Callon Petroleum (CPE) 10-Q 7 Aug 19 2019 Q2 Quarterly report Financial data

Cover Page

Cover Page - shares	6 Months Ended
	Jun. 30, 2019	Jul. 31, 2019
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Document Transition Report	false
Entity File Number	001-14039
Entity Registrant Name	Callon Petroleum Co
Entity Central Index Key	0000928022
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	64-0844345
Entity Address, Address Line One	One Briarlake Plaza
Entity Address, Address Line Two	2000 W. Sam Houston Parkway S., Suite 2000
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77042
City Area Code	(281)
Local Phone Number	589-5200
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		228,304,366
Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	CPE
Security Exchange Name	NYSE
Series A Cumulative Preferred Stock
Entity Information [Line Items]
Title of 12(b) Security	10.0% Series A Cumulative Preferred Stock
Trading Symbol	CPE.A
Security Exchange Name	NYSE
Former Address
Entity Information [Line Items]
Entity Address, Address Line One	1401 Enclave Pkwy,
Entity Address, Address Line Two	Suite 600,
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77077

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 16,052	$ 16,051
Accounts receivable	93,039	131,720
Fair value of derivatives	13,164	65,114
Other current assets	15,841	9,740
Total current assets	138,096	222,625
Oil and natural gas properties, full cost accounting method:
Evaluated properties	4,665,761	4,585,020
Less accumulated depreciation, depletion, amortization and impairment	(2,399,886)	(2,270,675)
Evaluated oil and natural gas properties, net	2,265,875	2,314,345
Unevaluated properties	1,429,624	1,404,513
Total oil and natural gas properties, net	3,695,499	3,718,858
Operating lease right-of-use assets	31,904
Other property and equipment, net	23,363	21,901
Restricted investments	3,468	3,424
Deferred financing costs	5,427	6,087
Fair value of derivatives	11,679	0
Other assets, net	6,061	6,278
Total assets	3,915,497	3,979,173
Current liabilities:
Accounts payable and accrued liabilities	221,452	261,184
Operating lease liabilities	24,141
Accrued interest	22,695	24,665
Cash-settleable restricted stock unit awards	819	1,390
Asset retirement obligations	3,103	3,887
Fair value of derivatives	17,251	10,480
Other current liabilities	2,472	13,310
Total current liabilities	291,933	314,916
Senior secured revolving credit facility	105,000	200,000
Operating lease liabilities	7,680
Asset retirement obligations	9,315	10,405
Cash-settleable restricted stock unit awards	2,568	2,067
Deferred tax liability	21,106	9,564
Fair value of derivatives	3,663	7,440
Other long-term liabilities	100	100
Total liabilities	1,431,625	1,533,965
Commitments and contingencies
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized; 1,458,948 shares outstanding	15	15
Common stock, $0.01 par value, 300,000,000 shares authorized; 228,263,955 and 227,582,575 shares outstanding, respectively	2,283	2,276
Capital in excess of par value	2,483,945	2,477,278
Accumulated deficit	(2,371)	(34,361)
Total stockholders’ equity	2,483,872	2,445,208
Total liabilities and stockholders’ equity	3,915,497	3,979,173
6.125% senior unsecured notes due 2024
Current liabilities:
Senior unsecured notes	596,154	595,788
6.375% senior unsecured notes due 2026
Current liabilities:
Senior unsecured notes	$ 394,106	$ 393,685

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Jun. 30, 2019	Dec. 31, 2018
Stockholders’ equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	300,000,000	300,000,000
Common stock, shares outstanding (in shares)	228,263,955	227,582,575
6.125% senior unsecured notes due 2024
Debt instrument, interest rate, stated (as a percent)	6.125%
6.375% senior unsecured notes due 2026
Debt instrument, interest rate, stated (as a percent)	6.375%
Series A Preferred Stock
Stockholders’ equity:
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, liquidation preference (in dollars per share)	$ 50	$ 50
Preferred stock, shares authorized (in shares)	2,500,000	2,500,000
Preferred stock, shares outstanding (in shares)	1,458,948	1,458,948

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Operating revenues:
Total operating revenues	$ 167,052	$ 137,075	$ 320,099	$ 264,515
Operating expenses:
Lease operating expenses	22,776	13,141	46,843	26,179
Production taxes	11,131	7,539	21,944	16,002
Depreciation, depletion and amortization	62,921	38,733	122,688	74,151
General and administrative	10,564	8,289	22,317	17,057
Settled share-based awards	0	0	3,024	0
Accretion expense	216	206	457	424
Other operating expense	935	1,767	1,092	2,315
Total operating expenses	108,543	69,675	218,365	136,128
Income from operations	58,509	67,400	101,734	128,387
Other (income) expenses:
Interest expense, net of capitalized amounts	741	594	1,479	1,053
(Gain) loss on derivative contracts	(14,036)	16,554	53,224	21,036
Other income	(67)	(703)	(148)	(914)
Total other (income) expense	(13,362)	16,445	54,555	21,175
Income (loss) before income taxes	71,871	50,955	47,179	107,212
Income tax (benefit) expense	16,691	481	11,542	976
Net income (loss)	55,180	50,474	35,637	106,236
Preferred stock dividends	(1,823)	(1,824)	(3,647)	(3,647)
Income (loss) available to common stockholders	$ 53,357	$ 48,650	$ 31,990	$ 102,589
Income (loss) per common share:
Basic (in dollars per share)	$ 0.23	$ 0.23	$ 0.14	$ 0.50
Diluted (in dollars per share)	$ 0.23	$ 0.23	$ 0.14	$ 0.50
Weighted average common shares outstanding:
Basic (in shares)	228,051	210,698	227,917	206,309
Diluted (in shares)	228,411	211,465	228,599	207,027
Oil sales
Operating revenues:
Total operating revenues	$ 160,728	$ 122,613	$ 301,826	$ 237,898
Natural gas sales
Operating revenues:
Total operating revenues	$ 6,324	$ 14,462	$ 18,273	$ 26,617

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Cash flows from operating activities:
Net income (loss)	$ 35,637	$ 106,236
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	125,046	75,453
Accretion expense	457	424
Amortization of non-cash debt related items	1,479	1,041
Deferred income tax (benefit) expense	11,542	976
(Gain) loss on derivatives, net of settlements	51,777	4,594
Loss on sale of other property and equipment	49	22
Non-cash expense related to equity share-based awards	6,299	2,758
Change in the fair value of liability share-based awards	1,031	549
Payments to settle asset retirement obligations	(771)	(573)
Payments for cash-settled restricted stock unit awards	(1,425)	(4,990)
Changes in current assets and liabilities:
Accounts receivable	38,681	2,380
Other current assets	(6,101)	(5,550)
Current liabilities	(36,254)	17,061
Other	(2,401)	(402)
Net cash provided by operating activities	225,046	199,979
Cash flows from investing activities:
Capital expenditures	(359,430)	(298,370)
Acquisitions	(39,370)	(45,392)
Acquisition deposit	0	(27,600)
Proceeds from sale of assets	274,296	3,077
Net cash used in investing activities	(124,504)	(368,285)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	360,000	165,000
Payments on senior secured revolving credit facility	(455,000)	(190,000)
Issuance of 6.375% senior unsecured notes due 2026	0	400,000
Issuance of common stock	0	288,357
Payment of preferred stock dividends	(3,647)	(3,647)
Payment of deferred financing costs	(31)	(8,664)
Tax withholdings related to restricted stock units	(1,858)	(1,589)
Other financing activities	(5)	0
Net cash provided by (used in) financing activities	(100,541)	649,457
Net change in cash and cash equivalents	1	481,151
Balance, beginning of period	16,051	27,995
Balance, end of period	16,052	509,146
Supplemental cash flow information:
Interest paid, net of capitalized amounts	0	0
Income taxes paid	0	0
Operating cash flows from operating leases	1,293
Investing cash flows from operating leases	17,865
Non-cash investing and financing activities:
Change in accrued capital expenditures	(16,286)	16,088
Change in asset retirement costs	0	4,440
Right-of-use assets obtained in exchange for operating lease liabilities	2,462	0
Contingent consideration arrangement	$ 8,512	$ 0

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical) (Unaudited)	Jun. 30, 2019
6.375% senior unsecured notes due 2026
Debt instrument, interest rate, stated (as a percent)	6.375%

