10-Q

UNITED STATES

SECURITIES ANDEXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For The Quarterly Period EndedSeptember 30, 2018

OR

☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ____________ to ____________

Commission File Number 001-14039

Callon Petroleum Company

(Exact Name of Registrant as Specified in Its Charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)	64-0844345 (IRS Employer Identification No.)
200 North Canal Street Natchez, Mississippi (Address of Principal Executive Offices)	39120 (Zip Code)

601-442-1601

(Registrant’s Telephone Number, Including Area Code)

Not Applicable

(Former Name, Former Address and Former Fiscal Year, If Changed Since Last Report)

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐	Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The Registrant had 227,581,223 shares of common stock outstanding as of November 2, 2018.

Table of Contents

Part I. Financial Information
Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheets	4
Consolidated Statements of Operations	5
Consolidated Statements of Cash Flows	6
Notes to Consolidated Financial Statements	7
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.  Quantitative and Qualitative Disclosures about Market Risk	34
Item 4.  Controls and Procedures	35
Part II.  Other Information
Item 1.  Legal Proceedings	36
Item 1A.  Risk Factors	36
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 3.  Defaults Upon Senior Securities	36
Item 4.  Mine Safety Disclosures	36
Item 5.  Other Information	36
Item 6.  Exhibits	37

2

Glossary of Certain Terms

All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document:

• ARO:  asset retirement obligation.

• ASU: accounting standards update.

• Bbl or Bbls:  barrel or barrels of oil or natural gas liquids.

• BOE:  barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.  The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.

• BOE/d:  BOE per day.

• Btu:  a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

• Completion: The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

• Cushing: An oil delivery point that serves as the benchmark oil price for West Texas Intermediate.

FASB: Financial Accounting Standards Board.

• GAAP: Generally Accepted Accounting Principles in the United States.

• Henry Hub: A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.

• Horizontal drilling: A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

• LIBOR:  London Interbank Offered Rate.

• LOE:  lease operating expense.

• MBbls:  thousand barrels of oil.

• MBOE:  thousand BOE.

• Mcf:  thousand cubic feet of natural gas.

• MMBtu:  million Btu.

• MMcf:  million cubic feet of natural gas.

• NGL or NGLs:  natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.

• NYMEX:  New York Mercantile Exchange.

• Oil: includes crude oil and condensate.

• Realized price: The cash market price less all expected quality, transportation and demand adjustments.

• Royalty interest: An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

• RSU: restricted stock units.

• SEC:  United States Securities and Exchange Commission.

• Waha: A natural gas delivery point in West Texas that serves as the benchmark for gas delivered and sold into Pecos County.

• Working interest: An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

• WTI: West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.

With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 

3

Part I.  Financial Information

Item I.  Financial Statements

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par and per share data)

	September 30, 2018			December 31, 2017
ASSETS	Unaudited
Current assets:
Cash and cash equivalents	$	12,129		$	27,995
Accounts receivable	168,753			114,320
Fair value of derivatives	4,289			406
Other current assets	3,804			2,139
Total current assets	188,975			144,860
Oil and natural gas properties, full cost accounting method:
Evaluated properties	4,305,189			3,429,570
Less accumulated depreciation, depletion, amortization and impairment	(2,208,066		)	(2,084,095		)
Net evaluated oil and natural gas properties	2,097,123			1,345,475
Unevaluated properties	1,385,529			1,168,016
Total oil and natural gas properties	3,482,652			2,513,491
Other property and equipment, net	21,738			20,361
Restricted investments	3,413			3,372
Deferred tax asset	—			52
Deferred financing costs	6,406			4,863
Acquisition deposit	—			900
Other assets, net	5,552			5,397
Total assets	$	3,708,736		$	2,693,296
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	251,754		$	162,878
Accrued interest	27,325			9,235
Cash-settleable restricted stock unit awards	2,422			4,621
Asset retirement obligations	4,464			1,295
Fair value of derivatives	47,167			27,744
Total current liabilities	333,132			205,773
Senior secured revolving credit facility	65,000			25,000
6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs	595,729			595,196
6.375% senior unsecured notes due 2026, net of unamortized deferred financing costs	392,799			—
Asset retirement obligations	5,428			4,725
Cash-settleable restricted stock unit awards	2,818			3,490
Deferred tax liability	3,917			1,457
Fair value of derivatives	15,440			1,284
Other long-term liabilities	6,165			405
Total liabilities	1,420,428			837,330
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; 227,567,936 and 201,836,172 shares outstanding, respectively	2,276			2,018
Capital in excess of par value	2,474,748			2,181,359
Accumulated deficit	(188,731		)	(327,426		)
Total stockholders’ equity	2,288,308			1,855,966
Total liabilities and stockholders’ equity	$	3,708,736		$	2,693,296

The accompanying notes are an integral part of these consolidated financial statements.

4

Callon Petroleum Company

Consolidated Statements of Operations

(Unaudited; in thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Operating revenues:
Oil sales	$	142,601		$	73,349		$	380,500		$	218,242
Natural gas sales	18,613			11,265			45,229			30,019
Total operating revenues	161,214			84,614			425,729			248,261
Operating expenses:
Lease operating expenses	18,525			11,624			44,705			36,708
Production taxes	10,263			5,444			26,265			16,168
Depreciation, depletion and amortization	48,257			28,525			122,407			79,172
General and administrative	9,721			7,259			26,779			18,894
Settled share-based awards	—			—			—			6,351
Accretion expense	202			131			626			523
Acquisition expense	1,435			205			3,750			3,027
Total operating expenses	88,403			53,188			224,532			160,843
Income from operations	72,811			31,426			201,197			87,418
Other (income) expenses:
Interest expense, net of capitalized amounts	711			444			1,765			1,698
(Gain) loss on derivative contracts	34,339			14,162			55,374			(11,636		)
Other income	(1,657		)	(498		)	(2,571		)	(1,270		)
Total other (income) expense	33,393			14,108			54,568			(11,208		)
Income before income taxes	39,418			17,318			146,629			98,626
Income tax expense	1,487			237			2,463			1,026
Net income	37,931			17,081			144,166			97,600
Preferred stock dividends	(1,823		)	(1,824		)	(5,471		)	(5,471		)
Income available to common stockholders	$	36,108		$	15,257		$	138,695		$	92,129
Income per common share:
Basic	$	0.16		$	0.08		$	0.65		$	0.46
Diluted	$	0.16		$	0.08		$	0.65		$	0.46
Shares used in computing income per common share:
Basic	227,564			201,827			213,409			201,422
Diluted	228,140			202,337			214,079			201,995

The accompanying notes are an integral part of these consolidated financial statements.

5

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)

	Nine Months Ended September 30,
	2018			2017
Cash flows from operating activities:
Net income	$	144,166		$	97,600
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	124,430			80,829
Accretion expense	626			523
Amortization of non-cash debt related items	1,749			1,695
Deferred income tax expense	2,463			1,026
Net (gain) loss on derivatives, net of settlements	29,696			(15,608		)
(Gain) loss on sale of other property and equipment	(80		)	62
Non-cash expense related to equity share-based awards	4,466			7,014
Change in the fair value of liability share-based awards	1,428			2,423
Payments to settle asset retirement obligations	(1,080		)	(1,831		)
Changes in current assets and liabilities:
Accounts receivable	(54,384		)	(12,148		)
Other current assets	(1,665		)	(336		)
Current liabilities	64,801			7,534
Other long-term liabilities	5,787			121
Long-term prepaid	—			(4,650		)
Other assets, net	(1,398		)	(1,376		)
Payments to settle vested liability share-based awards	(4,990		)	(13,173		)
Net cash provided by operating activities	316,015			149,705
Cash flows from investing activities:
Capital expenditures	(455,352		)	(267,218		)
Acquisitions	(595,984		)	(714,504		)
Acquisition deposit	—			46,138
Proceeds from sale of assets	8,326			—
Net cash used in investing activities	(1,043,010		)	(935,584		)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	270,000			—
Payments on senior secured revolving credit facility	(230,000		)	—
Issuance of 6.125% senior unsecured notes due 2024	—			200,000
Premium on the issuance of 6.125% senior unsecured notes due 2024	—			8,250
Issuance of 6.375% senior unsecured notes due 2026	400,000			—
Issuance of common stock	288,364			—
Payment of preferred stock dividends	(5,471		)	(5,471		)
Payment of deferred financing costs	(9,960		)	(7,166		)
Tax withholdings related to restricted stock units	(1,804		)	(1,118		)
Net cash provided by financing activities	711,129			194,495
Net change in cash and cash equivalents	(15,866		)	(591,384		)
Balance, beginning of period	27,995			652,993
Balance, end of period	$	12,129		$	61,609

The accompanying notes are an integral part of these consolidated financial statements. 

6

Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

Index to the Notes to the Consolidated Financial Statements

1.	Description of Business and Basis of Presentation	7.	Fair Value Measurements
2.	Revenue Recognition	8.	Income Taxes
3.	Acquisitions	9.	Asset Retirement Obligations
4.	Earnings Per Share	10.	Equity Transactions
5.	Borrowings	11.	Other
6.	Derivative Instruments and Hedging Activities

Note 1 - Description of Business and Basis of Presentation

Description of business

Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. 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.

Callon is focused on the acquisition, development, exploration and exploitation of unconventional onshore, oil and natural gas reserves in the Permian Basin. The Company’s operations to date have been predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on its existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. 

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 subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc.

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, 2017. The balance sheet at December 31, 2017 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, 2018.

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, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts may have been reclassified to conform to current year presentation.

Accounting Standards Updates (“ASUs”)

Recently Adopted ASUs - Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 replaced most of the existing revenue recognition requirements in GAAP.

Throughout 2015 and 2016, the FASB issued several updates to the revenue recognition guidance in Accounting Standards Codification Topic 606 (“ASC 606”). In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers - Principal versus Agent Considerations (Reporting Revenue Gross versus Net). Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods

7

Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

or services. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers - Identifying Performance Obligations and Licensing. This update clarifies two principles of ASC 606: identifying performance obligations and the licensing implementation guidance. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients. This update applies only to the following areas from ASC 606: assessing the collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar taxes collected from customers, non-cash consideration, contract modification at transition, completed contracts at transition and technical correction.

Prior to the adoption of ASC 606, gathering and treating fees associated with our gas processing agreements have historically been presented within lease operating expenses in the statement of operations. The current period presentation reports these fees as a reduction to natural gas revenues. See Note 2 for additional information on revenue recognition.

The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption and the impact of adoption on the current period statement of operations is as follows:

	Three Months Ended September 30, 2018
	As reported		Adjustments		Presentation without adoption of ASC Topic 606
Operating revenues:
Natural gas sales	$	18,613	$	2,209	$	20,822
Total operating revenues	161,214		2,209		163,423
Operating expenses:
Lease operating expenses	$	18,525	$	2,209	$	20,734
Total operating expenses	88,403		2,209		90,612

	Nine Months Ended September 30, 2018
	As reported		Adjustments		Presentation without adoption of ASC Topic 606
Operating revenues:
Natural gas sales	$	45,229	$	5,413	$	50,642
Total operating revenues	425,729		5,413		431,142
Operating expenses:
Lease operating expenses	$	44,705	$	5,413	$	50,118
Total operating expenses	224,532		5,413		229,945

Recently adopted ASUs - Other

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. The Company adopted this update on January 1, 2018 and it did not have a material impact on its consolidated financial statements.

8

Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations-Clarifying the Definition of a Business (“ASU 2017-01”). The guidance in ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The guidance in ASU 2017-01 is effective for annual reporting periods beginning after December 15, 2017, including interim periods therein. The Company adopted this update effective January 1, 2018. The adoption of this update did not have a material impact on its consolidated financial statements.

Recently issued 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”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”).

ASC Topic 842 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under Topic 840. The Company has engaged a third party consultant to assist with its current process of assessing existing contracts, as well as future potential contracts, and to determine the impact of applying Topic 842 on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, field vehicles and equipment, office facility leases, compressors, general corporate leased equipment, and other existing arrangements that may contain a lease component. The Company will adopt this guidance as of January 1, 2019, the transition date, using a modified retrospective method with use of the transition option, in which a cumulative-effect adjustment will be recognized in the opening balance of retained earnings in the period of adoption.  The Company expects the adoption of ASC Topic 842 to primarily impact the asset and liability balances on the balance sheet and will result in changes to the timing and presentation of certain operating expenses on its consolidated statement of operations.

Recently issued 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 guidance in ASU 2018-06 is effective for public entities for annual reporting periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted, but no earlier than an entity’s adoption date of Topic 606. The Company does not expect a material impact on its consolidated financial statements upon adoption of this guidance.

Note 2 - 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 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 revenues. For the three and nine months ended September 30, 2018, $2,209 and $5,413 of gathering and treating fees were recognized and recorded as a reduction to natural gas revenues in the consolidated statement of operations, respectively. For the three and nine months ended September 30, 2017, $909 and $2,393 of gathering and treating fees were recognized and recorded as part of lease operating expense in the consolidated statement of operations, respectively.

9

Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

Production imbalances

Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer applicable. In conjunction with the Company’s adoption of the new revenue recognition accounting standards, there was no material impact to the financial statements due to this change in accounting for its production imbalances.

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.

Note 3 - Acquisitions 

Acquisitions were accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed under the income approach.

2018 Acquisitions

During the first quarter of 2018, the Company completed acquisitions of additional working interests and acreage in the Company’s existing core operating areas of Monarch and Wildhorse, located in the Permian Basin, for an aggregate total purchase price of approximately $35,900 excluding customary purchase price adjustments.

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 “Cimarex Asset Acquisition”). The Company issued debt and equity to fund, in part, the Cimarex Asset Acquisition. See Notes 5 and 10 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

The preliminary purchase price allocations are subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material.

2017Acquisitions

On February 13, 2017, the Company completed the acquisition of 29,175 gross (16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for $646,559 excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company obtained an 82% average working interest (75% average net revenue interest) in the properties acquired in the Ameredev Transaction.

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Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

The following table summarizes the estimated acquisition date fair values of the acquisition:

Evaluated oil and natural gas properties	$	137,368
Unevaluated oil and natural gas properties	509,359
Asset retirement obligations	(168		)
Net assets acquired	$	646,559

On June 5, 2017, the Company completed the acquisition of 7,031 gross (2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for $52,500 excluding customary purchase price adjustments. The Company funded the cash purchase price with its available cash and proceeds from the issuance of an additional $200,000 of its 6.125% senior notes due 2024 (see Note 5 for additional information regarding the Company’s debt obligations).

Unaudited pro forma financial statements

The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Cimarex Asset Acquisition and Ameredev Transaction had occurred as presented, or to project the Company’s results of operations for any future periods:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		(a)	2017		(a)	2018		(a)	2017		(a)
Revenues	$	181,880		$	107,966		$	506,864		$	326,357
Income from operations	82,057			42,556			238,776			124,005
Income available to common stockholders	44,703			26,387			175,623			128,716
Net income per common share:
Basic	$	0.20		$	0.13		$	0.82		$	0.64
Diluted	$	0.20		$	0.13		$	0.82		$	0.64

(a) The pro forma financial information was prepared assuming the Cimarex Asset Acquisition and the Ameredev Transaction occurred as of January 1, 2017.

