of Revenue	12.50%	19.60%	20.20%
Aka Energy Group. LLC [Member]
Concentration Risk [Line Items]
Percentage of Revenue	0.00%	0.00%	13.40%
Concord Energy
Concentration Risk [Line Items]
Percentage of Revenue	0.00%	0.00%	13.40%
Bridger Energy, LLC [Member]
Concentration Risk [Line Items]
Percentage of Revenue	0.00%	0.00%	11.50%

DERIVATIVE FINANCIAL INSTRUME_4

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Net settlements	$ (115,538)	$ 13,324	$ 208,103
Net change in fair value of unsettled derivatives	260,775	(17,260)	(333,784)
Total Derivative Gain (Loss)	$ 145,237	$ (3,936)	$ (125,681)

DERIVATIVE FINANCIAL INSTRUME_5

DERIVATIVE FINANCIAL INSTRUMENTS Effect of Master Netting Agreements (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Liability	$ 743	$ 87,472
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	178,214	14,338
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(3,985)	(14,173)
Derivative Asset	174,229	165
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	4,728	101,645
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ (3,985)	$ (14,173)

CONCENTRATION OF RISK Notes Rec

CONCENTRATION OF RISK Notes Receivable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes, Loans and Financing Receivable, Gross, Noncurrent	$ 39,000
Provision for Doubtful Accounts	$ 0	$ (40,203)	$ 44,038
Proceeds from Sale of Notes Receivable		$ 40,203

DERIVATIVE FINANCIAL INSTRUME_6

DERIVATIVE FINANCIAL INSTRUMENTS Additional Information (Details) - Scenario, Forecast [Member] MMBbls in Millions, Bcf in Millions	Dec. 31, 2020MMBbls	Dec. 31, 2019MMBblsBcf
Natural Gas [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged (MMBbls) | Bcf		26.4
2019 [Member] | Crude Oil [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged (MMBbls)		11
2020 [Member] | Crude Oil [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged (MMBbls)	8.6

CONCENTRATION OF RISK Other acc

CONCENTRATION OF RISK Other accrued expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Other Liabilities [Line Items]
Saddle Butte Rockies Midstream Amendment Payment	$ 24,100
Production Tax Liability	61,310	$ 50,476
Amortization of Other Deferred Charges	1,400
Other Accrued Liabilities, Noncurrent	92,664	57,333
Accrued Employee Benefits	25,811	22,383
Asset Retirement Obligation, Current	25,598	15,801
Accrued Environmental Liabilities	3,038	1,374
Other Accrued Liabilities	20,686	3,429
Other Accrued Liabilities, Noncurrent	75,133	42,987
Non Current Liabilities [Member]
Schedule of Other Liabilities [Line Items]
Increase (Decrease) in Accrued Cost of Oil and Gas Reclamation	22,710	0
Other Accrued Liabilities	$ 8,644	$ 6,857

DERIVATIVE FINANCIAL INSTRUME_7

DERIVATIVE FINANCIAL INSTRUMENTS Outstanding Derivative Contracts (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)MMBTU$ / UnitMBbls
Derivative [Line Items]
FV Commodity Derivatives Assets measured with Level 3	33.50%
Derivative, Fair Value, Net | $	$ 173,486
FV Commodity Derivatives Liabilities measured with Level 3	28.90%
Natural Gas [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ 1,438
Natural Gas [Member] | Commodity Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	0
Natural Gas [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	26,383,000
Natural Gas [Member] | Basis Protection Contracts Related to Natural Gas Marketing [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (2,616)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	25,924,000
Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ 174,664
Crude Oil [Member] | Commodity Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	6,200
Crude Oil [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	13,400
2019 [Member] | Natural Gas [Member] | Columbia [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ 0
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	3,000
2019 [Member] | Natural Gas [Member] | Dominion South [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ 30
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	372,000
2019 [Member] | Natural Gas [Member] | Commodity Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	0
2019 [Member] | Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ 1,408
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	26,008,000
2019 [Member] | Natural Gas [Member] | Basis Protection - CIG [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (2,616)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	25,924,000
2019 [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ 82,305
2019 [Member] | Crude Oil [Member] | Commodity Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	2,600
2019 [Member] | Crude Oil [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	8,400
2020 [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ 92,359
2020 [Member] | Crude Oil [Member] | Commodity Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	3,600
2020 [Member] | Crude Oil [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	5,000
CIG [Member] | Natural Gas [Member] | 2019 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	(0.78)
Columbia [Member] | Natural Gas [Member] | 2019 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	2.40
Dominion South [Member] | Natural Gas [Member] | 2019 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	3.13
CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member] | 2019 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	2.91
CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member] | 2019 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	53.86
Derivative, Floor Price | $ / Unit	56.54
Derivative, Cap Price | $ / Unit	68.13
CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member] | 2020 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	62.07
Derivative, Floor Price | $ / Unit	55
Derivative, Cap Price | $ / Unit	71.68

PROPERTIES AND EQUIPMENT Prop_2

PROPERTIES AND EQUIPMENT Properties and Equipment (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)Wells	Dec. 31, 2017USD ($)Wells	Dec. 31, 2016USD ($)
Property, Plant and Equipment [Line Items]
Exploratory Wells Drilled, Net Nonproductive	$ 113	$ 41,297	$ 0
Capitalized Exploratory Well Costs	12,188	15,448	0
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves	35,127	51,776
Properties and equipment, net	4,002,862	3,933,467
Assets	4,544,145	4,420,390
Asset retirement obligations	85,312	71,006
Liabilities	2,017,437	1,912,741
Proved Natural Gas and Crude Oil Properties	5,452,613	4,356,922
Unproved Natural Gas and Crude Oil Properties	492,594	1,097,317
Total Natural Gas and Crude Oil Properties	5,945,207	5,454,239
Transportation and Other Equipment	60,612	109,359
Land and Buildings	11,243	10,960
Construction in Progress	356,095	196,024
Property and Equipment, at cost	6,373,157	5,770,582
Accumulated Depreciation, Depletion and Amortization	(2,370,295)	(1,837,115)
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves	$ (38,387)	$ (36,328)
Wells to be completed | Wells	2	3
Geological and geophysical	$ 3,401	$ 3,881	3,472
Other expenses	2,690	2,156	1,197
Exploration, geologic and geophysical expense	6,204	47,334	4,669
Property, Plant and Equipment, Net	4,002,862	3,933,467
Exploration and Production Equipment [Member]
Property, Plant and Equipment [Line Items]
Exploration, geologic and geophysical expense	6,204	47,334	$ 4,669
Midstream [Member] [Member]
Property, Plant and Equipment [Line Items]
Assets Held-for-sale, Not Part of Disposal Group, Other	3,257	0
Assets	140,705
Asset retirement obligations	4,111
Liabilities	4,111
Property and Equipment, at cost	$ 137,448
Utica Shale [Member]
Property, Plant and Equipment [Line Items]
Properties and equipment, net		40,583
Assets		40,583
Asset retirement obligations		499
Liabilities		$ 499

PROPERTIES AND EQUIPMENT Impair

PROPERTIES AND EQUIPMENT Impairment of Natural Gas and Crude Oil Properties (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)a	Dec. 31, 2016USD ($)
Impairment of natural gas and crude oil properties [Line Items]
Exploratory operating costs	$ 113	$ 41,297	$ 0
Delaware Basin Unproved Property Impairment	6,300	$ 251,600
Impaired acreage | a		13,400
Continuing Operations:
Impairment of proved and unproved properties	458,397	$ 285,465	5,562
Amortization of Individually Insignificant Unproved Properties	0	422	1,379
Impairment of Long-Lived Assets to be Disposed of	0	0	3,032
Results of Operations, Impairment of Oil and Gas Properties	458,397	285,887	$ 9,973
Discontinued operations:
Delaware Basin Impairment_Q4	$ 8,400
Delaware Basin [Member]
Impairment of natural gas and crude oil properties [Line Items]
Delaware Basin Unproved Property Impairment		29,000
Utica Shale [Member]
Discontinued operations:
Impairment of other properties		$ 2,100

PROPERTIES AND EQUIPMENT Prop_3

PROPERTIES AND EQUIPMENT Properties and Equipment Acreage exchange (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)a	Dec. 31, 2017a
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property Held-for-sale | $	$ 39
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	12,300	16,200
Third Party 1 acreage to PDC [Member]
Property, Plant and Equipment [Line Items]
Gas and Oil Area, Developed, Gross	2,500
PDC acres transferred to Noble [Member]
Property, Plant and Equipment [Line Items]
Gas and Oil Area, Developed, Gross	6,000,000

PROPERTIES AND EQUIPMENT Acreag

PROPERTIES AND EQUIPMENT Acreage Exchange (Details) $ in Millions	Dec. 31, 2018USD ($)a	Dec. 31, 2017a
Third Party 1 acreage to PDC [Member]
Gas and Oil Acreage [Line Items]
Gas and Oil Area, Developed, Gross	2,500
Cash, additional to acreage, received | $	$ 3.7
PDC acreage to Third Party 2 [Member]
Gas and Oil Acreage [Line Items]
Gas and Oil Area, Developed, Gross	12,300	16,200

PROPERTIES AND EQUIPMENT Asse_2

PROPERTIES AND EQUIPMENT Assets Held for Sale (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Long Lived Assets Held-for-sale [Line Items]
Proceeds from Sale of Property Held-for-sale	$ 39
Utica Shale [Member]
Long Lived Assets Held-for-sale [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	$ 1.4

GOODWILL (Details)

