PDC Energy (PDCE) 10-Q 3 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document Document - shares	3 Months Ended
	Mar. 31, 2018	Apr. 20, 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-Q
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		66,065,856

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 45,923	$ 180,675
Accounts receivable, net	181,025	197,598
Fair value of derivatives	28,610	14,338
Prepaid expenses and other current assets	8,897	8,613
Total current assets	264,455	401,224
Properties and equipment, net	4,231,257	3,933,467
Assets held-for-sale, net	1,647	40,084
Other assets	24,798	45,116
Total Assets	4,522,157	4,419,891
Current liabilities:
Accounts payable	195,703	150,067
Production tax liability	36,650	37,654
Fair value of derivatives	110,683	79,302
Funds held for distribution	97,611	95,811
Accrued interest payable	13,760	11,815
Other accrued expenses	33,777	42,987
Total current liabilities	488,184	417,636
Long-term debt	1,154,528	1,151,932
Deferred income taxes	187,183	191,992
Asset retirement obligations	73,905	71,006
Fair value of derivatives	26,426	22,343
Other liabilities	94,557	57,333
Total liabilities	2,024,783	1,912,242
Commitments and contingent liabilities
Stockholders' Equity:
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,999,010 and 65,955,080 issued as of March 31, 2018 and December 31, 2017, respectively	660	659
Additional paid-in capital	2,504,663	2,503,294
Retained earnings (deficit)	(6,435)	6,704
Treasury shares - at cost, 29,255 and 55,927 as of March 31, 2018 and December 31, 2017, respectively	(1,514)	(3,008)
Total stockholders' equity	2,497,374	2,507,649
Total Liabilities and Stockholders' Equity	$ 4,522,157	$ 4,419,891

Balance Sheet Parenthetical (Pa

Balance Sheet Parenthetical (Parentheticals) - $ / shares	Mar. 31, 2018	Dec. 31, 2017
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	65,999,010	65,955,080
Preferred stock, par value	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	50,000,000	50,000,000
Preferred Stock, Shares Issued	0	0
Treasury shares, at cost	29,255	55,927

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues:
Crude oil, natural gas, and NGLs sales	$ 305,225	$ 189,692
Commodity price risk management gain (loss), net	(47,240)	80,704
Other income	2,615	3,311
Total revenues	260,600	273,707
Costs, expenses and other:
Lease operating expenses	29,636	19,789
Production taxes	20,169	12,399
Transportation, gathering, and processing expenses	7,313	5,902
Exploration, geologic, and geophysical expense	2,646	954
Impairment of properties and equipment	33,188	2,193
General and administrative expense	35,696	26,315
Depreciation, depletion, and amortization	126,788	109,316
Accretion of asset retirement obligations	1,288	1,768
(Gain) loss on sale of properties and equipment	1,432	(160)
Other expenses	2,768	3,528
Total cost, expenses and other	260,924	182,004
Income (loss) from operations	(324)	91,703
Interest expense	(17,529)	(19,467)
Interest income	148	240
Income (loss) before income taxes	(17,705)	72,476
Income tax (expense) benefit	4,566	(26,330)
Net income (loss)	$ (13,139)	$ 46,146
Earnings per share:
Basic	$ (0.20)	$ 0.70
Diluted	$ (0.20)	$ 0.70
Weighted-average common shares outstanding
Basic	65,957	65,749
Diluted	65,957	66,117

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net income (loss)	$ (13,139)	$ 46,146
Net income (loss)	(13,139)	46,146
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Net change in fair value of unsettled derivatives	21,202	(80,153)
Depreciation, depletion, and amortization	126,788	109,316
Impairment of properties and equipment	33,188	2,193
Accretion of asset retirement obligations	1,288	1,768
Non-cash stock-based compensation	5,261	4,454
(Gain) loss on sale of properties and equipment	1,432	(160)
Amortization of debt discount and issuance costs	3,246	3,184
Deferred income taxes	(4,809)	26,280
Other	515	722
Changes in assets and liabilities	30,177	25,750
Net cash from operating activities	205,149	139,500
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(196,917)	(129,826)
Capital expenditures for other properties and equipment	(1,066)	(821)
Acquisition of crude oil and natural gas properties, including settlement adjustments	(180,825)	6,181
Proceeds from sale of properties and equipment	20	737
Proceeds from divestiture	39,023	0
Restricted cash	1,249	0
Purchases of short-term investments	0	(49,890)
Net cash from investing activities	(338,516)	(173,619)
Cash flows from financing activities:
Proceeds from revolving credit facility	35,000	0
Repayment of revolving credit facility	(35,000)	0
Purchase of treasury shares	(2,255)	(2,017)
Other	(379)	(340)
Net cash from financing activities	(2,634)	(2,357)
Net change in cash, cash equivalents, and restricted cash	(136,001)	(36,476)
Cash, cash equivalents, and restricted cash, beginning of period	189,925	244,100
Cash, cash equivalents, and restricted cash, end of period	53,924	207,624
Cash payments (receipts) for:
Interest, net of capitalized interest	12,343	13,224
Income taxes	193	(39)
Non-cash investing and financing activities:
Change in accounts payable related to purchases of properties and equipment	51,093	69,604
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals	5,354	1,233
Purchase of properties and equipment under capital leases	$ 348	$ 1,190

Consolidated Statement of Equit

Consolidated Statement of Equity (Statement) - USD ($) $ in Thousands	Total	Parent [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued			65,955,080			(55,927)
Issuance of stock awards, net of forfeitures			43,930
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract]
Purchase of treasury shares						(41,357)
Issuance of treasury shares			0			70,603
Non-employee directors' deferred compensation plan						(2,574)
Stockholders' Equity Beginning, 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]
Purchase of treasury shares	$ (2,255)	(2,255)				(2,255)
Issuance of stock awards, net of forfeitures		0	1	(1)
Share-based Compensation expense	5,261	5,261		5,261
Issuance of treasury shares		0	0	(3,891)		3,891
Non-employee directors' deferred compensation plan		(142)		0		(142)
Net income (Loss) attributable to shareholders	(13,139)	(13,139)			(13,139)
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Mar. 31, 2018		2,497,374	$ 660	$ 2,504,663	$ (6,435)	$ (1,514)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' Equity, Other	$ 0	$ 0
Shares, Issued			65,999,010			(29,255)

NATURE OF OPERATIONS AND BASIS

NATURE OF OPERATIONS AND BASIS OF PRESENTATION	3 Months Ended
	Mar. 31, 2018
NATURE OF OPERATIONS AND BASIS OF PRESENTATION [Abstract]
Nature of Operations	NATURE OF OPERATIONS AND BASIS OF PRESENTATION PDC Energy, Inc. 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 horizontal Niobrara and Codell plays and our Delaware Basin operations are currently focused in the Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the three months ended March 31, 2018 . As of March 31, 2018 , we owned an interest in approximately 3,000 gross productive 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 accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues, and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. In our opinion, the accompanying condensed consolidated financial statements contain all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2017 condensed consolidated balance sheet data was derived from audited statements, but does not include all disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2017 Form 10-K. Our results of operations and cash flows for the three months ended March 31, 2018 are not necessarily indicative of the results to be expected for the full year or any other future period.

Recent Accounting Standards

Recent Accounting Standards	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Recently Adopted Accounting Standard 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 standard has been updated and now includes technical corrections. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations, and (5) recognize revenue when or as each performance obligation is satisfied. We adopted the standard effective January 1, 2018. 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. We determined that we would adopt the standard under the modified retrospective method. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. 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. The adoption of this standard impacted our condensed consolidated statements of cash flows. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the condensed consolidated balance sheets at March 31, 2018 and December 31, 2017 , which sum to the total of cash, cash equivalents, and restricted cash in the condensed consolidated statements of cash flows: March 31, 2018 December 31, 2017 (in thousands) Cash and cash equivalents $ 45,923 $ 180,675 Restricted cash 8,001 9,250 Cash, cash equivalents, and restricted cash shown in the condensed consolidated statements of cash flows $ 53,924 $ 189,925 Restricted cash is included in other assets on the condensed consolidated balance sheets at March 31, 2018 and December 31, 2017 . We did not have any cash classified as restricted cash at March 31, 2017 or December 31, 2016. Recently Issued Accounting Standards In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. The standard has been updated and now includes amendments. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.
Description of New Accounting Pronouncements Not yet Adopted [Text Block]	In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. The standard has been updated and now includes amendments. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.

Business Combination Business C

Business Combination Business Combinations (Notes)	3 Months Ended
	Mar. 31, 2018
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	BUSINESS COMBINATION In January 2018, we closed the acquisition of properties from Bayswater Exploration and Production LLC (the "Bayswater Acquisition") for approximately $201.8 million in cash, including $21.0 million deposited into an escrow account in September 2017, subject to certain customary post-closing adjustments. The $21.0 million deposit was included in other assets on our December 31, 2017 condensed consolidated balance sheet. We acquired approximately 7,400 net acres, approximately 220 gross drilling locations, and 24 operated horizontal wells that were either drilled uncompleted wells ("DUCs") or in-process wells at the time of closing. The details of the estimated purchase price and the preliminary allocation of the purchase price for the transaction, are presented below (in thousands): March 31, 2018 Acquisition costs: Cash $ 171,091 Deposit made in prior period 21,000 Total cash consideration 192,091 Other purchase price adjustments 9,734 Total acquisition costs $ 201,825 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current assets $ 517 Crude oil and natural gas properties - proved 208,279 Other assets 2,796 Total assets acquired 211,592 Liabilities assumed: Current liabilities (5,080 ) Asset retirement obligations (4,687 ) Total liabilities assumed (9,767 ) Total identifiable net assets acquired $ 201,825 This acquisition 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. Within the unproved properties, 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 and were the most sensitive and subject to change. The results of operations for the Bayswater Acquisition for the three months ended March 31, 2018 have been included in our condensed consolidated financial statements. Pro forma results of operations for the Bayswater Acquisition showing results as if the acquisition had been completed as of January 1, 2017 would not have been material to our condensed consolidated financial statements for the three months ended March 31, 2017 .

Revenue Recognition (Notes)

Revenue Recognition (Notes)	3 Months Ended
	Mar. 31, 2018
Revenue Recognition and Deferred Revenue [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 and the International Accounting Standards Board that converged their standard on revenue recognition and provides a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all the related amendments (“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 standard would have reduced our crude oil, natural gas, and NGLs sales by approximately $2.5 million in the first quarter of 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 the three months ended March 31, 2017, we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the new standard to have a significant impact on our net income going forward. 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 and prices received. We receive payment for sales from 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 the three months ended March 31, 2018 and 2017 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 purchase 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 indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when 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. 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 recognition 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 our natural gas average NYMEX pricing is based upon first-of-the-month index prices as 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 the three months ended March 31, 2018 and 2017 (in thousands): Three Months Ended March 31, Revenue by Commodity and Operating Region 2018 2017 (2) Percentage Change Crude oil Wattenberg Field $ 170,306 $ 105,188 61.9 % Delaware Basin 53,418 13,538 294.6 % Utica Shale (1) 2,696 4,270 (36.9 )% Total $ 226,420 $ 122,996 84.1 % Natural gas Wattenberg Field $ 29,772 $ 32,614 (8.7 )% Delaware Basin 7,679 2,468 211.1 % Utica Shale (1) 1,110 1,860 (40.3 )% Total $ 38,561 $ 36,942 4.4 % NGLs Wattenberg Field $ 28,770 $ 25,318 13.6 % Delaware Basin 10,635 2,947 260.9 % Utica Shale (1) 839 1,489 (43.7 )% Total $ 40,244 $ 29,754 35.3 % Revenue by Operating Region Wattenberg Field $ 228,848 $ 163,120 40.3 % Delaware Basin 71,732 18,953 278.5 % Utica Shale (1) 4,645 7,619 (39.0 )% Total $ 305,225 $ 189,692 60.9 % ________________ (1) In March 2018, we completed the sale of our Utica Shale properties. (2) As we have elected the modified retrospective method of adoption, revenues for the three months ended March 31, 2017 have not been restated for the new revenue recognition standard. Such amounts would not have been material. Contract Assets. Contract assets include material contributions in aid of construction ("CIAC"), which are common in purchase/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 that are classified as current assets are included in prepaid expenses and other current assets on our condensed consolidated balance sheet. Contract assets that are classified as long-term are included in other assets on our condensed consolidated balance sheet. The contract assets will be amortized as a reduction to crude oil, natural gas, or NGLs sales revenue during the periods that 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 the three months ended March 31, 2018 : Amount (in thousands) Beginning balance, January 1, 2018 $ 4,446 Contract assets amortized as a reduction to crude oil, natural gas, and NGLs sales (1,233 ) Ending balance, March 31, 2018 $ 3,213 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 March 31, 2018 and December 31, 2017 was $145.3 million and $154.3 million , respectively. Historically, we have not recorded a significant amount of write-offs related to our accounts receivable from sales of our crude oil, natural gas, and NGLs sales, therefore; we did not record an allowance for doubtful accounts for these receivables at March 31, 2018 or December 31, 2017 .
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	On January 1, 2018, we adopted the new accounting standard that was issued by the FASB and the International Accounting Standards Board that converged their standard on revenue recognition and provides a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all the related amendments (“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 standard would have reduced our crude oil, natural gas, and NGLs sales by approximately $2.5 million in the first quarter of 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 the three months ended March 31, 2017, we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the new standard to have a significant impact on our net income going forward. 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 and prices received. We receive payment for sales from 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 the three months ended March 31, 2018 and 2017 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 purchase 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 indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when 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. 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 recognition 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 our natural gas average NYMEX pricing is based upon first-of-the-month index prices as 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.

Fair Value Measurements and Dis

Fair Value Measurements and Disclosures	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value, Measurement Inputs, Disclosure	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 derivative instruments based upon 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, determination that the source of the inputs is valid, corroboration of the original source of inputs through access to multiple quotes, if available, or other information, and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars and propane fixed-price swaps are included in Level 3. Our basis swaps are included in Level 2 and Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: March 31, 2018 December 31, 2017 Significant Other Significant Total Significant Other Significant Total (in thousands) Assets: Total assets $ 22,467 $ 6,143 $ 28,610 $ 12,949 $ 1,389 $ 14,338 Total liabilities 122,133 14,976 137,109 90,569 11,076 101,645 Net liability $ (99,666 ) $ (8,833 ) $ (108,499 ) $ (77,620 ) $ (9,687 ) $ (87,307 ) The following table presents a reconciliation of our Level 3 assets measured at fair value: Three Months Ended March 31, 2018 2017 (in thousands) Fair value of Level 3 instruments, net liability beginning of period $ (9,687 ) $ (9,574 ) Changes in fair value included in condensed consolidated statement of operations line item: Commodity price risk management gain (loss), net (2,152 ) 13,360 Settlements included in condensed consolidated statement of operations line items: Commodity price risk management gain ( loss) , net 3,006 (1,470 ) Fair value of Level 3 instruments, net asset (liability) end of period $ (8,833 ) $ 2,316 Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item: Commodity price risk management gain ( loss) , net $ 1,205 $ 11,427 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 this report. 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 proved crude oil and natural gas properties 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 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 March 31, 2018 . Estimated Fair Value Percent of Par (in millions) Senior notes: 2021 Convertible Notes $ 194.0 97.0 % 2024 Senior Notes 409.0 102.3 % 2026 Senior Notes 593.3 98.9 % 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 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 and natural gas. 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. An insignificant portion of our commodity derivative instruments may be with other counterparties. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at March 31, 2018 , taking into account the estimated likelihood of nonperformance. Cash and Cash Equivalents. We consider all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of the FDIC insurance limits at March 31, 2018 and December 31, 2017 . We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also major lenders under our revolving credit facility.