The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest.

The properties associated with the Cimarex Asset Acquisition and Ameredev Transaction have been commingled with the Company’s existing properties and it is impractical to provide the stand-alone operational results related to these properties.

Note 4 - EarningsPer Share

The following table sets forth the computation of basic and diluted earnings per share:

(share amounts in thousands)	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net income	$	37,931		$	17,081		$	144,166		$	97,600
Preferred stock dividends	(1,823		)	(1,824		)	(5,471		)	(5,471		)
Income available to common stockholders	$	36,108		$	15,257		$	138,695		$	92,129
Weighted average shares outstanding	227,564			201,827			213,409			201,422
Dilutive impact of restricted stock	576			510			670			573
Weighted average shares outstanding for diluted income per share	228,140			202,337			214,079			201,995
Basic income per share	$	0.16		$	0.08		$	0.65		$	0.46
Diluted income per share	$	0.16		$	0.08		$	0.65		$	0.46
Restricted stock (a)	154			51			154			51

(a) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

11

Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

Note 5 - Borrowings

The Company’s borrowings consisted of the following at:

	September 30, 2018			December 31, 2017
Principal components:
Senior secured revolving credit facility	$	65,000		$	25,000
6.125% senior unsecured notes due 2024	600,000			600,000
6.375% senior unsecured notes due 2026	400,000			—
Total principal outstanding	1,065,000			625,000
Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization	6,750			7,594
Unamortized deferred financing costs	(18,222		)	(12,398		)
Total carrying value of borrowings	$	1,053,528		$	620,196

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 with a maturity date of May 25, 2022. 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.

Effective April 5, 2018, the Company entered into the first amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $825,000, (2) increased the elected commitment amount to $650,000, (3) decreased the applicable margins for interest rates, based on utilization, to a range of 1.25% to 2.25%, and (4) extended the maturity date to May 25, 2023.

Effective September 27, 2018, the Company entered into the second amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $1,100,000, (2) increase the elected commitment amount to $850,000, and (3) amended various covenants and terms to reflect current market trends. As of September 30, 2018, the Credit Facility’s borrowing base remained at $1,100,000 with an elected commitment amount of $850,000.

As of September 30, 2018, there was $65,000 principal and $17,675 in letters of credit outstanding under the Credit Facility. For the quarter ended September 30, 2018, the Credit Facility had a weighted-average interest rate of 3.29%, 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 carried a commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base.

6.375% senior unsecured notes due 2026 (“6.375% Senior Notes”)

On June 7, 2018, the Company issued $400,000 aggregate principal amount of 6.375% Senior Notes with a maturity date of July 1, 2026 and interest payable semi-annually beginning on January 1, 2019. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $394,000. The 6.375% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

The Company may redeem the 6.375% Senior Notes in accordance with the following terms: (1) prior to July 1, 2021, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.375% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to July 1, 2021, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 103.188% of principal if the redemption occurs on or after July 1, 2021, but before July 1, 2022, and (ii) of 102.125% of principal if the redemption occurs on or after July 1, 2022, but before July 1, 2023, and (iii) of 101.063% of principal if the redemption occurs on or after July 1, 2023, but before July 1, 2024, and (iv) of 100% of principal if the redemption occurs on or after July 1, 2024.

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Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

Following a change of control, each holder of the 6.375% Senior Notes may require the Company to repurchase all or a portion of the 6.375% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.

6.125% senior unsecured notes due 2024 (“6.125% Senior Notes”)

On October 3, 2016, the Company issued $400,000 aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391,270. The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

On May 19, 2017, the Company issued an additional $200,000 aggregate principal amount of its 6.125% Senior Notes which with the existing $400,000 aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206,139. The Company used the proceeds, in part, to fund an acquisition completed on June 5, 2017 (discussed further in Note 3) and for general corporate purposes.

The Company may redeem the 6.125% Senior Notes in accordance with the following terms: (1) prior to October 1, 2019, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.125% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2019, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 104.594% of principal if the redemption occurs on or after October 1, 2019, but before October 1, 2020, and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020, but before October 1, 2021, and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022, and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022.

Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.

Restrictive covenants

The Company’s Credit Facility and the indentures governing its 6.125% and 6.375% 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 September 30, 2018.

Note 6 - Derivative Instruments and Hedging Activities

Objectives and strategies for using 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, put and call options and similar derivative financial instruments 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

13

Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

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 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.

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: 

	Balance Sheet Presentation		Asset Fair Value				Liability Fair Value						Net Derivative Fair Value
Commodity	Classification	Line Description	9/30/2018		12/31/2017		9/30/2018			12/31/2017			9/30/2018			12/31/2017
Natural gas	Current	Fair value of derivatives	$	750	$	406	$	(21	)	$	—		$	729		$	406
Natural gas	Non-current	Fair value of derivatives	—		—		(1,299		)	—			(1,299		)	—
Oil	Current	Fair value of derivatives	3,539		—		(47,146		)	(27,744		)	(43,607		)	(27,744		)
Oil	Non-current	Fair value of derivatives	—		—		(14,141		)	(1,284		)	(14,141		)	(1,284		)
Totals			$	4,289	$	406	$	(62,607	)	$	(29,028	)	$	(58,318	)	$	(28,622	)

As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of 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:

	September 30, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	16,157		$	(11,868	)	$	4,289
Long-term assets: Fair value of derivatives	2,786			(2,786		)	—
Current liabilities: Fair value of derivatives	$	(59,035	)	$	11,868		$	(47,167	)
Long-term liabilities: Fair value of derivatives	(18,226		)	2,786			(15,440		)

	December 31, 2017
	Presented without					As Presented with
	Effects of Netting			Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	406		$	—	$	406
Current liabilities: Fair value of derivatives	$	(27,744	)	$	—	$	(27,744	)
Long-term liabilities: Fair value of derivatives	(1,284		)	—		(1,284		)

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Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Oil derivatives
Net loss on settlements	$	(9,306	)	$	(1,373	)	$	(26,353	)	$	(4,213	)
Net gain (loss) on fair value adjustments	(24,476		)	(12,811		)	(28,720		)	14,584
Total gain (loss) on oil derivatives	$	(33,782	)	$	(14,184	)	$	(55,073	)	$	10,371
Natural gas derivatives
Net gain on settlements	$	67		$	159		$	675		$	241
Net gain (loss) on fair value adjustments	(624		)	(137		)	(976		)	1,024
Total gain (loss) on natural gas derivatives	$	(557	)	$	22		$	(301	)	$	1,265
Total gain (loss) on oil & natural gas derivatives	$	(34,339	)	$	(14,162	)	$	(55,374	)	$	11,636

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Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of September 30, 2018:  

	For the Remainder			For the Full Year			For the Full Year
Oil contracts (WTI)	of 2018			of 2019			of 2020
Swap contracts
Total volume (Bbls)	552,000			—			—
Weighted average price per Bbl	$	52.07		$	—		$	—
Collar contracts (two-way collars)
Total volume (Bbls)	92,000			1,095,000			—
Weighted average price per Bbl
Ceiling (short call)	$	60.50		$	80.00		$	—
Floor (long put)	$	50.00		$	65.00		$	—
Collar contracts combined with short puts (three-way collars)
Total volume (Bbls)	874,000			3,469,000			—
Weighted average price per Bbl
Ceiling (short call option)	$	60.86		$	63.71		$	—
Floor (long put option)	$	48.95		$	53.95		$	—
Short put option	$	39.21		$	43.95		$	—
Puts
Total volume (Bbls)	276,000			1,825,000			—
Weighted average price per Bbl	$	65.00		$	65.00		$	—
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	1,518,000			4,746,500			4,024,000
Weighted average price per Bbl	$	(5.30	)	$	(4.72	)	$	(1.51	)
Natural gas contracts (Henry Hub)
Swap contracts
Total volume (MMBtu)	1,380,000			—			—
Weighted average price per MMBtu	$	2.91		$	—		$	—
Collar contracts (two-way collars)
Total volume (MMBtu)	552,000			2,372,500			—
Weighted average price per MMBtu
Ceiling (short call)	$	3.19		$	2.95		$	—
Floor (long put)	$	2.75		$	2.65		$	—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	552,000			5,840,000			2,196,000
Weighted average price per MMBtu	$	(1.14	)	$	(1.21	)	$	(1.14	)

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Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

Subsequent Event

The following derivative contracts were executed subsequent to September 30, 2018:

	For the Remainder	For the Full Year			For the Full Year
	of 2018	of 2019			of 2020
Natural gas contracts (Henry Hub)
Collar contracts (two-way collars)
Total volume (MMBtu)	—	1,355,000			—
Weighted average price per MMBtu
Ceiling (short call)	—	$	3.45		—
Floor (long put)	—	$	2.83		—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	—	3,650,000			—
Weighted average price per MMBtu	—	$	(1.30	)	—

Note 7 - Fair Value Measurements

The fair value hierarchy included in GAAP 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 offinancial 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.

	September 30, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit Facility (a)	$	65,000	$	—	$	25,000	$	—
6.125% Senior Notes (b)	595,729		610,500		595,196		618,000
6.375% Senior Notes (b)	392,799		409,000		—		—
Total	$	1,053,528	$	1,019,500	$	620,196	$	618,000

(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.

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Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:

September 30, 2018	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	4,289		$	—	$	4,289
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(62,607		)	—		(62,607		)
Total net liabilities		$	—	$	(58,318	)	$	—	$	(58,318	)
December 31, 2017	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	406		$	—	$	406
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(29,028		)	—		(29,028		)
Total net liabilities		$	—	$	(28,622	)	$	—	$	(28,622	)

Assets andliabilitiesmeasured atfairvalue on anonrecurringbasis

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 are based on Level 2 and Level 3 inputs.

Note 8 - Income Taxes

The Company provides for income taxes at the statutory rate of 21%. The statutory rate is adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls and shortfalls, and state income taxes.

As a result of the write-down of oil and natural gas properties in the latter part of 2015 and the first half of 2016, the Company incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a full valuation allowance for the net U.S. federal deferred tax asset in 2015. In subsequent periods where the Company has recorded pre-tax income, it has reversed a portion of the U.S. federal valuation allowance, net of discrete items, to the extent necessary to offset U.S. federal income tax expense on pre-tax income recorded for the period. Income tax expense recorded in this period primarily relates to deferred State of Texas gross margin tax. The valuation allowance was $30,281 as of September 30, 2018. 

Note 9 - Asset Retirement Obligations

The table below summarizes the activity for the Company’s ARO:

	Nine Months Ended
	September 30, 2018
Asset retirement obligations at January 1, 2018	$	6,020
Accretion expense	626
Liabilities incurred	729
Liabilities settled	(989		)
Sales	(612		)
Revisions to estimate (a)	4,118
Asset retirement obligations at end of period	9,892
Less: Current asset retirement obligations	(4,464		)
Long-term asset retirement obligations at September 30, 2018	$	5,428

(a) Revisions to estimated ARO obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

18

Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at September 30, 2018 as long-term restricted investments were $3,413. 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.

Note 10 - Equity Transactions

10% Series A Cumulative Preferred Stock (“Preferred Stock”)

Holders of the Company’s Preferred Stock are 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 are 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 were $1,823 and $1,824 for the three months ended September 30, 2018 and 2017, respectively. Preferred Stock dividends of $5,471 for the nine months ended September 30, 2018 remained consistent compared to the same period of 2017.

The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. The Company may, at its option, redeem the Preferred Stock, in whole or in part, at any time on or after May 30, 2018, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date.

Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part, for $50.00 per share in cash plus accrued and unpaid dividends (whether or not declared) to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon such change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on September 30, 2018, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $11.99 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 4.2 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.

Commonstock 

On May 30, 2018, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering costs) of approximately $288,364. The Company used proceeds from the offering to partially fund the Cimarex Asset Acquisition completed in the third quarter, described in Note 3.

On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,934. Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in Note 3.

Note 11 - Other

Operating leases

As of September 30, 2018 the Company had contracts for five horizontal drilling rigs. The contract terms, as amended effective as of July 9, 2018, will end on various dates between July 2019 and February 2021. All of the drilling rig contracts provide for early termination, with penalties calculated at a reduced daily rate. In the event that Callon terminated all five drilling contracts as of November 6, 2018, the Company would owe a maximum of $26,696 over the remaining terms of the respective contracts, offset by any revenues earned for replacement work subsequently secured by the contractor. Management does not currently anticipate the early termination of any drilling rig contracts.

Other commitments

In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a two-year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021.

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,

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Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

Ward, Reagan and Upton 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.

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Callon Petroleum Company Table of Contents

Special Note Regarding Forward Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-Q by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as:

• our oil and gas reserve quantities, and the discounted present value of these reserves;

• the amount and nature of our capital expenditures;

• our future drilling and development plans and our potential drilling locations;

• the timing and amount of future production and operating costs;

• commodity price risk management activities and the impact on our average realized prices;

• business strategies and plans of management;

• our ability to consummate and efficiently integrate recent acquisitions;

• prospect development and property acquisitions; and

• the expected impact of the Tax Cuts and Jobs Act of 2017.

Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include:

• general economic conditions including the availability of credit and access to existing lines of credit;

• the volatility of oil and natural gas prices;

• the uncertainty of estimates of oil and natural gas reserves;

• risks associated with acquisitions, including liabilities associated with acquired properties or businesses and the ability to realize expected benefits;

• impairments;

• the impact of competition;

• the availability and cost of seismic, drilling and other equipment, water, and personnel;

• operating hazards inherent in the exploration for and production of oil and natural gas;

• difficulties encountered during the exploration for and production of oil and natural gas;

• difficulties encountered in delivering oil and natural gas to commercial markets, including the potential for capacity constraints in pipeline systems;

• changes in customer demand and producers’ supply;

• the uncertainty of our ability to attract capital and obtain financing on favorable terms;

• compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;

• the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells;

• any increase in severance or similar taxes;

• the financial impact of accounting regulations and critical accounting policies;

• the comparative cost of alternative fuels;

• credit risk relating to the risk of loss as a result of non-performance by our counterparties;

• cyberattacks on the Company or on systems and infrastructure used by the oil and gas industry;

• weather conditions; and

• any other factors listed in the reports we have filed and may file with the SEC.

We caution you that the forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto.

Should one or more of the risks or uncertainties described herein or in our 2017 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

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Callon Petroleum Company Management’s Discussion and Analysis of Financial Condition and Results Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our 2017 Annual Report on Form 10-K, which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. Our website address is www.callon.com. All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this report on Form 10-Q.

We are an independent oil and natural gas company established in 1950, focused on the acquisition, development, exploration and exploitation 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. We have historically been focused on the Midland Basin and more recently entered the Delaware Basin through an acquisition completed in February 2017. Our operating culture is centered on responsible development of hydrocarbon resources, with a particular focus on safety and the environment, which we believe strengthens our operational performance. Our operational performance is enhanced by the empowerment of our employees. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. Our production was approximately 77% oil and 23% natural gas for the nine months ended September 30, 2018. On September 30, 2018, our net acreage position in the Permian Basin was approximately 87,000 net acres.

Acquisition Highlights

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 $539.5 million, including customary purchase price adjustments (the “Cimarex Asset Acquisition”). The Company issued debt and equity to fund, in part, the Cimarex Asset Acquisition. See Notes 3, 5, and 10 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions, debt obligations, and equity offerings.