GOODWILL (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Abstract]
Goodwill, Impairment Loss	$ 0	$ 75,121	$ 0

LONG-TERM DEBT SCHEDULE OF LONG

LONG-TERM DEBT SCHEDULE OF LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total senior notes	$ 1,162,376	$ 1,151,932
Total debt, net of discount and unamortized debt issuance costs	1,194,876	1,151,932
Less current portion of long-term debt	0	0
Long-term debt	1,194,876	1,151,932
1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Principal amount	(200,000)	(200,000)
Unamortized Discount	22,766	30,328
Unamortized Debt Issuance Costs	(2,640)	(3,615)
Convertible Debt	174,594	166,057
6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Costs	(5,590)	(6,570)
Principal amount	(400,000)	(400,000)
Senior Long Term Notes	394,410	393,430
5.75% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Principal amount	(600,000)	(600,000)
Unamortized Debt Issuance Costs	(6,628)	(7,555)
Convertible Debt	593,372	592,445
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 32,500	$ 0

LONG-TERM DEBT ADDITIONAL INFOR

LONG-TERM DEBT ADDITIONAL INFORMATION (Details) - USD ($)	May 15, 2026	Sep. 15, 2021	Mar. 15, 2021	Sep. 15, 2019	Sep. 12, 2016	Jun. 30, 2021	Sep. 30, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Redemption of senior notes								$ 0	$ (519,375,000)	$ 0
Loss on extinguishment of debt								0	24,747,000	$ 0
Convertible Note, Conversion Price										$ 85.39
Debt Issuance Costs ($)								7,704,000	50,000	$ 15,556,000
Line of Credit Facility, Initial Borrowing Base								1,300,000,000
Line of Credit, Initial Elected Commitment								700,000,000
Swingline Facility								25,000,000
Debt Issuance Costs, Line of Credit Arrangements, Net								11,500,000	6,200,000
Line of Credit Facility, Capacity Available for Trade Purchases								$ 1,300,000,000	700,000,000
Line of Credit Facility, Weighted Average Interest Rate								4.50%
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, Description								0.35
Minimum percent of aggregate principal debt amount required to remain outstanding								65.00%
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, Description								.35
Minimum percent of aggregate principal debt amount required to remain outstanding								65.00%
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								11.7113
5.75% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Principal amount								$ 600,000,000	600,000,000
Debt Issuance Costs, Gross								$ 7,600,000
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
Maximum Borrowing Base [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity ($)								$ 2,500,000,000
1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Principal amount								200,000,000	200,000,000
Debt Issuance Costs, Gross								4,800,000
Liability component of gross proceeds of Convertible Notes								160,500,000
Convertible Debt, Equity Component ($)								39,500,000
6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Issuance Costs, Gross								7,800,000
Senior Notes ($)								$ 400,000,000	$ 400,000,000
Scenario, Forecast [Member] | 1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Convertible Note Principal Amount			$ 1,000
Scenario, Forecast [Member] | 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%
Subsequent Event [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	May 15, 2026	Sep. 15, 2021
Subsequent Event [Member] | 5.75% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Period, End Date						May 15, 2021
Subsequent Event [Member] | 6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Period, End Date				Sep. 15, 2019
Subsequent Event [Member] | 1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Convertible Note, Conversion Price			$ 85.39
Debt Instrument, Call Date, Latest			Mar. 15, 2021
Subsequent Event [Member] | 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%
Subsequent Event [Member] | 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%
Subsequent Event [Member] | 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%
Restricted Stock [Member]
Debt Instrument [Line Items]
Share Price								$ 29.76	$ 51.54	$ 72.58
Unused Commitment Fee [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End								0.375%
Alternate Base Rate Option [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End								0.25%
LIBOR Option [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End								1.25%

CAPITAL LEASES Leased Vehicles

CAPITAL LEASES Leased Vehicles under capital leases (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Capital Leased Assets [Line Items]
Vehicles	$ 7,941	$ 6,249
Accumulated depreciation	(3,368)	(1,882)
Total leased assets, Net	$ 4,573	$ 4,367

CAPITAL LEASES Future Minimum L

CAPITAL LEASES Future Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2018USD ($)
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	$ 5,560
Less Executory Costs	278
Less Amounts Representing Interest	603
Present Value of Minimum Lease Payments	4,679
Short-term Capital Lease Obligations	1,779
Long-term Capital Lease Obligations	2,900
Total Capital Lease Obligations	4,679
2018 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	2,111
2020 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	2,236
2021 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	698
2022 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	381
2023 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	$ 134

ASSET RETIREMENT OBLIGATIONS _2

ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reconciliation Of Changes In Asset Retirement Obligations [Line Items]
Disposal Group, Including Discontinued Operation, Other Liabilities	$ (4,111)	$ (499)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance beginning of year, January 1	87,306	92,387
Revisions in estimated cash flows	30,166	(2,860)
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal	2,793	3,638
Business Acquisition Purchase Price Allocation Asset Retirement Obligation	4,332	0
Accretion of asset retirement obligations	5,075	6,306	$ 7,080
Obligations discharged with disposal of properties and asset retirements	(14,651)	(12,165)
Balance end of year, December 31	115,021	87,306	$ 92,387
Less: Current portion	$ (25,598)	$ (15,801)

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)MBblsbblMMcf
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	340,679
Dollar Commitment ($ in thousands) | $	$ 429,741
LT transportation volumes, net to interest | $	$ 27,300
2,019
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	79,198
Dollar Commitment ($ in thousands) | $	$ 106,844
2,020
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	75,676
Dollar Commitment ($ in thousands) | $	$ 78,209
2,021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	59,388
Dollar Commitment ($ in thousands) | $	$ 74,409
2,022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	35,520
Dollar Commitment ($ in thousands) | $	$ 67,354
commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	90,897
Dollar Commitment ($ in thousands) | $	$ 102,925
Appalachiain Basin
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	25,804
Appalachiain Basin | 2019
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
Appalachiain Basin | 2020
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,136
Appalachiain Basin | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,056
Appalachiain Basin | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	4,495
Appalachiain Basin | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	0
Appalachiain Basin | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Aug. 31, 2022
Wattenberg Field
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	207,991
Wattenberg Field | 2019
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	23,934
Wattenberg Field | 2020
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	31,110
Wattenberg Field | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	31,025
Wattenberg Field | 2022
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)	90,897
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)	106,884
Delaware Basin [Member] | 2019
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	48,147
Delaware Basin [Member] | 2020
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	37,430
Delaware Basin [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	21,307
Delaware Basin [Member] | 2022
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, 2021
Water [Member] | Wattenberg Field
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	34,137
Water [Member] | Wattenberg Field | 2019
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	3,103
Water [Member] | Wattenberg Field | 2020
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	6,207
Water [Member] | Wattenberg Field | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	6,207
Water [Member] | Wattenberg Field | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	6,207
Water [Member] | Wattenberg Field | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	12,413
Water [Member] | Wattenberg Field | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Dec. 31, 2024
Water [Member] | Delaware Basin [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	16,380
Water [Member] | Delaware Basin [Member] | 2019
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	3,650
Water [Member] | Delaware Basin [Member] | 2020
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	3,660
Water [Member] | Delaware Basin [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	3,650
Water [Member] | Delaware Basin [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	3,650
Water [Member] | Delaware Basin [Member] | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	1,770
Water [Member] | Delaware Basin [Member] | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Jun. 26, 2023
Crude Oil [Member] | Wattenberg Field
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	29,761
Crude Oil [Member] | Wattenberg Field | 2019
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	9,713
Crude Oil [Member] | Wattenberg Field | 2020
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	5,918
Crude Oil [Member] | Wattenberg Field | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	5,475
Crude Oil [Member] | Wattenberg Field | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	5,475
Crude Oil [Member] | Wattenberg Field | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	3,180
Crude Oil [Member] | Wattenberg Field | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Apr. 30, 2023
Crude Oil [Member] | Delaware Basin [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	40,233
Crude Oil [Member] | Delaware Basin [Member] | 2019
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	7,359
Crude Oil [Member] | Delaware Basin [Member] | 2020
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	8,784
Crude Oil [Member] | Delaware Basin [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	8,030
Crude Oil [Member] | Delaware Basin [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	8,030
Crude Oil [Member] | Delaware Basin [Member] | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	8,030
Crude Oil [Member] | Delaware Basin [Member] | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Dec. 31, 2023
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
Water [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	50,517
Water [Member] | 2019
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	6,753
Water [Member] | 2020
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,867
Water [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,857
Water [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,857
Water [Member] | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	14,183
Crude Oil [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	69,994
Crude Oil [Member] | 2019
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	17,072
Crude Oil [Member] | 2020
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	14,702
Crude Oil [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	13,505
Crude Oil [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	13,505
Crude Oil [Member] | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	11,210
Minimum [Member] | Delaware Basin [Member]
Supply Commitment [Line Items]
Committed Barrels of Crude Oil per day | bbl	14,600
Maximum [Member] | Delaware Basin [Member]
Supply Commitment [Line Items]
Committed Barrels of Crude Oil per day | bbl	26,400

COMMITMENTS AND CONTINGENCIES M

COMMITMENTS AND CONTINGENCIES Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2018USD ($)
Minimum Future Lease Payments under Non-cancelable Operating Leases [Line Items]
2,019	$ 6,273
2,020	6,365
2,021	6,290
2,022	5,229
2,023	1,385
Thereafter	2,256
Total	$ 27,798