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) shares in Thousands, $ in Thousands	Total	Preferred Stock	Common Stock	Capital in Excess of Par	Retained Deficit
Balance (in shares) at Dec. 31, 2017		1,459	201,836
Balance at Dec. 31, 2017	$ 1,855,966	$ 15	$ 2,018	$ 2,181,359	$ (327,426)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	55,761				55,761
Shares issued pursuant to employee benefit plans (in shares)			7
Shares issued pursuant to employee benefit plans	88			88
Restricted stock (in shares)			105
Restricted stock	1,153		$ 1	1,152
Preferred stock dividend ($1.25 per share)	(1,824)				(1,824)
Balance (in shares) at Mar. 31, 2018		1,459	201,948
Balance at Mar. 31, 2018	1,911,144	$ 15	$ 2,019	2,182,599	(273,489)
Balance (in shares) at Dec. 31, 2017		1,459	201,836
Balance at Dec. 31, 2017	1,855,966	$ 15	$ 2,018	2,181,359	(327,426)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	106,236
Balance (in shares) at Jun. 30, 2018		1,459	227,507
Balance at Jun. 30, 2018	2,249,608	$ 15	$ 2,275	2,472,155	(224,837)
Balance (in shares) at Mar. 31, 2018		1,459	201,948
Balance at Mar. 31, 2018	1,911,144	$ 15	$ 2,019	2,182,599	(273,489)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	50,474				50,474
Shares issued pursuant to employee benefit plans (in shares)			11
Shares issued pursuant to employee benefit plans	141			141
Restricted stock (in shares)			248
Restricted stock	1,315		$ 3	1,312
Common stock issued (in shares)			25,300
Common stock issued	288,356		$ 253	288,103
Preferred stock dividend ($1.25 per share)	(1,824)				(1,824)
Balance (in shares) at Jun. 30, 2018		1,459	227,507
Balance at Jun. 30, 2018	2,249,608	$ 15	$ 2,275	2,472,155	(224,837)
Balance (in shares) at Dec. 31, 2018		1,459	227,583
Balance at Dec. 31, 2018	2,445,208	$ 15	$ 2,276	2,477,278	(34,361)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(19,543)				(19,543)
Shares issued pursuant to employee benefit plans (in shares)			24
Shares issued pursuant to employee benefit plans	154			154
Restricted stock (in shares)			277
Restricted stock	4,450		$ 3	4,447
Preferred stock dividend ($1.25 per share)	(1,824)				(1,824)
Balance (in shares) at Mar. 31, 2019		1,459	227,884
Balance at Mar. 31, 2019	2,428,445	$ 15	$ 2,279	2,481,879	(55,728)
Balance (in shares) at Dec. 31, 2018		1,459	227,583
Balance at Dec. 31, 2018	2,445,208	$ 15	$ 2,276	2,477,278	(34,361)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	35,637
Balance (in shares) at Jun. 30, 2019		1,459	228,264
Balance at Jun. 30, 2019	2,483,872	$ 15	$ 2,283	2,483,945	(2,371)
Balance (in shares) at Mar. 31, 2019		1,459	227,884
Balance at Mar. 31, 2019	2,428,445	$ 15	$ 2,279	2,481,879	(55,728)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	55,180				55,180
Restricted stock (in shares)			380
Restricted stock	2,075		$ 4	2,071
Preferred stock dividend ($1.25 per share)	(1,823)				(1,823)
Preferred stock redemption costs	(5)			(5)
Balance (in shares) at Jun. 30, 2019		1,459	228,264
Balance at Jun. 30, 2019	$ 2,483,872	$ 15	$ 2,283	$ 2,483,945	$ (2,371)

Consolidated Statements of St_2

Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical) - $ / shares	3 Months Ended
	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018
Statement of Stockholders' Equity [Abstract]
Preferred stock dividends (in dollars per share)	$ 1.25	$ 1.25	$ 1.25	$ 1.25

Description of Business and Bas

Description of Business and Basis of Presentation	6 Months Ended
	Jun. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business and Basis of Presentation	Description of Business and Basis of Presentation Description of business Callon Petroleum Company has been engaged in the development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. We were incorporated in the state of Delaware in 1994. Callon is focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. Since our entry into the Permian Basin in late 2009, we have been focused on the Midland Basin and entered the Delaware Basin through an acquisition completed in February 2017. The Company further expanded its presence in the Delaware Basin through acquisitions in 2018. Basis of presentation Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data. The interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of Callon Petroleum Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has a subsidiary, namely Mississippi Marketing, Inc. Effective February 28, 2019, Callon Offshore Production, Inc. was merged with and into Callon Petroleum Operating Company. These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 . The balance sheet at December 31, 2018 has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2019 . In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, results of operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. Accounting Standards Updates (“ASUs”) Recently adopted ASUs - Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements (“ASU 2019-01”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”). ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component. The new standard was effective for us in the first quarter of 2019, and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized the cumulative effect of adoption in retained earnings as of January 1, 2019. We further utilized the package of practical expedients at transition to not reassess the following: • Whether any expired or existing contracts were or contained leases; • The lease classification for any expired or existing leases; and • Initial direct costs for any existing leases. Additionally, we elected the practical expedient under ASU 2018-01, which did not require us to evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. We also chose not to separate lease and non-lease components for the various classes of underlying assets. In addition, for all of our asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases. Accordingly, we recognize lease payments related to our short-term leases in profit or loss on a straight-line basis over the lease term. Through our implementation process, we evaluated each of our lease arrangements and enhanced our systems to track and calculate additional information required upon adoption of this standard. The standard had an impact on our consolidated balance sheets at March 31, 2019 and June 30, 2019, resulting from the recognition of right-of-use assets and lease liabilities for operating leases. We have no leases that meet the criteria for classification as a finance lease. We lease certain office space, office equipment, production facilities, compressors, drilling rigs, vehicles and other ancillary drilling equipment under cancelable and non-cancelable leases to support our operations. See Note 10 for additional information regarding the impact of adoption of the new leases standard on our current period results. Adoption of the new leases standard did not impact our consolidated statement of operations or cash provided from or used in operating, investing or financing in our consolidated statement of cash flows. We note that the standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. Recently adopted ASUs - Other In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the timing and measurement of nonemployee awards. The Company adopted this update on January 1, 2019 and it did not have a material impact on its consolidated financial statements upon adoption of this guidance.

Revenue Recognition

Revenue Recognition	6 Months Ended
	Jun. 30, 2019
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Revenue Recognition Revenue from contracts with customers Oil sales Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. Natural gas sales Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. The Company’s share of revenue received from the sale of NGLs is included in the natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. Gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company has modified the presentation of revenues and expenses to include these fees net of operating revenues. For the three and six months ended June 30, 2019 , $2,805 and $5,213 of gathering and treating fees were recognized and recorded as a reduction to natural gas sales in the consolidated statement of operations, respectively. For the three and six months ended June 30, 2018 , $1,952 and $3,204 of gathering and treating fees were recognized and recorded as a reduction to natural gas sales in the consolidated statement of operations, respectively. Accounts receivable from revenues from contracts with customers Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at June 30, 2019 and December 31, 2018 of $67,891 and $87,061 , respectively, and does not currently include an allowance for doubtful accounts. Accounts receivable, net, from the sale of oil and natural gas are included in accounts receivable on the consolidated balance sheets. Transaction price allocated to remaining performance obligations For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Prior period performance obligations The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.

Acquisitions and Dispositions

Acquisitions and Dispositions	6 Months Ended
	Jun. 30, 2019
Business Combinations [Abstract]
Acquisitions and Dispositions	Acquisitions and Dispositions 2019 Acquisitions and Dispositions On June 12, 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Asset Divestiture”) for net cash proceeds received at closing of $244,935 , including customary purchase price adjustments. The transaction also provides for potential contingent consideration in payments of up to $60,000 based on West Texas Intermediate average annual pricing over a three-year period (see Notes 6 and 7 for additional information regarding the contingent consideration payments). The divestiture encompasses the Ranger operating area in the southern Midland Basin which includes approximately 9,850 net Wolfcamp acres with an average 66% working interest. The divestiture did not significantly alter the relationship between capitalized costs and proved reserves, and as such, net cash proceeds and contingent consideration were recorded as adjustments to our full cost pool with no gain or loss recognized. In the first quarter of 2019, the Company completed various acquisitions and dispositions of additional working interests and acreage located in our existing core operating areas within the Permian Basin. The Company purchased mineral rights for $21,407 in the Spur operating area and received proceeds of $14,084 , including customary purchase price adjustments, for certain leasehold interests in our WildHorse acreage. In the second quarter of 2019, the Company completed various acreage swaps in the Permian Basin and received proceeds of $19,108 , including customary purchase price adjustments, for certain working interests in our Spur acreage. 2018 Acquisitions On August 31, 2018 , the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for $539,519 , including customary purchase price adjustments (the “Delaware Asset Acquisition”). The Company issued debt and equity to fund, in part, the Delaware Asset Acquisition. See Notes 5 and 9 for additional information regarding the Company’s debt obligations and equity offerings. The following table summarizes the estimated acquisition date fair values of the acquisition: Evaluated oil and natural gas properties $ 253,089 Unevaluated oil and natural gas properties 287,000 Asset retirement obligations (570 ) Net assets acquired $ 539,519 In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian Basin. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for $37,770 , including customary purchase price adjustments. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for $87,865 , including customary purchase price adjustments.