Derivative Financial Instrument

Derivative Financial Instruments	3 Months Ended
	Mar. 31, 2018
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	COMMODITY 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 March 31, 2018 , we had derivative instruments, which were comprised of collars, fixed-price swaps, and basis protection swaps, in place for a portion of our anticipated 2018 and 2019 production. 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 March 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 (Gas - BBtu Oil - MBbls) Weighted-Average Contract Price Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls) Weighted- Average Contract Price Fair Value March 31, 2018 (1) (in millions) Floors Ceilings Crude Oil NYMEX 2018 1,784.0 $ 46.64 $ 57.53 7,704.0 $ 52.54 $ (91.4 ) 2019 400.0 50.00 60.67 7,800.0 53.20 (42.9 ) Total Crude Oil 2,184.0 15,504.0 $ (134.3 ) Natural Gas NYMEX 2018 2,735.0 $ 3.00 $ 3.56 40,335.0 $ 2.94 $ 5.1 2019 — — — 4,004.0 2.77 (0.1 ) Total Natural Gas 2,735.0 44,339.0 $ 5.0 Basis Protection - Crude Oil Midland Cushing 2018 — $ — $ — 1,456.1 $ (0.10 ) $ 5.4 Total Basis Protection - Crude Oil — 1,456.1 $ 5.4 Basis Protection - Natural Gas CIG 2018 — $ — $ — 31,409.9 $ (0.43 ) $ 12.3 2019 — — — 4,004.0 (0.88 ) (0.1 ) Waha 2018 — — — 4,923.8 (0.50 ) 3.4 El Paso 2018 — — — 2,450.0 (0.62 ) 1.6 Total Basis Protection - Natural Gas — 42,787.7 $ 17.2 Propane Mont Belvieu 2018 — $ — $ — 714.4 $ 32.52 $ — Total Propane — 714.4 $ — Rollfactor (2) Crude Oil CMA 2018 — $ — $ — 4,192 $ 0.12 $ (1.8 ) Total Rollfactor — 4,192 $ (1.8 ) Commodity Derivatives Fair Value $ (108.5 ) _____________ (1) Approximately 21.5 percent of the fair value of our commodity derivative assets and 10.9 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). (2) These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month. We have not elected to designate any of our derivative instruments as cash flow hedges, and therefore these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the condensed consolidated statements of operations. The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets: Fair Value Derivative instruments: Condensed consolidated balance sheet line item March 31, 2018 December 31, 2017 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 5,958 $ 7,340 Basis protection derivative contracts Fair value of derivatives 22,652 6,998 28,610 14,338 Non-current — — Total derivative assets $ 28,610 $ 14,338 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives 108,763 77,999 Basis protection derivative contracts Fair value of derivatives 122 234 Rollfactor derivative contracts Fair value of derivatives 1,798 1,069 110,683 79,302 Non-current Commodity derivative contracts Fair value of derivatives 26,447 22,343 Basis protection derivative contracts Fair value of derivatives (21 ) — 26,426 22,343 Total derivative liabilities $ 137,109 $ 101,645 The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations: Three Months Ended March 31, Condensed consolidated statement of operations line item 2018 2017 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (26,038 ) $ 551 Net change in fair value of unsettled derivatives (21,202 ) 80,153 Total commodity price risk management gain (loss), net $ (47,240 ) $ 80,704 Net settlements of commodity derivatives and net change in fair value of unsettled derivatives decreased for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017 as a result of the increase in future commodity prices during the first quarter of 2018 compared to a decrease during the first quarter of 2017. 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 condensed consolidated balance sheets. The following table reflects the impact of netting agreements on gross derivative assets and liabilities: As of March 31, 2018 Derivative instruments, recorded in condensed consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 28,610 $ (27,971 ) $ 639 Liability derivatives: Derivative instruments, at fair value $ 137,109 $ (27,971 ) $ 109,138 As of December 31, 2017 Derivative instruments, recorded in condensed consolidated balance sheet, 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	3 Months Ended
	Mar. 31, 2018
Oil and Gas Property [Abstract]
Property, Plant and Equipment Disclosure	PROPERTIES AND EQUIPMENT The following table presents the components of properties and equipment, net of accumulated depreciation, depletion, and amortization ("DD&A"): March 31, 2018 December 31, 2017 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 4,706,258 $ 4,356,922 Unproved 1,055,774 1,097,317 Total crude oil and natural gas properties 5,762,032 5,454,239 Infrastructure, pipeline, and other 125,529 109,359 Land and buildings 12,679 10,960 Construction in progress 294,311 196,024 Properties and equipment, at cost 6,194,551 5,770,582 Accumulated DD&A (1,963,294 ) (1,837,115 ) Properties and equipment, net $ 4,231,257 $ 3,933,467 The following table presents impairment charges recorded for crude oil and natural gas properties: Three Months Ended March 31, 2018 2017 (in thousands) Impairment of proved and unproved properties $ 33,130 $ 2,102 Amortization of individually insignificant unproved properties 58 91 Impairment of crude oil and natural gas properties $ 33,188 $ 2,193 During the three months ended March 31, 2018 , we recorded impairment charges of $26.9 million , primarily related to certain unproved Delaware Basin leasehold positions that expired during the three months ended March 31, 2018 . Additionally, we corrected an error in our calculation of the unproved properties and goodwill impairment originally reported in the quarter ended September 30, 2017. The correction of the error resulted in an additional impairment charge of $6.3 million , recorded in the three months ended March 31, 2018, which we have included in the impairment of properties and equipment expense line in our condensed consolidated statement of operations. We evaluated the error 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 impact of the error did not have a material impact to our previously-issued financial statements or those of the period of correction. Utica Shale Divestiture. In March 2018, we completed the sale of our Utica Shale properties (the "Utica Shale Divestiture") for net cash proceeds of approximately $39.0 million , subject to certain customary post-closing adjustments. We recorded a loss on sale of properties and equipment of $1.4 million for the three months ended March 31, 2018 . The divestiture of the Utica Shale properties 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. Classification of Assets as Held-for-Sale. Assets held-for-sale as of March 31, 2018 were $1.6 million for a field office facility. We subsequently sold the field office facility in April 2018 for $1.9 million and will record a gain on sale of properties and equipment of $0.3 million during the second quarter of 2018. Assets held-for-sale as of December 31, 2017 included $36.8 million and $3.3 million , representing our Utica Shale properties and field office facilities and a separate parcel of land, respectively. The following table presents balance sheet data related to assets held-for-sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities that are expected to be assumed by the purchasers: March 31, 2018 December 31, 2017 (in thousands) Assets Properties and equipment, net $ 1,647 $ 40,583 Total assets $ 1,647 $ 40,583 Liabilities Asset retirement obligation $ — $ 499 Total liabilities $ — $ 499 Assets held-for-sale, net $ 1,647 $ 40,084 Suspended Well Costs. We have spud three wells in the Delaware Basin for which we are unable to make a final determination regarding whether proved reserves can be associated with the wells as of March 31, 2018 as the wells had not been completed as of that date. Therefore, we have classified the capitalized costs of the wells as suspended well costs as of March 31, 2018 while we continue to conduct completion and testing operations to determine the existence of proved reserves. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the condensed consolidated balance sheets: March 31, 2018 December 31, 2017 (in thousands, except for number of wells) Beginning balance $ 15,448 $ — Additions to capitalized exploratory well costs pending the determination of proved reserves 17,143 51,776 Reclassifications to proved properties — (36,328 ) Ending balance $ 32,591 $ 15,448 Number of wells pending determination at period end 3 3 Exploration, geologic, and geophysical expense. Exploration, geologic, and geophysical expense of $2.6 million during the three months ended March 31, 2018 was primarily related to the purchase of seismic data related to unproved acreage and lease costs associated with certain delayed drilling in the Delaware Basin. Exploration, geologic, and geophysical expense of $1.0 million during the three months ended March 31, 2017 was primarily related to drilling pilot holes in the Delaware Basin.

Other Accrued Expenses Other Ac

Other Accrued Expenses Other Accrued Expenses (Notes)	3 Months Ended
	Mar. 31, 2018
Other Accrued Expenses [Abstract]
Other Income and Other Expense Disclosure [Text Block]	OTHER ACCRUED EXPENSES AND OTHER LIABILITIES Other Accrued Expenses. The following table presents the components of other accrued expenses as of: March 31, 2018 December 31, 2017 (in thousands) Employee benefits $ 10,901 $ 22,383 Asset retirement obligations 15,944 15,801 Environmental expenses 2,074 1,374 Short-term deferred oil gathering credit 2,010 — Other 2,848 3,429 Other accrued expenses $ 33,777 $ 42,987 Other Liabilities. The following table presents the components of other liabilities as of: March 31, 2018 December 31, 2017 (in thousands) Production taxes $ 63,454 $ 50,476 Long-term deferred oil gathering credit 21,608 — Other 9,495 6,857 Other liabilities $ 94,557 $ 57,333 On January 31, 2018, we received a payment of $24.1 million from Saddle Butte Rockies Midstream, LLC 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 Saddle Butte's gathering lines and extends the term of the agreement through December 2029. Subsequent to the receipt of this payment, Saddle Butte was purchased by Black Diamond Gathering, LLC. The short-term portion of the deferred oil gathering credit is included in other accrued expenses and the long-term portion is included in other liabilities on our condensed consolidated balance sheet as of March 31, 2018 . The payment will be amortized using the straight-line method over the life of the amendment. Amortization charges totaling approximately $0.4 million for the three months ended March 31, 2018 related to the deferred oil gathering credit are included as a reduction to transportation, gathering, and processing expenses on our condensed consolidated statements of operations.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Long-term Debt	LONG-TERM DEBT Long-term debt consisted of the following as of: March 31, 2018 December 31, 2017 (in thousands) Senior notes: 1.125% Convertible Notes due 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (28,478 ) (30,328 ) Unamortized debt issuance costs (3,371 ) (3,615 ) 1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs 168,151 166,057 5.75% Senior Notes due 2026: Principal amount 600,000 600,000 Unamortized debt issuance costs (7,298 ) (7,555 ) 5.75% Senior Notes due 2026, net of unamortized debt issuance costs 592,702 592,445 6.125% Senior Notes due 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (6,325 ) (6,570 ) 6.125% Senior Notes due 2024, net of unamortized debt issuance costs 393,675 393,430 Total senior notes 1,154,528 1,151,932 Revolving credit facility — — Total long-term debt, net of unamortized discount and debt issuance costs $ 1,154,528 $ 1,151,932 Senior Notes 2021 Convertible Notes. In September 2016 , we issued $200 million of 1.125% convertible notes due 2021 (the "2021 Convertible Notes") in a public offering. 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 conversion stock price at maturity is $85.39 per share. 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, priced on the same day we issued 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. As of March 31, 2018 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using an effective interest rate of 5.8 percent . Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash, or a combination of cash and shares of our common stock. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares of our common stock, with cash paid in lieu of fractional shares. 2024 Senior Notes. In September 2016 , we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”) in a private placement to qualified institutional buyers. In May 2017, in accordance with the registration rights agreement that we entered into with the initial purchasers when we issued the 2024 Senior Notes, we filed a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical terms, and we completed the exchange offer in September 2017. The 2024 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on March 15 and September 15 . Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. 2026 Senior Notes. In November 2017, we issued $600 million aggregate principal amount of 5.75% senior notes due May 15, 2026, in a private placement to qualified institutional buyers. The 2026 Senior Notes are governed by an indenture dated November 29, 2017 between us and the U.S. Bank National Association, as trustee. The maturity for the payment of principal is May 15, 2026 . Interest at the rate of 5.75% per year is payable in cash semiannually in arrears on each May 15 and November 15 , commencing on May 15, 2018. Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. Our wholly-owned subsidiary PDC Permian, Inc. guarantees our obligations under the 2021 Convertible Notes, the 2026 Senior Notes, and the 2024 Senior Notes (collectively, the "Notes"). Accordingly, condensed consolidating financial information for PDC and PDC Permian, Inc. is presented in the footnote titled Subsidiary Guarantor . As of March 31, 2018 , we were in compliance with all covenants related to the Notes, and expect to remain in compliance throughout the next 12-month period. Revolving Credit Facility The revolving credit facility is available for working capital requirements, capital investments, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility matures in May 2020 and provides for a maximum of $1.0 billion in allowable borrowing capacity, subject to the borrowing base and certain limitations under our senior notes. 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 revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. In May and October 2017, we entered into the Fifth and Sixth Amendments, respectively, to the Third Amended and Restated Credit Agreement to amend the revolving credit facility to reflect increases in the borrowing base. The Fifth amendment reflected an increase of the borrowing base from $700 million to $950 million and the Sixth Amendment amended the revolving credit facility to allow the borrowing base to increase above the borrowing capacity of $1.0 billion . In addition, the Fifth Amendment made changes to certain of the covenants in the existing agreement as well as other administrative changes. We elected to increase the borrowing base to $1.1 billion for our November 2017 borrowing base redetermination and have elected to maintain a $700 million commitment level as of the date of this report. In April 2018, we began negotiations with our bank group to enter into the Fourth Amended and Restated Credit Agreement, and we anticipate closing to occur by the end of May 2018. This agreement is expected to replace the Third Amended and Restated Credit Agreement. Following the amendment and restatement, the facility is expected to mature in May 2023. As of March 31, 2018 and December 31, 2017 , debt issuance costs related to our revolving credit facility were $5.5 million and $6.2 million , respectively, and are included in other assets on the condensed consolidated balance sheets. We had no outstanding balance on our revolving credit facility as of March 31, 2018 or December 31, 2017 . 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 JPMorgan Chase Bank, N.A.'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 March 31, 2018 , the applicable interest margin is 1.25 percent for the alternate base rate option or 2.25 percent for the LIBOR option, and the unused commitment fee is 0.5 percent . Principal payments are generally not required until the revolving credit facility expires in May 2020 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 March 31, 2018 , we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. As defined by the revolving credit facility, our leverage ratio was 1.7 and our current ratio was 2.5 as of March 31, 2018 .

Capital Leases (Notes)

Capital Leases (Notes)	3 Months Ended
	Mar. 31, 2018
Capital Leased Assets [Line Items]
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 vehicles under capital lease as of: March 31, 2018 December 31, 2017 (in thousands) Vehicles $ 6,500 $ 6,249 Accumulated depreciation (2,271 ) (1,882 ) $ 4,229 $ 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 March 31, Amount (in thousands) 2019 $ 1,952 2020 2,061 2021 1,247 5,260 Less executory cost (400 ) Less amount representing interest (501 ) Present value of minimum lease payments $ 4,359 Short-term capital lease obligations $ 1,789 Long-term capital lease obligations 2,570 $ 4,359 Short-term capital lease obligations are included in other accrued expenses on the condensed consolidated balance sheets and long-term capital lease obligations are included in other liabilities on the condensed consolidated balance sheets.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Income Tax Disclosure	INCOME TAXES We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual annual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective income tax rate, adjusted for the effect of discrete items. The effective income tax rate for the three months ended March 31, 2018 was a 25.8 percent benefit on loss compared to a 36.3 percent expense on income for the three months ended March 31, 2017 . The effective income tax rate for the three months ended March 31, 2018 , is based upon a full year forecasted tax expense on income. The effective income tax rate for the three months ended March 31, 2018 includes discrete income tax benefits of $0.2 million relating to the excess tax benefit recognized with the vesting of stock awards during the three months ended March 31, 2018 , which resulted in a 1.2 percent increase to our effective tax rate. The federal corporate statutory income tax rate decreased from 35 percent in 2017 to 21 percent in 2018 resulting from the 2017 Tax Cuts and Jobs Act (the "2017 Tax Act"). The effective income tax rate for the three months ended March 31, 2018 is based upon a full year forecasted tax expense on income and is greater than the statutory federal tax rate, primarily due to state taxes, nondeductible officers’ compensation, and nondeductible lobbying expenses, partially offset by stock-based compensation tax deductions. We anticipate the potential for increased periodic volatility in future effective tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items. The effective tax rate for the three months ended March 31, 2017 is based upon a full year forecasted tax expense on income and is greater than the statutory federal tax rate, primarily due to state taxes, nondeductible officers’ compensation and nondeductible lobbying expenses, partially offset by stock-based compensation tax deductions. As of March 31, 2018 , there is no liability for unrecognized income tax benefits. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. We continue to voluntarily participate in the Internal Revenue Service's ("IRS") Compliance Assurance Program for the 2017 and 2018 tax years. We have received final acceptance of our 2016 federal income tax return from the IRS; however, this return is going through the Joint Tax Committee review process due to tax refunds requested.