COMMITMENTS AND CONTINGENCIES A

COMMITMENTS AND CONTINGENCIES Additional information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Oct. 23, 2018
Loss Contingencies [Line Items]
Transportation, gathering and processing expenses	$ 37,403,000	$ 33,220,000	$ 18,415,000
AOC penalty				$ 130,000
AOC penalty suspended percentage				20.00%
Operating Lease Expense	26,700,000	$ 17,200,000	$ 10,200,000
Delaware Basin/Wattenberg Field [Member]
Loss Contingencies [Line Items]
Transportation, gathering and processing expenses	1,600,000
Utica Shale natural gas and Wattenberg Field crude oil [Member]
Loss Contingencies [Line Items]
Transportation, gathering and processing expenses	$ 10,000,000

COMMITMENTS AND CONTINGENCIES L

COMMITMENTS AND CONTINGENCIES Long-term fIrm transportation costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Transportation, gathering and processing expenses	$ 37,403	$ 33,220	$ 18,415
Utica Shale natural gas and Wattenberg Field crude oil [Member]
Loss Contingencies [Line Items]
Transportation, gathering and processing expenses	$ 10,000

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES Commitments and Contingencies New Plant (Details)	12 Months Ended
	Dec. 31, 2018bbl
Natural Gas [Member]
Supply Commitment [Line Items]
Qualitative and Quantitative Information, Transferor's Continuing Involvement, Third Party Commitments	200
Delaware Basin [Member] | Minimum [Member]
Supply Commitment [Line Items]
Committed Barrels of Crude Oil per day	14,600

COMMITMENTS AND CONTINGENCIES_4

COMMITMENTS AND CONTINGENCIES Commitments and Contingencies Clean Air Act (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Commitments and Contingencies Clean Air Act [Abstract]
Supplemental environmental legal expense paid	$ 1.5
Supplemental environment projects legal expense	1
Injunctive relief legal expense accrual	18
Mitigation legal expense accrual	$ 1.7

COMMON STOCK Stock based compen

COMMON STOCK Stock based compensation plans (Details) - shares	Dec. 31, 2018	Dec. 31, 2017
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Common Stock, Shares Authorized	150,000,000	150,000,000
Common stock shares remain avaliable for issuance	284,152

COMMON STOCK Stocked Based Comp

COMMON STOCK Stocked Based Compensation Summary (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance	1,800,000
Stock-based compensation expense	$ 21,782	$ 19,353	$ 19,502
Income tax benefit	(5,210)	(7,372)	(7,296)
Net stock-based compensation expense	$ 16,572	$ 11,981	$ 12,206

COMMON STOCK SARs Fair Value As

COMMON STOCK SARs Fair Value Assumptions (Details) - Stock Appreciation Rights (SARs) [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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 generally 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 executive officers 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
Risk-free interest rate		2.00%	1.80%
Expected Volatility		53.30%	54.50%
Weighted-average grant date fair value per share		$ 38.58	$ 26.96

COMMON STOCK Schedule of Change

COMMON STOCK Schedule of Changes in SARs (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share based compesation aggregate intrinsic valu [Roll Forward]
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent				$ 63,969
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period	(71,931)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$ 46.34
Stock Appreciation Rights (SARs) [Member]
Number of SARs
Outstanding beginning of year, January 1,	298,220	244,078	326,453
Awarded	0	54,142	58,709
Exercised	0	0	(141,084)
Outstanding end of year, December 31,	290,258	298,220	244,078
Exercisable at December 31,				260,101	223,865	174,919
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Outstanding beginning of year, January 1,	$ 47.39	$ 41.36	$ 38.99
Awarded	0	74.57	51.63
Exercised	0	0	40.16
Outstanding end of year, December 31,	$ 46.64	$ 47.39	$ 41.36
Exercisable at December 31,				$ 44.88	$ 43.28	$ 38.72
Weighted-Average Remaining Contractual Term (in years)
Outstanding at December 31,	4 years 7 months 6 days	6 years 6 months
Exercisable at December 31,	4 years 3 months 20 days
Share based compesation aggregate intrinsic valu [Roll Forward]
Outstanding beginning of year, January 1,	$ 125,000	$ 2,490,000	$ 7,620,000	$ 125,000	$ 2,490,000	$ 7,620,000	$ 4,697,000
Awarded	0	0	0
Exercised	0	0	2,770,000
Outstanding end of year, December 31,	$ 125,000	$ 2,490,000	$ 7,620,000
Exercisable at December 31,				125,000	$ 2,267,000	$ 5,924,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized				$ 500,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	5 months 24 days

COMMON STOCK Schedule of Chan_2

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, 2018	Dec. 31, 2017	Dec. 31, 2016
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,	472,132
Granted	446,743
Vested	(249,317)
Forfeited	(51,151)
Outstanding end of year, December 31,	618,407	472,132
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 60.23
Weighted-average grant date fair value per share	50.69	$ 65.14	$ 58.52
Vested	58.95
Forfeited	56.45
Outstanding at end of year, December 31,	$ 54.16	$ 60.23
Total intrinsic value of time based awards vested	$ 12,282	$ 16,303	$ 18,973
Total intrinsic value of time-based awards non-vested	$ 18,404	$ 24,334	$ 34,812
Market price per common share as of December 31,	$ 29.76	$ 51.54	$ 72.58
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 20,700
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 9 months 20 days

COMMON STOCK Restricted Stock -

COMMON STOCK Restricted Stock - Market Based Awards Fair Value Assumptions (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	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	12,115	21,401
Restricted Stock - Market Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 9 months 20 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	$ 620	$ 2,687	$ 6,562
Expected term of award	3 years	3 years	3 years
Risk-free interest rate	2.40%	1.40%	1.20%
Expected Volatility	42.30%	51.40%	52.30%
Weighted-average grant date fair value per share	$ 69.98	$ 94.02	$ 72.54
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 shares 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
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Range	0.00%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Range	200.00%

COMMON STOCK Schedule of Chan_3

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, 2018	Dec. 31, 2017	Dec. 31, 2016
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	$ 620	$ 2,687	$ 6,562
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 shares 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	90,778
Number of Shares
Outstanding beginning of year, January 1,	52,349
Granted	90,778
Vested	(18,941)
Forfeited	(21,272)
Outstanding end of year, December 31,	102,914	52,349
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 84.06
Weighted-average grant date fair value per share	69.98	$ 94.02	$ 72.54
Vested	72.54
Forfeited	78.65
Outstanding at end of year, December 31,	$ 74.88	$ 84.06
Total intrinsic value of market-based awards non-vested	$ 3,063	$ 2,698	$ 3,514
Market price per common share as of December 31,	$ 29.76	$ 51.54	$ 72.58
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 4,700
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 9 months 20 days

COMMON STOCK Treasury Shares (D

COMMON STOCK Treasury Shares (Details) - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Held in Employee Trust, Shares	12,115	21,401
Treasury Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Treasury Stock, Shares, Acquired	102,647	107,357
Treasury stock acquired and reissued	104,068	83,228
Treasury stock acquired, and available for reissuance	33,105	34,526

COMMON STOCK Preferred Stock (D

COMMON STOCK Preferred Stock (Details) - shares	Dec. 31, 2018	Dec. 31, 2017	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

INCOME TAXES Provision for Inco

INCOME TAXES Provision for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Current Federal Tax Benefit (Expense)	$ 886	$ 8,443	$ 9,646
Current State and Local Tax Benefit (Expense)	(188)	(200)	300
Current Income Tax Benefit (Expense)	698	8,243	9,946
Deferred Federal Income Tax Benefit (Expense)	(1,986)	193,809	118,427
Deferred State and Local Income Tax Benefit (Expense)	(4,118)	9,876	18,822
Deferred Income Tax Benefit (Expense)	(6,104)	203,685	137,249
Provision for income taxes	$ (5,406)	$ 211,928	$ 147,195

INCOME TAXES Reconciliation of

INCOME TAXES Reconciliation of Statutory Rate to Effective Rate (Details)	12 Months Ended
	Dec. 31, 2018Rate	Dec. 31, 2017Rate	Dec. 31, 2016Rate
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Statutory tax rate	21.00%	35.00%	35.00%
State income tax, net	(6.40%)	1.80%	2.60%
Federal tax credits	(52.10%)	0.00%	0.00%
Effect of state income tax rate changes	6.70%	0.00%	0.60%
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent	45.50%	0.00%	0.00%
Non-deductible compensation	21.80%	(0.30%)	(0.50%)
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Other, Amount	31.80%	0.00%	0.00%
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	4.90%	0.00%	0.00%
Federal tax reform rate reduction	0.00%	33.70%	0.00%
Non-deductible goodwill impairment	0.00%	(7.70%)	0.00%
Other	(0.40%)	(0.10%)	(0.30%)
Effective Income Tax Rate Reconciliation, Percent	72.80%	62.40%	37.40%

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, 2018	Dec. 31, 2017
Components of Deferred Tax Assets [Abstract]
Deferred compensation	$ 9,963	$ 6,059
Asset retirement obligations	27,166	21,760
deferred tax assets, federal tax	54,736	19,386
State NOL and tax credit carryforwards, net	13,223	7,815
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	7,756	4,366
Deferred Tax Assets, Derivative Instruments	0	20,929
Deferred Tax Assets, Tax Deferred Expense, Other	5,288	0
Other	4,647	2,453
Deferred Tax Assets, Valuation Allowance, Current	(3,380)	0
Deferred tax assets	(119,399)	82,768
Components of Deferred Tax Liabilities [Abstract]
properties and equipment	270,565	267,498
Deferred Tax Liabilities, Derivatives	41,496	0
Convertible debt	5,434	7,262
Total gross deferred tax liabilities	317,495	274,760
Net deferred tax liability	$ 198,096	$ 191,992