Earnings Per Share

Earnings Per Share	6 Months Ended
	Jun. 30, 2019
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share: (amounts in thousands) Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 Net income (loss) $ 55,180 $ 50,474 $ 35,637 $ 106,236 Preferred stock dividends (1,823 ) (1,824 ) (3,647 ) (3,647 ) Income (loss) available to common stockholders $ 53,357 $ 48,650 $ 31,990 $ 102,589 Weighted average common shares outstanding 228,051 210,698 227,917 206,309 Dilutive impact of restricted stock 360 767 682 718 Weighted average common shares outstanding for diluted income (loss) per share 228,411 211,465 228,599 207,027 Basic income (loss) per share $ 0.23 $ 0.23 $ 0.14 $ 0.50 Diluted income (loss) per share $ 0.23 $ 0.23 $ 0.14 $ 0.50 Restricted stock (a) 641 — 498 — (a)

Borrowings

Borrowings	6 Months Ended
	Jun. 30, 2019
Debt Disclosure [Abstract]
Borrowings	Borrowings The Company’s borrowings consisted of the following: As of Principal components: June 30, 2019 December 31, 2018 Senior secured revolving credit facility $ 105,000 $ 200,000 6.125% senior unsecured notes due 2024 600,000 600,000 6.375% senior unsecured notes due 2026 400,000 400,000 Total principal outstanding 1,105,000 1,200,000 Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization 5,906 6,469 Unamortized deferred financing costs (15,646 ) (16,996 ) Total carrying value of borrowings (a) $ 1,095,260 $ 1,189,473 (a) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $5,427 and $6,087 as of June 30, 2019 and December 31, 2018 , respectively. Senior secured revolving credit facility (the “Credit Facility”) On May 25, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility. JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include 17 institutional lenders. The total notional amount available under the Credit Facility is $2,000,000 . Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. The maturity date of the Credit Facility is May 25, 2023 . Effective May 1, 2019, the Company entered into the third amendment (the “Third Amendment”) to the Sixth Amended and Restated Credit Agreement to the Credit Facility to, among other things: (i) reaffirm the borrowing base at $1,100,000 , excluding the Ranger assets sold; and (ii) amend various covenants and terms to reflect current market trends. As of June 30, 2019 , the Credit Facility’s borrowing base remained at $1,100,000 with an elected commitment amount of $850,000 . As of June 30, 2019 , there was $105,000 principal and $17,675 in letters of credit outstanding under the Credit Facility. For the period ended June 30, 2019 , the Credit Facility had a weighted-average interest rate of 3.65% , calculated as the LIBOR plus a tiered rate ranging from 1.25% to 2.25% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a current commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base. Restrictive covenants The Company’s Credit Facility and the indentures governing its senior notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at June 30, 2019 .

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	6 Months Ended
	Jun. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities Objectives and strategies for using commodity derivative instruments The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps and put and call options to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. Counterparty risk and offsetting The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 7 for additional information regarding fair value. The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. Financial statement presentation and settlements Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See Note 7 for additional information regarding fair value. Contingent consideration arrangement Our Ranger Asset Divestiture in June of 2019 provides for potential contingent consideration to be received by the Company if commodity prices exceed specific thresholds in each of the next several years. On the disposition date, we recognized a derivative asset of $8,512 based on the initial fair value measurement. See Note 7 for additional information regarding fair value measurement. These contingent payments are summarized in the tables below (in thousands): Year of Potential Settlement Threshold (a) Contingent Payment Amount Threshold (a) Contingent Payment Amount Fair Value as of June 30, 2019 (b) Aggregate Settlements Limit (c) $ 60,000 2019 Greater than $60/bbl, less than $65/bbl $9,000 Equal to or greater than $65/bbl $20,833 $2,485 2020 Greater than $60/bbl, less than $65/bbl $9,000 Equal to or greater than $65/bbl $20,833 $5,085 2021 Greater than $60/bbl, less than $65/bbl $9,000 Equal to or greater than $65/bbl $20,833 (c) $4,255 (a) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc. (b) Contingent consideration to be received will be classified as cash flows from financing activities up to the initial recognition fair value of $8,512 ; amounts in excess of the initial recognition fair value will be classified as cash flows from operating activities. (c) In the event that the 2019 and 2020 prices exceed the $65 /bbl threshold, the aggregate amount of contingent consideration is limited to $60,000 , resulting in the potential reduction in settlement for 2021 to $18,334 . Derivatives not designated as hedging instruments The Company records its derivative contracts at fair value in the consolidated balance sheets and records changes in fair value as a gain or loss on derivative contracts in the consolidated statements of operations. Settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations. The following table reflects the fair value of the Company’s derivative instruments for the periods presented: As of June 30, 2019 Derivative Instrument Balance Sheet Presentation Asset Liability Net Asset (Liability) Commodity - Oil Fair value of derivatives - Current $ 8,671 $ (17,251 ) $ (8,580 ) Commodity - Natural gas Fair value of derivatives - Current 2,008 — 2,008 Contingent consideration arrangement Fair value of derivatives - Current 2,485 — 2,485 Commodity - Oil Fair value of derivatives - Non-current 2,335 (3,327 ) (992 ) Commodity - Natural gas Fair value of derivatives - Non-current 4 (336 ) (332 ) Contingent consideration arrangement Fair value of derivatives - Non-current 9,340 — 9,340 Totals $ 24,843 $ (20,914 ) $ 3,929 As of December 31, 2018 Derivative Instrument Balance Sheet Presentation Asset Liability Net Asset (Liability) Commodity - Oil Fair value of derivatives - Current $ 60,097 $ (10,480 ) $ 49,617 Commodity - Natural gas Fair value of derivatives - Current 5,017 — 5,017 Commodity - Oil Fair value of derivatives - Non-current — (5,672 ) (5,672 ) Commodity - Natural gas Fair value of derivatives - Non-current — (1,768 ) (1,768 ) Totals $ 65,114 $ (17,920 ) $ 47,194 As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of commodity derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: As of June 30, 2019 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of commodity derivatives $ 20,044 $ (9,365 ) $ 10,679 Long-term assets: Fair value of commodity derivatives 4,420 (2,081 ) 2,339 Current liabilities: Fair value of commodity derivatives $ (26,616 ) $ 9,365 $ (17,251 ) Long-term liabilities: Fair value of commodity derivatives (5,744 ) 2,081 (3,663 ) As of December 31, 2018 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of commodity derivatives $ 78,091 $ (12,977 ) $ 65,114 Current liabilities: Fair value of commodity derivatives $ (23,457 ) $ 12,977 $ (10,480 ) Long-term liabilities: Fair value of commodity derivatives (7,440 ) — (7,440 ) For the periods indicated, the Company recorded the following in the consolidated statements of operations as a gain or loss on derivative contracts: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 Oil derivatives Net gain (loss) on settlements $ (4,461 ) $ (8,131 ) $ (6,003 ) $ (17,049 ) Net gain (loss) on fair value adjustments 13,310 (8,311 ) (53,517 ) (4,243 ) Total gain (loss) on oil derivatives 8,849 (16,442 ) (59,520 ) (21,292 ) Natural gas derivatives Net gain (loss) on settlements 3,304 151 4,556 607 Net gain (loss) on fair value adjustments (1,430 ) (263 ) (1,573 ) (351 ) Total gain (loss) on natural gas derivatives 1,874 (112 ) 2,983 256 Contingent consideration arrangement Net gain (loss) on fair value adjustments 3,313 — 3,313 — Total gain (loss) on derivatives $ 14,036 $ (16,554 ) $ (53,224 ) $ (21,036 ) Derivative positions Listed in the tables below are the outstanding oil and natural gas derivative contracts as of June 30, 2019 : For the Remainder For the Full Year For the Full Year Oil contracts (WTI) of 2019 of 2020 of 2021 Puts Total volume (Bbls) 460,000 — — Weighted average price per Bbl $ 65.00 $ — $ — Put spreads Total volume (Bbls) 460,000 — — Weighted average price per Bbl Floor (long put) $ 65.00 $ — $ — Floor (short put) $ 42.50 $ — $ — Collar contracts with short puts (three-way collars) Total volume (Bbls) 2,392,000 3,294,000 — Weighted average price per Bbl Ceiling (short call) $ 67.46 $ 65.72 $ — Floor (long put) $ 56.54 $ 55.69 $ — Floor (short put) $ 43.65 $ 44.47 $ — Oil contracts (Midland basis differential) Swap contracts Total volume (Bbls) 4,137,500 4,576,000 1,095,000 Weighted average price per Bbl $ (2.64 ) $ (1.29 ) $ 1.00 Oil contracts (Argus Houston MEH basis differential) Swap contracts Total volume (Bbls) — 552,000 — Weighted average price per Bbl $ — $ 3.30 $ — Natural gas contracts (Henry Hub) Collar contracts (two-way collars) Total volume (MMBtu) 1,196,000 — — Weighted average price per MMBtu Ceiling (short call) $ 3.50 $ — $ — Floor (long put) $ 3.13 $ — $ — Swap contracts Total volume (MMBtu) 1,397,000 — — Weighted average price per MMBtu $ 2.89 $ — $ — Natural gas contracts (Waha basis differential) Swap contracts Total volume (MMBtu) 4,232,000 4,758,000 — Weighted average price per MMBtu $ (1.18 ) $ (1.12 ) $ —