Operational Highlights

All of our producing properties are located in the Permian Basin. As a result of our acquisitions and horizontal development efforts, our production grew 55% and 39% for the three and nine months ended September 30, 2018, compared to the same periods of 2017, respectively. Production increased to 3,212 MBOE for the three months ended September 30, 2018 from 2,074 MBOE for the three months ended September 30, 2017 and increased to 8,238 MBOE for the nine months ended September 30, 2018 from 5,934 MBOE for the nine months ended September 30, 2017.

For the three months ended September 30, 2018, we drilled 19 gross (15.2 net) horizontal wells and completed 19 gross (14.6 net) horizontal wells. For the nine months ended September 30, 2018, we drilled 53 gross (42.2 net) horizontal wells and completed 46 gross (36.3 net) horizontal wells. As of September 30, 2018, we had 12 gross (10.0 net) horizontal wells awaiting completion.

As of September 30, 2018, we had 846 gross (641.6 net) working interest oil wells, three gross (0.1 net) royalty interest oil wells and no natural gas wells. A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas.

Liquidity and Capital Resources

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities, and non-core asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. We continue to evaluate other sources of capital to complement our cash flow from operations and as we pursue our long-term growth plans.

As of September 30, 2018, we had $65 million principal outstanding on our Credit Facility, which had a borrowing base of $1.1 billion with an elected commitment of $850 million. At period ended September 30, 2018, we held cash and cash equivalents of $12.1 million as compared to $28.0 million at year ended December 31, 2017.

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Callon Petroleum Company Management’s Discussion and Analysis of Financial Condition and Results Table of Contents

Liquidity and cash flow

	Nine Months Ended September 30,
(in thousands)	2018			2017
Net cash provided by operating activities	$	316,015		$	149,705
Net cash used in investing activities	(1,043,010		)	(935,584		)
Net cash provided by financing activities	711,129			194,495
Net change in cash and cash equivalents	$	(15,866	)	$	(591,384	)

Operating activities. For the nine months ended September 30, 2018, net cash provided by operating activities was $316.0 million compared to net cash provided by operating activities of $149.7 million for the same period in 2017. The change was predominantly attributable to the following:

• An increase in revenue;

• A decrease on settlements of derivative contracts;

• An increase in certain operating expenses related to acquired properties;  

• An decrease in payments in cash-settled restricted stock unit (“RSU”) awards; and

• A change related to the timing of working capital payments and receipts.

Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 6 and 7 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. 

Investing activities. For the nine months ended September 30, 2018, net cash used in investing activities was $1.0 billion compared to $935.6 million for the same period in 2017. The change was predominantly attributable to the following:

• A $178.9 million increase in operational expenditures due to the transition from a three-rig program in the second quarter 2017 to a five-rig program commencing February 2018; and

• An $80.7 million decrease in acquisition activity, net of proceeds from sale of assets. See Note 3 in the Footnotes to the Financial Statements for additional information on the Company’s acquisitions.

Our investing activities, on a cash basis, include the following for the periods indicated (in thousands):

	Nine Months Ended September 30,
	2018			2017			$ Change
Operational expenditures	$	411,109		$	232,169		$	178,940
Seismic, leasehold and other	7,137			11,379			(4,242		)
Capitalized general and administrative costs	16,544			11,913			4,631
Capitalized interest	20,562			11,757			8,805
Total capital expenditures(a)	455,352			267,218			188,134
Acquisitions	595,984			714,504			(118,520		)
Acquisition deposits	—			(46,138		)	46,138
Proceeds from sale of assets	(8,326		)	—			(8,326		)
Total investing activities	$	1,043,010		$	935,584		$	107,426

(a) On an accrual (GAAP) basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the nine months ended September 30, 2018 were $435.1 million. Inclusive of seismic, leasehold and other, capitalized general and administrative, and capitalized interest costs, total capital expenditures for the nine months ended September 30, 2018 were $500.7 million.

General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Note 3 in the Footnotes to the Financial Statements for additional information on acquisitions.

Financing activities. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility, term debt and equity offerings. For the nine months ended September 30, 2018, net cash provided by financing activities was $711.1 million compared to net cash provided by financing activities of $194.5 million for the same period of 2017. The change was predominantly attributable to the following:

• An increase in proceeds from a common stock offering in 2018 that raised $288.4 million as compared to no offerings in 2017;

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Callon Petroleum Company Management’s Discussion and Analysis of Financial Condition and Results Table of Contents

• A $200.0 million increase in net borrowings on fixed-rate debt, resulting from the issuances of $400 million of 6.375% Senior Notes in 2018 as compared to $200 million of 6.125% Senior Notes in 2017; and

• A $40.0 million increase in net borrowings on our Credit Facility in 2018.

Net cash provided by financing activities includes the following for the periods indicated (in thousands):

	Nine Months Ended September 30, 2018
	2018			2017			$ Change
Net borrowings on senior secured revolving credit facility	$	40,000		$	—		$	40,000
Issuance of 6.125% senior unsecured notes due 2024	—			200,000			(200,000		)
Premium on the issuance of 6.125% senior unsecured notes due 2024	—			8,250			(8,250		)
Issuance of 6.375% senior unsecured notes due 2026	400,000			—			400,000
Issuance of common stock	288,364			—			288,364
Payment of preferred stock dividends	(5,471		)	(5,471		)	—
Payment of deferred financing costs	(9,960		)	(7,166		)	(2,794		)
Tax withholdings related to restricted stock units	(1,804		)	(1,118		)	(686		)
Net cash provided by financing activities	$	711,129		$	194,495		$	516,634

See Notes 5 and 10 in the Footnotes to the Financial Statements for additional information on our debt and equity transactions.

Capital Plan and Year to Date 2018 Summary

Operational capital expenditures, including other items, on an accrual basis were $442.2 million for the nine months ended September 30, 2018. In addition to the operational capital expenditures, $19.9 million of capitalized general and administrative and $38.7 million of capitalized interest expenses were accrued in the nine months ended September 30, 2018. As of September 30, 2018, we have placed 48 gross (36.5 net) horizontal wells on production. Our operational capital budget for 2018 was revised to approximately $560 million.

Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly.

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Callon Petroleum Company Management’s Discussion and Analysis of Financial Condition and Results Table of Contents

Results of Operations

The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated: 

	Three Months Ended September 30,
	2018			2017			Change			% Change
Net production
Oil (MBbls)	2,521			1,591			930			58	%
Natural gas (MMcf)	4,144			2,900			1,244			43	%
Total (MBOE)	3,212			2,074			1,138			55	%
Average daily production (BOE/d)	34,913			22,543			12,370			55	%
% oil (BOE basis)	78		%	77		%
Average realized sales price (excluding impact of settled derivatives):
Oil (Bbl)	$	56.57		$	46.10		$	10.47		23	%
Natural gas (Mcf)	4.49			3.88			0.61			16	%
Total (BOE)	50.19			40.80			9.39			23	%
Average realized sales price (including impact of settled derivatives):
Oil (Bbl)	$	52.87		$	45.24		$	7.63		17	%
Natural gas (Mcf)	4.51			3.94			0.57			14	%
Total (BOE)	47.31			40.21			7.10			18	%
Oil and natural gas revenues (in thousands)
Oil revenue	$	142,601		$	73,349		$	69,252		94	%
Natural gas revenue	18,613			11,265			7,348			65	%
Total	$	161,214		$	84,614		$	76,600		91	%
Additional per BOE data
Sales price (a)	$	50.19		$	40.80		$	9.39		23	%
Lease operating expense (b)	5.77			5.08			0.69			14	%
Gathering and treating expense (c)	—			0.52			(0.52		)	(100	)%
Production taxes	3.20			2.62			0.58			22	%
Operating margin	$	41.22		$	32.58		$	8.64		27	%

(a) Excludes the impact of settled derivatives.

(b) Excludes gathering and treating expense.

(c) On January 1, 2018, the Company adopted the revenue recognition accounting standard. Consequently, natural gas gathering and treating expenses for the three months ended September 30, 2018 were accounted for as a reduction to revenue. See Notes 1 and 2 in the Footnotes to the Financial Statements for additional information regarding revenue recognition and the treatment of gathering and treating expense.

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Callon Petroleum Company Management’s Discussion and Analysis of Financial Condition and Results Table of Contents

	Nine Months Ended September 30,
	2018			2017			Change			% Change
Net production
Oil (MBbls)	6,368			4,621			1,747			38	%
Natural gas (MMcf)	11,222			7,878			3,344			42	%
Total (MBOE)	8,238			5,934			2,304			39	%
Average daily production (BOE/d)	30,176			21,736			8,440			39	%
% oil (BOE basis)	77		%	78		%
Average realized sales price (excluding impact of settled derivatives)
Oil (Bbl)	$	59.75		$	47.23		$	12.52		27	%
Natural gas (Mcf)	4.03			3.81			0.22			6	%
Total (BOE)	51.68			41.84			9.84			24	%
Average realized sales price (including impact of settled derivatives)
Oil (Bbl)	$	55.61		$	46.32		$	9.29		20	%
Natural gas (Mcf)	4.09			3.84			0.25			7	%
Total (BOE)	48.56			41.17			7.39			18	%
Oil and natural gas revenues (in thousands)
Oil revenue	$	380,500		$	218,242		$	162,258		74	%
Natural gas revenue	45,229			30,019			15,210			51	%
Total	$	425,729		$	248,261		$	177,468		71	%
Additional per BOE data
Sales price (a)	$	51.68		$	41.84		$	9.84		24	%
Lease operating expense (b)	5.43			5.72			(0.29		)	(5	)%
Gathering and treating expense (c)	—			0.47			(0.47		)	(100	)%
Production taxes	3.19			2.72			0.47			17	%
Operating margin	$	43.06		$	32.93		$	10.13		31	%

(a) Excludes the impact of settled derivatives.

(b) Excludes gathering and treating expense.

(c) On January 1, 2018, the Company adopted the revenue recognition accounting standard. Consequently, natural gas gathering and treating expenses for the nine months ended September 30, 2018 were accounted for as a reduction to revenue. See Notes 1 and 2 in the Footnotes to the Financial Statements for additional information regarding revenue recognition and the treatment of gathering and treating expense.

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Callon Petroleum Company Management’s Discussion and Analysis of Financial Condition and Results Table of Contents

Revenues

The following tables reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices.

(in thousands)	Oil		Natural Gas		Total
Revenues for the three months ended September 30, 2017	$	73,349	$	11,265	$	84,614
Volume increase	42,873		4,827		47,700
Price increase	26,379		2,521		28,900
Net increase	69,252		7,348		76,600
Revenues for the three months ended September 30, 2018	$	142,601	$	18,613	$	161,214

(in thousands)	Oil		Natural Gas		Total
Revenues for the nine months ended September 30, 2017	$	218,242	$	30,019	$	248,261
Volume increase	82,511		12,741		95,252
Price increase	79,747		2,469		82,216
Net increase	162,258		15,210		177,468
Revenues for the nine months ended September 30, 2018	$	380,500	$	45,229	$	425,729

Commodityprices

The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by the Organization of Petroleum Exporting Countries and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business:

• our revenues, cash flows and earnings;

• the amount of oil and natural gas that we are economically able to produce;

• our ability to attract capital to finance our operations and cost of the capital;

• the amount we are allowed to borrow under our Credit Facility; and

• the value of our oil and natural gas properties.

For the three and nine months ended September 30, 2018, the average NYMEX price for a barrel of oil was $69.43 and $66.77 per Bbl compared to $48.20 and $49.36 per Bbl for the same period of 2017. The NYMEX price for a barrel of oil for the three and nine months ended September 30, 2018 ranged from a low of $65.01 per Bbl to a high of $74.14 per Bbl and a low of $59.19 per Bbl to a high of $74.15 per Bbl, respectively.

For the three and nine months ended September 30, 2018, the average NYMEX price for natural gas was $2.87 and $2.85 per MMBtu compared to $2.95 and $3.05 per MMBtu for the same periods of 2017. The NYMEX price for natural gas for the three and nine months ended September 30, 2018 ranged from a low of $2.72 per MMBtu to a high of $3.08 per MMBtu and a low of $2.55 per MMBtu to a high of $3.63 per MMBtu, respectively.

Oil revenue 

For the three months ended September 30, 2018, oil revenues of $142.6 millionincreased$69.3 million, or 94%, compared to revenues of $73.3 million for the same period of 2017. The increase in oil revenue was primarily attributable to a 58%increase in production and a 23%increase in the average realized sales price, which rose to $56.57 per Bbl from $46.10 per Bbl. The production increase of 930 MBbls was a result of new wells placed on production from our horizontal drilling program, as well as volumes contributed by newly acquired properties. Offsetting these increases were normal and expected declines from our existing wells.

For the nine months ended September 30, 2018, oil revenues of $380.5 millionincreased$162.3 million, or 74%, compared to revenues of $218.2 million for the same period of 2017. The increase in oil revenue was primarily attributable to a 38%increase in production and a 27%increase in the average realized sales price, which rose to $59.75 per Bbl from $47.23 per Bbl. The production increase of 2,774 MBbls was a result of new wells placed on production from our horizontal drilling program, as well as volumes contributed by newly acquired properties. Offsetting these increases were normal and expected declines from our existing wells.

See Note 3 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.

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Callon Petroleum Company Management’s Discussion and Analysis of Financial Condition and Results Table of Contents

Natural gas revenue (including NGLs)

For the three months ended September 30, 2018, natural gas revenues of $18.6 million increased $7.3 million, or 65%, compared to $11.3 million for the same period of 2017. The increase primarily relates to a 43% increase in natural gas volumes and a 16% increase in the average realized sales price, which rose to $4.49 per Mcf from $3.88 per Mcf, reflecting both natural gas and natural gas liquids prices. The production increase of 1,244 MMcf was a result of new wells placed on production from our horizontal drilling program, as well as volumes contributed by newly acquired properties. Offsetting these increases were normal and expected declines from our existing wells. Natural gas revenues for the three months ended September 30, 2018, include a reduction of $2.2 million of gathering and treating expense.

For the nine months ended September 30, 2018, natural gas revenues of $45.2 million increased $15.2 million, or 51%, compared to $30.0 million for the same period of 2017. The increase primarily relates to a 42% increase in natural gas volumes. The production increase of 3,344 MMcf was a result of new wells placed on production from our horizontal drilling program, as well as volumes contributed by newly acquired properties. The average realized sales price of $4.03 per Mcf, reflecting both natural gas and natural gas liquids prices, was consistent with prices for the same period of 2017. Offsetting these increases were normal and expected declines from our existing wells. Natural gas revenues for the nine months ended September 30, 2018, include a reduction of $5.4 million of gathering and treating expense.

See Notes 1, 2 and 3 in the Footnotes to the Financial Statements for additional information regarding revenue recognition and the treatment of gathering and treating expense and the Company’s acquisitions, respectively.