INCOME TAXES Additional Informa

INCOME TAXES Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards:
Combined federal and state deferred tax rate			23.90%
Deferred Tax Liabilities, Property, Plant and Equipment	$ 267,498	$ 270,565	$ 267,498
Federal tax reform rate reduction		0.00%	33.70%	0.00%
Effective Income Tax Rate Reconciliation, Percent		72.80%	62.40%	37.40%
Net deferred tax liability	191,992	$ 198,096	$ 191,992
Income Tax Expense (Benefit)		6,105	(203,685)	$ (137,249)
Deferred Tax Assets, Operating Loss Carryforwards		169,100
Deferred tax asset, operating loss carryforward, annual limitation		15,100
Operating Loss Carryforwards	31,500		31,500
Alternative minimum tax - credit carryforward	4,366	7,756	$ 4,366
Gas Well Credit [Member]
Operating Loss Carryforwards:
Tax Credit Carryforward, Amount		5,100
amt tax credit [Member]
Operating Loss Carryforwards:
Alternative minimum tax - credit carryforward		2,700
State NOL Carryforwards
Operating Loss Carryforwards:
State NOL carryforwards		$ 284,600
Year Carryforwards Expire		Dec. 31, 2030
State Credit Carryforwards
Operating Loss Carryforwards:
State credit carryforwards		$ 3,300
Year Carryforwards Expire		Dec. 31, 2022
Delaware Basin Acquisition [Member]
Operating Loss Carryforwards:
Deferred Tax Assets, Operating Loss Carryforwards		$ 60,100
2017 Tax Act [Member]
Operating Loss Carryforwards:
Income Tax Expense (Benefit)	$ 114,400

EARNINGS PER SHARE Earnings Per

EARNINGS PER SHARE Earnings Per Share (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Weighted-Average Diluted Shares Outstanding
Weighted average common shares outstanding - basic	66,059	65,837	49,052
Weighted Average Number of Shares Outstanding - Diluted	66,303	65,837	49,052
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	254	665	1,090
Convertible Senior Note
Convertible Note, Number of Shares Convertible			2,300
Convertible Note, Conversion Price			$ 85.39
Restricted Stock [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	173	0	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	145	590	689
1.125% Convertible Senior Notes due 2021 [Member]
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	0	292
Other Equity-Based Awards
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	71	0	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	109	75	109

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION Cash payments (receipts) for: (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Interest Paid, Excluding Capitalized Interest, Operating Activities	$ 55,586	$ 69,880	$ 43,406
Income Taxes Paid, Net	$ (6,719)	$ (13,925)	$ 167

SUPPLEMENTAL CASH FLOW INFORM_4

SUPPLEMENTAL CASH FLOW INFORMATION Non-cash investing and financing activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	$ 0	$ 0	$ 690,702
Capital Expenditures Incurred but Not yet Paid	36,328	50,761	(40,448)
Noncash Change In Asset Retirement Obligation	37,136	839	4,894
Capital Lease Obligations Incurred	$ 1,940	$ 3,497	$ 1,404

SUBSIDIARY GUARANTOR SUBSIDIA_3

SUBSIDIARY GUARANTOR SUBSIDIARY GUARANTOR BALANCE SHEET (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Cash and cash equivalents	$ 1,398,000	$ 180,675,000
Accounts receivable, net	181,434,000	197,598,000
Fair value of derivatives	84,492,000	14,338,000
Prepaid expenses and other current assets	7,136,000	8,613,000
Assets, Current	274,460,000	401,224,000
Properties and equipment, net	4,002,862,000	3,933,467,000
Assets held-for-sale	140,705,000	40,583,000
Intercompany Receivables	0	0
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	0	0
Fair value of derivatives	93,722,000	0
Other assets	32,396,000	45,116,000
Assets	4,544,145,000	4,420,390,000
Accounts payable	181,864,000	150,067,000
Production tax liability	60,719,000	37,654,000
Fair value of derivatives	3,364,000	79,302,000
Funds held for distribution	105,784,000	95,811,000
Accrued interest payable	14,150,000	11,815,000
Other accrued expenses	75,133,000	42,987,000
Liabilities, Current	441,014,000	417,636,000
Intercompany Payable	0	0
Long-term debt	1,194,876,000	1,151,932,000
Deferred income taxes	198,096,000	191,992,000
Asset retirement obligations	85,312,000	71,006,000
Disposal Group, Including Discontinued Operation, Liabilities	4,111,000	499,000
Fair value of derivatives	1,364,000	22,343,000
Other liabilities	92,664,000	57,333,000
Liabilities	2,017,437,000	1,912,741,000
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,148,609 and 65,955,080 issued as of December 31, 2018 and 2017, respectively	661,000	659,000
Additional paid-in capital	2,519,423,000	2,503,294,000
Retained earnings	8,727,000	6,704,000
Treasury Stock, Value	2,103,000	3,008,000
Stockholders' Equity Attributable to Parent	2,526,708,000	2,507,649,000
Liabilities and Equity	4,544,145,000	4,420,390,000
Corporate, Non-Segment [Member]
Cash and cash equivalents	1,398,000	180,675,000
Accounts receivable, net	146,529,000	160,490,000
Fair value of derivatives	84,492,000	14,338,000
Prepaid expenses and other current assets	6,725,000	8,284,000
Assets, Current	239,144,000	363,787,000
Properties and equipment, net	2,270,711,000	1,891,314,000
Assets held-for-sale	0	40,583,000
Intercompany Receivables	451,601,000	250,279,000
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	1,316,945,000	1,617,537,000
Fair value of derivatives	93,722,000
Other assets	30,084,000	42,547,000
Assets	4,402,207,000	4,206,047,000
Accounts payable	110,847,000	85,000,000
Production tax liability	53,309,000	35,902,000
Fair value of derivatives	3,364,000	79,302,000
Funds held for distribution	90,183,000	83,898,000
Accrued interest payable	14,143,000	11,812,000
Other accrued expenses	73,689,000	42,543,000
Liabilities, Current	345,535,000	338,457,000
Intercompany Payable	0	0
Long-term debt	1,194,876,000	1,151,932,000
Deferred income taxes	162,368,000	62,857,000
Asset retirement obligations	79,904,000	65,301,000
Disposal Group, Including Discontinued Operation, Liabilities	0	499,000
Fair value of derivatives	1,364,000	22,343,000
Other liabilities	91,452,000	57,009,000
Liabilities	1,875,499,000	1,698,398,000
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,148,609 and 65,955,080 issued as of December 31, 2018 and 2017, respectively	661,000	659,000
Additional paid-in capital	2,519,423,000	2,503,294,000
Retained earnings	8,727,000	6,704,000
Treasury Stock, Value	2,103,000	3,008,000
Stockholders' Equity Attributable to Parent	2,526,708,000	2,507,649,000
Liabilities and Equity	4,402,207,000	4,206,047,000
Reportable Legal Entities [Member]
Cash and cash equivalents	0	0
Accounts receivable, net	34,905,000	37,108,000
Fair value of derivatives	0	0
Prepaid expenses and other current assets	411,000	329,000
Assets, Current	35,316,000	37,437,000
Properties and equipment, net	1,732,151,000	2,042,153,000
Assets held-for-sale	140,705,000	0
Intercompany Receivables	0	0
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	0	0
Fair value of derivatives	0
Other assets	2,312,000	2,569,000
Assets	1,910,484,000	2,082,159,000
Accounts payable	71,017,000	65,067,000
Production tax liability	7,410,000	1,752,000
Fair value of derivatives	0	0
Funds held for distribution	15,601,000	11,913,000
Accrued interest payable	7,000	3,000
Other accrued expenses	1,444,000	444,000
Liabilities, Current	95,479,000	79,179,000
Intercompany Payable	451,601,000	250,279,000
Long-term debt	0	0
Deferred income taxes	35,728,000	129,135,000
Asset retirement obligations	5,408,000	5,705,000
Disposal Group, Including Discontinued Operation, Liabilities	4,111,000	0
Fair value of derivatives	0	0
Other liabilities	1,212,000	324,000
Liabilities	593,539,000	464,622,000
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,148,609 and 65,955,080 issued as of December 31, 2018 and 2017, respectively	0	0
Additional paid-in capital	1,766,775,000	1,766,775,000
Retained earnings	(449,830,000)	(149,238,000)
Treasury Stock, Value	0	0
Stockholders' Equity Attributable to Parent	1,316,945,000	1,617,537,000
Liabilities and Equity	1,910,484,000	2,082,159,000
Consolidation, Eliminations [Member]
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
Assets, Current	0	0
Properties and equipment, net	0	0
Assets held-for-sale	0	0
Intercompany Receivables	(451,601,000)	(250,279,000)
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	(1,316,945,000)	(1,617,537,000)
Fair value of derivatives	0
Other assets	0	0
Assets	(1,768,546,000)	(1,867,816,000)
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
Liabilities, Current	0	0
Intercompany Payable	(451,601,000)	(250,279,000)
Long-term debt	0	0
Deferred income taxes	0	0
Asset retirement obligations	0	0
Disposal Group, Including Discontinued Operation, Liabilities	0	0
Fair value of derivatives	0	0
Other liabilities	0	0
Liabilities	(451,601,000)	(250,279,000)
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,148,609 and 65,955,080 issued as of December 31, 2018 and 2017, respectively	0	0
Additional paid-in capital	(1,766,775,000)	(1,766,775,000)
Retained earnings	449,830,000	149,238,000
Treasury Stock, Value	0	0
Stockholders' Equity Attributable to Parent	(1,316,945,000)	(1,617,537,000)
Liabilities and Equity	$ (1,768,546,000)	$ (1,867,816,000)