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure	ASSET RETIREMENT OBLIGATIONS The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties: Amount (in thousands) Balance at December 31, 2017 $ 87,306 Obligations incurred with development activities 620 Obligations incurred with acquisition 4,687 Accretion expense 1,288 Revisions in estimated cash flows 50 Obligations discharged with asset retirements and divestiture (4,102 ) Balance at March 31, 2018 89,849 Less current portion (15,944 ) Long-term portion $ 73,905 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. As of March 31, 2018 , the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 6.5 percent to 7.5 percent. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors, and changes to our credit-adjusted risk-free rate as market conditions warrant. Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure	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 condensed 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 and processing agreements for pipeline capacity: For the Twelve Months Ending March 31, Area 2019 2020 2021 2022 2023 and Total Expiration Natural gas (MMcf) Wattenberg Field 7,416 27,794 31,025 31,025 114,272 211,532 April 30, 2026 Delaware Basin 25,520 25,600 11,000 — — 62,120 December 31, 2020 Gas Marketing 7,117 7,136 7,117 6,965 2,830 31,165 August 31, 2022 Total 40,053 60,530 49,142 37,990 117,102 304,817 Crude oil (MBbls) Wattenberg Field 7,438 8,062 5,085 4,563 4,937 30,085 April 30, 2023 Delaware Basin 4,493 8,227 8,580 7,392 14,080 42,772 December 31, 2023 Total 11,931 16,289 13,665 11,955 19,017 72,857 Dollar commitment (in thousands) $ 64,690 $ 99,560 $ 69,434 $ 65,060 $ 160,183 $ 458,927 In March 2018, we completed the sale of our Utica Shale properties. Upon closing, the related commitment was assumed by the purchaser of the Utica Shale properties. 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 is expected to construct two new 200 MMcfd cryogenic plants. We will be bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service dates of the plants, which, as reflected in the above table, are currently scheduled to be in the third quarter of 2018 for the first plant and the second quarter of 2019 for the second plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016, to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. Any shortfall 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. We currently expect that our future development plans will meet both the baseline and incremental volumes, and we believe that the contractual target profit margin will be achieved without additional payment from us. In April 2018, we entered into a five-year firm transportation agreement, effective May 1, 2018, with a third-party crude oil pipeline company to transport 12,500 barrels of crude oil per day from our Wattenberg Field via pipeline to Cushing, Oklahoma and other area refineries. This agreement is reflected in the pipeline capacity commitment table above. In May 2018, we entered into a firm sales agreement that is effective from June 1, 2018 through December 31, 2023 for an initial 11,400 barrels of crude oil per day and incrementally increasing to 26,400 barrels of crude oil per day with a large integrated marketing company for our crude oil production in the Delaware Basin. This agreement is expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices. The fixed transportation charge associated with this agreement is reflected in the pipeline capacity commitment table above. For the three months ended March 31, 2018 , commitments for long-term transportation volumes, net to our interest, for Wattenberg Field crude oil and Delaware Basin natural gas were $2.6 million , and in accordance with the guidance in the new revenue recognition standard, were netted against our crude oil and natural gas sales in our condensed consolidated statements of operations. For the three months ended March 31, 2017 , commitments for long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $2.2 million and were recorded in transportation, gathering, and processing expense in our condensed consolidated statements of operations. Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations, or liquidity. Action Regarding Partnerships . In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al., filed in the United States District Court for the District of Colorado. The complaint states that it is a derivative action brought by a number of limited partner investors seeking to assert claims on behalf of our two affiliated partnerships, Rockies Region 2006 LP and Rockies Region 2007 LP, against PDC and includes claims for breach of fiduciary duty and breach of contract. The plaintiffs also included claims against two of our senior officers for alleged breach of fiduciary duty. The lawsuit accuses PDC, as the managing general partner of the two partnerships, of, among other things, failing to maximize the productivity of the partnerships’ crude oil and natural gas wells. We filed a motion to dismiss the lawsuit on February 1, 2018, on the grounds that the complaint is deficient, including because the plaintiffs failed to allege that PDC refused a demand to take action on their claims. On March 14, 2018, the motion was denied as moot by the court because the plaintiffs requested leave to amend their complaint. In late April 2018, the plaintiffs filed an amendment to their complaint. Such amendment primarily alleges additional facts to support the plaintiffs’ claims and purports to add direct class action claims in addition to the original derivative claims. The amendment also adds three new individual defendants, all of which are independent members of our Board of Directors. We are currently unable to estimate any potential damages as a result of this lawsuit. 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 March 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 condensed consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual. Clean Air Act Tentative Agreement and Related Consent Decree. In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the U.S. Environmental Protection Agency ("EPA"). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado ("DJ Basin"). The Information Request focused on historical operation and design information for 46 of our production facilities and requested sampling and analyses at the identified 46 facilities. We responded to the Information Request with the requested data in January 2016. In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. 25-7-115(2) from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. In June 2017, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to resolve the lawsuit. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($ 1.5 million cash fine, plus $ 1 million in supplemental environmental projects) of which the cash fines were paid in the first quarter of 2018 and the environmental projects have been accrued in other accrued expenses on our consolidated balance sheet as of March 31, 2018 (ii) injunctive relief with an estimated cost of approximately $ 18 million , primarily representing capital enhancements to our operations; and (iii) mitigation with an estimated cost of $ 1.7 million . We continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. In addition, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. Since our entry into the consent decree we have implemented a comprehensive program to comply with all of its requirements. As of the date of the filing of this report, all aspects of the consent decree compliance program are on or ahead of schedule.

Common Stock

Common Stock	3 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award	COMMON STOCK Stock-Based Compensation Plans 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: Three Months Ended March 31, 2018 2017 (in thousands) Stock-based compensation expense $ 5,261 $ 4,453 Income tax benefit (1,261 ) (1,666 ) Net stock-based compensation expense $ 4,000 $ 2,787 Stock Appreciation Rights The stock appreciation right ("SARs") vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the 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. No SARs were awarded or expired during the three months ended March 31, 2018 . Total compensation cost related to non-vested SARs granted and not yet recognized in our condensed consolidated statement of operations as of March 31, 2018 was $1.4 million . The cost is expected to be recognized over a weighted-average period of 1.52 years. Restricted Stock Awards Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three years. The time-based shares generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed. The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the three months ended March 31, 2018 : Shares Weighted-Average Non-vested at December 31, 2017 472,132 $ 60.23 Granted 136,256 50.94 Vested (66,253 ) 58.16 Forfeited (5,800 ) 68.18 Non-vested at March 31, 2018 536,335 58.04 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Three Months Ended March 31, 2018 2017 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 3,530 $ 3,602 Total intrinsic value of time-based awards non-vested 26,297 33,366 Market price per share as of March 31, 49.03 62.35 Weighted-average grant date fair value per share 50.94 73.28 Total compensation cost related to non-vested time-based awards and not yet recognized in our condensed consolidated statements of operations as of March 31, 2018 was $20.6 million . This cost is expected to be recognized over a weighted-average period of 2.0 years. Market-Based Awards. The fair value of the market-based restricted shares 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. The Compensation Committee of our Board of Directors awarded a total of 90,778 market-based restricted shares to our executive officers during the three months ended March 31, 2018 . In addition to continuous employment, the vesting of these shares is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2020, and can result in a payout between 0 percent and 200 percent of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards was computed using the Monte Carlo pricing model using the following assumptions: Three Months Ended March 31, 2018 2017 Expected term of award (in years) 3 3 Risk-free interest rate 2.4 % 1.4 % Expected volatility 42.3 % 51.4 % Weighted-average grant date fair value per share $ 69.98 $ 94.02 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 the three months ended March 31, 2018 : Shares Weighted-Average Non-vested at December 31, 2017 52,349 $ 84.06 Granted 90,778 69.98 Forfeited (4,128 ) 94.02 Non-vested at March 31, 2018 138,999 74.57 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of Three Months Ended March 31, 2018 2017 (in thousands, except per share data) Total intrinsic value of market-based awards non-vested $ 6,815 $ 4,769 Market price per common share as of March 31, 49.03 62.35 Weighted-average grant date fair value per share 69.98 94.02 Total compensation cost related to non-vested market-based awards not yet recognized in our condensed consolidated statements of operations as of March 31, 2018 was $7.9 million . This cost is expected to be recognized over a weighted-average period of 2.5 years. Preferred Stock We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges, and restrictions as shall be fixed by our Board of Directors from time to time. Through March 31, 2018 , no preferred shares have been issued.

Earnings per share

Earnings per share	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Earnings Per Share	EARNINGS PER SHARE Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes, and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. The following table presents a reconciliation of the weighted-average diluted shares outstanding: Three Months Ended March 31, 2018 2017 (in thousands) Weighted-average common shares outstanding - basic 65,957 65,749 Dilutive effect of: Restricted stock — 211 Convertible notes — 157 Weighted-average common shares and equivalents outstanding - diluted 65,957 66,117 We reported a net loss for the three months ended March 31, 2018 . As a result, our basic and diluted weighted-average common shares outstanding were the same for that period 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: Three Months Ended March 31, 2018 2017 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: Restricted stock 491 76 Convertible notes — — Other equity-based awards 198 18 Total anti-dilutive common share equivalents 689 94 In September 2016, we issued the 2021 Convertible Notes, which give the holders, at our election, 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 could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $85.39 conversion price during the periods presented. During the three months ended March 31, 2018 and 2017 , the average market price of our common stock did not exceed the conversion price; therefore, shares issuable upon conversion of the 2021 Convertible Notes were not included in the diluted earnings per share calculation.

Subsidiary Guarantor Subsidiary

Subsidiary Guarantor Subsidiary Guarantor (Notes)	3 Months Ended
	Mar. 31, 2018
Subsidiary Guarantor [Abstract]
Guarantees [Text Block]	SUBSIDIARY GUARANTOR PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the condensed consolidating financial information separately for: (i) PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries; (ii) PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes; (iii) Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor, and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and (iv) Parent and subsidiaries on a consolidated basis ("Consolidated"). The Guarantor is 100 percent owned by the Parent. 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 condensed consolidating financial information follows the same accounting policies as described in the notes to the condensed consolidated financial statements. The following condensed consolidating financial statements have been prepared on the same basis of accounting as our condensed 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. Condensed Consolidating Balance Sheets March 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Current assets: Cash and cash equivalents $ 45,923 $ — $ — $ 45,923 Accounts receivable, net 143,250 37,775 — 181,025 Fair value of derivatives 28,610 — — 28,610 Prepaid expenses and other current assets 7,116 1,781 — 8,897 Total current assets 224,899 39,556 — 264,455 Properties and equipment, net 2,139,471 2,091,786 — 4,231,257 Assets held-for-sale, net 1,647 — — 1,647 Intercompany receivable 294,476 — (294,476 ) — Investment in subsidiaries 1,605,330 — (1,605,330 ) — Other assets 23,339 1,459 — 24,798 Total Assets $ 4,289,162 $ 2,132,801 $ (1,899,806 ) $ 4,522,157 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 113,529 $ 82,174 $ — $ 195,703 Production tax liability 35,309 1,341 — 36,650 Fair value of derivatives 110,683 — — 110,683 Funds held for distribution 80,203 17,408 — 97,611 Accrued interest payable 13,756 4 — 13,760 Other accrued expenses 33,136 641 — 33,777 Total current liabilities 386,616 101,568 — 488,184 Intercompany payable — 294,476 (294,476 ) — Long-term debt 1,154,528 — — 1,154,528 Deferred income taxes 62,088 125,095 — 187,183 Asset retirement obligations 67,922 5,983 — 73,905 Fair value of derivatives 26,426 — — 26,426 Other liabilities 94,208 349 — 94,557 Total liabilities 1,791,788 527,471 (294,476 ) 2,024,783 Commitments and contingent liabilities Stockholders' Equity Stockholders' equity Common shares 660 — — 660 Additional paid-in capital 2,504,663 1,766,777 (1,766,777 ) 2,504,663 Retained earnings (6,435 ) (161,447 ) 161,447 (6,435 ) Treasury shares (1,514 ) — — (1,514 ) Total stockholders' equity 2,497,374 1,605,330 (1,605,330 ) 2,497,374 Total Liabilities and Stockholders' Equity $ 4,289,162 $ 2,132,801 $ (1,899,806 ) $ 4,522,157 Condensed Consolidating Balance Sheets December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Current assets: Cash and cash equivalents $ 180,675 $ — $ — $ 180,675 Accounts receivable, net 160,490 37,108 — 197,598 Fair value of derivatives 14,338 — — 14,338 Prepaid expenses and other current assets 8,284 329 — 8,613 Total current assets 363,787 37,437 — 401,224 Properties and equipment, net 1,891,314 2,042,153 — 3,933,467 Assets held-for-sale, net 40,084 — — 40,084 Intercompany receivable 250,279 — (250,279 ) — Investment in subsidiaries 1,617,537 — (1,617,537 ) — Other assets 42,547 2,569 — 45,116 Total Assets $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 85,000 $ 65,067 $ — $ 150,067 Production tax liability 35,902 1,752 — 37,654 Fair value of derivatives 79,302 — — 79,302 Funds held for distribution 83,898 11,913 — 95,811 Accrued interest payable 11,812 3 — 11,815 Other accrued expenses 42,543 444 — 42,987 Total current liabilities 338,457 79,179 — 417,636 Intercompany payable — 250,279 (250,279 ) — Long-term debt 1,151,932 — — 1,151,932 Deferred income taxes 62,857 129,135 — 191,992 Asset retirement obligations 65,301 5,705 — 71,006 Fair value of derivatives 22,343 — — 22,343 Other liabilities 57,009 324 — 57,333 Total liabilities 1,697,899 464,622 (250,279 ) 1,912,242 Commitments and contingent liabilities Stockholders' Equity Stockholders' equity Common shares 659 — — 659 Additional paid-in capital 2,503,294 1,766,775 (1,766,775 ) 2,503,294 Retained earnings 6,704 (149,238 ) 149,238 6,704 Treasury shares (3,008 ) — — (3,008 ) Total stockholders' equity 2,507,649 1,617,537 (1,617,537 ) 2,507,649 Total Liabilities and Stockholders' Equity $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Condensed Consolidating Statements of Operations Three Months Ended March 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas, and NGLs sales $ 233,494 $ 71,731 $ — $ 305,225 Commodity price risk management loss, net (47,240 ) — — (47,240 ) Other income 2,516 99 — 2,615 Total revenues 188,770 71,830 — 260,600 Costs, expenses and other Lease operating expenses 21,362 8,274 — 29,636 Production taxes 16,081 4,088 — 20,169 Transportation, gathering, and processing expenses 3,231 4,082 — 7,313 Exploration, geologic, and geophysical expense 313 2,333 — 2,646 Impairment of properties and equipment 6 33,182 — 33,188 General and administrative expense 31,559 4,137 — 35,696 Depreciation, depletion and amortization 94,376 32,412 — 126,788 Accretion of asset retirement obligations 1,200 88 — 1,288 Loss on sale of properties and equipment 1,432 — — 1,432 Other expenses 2,768 — — 2,768 Total costs, expenses and other 172,328 88,596 — 260,924 Income (loss) from operations 16,442 (16,766 ) — (324 ) Interest expense (18,097 ) 568 — (17,529 ) Interest income 148 — — 148 Loss before income taxes (1,507 ) (16,198 ) — (17,705 ) Income tax benefit 577 3,989 — 4,566 Equity in loss of subsidiary (12,209 ) — 12,209 — Net loss $ (13,139 ) $ (12,209 ) $ 12,209 $ (13,139 ) Condensed Consolidating Statements of Operations Three Months Ended March 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas, and NGLs sales $ 170,739 $ 18,953 $ — $ 189,692 Commodity price risk management gain, net 80,704 — — 80,704 Other income 3,297 14 — 3,311 Total revenues 254,740 18,967 — 273,707 Costs, expenses and other Lease operating expenses 15,816 3,973 — 19,789 Production taxes 11,144 1,255 — 12,399 Transportation, gathering, and processing expenses 5,215 687 — 5,902 Exploration, geologic, and geophysical expense 271 683 — 954 Impairment of properties and equipment 604 1,589 — 2,193 General and administrative expense 23,529 2,786 — 26,315 Depreciation, depletion and amortization 101,738 7,578 — 109,316 Accretion of asset retirement obligations 1,685 83 — 1,768 Gain on sale of properties and equipment (160 ) — — (160 ) Other expenses 3,528 — — 3,528 Total costs, expenses and other 163,370 18,634 — 182,004 Income from operations 91,370 333 — 91,703 Interest expense (19,597 ) 130 — (19,467 ) Interest income 240 — — 240 Income before income taxes 72,013 463 — 72,476 Income tax expense (26,162 ) (168 ) — (26,330 ) Equity in income of subsidiary 295 — (295 ) — Net income $ 46,146 $ 295 $ (295 ) $ 46,146 Condensed Consolidating Statements of Cash Flows Three Months Ended March 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 149,009 $ 56,140 $ — $ 205,149 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (97,286 ) (99,631 ) — (196,917 ) Capital expenditures for other properties and equipment (701 ) (365 ) — (1,066 ) Acquisition of crude oil and natural gas properties, including settlement adjustments (180,825 ) — — (180,825 ) Proceeds from sale of properties and equipment 20 — — 20 Proceeds from divestiture 39,023 — — 39,023 Restricted cash 1,249 — — 1,249 Intercompany transfers (43,891 ) — 43,891 — Net cash from investing activities (282,411 ) (99,996 ) 43,891 (338,516 ) Cash flows from financing activities: Proceeds from revolving credit facility 35,000 — — 35,000 Repayment of revolving credit facility (35,000 ) — — (35,000 ) Purchase of treasury stock (2,255 ) — — (2,255 ) Other (344 ) (35 ) — (379 ) Intercompany transfers — 43,891 (43,891 ) — Net cash from financing activities (2,599 ) 43,856 (43,891 ) (2,634 ) Net change in cash, cash equivalents, and restricted cash (136,001 ) — — (136,001 ) Cash, cash equivalents, and restricted cash, beginning of period 189,925 — — 189,925 Cash, cash equivalents, and restricted cash, end of period $ 53,924 $ — $ — $ 53,924 Condensed Consolidating Statements of Cash Flows Three Months Ended March 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 131,661 $ 7,839 $ — $ 139,500 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (82,489 ) (47,337 ) — (129,826 ) Capital expenditures for other properties and equipment (890 ) 69 — (821 ) Acquisition of crude oil and natural gas properties, including settlement adjustments — 6,181 — 6,181 Proceeds from sale of properties and equipment 737 — — 737 Purchase of short-term investments (49,890 ) — — (49,890 ) Intercompany transfers (33,795 ) — 33,795 — Net cash from investing activities (166,327 ) (41,087 ) 33,795 (173,619 ) Cash flows from financing activities: Purchase of treasury stock (2,017 ) — — (2,017 ) Other (330 ) (10 ) — (340 ) Intercompany transfers — 33,795 (33,795 ) — Net cash from financing activities (2,347 ) 33,785 (33,795 ) (2,357 ) Net change in cash, cash equivalents, and restricted cash (37,013 ) 537 — (36,476 ) Cash, cash equivalents, and restricted cash, beginning of period 240,487 3,613 — 244,100 Cash, cash equivalents, and restricted cash, end of period $ 203,474 $ 4,150 $ — $ 207,624