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Callon Petroleum Company Management’s Discussion and Analysis of Financial Condition and Results Table of Contents

Operating Expenses

	Three Months Ended September 30,
			Per				Per		Total Change				BOE Change
(in thousands, except per unit amounts)	2018		BOE		2017		BOE		$		%		$			%
Lease operating expenses (a)	$	18,525	$	5.77	$	11,624	$	5.60	$	6,901	59	%	$	0.17		3	%
Production taxes	10,263		3.20		5,444		2.62		4,819		89	%	0.58			22	%
Depreciation, depletion and amortization	48,257		15.02		28,525		13.75		19,732		69	%	1.27			9	%
General and administrative	9,721		3.03		7,259		3.50		2,462		34	%	(0.47		)	(13	)%
Accretion expense	202		0.06		131		0.06		71		54	%	—			—	%
Acquisition expense	1,435		0.45		205		0.10		1,230		600	%	0.35			350	%

	Nine Months Ended September 30,
			Per				Per		Total Change					BOE Change
(in thousands, except per unit amounts)	2018		BOE		2017		BOE		$			%		$			%
Lease operating expenses (a)	$	44,705	$	5.43	$	36,708	$	6.19	$	7,997		22	%	$	(0.76	)	(12	)%
Production taxes	26,265		3.19		16,168		2.72		10,097			62	%	0.47			17	%
Depreciation, depletion and amortization	122,407		14.86		79,172		13.34		43,235			55	%	1.52			11	%
General and administrative	26,779		3.25		18,894		3.18		7,885			42	%	0.07			2	%
Settled share-based awards	—		—		6,351		1.07		(6,351		)	(100	)%	(1.07		)	(100	)%
Accretion expense	626		0.08		523		0.09		103			20	%	(0.01		)	(11	)%
Acquisition expense	3,750		0.46		3,027		0.51		723			24	%	(0.05		)	(10	)%

(a) On January 1, 2018, the Company adopted the revenue recognition accounting standard. Consequently, natural gas gathering and treating expenses for the three and nine months ended September 30, 2018 were accounted for as a reduction to revenue. See Notes 1 and 2 in the Footnotes to the Financial Statements for additional information regarding revenue recognition and the treatment of gathering and treating expense.

Lease operating expenses (“LOE”). These are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs also include maintenance, repairs, salt water disposal, insurance and workover expenses related to our oil and natural gas properties. 

For the three months ended September 30, 2018, LOE increased by 59% to $18.5 million compared to $11.6 million for the same period of 2017. For the three months ended September 30, 2018, LOE per BOE increased to $5.77 per BOE, excluding gathering and treating expense, compared to $5.60 per BOE, including $0.52 per BOE of gathering and treating expense, for the same period of 2017, which was primarily attributable to an increase in costs from workover activity on our properties offset by higher production volumes. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above. See Notes 1 and 2 in the Footnotes to the Financial Statements for additional information regarding revenue recognition and the treatment of gathering and treating expense.

For the nine months ended September 30, 2018, LOE increased by 22% to $44.7 million compared to $36.7 million for the same period of 2017. For the nine months ended September 30, 2018, LOE per BOE decreased to $5.43 per BOE, excluding gathering and treating expense, compared to $6.19 per BOE, including $0.47 per BOE of gathering and treating expense, for the same period of 2017, which was primarily attributable to higher production volumes from an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above. See Notes 1 and 2 in the Footnotes to the Financial Statements for additional information regarding revenue recognition and the treatment of gathering and treating expense.

Production taxes. Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, severance taxes are based upon current year commodity prices, whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties. 

Production taxes for the three months ended September 30, 2018increased by 89% to $10.3 million compared to $5.4 million for the same period of 2017. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in revenue. On a per BOE basis, production taxes for the three months ended September 30, 2018increased by 22% compared to the same period of 2017.

Production taxes for the nine months ended September 30, 2018increased by 62% to $26.3 million compared to $16.2 million for the same period of 2017. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in

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Callon Petroleum Company Management’s Discussion and Analysis of Financial Condition and Results Table of Contents

revenue. Also contributing to the increase was an increase in ad valorem taxes, which was attributable to an increase in the valuation of our oil and gas properties by taxing jurisdictions as a result of an increased number of producing wells from our horizontal drilling program, and acquisitions as discussed above. On a per BOE basis, production taxes for the nine months ended September 30, 2018increased by 17% compared to the same period of 2017.

Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.

For the three months ended September 30, 2018, DD&A increased69% to $48.3 million compared to $28.5 million for the same period of 2017. The increase is primarily attributable to a 55%increase in production and a 9% increase in our per BOE DD&A rate. For the three months ended September 30, 2018, DD&A on a per unit basis increased to $15.02 per BOE compared to $13.75 per BOE for the same period of 2017. The increase is attributable to greater increases in our depreciable base and assumed future development costs to undeveloped proved reserves relative to the increase in our estimated proved reserve base. The increases in our depreciable base, assumed future development costs and estimated proved reserve base are a result of additions made through our horizontal drilling efforts and acquisitions.

For the nine months ended September 30, 2018, DD&A increased55% to $122.4 million compared to $79.2 million for the same period of 2017. The increase is primarily attributable to a 39%increase in production and an 11% increase in our per BOE DD&A rate. For the nine months ended September 30, 2018, DD&A on a per unit basis increased to $14.86 per BOE compared to $13.34 per BOE for the same period of 2017. The increase is attributable to greater increases in our depreciable base and assumed future development costs to undeveloped proved reserves relative to the increase in our estimated proved reserve base. The increases in our depreciable base, assumed future development costs and estimated proved reserve base are a result of additions made through our horizontal drilling efforts and acquisitions.

General and administrative, net of amounts capitalized (“G&A”). These are costs incurred for overhead, including payroll and benefits for our corporate staff, severance and early retirement expenses, costs of maintaining offices, managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance.

G&A for the three months ended September 30, 2018increased to $9.7 million compared to $7.3 million for the same period of 2017. The increase is primarily attributable to non-cash compensation and the corresponding rise in personnel costs due to the growth in our operating activities. G&A expenses for the periods indicated include the following (in thousands):

	Three Months Ended September 30,
	2018		2017		$ Change		% Change
Recurring expenses
G&A	$	7,070	$	5,330	$	1,740	33	%
Share-based compensation	1,730		1,198		532		44	%
Fair value adjustments of cash-settled RSU awards	921		731		190		26	%
Total G&A expenses	$	9,721	$	7,259	$	2,462	34	%

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G&A for the nine months ended September 30, 2018increased to $26.8 million compared to $18.9 million for the same period of 2017. The increase is primarily attributable to non-cash compensation and the corresponding rise in personnel costs due to the growth in our operating activities. G&A expenses for the periods indicated include the following (in thousands):

	Nine Months Ended September 30,
	2018		2017			$ Change			% Change
Recurring expenses
G&A	$	20,929	$	15,428		$	5,501		36	%
Share-based compensation	4,422		3,084			1,338			43	%
Fair value adjustments of cash-settled RSU awards	1,428		(143		)	1,571			(1,099	)%
Non-recurring expenses
Early retirement expenses	—		444			(444		)	(100	)%
Early retirement expenses related to share-based compensation	—		81			(81		)	(100	)%
Total G&A expenses	$	26,779	$	18,894		$	7,885		42	%

Settled share-based awards. In June 2017, the Company settled the outstanding share-based award agreements of its former Chief Executive Officer, resulting in $6.4 million recorded on the Consolidated Statements of Operations as Settled share-based awards.

Accretion expense. The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated ARO costs. Interest is accreted on the present value of the ARO and reported as accretion expense within operating expenses in the consolidated statements of operations.

Accretion expense related to our ARO for the three and nine months ended September 30, 2018, increased54% and 20%, compared to the same periods of 2017, respectively. Accretion expense generally correlates with the Company’s ARO, which was $9.9 million at September 30, 2018 as compared to $5.0 million at September 30, 2017. See Note 9 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO.

Acquisition expense. Acquisition expense increased$1.2 million and $0.7 million for the three and nine months ended September 30, 2018, compared to the same periods of 2017. Acquisition expense for all periods was related to costs with respect to our acquisition efforts in the Permian Basin. See Note 3 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.

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Other Income and Expenses and Preferred Stock Dividends

	Three Months Ended September 30,
(in thousands)	2018			2017			$ Change			% Change
Interest expense, net of capitalized amounts	$	711		$	444		$	267		60	%
Loss on derivative contracts	34,339			14,162			20,177			142	%
Other income	(1,657		)	(498		)	(1,159		)	233	%
Total other (income) expense	$	33,393		$	14,108
Income tax expense	$	1,487		$	237		$	1,250		527	%
Preferred stock dividends	(1,823		)	(1,824		)	1			—	%

	Nine Months Ended September 30,
(in thousands)	2018			2017			$ Change			% Change
Interest expense, net of capitalized amounts	$	1,765		$	1,698		$	67		4	%
(Gain) loss on derivative contracts	55,374			(11,636		)	67,010			(576	)%
Other income	(2,571		)	(1,270		)	(1,301		)	102	%
Total other (income) expense	$	54,568		$	(11,208	)
Income tax expense	$	2,463		$	1,026		$	1,437		140	%
Preferred stock dividends	(5,471		)	(5,471		)	—			—	%

Interest expense, net of capitalized amounts. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense. Interest expense, net of capitalized amounts, of $0.7 million and $1.8 million incurred during the three and nine months ended September 30, 2018, remained consistent compared to the same periods of 2017.

Gain (loss) on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period.

For the three months ended September 30, 2018, we recorded a net loss on derivative contracts of $34.3 million as compared to a net loss of $14.2 million for the same period of 2017. The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands):

	Three Months Ended September 30,
	2018			2017
Oil derivatives
Net loss on settlements	$	(9,306	)	$	(1,373	)
Net loss on fair value adjustments	(24,476		)	(12,811		)
Total loss on oil derivatives	$	(33,782	)	$	(14,184	)
Natural gas derivatives
Net gain on settlements	$	67		$	159
Net loss on fair value adjustments	(624		)	(137		)
Total gain (loss) on natural gas derivatives	$	(557	)	$	22
Total loss on oil & natural gas derivatives	$	(34,339	)	$	(14,162	)

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For the nine months ended September 30, 2018, we recorded a net loss on derivative contracts of $55.4 million compared to a net gain of $11.6 million for the same period of 2017. The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands):

	Nine Months Ended September 30,
	2018			2017
Oil derivatives
Net loss on settlements	$	(26,353	)	$	(4,213	)
Net gain (loss) on fair value adjustments	(28,720		)	14,584
Total gain (loss) on oil derivatives	$	(55,073	)	$	10,371
Natural gas derivatives
Net gain on settlements	$	675		$	241
Net gain (loss) on fair value adjustments	(976		)	1,024
Total gain (loss) on natural gas derivatives	$	(301	)	$	1,265
Total gain (loss) on oil & natural gas derivatives	$	(55,374	)	$	11,636

See Notes 6 and 7 in the Footnotes to the Financial Statements for additional information on the Company’s derivative contracts and disclosures related to derivative instruments.

Income tax expense.We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate, based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized.

The Company had income tax expense of $1.5 million and $2.5 million for the three and nine months ended September 30, 2018, compared to income tax expense of $0.2 million and $1.0 million for the same periods of 2017. The change in income tax expense is primarily related to deferred state of Texas gross margin tax. The Company had a valuation allowance of $30.3 million as of September 30, 2018. See Note 8 in the Footnotes to the Financial Statements for additional information.

Preferred Stock dividends. Preferred Stock dividends of $1.8 million and $5.5 million for the three and nine months ended September 30, 2018 were consistent with dividends for the same periods of 2017. Dividends reflect a 10% dividend rate. See Note 10 in the Footnotes to the Financial Statements for additional information.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We mitigate these risks through a program of risk management including the use of derivative instruments.

Commodity price risk

The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, demand, regional market conditions, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and natural gas price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we hedge through use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 40% to 60% of our anticipated internally forecast production, subject to market conditions, for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices, in addition to modification of our capital spending plans related to operational activities and acquisitions.

The Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approximately 1,794,000 Bbls and 1,932,000 MMBtu of our expected oil and natural gas production, respectively, for the remainder of 2018. We also have commodity hedging contracts linked to Midland WTI basis differentials relative to Cushing and Waha basis differentials covering approximately 1,518,000 Bbls and 552,000 MMBtu of our expected oil and natural gas production, respectively, for the remainder of 2018. See Note 6 in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at September 30, 2018, and any derivative contracts established subsequent to that date.

The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales.

The Company may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company may sell put (or call) options at a price lower than the floor price (or higher than the ceiling price) in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), the Company’s net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis.

The Company may purchase put and call options, which reduce the Company’s exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to the Company.

The Company enters into these various agreements to reduce the effects of volatile oil and natural gas prices and does not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as hedges for accounting purposes.

Interest rate risk

The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of September 30, 2018, the Company had $65.0 million principal outstanding under the Credit Facility with a weighted average interest rate of 3.29%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $0.7 million, based on the balance outstanding at September 30, 2018. See Note 5 in the Footnotes to the Financial Statements for more information on the Company’s interest rates on its Credit Facility.

Counterparty and customer credit risk

The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts.

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The Company markets its oil and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. At September 30, 2018 our total receivables from the sale of our oil and natural gas production were approximately $107.3 million.

Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At September 30, 2018 our joint interest receivables were approximately $59.5 million.

Our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.  

Item 4. Controls and Procedures

Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2018.

Changes in internal control over financial reporting. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II.  Other Information

Item 1.  Legal Proceedings

We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our financial position or results of operations.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2017, and the risk factors and other cautionary statements contained in our other SEC filings, including our Quarterly Report on Form 10-Q for the period ended June 30, 2018, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our Annual Report or our other SEC filings.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.  Defaults Upon Senior Securities

None.

Item 4.  Mine Safety Disclosures

None.

Item 5.  Other Information

None.

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Item 6.  Exhibits

The following exhibits are filed as part of this Form 10-Q.

Exhibit Number			Description
2.			Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
	2.1		Purchase and Sale Agreement, dated May 23, 2018, between Cimarex Energy Co, Prize Energy Resources, Inc., and Magnum Hunter Production, Inc. and Callon Petroleum Operating Company (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed on May 24, 2018)
3.			Articles of Incorporation and By-Laws
	3.1		Certificate of Incorporation of the Company, as amended through May 12, 2016 (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q, filed on November 3, 2016)
	3.2		Certificate of Designation of Rights and Preferences of 10.00% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5 of the Company’s Form 8-A, filed on May 23, 2013)
	3.3		Bylaws of the Company (incorporated by reference to Exhibit 3.3 of the Company’s Form 10-K, filed on February 28, 2018)
4.			Instruments defining the rights of security holders, including indentures
	4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of the Company’s Form 10-K, filed on February 28, 2018)
	4.2		Certificate for the Company’s 10.00% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-A, filed on May 23, 2013)
	4.3		Registration Rights Agreement, dated May 26, 2016, among Callon Petroleum Company and each of the Persons set forth on Schedule A therein (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on May 31, 2016)
	4.4		Indenture of 6.125% Senior Notes Due 2024, dated as of October 3, 2016, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed on October 4, 2016)
	4.5		Indenture of 6.375% Senior Notes Due 2026, dated as of June 7, 2018, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed on June 7, 2018)
	4.6		Registration Rights Agreement of 6.375% Senior Notes Due 2026, dated June 7, 2018, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K, filed on June 7, 2018)
10.			Material contracts
	10.1		Amendment No. 2 to the Sixth Amended and Restated Credit Agreement, dated September 27, 2018, among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on September 28, 2018)
31.			Section 13a-14 Certifications
	31.1	(a)	Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)
	31.2	(a)	Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
32.		(b)	Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b)
101.		(c)	Interactive Data Files

(a) Filed herewith.