SUBSIDIARY GUARANTOR SUBSIDIA_4

SUBSIDIARY GUARANTOR SUBSIDIARY GUARANTOR INCOME STATEMENT (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Results of Operations, Revenue from Oil and Gas Producing Activities									$ 1,389,961	$ 913,084	$ 497,353
Commodity price risk management gain (loss), net									145,237	(3,936)	(125,681)
Other income									13,461	12,468	11,243
Revenues	$ 794,811	$ 280,717	$ 212,531	$ 260,600	$ 189,516	$ 183,235	$ 275,158	$ 273,707	1,548,659	921,616	382,915
Lease operating expenses									130,957	89,641	59,950
Production taxes									90,357	60,717	31,410
Transportation, gathering and processing expenses									37,403	33,220	18,415
Exploration, geologic and geophysical expense									6,204	47,334	4,669
Impairment of properties and equipment									458,397	285,887	9,973
Impairment of goodwill									0	75,121	0
General and administrative expense									170,504	120,370	112,470
Depreciation, depletion and amortization									559,793	469,084	416,874
Accretion of asset retirement obligations									5,075	6,306	7,080
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations									(394)	766	43
Provision for Doubtful Accounts									0	(40,203)	44,038
Other expenses									11,829	13,157	10,193
Costs and Expenses	538,626	270,593	400,770	260,924	208,016	579,326	190,522	182,004	1,470,913	1,159,868	715,029
Operating Income (Loss)	256,185	10,124	(188,239)	(324)	(18,500)	(396,091)	84,636	91,703	77,746	(238,252)	(332,114)
Gain (Loss) on Extinguishment of Debt									0	(24,747)	0
Interest Expense									70,730	78,694	61,972
Interest income									413	2,261	963
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	238,024	(7,310)	(205,580)	(17,705)	62,808	(414,887)	65,787	72,476	7,429	(339,432)	(393,123)
Income Tax Expense (Benefit)									5,406	(211,928)	(147,195)
Income (Loss) from Subsidiaries, Net of Tax									0	0	0
Net income (loss)	$ 178,853	$ (3,434)	$ (160,257)	$ (13,139)	$ 77,637	$ (292,537)	$ 41,250	$ 46,146	2,023	(127,504)	(245,928)
Reportable Legal Entities [Member]
Results of Operations, Revenue from Oil and Gas Producing Activities									339,265	124,684	5,603
Commodity price risk management gain (loss), net									0	0	0
Other income									2,717	567	2
Revenues									341,982	125,251	5,605
Lease operating expenses									38,729	21,610	1,549
Production taxes									22,538	7,481	278
Transportation, gathering and processing expenses									20,796	9,919	152
Exploration, geologic and geophysical expense									4,970	46,242	3,472
Impairment of properties and equipment									458,370	280,936	0
Impairment of goodwill										75,121
General and administrative expense									17,706	12,852	304
Depreciation, depletion and amortization									169,952	65,100	1,553
Accretion of asset retirement obligations									458	341	10
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations									(4,781)	0	0
Provision for Doubtful Accounts										0	0
Other expenses									0	0	0
Costs and Expenses									738,300	519,602	7,318
Operating Income (Loss)									(396,318)	(394,351)	(1,713)
Gain (Loss) on Extinguishment of Debt										0
Interest Expense									2,521	1,225	30
Interest income									0	0	0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest									(393,797)	(393,126)	(1,683)
Income Tax Expense (Benefit)									(93,205)	(245,571)	0
Income (Loss) from Subsidiaries, Net of Tax									0	0	0
Net income (loss)									(300,592)	(147,555)	(1,683)
Corporate, Non-Segment [Member]
Results of Operations, Revenue from Oil and Gas Producing Activities									1,050,696	788,400	491,750
Commodity price risk management gain (loss), net									145,237	(3,936)	(125,681)
Other income									10,744	11,901	11,241
Revenues									1,206,677	796,365	377,310
Lease operating expenses									92,228	68,031	58,401
Production taxes									67,819	53,236	31,132
Transportation, gathering and processing expenses									16,607	23,301	18,263
Exploration, geologic and geophysical expense									1,234	1,092	1,197
Impairment of properties and equipment									27	4,951	9,973
Impairment of goodwill										0
General and administrative expense									152,798	107,518	112,166
Depreciation, depletion and amortization									389,841	403,984	415,321
Accretion of asset retirement obligations									4,617	5,965	7,070
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations									4,387	766	43
Provision for Doubtful Accounts										(40,203)	44,038
Other expenses									11,829	13,157	10,193
Costs and Expenses									732,613	640,266	707,711
Operating Income (Loss)									474,064	156,099	(330,401)
Gain (Loss) on Extinguishment of Debt										(24,747)
Interest Expense									73,251	79,919	62,002
Interest income									413	2,261	963
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest									401,226	53,694	(391,440)
Income Tax Expense (Benefit)									98,611	33,643	(147,195)
Income (Loss) from Subsidiaries, Net of Tax									(300,592)	(147,555)	(1,683)
Net income (loss)									2,023	(127,504)	(245,928)
Consolidation, Eliminations [Member]
Results of Operations, Revenue from Oil and Gas Producing Activities									0	0	0
Commodity price risk management gain (loss), net									0	0	0
Other income									0	0	0
Revenues									0	0	0
Lease operating expenses									0	0	0
Production taxes									0	0	0
Transportation, gathering and processing expenses									0	0	0
Exploration, geologic and geophysical expense									0	0	0
Impairment of properties and equipment									0	0	0
Impairment of goodwill										0
General and administrative expense									0	0	0
Depreciation, depletion and amortization									0	0	0
Accretion of asset retirement obligations									0	0	0
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations									0	0	0
Provision for Doubtful Accounts										0	0
Other expenses									0	0	0
Costs and Expenses									0	0	0
Operating Income (Loss)									0	0	0
Gain (Loss) on Extinguishment of Debt										0
Interest Expense									0	0	0
Interest income									0	0	0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest									0	0	0
Income Tax Expense (Benefit)									0	0	0
Income (Loss) from Subsidiaries, Net of Tax									300,592	147,555	1,683
Net income (loss)									$ 300,592	$ 147,555	$ 1,683