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority. Fair value of financial instruments Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximated fair value due to the short-term nature or maturity of the instruments. Debt. The carrying amount of the Company’s floating-rate debt approximated fair value, because the interest rates were variable and reflective of market rates. June 30, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value Credit Facility (a) $ 105,000 $ 105,000 $ 200,000 $ 200,000 6.125% Senior Notes (b) 596,154 609,048 595,788 558,000 6.375% Senior Notes (b) 394,106 403,988 393,685 372,000 Total $ 1,095,260 $ 1,118,036 $ 1,189,473 $ 1,130,000 (a) Floating-rate debt. (b) The fair value was based upon Level 2 inputs. See Note 5 for additional information about the Company’s 6.125% and 6.375% Senior Notes. Assets and liabilities measured at fair value on a recurring basis Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value: Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 6 for additional information regarding the Company’s derivative instruments. Contingent consideration arrangement - embedded derivative financial instrument. The embedded option within the contingent consideration arrangement is considered a financial instrument under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded option on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates an undiscounted payout, and risk adjusts for the discount rates inclusive of adjustments for the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangement, the inputs are considered Level 2 inputs within the fair value hierarchy. See Note 6 for additional information regarding the Company’s contingent consideration arrangement. The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis: June 30, 2019 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 24,843 $ — $ 24,843 Liabilities Derivative financial instruments Fair value of derivatives — (20,914 ) — (20,914 ) Total net assets (liabilities) $ — $ 3,929 $ — $ 3,929 December 31, 2018 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 65,114 $ — $ 65,114 Liabilities Derivative financial instruments Fair value of derivatives — (17,920 ) — (17,920 ) Total net assets $ — $ 47,194 $ — $ 47,194 Assets and liabilities measured at fair value on a nonrecurring basis Acquisitions. The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 1, Level 2 and Level 3 inputs.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations: Three Months Ended June 30, Six Months Ended June 30, Components of income tax rate reconciliation 2019 2018 2019 2018 Income tax expense computed at the statutory federal income tax rate 21 % 21 % 21 % 21 % State taxes net of federal expense 1 % 1 % 1 % 1 % Section 162(m) — % 1 % — % — % Valuation allowance — % (21 )% — % (21 )% Effective income tax rate, before discrete items 22 % 2 % 22 % 1 % Discrete items (a) 1 % (1 )% 2 % — % Effective income tax rate, after discrete items 23 % 1 % 24 % 1 % (a) Accounts for the potential impact of periodic volatility of stock-based compensation tax deductions on future effective tax rates.

Equity Transactions

Equity Transactions	6 Months Ended
	Jun. 30, 2019
Equity [Abstract]
Equity Transactions	Equity Transactions 10% Series A Cumulative Preferred Stock (“Preferred Stock”) Holders of the Company’s 10.00% Series A Cumulative Preferred Stock were entitled to receive, when, as and if declared by the Company’s Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by the Company’s Board of Directors. Preferred Stock dividends of $1,823 and $3,647 for the three and six months ended June 30, 2019 remained consistent compared to the same periods of 2018 , respectively. On June 18, 2019, the Company announced it had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. The redemption date of the Preferred Stock was July 18, 2019 (the “Redemption Date”). The Preferred Stock were redeemed at the redemption price equal to $50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share (the “Redemption Price”). After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest. Regular dividends on the Preferred Stock for the second quarter of 2019 were paid prior to the end of the period. Common stock On May 30, 2018 , the Company completed an underwritten public offering of 25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering costs) of approximately $287,988 . The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter of 2018, described in Note 3 .

Leases

Leases	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Leases	Leases Leases We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. Based on our evaluation of leases for the three months ended March 31, 2019, we have no leases that meet the criteria for classification as a finance lease. We capitalize operating leases on our consolidated balance sheets through a right-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments arising from the lease. Operating leases are included in operating lease ROU assets, current operating lease liabilities, and long-term operating lease liabilities in our consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Nature of leases In support of our operations, we lease certain drilling rigs, office space, office equipment, production facilities, compressors, vehicles and other ancillary drilling equipment under cancelable and non-cancelable contracts. A more detailed description of our material lease types is included below. Drilling rigs The Company enters into daywork and long-term contracts for drilling rigs with third party service contractors to support the development of undeveloped reserves. Our daywork drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells, well pads or contractually stated extension terms by providing 30 days ’ notice prior to the end of the original contract term. The Company’s long-term drilling contracts are generally structured with an initial non-cancelable term of one to two years . We have concluded that our long-term drilling rig arrangements represent operating leases with a lease term greater than twelve months. Additionally, we have concluded that our daywork drilling rig arrangements represent short-term operating leases with a lease term that equals the period of time required to complete drilling operations on the contractually specified well or well pad (that is, generally one to a few months from commencement of drilling). We do not include the option to extend the drilling rig contract in the lease term due to the continuously evolving nature of our drilling schedules, which requires significant flexibility in the structure of the term of these arrangements, and the potential volatility in commodity prices in an annual period. We have further elected to apply the practical expedient for short-term leases to our daywork drilling rig leases. Accordingly, we do not apply the lease recognition requirements to our daywork drilling rig contracts, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term. Corporate and field offices We enter into long-term contracts to lease corporate and field office space in support of company operations. These contracts are generally structured with an initial non-cancelable term of two to five years . To the extent that our corporate and field office contracts include renewal options, we evaluate whether we are reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. We have further determined that our current corporate and field office leases represent operating leases. Transportation, gathering and processing arrangements We engage in various types of transactions in which midstream entities transport, gather and/or process our product leveraging integrated systems and facilities wholly-owned and operated by the midstream counterparty. Under most of these arrangements, we do not utilize substantially all of the underlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an identified asset. The following tables reflect the current period impact of our adoption of the new leases standard. As we have no leases that meet the criteria for classification as a finance lease, all information contained herein represents our operating leases. The components of our total lease cost were as follows: Three Months Ended Six Months Ended June 30, 2019 June 30, 2019 Operating lease cost $ 9,591 $ 19,156 Short-term lease cost (a) 1,849 3,347 (a) Short-term lease cost excludes expenses related to leases with a contract term of one month or less. As of June 30, 2019 , our weighted average remaining lease term and our weighted average discount rate for our operating leases were 1.45 years and 4.02% , respectively. Our operating lease liabilities with enforceable contract terms that are greater than one year mature as follows: As of June 30, 2019 Remainder of 2019 $ 15,937 2020 13,847 2021 1,576 2022 534 2023 517 Thereafter 431 Total lease payments 32,842 Less imputed interest 1,022 Total $ 31,820

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2019
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The table below summarizes the activity for the Company’s ARO: Six Months Ended June 30, 2019 Asset retirement obligations at January 1, 2019 $ 14,292 Accretion expense 457 Liabilities incurred 199 Liabilities settled (630 ) Dispositions (1,701 ) Revisions to estimate (199 ) Asset retirement obligations at end of period 12,418 Less: Current asset retirement obligations (3,103 ) Long-term asset retirement obligations at June 30, 2019 $ 9,315 • Liabilities incurred include additions from acquisitions, asset swaps, and new wells drilled during the year. • Liabilities settled include the retirement of 20 wells during the year. • Dispositions are primarily attributable to the Ranger Asset Divestiture in the second quarter of 2019. See Note 3 for details about the Ranger Asset Divestiture. • Revisions to estimates were due to changes in plugging cost estimates, timing of abandonment activities, and changes in working interest of producing wells. Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at June 30, 2019 as long-term restricted investments were $3,468 . These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.

Other

Other	6 Months Ended
	Jun. 30, 2019
Other [Abstract]
Other	Other Other commitments In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward counties to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. In January 2019, the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward counties and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. We will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. In June 2019, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originates in Midland, Texas and terminates in Houston, Texas. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our quantities committed that average 10,000 Bbls per day for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. In July 2019, the Company executed a crude oil sales contact that provides dedicated capacity on a new pipeline system that originates in Midland County and will have delivery points in several locations along the Gulf Coast. We will have a long-term 5,000 Bbls per day commitment for the term of the agreement and will apply applicable tariff rates to those quantities. Barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

Carrizo Acquisition

Carrizo Acquisition	6 Months Ended
	Jun. 30, 2019
Subsequent Events [Abstract]
Carrizo Acquisition	Carrizo Acquisition On July 14, 2019, Callon and Carrizo Oil & Gas, Inc. (“Carrizo”) entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which, upon the terms and subject to the conditions set forth therein, Carrizo will merge with and into Callon, with Callon as the surviving corporation (the “Merger” or the “Carrizo Acquisition”). The combination will result in a portfolio of core oil-weighted assets in both the Permian Basin and Eagle Ford Shale. Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each outstanding share of Carrizo Common Stock, will be converted into the right to receive 2.05 shares of Callon Common Stock. Following the closing of the Merger, Callon’s existing shareholders and Carrizo’s existing shareholders will own approximately 54% and 46% , respectively, of the outstanding shares of the combined company. The Merger Agreement provides that, upon consummation of the Merger, the board of directors of Callon will consist of the eight members of the board of directors of Callon immediately prior to the Effective Time and three members of the board of directors of Carrizo, two of such directors to be chosen by Carrizo and one such director to be chosen by Callon. Additionally, the Merger Agreement provides that, upon consummation of the Merger, the officers of Callon immediately prior to the Effective Time shall be the officers of the combined company. Callon will continue to be headquartered in Houston, Texas, where both companies are currently based. Callon expects that the acquisition will close during the fourth quarter of 2019, subject to the approval of both shareholder bases, the satisfaction of certain regulatory approvals and other closing conditions.