Significant Accounting Policies

Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	On January 1, 2018, we adopted the new accounting standard that was issued by the FASB and the International Accounting Standards Board that converged their standard on revenue recognition and provides a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all the related amendments (“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 standard would have reduced our crude oil, natural gas, and NGLs sales by approximately $2.5 million in the first quarter of 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 the three months ended March 31, 2017, we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the new standard to have a significant impact on our net income going forward. 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 and prices received. We receive payment for sales from 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 the three months ended March 31, 2018 and 2017 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 purchase 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 indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when 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. 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 recognition 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 our natural gas average NYMEX pricing is based upon first-of-the-month index prices as 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.
Revenue Recognition, Customer Acquisitions [Policy Text Block]	Contract Assets. Contract assets include material contributions in aid of construction ("CIAC"), which are common in purchase/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 that are classified as current assets are included in prepaid expenses and other current assets on our condensed consolidated balance sheet. Contract assets that are classified as long-term are included in other assets on our condensed consolidated balance sheet. The contract assets will be amortized as a reduction to crude oil, natural gas, or NGLs sales revenue during the periods that the related production is transferred to the customer.
Consolidation, Policy	The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues, and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation
Basis of Accounting, Policy	In our opinion, the accompanying condensed consolidated financial statements contain all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2017 condensed consolidated balance sheet data was derived from audited statements, but does not include all disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2017 Form 10-K. Our results of operations and cash flows for the three months ended March 31, 2018 are not necessarily indicative of the results to be expected for the full year or any other future period
Recently Issued Accounting Policy [Policy Text Block]	In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. The standard has been updated and now includes amendments. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.
Earnings Per Share, Policy	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.

Summary of Significant Accounti

Summary of Significant Accounting Policies Cash, Cash Equivalents, and Restricted Cash (Tables)	3 Months Ended
	Mar. 31, 2018
Cash and Cash Equivalents [Line Items]
Schedule of Cash and Cash Equivalents [Table Text Block]	The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the condensed consolidated balance sheets at March 31, 2018 and December 31, 2017 , which sum to the total of cash, cash equivalents, and restricted cash in the condensed consolidated statements of cash flows: March 31, 2018 December 31, 2017 (in thousands) Cash and cash equivalents $ 45,923 $ 180,675 Restricted cash 8,001 9,250 Cash, cash equivalents, and restricted cash shown in the condensed consolidated statements of cash flows $ 53,924 $ 189,925

Business Combination Business25

Business Combination Business Combinations (Tables)	3 Months Ended
	Mar. 31, 2018
Business Combinations [Abstract]
Business Combination, Segment Allocation [Table Text Block]	The details of the estimated purchase price and the preliminary allocation of the purchase price for the transaction, are presented below (in thousands): March 31, 2018 Acquisition costs: Cash $ 171,091 Deposit made in prior period 21,000 Total cash consideration 192,091 Other purchase price adjustments 9,734 Total acquisition costs $ 201,825 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current assets $ 517 Crude oil and natural gas properties - proved 208,279 Other assets 2,796 Total assets acquired 211,592 Liabilities assumed: Current liabilities (5,080 ) Asset retirement obligations (4,687 ) Total liabilities assumed (9,767 ) Total identifiable net assets acquired $ 201,825

Revenue Recognition (Tables)

Revenue Recognition (Tables)	3 Months Ended
	Mar. 31, 2018
Revenue Recognition and Deferred Revenue [Abstract]
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 the three months ended March 31, 2018 : Amount (in thousands) Beginning balance, January 1, 2018 $ 4,446 Contract assets amortized as a reduction to crude oil, natural gas, and NGLs sales (1,233 ) Ending balance, March 31, 2018 $ 3,213
Disaggregation of Revenue [Table Text Block]	Disaggregated Revenue. The following table presents crude oil, natural gas, and NGLs sales disaggregated by commodity and operating region for the three months ended March 31, 2018 and 2017 (in thousands): Three Months Ended March 31, Revenue by Commodity and Operating Region 2018 2017 (2) Percentage Change Crude oil Wattenberg Field $ 170,306 $ 105,188 61.9 % Delaware Basin 53,418 13,538 294.6 % Utica Shale (1) 2,696 4,270 (36.9 )% Total $ 226,420 $ 122,996 84.1 % Natural gas Wattenberg Field $ 29,772 $ 32,614 (8.7 )% Delaware Basin 7,679 2,468 211.1 % Utica Shale (1) 1,110 1,860 (40.3 )% Total $ 38,561 $ 36,942 4.4 % NGLs Wattenberg Field $ 28,770 $ 25,318 13.6 % Delaware Basin 10,635 2,947 260.9 % Utica Shale (1) 839 1,489 (43.7 )% Total $ 40,244 $ 29,754 35.3 % Revenue by Operating Region Wattenberg Field $ 228,848 $ 163,120 40.3 % Delaware Basin 71,732 18,953 278.5 % Utica Shale (1) 4,645 7,619 (39.0 )% Total $ 305,225 $ 189,692 60.9 % ________________ (1) In March 2018, we completed the sale of our Utica Shale properties. (2) As we have elected the modified retrospective method of adoption, revenues for the three months ended March 31, 2017 have not been restated for the new revenue recognition standard. Such amounts would not have been material.

Fair Value Measurements and D27

Fair Value Measurements and Disclosures (Tables)	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	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: March 31, 2018 December 31, 2017 Significant Other Significant Total Significant Other Significant Total (in thousands) Assets: Total assets $ 22,467 $ 6,143 $ 28,610 $ 12,949 $ 1,389 $ 14,338 Total liabilities 122,133 14,976 137,109 90,569 11,076 101,645 Net liability $ (99,666 ) $ (8,833 ) $ (108,499 ) $ (77,620 ) $ (9,687 ) $ (87,307 )
Fair Value Assets and Liabilities Unobservable Input Reconciliation	The following table presents a reconciliation of our Level 3 assets measured at fair value: Three Months Ended March 31, 2018 2017 (in thousands) Fair value of Level 3 instruments, net liability beginning of period $ (9,687 ) $ (9,574 ) Changes in fair value included in condensed consolidated statement of operations line item: Commodity price risk management gain (loss), net (2,152 ) 13,360 Settlements included in condensed consolidated statement of operations line items: Commodity price risk management gain ( loss) , net 3,006 (1,470 ) Fair value of Level 3 instruments, net asset (liability) end of period $ (8,833 ) $ 2,316 Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item: Commodity price risk management gain ( loss) , net $ 1,205 $ 11,427

Fair Value Measurements and D28

Fair Value Measurements and Disclosures Fair value of the portion of long-term debt related to senior and convertible notes (Tables)	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
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 March 31, 2018 . Estimated Fair Value Percent of Par (in millions) Senior notes: 2021 Convertible Notes $ 194.0 97.0 % 2024 Senior Notes 409.0 102.3 % 2026 Senior Notes 593.3 98.9 %

Derivative Financial Instrume29

Derivative Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative [Line Items]
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	As of March 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 (Gas - BBtu Oil - MBbls) Weighted-Average Contract Price Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls) Weighted- Average Contract Price Fair Value March 31, 2018 (1) (in millions) Floors Ceilings Crude Oil NYMEX 2018 1,784.0 $ 46.64 $ 57.53 7,704.0 $ 52.54 $ (91.4 ) 2019 400.0 50.00 60.67 7,800.0 53.20 (42.9 ) Total Crude Oil 2,184.0 15,504.0 $ (134.3 ) Natural Gas NYMEX 2018 2,735.0 $ 3.00 $ 3.56 40,335.0 $ 2.94 $ 5.1 2019 — — — 4,004.0 2.77 (0.1 ) Total Natural Gas 2,735.0 44,339.0 $ 5.0 Basis Protection - Crude Oil Midland Cushing 2018 — $ — $ — 1,456.1 $ (0.10 ) $ 5.4 Total Basis Protection - Crude Oil — 1,456.1 $ 5.4 Basis Protection - Natural Gas CIG 2018 — $ — $ — 31,409.9 $ (0.43 ) $ 12.3 2019 — — — 4,004.0 (0.88 ) (0.1 ) Waha 2018 — — — 4,923.8 (0.50 ) 3.4 El Paso 2018 — — — 2,450.0 (0.62 ) 1.6 Total Basis Protection - Natural Gas — 42,787.7 $ 17.2 Propane Mont Belvieu 2018 — $ — $ — 714.4 $ 32.52 $ — Total Propane — 714.4 $ — Rollfactor (2) Crude Oil CMA 2018 — $ — $ — 4,192 $ 0.12 $ (1.8 ) Total Rollfactor — 4,192 $ (1.8 ) Commodity Derivatives Fair Value $ (108.5 ) _____________ (1) Approximately 21.5 percent of the fair value of our commodity derivative assets and 10.9 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). (2) These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month.	[1],[2]
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location [Table Text Block]	The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets: Fair Value Derivative instruments: Condensed consolidated balance sheet line item March 31, 2018 December 31, 2017 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 5,958 $ 7,340 Basis protection derivative contracts Fair value of derivatives 22,652 6,998 28,610 14,338 Non-current — — Total derivative assets $ 28,610 $ 14,338 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives 108,763 77,999 Basis protection derivative contracts Fair value of derivatives 122 234 Rollfactor derivative contracts Fair value of derivatives 1,798 1,069 110,683 79,302 Non-current Commodity derivative contracts Fair value of derivatives 26,447 22,343 Basis protection derivative contracts Fair value of derivatives (21 ) — 26,426 22,343 Total derivative liabilities $ 137,109 $ 101,645 The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations: Three Months Ended March 31, Condensed consolidated statement of operations line item 2018 2017 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (26,038 ) $ 551 Net change in fair value of unsettled derivatives (21,202 ) 80,153 Total commodity price risk management gain (loss), net $ (47,240 ) $ 80,704
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets: Fair Value Derivative instruments: Condensed consolidated balance sheet line item March 31, 2018 December 31, 2017 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 5,958 $ 7,340 Basis protection derivative contracts Fair value of derivatives 22,652 6,998 28,610 14,338 Non-current — — Total derivative assets $ 28,610 $ 14,338 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives 108,763 77,999 Basis protection derivative contracts Fair value of derivatives 122 234 Rollfactor derivative contracts Fair value of derivatives 1,798 1,069 110,683 79,302 Non-current Commodity derivative contracts Fair value of derivatives 26,447 22,343 Basis protection derivative contracts Fair value of derivatives (21 ) — 26,426 22,343 Total derivative liabilities $ 137,109 $ 101,645 The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations: Three Months Ended March 31, Condensed consolidated statement of operations line item 2018 2017 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (26,038 ) $ 551 Net change in fair value of unsettled derivatives (21,202 ) 80,153 Total commodity price risk management gain (loss), net $ (47,240 ) $ 80,704 Net settlements of commodity derivatives and net change in fair value of unsettled derivatives decreased for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017 as a result of the increase in future commodity prices during the first quarter of 2018 compared to a decrease during the first quarter of 2017. 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 condensed consolidated balance sheets. The following table reflects the impact of netting agreements on gross derivative assets and liabilities: As of March 31, 2018 Derivative instruments, recorded in condensed consolidated balance sheet, gross Effect of master netting agreements Derivative instruments, net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 28,610 $ (27,971 ) $ 639 Liability derivatives: Derivative instruments, at fair value $ 137,109 $ (27,971 ) $ 109,138 As of December 31, 2017 Derivative instruments, recorded in condensed consolidated balance sheet, 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
[1]	Approximately 21.5 percent of the fair value of our commodity derivative assets and 10.9 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).
[2]	These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month.