SUBSIDIARY GUARANTOR SUBSIDIA_5

SUBSIDIARY GUARANTOR SUBSIDIARY GUARANTOR CASH FLOWS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net Cash Provided by (Used in) Operating Activities	$ 889,302	$ 597,813	$ 486,263
Payments to Explore and Develop Oil and Gas Properties	946,350	737,208	436,884
Payments for Capital Improvements	11,055	5,094	3,464
Payments to Acquire Businesses, Net of Cash Acquired	180,026	15,628	1,073,723
Proceeds from sale of properties and equipment	(3,562)	(9,991)	(4,945)
Proceeds from divestiture	44,693	0	0
Proceeds from Sale of Notes Receivable		40,203
Increase (Decrease) in Restricted Cash	(1,249)	9,250	0
Sale of short-term investments	0	49,890	0
Payments to Acquire Short-term Investments		49,890
intercompany Transfer Investing Activities	0	0	0
Net Cash Provided by (Used in) Investing Activities	(1,087,927)	(716,986)	(1,509,126)
Proceeds from issuance of senior notes	0	592,366	392,172
Proceeds from issuance of convertible senior notes	0	0	193,935
Redemption of convertible notes	0	0	(115,000)
Redemption of senior notes	0	(519,375)	0
Proceeds from Lines of Credit	1,072,500		85,000
Repayments of Lines of Credit	1,040,000	0	122,000
Proceeds from issuance of equity, net of issuance costs	0	0	855,074
Payment of debt issuance costs	(7,704)	(50)	(15,556)
Treasury Stock, Value, Acquired, Cost Method	(5,147)	(6,672)	(6,935)
Other	(1,550)	(1,271)	(577)
Intercompany Transfers Financing Activities	0	0	0
Net Cash Provided by (Used in) Financing Activities	18,099	64,998	1,266,113
Net change in cash, cash equivalents and restricted cash	(180,526)	(54,175)	243,250
Cash, cash equivalents and restricted cash, beginning of year	189,925	244,100	850
Cash, cash equivalents and restricted cash, end of year	9,399	189,925	244,100
Corporate, Non-Segment [Member]
Net Cash Provided by (Used in) Operating Activities	625,206	546,954	492,893
Payments to Explore and Develop Oil and Gas Properties	482,534	439,897	436,361
Payments for Capital Improvements	9,806	3,539	2,282
Payments to Acquire Businesses, Net of Cash Acquired	179,955	21,000	1,076,256
Proceeds from sale of properties and equipment	(1,929)	(10,084)	(4,945)
Proceeds from divestiture	44,693
Proceeds from Sale of Notes Receivable		40,203
Increase (Decrease) in Restricted Cash	(1,249)
intercompany Transfer Investing Activities	(199,584)	(239,191)	(9,415)
Net Cash Provided by (Used in) Investing Activities	(824,008)	(662,590)	(1,519,369)
Proceeds from issuance of senior notes		592,366	392,172
Proceeds from issuance of convertible senior notes			193,935
Redemption of convertible notes			(115,000)
Redemption of senior notes		(519,375)
Proceeds from Lines of Credit	1,072,500		85,000
Repayments of Lines of Credit	1,040,000		122,000
Proceeds from issuance of equity, net of issuance costs			855,074
Payment of debt issuance costs	7,704	50	15,556
Treasury Stock, Value, Acquired, Cost Method	5,147	6,672	6,935
Other	(1,373)	(1,195)	(577)
Intercompany Transfers Financing Activities	0	0	0
Net Cash Provided by (Used in) Financing Activities	18,276	65,074	1,266,113
Net change in cash, cash equivalents and restricted cash	(180,526)	(50,562)	239,637
Cash, cash equivalents and restricted cash, beginning of year	189,925	240,487	850
Cash, cash equivalents and restricted cash, end of year	9,399	189,925	240,487
Reportable Legal Entities [Member]
Net Cash Provided by (Used in) Operating Activities		50,859	(6,630)
Payments to Explore and Develop Oil and Gas Properties		297,311	523
Payments for Capital Improvements		1,555	1,182
Payments to Acquire Businesses, Net of Cash Acquired		5,372	2,533
Proceeds from sale of properties and equipment		(93)	0
Proceeds from Sale of Notes Receivable		0
intercompany Transfer Investing Activities		0	0
Net Cash Provided by (Used in) Investing Activities		(293,587)	828
Consolidation, Eliminations [Member]
Net Cash Provided by (Used in) Operating Activities	0	0	0
Payments to Explore and Develop Oil and Gas Properties	0	0	0
Payments for Capital Improvements	0	0	0
Payments to Acquire Businesses, Net of Cash Acquired	0	0	0
Proceeds from sale of properties and equipment	0	0	0
Proceeds from divestiture	0
Proceeds from Sale of Notes Receivable		0
Increase (Decrease) in Restricted Cash	0	0
Sale of short-term investments		0
Payments to Acquire Short-term Investments		0
intercompany Transfer Investing Activities	199,584	239,191	9,415
Net Cash Provided by (Used in) Investing Activities	199,584	239,191	9,415
Proceeds from issuance of senior notes		0	0
Proceeds from issuance of convertible senior notes			0
Redemption of convertible notes			0
Redemption of senior notes		0
Proceeds from Lines of Credit	0		0
Repayments of Lines of Credit	0		0
Proceeds from issuance of equity, net of issuance costs			0
Payment of debt issuance costs	0	0	0
Treasury Stock, Value, Acquired, Cost Method	0	0	0
Other	0	0	0
Intercompany Transfers Financing Activities	(199,584)	(239,191)	(9,415)
Net Cash Provided by (Used in) Financing Activities	(199,584)	(239,191)	(9,415)
Net change in cash, cash equivalents and restricted cash	0	0	0
Cash, cash equivalents and restricted cash, beginning of year	0	0	0
Cash, cash equivalents and restricted cash, end of year	0	0	0
Parent Company [Member] | Reportable Legal Entities [Member]
Increase (Decrease) in Restricted Cash		9,250
Sale of short-term investments		49,890
Payments to Acquire Short-term Investments		49,890
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Net Cash Provided by (Used in) Operating Activities	264,096
Payments to Explore and Develop Oil and Gas Properties	463,816
Payments for Capital Improvements	1,249
Payments to Acquire Businesses, Net of Cash Acquired	71
Proceeds from sale of properties and equipment	(1,633)
Proceeds from divestiture	0
Increase (Decrease) in Restricted Cash	0	0
Sale of short-term investments		0
Payments to Acquire Short-term Investments		0
intercompany Transfer Investing Activities	0
Net Cash Provided by (Used in) Investing Activities	(463,503)
Proceeds from issuance of senior notes		0	0
Proceeds from issuance of convertible senior notes			0
Redemption of convertible notes			0
Redemption of senior notes		0
Proceeds from Lines of Credit	0		0
Repayments of Lines of Credit	0		0
Proceeds from issuance of equity, net of issuance costs			0
Payment of debt issuance costs	0	0	0
Treasury Stock, Value, Acquired, Cost Method	0	0	0
Other	(177)	(76)	0
Intercompany Transfers Financing Activities	199,584	239,191	9,415
Net Cash Provided by (Used in) Financing Activities	199,407	239,115	9,415
Net change in cash, cash equivalents and restricted cash	0	(3,613)	3,613
Cash, cash equivalents and restricted cash, beginning of year	0	3,613	0
Cash, cash equivalents and restricted cash, end of year	$ 0	$ 0	$ 3,613

SUPPLEMENTAL INFORMATION - NA_3

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Index price of reserves (Details) - USD ($)		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Crude Oil [Member]
oil and gas index price for reserves [Line Items]
oil and gas index price for reserves	[1]	$ 65.56	$ 51.34	$ 42.75
Natural Gas (Mcf)
oil and gas index price for reserves [Line Items]
oil and gas index price for reserves	[1]	3.10	2.98	2.48
Natural Gas Liquids (Bbls)
oil and gas index price for reserves [Line Items]
oil and gas index price for reserves	[1]	$ 65.56	$ 51.34	$ 42.75
[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 - NA_4

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Prices Used to Estimate Reserves (Unaudited) (Details) - USD ($)		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Crude Oil [Member]
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	[1]	$ 61.14	$ 48.68	$ 38.67
Natural Gas (Mcf)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	[1]	2.15	2.31	1.85
Natural Gas Liquids (Bbls)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	[1],[2]	$ 23.04	$ 20.21	$ 11.97
[1]	These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and 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 - NA_5

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Changes in Estimated Proved Reserves (Unaudited) (Details) bbl in Thousands, Mcf in Thousands, MBbls in Thousands, MMBoe in Millions	12 Months Ended
	Dec. 31, 2018RatebblMcf	Dec. 31, 2018bblMcf	Dec. 31, 2018MBblsbblMcf	Dec. 31, 2018bblMcf	Dec. 31, 2018MMBoebblMcf	Dec. 31, 2018bblMcf	Dec. 31, 2017RatebblMcf	Dec. 31, 2017MBblsbblMcf	Dec. 31, 2017bblMcf	Dec. 31, 2017MMBoebblMcf	Dec. 31, 2017bblMcf	Dec. 31, 2016MMBblsbblMcf	Dec. 31, 2016RatebblMcf	Dec. 31, 2016MBblsbblMcf	Dec. 31, 2016bblMcf	Dec. 31, 2016bblMcf	Dec. 31, 2015bblMcf
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | MMBoe					92
Proved developed and undeveloped reserves percent increase or decrease | Rate	20.00%
Proved Reserves	544,953	544,953	544,953	544,953	544,953	544,953	452,917	452,917	452,917	452,917	452,917	341,407	341,407	341,407	341,407	341,407	272,825
Production				(40,160)					(31,830)						(22,176)
Undeveloped Reserves Converted to Developed				0					0						0
Purchases of Reserves				60,360					86,778						133,583
Dispositions				11,121					1,900						1,725
Extensions, Discoveries, and Other Additions				27,946					6,005						1,531
Revisions of Previous Estimates				55,011					52,457						(42,631)
Increase or Decrease in Proved Reserves									111,500
Proved Undeveloped Reserves [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | MMBoe										68.6
Proved Reserves	365,418	365,418	365,418	365,418	365,418	365,418	309,946	309,946	309,946	309,946	309,946	243,122	243,122	243,122	243,122	243,122	202,329
Production				0					0						0
Undeveloped Reserves Converted to Developed				(58,294)					(54,648)						(32,192)
Purchases of Reserves				51,602					85,473						123,354
Acquisition Of Reserves Acreage Swaps | MBbls			47,600											98,100
Acquisition Of Reserves Acquisition | MBbls			4,000											25,300
Dispositions				6,635					1,880					1,600	1,626
Extensions, Discoveries, and Other Additions				20,072					3,713						0
Gross PUD locations		16
Net PUD locations		15
Revisions of Previous Estimates			71,700	48,727				89,800	34,166					61,000	(48,743)
Upward Downward revisions Wattenberg Field related to PUDs that are no longer in our core drilling area | MBbls			26,800					58,500						10,800
Majority of upward downward revision of our previous estimate of proved reserves | MBbls			3,800					2,900						1,500
Actual PUD conversion rate | Rate	19.00%
Proved Developed Reserves [Member]
Reserve Quantities [Line Items]
Proved Reserves	179,535	179,535	179,535	179,535	179,535	179,535	142,971	142,971	142,971	142,971	142,971	98,285	98,285	98,285	98,285	98,285	70,496
Production				(40,160)					(31,830)						(22,176)
Upward (Downward) Revision due to change in SEC pricing | MBbls			11,400					17,700
Proved Developed Reserves Revisions Of Previous Estimates Increase Decrease Operating Costs | MBbls								600						3,500
Undeveloped Reserves Converted to Developed				58,294					54,648						32,192
Purchases of Reserves				8,758					1,305						10,229
Dispositions				4,486					20					99	99
Extensions, Discoveries, and Other Additions				7,874					2,292						1,531
Newly Drilled Wells Gross		17
Newly Drilled Wells Net		9.2
Revisions of Previous Estimates			5,100	6,284					18,291			2,600			6,112
Crude Oil [Member]
Reserve Quantities [Line Items]
Proved Reserves	190,349	190,349	190,349	190,349	190,349	190,349	154,842	154,842	154,842	154,842	154,842	118,169	118,169	118,169	118,169	118,169	98,975
Production				(16,964)					(12,902)						(8,728)
Purchases of Reserves				19,644					18,971						50,126
Dispositions				2,507					653						601
Extensions, Discoveries, and Other Additions				8,786					2,923						494
Revisions of Previous Estimates				26,548					28,334						(22,097)
Proved Developed Reserves	61,821	61,821	61,821	61,821	61,821	61,821	46,862	46,862	46,862	46,862	46,862	30,013	30,013	30,013	30,013	30,013
Proved Undeveloped Reserve	128,528	128,528	128,528	128,528	128,528	128,528	107,980	107,980	107,980	107,980	107,980	88,156	88,156	88,156	88,156	88,156
Natural Gas (Mcf)
Reserve Quantities [Line Items]
Proved Reserves | Mcf	1,335,689	1,335,689	1,335,689	1,335,689	1,335,689	1,335,689	1,154,294	1,154,294	1,154,294	1,154,294	1,154,294	833,697	833,697	833,697	833,697	833,697	660,737
Production | Mcf						(88,017)					(71,689)					(51,730)
Purchases of Reserves | Mcf						148,674					289,223					305,224
Dispositions | Mcf						35,750					4,597					4,202
Extensions, Discoveries, and Other Additions | Mcf						61,750					11,541					4,094
Revisions of Previous Estimates | Mcf						94,738					96,119					(80,426)
Proved Developed Reserves | Mcf	443,151	443,151	443,151	443,151	443,151	443,151	365,332	365,332	365,332	365,332	365,332	264,452	264,452	264,452	264,452	264,452
Proved Undeveloped Reserve | Mcf	892,538	892,538	892,538	892,538	892,538	892,538	788,962	788,962	788,962	788,962	788,962	569,245	569,245	569,245	569,245	569,245
Natural Gas Liquids (Bbls)
Reserve Quantities [Line Items]
Proved Reserves	131,987	131,987	131,987	131,987	131,987	131,987	105,692	105,692	105,692	105,692	105,692	84,288	84,288	84,288	84,288	84,288	63,727
Production				(8,527)					(6,981)						(4,826)
Purchases of Reserves				15,936					19,604						32,586
Dispositions				2,656					481						424
Extensions, Discoveries, and Other Additions				8,868					1,158						355
Revisions of Previous Estimates				12,674					8,104						(7,130)
Proved Developed Reserves	43,856	43,856	43,856	43,856	43,856	43,856	35,220	35,220	35,220	35,220	35,220	24,196	24,196	24,196	24,196	24,196
Proved Undeveloped Reserve	88,131	88,131	88,131	88,131	88,131	88,131	70,472	70,472	70,472	70,472	70,472	60,092	60,092	60,092	60,092	60,092
Crude Oil Equivalent (Boe)
Reserve Quantities [Line Items]
Proved Reserves	544,953	544,953	544,953	544,953	544,953	544,953	452,917	452,917	452,917	452,917	452,917	341,407	341,407	341,407	341,407	341,407	272,825
Production				(40,160)					(31,830)						(22,176)
Purchases of Reserves				60,360					86,778						133,583
Dispositions				11,121					1,900						1,725
Extensions, Discoveries, and Other Additions				27,946					6,005						1,531
Revisions of Previous Estimates				55,011					52,457						(42,631)
Proved Developed Reserves	179,535	179,535	179,535	179,535	179,535	179,535	142,971	142,971	142,971	142,971	142,971	98,284	98,284	98,284	98,284	98,284
Proved Undeveloped Reserve	365,418	365,418	365,418	365,418	365,418	365,418	309,946	309,946	309,946	309,946	309,946	243,122	243,122	243,122	243,122	243,122
Year-over-Year Activity [Domain]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves percent increase or decrease | Rate							33.00%						25.00%
Estimated PUD conversion rate for following year | Rate	16.00%						16.00%