Description of Business and B_2

Description of Business and Basis of Presentation (Policies)	6 Months Ended
	Jun. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of presentation	Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data. The interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of Callon Petroleum Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has a subsidiary, namely Mississippi Marketing, Inc. Effective February 28, 2019, Callon Offshore Production, Inc. was merged with and into Callon Petroleum Operating Company. These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 . The balance sheet at December 31, 2018 has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2019 . In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, results of operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.
Accounting Standards Updates (“ASUs”)	Recently adopted ASUs - Leases In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements (“ASU 2019-01”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”). ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component. The new standard was effective for us in the first quarter of 2019, and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized the cumulative effect of adoption in retained earnings as of January 1, 2019. We further utilized the package of practical expedients at transition to not reassess the following: • Whether any expired or existing contracts were or contained leases; • The lease classification for any expired or existing leases; and • Initial direct costs for any existing leases. Additionally, we elected the practical expedient under ASU 2018-01, which did not require us to evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. We also chose not to separate lease and non-lease components for the various classes of underlying assets. In addition, for all of our asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases. Accordingly, we recognize lease payments related to our short-term leases in profit or loss on a straight-line basis over the lease term. Through our implementation process, we evaluated each of our lease arrangements and enhanced our systems to track and calculate additional information required upon adoption of this standard. The standard had an impact on our consolidated balance sheets at March 31, 2019 and June 30, 2019, resulting from the recognition of right-of-use assets and lease liabilities for operating leases. We have no leases that meet the criteria for classification as a finance lease. We lease certain office space, office equipment, production facilities, compressors, drilling rigs, vehicles and other ancillary drilling equipment under cancelable and non-cancelable leases to support our operations. See Note 10 for additional information regarding the impact of adoption of the new leases standard on our current period results. Adoption of the new leases standard did not impact our consolidated statement of operations or cash provided from or used in operating, investing or financing in our consolidated statement of cash flows. We note that the standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. Recently adopted ASUs - Other In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the timing and measurement of nonemployee awards. The Company adopted this update on January 1, 2019 and it did not have a material impact on its consolidated financial statements upon adoption of this guidance.

Acquisitions and Dispositions (

Acquisitions and Dispositions (Tables)	6 Months Ended
	Jun. 30, 2019
Business Combinations [Abstract]
Fair Value of Net Assets Acquired	The following table summarizes the estimated acquisition date fair values of the acquisition: Evaluated oil and natural gas properties $ 253,089 Unevaluated oil and natural gas properties 287,000 Asset retirement obligations (570 ) Net assets acquired $ 539,519

Earnings Per Share (Tables)

Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2019
Earnings Per Share [Abstract]
Computation of Basic and Diluted Earnings Per Share	The following table sets forth the computation of basic and diluted earnings per share: (amounts in thousands) Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 Net income (loss) $ 55,180 $ 50,474 $ 35,637 $ 106,236 Preferred stock dividends (1,823 ) (1,824 ) (3,647 ) (3,647 ) Income (loss) available to common stockholders $ 53,357 $ 48,650 $ 31,990 $ 102,589 Weighted average common shares outstanding 228,051 210,698 227,917 206,309 Dilutive impact of restricted stock 360 767 682 718 Weighted average common shares outstanding for diluted income (loss) per share 228,411 211,465 228,599 207,027 Basic income (loss) per share $ 0.23 $ 0.23 $ 0.14 $ 0.50 Diluted income (loss) per share $ 0.23 $ 0.23 $ 0.14 $ 0.50 Restricted stock (a) 641 — 498 — (a)

Borrowings (Tables)

Borrowings (Tables)	6 Months Ended
	Jun. 30, 2019
Debt Disclosure [Abstract]
Schedule of Borrowings	The Company’s borrowings consisted of the following: As of Principal components: June 30, 2019 December 31, 2018 Senior secured revolving credit facility $ 105,000 $ 200,000 6.125% senior unsecured notes due 2024 600,000 600,000 6.375% senior unsecured notes due 2026 400,000 400,000 Total principal outstanding 1,105,000 1,200,000 Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization 5,906 6,469 Unamortized deferred financing costs (15,646 ) (16,996 ) Total carrying value of borrowings (a) $ 1,095,260 $ 1,189,473 (a) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $5,427 and $6,087 as of June 30, 2019 and December 31, 2018 , respectively.

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	6 Months Ended
	Jun. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Price Risk Derivatives	Our Ranger Asset Divestiture in June of 2019 provides for potential contingent consideration to be received by the Company if commodity prices exceed specific thresholds in each of the next several years. On the disposition date, we recognized a derivative asset of $8,512 based on the initial fair value measurement. See Note 7 for additional information regarding fair value measurement. These contingent payments are summarized in the tables below (in thousands): Year of Potential Settlement Threshold (a) Contingent Payment Amount Threshold (a) Contingent Payment Amount Fair Value as of June 30, 2019 (b) Aggregate Settlements Limit (c) $ 60,000 2019 Greater than $60/bbl, less than $65/bbl $9,000 Equal to or greater than $65/bbl $20,833 $2,485 2020 Greater than $60/bbl, less than $65/bbl $9,000 Equal to or greater than $65/bbl $20,833 $5,085 2021 Greater than $60/bbl, less than $65/bbl $9,000 Equal to or greater than $65/bbl $20,833 (c) $4,255 (a) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc. (b) Contingent consideration to be received will be classified as cash flows from financing activities up to the initial recognition fair value of $8,512 ; amounts in excess of the initial recognition fair value will be classified as cash flows from operating activities. (c) In the event that the 2019 and 2020 prices exceed the $65 /bbl threshold, the aggregate amount of contingent consideration is limited to $60,000 , resulting in the potential reduction in settlement for 2021 to $18,334 .
Fair Value of Derivative Instruments	The following table reflects the fair value of the Company’s derivative instruments for the periods presented: As of June 30, 2019 Derivative Instrument Balance Sheet Presentation Asset Liability Net Asset (Liability) Commodity - Oil Fair value of derivatives - Current $ 8,671 $ (17,251 ) $ (8,580 ) Commodity - Natural gas Fair value of derivatives - Current 2,008 — 2,008 Contingent consideration arrangement Fair value of derivatives - Current 2,485 — 2,485 Commodity - Oil Fair value of derivatives - Non-current 2,335 (3,327 ) (992 ) Commodity - Natural gas Fair value of derivatives - Non-current 4 (336 ) (332 ) Contingent consideration arrangement Fair value of derivatives - Non-current 9,340 — 9,340 Totals $ 24,843 $ (20,914 ) $ 3,929 As of December 31, 2018 Derivative Instrument Balance Sheet Presentation Asset Liability Net Asset (Liability) Commodity - Oil Fair value of derivatives - Current $ 60,097 $ (10,480 ) $ 49,617 Commodity - Natural gas Fair value of derivatives - Current 5,017 — 5,017 Commodity - Oil Fair value of derivatives - Non-current — (5,672 ) (5,672 ) Commodity - Natural gas Fair value of derivatives - Non-current — (1,768 ) (1,768 ) Totals $ 65,114 $ (17,920 ) $ 47,194
Schedule of Offsetting Assets	The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: As of June 30, 2019 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of commodity derivatives $ 20,044 $ (9,365 ) $ 10,679 Long-term assets: Fair value of commodity derivatives 4,420 (2,081 ) 2,339 Current liabilities: Fair value of commodity derivatives $ (26,616 ) $ 9,365 $ (17,251 ) Long-term liabilities: Fair value of commodity derivatives (5,744 ) 2,081 (3,663 ) As of December 31, 2018 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of commodity derivatives $ 78,091 $ (12,977 ) $ 65,114 Current liabilities: Fair value of commodity derivatives $ (23,457 ) $ 12,977 $ (10,480 ) Long-term liabilities: Fair value of commodity derivatives (7,440 ) — (7,440 )
Schedule of Offsetting Liabilities	The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: As of June 30, 2019 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of commodity derivatives $ 20,044 $ (9,365 ) $ 10,679 Long-term assets: Fair value of commodity derivatives 4,420 (2,081 ) 2,339 Current liabilities: Fair value of commodity derivatives $ (26,616 ) $ 9,365 $ (17,251 ) Long-term liabilities: Fair value of commodity derivatives (5,744 ) 2,081 (3,663 ) As of December 31, 2018 Presented without As Presented with Effects of Netting Effects of Netting Effects of Netting Current assets: Fair value of commodity derivatives $ 78,091 $ (12,977 ) $ 65,114 Current liabilities: Fair value of commodity derivatives $ (23,457 ) $ 12,977 $ (10,480 ) Long-term liabilities: Fair value of commodity derivatives (7,440 ) — (7,440 )
Schedule of Gain or Loss on Derivative Contracts	For the periods indicated, the Company recorded the following in the consolidated statements of operations as a gain or loss on derivative contracts: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 Oil derivatives Net gain (loss) on settlements $ (4,461 ) $ (8,131 ) $ (6,003 ) $ (17,049 ) Net gain (loss) on fair value adjustments 13,310 (8,311 ) (53,517 ) (4,243 ) Total gain (loss) on oil derivatives 8,849 (16,442 ) (59,520 ) (21,292 ) Natural gas derivatives Net gain (loss) on settlements 3,304 151 4,556 607 Net gain (loss) on fair value adjustments (1,430 ) (263 ) (1,573 ) (351 ) Total gain (loss) on natural gas derivatives 1,874 (112 ) 2,983 256 Contingent consideration arrangement Net gain (loss) on fair value adjustments 3,313 — 3,313 — Total gain (loss) on derivatives $ 14,036 $ (16,554 ) $ (53,224 ) $ (21,036 )
Schedule of Outstanding Oil and Natural Gas Derivative Contracts	Listed in the tables below are the outstanding oil and natural gas derivative contracts as of June 30, 2019 : For the Remainder For the Full Year For the Full Year Oil contracts (WTI) of 2019 of 2020 of 2021 Puts Total volume (Bbls) 460,000 — — Weighted average price per Bbl $ 65.00 $ — $ — Put spreads Total volume (Bbls) 460,000 — — Weighted average price per Bbl Floor (long put) $ 65.00 $ — $ — Floor (short put) $ 42.50 $ — $ — Collar contracts with short puts (three-way collars) Total volume (Bbls) 2,392,000 3,294,000 — Weighted average price per Bbl Ceiling (short call) $ 67.46 $ 65.72 $ — Floor (long put) $ 56.54 $ 55.69 $ — Floor (short put) $ 43.65 $ 44.47 $ — Oil contracts (Midland basis differential) Swap contracts Total volume (Bbls) 4,137,500 4,576,000 1,095,000 Weighted average price per Bbl $ (2.64 ) $ (1.29 ) $ 1.00 Oil contracts (Argus Houston MEH basis differential) Swap contracts Total volume (Bbls) — 552,000 — Weighted average price per Bbl $ — $ 3.30 $ — Natural gas contracts (Henry Hub) Collar contracts (two-way collars) Total volume (MMBtu) 1,196,000 — — Weighted average price per MMBtu Ceiling (short call) $ 3.50 $ — $ — Floor (long put) $ 3.13 $ — $ — Swap contracts Total volume (MMBtu) 1,397,000 — — Weighted average price per MMBtu $ 2.89 $ — $ — Natural gas contracts (Waha basis differential) Swap contracts Total volume (MMBtu) 4,232,000 4,758,000 — Weighted average price per MMBtu $ (1.18 ) $ (1.12 ) $ —