Properties and Equipment (Table

Properties and Equipment (Tables)	3 Months Ended
	Mar. 31, 2018
Oil and Gas Property [Abstract]
Property, Plant and Equipment	The following table presents the components of properties and equipment, net of accumulated depreciation, depletion, and amortization ("DD&A"): March 31, 2018 December 31, 2017 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 4,706,258 $ 4,356,922 Unproved 1,055,774 1,097,317 Total crude oil and natural gas properties 5,762,032 5,454,239 Infrastructure, pipeline, and other 125,529 109,359 Land and buildings 12,679 10,960 Construction in progress 294,311 196,024 Properties and equipment, at cost 6,194,551 5,770,582 Accumulated DD&A (1,963,294 ) (1,837,115 ) Properties and equipment, net $ 4,231,257 $ 3,933,467
Impairment of natural gas and crude oil properties	The following table presents impairment charges recorded for crude oil and natural gas properties: Three Months Ended March 31, 2018 2017 (in thousands) Impairment of proved and unproved properties $ 33,130 $ 2,102 Amortization of individually insignificant unproved properties 58 91 Impairment of crude oil and natural gas properties $ 33,188 $ 2,193
Disclosure of Long Lived Assets Held-for-sale [Table Text Block]	The following table presents balance sheet data related to assets held-for-sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities that are expected to be assumed by the purchasers: March 31, 2018 December 31, 2017 (in thousands) Assets Properties and equipment, net $ 1,647 $ 40,583 Total assets $ 1,647 $ 40,583 Liabilities Asset retirement obligation $ — $ 499 Total liabilities $ — $ 499 Assets held-for-sale, net $ 1,647 $ 40,084
Schedule of Aging of Capitalized Exploratory Well Costs [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 condensed consolidated balance sheets: March 31, 2018 December 31, 2017 (in thousands, except for number of wells) Beginning balance $ 15,448 $ — Additions to capitalized exploratory well costs pending the determination of proved reserves 17,143 51,776 Reclassifications to proved properties — (36,328 ) Ending balance $ 32,591 $ 15,448 Number of wells pending determination at period end 3 3

Other Accrued Expenses Other 31

Other Accrued Expenses Other Accrued Expenses (Tables)	3 Months Ended
	Mar. 31, 2018
Other Accrued Expense, Current [Abstract]
Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Current [Text Block]	The following table presents the components of other accrued expenses as of: March 31, 2018 December 31, 2017 (in thousands) Employee benefits $ 10,901 $ 22,383 Asset retirement obligations 15,944 15,801 Environmental expenses 2,074 1,374 Short-term deferred oil gathering credit 2,010 — Other 2,848 3,429 Other accrued expenses $ 33,777 $ 42,987
Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Noncurrent [Text Block]	The following table presents the components of other liabilities as of: March 31, 2018 December 31, 2017 (in thousands) Production taxes $ 63,454 $ 50,476 Long-term deferred oil gathering credit 21,608 — Other 9,495 6,857 Other liabilities $ 94,557 $ 57,333

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	Long-term debt consisted of the following as of: March 31, 2018 December 31, 2017 (in thousands) Senior notes: 1.125% Convertible Notes due 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (28,478 ) (30,328 ) Unamortized debt issuance costs (3,371 ) (3,615 ) 1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs 168,151 166,057 5.75% Senior Notes due 2026: Principal amount 600,000 600,000 Unamortized debt issuance costs (7,298 ) (7,555 ) 5.75% Senior Notes due 2026, net of unamortized debt issuance costs 592,702 592,445 6.125% Senior Notes due 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (6,325 ) (6,570 ) 6.125% Senior Notes due 2024, net of unamortized debt issuance costs 393,675 393,430 Total senior notes 1,154,528 1,151,932 Revolving credit facility — — Total long-term debt, net of unamortized discount and debt issuance costs $ 1,154,528 $ 1,151,932

Capital Leases (Tables)

Capital Leases (Tables)	3 Months Ended
	Mar. 31, 2018
Capital Leases [Abstract]
Schedule of Capital Leased Assets [Table Text Block]	The following table presents vehicles under capital lease as of: March 31, 2018 December 31, 2017 (in thousands) Vehicles $ 6,500 $ 6,249 Accumulated depreciation (2,271 ) (1,882 ) $ 4,229 $ 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 March 31, Amount (in thousands) 2019 $ 1,952 2020 2,061 2021 1,247 5,260 Less executory cost (400 ) Less amount representing interest (501 ) Present value of minimum lease payments $ 4,359 Short-term capital lease obligations $ 1,789 Long-term capital lease obligations 2,570 $ 4,359

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties: Amount (in thousands) Balance at December 31, 2017 $ 87,306 Obligations incurred with development activities 620 Obligations incurred with acquisition 4,687 Accretion expense 1,288 Revisions in estimated cash flows 50 Obligations discharged with asset retirements and divestiture (4,102 ) Balance at March 31, 2018 89,849 Less current portion (15,944 ) Long-term portion $ 73,905

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contigencies (Tables)	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Supply Commitment	: For the Twelve Months Ending March 31, Area 2019 2020 2021 2022 2023 and Total Expiration Natural gas (MMcf) Wattenberg Field 7,416 27,794 31,025 31,025 114,272 211,532 April 30, 2026 Delaware Basin 25,520 25,600 11,000 — — 62,120 December 31, 2020 Gas Marketing 7,117 7,136 7,117 6,965 2,830 31,165 August 31, 2022 Total 40,053 60,530 49,142 37,990 117,102 304,817 Crude oil (MBbls) Wattenberg Field 7,438 8,062 5,085 4,563 4,937 30,085 April 30, 2023 Delaware Basin 4,493 8,227 8,580 7,392 14,080 42,772 December 31, 2023 Total 11,931 16,289 13,665 11,955 19,017 72,857 Dollar commitment (in thousands) $ 64,690 $ 99,560 $ 69,434 $ 65,060 $ 160,183 $ 458,927

Common Stock (Tables)

Common Stock (Tables)	3 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by 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: Three Months Ended March 31, 2018 2017 (in thousands) Stock-based compensation expense $ 5,261 $ 4,453 Income tax benefit (1,261 ) (1,666 ) Net stock-based compensation expense $ 4,000 $ 2,787
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the three months ended March 31, 2018 : Shares Weighted-Average Non-vested at December 31, 2017 472,132 $ 60.23 Granted 136,256 50.94 Vested (66,253 ) 58.16 Forfeited (5,800 ) 68.18 Non-vested at March 31, 2018 536,335 58.04 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Three Months Ended March 31, 2018 2017 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 3,530 $ 3,602 Total intrinsic value of time-based awards non-vested 26,297 33,366 Market price per share as of March 31, 49.03 62.35 Weighted-average grant date fair value per share 50.94 73.28
Restricted Stock Awards, Market-Based, Valuation assumptions	he Compensation Committee of our Board of Directors awarded a total of 90,778 market-based restricted shares to our executive officers during the three months ended March 31, 2018 . In addition to continuous employment, the vesting of these shares is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2020, and can result in a payout between 0 percent and 200 percent of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards was computed using the Monte Carlo pricing model using the following assumptions: Three Months Ended March 31, 2018 2017 Expected term of award (in years) 3 3 Risk-free interest rate 2.4 % 1.4 % Expected volatility 42.3 % 51.4 % Weighted-average grant date fair value per share $ 69.98 $ 94.02
Schedule of Nonvested Performance-based Units Activity	The following table presents the change in non-vested market-based awards during the three months ended March 31, 2018 : Shares Weighted-Average Non-vested at December 31, 2017 52,349 $ 84.06 Granted 90,778 69.98 Forfeited (4,128 ) 94.02 Non-vested at March 31, 2018 138,999 74.57 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of Three Months Ended March 31, 2018 2017 (in thousands, except per share data) Total intrinsic value of market-based awards non-vested $ 6,815 $ 4,769 Market price per common share as of March 31, 49.03 62.35 Weighted-average grant date fair value per share 69.98 94.02

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation	The following table presents a reconciliation of the weighted-average diluted shares outstanding: Three Months Ended March 31, 2018 2017 (in thousands) Weighted-average common shares outstanding - basic 65,957 65,749 Dilutive effect of: Restricted stock — 211 Convertible notes — 157 Weighted-average common shares and equivalents outstanding - diluted 65,957 66,117
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	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: Three Months Ended March 31, 2018 2017 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: Restricted stock 491 76 Convertible notes — — Other equity-based awards 198 18 Total anti-dilutive common share equivalents 689 94

Subsidiary Guarantor Subsidia38

Subsidiary Guarantor Subsidiary Guarantor (Tables)	3 Months Ended
	Mar. 31, 2018
Subsidiary Guarantor [Abstract]
Schedule of Guarantor Obligations [Table Text Block]	The following condensed consolidating financial statements have been prepared on the same basis of accounting as our condensed 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. Condensed Consolidating Balance Sheets March 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Current assets: Cash and cash equivalents $ 45,923 $ — $ — $ 45,923 Accounts receivable, net 143,250 37,775 — 181,025 Fair value of derivatives 28,610 — — 28,610 Prepaid expenses and other current assets 7,116 1,781 — 8,897 Total current assets 224,899 39,556 — 264,455 Properties and equipment, net 2,139,471 2,091,786 — 4,231,257 Assets held-for-sale, net 1,647 — — 1,647 Intercompany receivable 294,476 — (294,476 ) — Investment in subsidiaries 1,605,330 — (1,605,330 ) — Other assets 23,339 1,459 — 24,798 Total Assets $ 4,289,162 $ 2,132,801 $ (1,899,806 ) $ 4,522,157 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 113,529 $ 82,174 $ — $ 195,703 Production tax liability 35,309 1,341 — 36,650 Fair value of derivatives 110,683 — — 110,683 Funds held for distribution 80,203 17,408 — 97,611 Accrued interest payable 13,756 4 — 13,760 Other accrued expenses 33,136 641 — 33,777 Total current liabilities 386,616 101,568 — 488,184 Intercompany payable — 294,476 (294,476 ) — Long-term debt 1,154,528 — — 1,154,528 Deferred income taxes 62,088 125,095 — 187,183 Asset retirement obligations 67,922 5,983 — 73,905 Fair value of derivatives 26,426 — — 26,426 Other liabilities 94,208 349 — 94,557 Total liabilities 1,791,788 527,471 (294,476 ) 2,024,783 Commitments and contingent liabilities Stockholders' Equity Stockholders' equity Common shares 660 — — 660 Additional paid-in capital 2,504,663 1,766,777 (1,766,777 ) 2,504,663 Retained earnings (6,435 ) (161,447 ) 161,447 (6,435 ) Treasury shares (1,514 ) — — (1,514 ) Total stockholders' equity 2,497,374 1,605,330 (1,605,330 ) 2,497,374 Total Liabilities and Stockholders' Equity $ 4,289,162 $ 2,132,801 $ (1,899,806 ) $ 4,522,157 Condensed Consolidating Balance Sheets December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Current assets: Cash and cash equivalents $ 180,675 $ — $ — $ 180,675 Accounts receivable, net 160,490 37,108 — 197,598 Fair value of derivatives 14,338 — — 14,338 Prepaid expenses and other current assets 8,284 329 — 8,613 Total current assets 363,787 37,437 — 401,224 Properties and equipment, net 1,891,314 2,042,153 — 3,933,467 Assets held-for-sale, net 40,084 — — 40,084 Intercompany receivable 250,279 — (250,279 ) — Investment in subsidiaries 1,617,537 — (1,617,537 ) — Other assets 42,547 2,569 — 45,116 Total Assets $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 85,000 $ 65,067 $ — $ 150,067 Production tax liability 35,902 1,752 — 37,654 Fair value of derivatives 79,302 — — 79,302 Funds held for distribution 83,898 11,913 — 95,811 Accrued interest payable 11,812 3 — 11,815 Other accrued expenses 42,543 444 — 42,987 Total current liabilities 338,457 79,179 — 417,636 Intercompany payable — 250,279 (250,279 ) — Long-term debt 1,151,932 — — 1,151,932 Deferred income taxes 62,857 129,135 — 191,992 Asset retirement obligations 65,301 5,705 — 71,006 Fair value of derivatives 22,343 — — 22,343 Other liabilities 57,009 324 — 57,333 Total liabilities 1,697,899 464,622 (250,279 ) 1,912,242 Commitments and contingent liabilities Stockholders' Equity Stockholders' equity Common shares 659 — — 659 Additional paid-in capital 2,503,294 1,766,775 (1,766,775 ) 2,503,294 Retained earnings 6,704 (149,238 ) 149,238 6,704 Treasury shares (3,008 ) — — (3,008 ) Total stockholders' equity 2,507,649 1,617,537 (1,617,537 ) 2,507,649 Total Liabilities and Stockholders' Equity $ 4,205,548 $ 2,082,159 $ (1,867,816 ) $ 4,419,891 Condensed Consolidating Statements of Operations Three Months Ended March 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas, and NGLs sales $ 233,494 $ 71,731 $ — $ 305,225 Commodity price risk management loss, net (47,240 ) — — (47,240 ) Other income 2,516 99 — 2,615 Total revenues 188,770 71,830 — 260,600 Costs, expenses and other Lease operating expenses 21,362 8,274 — 29,636 Production taxes 16,081 4,088 — 20,169 Transportation, gathering, and processing expenses 3,231 4,082 — 7,313 Exploration, geologic, and geophysical expense 313 2,333 — 2,646 Impairment of properties and equipment 6 33,182 — 33,188 General and administrative expense 31,559 4,137 — 35,696 Depreciation, depletion and amortization 94,376 32,412 — 126,788 Accretion of asset retirement obligations 1,200 88 — 1,288 Loss on sale of properties and equipment 1,432 — — 1,432 Other expenses 2,768 — — 2,768 Total costs, expenses and other 172,328 88,596 — 260,924 Income (loss) from operations 16,442 (16,766 ) — (324 ) Interest expense (18,097 ) 568 — (17,529 ) Interest income 148 — — 148 Loss before income taxes (1,507 ) (16,198 ) — (17,705 ) Income tax benefit 577 3,989 — 4,566 Equity in loss of subsidiary (12,209 ) — 12,209 — Net loss $ (13,139 ) $ (12,209 ) $ 12,209 $ (13,139 ) Condensed Consolidating Statements of Operations Three Months Ended March 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas, and NGLs sales $ 170,739 $ 18,953 $ — $ 189,692 Commodity price risk management gain, net 80,704 — — 80,704 Other income 3,297 14 — 3,311 Total revenues 254,740 18,967 — 273,707 Costs, expenses and other Lease operating expenses 15,816 3,973 — 19,789 Production taxes 11,144 1,255 — 12,399 Transportation, gathering, and processing expenses 5,215 687 — 5,902 Exploration, geologic, and geophysical expense 271 683 — 954 Impairment of properties and equipment 604 1,589 — 2,193 General and administrative expense 23,529 2,786 — 26,315 Depreciation, depletion and amortization 101,738 7,578 — 109,316 Accretion of asset retirement obligations 1,685 83 — 1,768 Gain on sale of properties and equipment (160 ) — — (160 ) Other expenses 3,528 — — 3,528 Total costs, expenses and other 163,370 18,634 — 182,004 Income from operations 91,370 333 — 91,703 Interest expense (19,597 ) 130 — (19,467 ) Interest income 240 — — 240 Income before income taxes 72,013 463 — 72,476 Income tax expense (26,162 ) (168 ) — (26,330 ) Equity in income of subsidiary 295 — (295 ) — Net income $ 46,146 $ 295 $ (295 ) $ 46,146 Condensed Consolidating Statements of Cash Flows Three Months Ended March 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 149,009 $ 56,140 $ — $ 205,149 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (97,286 ) (99,631 ) — (196,917 ) Capital expenditures for other properties and equipment (701 ) (365 ) — (1,066 ) Acquisition of crude oil and natural gas properties, including settlement adjustments (180,825 ) — — (180,825 ) Proceeds from sale of properties and equipment 20 — — 20 Proceeds from divestiture 39,023 — — 39,023 Restricted cash 1,249 — — 1,249 Intercompany transfers (43,891 ) — 43,891 — Net cash from investing activities (282,411 ) (99,996 ) 43,891 (338,516 ) Cash flows from financing activities: Proceeds from revolving credit facility 35,000 — — 35,000 Repayment of revolving credit facility (35,000 ) — — (35,000 ) Purchase of treasury stock (2,255 ) — — (2,255 ) Other (344 ) (35 ) — (379 ) Intercompany transfers — 43,891 (43,891 ) — Net cash from financing activities (2,599 ) 43,856 (43,891 ) (2,634 ) Net change in cash, cash equivalents, and restricted cash (136,001 ) — — (136,001 ) Cash, cash equivalents, and restricted cash, beginning of period 189,925 — — 189,925 Cash, cash equivalents, and restricted cash, end of period $ 53,924 $ — $ — $ 53,924 Condensed Consolidating Statements of Cash Flows Three Months Ended March 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 131,661 $ 7,839 $ — $ 139,500 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (82,489 ) (47,337 ) — (129,826 ) Capital expenditures for other properties and equipment (890 ) 69 — (821 ) Acquisition of crude oil and natural gas properties, including settlement adjustments — 6,181 — 6,181 Proceeds from sale of properties and equipment 737 — — 737 Purchase of short-term investments (49,890 ) — — (49,890 ) Intercompany transfers (33,795 ) — 33,795 — Net cash from investing activities (166,327 ) (41,087 ) 33,795 (173,619 ) Cash flows from financing activities: Purchase of treasury stock (2,017 ) — — (2,017 ) Other (330 ) (10 ) — (340 ) Intercompany transfers — 33,795 (33,795 ) — Net cash from financing activities (2,347 ) 33,785 (33,795 ) (2,357 ) Net change in cash, cash equivalents, and restricted cash (37,013 ) 537 — (36,476 ) Cash, cash equivalents, and restricted cash, beginning of period 240,487 3,613 — 244,100 Cash, cash equivalents, and restricted cash, end of period $ 203,474 $ 4,150 $ — $ 207,624