SUPPLEMENTAL INFORMATION - NA_6

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Schedule of Developed and Undeveloped Reserves (Unaudited) (Details) bbl in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2018Ratebbl	Dec. 31, 2018MBblsbbl	Dec. 31, 2018bbl	Dec. 31, 2017Ratebbl	Dec. 31, 2017MBblsbbl	Dec. 31, 2017bbl	Dec. 31, 2016MMBblsbbl	Dec. 31, 2016Ratebbl	Dec. 31, 2016MBblsbbl	Dec. 31, 2016bbl	Dec. 31, 2015bbl
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	544,953	544,953	544,953	452,917	452,917	452,917	341,407	341,407	341,407	341,407	272,825
Undeveloped Reserves Converted to Developed			0			0				0
Revisions of Previous Estimates			55,011			52,457				(42,631)
Extensions, Discoveries, and Other Additions			27,946			6,005				1,531
Purchases of Reserves			60,360			86,778				133,583
Dispositions			(11,121)			(1,900)				(1,725)
Production			(40,160)			(31,830)				(22,176)
Proved developed and undeveloped reserves percent increase or decrease | Rate	20.00%
Increase or Decrease in Proved Reserves						111,500
Proved Undeveloped Reserves [Member]
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	365,418	365,418	365,418	309,946	309,946	309,946	243,122	243,122	243,122	243,122	202,329
Undeveloped Reserves Converted to Developed			(58,294)			(54,648)				(32,192)
Revisions of Previous Estimates		71,700	48,727		89,800	34,166			61,000	(48,743)
Extensions, Discoveries, and Other Additions			20,072			3,713				0
Purchases of Reserves			51,602			85,473				123,354
Dispositions			(6,635)			(1,880)			(1,600)	(1,626)
Production			0			0				0
Actual PUD conversion rate | Rate	19.00%
Proved Developed Reserves [Member]
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	179,535	179,535	179,535	142,971	142,971	142,971	98,285	98,285	98,285	98,285	70,496
Undeveloped Reserves Converted to Developed			58,294			54,648				32,192
Revisions of Previous Estimates		5,100	6,284			18,291	2,600			6,112
Extensions, Discoveries, and Other Additions			7,874			2,292				1,531
Purchases of Reserves			8,758			1,305				10,229
Dispositions			(4,486)			(20)			(99)	(99)
Production			(40,160)			(31,830)				(22,176)
Upward (Downward) Revision due to change in SEC pricing | MBbls		11,400			17,700
Crude Oil Equivalent (Boe)
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	544,953	544,953	544,953	452,917	452,917	452,917	341,407	341,407	341,407	341,407	272,825
Revisions of Previous Estimates			55,011			52,457				(42,631)
Extensions, Discoveries, and Other Additions			27,946			6,005				1,531
Purchases of Reserves			60,360			86,778				133,583
Dispositions			(11,121)			(1,900)				(1,725)
Production			(40,160)			(31,830)				(22,176)
Crude Oil [Member]
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	190,349	190,349	190,349	154,842	154,842	154,842	118,169	118,169	118,169	118,169	98,975
Revisions of Previous Estimates			26,548			28,334				(22,097)
Extensions, Discoveries, and Other Additions			8,786			2,923				494
Purchases of Reserves			19,644			18,971				50,126
Dispositions			(2,507)			(653)				(601)
Production			(16,964)			(12,902)				(8,728)
Year-over-Year Activity [Domain]
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved developed and undeveloped reserves percent increase or decrease | Rate				33.00%				25.00%

SUPPLEMENTAL INFORMATION - NA_7

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Results of Operations for Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) bbl in Thousands, MBbls in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018MBbls	Dec. 31, 2018USD ($)	Dec. 31, 2018bbl	Dec. 31, 2017USD ($)bbl	Dec. 31, 2016MMBbls	Dec. 31, 2016MBbls	Dec. 31, 2016USD ($)	Dec. 31, 2016bbl
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Extensions, Discoveries, and Other Additions | bbl			27,946	6,005				1,531
Purchases of Reserves | bbl			60,360	86,778				133,583
Revisions of Previous Estimates | bbl			55,011	52,457				(42,631)
Production | bbl			40,160	31,830				22,176
Dispositions | bbl			11,121	1,900				1,725
Total Revenues from Oil and Gas Producing Activities		$ 1,389,961		$ 913,084			$ 497,353
Lease operating expenses		130,957		89,641			59,950
Production taxes		90,357		60,717			31,410
Transportation, gathering and processing expenses		37,403		33,220			18,415
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		1,389,961		913,084			497,353
Commodity price risk management		145,237		(3,936)			(125,681)
Total Revenues from Oil and Gas Producing Activities		1,535,198		909,148			371,672
Lease operating expenses		130,957		89,641			59,950
Production taxes		90,357		60,717			31,410
Transportation, gathering and processing expenses		37,403		33,220			18,415
Exploration Expense		6,204		47,334			4,669
Impairment of Oil and Gas Properties		458,397		285,887			9,973
Depreciation, Depletion and Amortization		551,265		462,482			413,105
Accretion of Asset Retirement Obligations		5,075		6,306			7,080
(Gain) loss on Sale of Properties and Equipment		394		(766)			(43)
Total Expense from Oil and Gas Producing Activities		1,280,052		984,821			544,559
Results of Operations of Natural Gas and Crude Oil Producing Activities, Income before Income Taxes		255,146		(75,673)			(172,887)
Provision for Income Taxes		(185,667)		47,247			64,733
Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs		$ 69,479		$ (28,426)			$ (108,154)
Proved Developed Reserves [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Extensions, Discoveries, and Other Additions | bbl			7,874	2,292				1,531
Purchases of Reserves | bbl			8,758	1,305				10,229
Revisions of Previous Estimates	5,100		6,284	18,291	2,600			6,112
Production | bbl			40,160	31,830				22,176
Dispositions			4,486	20		99		99