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2019
Fair Value Disclosures [Abstract]
Summary of Financial Instruments at Carrying and Fair Value	The carrying amount of the Company’s floating-rate debt approximated fair value, because the interest rates were variable and reflective of market rates. June 30, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value Credit Facility (a) $ 105,000 $ 105,000 $ 200,000 $ 200,000 6.125% Senior Notes (b) 596,154 609,048 595,788 558,000 6.375% Senior Notes (b) 394,106 403,988 393,685 372,000 Total $ 1,095,260 $ 1,118,036 $ 1,189,473 $ 1,130,000 (a) Floating-rate debt. (b) The fair value was based upon Level 2 inputs. See Note 5 for additional information about the Company’s 6.125% and 6.375% Senior Notes.
Fair Value of Assets and Liabilities Measured on Recurring Basis	The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis: June 30, 2019 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 24,843 $ — $ 24,843 Liabilities Derivative financial instruments Fair value of derivatives — (20,914 ) — (20,914 ) Total net assets (liabilities) $ — $ 3,929 $ — $ 3,929 December 31, 2018 Classification Level 1 Level 2 Level 3 Total Assets Derivative financial instruments Fair value of derivatives $ — $ 65,114 $ — $ 65,114 Liabilities Derivative financial instruments Fair value of derivatives — (17,920 ) — (17,920 ) Total net assets $ — $ 47,194 $ — $ 47,194

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2019
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation	The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations: Three Months Ended June 30, Six Months Ended June 30, Components of income tax rate reconciliation 2019 2018 2019 2018 Income tax expense computed at the statutory federal income tax rate 21 % 21 % 21 % 21 % State taxes net of federal expense 1 % 1 % 1 % 1 % Section 162(m) — % 1 % — % — % Valuation allowance — % (21 )% — % (21 )% Effective income tax rate, before discrete items 22 % 2 % 22 % 1 % Discrete items (a) 1 % (1 )% 2 % — % Effective income tax rate, after discrete items 23 % 1 % 24 % 1 % (a) Accounts for the potential impact of periodic volatility of stock-based compensation tax deductions on future effective tax rates.

Leases (Tables)

Leases (Tables)	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Lease, Cost	The components of our total lease cost were as follows: Three Months Ended Six Months Ended June 30, 2019 June 30, 2019 Operating lease cost $ 9,591 $ 19,156 Short-term lease cost (a) 1,849 3,347 (a) Short-term lease cost excludes expenses related to leases with a contract term of one month or less.
Lessee, Operating Lease, Liability, Maturity	Our operating lease liabilities with enforceable contract terms that are greater than one year mature as follows: As of June 30, 2019 Remainder of 2019 $ 15,937 2020 13,847 2021 1,576 2022 534 2023 517 Thereafter 431 Total lease payments 32,842 Less imputed interest 1,022 Total $ 31,820

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2019
Asset Retirement Obligation [Abstract]
Summary of Activity of Asset Retirement Obligations	The table below summarizes the activity for the Company’s ARO: Six Months Ended June 30, 2019 Asset retirement obligations at January 1, 2019 $ 14,292 Accretion expense 457 Liabilities incurred 199 Liabilities settled (630 ) Dispositions (1,701 ) Revisions to estimate (199 ) Asset retirement obligations at end of period 12,418 Less: Current asset retirement obligations (3,103 ) Long-term asset retirement obligations at June 30, 2019 $ 9,315 • Liabilities incurred include additions from acquisitions, asset swaps, and new wells drilled during the year. • Liabilities settled include the retirement of 20 wells during the year. • Dispositions are primarily attributable to the Ranger Asset Divestiture in the second quarter of 2019. See Note 3 for details about the Ranger Asset Divestiture. • Revisions to estimates were due to changes in plugging cost estimates, timing of abandonment activities, and changes in working interest of producing wells.

Revenue Recognition (Gathering

Revenue Recognition (Gathering and Treating Fees) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Accounts Receivable
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Contract with customer, asset, gross, current	$ 67,891		$ 67,891		$ 87,061
Natural Gas, Gathering and Treating Fees | Natural Gas Revenue
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of goods and services sold	$ 2,805	$ 1,952	$ 5,213	$ 3,204

Revenue Recognition (Performanc

Revenue Recognition (Performance Obligation) (Details)	6 Months Ended
	Jun. 30, 2019
Revenue from Contract with Customer [Abstract]
Performance obligation, description of timing	The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product.

Acquisitions and Dispositions_2

Acquisitions and Dispositions (Narrative - Dispositions) (Details) - Certain Non-core Assets in the Midland Basin $ in Thousands	Jun. 12, 2019USD ($)a
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration	$ 244,935
Potential contingency payments	$ 60,000
Potential contingency payments, period	3 years
Disposal Group, Including Discontinued Operation, Area of Land | a	9,850
Working interest	66.00%

Acquisitions and Dispositions_3

Acquisitions and Dispositions (Narrative - Acquisitions) (Details) a in Thousands, $ in Thousands	Aug. 31, 2018USD ($)a	Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Mar. 31, 2018USD ($)
Business Acquisition [Line Items]
Proceeds from acreage swaps		$ 19,108
WildHorse acreage
Business Acquisition [Line Items]
Proceeds from leasehold interest			$ 14,084
Spur operating areas
Business Acquisition [Line Items]
Consideration transferred			$ 21,407
Cimarex Energy Company
Business Acquisition [Line Items]
Consideration transferred	$ 539,519
Gas and oil area, developed and undeveloped, net (in acres) | a	28
Monarch and Wildhorse
Business Acquisition [Line Items]
Consideration transferred					$ 37,770
Wildhorse and Spur
Business Acquisition [Line Items]
Consideration transferred				$ 87,865

Acquisitions and Dispositions_4

Acquisitions and Dispositions (Fair Value of Net Assets Acquired ) (Details) - Cimarex Energy Company $ in Thousands	Aug. 31, 2018USD ($)
Business Acquisition [Line Items]
Asset retirement obligations	$ (570)
Net assets acquired	539,519
Evaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties	253,089
Unevaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties	$ 287,000