Nature of Operations and Basi39

Nature of Operations and Basis of Presentation Additional Information (Details)	3 Months Ended
	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Oil and gas producing wells, gross	3,000
Number of Operating Segments	2

Summary of Significant Accoun40

Summary of Significant Accounting Policies Reconciliation of cash, cash equivalents, and restricted cash (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Cash and cash equivalents	$ 45,923	$ 180,675
Restricted Cash	8,001	9,250
Restricted Cash and Cash Equivalents	$ 53,924	$ 189,925

Business Combination Business41

Business Combination Business Combination (Details) a in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)aWells
Business Acquisition [Line Items]
Escrow Deposit Disbursements Related to Property Acquisition	$ 21,000
Business Acquisition Purchase Price Allocation Asset Retirement Obligation	$ (4,687)
Oil and gas producing wells, gross	3,000
Bayswater Acquisition [Member]
Business Acquisition [Line Items]
Payments to Acquire Business Two, Net of Cash Acquired	$ 171,091
Payments to Acquire Businesses, Gross	192,091
Purchase Accounting Adjustments	9,734
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets	517
Business Acquisitions Purchase Price Allocation Proved Natural Gas Properties	208,279
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	2,796
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	211,592
Business Combination, Contingent Consideration, Liability, Current	(5,080)
Business Acquisition Purchase Price Allocation Asset Retirement Obligation	(4,687)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities	(9,767)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 201,825
Acquired Acreage | a	7,400
Oil and gas drilling locations, gross | Wells	220
Productive Oil Wells, Number of Wells, Net | Wells	24

Revenue Recognition Contract As

Revenue Recognition Contract Assets (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Capitalized Contract Cost, Gross	$ 3,213	$ 4,446
Capitalized Contract Cost, Amortization	$ (1,233)

Revenue Recognition Accounts Re

Revenue Recognition Accounts Receivable (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Accounts Receivable, Gross	$ 145.3	$ 154.3

Revenue Recognition Revenue by

Revenue Recognition Revenue by Commodity and Location (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenue from Contract with Customer, Excluding Assessed Tax	$ 305,225	$ 189,692
Revenue year over year percentage change [Line Items]	60.90%
Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 4,645	7,619
Revenue year over year percentage change [Line Items]	(39.00%)
Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 71,732	18,953
Revenue year over year percentage change [Line Items]	278.50%
Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	$ 228,848	163,120
Revenue year over year percentage change [Line Items]	40.30%
NGL [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 40,244	29,754
Revenue year over year percentage change [Line Items]	35.30%
NGL [Member] | Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	$ 28,770	25,318
Revenue year over year percentage change [Line Items]	13.60%
NGL [Member] | Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 10,635	2,947
Revenue year over year percentage change [Line Items]	260.90%
NGL [Member] | Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 839	1,489
Revenue year over year percentage change [Line Items]	(43.70%)
Natural Gas [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 38,561	36,942
Revenue year over year percentage change [Line Items]	4.40%
Natural Gas [Member] | Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	$ 29,772	32,614
Revenue year over year percentage change [Line Items]	(8.70%)
Natural Gas [Member] | Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 7,679	2,468
Revenue year over year percentage change [Line Items]	211.10%
Natural Gas [Member] | Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 1,110	1,860
Revenue year over year percentage change [Line Items]	(40.30%)
Crude Oil [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 226,420	122,996
Revenue year over year percentage change [Line Items]	84.10%
Crude Oil [Member] | Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	$ 170,306	105,188
Revenue year over year percentage change [Line Items]	61.90%
Crude Oil [Member] | Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 53,418	13,538
Revenue year over year percentage change [Line Items]	294.60%
Crude Oil [Member] | Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 2,696	$ 4,270
Revenue year over year percentage change [Line Items]	(36.90%)

Revenue Recognition Revenue, In

Revenue Recognition Revenue, Initial Application Period Cumulative Effect Transition (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Revenue from Contract with Customer [Abstract]
Revenue, Initial Application Period Cumulative Effect Transition, Explanation of Change	$ 2.5

Fair Value Measurements and D46

Fair Value Measurements and Disclosures (Details) - Fair Value - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Assets and Liabilities at Fair Value
Total assets	$ 28,610	$ 14,338
Total liabilities	137,109	101,645
Net asset (fair value)	(108,499)	(87,307)
Significant Other Observable Inputs (Level 2)
Assets and Liabilities at Fair Value
Total assets	22,467	12,949
Total liabilities	122,133	90,569
Net asset (fair value)	(99,666)	(77,620)
Significant Unobservable Inputs (Level 3)
Assets and Liabilities at Fair Value
Total assets	6,143	1,389
Total liabilities	14,976	11,076
Net asset (fair value)	$ (8,833)	$ (9,687)

Reconciliation of Level 3 Fair

Reconciliation of Level 3 Fair Value Measurements (Details) - Derivative Financial Instrument Net Assets - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Roll-forward of Level 3 Assets
Fair Value, net assets, beginning of period	$ (9,687)	$ (9,574)
Fair Value, net assets, end of period	(8,833)	2,316
Commodity Price Risk Management (loss), net
Roll-forward of Level 3 Assets
Changes in fair value included in statement of operations line item:	(2,152)	13,360
Settlements included in statement of operations line items:	3,006	(1,470)
Net change in fair value of unsettled derivatives included in statement of operations line item	$ 1,205	$ 11,427

Fair Value Measurements and D48

Fair Value Measurements and Disclosures Notes Receivable (Details) $ in Millions	Mar. 31, 2018USD ($)
1.125% Convertible Senior Notes due 2021 [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes Payable, Fair Value Disclosure	$ 194
Senior Notes fair value	97.00%
5.75% Senior Notes due 2026 [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes Payable, Fair Value Disclosure	$ 593.3
Senior Notes fair value	98.90%
6.125% Senior Notes due 2024 [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes Payable, Fair Value Disclosure	$ 409
Senior Notes fair value	102.30%

Fair Value of Derivative and Ba

Fair Value of Derivative and Balance Sheet Location (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value
Derivative Asset, Fair Value, Gross Asset	$ 28,610	$ 14,338
Derivative Liability, Fair Value, Gross Liability	137,109	101,645
Current Assets
Derivatives, Fair Value
Fair Value of Derivatives	22,652	6,998
Derivative Asset, Fair Value, Gross Asset	28,610	14,338
Non Current Assets
Derivatives, Fair Value
Derivative Asset, Fair Value, Gross Asset	0	0
Current Liabilities
Derivatives, Fair Value
Fair Value of Derivatives	122	234
Derivative Liability, Fair Value, Gross Liability	110,683	79,302
Non Current Liabilities
Derivatives, Fair Value
Fair Value of Derivatives	(21)	0
Derivative Liability, Fair Value, Gross Liability	26,426	22,343
Rollfactor Derivative Contracts Related to Natural Gas and Crude Oil Sales [Member] [Member] | Current Liabilities
Derivatives, Fair Value
Fair Value of Derivatives	1,798	1,069
Commodity Contracts Related to Natural Gas and Crude Oil Sales | Current Assets
Derivatives, Fair Value
Fair Value of Derivatives	5,958	7,340
Commodity Contracts Related to Natural Gas and Crude Oil Sales | Current Liabilities
Derivatives, Fair Value
Fair Value of Derivatives	108,763	77,999
Commodity Contracts Related to Natural Gas and Crude Oil Sales | Non Current Liabilities
Derivatives, Fair Value
Derivative Liability, Fair Value, Gross Liability	$ 26,447	$ 22,343

Impact of Derivative Instrument

Impact of Derivative Instruments on Statement of Operations (Details) - Commodity Price Risk Management (loss), net - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative [Line Items]
Net settlements	$ (26,038)	$ 551
Net change in fair value of unsettled derivatives	(21,202)	80,153
Total commodity price risk management gain (loss), net	$ (47,240)	$ 80,704

Derivative Financial Instrume51

Derivative Financial Instruments Impact of Netting Agreements (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivative Asset:
Derivative assets, gross	$ 28,610	$ 14,338
Effect of master netting agreements	(27,971)	(14,173)
Derivative asset, net	639	165
Derivative Liability:
Derivative liability, gross	137,109	101,645
Effect of master netting agreements	(27,971)	(14,173)
Derivative liability, net	$ 109,138	$ 87,472

Derivative Financial Instrume52

Derivative Financial Instruments Outstanding Derivative Contracts (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)MMBTU$ / UnitMBbls
Derivative [Line Items]
FV Commodity Derivatives Assets measured with Level 3	21.50%
Derivative, Fair Value, Net	$ (108.5)
FV Commodity Derivatives Liabilities measured with Level 3	10.90%
Natural Gas [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	$ 5
Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	(134.3)
2018 | Natural Gas [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	5.1
2018 | Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	(91.4)
2019 | Natural Gas [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	(0.1)
2019 | Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	$ (42.9)
CMA [Member] | Crude Oil [Member] | 2018
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	0.12
Mont Belvieu [Member] | Propane [Member] | 2018
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	32.52
El Paso [Member] | Natural Gas [Member] | 2018
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	(0.62)
Waha [Member] | Natural Gas [Member] | 2018
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	(0.50)
CIG [Member] | Natural Gas [Member] | 2018
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	(0.43)
CIG [Member] | Natural Gas [Member] | 2019
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	(0.88)
CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member] | 2018
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	2.94
Derivative, Floor Price | $ / Unit	3
Derivative, Cap Price | $ / Unit	3.56
CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member] | 2019
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	2.77
CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member] | 2018
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	52.54
Derivative, Floor Price | $ / Unit	46.64
Derivative, Cap Price | $ / Unit	57.53
CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member] | 2019
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	53.20
Derivative, Floor Price | $ / Unit	50
Derivative, Cap Price | $ / Unit	60.67
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Crude Oil [Member] | 2018
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / Unit	(0.10)
Commodity Option [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	2,735
Commodity Option [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	2,184
Commodity Option [Member] | 2018 | Natural Gas [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	2,735
Commodity Option [Member] | 2018 | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	1,784
Commodity Option [Member] | 2019 | Natural Gas [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	0
Commodity Option [Member] | 2019 | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	400
Rollfactor - CMA [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	4,192
Derivative, Fair Value, Net	$ (1.8)
Rollfactor - CMA [Member] | 2018 | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	4,192
Derivative, Fair Value, Net	$ (1.8)
Basis Protection Contracts Related to Natural Gas Marketing [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	$ 17.2
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	42,787.7
Basis Protection - El Paso [Member] | 2018 | Natural Gas [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	$ 1.6
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	2,450
Basis Protection - Waha [Member] | 2018 | Natural Gas [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	$ 3.4
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	4,923.8
Basis Protection - CIG [Member] | 2018 | Natural Gas [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	$ 12.3
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	31,409.9
Basis Protection - CIG [Member] | 2019 | Natural Gas [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	$ (0.1)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	4,004
Basis Protection - Midland Cushing [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	1,456.1
Derivative, Fair Value, Net	$ 5.4
Basis Protection - Midland Cushing [Member] | 2018 | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	1,456.1
Derivative, Fair Value, Net	$ 5.4
Energy Related Derivative [Member] | Propane [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	714.4
Derivative, Fair Value, Net	$ 0
Energy Related Derivative [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	44,339
Energy Related Derivative [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	15,504
Energy Related Derivative [Member] | 2018 | Propane [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	714.4
Derivative, Fair Value, Net	$ 0
Energy Related Derivative [Member] | 2018 | Natural Gas [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	40,335
Energy Related Derivative [Member] | 2018 | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	7,704
Energy Related Derivative [Member] | 2019 | Natural Gas [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	4,004
Energy Related Derivative [Member] | 2019 | Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	7,800

Properties and Equipment (Detai

Properties and Equipment (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018USD ($)Wells	Dec. 31, 2017USD ($)Wells	Dec. 31, 2016USD ($)
Property, Plant and Equipment [Line Items]
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves	$ 17,143	$ 51,776
Proved Natural Gas and Crude Oil Properties	4,706,258	4,356,922
Unproved Natural Gas and Crude Oil Properties	1,055,774	1,097,317
Total Natural Gas and Crude Oil Properties	5,762,032	5,454,239
Equipment and other	125,529	109,359
Land and Buildings	12,679	10,960
Construction in Progress	294,311	196,024
Properties and equipment, at cost	6,194,551	5,770,582
Accumulated DD&A	(1,963,294)	(1,837,115)
Property, Plant and Equipment, Net	4,231,257	3,933,467
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves	0	(36,328)
Capitalized Exploratory Well Costs	$ 32,591	$ 15,448	$ 0
Wells to be completed | Wells	3	3

Impairment of Natural Gas and C

Impairment of Natural Gas and Crude Oil Properties (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Impairment of natural gas and crude oil properties [Line Items]
Impairment of Leasehold	$ 33,130	$ 2,102
Delaware Basin Unproved Property Impairment	6,300
Impairment of proved ad unproved properties	26,900
Amortization of Individually Insignificant Unproved Properties	58	91
Impairment of Oil and Gas Properties	33,188	2,193
Impairment of properties and equipment	$ 33,188	$ 2,193

Properties and Equipment Assets

Properties and Equipment Assets Held for Sale (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Long Lived Assets Held-for-sale [Line Items]
Impairment of properties and equipment	$ 33,188	$ 2,193
Proceeds from Sale of Property Held-for-sale	39,000
(Gain) loss on sale of properties and equipment	1,432	(160)
Properties and equipment, net	4,231,257		$ 3,933,467
Assets	4,522,157		4,419,891
Asset retirement obligations	73,905		71,006
Liabilities	2,024,783		1,912,242
Proceeds from sale of properties and equipment	20	$ 737
Gain (Loss) on Sale of Properties, before Applicable Income Taxes	300
Utica Shale [Member]
Long Lived Assets Held-for-sale [Line Items]
Properties and equipment, net	1,647		40,583
Assets	1,647		40,583
Asset retirement obligations	0		499
Liabilities	0		499
Assets Held-for-sale, Not Part of Disposal Group, Other			40,084
Utica Shale
Long Lived Assets Held-for-sale [Line Items]
Assets Held-for-sale, Not Part of Disposal Group, Other	1,647
Proceeds from sale of properties and equipment	1,900
Utica Shale [Member]
Long Lived Assets Held-for-sale [Line Items]
(Gain) loss on sale of properties and equipment	$ 1,400
Assets Held-for-sale, Not Part of Disposal Group			36,800
Utica Shale
Long Lived Assets Held-for-sale [Line Items]
Assets Held-for-sale, Not Part of Disposal Group			$ 3,300

Other Accrued Expenses Other 56

Other Accrued Expenses Other Accrued Expenses (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Schedule of Other Liabilities [Line Items]
Saddle Butte Rockies Midstream Amendment Payment	$ 24,100
Production Tax Liability	63,454		$ 50,476
Other Accrued Liabilities, Noncurrent	94,557		57,333
Accrued Employee Benefits, Current	10,901		22,383
Asset Retirement Obligation, Current	15,944		15,801
Accrued Environmental Loss Contingencies, Current	2,074		1,374
Gas Gathering, Transportation, Marketing and Processing Costs	(7,313)	$ (5,902)
Amortization of Other Deferred Charges	400
Non Current Liabilities
Schedule of Other Liabilities [Line Items]
Gas Gathering, Transportation, Marketing and Processing Costs	21,608		0
Other Accrued Liabilities	9,495		6,857
Current Liabilities
Schedule of Other Liabilities [Line Items]
Gas Gathering, Transportation, Marketing and Processing Costs	2,010		0
Other Accrued Liabilities	$ 2,848		$ 3,429