(b) Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.

(c) Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Callon Petroleum Company

Signature	Title	Date
/s/ Joseph C. Gatto, Jr.	President and	November 6, 2018
Joseph C. Gatto, Jr.	Chief Executive Officer

/s/ James P. Ulm, II	Senior Vice President and	November 6, 2018
James P. Ulm, II	Chief Financial Officer

38

EX-31.1

Exhibit31.1

CERTIFICATIONS

I, Joseph C. Gatto, Jr., certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Callon Petroleum Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 6, 2018	/s/ Joseph C. Gatto, Jr.
		Joseph C. Gatto, Jr.
		President and Chief Executive Officer
		(Principal executive officer)

EX-31.2

Exhibit31.2

CERTIFICATIONS

I, James P. Ulm, II, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Callon Petroleum Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 6, 2018	/s/ James P. Ulm, II
		James P. Ulm, II
		Senior Vice President and Chief Financial Officer
		(Principal financial officer)

EX-32

Exhibit32

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Quarterly Report on Form 10-Q of Callon Petroleum Company for the quarterly period ended September 30, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacities and on the dates indicated below, each hereby certify pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Report fully complies with requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 6, 2018	/s/ Joseph C. Gatto, Jr.
		Joseph C. Gatto, Jr.
		(Principal executive officer)
Date:	November 6, 2018	/s/ James P. Ulm, II
		James P. Ulm, II
		(Principal financial officer)

The foregoing certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 02, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	CALLON PETROLEUM CO
Entity Central Index Key	0000928022
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		227,581,223

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Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 12,129	$ 27,995
Accounts receivable	168,753	114,320
Fair value of derivatives	4,289	406
Other current assets	3,804	2,139
Total current assets	188,975	144,860
Oil and natural gas properties, full cost accounting method:
Evaluated properties	4,305,189	3,429,570
Less accumulated depreciation, depletion, amortization and impairment	(2,208,066)	(2,084,095)
Net evaluated oil and natural gas properties	2,097,123	1,345,475
Unevaluated properties	1,385,529	1,168,016
Total oil and natural gas properties	3,482,652	2,513,491
Other property and equipment, net	21,738	20,361
Restricted investments	3,413	3,372
Deferred tax asset	0	52
Deferred financing costs	6,406	4,863
Acquisition deposit	0	900
Other assets, net	5,552	5,397
Total assets	3,708,736	2,693,296
Current liabilities:
Accounts payable and accrued liabilities	251,754	162,878
Accrued interest	27,325	9,235
Cash-settleable restricted stock unit awards	2,422	4,621
Asset retirement obligations	4,464	1,295
Fair value of derivatives	47,167	27,744
Total current liabilities	333,132	205,773
Senior secured revolving credit facility	65,000	25,000
Asset retirement obligations	5,428	4,725
Cash-settleable restricted stock unit awards	2,818	3,490
Deferred tax liability	3,917	1,457
Fair value of derivatives	15,440	1,284
Other long-term liabilities	6,165	405
Total liabilities	1,420,428	837,330
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; 227,567,936 and 201,836,172 shares outstanding, respectively	2,276	2,018
Capital in excess of par value	2,474,748	2,181,359
Accumulated deficit	(188,731)	(327,426)
Total stockholders’ equity	2,288,308	1,855,966
Total liabilities and stockholders’ equity	3,708,736	2,693,296
6.125% senior unsecured notes due 2024
Current liabilities:
Senior unsecured notes, net of unamortized deferred financing costs	595,729	595,196
6.375% senior unsecured notes due 2026
Current liabilities:
Senior unsecured notes, net of unamortized deferred financing costs	$ 392,799	$ 0

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2018	Dec. 31, 2017
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)	227,567,936	201,836,172
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)	$ 50.00	$ 50.00
Preferred stock, shares authorized (in shares)	2,500,000	2,500,000
Preferred stock, shares outstanding (in shares)	1,458,948	1,458,948

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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating revenues:
Total operating revenues	$ 161,214	$ 84,614	$ 425,729	$ 248,261
Operating expenses:
Lease operating expenses	18,525	11,624	44,705	36,708
Production taxes	10,263	5,444	26,265	16,168
Depreciation, depletion and amortization	48,257	28,525	122,407	79,172
General and administrative	9,721	7,259	26,779	18,894
Settled share-based awards	0	0	0	6,351
Accretion expense	202	131	626	523
Acquisition expense	1,435	205	3,750	3,027
Total operating expenses	88,403	53,188	224,532	160,843
Income from operations	72,811	31,426	201,197	87,418
Other (income) expenses:
Interest expense, net of capitalized amounts	711	444	1,765	1,698
(Gain) loss on derivative contracts	34,339	14,162	55,374	(11,636)
Other income	(1,657)	(498)	(2,571)	(1,270)
Total other (income) expense	33,393	14,108	54,568	(11,208)
Income before income taxes	39,418	17,318	146,629	98,626
Income tax expense	1,487	237	2,463	1,026
Net income	37,931	17,081	144,166	97,600
Preferred stock dividends	(1,823)	(1,824)	(5,471)	(5,471)
Income available to common stockholders	$ 36,108	$ 15,257	$ 138,695	$ 92,129
Income per common share:
Basic (in dollars per share)	$ 0.16	$ 0.08	$ 0.65	$ 0.46
Diluted (in dollars per share)	$ 0.16	$ 0.08	$ 0.65	$ 0.46
Shares used in computing income per common share:
Basic (in shares)	227,564	201,827	213,409	201,422
Diluted (in shares)	228,140	202,337	214,079	201,995
Oil sales
Operating revenues:
Total operating revenues	$ 142,601	$ 73,349	$ 380,500	$ 218,242
Natural gas sales
Operating revenues:
Total operating revenues	$ 18,613	$ 11,265	$ 45,229	$ 30,019

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities:
Net income	$ 144,166	$ 97,600
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	124,430	80,829
Accretion expense	626	523
Amortization of non-cash debt related items	1,749	1,695
Deferred income tax expense	2,463	1,026
Net (gain) loss on derivatives, net of settlements	29,696	(15,608)
(Gain) loss on sale of other property and equipment	(80)	62
Non-cash expense related to equity share-based awards	4,466	7,014
Change in the fair value of liability share-based awards	1,428	2,423
Payments to settle asset retirement obligations	(1,080)	(1,831)
Changes in current assets and liabilities:
Accounts receivable	(54,384)	(12,148)
Other current assets	(1,665)	(336)
Current liabilities	64,801	7,534
Other long-term liabilities	5,787	121
Long-term prepaid	0	(4,650)
Other assets, net	(1,398)	(1,376)
Payments to settle vested liability share-based awards	(4,990)	(13,173)
Net cash provided by operating activities	316,015	149,705
Cash flows from investing activities:
Capital expenditures	(455,352)	(267,218)
Acquisitions	(595,984)	(714,504)
Acquisition deposit	0	46,138
Proceeds from sale of assets	8,326	0
Net cash used in investing activities	(1,043,010)	(935,584)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	270,000	0
Payments on senior secured revolving credit facility	(230,000)	0
Issuance of common stock	288,364	0
Premium on the issuance of 6.125% senior unsecured notes due 2024	0	8,250
Payment of preferred stock dividends	(5,471)	(5,471)
Payment of deferred financing costs	(9,960)	(7,166)
Tax withholdings related to restricted stock units	(1,804)	(1,118)
Net cash provided by financing activities	711,129	194,495
Net change in cash and cash equivalents	(15,866)	(591,384)
Balance, beginning of period	27,995	652,993
Balance, end of period	12,129	61,609
6.125% senior unsecured notes due 2024
Cash flows from financing activities:
Issuance of senior unsecured notes	0	200,000
6.375% senior unsecured notes due 2026
Cash flows from financing activities:
Issuance of senior unsecured notes	$ 400,000	$ 0

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Consolidated Statements of Cash Flows (Parenthetical)	Sep. 30, 2018	May 19, 2017
6.125% senior unsecured notes due 2024
Debt instrument, interest rate, stated (as a percent)	6.125%	6.125%
6.375% senior unsecured notes due 2026
Debt instrument, interest rate, stated (as a percent)	6.375%

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Description of Business and Basis of Presentation

9 Months Ended

Sep. 30, 2018

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 is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. 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.

Callon is focused on the acquisition, development, exploration and exploitation of unconventional onshore, oil and natural gas reserves in the Permian Basin. The Company’s operations to date have been predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on its existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. 

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 subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc.

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, 2017. The balance sheet at December 31, 2017 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, 2018.

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, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts may have been reclassified to conform to current year presentation.

Accounting Standards Updates (“ASUs”)

Recently Adopted ASUs - Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 replaced most of the existing revenue recognition requirements in GAAP.

Throughout 2015 and 2016, the FASB issued several updates to the revenue recognition guidance in Accounting Standards Codification Topic 606 (“ASC 606”). In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers - Principal versus Agent Considerations (Reporting Revenue Gross versus Net). Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers - Identifying Performance Obligations and Licensing. This update clarifies two principles of ASC 606: identifying performance obligations and the licensing implementation guidance. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients. This update applies only to the following areas from ASC 606: assessing the collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar taxes collected from customers, non-cash consideration, contract modification at transition, completed contracts at transition and technical correction.

Prior to the adoption of ASC 606, gathering and treating fees associated with our gas processing agreements have historically been presented within lease operating expenses in the statement of operations. The current period presentation reports these fees as a reduction to natural gas revenues. See Note 2 for additional information on revenue recognition.

The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption and the impact of adoption on the current period statement of operations is as follows:

	Three Months Ended September 30, 2018
	As reported		Adjustments		Presentation without adoption of ASC Topic 606
Operating revenues:
Natural gas sales	$	18,613	$	2,209	$	20,822
Total operating revenues	161,214		2,209		163,423
Operating expenses:
Lease operating expenses	$	18,525	$	2,209	$	20,734
Total operating expenses	88,403		2,209		90,612

	Nine Months Ended September 30, 2018
	As reported		Adjustments		Presentation without adoption of ASC Topic 606
Operating revenues:
Natural gas sales	$	45,229	$	5,413	$	50,642
Total operating revenues	425,729		5,413		431,142
Operating expenses:
Lease operating expenses	$	44,705	$	5,413	$	50,118
Total operating expenses	224,532		5,413		229,945

Recently adopted ASUs - Other

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. The Company adopted this update on January 1, 2018 and it did not have a material impact on its consolidated financial statements.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations-Clarifying the Definition of a Business (“ASU 2017-01”). The guidance in ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The guidance in ASU 2017-01 is effective for annual reporting periods beginning after December 15, 2017, including interim periods therein. The Company adopted this update effective January 1, 2018. The adoption of this update did not have a material impact on its consolidated financial statements.

Recently issued 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”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”).

ASC Topic 842 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under Topic 840. The Company has engaged a third party consultant to assist with its current process of assessing existing contracts, as well as future potential contracts, and to determine the impact of applying Topic 842 on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, field vehicles and equipment, office facility leases, compressors, general corporate leased equipment, and other existing arrangements that may contain a lease component. The Company will adopt this guidance as of January 1, 2019, the transition date, using a modified retrospective method with use of the transition option, in which a cumulative-effect adjustment will be recognized in the opening balance of retained earnings in the period of adoption.  The Company expects the adoption of ASC Topic 842 to primarily impact the asset and liability balances on the balance sheet and will result in changes to the timing and presentation of certain operating expenses on its consolidated statement of operations.

Recently issued 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 guidance in ASU 2018-06 is effective for public entities for annual reporting periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted, but no earlier than an entity’s adoption date of Topic 606. The Company does not expect a material impact on its consolidated financial statements upon adoption of this guidance.

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Revenue Recognition

9 Months Ended

Sep. 30, 2018

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 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 revenues. For the three and nine months ended September 30, 2018, $2,209 and $5,413 of gathering and treating fees were recognized and recorded as a reduction to natural gas revenues in the consolidated statement of operations, respectively. For the three and nine months ended September 30, 2017, $909 and $2,393 of gathering and treating fees were recognized and recorded as part of lease operating expense in the consolidated statement of operations, respectively.

Production imbalances

Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer applicable. In conjunction with the Company’s adoption of the new revenue recognition accounting standards, there was no material impact to the financial statements due to this change in accounting for its production imbalances.

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.

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Acquisitions

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

Acquisitions

Acquisitions 

Acquisitions were accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed under the income approach.

2018 Acquisitions

During the first quarter of 2018, the Company completed acquisitions of additional working interests and acreage in the Company’s existing core operating areas of Monarch and Wildhorse, located in the Permian Basin, for an aggregate total purchase price of approximately $35,900 excluding customary purchase price adjustments.

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 “Cimarex Asset Acquisition”). The Company issued debt and equity to fund, in part, the Cimarex Asset Acquisition. See Notes 5 and 10 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

The preliminary purchase price allocations are subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material.

2017Acquisitions

On February 13, 2017, the Company completed the acquisition of 29,175 gross (16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for $646,559 excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company obtained an 82% average working interest (75% average net revenue interest) in the properties acquired in the Ameredev Transaction.

The following table summarizes the estimated acquisition date fair values of the acquisition:

Evaluated oil and natural gas properties	$	137,368
Unevaluated oil and natural gas properties	509,359
Asset retirement obligations	(168		)
Net assets acquired	$	646,559

On June 5, 2017, the Company completed the acquisition of 7,031 gross (2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for $52,500 excluding customary purchase price adjustments. The Company funded the cash purchase price with its available cash and proceeds from the issuance of an additional $200,000 of its 6.125% senior notes due 2024 (see Note 5 for additional information regarding the Company’s debt obligations).

Unaudited pro forma financial statements

The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Cimarex Asset Acquisition and Ameredev Transaction had occurred as presented, or to project the Company’s results of operations for any future periods:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		(a)	2017		(a)	2018		(a)	2017		(a)
Revenues	$	181,880		$	107,966		$	506,864		$	326,357
Income from operations	82,057			42,556			238,776			124,005
Income available to common stockholders	44,703			26,387			175,623			128,716
Net income per common share:
Basic	$	0.20		$	0.13		$	0.82		$	0.64
Diluted	$	0.20		$	0.13		$	0.82		$	0.64

(a) The pro forma financial information was prepared assuming the Cimarex Asset Acquisition and the Ameredev Transaction occurred as of January 1, 2017.

The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest.

The properties associated with the Cimarex Asset Acquisition and Ameredev Transaction have been commingled with the Company’s existing properties and it is impractical to provide the stand-alone operational results related to these properties.