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Earnings Per Share, Basic and Diluted
Net income	$ 55,180	$ (19,543)	$ 50,474	$ 55,761	$ 35,637	$ 106,236
Preferred stock dividends	(1,823)		(1,824)		(3,647)	(3,647)
Income (loss) available to common stockholders	$ 53,357		$ 48,650		$ 31,990	$ 102,589
Weighted average common shares outstanding (in shares)	228,051		210,698		227,917	206,309
Dilutive impact of restricted stock (in shares)	360		767		682	718
Weighted average common shares outstanding for diluted income (loss) per share (in shares)	228,411		211,465		228,599	207,027
Basic income (loss) per share (in dollars per share)	$ 0.23		$ 0.23		$ 0.14	$ 0.50
Diluted income (loss) per share (in dollars per share)	$ 0.23		$ 0.23		$ 0.14	$ 0.50
Restricted Stock
Earnings Per Share, Basic and Diluted
Excluded from the diluted EPS calculation because their effect would be anti-dilutive (in shares)	641		0		498	0

Borrowings (Schedule of Borrowi

Borrowings (Schedule of Borrowings) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Principal components:
Total principal outstanding	$ 1,105,000	$ 1,200,000
Premium on senior unsecured notes, net of accumulated amortization	5,906	6,469
Unamortized deferred financing costs	(15,646)	(16,996)
Total carrying value of borrowings (a)	1,095,260	1,189,473
Deferred financing costs	5,427	6,087
Senior secured revolving credit facility
Principal components:
Total principal outstanding	105,000	200,000
6.125% senior unsecured notes due 2024
Principal components:
Total principal outstanding	$ 600,000	600,000
Debt instrument, interest rate, stated (as a percent)	6.125%
6.375% senior unsecured notes due 2026
Principal components:
Total principal outstanding	$ 400,000	$ 400,000
Debt instrument, interest rate, stated (as a percent)	6.375%

Borrowings (Credit Facility) (N

Borrowings (Credit Facility) (Narrative) (Details)	6 Months Ended
	Jun. 30, 2019USD ($)	May 01, 2019USD ($)	Dec. 31, 2018USD ($)	May 25, 2017USD ($)lender
Line of Credit Facility [Line Items]
Balance outstanding on credit facility	$ 105,000,000		$ 200,000,000
Senior secured revolving credit facility | Secured debt
Line of Credit Facility [Line Items]
Institutional lenders | lender				17
Maximum borrowing capacity				$ 2,000,000,000
Credit facility borrowing base	1,100,000,000	$ 1,100,000,000
Increase limit	850,000,000
Balance outstanding on credit facility	105,000,000
Letters of credit outstanding	$ 17,675,000
Interest rate at period end (as a percent)	3.65%
Unused capacity, commitment fee (as a percent)	0.375%
Senior secured revolving credit facility | Secured debt | Minimum
Line of Credit Facility [Line Items]
Debt instrument interest rate (as a percent)	1.25%
Senior secured revolving credit facility | Secured debt | Maximum
Line of Credit Facility [Line Items]
Debt instrument interest rate (as a percent)	2.25%

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities (Contingent Consideration Arrangement) (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2019USD ($)$ / bbl	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)
Derivative [Line Items]
Contingent consideration arrangement	$ 8,512	$ 0
Aggregate Settlements Limit	60,000
Year of Potential Settlement 2019
Derivative [Line Items]
Fair Value	$ 2,485
Threshold | $ / bbl	65
Year of Potential Settlement 2019 | Minimum
Derivative [Line Items]
Contingent Payment Amount	$ 9,000
Threshold | $ / bbl	60
Year of Potential Settlement 2019 | Maximum
Derivative [Line Items]
Contingent Payment Amount	$ 20,833
Threshold | $ / bbl	65
Year of Potential Settlement 2020
Derivative [Line Items]
Fair Value	$ 5,085
Threshold | $ / bbl	65
Year of Potential Settlement 2020 | Minimum
Derivative [Line Items]
Contingent Payment Amount	$ 9,000
Threshold | $ / bbl	60
Year of Potential Settlement 2020 | Maximum
Derivative [Line Items]
Contingent Payment Amount	$ 20,833
Threshold | $ / bbl	65
Year of Potential Settlement 2021
Derivative [Line Items]
Fair Value	$ 4,255
Threshold | $ / bbl	65
Potential reduction in settlements	$ 18,334
Year of Potential Settlement 2021 | Minimum
Derivative [Line Items]
Contingent Payment Amount	$ 9,000
Threshold | $ / bbl	60
Year of Potential Settlement 2021 | Maximum
Derivative [Line Items]
Contingent Payment Amount	$ 20,833
Threshold | $ / bbl	65
Not Designated as Hedging Instrument
Derivative [Line Items]
Contingent consideration arrangement	$ 24,843		$ 65,114
Fair value of derivatives - Non-current | Not Designated as Hedging Instrument
Derivative [Line Items]
Contingent consideration arrangement	2,339
Fair value of derivatives - Non-current | Contingent consideration arrangement | Not Designated as Hedging Instrument
Derivative [Line Items]
Contingent consideration arrangement	$ 9,340

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities (Fair Value of Derivative Instruments) (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Asset Fair Value	$ 24,843	$ 65,114
Liability Fair Value	(20,914)	(17,920)
Net Derivative Fair Value	3,929	47,194
Fair value of derivatives - Current
Derivatives, Fair Value [Line Items]
Asset Fair Value	10,679	65,114
Fair value of derivatives - Current
Derivatives, Fair Value [Line Items]
Liability Fair Value	(17,251)	(10,480)
Fair value of derivatives - Non-current
Derivatives, Fair Value [Line Items]
Asset Fair Value	2,339
Fair value of derivatives - Non-current
Derivatives, Fair Value [Line Items]
Liability Fair Value	(3,663)	(7,440)
Commodity - Oil | Fair value of derivatives - Current
Derivatives, Fair Value [Line Items]
Asset Fair Value	8,671	60,097
Commodity - Oil | Fair value of derivatives - Current
Derivatives, Fair Value [Line Items]
Liability Fair Value	(17,251)	(10,480)
Commodity - Oil | Fair value of derivatives - Current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	(8,580)	49,617
Commodity - Oil | Fair value of derivatives - Non-current
Derivatives, Fair Value [Line Items]
Asset Fair Value	2,335	0
Commodity - Oil | Fair value of derivatives - Non-current
Derivatives, Fair Value [Line Items]
Liability Fair Value	(3,327)	(5,672)
Commodity - Oil | Fair value of derivatives - Non-current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	(992)	(5,672)
Commodity - Natural gas | Fair value of derivatives - Current
Derivatives, Fair Value [Line Items]
Asset Fair Value	2,008	5,017
Commodity - Natural gas | Fair value of derivatives - Current
Derivatives, Fair Value [Line Items]
Liability Fair Value	0	0
Commodity - Natural gas | Fair value of derivatives - Current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	2,008	5,017
Commodity - Natural gas | Fair value of derivatives - Non-current
Derivatives, Fair Value [Line Items]
Asset Fair Value	4	0
Commodity - Natural gas | Fair value of derivatives - Non-current
Derivatives, Fair Value [Line Items]
Liability Fair Value	(336)	(1,768)
Commodity - Natural gas | Fair value of derivatives - Non-current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	(332)	$ (1,768)
Contingent consideration arrangement | Fair value of derivatives - Current
Derivatives, Fair Value [Line Items]
Asset Fair Value	2,485
Contingent consideration arrangement | Fair value of derivatives - Current
Derivatives, Fair Value [Line Items]
Liability Fair Value	0
Contingent consideration arrangement | Fair value of derivatives - Current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	2,485
Contingent consideration arrangement | Fair value of derivatives - Non-current
Derivatives, Fair Value [Line Items]
Asset Fair Value	9,340
Contingent consideration arrangement | Fair value of derivatives - Non-current
Derivatives, Fair Value [Line Items]
Liability Fair Value	0
Contingent consideration arrangement | Fair value of derivatives - Non-current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	$ 9,340

Derivative Instruments and He_5

Derivative Instruments and Hedging Activities (Schedule of Derivative Instruments in Statement of Financial Position, Fair Value) (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Offsetting Assets and Liabilities [Line Items]
As Presented with Effects of Netting	$ 24,843	$ 65,114
As Presented with Effects of Netting	(20,914)	(17,920)
Current assets: Fair value of commodity derivatives
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	20,044	78,091
Effects of Netting	(9,365)	(12,977)
As Presented with Effects of Netting	10,679	65,114
Long-term assets: Fair value of commodity derivatives
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	4,420
Effects of Netting	(2,081)
As Presented with Effects of Netting	2,339
Current liabilities: Fair value of commodity derivatives
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(26,616)	(23,457)
Effects of Netting	9,365	12,977
As Presented with Effects of Netting	(17,251)	(10,480)
Long-term liabilities: Fair value of commodity derivatives
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(5,744)	(7,440)
Effects of Netting	2,081	0
As Presented with Effects of Netting	$ (3,663)	$ (7,440)

Derivative Instruments and He_6

Derivative Instruments and Hedging Activities (Schedule of Gain or Loss on Derivative Contracts) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on fair value adjustments			$ (51,777)	$ (4,594)
Total gain (loss) on derivatives	$ 14,036	$ (16,554)	(53,224)	(21,036)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivatives	14,036	(16,554)	(53,224)	(21,036)
Not Designated as Hedging Instrument | Commodity - Oil
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	(4,461)	(8,131)	(6,003)	(17,049)
Net gain (loss) on fair value adjustments	13,310	(8,311)	(53,517)	(4,243)
Total gain (loss) on derivatives	8,849	(16,442)	(59,520)	(21,292)
Not Designated as Hedging Instrument | Commodity - Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	3,304	151	4,556	607
Net gain (loss) on fair value adjustments	(1,430)	(263)	(1,573)	(351)
Total gain (loss) on derivatives	1,874	(112)	2,983	256
Credit Risk Contract | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on fair value adjustments	$ 3,313	$ 0	$ 3,313	$ 0