Other Accrued Expenses Schedule

Other Accrued Expenses Schedule of Other Accrued Expense (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Schedule of Other Accrued Expense [Line Items]
Accrued Employee Benefits, Current	$ 10,901		$ 22,383
Asset Retirement Obligation, Current	15,944		15,801
Accrued Environmental Loss Contingencies, Current	2,074		1,374
Transportation, gathering, and processing expenses	7,313	$ 5,902
Other accrued expenses	33,777		42,987
Current Liabilities
Schedule of Other Accrued Expense [Line Items]
Transportation, gathering, and processing expenses	(2,010)		0
Other Accrued Liabilities	2,848		3,429
Non Current Liabilities
Schedule of Other Accrued Expense [Line Items]
Transportation, gathering, and processing expenses	(21,608)		0
Other Accrued Liabilities	$ 9,495		$ 6,857

Schedule of Long-Term Debt (Det

Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Sep. 14, 2016
Debt Instrument
Total senior notes	$ 1,154,528	$ 1,151,932
Total debt, net of discount and unamortized debt issuance costs	1,154,528	1,151,932
Long-term debt	1,154,528	1,151,932
1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument
Principal amount	200,000	200,000
Unamortized Discount	(28,478)	(30,328)
Unamortized Debt Issuance Expense	(3,371)	(3,615)	$ (4,800)
Convertible senior notes net of discount	168,151	166,057
5.75% Senior Notes due 2026 [Member]
Debt Instrument
Unamortized Debt Issuance Expense	(7,298)	(7,555)
Principal amount	600,000	600,000
Senior notes, net of unamortized debt issuance costs	592,702	592,445
6.125% Senior Notes due 2024 [Member]
Debt Instrument
Unamortized Debt Issuance Expense	(6,325)	(6,570)	$ (7,800)
Principal amount	400,000	400,000
Senior notes, net of unamortized debt issuance costs	393,675	393,430
Revolving Credit Facility
Debt Instrument
Revolving credit facility	$ 0	$ 0

Long-Term Debt Additional Infor

Long-Term Debt Additional Information (Details) $ / shares in Units, $ in Thousands	May 15, 2026	Sep. 12, 2016	Mar. 31, 2018USD ($)$ / sharesRate	Dec. 31, 2017USD ($)Rate	Sep. 14, 2016USD ($)
Debt Instrument
Convertible Note, Conversion Price | $ / shares			$ 85.39
Debt Instrument, Maturity Date	May 15, 2026		Sep. 15, 2021
Debt Issuance Costs, Line of Credit Arrangements, Net			$ 5,500	$ 6,200
Supplementary Leverage Ratio			1.7
Current Ratio			2.5
5.75% Senior Notes due 2026 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage | Rate				5.75%
Debt Instrument, Issuance Date				Nov. 29, 2017
1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage | Rate			1.125%
Debt Instrument, Issuance Date			Sep. 12, 2016
6.125% Senior Notes due 2024 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage | Rate			6.125%
Debt Instrument, Issuance Date		Sep. 12, 2016
Revolving Credit Facility
Debt Instrument
Line of Credit Facility, Expiration Date			May 21, 2020
5.75% Senior Notes due 2026 [Member]
Debt Instrument
Convertible senior notes fair value				$ 600,000
Debt Issuance Costs, Gross				$ 7,600
Minimum [Member] | Revolving Credit Facility
Debt Instrument
Line of Credit Facility, Maximum Borrowing Capacity ($)			$ 700,000
Maximum [Member] | Revolving Credit Facility
Debt Instrument
Line of Credit Facility, Maximum Borrowing Capacity ($)			950,000
Maximum Borrowing Base [Member] | Revolving Credit Facility
Debt Instrument
Line of Credit Facility, Maximum Borrowing Capacity ($)			$ 1,100,000
First Payment | 5.75% Senior Notes due 2026 [Member]
Debt Instrument
Debt Instrument, Frequency of Periodic Payment				May 15
First Payment | 1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument
Debt Instrument, Frequency of Periodic Payment			March 15
First Payment | 6.125% Senior Notes due 2024 [Member]
Debt Instrument
Debt Instrument, Frequency of Periodic Payment			March 15
Second Payment | 5.75% Senior Notes due 2026 [Member]
Debt Instrument
Debt Instrument, Frequency of Periodic Payment				November 15
Second Payment | 1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument
Debt Instrument, Frequency of Periodic Payment			September 15
Second Payment | 6.125% Senior Notes due 2024 [Member]
Debt Instrument
Debt Instrument, Frequency of Periodic Payment			September 15
Revolving Credit Facility
Debt Instrument
Long-term Line of Credit			$ 0	$ 0
1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument
Convertible senior notes fair value			200,000	200,000
Liability component of gross proceeds of Convertible Notes			160,500
Unamortized Debt Issuance Expense			$ (3,371)	$ (3,615)	$ (4,800)
Debt Instrument, Interest Rate, Effective Percentage | Rate			5.80%
Alternate Base Rate Option [Member]
Debt Instrument
Line of Credit Facility, Interest Rate at Period End | Rate			1.25%
LIBOR Option [Member]
Debt Instrument
Line of Credit Facility, Interest Rate at Period End | Rate			2.25%
Unused Commitment Fee [Member]
Debt Instrument
Line of Credit Facility, Interest Rate at Period End | Rate			0.50%

Capital Leases Capital Leases (

Capital Leases Capital Leases (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Capital Leased Assets [Line Items]
Vehicles	$ 6,500	$ 6,249
Accumulated Depreciation	(2,271)	(1,882)
Capital Leased Assets, Net	$ 4,229	$ 4,367

Capital Leases Minimum Lease Pa

Capital Leases Minimum Lease Payments (Details) $ in Thousands	Mar. 31, 2018USD ($)
Capital Leased Assets [Line Items]
Future Minimum Payments	$ 5,260
Executory Costs	(400)
Amount representing interest	(501)
Present Value of Net Minimum Payments	4,359
Short-term Capital Lease Obligations	1,789
Long-Term Capital Lease Obligations	2,570
Total Capital Lease Obligations	4,359
2,019
Capital Leased Assets [Line Items]
Future Minimum Payments	1,952
2,020
Capital Leased Assets [Line Items]
Future Minimum Payments	2,061
2,021
Capital Leased Assets [Line Items]
Future Minimum Payments	$ 1,247

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Effective Income Tax Rate, Continuing Operations	25.80%	36.30%
Other Tax Expense (Benefit)	$ 0.2
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	1.20%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis
Balance at beginning of period	$ 87,306
Obligations incurred with development activities	620
Business Acquisition Purchase Price Allocation Asset Retirement Obligation	4,687
Accretion expense	1,288	$ 1,768
Asset Retirement Obligation, Revision of Estimate	50
Obligations discharged asset retirements	(4,102)
Balance end of period	89,849
Less current portion	(15,944)		$ (15,801)
Asset retirement obligations	$ 73,905		$ 71,006
Minimum [Member]
Reconciliation Of Changes In Asset Retirement Obligations [Line Items]
Credit Adjusted Risk-Free Rate used to discount plugging and abandonment liabilities range	6.50%
Maximum [Member]
Reconciliation Of Changes In Asset Retirement Obligations [Line Items]
Credit Adjusted Risk-Free Rate used to discount plugging and abandonment liabilities range	7.50%

Commitments and Contingencies64

Commitments and Contingencies Commitments and Contigencies (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)MMcfbblMBbls
Supply Commitment
Dollar Commitment ($ in thousands) | $	$ 458,927
Appalachiain Basin
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	31,165
Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	211,532
Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	62,120
First Year Commitment [Member]
Supply Commitment
Dollar Commitment ($ in thousands) | $	$ 64,690
First Year Commitment [Member] | Appalachiain Basin
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
First Year Commitment [Member] | Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	7,416
First Year Commitment [Member] | Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	25,520
Second Year Commitment [Member]
Supply Commitment
Dollar Commitment ($ in thousands) | $	$ 99,560
Second Year Commitment [Member] | Appalachiain Basin
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	7,136
Second Year Commitment [Member] | Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	27,794
Second Year Commitment [Member] | Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	25,600
Third Year Commitment [Member]
Supply Commitment
Dollar Commitment ($ in thousands) | $	$ 69,434
Third Year Commitment [Member] | Appalachiain Basin
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
Third Year Commitment [Member] | Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	31,025
Third Year Commitment [Member] | Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	11,000
Fourth Year Commitment [Member]
Supply Commitment
Dollar Commitment ($ in thousands) | $	$ 65,060
Fourth Year Commitment [Member] | Appalachiain Basin
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	6,965
Fourth Year Commitment [Member] | Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	31,025
Fourth Year Commitment [Member] | Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	0
commitments 5 years and beyond [Member]
Supply Commitment
Dollar Commitment ($ in thousands) | $	$ 160,183
commitments 5 years and beyond [Member] | Appalachiain Basin
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	2,830
commitments 5 years and beyond [Member] | Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	114,272
commitments 5 years and beyond [Member] | Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	0
Supply Contract Expiration Date [Member] | Appalachiain Basin
Supply Commitment
Supply Commitments Contract Expiration Date	Aug. 31, 2022
Supply Contract Expiration Date [Member] | Wattenberg Field
Supply Commitment
Supply Commitments Contract Expiration Date	Apr. 30, 2026
Supply Contract Expiration Date [Member] | Delaware Basin [Member]
Supply Commitment
Supply Commitments Contract Expiration Date	Dec. 31, 2020
Crude Oil [Member] | Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	30,085
Crude Oil [Member] | Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	42,772
Crude Oil [Member] | First Year Commitment [Member] | Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	7,438
Crude Oil [Member] | First Year Commitment [Member] | Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	4,493
Crude Oil [Member] | Second Year Commitment [Member] | Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	8,062
Crude Oil [Member] | Second Year Commitment [Member] | Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	8,227
Crude Oil [Member] | Third Year Commitment [Member] | Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	5,085
Crude Oil [Member] | Third Year Commitment [Member] | Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	8,580
Crude Oil [Member] | Fourth Year Commitment [Member] | Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	4,563
Crude Oil [Member] | Fourth Year Commitment [Member] | Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	7,392
Crude Oil [Member] | commitments 5 years and beyond [Member] | Wattenberg Field
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	4,937
Crude Oil [Member] | commitments 5 years and beyond [Member] | Delaware Basin [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	14,080
Crude Oil [Member] | Supply Contract Expiration Date [Member] | Wattenberg Field
Supply Commitment
Supply Commitments Contract Expiration Date	Apr. 30, 2023
Crude Oil [Member] | Supply Contract Expiration Date [Member] | Delaware Basin [Member]
Supply Commitment
Supply Commitments Contract Expiration Date	Dec. 31, 2023
First facilities agreement with midstream provider [Member]
Supply Commitment
incremental volume commitment	51.5
Second facilities agreement with midstream provider [Member]
Supply Commitment
incremental volume commitment	33.5
Wattenberg Field
Supply Commitment
Committed Barrels of Crude Oil per day | bbl	12,500
Natural Gas [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	304,817
Natural Gas [Member] | First Year Commitment [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	40,053
Natural Gas [Member] | Second Year Commitment [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	60,530
Natural Gas [Member] | Third Year Commitment [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	49,142
Natural Gas [Member] | Fourth Year Commitment [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	37,990
Natural Gas [Member] | commitments 5 years and beyond [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	117,102
Crude Oil [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	72,857
Crude Oil [Member] | First Year Commitment [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	11,931
Crude Oil [Member] | Second Year Commitment [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	16,289
Crude Oil [Member] | Third Year Commitment [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	13,665
Crude Oil [Member] | Fourth Year Commitment [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	11,955
Crude Oil [Member] | commitments 5 years and beyond [Member]
Supply Commitment
Oil and Gas Delivery Commitments Volumes (MMcf)	19,017
Minimum [Member] | Delaware Basin [Member]
Supply Commitment
Committed Barrels of Crude Oil per day | bbl	11,400
Maximum [Member] | Delaware Basin [Member]
Supply Commitment
Committed Barrels of Crude Oil per day | bbl	26,400

Commitments and Contingencies A

Commitments and Contingencies Additional information (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)MMcf	Mar. 31, 2017USD ($)
Loss Contingencies [Line Items]
Transportation, gathering, and processing expenses	$ 7,313	$ 5,902
First facilities agreement with midstream provider [Member]
Loss Contingencies [Line Items]
incremental volume commitment | MMcf	51.5
Utica Shale natural gas and Wattenberg Field crude oil [Member]
Loss Contingencies [Line Items]
Transportation, gathering, and processing expenses	$ 2,600	$ 2,200

Commitments and Contingencies N

Commitments and Contingencies New Plant (Details)	3 Months Ended
	Mar. 31, 2018
New Plants [Member]
Property, Plant and Equipment [Line Items]
Qualitative and Quantitative Information, Transferor's Continuing Involvement, Third Party Commitments	two
Natural Gas [Member]
Property, Plant and Equipment [Line Items]
Qualitative and Quantitative Information, Transferor's Continuing Involvement, Third Party Commitments	200

Commitments and Contingencies67

Commitments and Contingencies Clean Air Act (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Obligation with Joint and Several Liability Arrangement [Line Items]
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 Sale of Common Sto

Common Stock Sale of Common Stock (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Common stock, par value	$ 0.01	$ 0.01
Common shares - par value	$ 660	$ 659
Additional paid-in capital	$ 2,504,663	$ 2,503,294
Debt Instrument, Convertible, Conversion Price	$ 85.39

Share Based Compensation Summar

Share Based Compensation Summary (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Stock-based compensation expense	$ 5,261	$ 4,453
Income tax benefit	(1,261)	(1,666)
Net stock-based compensation expense	$ 4,000	$ 2,787

Schedule of Changes in SARs (De

Schedule of Changes in SARs (Details) - Stock Appreciation Rights (SARs) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Share based compesation aggregate intrinsic value
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 1.4
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 6 months 7 days

Schedule of Changes in Restrict

Schedule of Changes in Restricted Stock - TIme Based Awards (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Number of Shares
Forfeited	(4,128)	94.02
Restricted stock
Share-based Compensation Arrangement by Share-based Payment Award
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three years. The time-based shares generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed.
Number of Shares
Outstanding beginning of year, January 1,	472,132
Granted	136,256
Vested	(66,253)
Forfeited	(5,800)
Outstanding at period end,	536,335
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 60.23
Granted	50.94	$ 73.28
Vested	58.16
Forfeited	68.18
Outstanding at period end,	$ 58.04
Total intrinsic value of time based awards vested	$ 3,530	$ 3,602
Total intrinsic value of time-based awards non-vested	$ 26,297	$ 33,366
Market price per common share as of period end,	$ 49.03	$ 62.35
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 20,600
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2 years

Restricted Stock - Market Based

Restricted Stock - Market Based Awards Fair Value Assumptions (Details) - Restricted Stock - Market Based Awards - $ / shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award
Expected term of award	3 years	3 years
Risk-free interest rate	2.40%	1.40%
Expected Volatility	42.30%	51.40%
Granted	$ 69.98	$ 94.02

Schedule of Changes in Restri73

Schedule of Changes in Restricted Stock - Market Based Awards (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award
Forfeited	(4,128)	94.02
Restricted Stock - Market Based Awards
Share-based Compensation Arrangement by Share-based Payment Award
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	The fair value of the market-based restricted shares 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
Outstanding at period end,	138,999
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 84.06
Granted	69.98	$ 94.02
Outstanding at period end,	$ 74.57
Total intrinsic value of market-based awards non-vested	$ 6,815	$ 4,769
Market price per common share as of period end,	$ 49.03	$ 62.35
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 7,900
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2 years 6 months