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Earnings Per Share

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Earnings Per Share

EarningsPer Share

The following table sets forth the computation of basic and diluted earnings per share:

(share amounts in thousands)	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net income	$	37,931		$	17,081		$	144,166		$	97,600
Preferred stock dividends	(1,823		)	(1,824		)	(5,471		)	(5,471		)
Income available to common stockholders	$	36,108		$	15,257		$	138,695		$	92,129
Weighted average shares outstanding	227,564			201,827			213,409			201,422
Dilutive impact of restricted stock	576			510			670			573
Weighted average shares outstanding for diluted income per share	228,140			202,337			214,079			201,995
Basic income per share	$	0.16		$	0.08		$	0.65		$	0.46
Diluted income per share	$	0.16		$	0.08		$	0.65		$	0.46
Restricted stock (a)	154			51			154			51

(a) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

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Borrowings

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Borrowings

Borrowings

The Company’s borrowings consisted of the following at:

	September 30, 2018			December 31, 2017
Principal components:
Senior secured revolving credit facility	$	65,000		$	25,000
6.125% senior unsecured notes due 2024	600,000			600,000
6.375% senior unsecured notes due 2026	400,000			—
Total principal outstanding	1,065,000			625,000
Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization	6,750			7,594
Unamortized deferred financing costs	(18,222		)	(12,398		)
Total carrying value of borrowings	$	1,053,528		$	620,196

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 with a maturity date of May 25, 2022. 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.

Effective April 5, 2018, the Company entered into the first amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $825,000, (2) increased the elected commitment amount to $650,000, (3) decreased the applicable margins for interest rates, based on utilization, to a range of 1.25% to 2.25%, and (4) extended the maturity date to May 25, 2023.

Effective September 27, 2018, the Company entered into the second amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $1,100,000, (2) increase the elected commitment amount to $850,000, and (3) amended various covenants and terms to reflect current market trends. As of September 30, 2018, the Credit Facility’s borrowing base remained at $1,100,000 with an elected commitment amount of $850,000.

As of September 30, 2018, there was $65,000 principal and $17,675 in letters of credit outstanding under the Credit Facility. For the quarter ended September 30, 2018, the Credit Facility had a weighted-average interest rate of 3.29%, 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 carried a commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base.

6.375% senior unsecured notes due 2026 (“6.375% Senior Notes”)

On June 7, 2018, the Company issued $400,000 aggregate principal amount of 6.375% Senior Notes with a maturity date of July 1, 2026 and interest payable semi-annually beginning on January 1, 2019. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $394,000. The 6.375% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

The Company may redeem the 6.375% Senior Notes in accordance with the following terms: (1) prior to July 1, 2021, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.375% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to July 1, 2021, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 103.188% of principal if the redemption occurs on or after July 1, 2021, but before July 1, 2022, and (ii) of 102.125% of principal if the redemption occurs on or after July 1, 2022, but before July 1, 2023, and (iii) of 101.063% of principal if the redemption occurs on or after July 1, 2023, but before July 1, 2024, and (iv) of 100% of principal if the redemption occurs on or after July 1, 2024.

Following a change of control, each holder of the 6.375% Senior Notes may require the Company to repurchase all or a portion of the 6.375% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.

6.125% senior unsecured notes due 2024 (“6.125% Senior Notes”)

On October 3, 2016, the Company issued $400,000 aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391,270. The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

On May 19, 2017, the Company issued an additional $200,000 aggregate principal amount of its 6.125% Senior Notes which with the existing $400,000 aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206,139. The Company used the proceeds, in part, to fund an acquisition completed on June 5, 2017 (discussed further in Note 3) and for general corporate purposes.

The Company may redeem the 6.125% Senior Notes in accordance with the following terms: (1) prior to October 1, 2019, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.125% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2019, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 104.594% of principal if the redemption occurs on or after October 1, 2019, but before October 1, 2020, and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020, but before October 1, 2021, and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022, and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022.

Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.

Restrictive covenants

The Company’s Credit Facility and the indentures governing its 6.125% and 6.375% 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 September 30, 2018.

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Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

Objectives and strategies for using 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, put and call options and similar derivative financial instruments 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 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.

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: 

	Balance Sheet Presentation		Asset Fair Value				Liability Fair Value						Net Derivative Fair Value
Commodity	Classification	Line Description	9/30/2018		12/31/2017		9/30/2018			12/31/2017			9/30/2018			12/31/2017
Natural gas	Current	Fair value of derivatives	$	750	$	406	$	(21	)	$	—		$	729		$	406
Natural gas	Non-current	Fair value of derivatives	—		—		(1,299		)	—			(1,299		)	—
Oil	Current	Fair value of derivatives	3,539		—		(47,146		)	(27,744		)	(43,607		)	(27,744		)
Oil	Non-current	Fair value of derivatives	—		—		(14,141		)	(1,284		)	(14,141		)	(1,284		)
Totals			$	4,289	$	406	$	(62,607	)	$	(29,028	)	$	(58,318	)	$	(28,622	)

As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of 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:

	September 30, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	16,157		$	(11,868	)	$	4,289
Long-term assets: Fair value of derivatives	2,786			(2,786		)	—
Current liabilities: Fair value of derivatives	$	(59,035	)	$	11,868		$	(47,167	)
Long-term liabilities: Fair value of derivatives	(18,226		)	2,786			(15,440		)

	December 31, 2017
	Presented without					As Presented with
	Effects of Netting			Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	406		$	—	$	406
Current liabilities: Fair value of derivatives	$	(27,744	)	$	—	$	(27,744	)
Long-term liabilities: Fair value of derivatives	(1,284		)	—		(1,284		)

For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Oil derivatives
Net loss on settlements	$	(9,306	)	$	(1,373	)	$	(26,353	)	$	(4,213	)
Net gain (loss) on fair value adjustments	(24,476		)	(12,811		)	(28,720		)	14,584
Total gain (loss) on oil derivatives	$	(33,782	)	$	(14,184	)	$	(55,073	)	$	10,371
Natural gas derivatives
Net gain on settlements	$	67		$	159		$	675		$	241
Net gain (loss) on fair value adjustments	(624		)	(137		)	(976		)	1,024
Total gain (loss) on natural gas derivatives	$	(557	)	$	22		$	(301	)	$	1,265
Total gain (loss) on oil & natural gas derivatives	$	(34,339	)	$	(14,162	)	$	(55,374	)	$	11,636

Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of September 30, 2018:  

	For the Remainder			For the Full Year			For the Full Year
Oil contracts (WTI)	of 2018			of 2019			of 2020
Swap contracts
Total volume (Bbls)	552,000			—			—
Weighted average price per Bbl	$	52.07		$	—		$	—
Collar contracts (two-way collars)
Total volume (Bbls)	92,000			1,095,000			—
Weighted average price per Bbl
Ceiling (short call)	$	60.50		$	80.00		$	—
Floor (long put)	$	50.00		$	65.00		$	—
Collar contracts combined with short puts (three-way collars)
Total volume (Bbls)	874,000			3,469,000			—
Weighted average price per Bbl
Ceiling (short call option)	$	60.86		$	63.71		$	—
Floor (long put option)	$	48.95		$	53.95		$	—
Short put option	$	39.21		$	43.95		$	—
Puts
Total volume (Bbls)	276,000			1,825,000			—
Weighted average price per Bbl	$	65.00		$	65.00		$	—
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	1,518,000			4,746,500			4,024,000
Weighted average price per Bbl	$	(5.30	)	$	(4.72	)	$	(1.51	)
Natural gas contracts (Henry Hub)
Swap contracts
Total volume (MMBtu)	1,380,000			—			—
Weighted average price per MMBtu	$	2.91		$	—		$	—
Collar contracts (two-way collars)
Total volume (MMBtu)	552,000			2,372,500			—
Weighted average price per MMBtu
Ceiling (short call)	$	3.19		$	2.95		$	—
Floor (long put)	$	2.75		$	2.65		$	—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	552,000			5,840,000			2,196,000
Weighted average price per MMBtu	$	(1.14	)	$	(1.21	)	$	(1.14	)

Subsequent Event

The following derivative contracts were executed subsequent to September 30, 2018:

	For the Remainder	For the Full Year			For the Full Year
	of 2018	of 2019			of 2020
Natural gas contracts (Henry Hub)
Collar contracts (two-way collars)
Total volume (MMBtu)	—	1,355,000			—
Weighted average price per MMBtu
Ceiling (short call)	—	$	3.45		—
Floor (long put)	—	$	2.83		—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	—	3,650,000			—
Weighted average price per MMBtu	—	$	(1.30	)	—

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Fair Value Measurements

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The fair value hierarchy included in GAAP 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 offinancial 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.

	September 30, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit Facility (a)	$	65,000	$	—	$	25,000	$	—
6.125% Senior Notes (b)	595,729		610,500		595,196		618,000
6.375% Senior Notes (b)	392,799		409,000		—		—
Total	$	1,053,528	$	1,019,500	$	620,196	$	618,000

(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.

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:

September 30, 2018	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	4,289		$	—	$	4,289
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(62,607		)	—		(62,607		)
Total net liabilities		$	—	$	(58,318	)	$	—	$	(58,318	)
December 31, 2017	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	406		$	—	$	406
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(29,028		)	—		(29,028		)
Total net liabilities		$	—	$	(28,622	)	$	—	$	(28,622	)

Assets andliabilitiesmeasured atfairvalue on anonrecurringbasis

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 are based on Level 2 and Level 3 inputs.

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Income Taxes

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company provides for income taxes at the statutory rate of 21%. The statutory rate is adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls and shortfalls, and state income taxes.

As a result of the write-down of oil and natural gas properties in the latter part of 2015 and the first half of 2016, the Company incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a full valuation allowance for the net U.S. federal deferred tax asset in 2015. In subsequent periods where the Company has recorded pre-tax income, it has reversed a portion of the U.S. federal valuation allowance, net of discrete items, to the extent necessary to offset U.S. federal income tax expense on pre-tax income recorded for the period. Income tax expense recorded in this period primarily relates to deferred State of Texas gross margin tax. The valuation allowance was $30,281 as of September 30, 2018.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The table below summarizes the activity for the Company’s ARO:

	Nine Months Ended
	September 30, 2018
Asset retirement obligations at January 1, 2018	$	6,020
Accretion expense	626
Liabilities incurred	729
Liabilities settled	(989		)
Sales	(612		)
Revisions to estimate (a)	4,118
Asset retirement obligations at end of period	9,892
Less: Current asset retirement obligations	(4,464		)
Long-term asset retirement obligations at September 30, 2018	$	5,428

(a) Revisions to estimated ARO obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at September 30, 2018 as long-term restricted investments were $3,413. 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.

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Equity Transactions

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Equity Transactions

Equity Transactions

10% Series A Cumulative Preferred Stock (“Preferred Stock”)

Holders of the Company’s Preferred Stock are 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 are 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 were $1,823 and $1,824 for the three months ended September 30, 2018 and 2017, respectively. Preferred Stock dividends of $5,471 for the nine months ended September 30, 2018 remained consistent compared to the same period of 2017.

The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. The Company may, at its option, redeem the Preferred Stock, in whole or in part, at any time on or after May 30, 2018, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date.

Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part, for $50.00 per share in cash plus accrued and unpaid dividends (whether or not declared) to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon such change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on September 30, 2018, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $11.99 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 4.2 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.

Commonstock 

On May 30, 2018, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering costs) of approximately $288,364. The Company used proceeds from the offering to partially fund the Cimarex Asset Acquisition completed in the third quarter, described in Note 3.

On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,934. Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in Note 3.

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Other

9 Months Ended

Sep. 30, 2018

Other [Abstract]

Other

Other

Operating leases

As of September 30, 2018 the Company had contracts for five horizontal drilling rigs. The contract terms, as amended effective as of July 9, 2018, will end on various dates between July 2019 and February 2021. All of the drilling rig contracts provide for early termination, with penalties calculated at a reduced daily rate. In the event that Callon terminated all five drilling contracts as of November 6, 2018, the Company would owe a maximum of $26,696 over the remaining terms of the respective contracts, offset by any revenues earned for replacement work subsequently secured by the contractor. Management does not currently anticipate the early termination of any drilling rig contracts.

Other commitments

In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a two-year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021.

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, Ward, Reagan and Upton 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.

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Description of Business and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2018

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 subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc.

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, 2017. The balance sheet at December 31, 2017 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, 2018.

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, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts may have been reclassified to conform to current year presentation.

Accounting Standards Updates (ASUs)

Recently Adopted ASUs - Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 replaced most of the existing revenue recognition requirements in GAAP.

Throughout 2015 and 2016, the FASB issued several updates to the revenue recognition guidance in Accounting Standards Codification Topic 606 (“ASC 606”). In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers - Principal versus Agent Considerations (Reporting Revenue Gross versus Net). Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers - Identifying Performance Obligations and Licensing. This update clarifies two principles of ASC 606: identifying performance obligations and the licensing implementation guidance. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients. This update applies only to the following areas from ASC 606: assessing the collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar taxes collected from customers, non-cash consideration, contract modification at transition, completed contracts at transition and technical correction.

Prior to the adoption of ASC 606, gathering and treating fees associated with our gas processing agreements have historically been presented within lease operating expenses in the statement of operations. The current period presentation reports these fees as a reduction to natural gas revenues. See Note 2 for additional information on revenue recognition.

The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption and the impact of adoption on the current period statement of operations is as follows:

	Three Months Ended September 30, 2018
	As reported		Adjustments		Presentation without adoption of ASC Topic 606
Operating revenues:
Natural gas sales	$	18,613	$	2,209	$	20,822
Total operating revenues	161,214		2,209		163,423
Operating expenses:
Lease operating expenses	$	18,525	$	2,209	$	20,734
Total operating expenses	88,403		2,209		90,612

	Nine Months Ended September 30, 2018
	As reported		Adjustments		Presentation without adoption of ASC Topic 606
Operating revenues:
Natural gas sales	$	45,229	$	5,413	$	50,642
Total operating revenues	425,729		5,413		431,142
Operating expenses:
Lease operating expenses	$	44,705	$	5,413	$	50,118
Total operating expenses	224,532		5,413		229,945

Recently adopted ASUs - Other

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. The Company adopted this update on January 1, 2018 and it did not have a material impact on its consolidated financial statements.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations-Clarifying the Definition of a Business (“ASU 2017-01”). The guidance in ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The guidance in ASU 2017-01 is effective for annual reporting periods beginning after December 15, 2017, including interim periods therein. The Company adopted this update effective January 1, 2018. The adoption of this update did not have a material impact on its consolidated financial statements.

Recently issued 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”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”).

ASC Topic 842 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under Topic 840. The Company has engaged a third party consultant to assist with its current process of assessing existing contracts, as well as future potential contracts, and to determine the impact of applying Topic 842 on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, field vehicles and equipment, office facility leases, compressors, general corporate leased equipment, and other existing arrangements that may contain a lease component. The Company will adopt this guidance as of January 1, 2019, the transition date, using a modified retrospective method with use of the transition option, in which a cumulative-effect adjustment will be recognized in the opening balance of retained earnings in the period of adoption.  The Company expects the adoption of ASC Topic 842 to primarily impact the asset and liability balances on the balance sheet and will result in changes to the timing and presentation of certain operating expenses on its consolidated statement of operations.

Recently issued 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 guidance in ASU 2018-06 is effective for public entities for annual reporting periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted, but no earlier than an entity’s adoption date of Topic 606. The Company does not expect a material impact on its consolidated financial statements upon adoption of this guidance.