SUPPLEMENTAL INFORMATION - NA_8

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Costs Incurred in Natural Gas and Crude Oil Property Acquisition, Exploration and Development Activities (Unadited) (Details) bbl in Thousands, MBbls in Thousands, $ in Thousands, MMBoe in Millions		12 Months Ended
		Dec. 31, 2018Rate	Dec. 31, 2018MBbls	Dec. 31, 2018USD ($)	Dec. 31, 2018bbl	Dec. 31, 2018MMBoe	Dec. 31, 2017Rate	Dec. 31, 2017MBbls	Dec. 31, 2017USD ($)	Dec. 31, 2017bbl	Dec. 31, 2017MMBoe	Dec. 31, 2016MMBbls	Dec. 31, 2016Rate	Dec. 31, 2016MBbls	Dec. 31, 2016USD ($)	Dec. 31, 2016bbl
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Dispositions					11,121					1,900						1,725
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | MMBoe						92
Proved Properties | $	[1]			$ 205,253					$ 172						$ 268,567
Unproved Properties | $	[1]			5,477					18,914						1,843,985
Development Costs | $	[2]			970,970					688,165						383,336
Exploratory drilling | $	[3]			36,704					80,103						0
Geological and geophysical | $	[3]			3,401					3,881						4,669
Total Costs Incurred | $	[4]			1,221,805					791,235						2,500,557
Cost Incurred to Convert PUDs to PDNP | $				438,400					463,400						204,600
Cost Incurred to Convert PUDs to PDNP, Infrastructure And Pipeline Costs | $				$ 74,600					32,800
Reduction To Proved, Undeveloped And Development Costs | $	[4]								$ 24,600
Extensions, Discoveries, and Other Additions					27,946					6,005						1,531
Undeveloped Reserves Converted to Developed					0					0						0
Proved developed and undeveloped reserves percent increase or decrease | Rate		20.00%
Increase or Decrease in Proved Reserves										111,500
Purchases of Reserves					60,360					86,778						133,583
Revisions of Previous Estimates					55,011					52,457						(42,631)
Production					40,160					31,830						22,176
Infrastructure And Pipeline Costs [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved Properties | $	[1]														$ 40,900
Year-over-Year Activity [Domain]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Estimated PUD conversion rate for following year | Rate		16.00%					16.00%
Proved developed and undeveloped reserves percent increase or decrease | Rate							33.00%						25.00%
Proved Developed Reserves [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Dispositions					4,486					20				99		99
Extensions, Discoveries, and Other Additions					7,874					2,292						1,531
Undeveloped Reserves Converted to Developed					58,294					54,648						32,192
Purchases of Reserves					8,758					1,305						10,229
Revisions of Previous Estimates			5,100		6,284					18,291		2,600				6,112
Production					40,160					31,830						22,176
Proved Undeveloped Reserves [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Dispositions					6,635					1,880				1,600		1,626
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | MMBoe											68.6
Extensions, Discoveries, and Other Additions					20,072					3,713						0
Actual PUD conversion rate | Rate		19.00%
Undeveloped Reserves Converted to Developed					(58,294)					(54,648)						(32,192)
Purchases of Reserves					51,602					85,473						123,354
Revisions of Previous Estimates			71,700		48,727			89,800		34,166				61,000		(48,743)
Production					0					0						0
Crude Oil Equivalent (Boe)
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Dispositions					11,121					1,900						1,725
Extensions, Discoveries, and Other Additions					27,946					6,005						1,531
Purchases of Reserves					60,360					86,778						133,583
Revisions of Previous Estimates					55,011					52,457						(42,631)
Production					40,160					31,830						22,176
[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, 2018, 2017 and 2016, $438.4 million, $463.4 million and $204.6 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $74.6 million and $32.8 million of infrastructure and pipeline costs in 2018 and 2017, respectively.(3)
[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 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 - NA_9

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, 2018	Dec. 31, 2017
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved natural gas and crude oil properties	$ 5,452,613	$ 4,356,922
Unproved natural gas and crude oil properties	492,594	1,097,317
Uncompleted Wells, Equipment and Facilities	332,264	265,526
Capitalized Costs	6,277,471	5,719,765
Less accumulated DD&A	(2,341,897)	(1,803,847)
Capitalized Costs, Net	$ 3,935,574	$ 3,915,918

SUPPLEMENTAL INFORMATION - N_10

SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves (Unaudited) (Details) bbl in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)bbl	Dec. 31, 2017USD ($)bbl	Dec. 31, 2016USD ($)bbl
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Dispositions | bbl	11,121	1,900	1,725
Future Estimated Cash Flows	$ 17,554,880	$ 12,340,407	$ 7,122,525
Future Estimated Production Costs	(4,782,948)	(3,245,627)	(1,624,167)
Future Estimated Development Costs	(3,632,822)	(2,893,335)	(2,219,914)
Future Estimated Income Tax Expense	(1,404,121)	(748,494)	(597,476)
Future Net Cash Flows	7,734,989	5,452,951	2,680,968
10% Annual Discount for Estimated Timing of Cash Flows	(3,287,273)	(2,572,846)	(1,260,339)
Standardized Measure of Disconted Future Estimated Net Cash Flows	$ 4,447,716	$ 2,880,105	$ 1,420,629
Crude Oil [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Dispositions | bbl	2,507	653	601

SUPPLEMENTAL INFORMATION - N_11

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Principal Sources of Change:
Standardized Measure of Discounted Future Net Cash Flow of Proved Oil and Gas Reserves, Period Increase (Decrease)		$ 4,447,716,000	$ 2,880,105,000	$ 1,420,629,000	$ 1,096,864,000
Sales of natural gas, NGL and crude oil production, net of production costs		(1,131,244,000)	(729,506,000)	(387,576,000)
Net changes in prices and production costs	[1]	936,077,000	841,713,000	(205,760,000)
Extensions, discoveries and improved recovery, less related costs		190,084,000	47,240,000	15,128,000
Sales of reserves		(42,362,000)	(2,613,000)	(3,745,000)
Purchases of reserves		467,807,000	224,483,000	487,636,000
Development costs incurred during the period		462,088,000	419,047,000	268,672,000
Revisions of previous quantity estimates		631,198,000	484,431,000	(320,286,000)
Changes in estimated income taxes		(232,002,000)	(138,560,000)	(13,630,000)
Net change in future development costs		(123,663,000)	25,183,000	391,145,000
Accretion of discount		583,744,000	167,487,000	133,747,000
Timing and other		(174,116,000)	120,571,000	(41,566,000)
Notes to Changes in SMOG [Abstract]
Weighted-Average price, net of production cost		$ 23.44	$ 20.08	$ 15.73
[1]	Our weighted-average price, net of production costs per Boe, in our 2018 reserve report increased to $23.44 as compared to $20.08 for 2017 and $15.73 for 2016.

SUPPLEMENTAL INFORMATION - QU_3

SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION QUARTERLY FINANCIAL INFORMATION (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Total revenues	$ 794,811	$ 280,717	$ 212,531	$ 260,600	$ 189,516	$ 183,235	$ 275,158	$ 273,707	$ 1,548,659	$ 921,616	$ 382,915
Costs, expenses and other:
Total cost, expenses and other	538,626	270,593	400,770	260,924	208,016	579,326	190,522	182,004	1,470,913	1,159,868	715,029
Income from operations	256,185	10,124	(188,239)	(324)	(18,500)	(396,091)	84,636	91,703	77,746	(238,252)	(332,114)
Income (loss) before income taxes	238,024	(7,310)	(205,580)	(17,705)	62,808	(414,887)	65,787	72,476	7,429	(339,432)	(393,123)
Net income (loss)	$ 178,853	$ (3,434)	$ (160,257)	$ (13,139)	$ 77,637	$ (292,537)	$ 41,250	$ 46,146	$ 2,023	$ (127,504)	$ (245,928)
Basic
Basic	$ 2.71	$ (0.05)	$ (2.43)	$ (0.20)	$ 1.18	$ (4.44)	$ 0.63	$ 0.70	$ 0.03	$ (1.94)	$ (5.01)
Diluted
Diluted	$ 2.71	$ (0.05)	$ (2.43)	$ (0.20)	$ 1.17	$ (4.44)	$ 0.62	$ 0.70	$ 0.03	$ (1.94)	$ (5.01)
Deferred income taxes									$ 6,105	$ (203,685)	$ (137,249)
2017 Tax Act [Member]
Diluted
Deferred income taxes					$ 114,400

SCHEDULE II - VALUATION AND Q_3

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
SEC Schedule, 12-09, Reserve, Impairment of Recognized Servicing Asset [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense		$ 388,068		$ 263,817	$ 215
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction		96,518	[1]	13,017	0	[1]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount		542,709		251,159	359		$ 144
allowance for uncollectible notes [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Allowance for Notes, Loans and Financing Receivable, Noncurrent				0	44,038		0
Increase (Decrease) in Notes Receivables	[1]			0	44,038
Increase (Decrease) in Accounts and Notes Receivable				44,038	0
SEC Schedule, 12-09, Allowance, Credit Loss [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense		1,276		1,108	1,309
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	[1]	23		170	1,128
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount		$ 4,381		$ 3,128	$ 2,190		$ 2,009
[1]	For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. 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 actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.