Common Stock Preferred Stock (D

Common Stock Preferred Stock (Details) - shares	Mar. 31, 2018	Dec. 31, 2017	Jun. 23, 2008
Share-based Compensation Arrangement by Share-based Payment Award
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
Preferred Stock, Shares Authorized			50,000,000
Preferred Stock, Shares Issued	0

Common Stock Treasury Shares (D

Common Stock Treasury Shares (Details) - shares	Mar. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award
Common stock, shares authorized	150,000,000	150,000,000

Earnings Per Share (Details)

Earnings Per Share (Details) - $ / shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Reconciliation of Weighted-Average Diluted Shares Outstanding
Weighted average common shares outstanding - basic	65,957,000	65,749,000
Pro Forma Weighted Average Shares Outstanding, Diluted	65,957,000	66,117,000
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	689,000	94,000
Convertible Senior Note
Convertible Note, Shares To Be Received Upon Conversion (in thousands)	2,300,000
Convertible Note, Conversion Price	$ 85.39
Restricted stock
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	0	211,000
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	491,000	76,000
Convertible Note [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	0	157,000
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	0
Other equity-based awards
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	198,000	18,000

Subsidiary Guarantor Condensed

Subsidiary Guarantor Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Cash and cash equivalents	$ 45,923	$ 180,675
Accounts receivable, net	181,025	197,598
Fair value of derivatives	28,610	14,338
Prepaid expenses and other current assets	8,897	8,613
Total current assets	264,455	401,224
Properties and equipment, net	4,231,257	3,933,467
Assets held-for-sale, net	1,647	40,084
Intercompany Receivables	0	0
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	0	0
Other assets	24,798	45,116
Total Assets	4,522,157	4,419,891
Accounts payable	195,703	150,067
Production tax liability	36,650	37,654
Fair value of derivatives	110,683	79,302
Funds held for distribution	97,611	95,811
Accrued interest payable	13,760	11,815
Other accrued expenses	33,777	42,987
Total current liabilities	488,184	417,636
Intercompany Payable	0	0
Long-term debt	1,154,528	1,151,932
Deferred income taxes	187,183	191,992
Asset retirement obligations	73,905	71,006
Fair value of derivatives	26,426	22,343
Other liabilities	94,557	57,333
Total liabilities	2,024,783	1,912,242
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,999,010 and 65,955,080 issued as of March 31, 2018 and December 31, 2017, respectively	660	659
Additional paid-in capital	2,504,663	2,503,294
Retained earnings (deficit)	(6,435)	6,704
Treasury Stock, Value	1,514	3,008
Total stockholders' equity	2,497,374	2,507,649
Total Liabilities and Stockholders' Equity	4,522,157	4,419,891
Corporate, Non-Segment [Member]
Cash and cash equivalents	45,923	180,675
Accounts receivable, net	143,250	160,490
Fair value of derivatives	28,610	14,338
Prepaid expenses and other current assets	7,116	8,284
Total current assets	224,899	363,787
Properties and equipment, net	2,139,471	1,891,314
Assets held-for-sale, net	1,647	40,084
Intercompany Receivables	294,476	250,279
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	1,605,330	1,617,537
Other assets	23,339	42,547
Total Assets	4,289,162	4,205,548
Accounts payable	113,529	85,000
Production tax liability	35,309	35,902
Fair value of derivatives	110,683	79,302
Funds held for distribution	80,203	83,898
Accrued interest payable	13,756	11,812
Other accrued expenses	33,136	42,543
Total current liabilities	386,616	338,457
Intercompany Payable	0	0
Long-term debt	1,154,528	1,151,932
Deferred income taxes	62,088	62,857
Asset retirement obligations	67,922	65,301
Fair value of derivatives	26,426	22,343
Other liabilities	94,208	57,009
Total liabilities	1,791,788	1,697,899
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,999,010 and 65,955,080 issued as of March 31, 2018 and December 31, 2017, respectively	660	659
Additional paid-in capital	2,504,663	2,503,294
Retained earnings (deficit)	(6,435)	6,704
Treasury Stock, Value	1,514	3,008
Total stockholders' equity	2,497,374	2,507,649
Total Liabilities and Stockholders' Equity	4,289,162	4,205,548
Reportable Legal Entities [Member]
Cash and cash equivalents	0	0
Accounts receivable, net	37,775	37,108
Fair value of derivatives	0	0
Prepaid expenses and other current assets	1,781	329
Total current assets	39,556	37,437
Properties and equipment, net	2,091,786	2,042,153
Assets held-for-sale, net	0	0
Intercompany Receivables	0	0
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	0	0
Other assets	1,459	2,569
Total Assets	2,132,801	2,082,159
Accounts payable	82,174	65,067
Production tax liability	1,341	1,752
Fair value of derivatives	0	0
Funds held for distribution	17,408	11,913
Accrued interest payable	4	3
Other accrued expenses	641	444
Total current liabilities	101,568	79,179
Intercompany Payable	294,476	250,279
Long-term debt	0	0
Deferred income taxes	125,095	129,135
Asset retirement obligations	5,983	5,705
Fair value of derivatives	0	0
Other liabilities	349	324
Total liabilities	527,471	464,622
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,999,010 and 65,955,080 issued as of March 31, 2018 and December 31, 2017, respectively	0	0
Additional paid-in capital	1,766,777	1,766,775
Retained earnings (deficit)	(161,447)	(149,238)
Treasury Stock, Value	0	0
Total stockholders' equity	1,605,330	1,617,537
Total Liabilities and Stockholders' Equity	2,132,801	2,082,159
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
Total current assets	0	0
Properties and equipment, net	0	0
Assets held-for-sale, net	0	0
Intercompany Receivables	(294,476)	(250,279)
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	(1,605,330)	(1,617,537)
Other assets	0	0
Total Assets	(1,899,806)	(1,867,816)
Accounts payable	0	0
Production tax liability	0	0
Fair value of derivatives	0	0
Funds held for distribution	0	0
Accrued interest payable	0	0
Other accrued expenses	0	0
Total current liabilities	0	0
Intercompany Payable	(294,476)	(250,279)
Long-term debt	0	0
Deferred income taxes	0	0
Asset retirement obligations	0	0
Fair value of derivatives	0	0
Other liabilities	0	0
Total liabilities	(294,476)	(250,279)
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,999,010 and 65,955,080 issued as of March 31, 2018 and December 31, 2017, respectively	0	0
Additional paid-in capital	(1,766,777)	(1,766,775)
Retained earnings (deficit)	161,447	149,238
Treasury Stock, Value	0	0
Total stockholders' equity	(1,605,330)	(1,617,537)
Total Liabilities and Stockholders' Equity	$ (1,899,806)	$ (1,867,816)

Subsidiary Guarantor Condense78

Subsidiary Guarantor Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Crude oil, natural gas, and NGLs sales	$ 305,225	$ 189,692
Commodity price risk management gain (loss), net	(47,240)	80,704
Other income	2,615	3,311
Revenues	260,600	273,707
Lease operating expenses	29,636	19,789
Production taxes	20,169	12,399
Transportation, gathering, and processing expenses	7,313	5,902
Exploration, geologic, and geophysical expense	2,646	954
Impairment of properties and equipment	33,188	2,193
General and administrative expense	35,696	26,315
Results of Operations, Depreciation, Depletion, Amortization and Accretion	126,788	109,316
Accretion of asset retirement obligations	1,288	1,768
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations	(1,432)	160
Other Cost and Expense, Operating	2,768	3,528
Costs and Expenses	260,924	182,004
Operating Income (Loss)	(324)	91,703
Interest Expense	17,529	19,467
Interest income	148	240
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	(17,705)	72,476
Income tax (expense) benefit	4,566	(26,330)
Income (Loss) from Subsidiaries, Net of Tax	0	0
Net Income (Loss) Attributable to Parent	(13,139)	46,146
Corporate, Non-Segment [Member]
Crude oil, natural gas, and NGLs sales	233,494	170,739
Commodity price risk management gain (loss), net	(47,240)	80,704
Other income	2,516	3,297
Revenues	188,770	254,740
Lease operating expenses	21,362	15,816
Production taxes	16,081	11,144
Transportation, gathering, and processing expenses	3,231	5,215
Exploration, geologic, and geophysical expense	313	271
Impairment of properties and equipment	6	604
General and administrative expense	31,559	23,529
Results of Operations, Depreciation, Depletion, Amortization and Accretion	94,376	101,738
Accretion of asset retirement obligations	1,200	1,685
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations	(1,432)	160
Other Cost and Expense, Operating	2,768	3,528
Costs and Expenses	172,328	163,370
Operating Income (Loss)	16,442	91,370
Interest Expense	18,097	19,597
Interest income	148	240
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	(1,507)	72,013
Income tax (expense) benefit	577	(26,162)
Income (Loss) from Subsidiaries, Net of Tax	(12,209)	295
Net Income (Loss) Attributable to Parent	(13,139)	46,146
Reportable Legal Entities [Member]
Crude oil, natural gas, and NGLs sales	71,731	18,953
Commodity price risk management gain (loss), net	0	0
Other income	99	14
Revenues	71,830	18,967
Lease operating expenses	8,274	3,973
Production taxes	4,088	1,255
Transportation, gathering, and processing expenses	4,082	687
Exploration, geologic, and geophysical expense	2,333	683
Impairment of properties and equipment	33,182	1,589
General and administrative expense	4,137	2,786
Results of Operations, Depreciation, Depletion, Amortization and Accretion	32,412	7,578
Accretion of asset retirement obligations	88	83
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations	0	0
Other Cost and Expense, Operating	0	0
Costs and Expenses	88,596	18,634
Operating Income (Loss)	(16,766)	333
Interest Expense	(568)	(130)
Interest income	0	0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	(16,198)	463
Income tax (expense) benefit	3,989	(168)
Income (Loss) from Subsidiaries, Net of Tax	0	0
Net Income (Loss) Attributable to Parent	(12,209)	295
Consolidation, Eliminations [Member]
Crude oil, natural gas, and NGLs sales	0	0
Commodity price risk management gain (loss), net	0	0
Other income	0	0
Revenues	0	0
Lease operating expenses	0	0
Production taxes	0	0
Transportation, gathering, and processing expenses	0	0
Exploration, geologic, and geophysical expense	0	0
Impairment of properties and equipment	0	0
General and administrative expense	0	0
Results of Operations, Depreciation, Depletion, Amortization and Accretion	0	0
Accretion of asset retirement obligations	0	0
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations	0	0
Other Cost and Expense, Operating	0	0
Costs and Expenses	0	0
Operating Income (Loss)	0	0
Interest Expense	0	0
Interest income	0	0
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	0	0
Income tax (expense) benefit	0	0
Income (Loss) from Subsidiaries, Net of Tax	12,209	(295)
Net Income (Loss) Attributable to Parent	$ 12,209	$ (295)

Subsidiary Guarantor Condense79

Subsidiary Guarantor Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net Cash Provided by (Used in) Operating Activities	$ 205,149	$ 139,500
Payments to Explore and Develop Oil and Gas Properties	(196,917)	(129,826)
Payments for Capital Improvements	(1,066)	(821)
Payments to Acquire Businesses, Net of Cash Acquired	(180,825)	6,181
Proceeds from sale of properties and equipment	20	737
Proceeds from divestiture	39,023	0
Purchases of short-term investments	0	(49,890)
Increase (Decrease) in Restricted Cash	1,249	0
intercompany Transfer Investing Activities	0	0
Net Cash Provided by (Used in) Investing Activities	(338,516)	(173,619)
Proceeds from Lines of Credit	35,000
Repayment of revolving credit facility	(35,000)	0
Treasury Stock, Value, Acquired, Cost Method	(2,255)	(2,017)
Other	(379)	(340)
Intercompany Transfers Financing Activities	0	0
Net Cash Provided by (Used in) Financing Activities	(2,634)	(2,357)
Net change in cash, cash equivalents, and restricted cash	(136,001)	(36,476)
Cash, cash equivalents, and restricted cash, beginning of period	189,925	244,100
Cash, cash equivalents, and restricted cash, end of period	53,924	207,624
Corporate, Non-Segment [Member]
Net Cash Provided by (Used in) Operating Activities	149,009	131,661
Payments to Explore and Develop Oil and Gas Properties	(97,286)	(82,489)
Payments for Capital Improvements	(701)	(890)
Payments to Acquire Businesses, Net of Cash Acquired	(180,825)	0
Proceeds from sale of properties and equipment	20	737
Proceeds from divestiture	39,023
Increase (Decrease) in Restricted Cash	1,249
intercompany Transfer Investing Activities	(43,891)	(33,795)
Net Cash Provided by (Used in) Investing Activities	(282,411)	(166,327)
Proceeds from Lines of Credit	35,000
Repayment of revolving credit facility	(35,000)
Treasury Stock, Value, Acquired, Cost Method	(2,255)	(2,017)
Other	(344)	(330)
Intercompany Transfers Financing Activities	0	0
Net Cash Provided by (Used in) Financing Activities	(2,599)	(2,347)
Net change in cash, cash equivalents, and restricted cash	(136,001)	(37,013)
Cash, cash equivalents, and restricted cash, beginning of period	189,925	240,487
Cash, cash equivalents, and restricted cash, end of period	53,924	203,474
Reportable Legal Entities [Member]
Net Cash Provided by (Used in) Operating Activities		7,839
Payments to Explore and Develop Oil and Gas Properties		(47,337)
Payments for Capital Improvements		69
Payments to Acquire Businesses, Net of Cash Acquired		6,181
Proceeds from sale of properties and equipment		0
intercompany Transfer Investing Activities		0
Net Cash Provided by (Used in) Investing Activities		(41,087)
Treasury Stock, Value, Acquired, Cost Method		0
Other		(10)
Intercompany Transfers Financing Activities		33,795
Net Cash Provided by (Used in) Financing Activities		33,785
Net change in cash, cash equivalents, and restricted cash		537
Cash, cash equivalents, and restricted cash, beginning of period		3,613
Cash, cash equivalents, and restricted cash, end of period		4,150
Consolidation, Eliminations [Member]
Net Cash Provided by (Used in) Operating Activities	0	0
Payments to Explore and Develop Oil and Gas Properties	0	0
Payments for Capital Improvements	0	0
Payments to Acquire Businesses, Net of Cash Acquired	0	0
Proceeds from sale of properties and equipment	0	0
Proceeds from divestiture	0
Purchases of short-term investments		0
Increase (Decrease) in Restricted Cash	0
intercompany Transfer Investing Activities	43,891	33,795
Net Cash Provided by (Used in) Investing Activities	43,891	33,795
Proceeds from Lines of Credit	0
Repayment of revolving credit facility	0
Treasury Stock, Value, Acquired, Cost Method	0	0
Other	0	0
Intercompany Transfers Financing Activities	(43,891)	(33,795)
Net Cash Provided by (Used in) Financing Activities	(43,891)	(33,795)
Net change in cash, cash equivalents, and restricted cash	0	0
Cash, cash equivalents, and restricted cash, beginning of period	0	0
Cash, cash equivalents, and restricted cash, end of period	0	0
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Net Cash Provided by (Used in) Operating Activities	56,140
Payments to Explore and Develop Oil and Gas Properties	(99,631)
Payments for Capital Improvements	(365)
Payments to Acquire Businesses, Net of Cash Acquired	0
Proceeds from sale of properties and equipment	0
Proceeds from divestiture	0
Purchases of short-term investments		0
Increase (Decrease) in Restricted Cash	0
intercompany Transfer Investing Activities	0
Net Cash Provided by (Used in) Investing Activities	(99,996)
Proceeds from Lines of Credit	0
Repayment of revolving credit facility	0
Treasury Stock, Value, Acquired, Cost Method	0
Other	(35)
Intercompany Transfers Financing Activities	43,891
Net Cash Provided by (Used in) Financing Activities	43,856
Net change in cash, cash equivalents, and restricted cash	0
Cash, cash equivalents, and restricted cash, beginning of period	0
Cash, cash equivalents, and restricted cash, end of period	$ 0
Parent Company [Member] | Reportable Legal Entities [Member]
Purchases of short-term investments		$ (49,890)