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Description of Business and Basis of Presentation (Tables)

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Effects of Adoption of New Accounting Standard

The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption and the impact of adoption on the current period statement of operations is as follows:

	Three Months Ended September 30, 2018
	As reported		Adjustments		Presentation without adoption of ASC Topic 606
Operating revenues:
Natural gas sales	$	18,613	$	2,209	$	20,822
Total operating revenues	161,214		2,209		163,423
Operating expenses:
Lease operating expenses	$	18,525	$	2,209	$	20,734
Total operating expenses	88,403		2,209		90,612

	Nine Months Ended September 30, 2018
	As reported		Adjustments		Presentation without adoption of ASC Topic 606
Operating revenues:
Natural gas sales	$	45,229	$	5,413	$	50,642
Total operating revenues	425,729		5,413		431,142
Operating expenses:
Lease operating expenses	$	44,705	$	5,413	$	50,118
Total operating expenses	224,532		5,413		229,945

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Acquisitions (Tables)

9 Months Ended

Sep. 30, 2018

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

The following table summarizes the estimated acquisition date fair values of the acquisition:

Evaluated oil and natural gas properties	$	137,368
Unevaluated oil and natural gas properties	509,359
Asset retirement obligations	(168		)
Net assets acquired	$	646,559

Unaudited Summary Pro Forma Financial Information

The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Cimarex Asset Acquisition and Ameredev Transaction had occurred as presented, or to project the Company’s results of operations for any future periods:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		(a)	2017		(a)	2018		(a)	2017		(a)
Revenues	$	181,880		$	107,966		$	506,864		$	326,357
Income from operations	82,057			42,556			238,776			124,005
Income available to common stockholders	44,703			26,387			175,623			128,716
Net income per common share:
Basic	$	0.20		$	0.13		$	0.82		$	0.64
Diluted	$	0.20		$	0.13		$	0.82		$	0.64

(a) The pro forma financial information was prepared assuming the Cimarex Asset Acquisition and the Ameredev Transaction occurred as of January 1, 2017.

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2018

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:

(share amounts in thousands)	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net income	$	37,931		$	17,081		$	144,166		$	97,600
Preferred stock dividends	(1,823		)	(1,824		)	(5,471		)	(5,471		)
Income available to common stockholders	$	36,108		$	15,257		$	138,695		$	92,129
Weighted average shares outstanding	227,564			201,827			213,409			201,422
Dilutive impact of restricted stock	576			510			670			573
Weighted average shares outstanding for diluted income per share	228,140			202,337			214,079			201,995
Basic income per share	$	0.16		$	0.08		$	0.65		$	0.46
Diluted income per share	$	0.16		$	0.08		$	0.65		$	0.46
Restricted stock (a)	154			51			154			51

(a) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

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Borrowings (Tables)

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Schedule of Borrowings

The Company’s borrowings consisted of the following at:

	September 30, 2018			December 31, 2017
Principal components:
Senior secured revolving credit facility	$	65,000		$	25,000
6.125% senior unsecured notes due 2024	600,000			600,000
6.375% senior unsecured notes due 2026	400,000			—
Total principal outstanding	1,065,000			625,000
Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization	6,750			7,594
Unamortized deferred financing costs	(18,222		)	(12,398		)
Total carrying value of borrowings	$	1,053,528		$	620,196

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Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair Value of Derivative Instruments

The following table reflects the fair value of the Company’s derivative instruments for the periods presented: 

	Balance Sheet Presentation		Asset Fair Value				Liability Fair Value						Net Derivative Fair Value
Commodity	Classification	Line Description	9/30/2018		12/31/2017		9/30/2018			12/31/2017			9/30/2018			12/31/2017
Natural gas	Current	Fair value of derivatives	$	750	$	406	$	(21	)	$	—		$	729		$	406
Natural gas	Non-current	Fair value of derivatives	—		—		(1,299		)	—			(1,299		)	—
Oil	Current	Fair value of derivatives	3,539		—		(47,146		)	(27,744		)	(43,607		)	(27,744		)
Oil	Non-current	Fair value of derivatives	—		—		(14,141		)	(1,284		)	(14,141		)	(1,284		)
Totals			$	4,289	$	406	$	(62,607	)	$	(29,028	)	$	(58,318	)	$	(28,622	)

Schedule of Offsetting Assets

The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:

	September 30, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	16,157		$	(11,868	)	$	4,289
Long-term assets: Fair value of derivatives	2,786			(2,786		)	—
Current liabilities: Fair value of derivatives	$	(59,035	)	$	11,868		$	(47,167	)
Long-term liabilities: Fair value of derivatives	(18,226		)	2,786			(15,440		)

	December 31, 2017
	Presented without					As Presented with
	Effects of Netting			Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	406		$	—	$	406
Current liabilities: Fair value of derivatives	$	(27,744	)	$	—	$	(27,744	)
Long-term liabilities: Fair value of derivatives	(1,284		)	—		(1,284		)

Schedule of Offsetting Liabilities

The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:

	September 30, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	16,157		$	(11,868	)	$	4,289
Long-term assets: Fair value of derivatives	2,786			(2,786		)	—
Current liabilities: Fair value of derivatives	$	(59,035	)	$	11,868		$	(47,167	)
Long-term liabilities: Fair value of derivatives	(18,226		)	2,786			(15,440		)

	December 31, 2017
	Presented without					As Presented with
	Effects of Netting			Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	406		$	—	$	406
Current liabilities: Fair value of derivatives	$	(27,744	)	$	—	$	(27,744	)
Long-term liabilities: Fair value of derivatives	(1,284		)	—		(1,284		)

Schedule of Gain or Loss on Derivative Contracts

For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Oil derivatives
Net loss on settlements	$	(9,306	)	$	(1,373	)	$	(26,353	)	$	(4,213	)
Net gain (loss) on fair value adjustments	(24,476		)	(12,811		)	(28,720		)	14,584
Total gain (loss) on oil derivatives	$	(33,782	)	$	(14,184	)	$	(55,073	)	$	10,371
Natural gas derivatives
Net gain on settlements	$	67		$	159		$	675		$	241
Net gain (loss) on fair value adjustments	(624		)	(137		)	(976		)	1,024
Total gain (loss) on natural gas derivatives	$	(557	)	$	22		$	(301	)	$	1,265
Total gain (loss) on oil & natural gas derivatives	$	(34,339	)	$	(14,162	)	$	(55,374	)	$	11,636

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 September 30, 2018:  

	For the Remainder			For the Full Year			For the Full Year
Oil contracts (WTI)	of 2018			of 2019			of 2020
Swap contracts
Total volume (Bbls)	552,000			—			—
Weighted average price per Bbl	$	52.07		$	—		$	—
Collar contracts (two-way collars)
Total volume (Bbls)	92,000			1,095,000			—
Weighted average price per Bbl
Ceiling (short call)	$	60.50		$	80.00		$	—
Floor (long put)	$	50.00		$	65.00		$	—
Collar contracts combined with short puts (three-way collars)
Total volume (Bbls)	874,000			3,469,000			—
Weighted average price per Bbl
Ceiling (short call option)	$	60.86		$	63.71		$	—
Floor (long put option)	$	48.95		$	53.95		$	—
Short put option	$	39.21		$	43.95		$	—
Puts
Total volume (Bbls)	276,000			1,825,000			—
Weighted average price per Bbl	$	65.00		$	65.00		$	—
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	1,518,000			4,746,500			4,024,000
Weighted average price per Bbl	$	(5.30	)	$	(4.72	)	$	(1.51	)
Natural gas contracts (Henry Hub)
Swap contracts
Total volume (MMBtu)	1,380,000			—			—
Weighted average price per MMBtu	$	2.91		$	—		$	—
Collar contracts (two-way collars)
Total volume (MMBtu)	552,000			2,372,500			—
Weighted average price per MMBtu
Ceiling (short call)	$	3.19		$	2.95		$	—
Floor (long put)	$	2.75		$	2.65		$	—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	552,000			5,840,000			2,196,000
Weighted average price per MMBtu	$	(1.14	)	$	(1.21	)	$	(1.14	)

Subsequent Event

The following derivative contracts were executed subsequent to September 30, 2018:

	For the Remainder	For the Full Year			For the Full Year
	of 2018	of 2019			of 2020
Natural gas contracts (Henry Hub)
Collar contracts (two-way collars)
Total volume (MMBtu)	—	1,355,000			—
Weighted average price per MMBtu
Ceiling (short call)	—	$	3.45		—
Floor (long put)	—	$	2.83		—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	—	3,650,000			—
Weighted average price per MMBtu	—	$	(1.30	)	—

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2018

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.

	September 30, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit Facility (a)	$	65,000	$	—	$	25,000	$	—
6.125% Senior Notes (b)	595,729		610,500		595,196		618,000
6.375% Senior Notes (b)	392,799		409,000		—		—
Total	$	1,053,528	$	1,019,500	$	620,196	$	618,000

(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:

September 30, 2018	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	4,289		$	—	$	4,289
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(62,607		)	—		(62,607		)
Total net liabilities		$	—	$	(58,318	)	$	—	$	(58,318	)
December 31, 2017	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	406		$	—	$	406
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(29,028		)	—		(29,028		)
Total net liabilities		$	—	$	(28,622	)	$	—	$	(28,622	)

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation [Abstract]

Summary of Activity of Asset Retirement Obligations

The table below summarizes the activity for the Company’s ARO:

	Nine Months Ended
	September 30, 2018
Asset retirement obligations at January 1, 2018	$	6,020
Accretion expense	626
Liabilities incurred	729
Liabilities settled	(989		)
Sales	(612		)
Revisions to estimate (a)	4,118
Asset retirement obligations at end of period	9,892
Less: Current asset retirement obligations	(4,464		)
Long-term asset retirement obligations at September 30, 2018	$	5,428

(a) Revisions to estimated ARO obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

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Description of Business and Basis of Presentation (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating revenues:
Total operating revenues	$ 161,214	$ 84,614	$ 425,729	$ 248,261
Operating expenses:
Lease operating expenses	18,525	11,624	44,705	36,708
Total operating expenses	88,403	53,188	224,532	160,843
Natural gas sales
Operating revenues:
Total operating revenues	18,613	$ 11,265	45,229	$ 30,019
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
Operating revenues:
Total operating revenues	2,209		5,413
Operating expenses:
Lease operating expenses	2,209		5,413
Total operating expenses	2,209		5,413
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09 | Natural gas sales
Operating revenues:
Total operating revenues	2,209		5,413
Difference between Revenue Guidance in Effect before and after Topic 606
Operating revenues:
Total operating revenues	163,423		431,142
Operating expenses:
Lease operating expenses	20,734		50,118
Total operating expenses	90,612		229,945
Difference between Revenue Guidance in Effect before and after Topic 606 | Natural gas sales
Operating revenues:
Total operating revenues	$ 20,822		$ 50,642

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Revenue Recognition (Gathering and Treating Fees) (Details) - Natural Gas, Gathering and Treating Fees - Accounting Standards Update 2014-09 - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Natural Gas Revenue
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of goods and services sold	$ 2,209		$ 5,413
Lease Operating Expense
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of goods and services sold		$ 909		$ 2,393

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Revenue Recognition (Performance Obligation) (Details)	9 Months Ended
	Sep. 30, 2018
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.

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Acquisitions (Narrative) (Details)				3 Months Ended
	Aug. 31, 2018 USD ($) a	Jun. 05, 2017 USD ($) a	Feb. 13, 2017 USD ($) a	Mar. 31, 2018 USD ($)	Sep. 30, 2018	May 19, 2017 USD ($)
6.125% senior unsecured notes due 2024
Business Acquisition [Line Items]
Debt instrument aggregate principal amount						$ 200,000,000
Debt instrument, interest rate, stated (as a percent)					6.125%	6.125%
Monarch and Wildhorse
Business Acquisition [Line Items]
Consideration transferred				$ 35,900,000
Cimarex Energy Company
Business Acquisition [Line Items]
Consideration transferred	$ 539,519,000
Gas and oil area, developed and undeveloped, net (in acres) | a	28,000
Ameredev
Business Acquisition [Line Items]
Consideration transferred		$ 52,500,000	$ 646,559,000
Gas and oil area, developed and undeveloped, net (in acres) | a		2,488	16,688
Gas and oil area, developed and undeveloped, gross (in acres) | a		7,031	29,175
Working interest (as a percent)			82.00%
Net revenue interest (as a percent)			75.00%

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Acquisitions (Fair Value of Net Assets Acquired ) (Details) - USD ($) $ in Thousands	Aug. 31, 2018	Feb. 13, 2017
Cimarex Energy Company
Business Acquisition [Line Items]
Asset retirement obligations	$ (570)
Net assets acquired	539,519
Cimarex Energy Company | Evaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties	253,089
Cimarex Energy Company | Unevaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties	$ 287,000
Ameredev
Business Acquisition [Line Items]
Asset retirement obligations		$ (168)
Net assets acquired		646,559
Ameredev | Evaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties		137,368
Ameredev | Unevaluated oil and natural gas properties
Business Acquisition [Line Items]
Oil and natural gas properties		$ 509,359

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Acquisitions (Unaudited Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Business Combinations [Abstract]
Revenues	$ 181,880	$ 107,966	$ 506,864	$ 326,357
Income from operations	82,057	42,556	238,776	124,005
Income available to common stockholders	$ 44,703	$ 26,387	$ 175,623	$ 128,716
Net income per common share:
Basic (in dollars per share)	$ 0.20	$ 0.13	$ 0.82	$ 0.64
Diluted (in dollars per share)	$ 0.20	$ 0.13	$ 0.82	$ 0.64

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share, Basic and Diluted
Net income	$ 37,931	$ 17,081	$ 144,166	$ 97,600
Preferred stock dividends	(1,823)	(1,824)	(5,471)	(5,471)
Income available to common stockholders	$ 36,108	$ 15,257	$ 138,695	$ 92,129
Weighted average shares outstanding (in shares)	227,564	201,827	213,409	201,422
Dilutive impact of restricted stock (in shares)	576	510	670	573
Weighted average shares outstanding for diluted income per share (in shares)	228,140	202,337	214,079	201,995
Basic income per share (in dollars per share)	$ 0.16	$ 0.08	$ 0.65	$ 0.46
Diluted income per share (in dollars per share)	$ 0.16	$ 0.08	$ 0.65	$ 0.46
Restricted Stock
Earnings Per Share, Basic and Diluted
Excluded from the diluted EPS calculation because their effect would be anti-dilutive (in shares)	154	51	154	51

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Borrowings (Schedule of Borrowings) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017	May 19, 2017
Principal components:
Total principal outstanding	$ 1,065,000	$ 625,000
Premium on senior unsecured notes, net of accumulated amortization	6,750	7,594
Unamortized deferred financing costs	(18,222)	(12,398)
Total carrying value of borrowings	1,053,528	620,196
Senior secured revolving credit facility
Principal components:
Total principal outstanding	65,000	25,000
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%		6.125%
6.375% senior unsecured notes due 2026
Principal components:
Total principal outstanding	$ 400,000	$ 0
Debt instrument, interest rate, stated (as a percent)	6.375%