Derivative Instruments and He_7

Derivative Instruments and Hedging Activities (Schedule of Outstanding Oil and Natural Gas Derivative Contracts) (Details) - Forecast - Not Designated as Hedging Instrument	6 Months Ended	12 Months Ended
	Dec. 31, 2019MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2021MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2020MMBTU$ / bbl$ / MMBTUbbl
Commodity - Oil | Put spreads
Derivative [Line Items]
Total volume (Bbls) | bbl	460,000	0	0
Commodity - Oil | Collar contracts with short puts (three-way collars)
Derivative [Line Items]
Total volume (Bbls) | bbl	2,392,000	0	3,294,000
Commodity - Oil | Oil contracts (Midland basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl	4,137,500	1,095,000	4,576,000
Weighted average swap price (in dollars per share)	(2.64)	(1)	(1.29)
Commodity - Oil | Oil contracts (Argus Houston MEH basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	0	552,000
Strike price (in dollars per share) | $ / MMBTU	0	0	3.30
Commodity - Oil | Put option
Derivative [Line Items]
Total volume (Bbls) | bbl	460,000	0	0
Strike price (in dollars per share)	65	0	0
Commodity - Oil | Put option | Put spreads | Long
Derivative [Line Items]
Strike price (in dollars per share)	65	0	0
Commodity - Oil | Put option | Put spreads | Short
Derivative [Line Items]
Strike price (in dollars per share)	42.50	0	0
Commodity - Oil | Put option | Collar contracts with short puts (three-way collars) | Long
Derivative [Line Items]
Strike price (in dollars per share)	56.54	0	55.69
Commodity - Oil | Put option | Collar contracts with short puts (three-way collars) | Short
Derivative [Line Items]
Strike price (in dollars per share)	43.65	0	44.47
Commodity - Oil | Call option | Collar contracts with short puts (three-way collars) | Short
Derivative [Line Items]
Strike price (in dollars per share)	67.46	0	65.72
Commodity - Natural gas | Swap contracts
Derivative [Line Items]
Strike price (in dollars per share) | $ / MMBTU	2.89	0	0
Total volume (MMBtu) | MMBTU	1,397,000	0	0
Commodity - Natural gas | Collar contracts (two-way collars)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	1,196,000	0	0
Commodity - Natural gas | Collar contracts (two-way collars) | Long
Derivative [Line Items]
Strike price (in dollars per share) | $ / MMBTU	3.13	0	0
Commodity - Natural gas | Collar contracts (two-way collars) | Short
Derivative [Line Items]
Strike price (in dollars per share) | $ / MMBTU	3.50	0	0
Commodity - Natural gas | Waha basis differential | Swap contracts
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	4,232,000	0	4,758,000
Weighted average swap price (in dollars per share) | $ / MMBTU	(1.18)	0	(1.12)

Fair Value Measurements (Summar

Fair Value Measurements (Summary of Financial Instruments at Carrying and Fair Value) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018	Jun. 07, 2018
6.125% senior unsecured notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%
6.125% senior unsecured notes due 2024 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%
6.375% senior unsecured notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%
6.375% senior unsecured notes due 2026 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)			6.375%
Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit Facility	$ 105,000	$ 200,000
Total	1,095,260	1,189,473
Carrying Value | 6.125% senior unsecured notes due 2024 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	596,154	595,788
Carrying Value | 6.375% senior unsecured notes due 2026 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	394,106	393,685
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit Facility	105,000	200,000
Total	1,118,036	1,130,000
Fair Value | 6.125% senior unsecured notes due 2024 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	609,048	558,000
Fair Value | 6.375% senior unsecured notes due 2026 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	$ 403,988	$ 372,000

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - Recurring Basis - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Assets
Derivative financial instruments	$ 24,843	$ 65,114
Liabilities
Derivative financial instruments	(20,914)	(17,920)
Net Derivative Fair Value	3,929	47,194
Level 1
Assets
Derivative financial instruments	0	0
Liabilities
Derivative financial instruments	0	0
Net Derivative Fair Value	0	0
Level 2
Assets
Derivative financial instruments	24,843	65,114
Liabilities
Derivative financial instruments	(20,914)	(17,920)
Net Derivative Fair Value	3,929	47,194
Level 3
Assets
Derivative financial instruments	0	0
Liabilities
Derivative financial instruments	0	0
Net Derivative Fair Value	$ 0	$ 0

Income Taxes (Details)

Income Taxes (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Components of income tax rate reconciliation
Income tax expense computed at the statutory federal income tax rate	21.00%	21.00%	21.00%	21.00%
State taxes net of federal expense	1.00%	1.00%	1.00%	1.00%
Section 162(m)	0.00%	1.00%	0.00%	0.00%
Valuation allowance	0.00%	(21.00%)	0.00%	(21.00%)
Effective income tax rate, before discrete items	22.00%	2.00%	22.00%	1.00%
Discrete items (a)	1.00%	(1.00%)	2.00%	0.00%
Effective income tax rate, before discrete items	23.00%	1.00%	24.00%	1.00%

Equity Transactions (Details)

Equity Transactions (Details) - USD ($) $ / shares in Units, $ in Thousands	Jun. 18, 2019	May 30, 2018	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Class of Stock [Line Items]
Preferred stock dividend			$ 1,823		$ 1,824		$ 3,647	$ 3,647
Accrued and unpaid dividends (in dollars per share)			$ 1.25	$ 1.25	$ 1.25	$ 1.25
Issuance of common stock							$ 0	$ 288,357
Series A Preferred Stock
Class of Stock [Line Items]
Preferred stock cumulative cash dividends rate							10.00%
Preferred stock, liquidation preference (in dollars per share)	$ 50		$ 50				$ 50		$ 50
Preferred stock, dividend rate (in dollars per share)							$ 5
Accrued and unpaid dividends (in dollars per share)	0.24
Redemption price (in dollars per share)	$ 50.24
Common Stock
Class of Stock [Line Items]
Shares of common stock issued in public offering (in shares)		25,300,000
Issuance of common stock		$ 287,988

Leases (Cost) (Details)

Leases (Cost) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Leases [Abstract]
Operating lease cost	$ 9,591	$ 19,156
Short-term lease cost	$ 1,849	$ 3,347

Leases (Narrative) (Details)

Leases (Narrative) (Details)	6 Months Ended
	Jun. 30, 2019
Lessee, Lease, Description [Line Items]
Weighted average remaining lease term	1 year 5 months 12 days
Weighted average discount rate, percent	4.02%
Drilling Rigs
Lessee, Lease, Description [Line Items]
Extension period notice	30 days
Drilling Rigs | Minimum
Lessee, Lease, Description [Line Items]
Term of contract	1 year
Drilling Rigs | Maximum
Lessee, Lease, Description [Line Items]
Term of contract	2 years
Offices | Minimum
Lessee, Lease, Description [Line Items]
Term of contract	2 years
Offices | Maximum
Lessee, Lease, Description [Line Items]
Term of contract	5 years

Leases (Maturities) (Details)

Leases (Maturities) (Details) $ in Thousands	Jun. 30, 2019USD ($)
Leases [Abstract]
Remainder of 2019	$ 15,937
2020	13,847
2021	1,576
2022	534
2023	517
Thereafter	431
Total lease payments	32,842
Less imputed interest	1,022
Total	$ 31,820

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2019USD ($)well	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1, 2019			$ 14,292
Accretion expense	$ 216	$ 206	457	$ 424
Liabilities incurred			199
Liabilities settled			(630)
Dispositions			(1,701)
Revisions to estimate			(199)
Asset retirement obligations at end of period	12,418		12,418
Less: Current asset retirement obligations	(3,103)		(3,103)		$ (3,887)
Long-term asset retirement obligations at June 30, 2019	9,315		$ 9,315		10,405
Number of wells retired | well			20
Restricted Investments
Restricted investments	$ 3,468		$ 3,468		$ 3,424

Other (Details)

Other (Details) - bbl / d	Aug. 06, 2018	Jul. 31, 2019	Jun. 30, 2019	Jan. 31, 2019
Subsequent Event [Line Items]
Delivery commitments per day	15,000		10,000	10,000
Subsequent Event
Subsequent Event [Line Items]
Delivery commitments per day		5,000

Carrizo Acquisition (Details)

Carrizo Acquisition (Details) - Subsequent Event	Jul. 14, 2019shares
Callon Petroleum Company
Subsequent Event [Line Items]
Post merger, percent of share outstanding owned	54.00%
Carrizo
Subsequent Event [Line Items]
Post merger, percent of share outstanding owned	46.00%
Carrizo
Subsequent Event [Line Items]
Exchange ratio (in shares)	2.05