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Borrowings (Credit Facility) (Narrative) (Details)			9 Months Ended
	Apr. 05, 2018 USD ($)	May 25, 2017 USD ($) lender	Sep. 30, 2018 USD ($)	Sep. 27, 2018 USD ($)	Dec. 31, 2017 USD ($)
Line of Credit Facility [Line Items]
Balance outstanding on credit facility			$ 65,000,000		$ 25,000,000
Senior secured revolving credit facility | Secured debt
Line of Credit Facility [Line Items]
Debt instrument maturity date	May 25, 2023	May 25, 2022
Institutional lenders | lender		17
Maximum borrowing capacity		$ 2,000,000,000
Credit facility borrowing base	$ 825,000,000		1,100,000,000	$ 1,100,000,000
Increase limit	$ 650,000,000		850,000,000	$ 850,000,000
Balance outstanding on credit facility			65,000,000
Letters of credit outstanding			$ 17,675,000
Interest rate at period end (as a percent)			3.29%
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%		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%		2.25%

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Borrowings Borrowings (6.375% Senior Notes) (Details) - 6.375% senior unsecured notes due 2026 - USD ($)	Jun. 07, 2018	Sep. 30, 2018
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)		6.375%
Unsecured debt
Debt Instrument [Line Items]
Debt instrument aggregate principal amount	$ 400,000,000
Debt instrument, interest rate, stated (as a percent)	6.375%	6.375%
Net proceeds from issuance of senior unsecured notes	$ 394,000,000
Unsecured debt | Change Of Control
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	101.00%
Unsecured debt | Prior to July 1, 2021, a Redemption of up to 35% of the Principal
Debt Instrument [Line Items]
Number of days to closing date of equity offerings	180 days
Debt instrument redemption price percent (as a percent)	106.375%
Unsecured debt | Prior to July 1, 2021, a Redemption of up to 35% of the Principal | Maximum
Debt Instrument [Line Items]
Redemption principal amount percentage (as a percent)	35.00%
Unsecured debt | Prior to July 1, 2021, a Redemption of up to 35% of the Principal | Minimum
Debt Instrument [Line Items]
Redemption principal remaining amount percentage (as a percent)	65.00%
Unsecured debt | Prior to July 1, 2021, a Redemption of All or Part of the Principal
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	100.00%
Unsecured debt | On or After July 1, 2021, but Before July 1, 2022
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	103.188%
Unsecured debt | On or After July 1, 2022, but Before July 1, 2023
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	102.125%
Unsecured debt | On or After July 1, 2023, but Before July 1, 2024
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	101.063%
Unsecured debt | On or After July 1, 2024
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	100.00%

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Borrowings (6.125% Senior Notes) (Narrative) (Details) - USD ($)			9 Months Ended
	May 19, 2017	Oct. 03, 2016	Sep. 30, 2018
Unsecured debt | Callon Petroleum Operating Company
Debt Instrument, Redemption [Line Items]
Percentage of ownership in wholly-owned subsidiary (as a percent)			100.00%
6.125% senior unsecured notes due 2024
Debt Instrument, Redemption [Line Items]
Debt instrument aggregate principal amount	$ 200,000,000
Debt instrument, interest rate, stated (as a percent)	6.125%		6.125%
6.125% senior unsecured notes due 2024 | Unsecured debt
Debt Instrument, Redemption [Line Items]
Debt instrument aggregate principal amount	$ 200,000,000	$ 400,000,000
Debt instrument, interest rate, stated (as a percent)	6.125%	6.125%	6.125%
Debt instrument maturity date			Oct. 01, 2024
Debt instrument repayment beginning date			Apr. 01, 2017
Net proceeds from issuance of senior unsecured notes	$ 206,139,000	$ 391,270,000
Debt instrument redemption price percent (as a percent)	104.125%
6.125% senior unsecured notes due 2024 | Unsecured debt | Change Of Control
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		101.00%
6.125% senior unsecured notes due 2024 | Unsecured debt | Prior to October 1, 2019, a Redemption of up to 35% of the Principal
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		106.125%
Number of days to closing date of equity offerings		180 days
6.125% senior unsecured notes due 2024 | Unsecured debt | Prior to October 1, 2019, a Redemption of All or Part of the Principal
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		100.00%
6.125% senior unsecured notes due 2024 | Unsecured debt | On or After October 1, 2019, but Before October 1, 2020
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		104.594%
6.125% senior unsecured notes due 2024 | Unsecured debt | On or After October 1, 2020, but Before October 1, 2021
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		103.063%
6.125% senior unsecured notes due 2024 | Unsecured debt | On or After October 1, 2021, but Before October 1, 2022
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		101.531%
6.125% senior unsecured notes due 2024 | Unsecured debt | On or After October 1, 2022
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		100.00%
6.125% senior unsecured notes due 2024 | Unsecured debt | Maximum | Prior to October 1, 2019, a Redemption of up to 35% of the Principal
Debt Instrument, Redemption [Line Items]
Redemption principal amount percentage (as a percent)		35.00%
6.125% senior unsecured notes due 2024 | Unsecured debt | Minimum | Prior to October 1, 2019, a Redemption of up to 35% of the Principal
Debt Instrument, Redemption [Line Items]
Redemption principal remaining amount percentage (as a percent)		65.00%

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Derivative Instruments and Hedging Activities (Fair Value of Derivative Instruments) (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Asset Fair Value	$ 4,289	$ 406
Liability Fair Value	(62,607)	(29,028)
Net Derivative Fair Value	(58,318)	(28,622)
Current assets: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Asset Fair Value	4,289	406
Current liabilities: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Liability Fair Value	(47,167)	(27,744)
Long-term assets: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Asset Fair Value	0
Long-term liabilities: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Liability Fair Value	(15,440)	(1,284)
Natural gas | Current assets: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Asset Fair Value	750	406
Natural gas | Current liabilities: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Liability Fair Value	(21)	0
Natural gas | Current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	729	406
Natural gas | Long-term assets: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Asset Fair Value	0	0
Natural gas | Long-term liabilities: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Liability Fair Value	(1,299)	0
Natural gas | Non-current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	(1,299)	0
Oil | Current assets: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Asset Fair Value	3,539	0
Oil | Current liabilities: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Liability Fair Value	(47,146)	(27,744)
Oil | Current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	(43,607)	(27,744)
Oil | Long-term assets: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Asset Fair Value	0	0
Oil | Long-term liabilities: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Liability Fair Value	(14,141)	(1,284)
Oil | Non-current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	$ (14,141)	$ (1,284)

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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	Sep. 30, 2018	Dec. 31, 2017
Offsetting Assets and Liabilities [Line Items]
Derivative asset	$ 4,289	$ 406
Derivative liability	(62,607)	(29,028)
Current assets: Fair value of derivatives
Offsetting Assets and Liabilities [Line Items]
Derivative asset, fair value, gross asset	16,157	406
Derivative asset, fair value, gross liability	(11,868)	0
Derivative asset	4,289	406
Long-term assets: Fair value of derivatives
Offsetting Assets and Liabilities [Line Items]
Derivative asset, fair value, gross asset	2,786
Derivative asset, fair value, gross liability	(2,786)
Derivative asset	0
Current liabilities: Fair value of derivatives
Offsetting Assets and Liabilities [Line Items]
Derivative liability, fair value, gross liability	(59,035)	(27,744)
Derivative liability, fair value, gross asset	11,868	0
Derivative liability	(47,167)	(27,744)
Long-term liabilities: Fair value of derivatives
Offsetting Assets and Liabilities [Line Items]
Derivative liability, fair value, gross liability	(18,226)	(1,284)
Derivative liability, fair value, gross asset	2,786	0
Derivative liability	$ (15,440)	$ (1,284)

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Derivative Instruments and Hedging Activities (Schedule of Gain or Loss on Derivative Contracts) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on fair value adjustments			$ (29,696)	$ 15,608
Total gain (loss) on oil & natural gas derivatives	$ (34,339)	$ (14,162)	(55,374)	11,636
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on oil & natural gas derivatives	(34,339)	(14,162)	(55,374)	11,636
Not Designated as Hedging Instrument | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	(9,306)	(1,373)	(26,353)	(4,213)
Net gain (loss) on fair value adjustments	(24,476)	(12,811)	(28,720)	14,584
Total gain (loss) on oil & natural gas derivatives	(33,782)	(14,184)	(55,073)	10,371
Not Designated as Hedging Instrument | Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	67	159	675	241
Net gain (loss) on fair value adjustments	(624)	(137)	(976)	1,024
Total gain (loss) on oil & natural gas derivatives	$ (557)	$ 22	$ (301)	$ 1,265

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Derivative Instruments and Hedging Activities (Schedule of Outstanding Oil and Natural Gas Derivative Contracts) (Details) - Forecast - Not Designated as Hedging Instrument	3 Months Ended	12 Months Ended
	Dec. 31, 2018 MMBTU $ / MMBTU bbl	Dec. 31, 2020 MMBTU $ / MMBTU bbl	Dec. 31, 2019 MMBTU $ / MMBTU bbl
Oil | Put option
Derivative [Line Items]
Total volume (Bbls) | bbl	276,000	0	1,825,000
Strike price (in dollars per share)	65	0	65
Oil | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl	552,000	0	0
Strike price (in dollars per share)	52.07	0	0
Oil | Collar contracts (two-way collars)
Derivative [Line Items]
Total volume (Bbls) | bbl	92,000	0	1,095,000
Oil | Collar contracts (two-way collars) | Short
Derivative [Line Items]
Strike price (in dollars per share)	60.50	0	80
Oil | Collar contracts (two-way collars) | Long
Derivative [Line Items]
Strike price (in dollars per share)	50	0	65
Oil | Collar contracts combined with short puts (three-way collars)
Derivative [Line Items]
Total volume (Bbls) | bbl	874,000	0	3,469,000
Oil | Collar contracts combined with short puts (three-way collars) | Call option | Short
Derivative [Line Items]
Strike price (in dollars per share)	60.86	0	63.71
Oil | Collar contracts combined with short puts (three-way collars) | Put option | Short
Derivative [Line Items]
Strike price (in dollars per share)	39.21	0	43.95
Oil | Collar contracts combined with short puts (three-way collars) | Put option | Long
Derivative [Line Items]
Strike price (in dollars per share)	48.95	0	53.95
Oil | Oil contracts (Midland basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl	1,518,000	4,024,000	4,746,500
Weighted average swap price (in dollars per share)	(5.30)	(1.51)	(4.72)
Natural gas | Collar contracts (two-way collars)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	552,000	0	2,372,500
Natural gas | Collar contracts (two-way collars) | Short
Derivative [Line Items]
Strike price (in dollars per share)	3.19	0	2.95
Natural gas | Collar contracts (two-way collars) | Long
Derivative [Line Items]
Strike price (in dollars per share)	2.75	0	2.65
Natural gas | Swap contracts (Henry Hub) | Swap contracts
Derivative [Line Items]
Strike price (in dollars per share)	2.91	0	0
Total volume (MMBtu) | MMBTU	1,380,000	0	0
Natural gas | Waha basis differential | Swap contracts
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	552,000	2,196,000	5,840,000
Weighted average swap price (in dollars per share)	(1.14)	(1.14)	(1.21)

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Derivative Instruments and Hedging Activities (Subsequent Events) (Details) - Not Designated as Hedging Instrument - Forecast - Natural gas	3 Months Ended	12 Months Ended
	Dec. 31, 2018 MMBTU $ / MMBTU	Dec. 31, 2020 MMBTU $ / MMBTU	Dec. 31, 2019 MMBTU $ / MMBTU
Collar contracts (two-way collars), Subsequent Contracts
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	0	0	1,355,000
Collar contracts (two-way collars), Subsequent Contracts | Short
Derivative [Line Items]
Strike price (in dollars per share)	0	0	3.45
Collar contracts (two-way collars), Subsequent Contracts | Long
Derivative [Line Items]
Strike price (in dollars per share)	0	0	2.83
Waha Basis Differential, Subsequent Contracts | Swap contracts
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	0	0	3,650,000
Weighted average swap price (in dollars per share)	0	0	(1.30)

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Fair Value Measurements (Summary of Financial Instruments at Carrying and Fair Value) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Jun. 07, 2018	Dec. 31, 2017	May 19, 2017	Oct. 03, 2016
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%
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%			6.125%	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%	6.375%
Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit Facility	$ 65,000		$ 25,000
Total	1,053,528		620,196
Carrying Value | 6.125% senior unsecured notes due 2024 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	595,729		595,196
Carrying Value | 6.375% senior unsecured notes due 2026 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	392,799		0
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit Facility	0		0
Total	1,019,500		618,000
Fair Value | 6.125% senior unsecured notes due 2024 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	610,500		618,000
Fair Value | 6.375% senior unsecured notes due 2026 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	$ 409,000		$ 0

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Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - Recurring Basis - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Assets
Derivative financial instruments	$ 4,289	$ 406
Liabilities
Derivative financial instruments	(62,607)	(29,028)
Net Derivative Fair Value	(58,318)	(28,622)
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	4,289	406
Liabilities
Derivative financial instruments	(62,607)	(29,028)
Net Derivative Fair Value	(58,318)	(28,622)
Level 3
Assets
Derivative financial instruments	0	0
Liabilities
Derivative financial instruments	0	0
Net Derivative Fair Value	$ 0	$ 0

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Income Taxes (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2018 USD ($)
Income Tax Disclosure [Abstract]
Cummulative loss incurred, period	3 years
Deferred tax assets, valuation allowance	$ 30,281

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1, 2018			$ 6,020
Accretion expense	$ 202	$ 131	626	$ 523
Liabilities incurred			729
Liabilities settled			(989)
Sales			(612)
Revisions to estimate			4,118
Asset retirement obligations at end of period	9,892		9,892
Less: Current asset retirement obligations	(4,464)		(4,464)		$ (1,295)
Long-term asset retirement obligations at September 30, 2018	5,428		5,428		4,725
Restricted Investments
Restricted investments	$ 3,413		$ 3,413		$ 3,372

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Equity Transactions (Details) - USD ($) $ / shares in Units, $ in Thousands			3 Months Ended		9 Months Ended
	May 30, 2018	Dec. 19, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Class of Stock [Line Items]
Preferred stock dividend			$ (1,823)	$ (1,824)	$ (5,471)	$ (5,471)
Issuance of common stock					$ 288,364	$ 0
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)			$ 50.00		$ 50.00		$ 50.00
Preferred stock, dividend rate (in dollars per share)					5.00
Common Stock
Class of Stock [Line Items]
Value of a share of common stock (in dollars per share)			$ 11.99		$ 11.99
Conversion ratio of preferred stock to common stock					4.2
Shares of common stock issued in public offering (in shares)	25,300,000	40,000,000
Issuance of common stock	$ 288,364	$ 634,934

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Other (Details) $ in Thousands			1 Months Ended	9 Months Ended
	Nov. 06, 2018 USD ($)	Aug. 06, 2018 bbl / d	Mar. 31, 2018	Sep. 30, 2018 contract
Other [Abstract]
Dedicated fracturing and pump down perforating crews, agreement period			2 years
Delivery commitments per day | bbl / d		15,000
Horizontal Drilling Rig
Subsequent Event [Line Items]
Number of contracts | contract				5
Subsequent Event | Horizontal Drilling Rig
Subsequent Event [Line Items]
Potential loss on contract termination | $	$ 26,696