10-Q

UNITED STATES

SECURITIES ANDEXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒     QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended March 31, 2019

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	64-0844345
State or Other Jurisdiction of Incorporation or Organization	I.R.S. Employer Identification No.
1401 Enclave Parkway, Suite 600 Houston, Texas	77077
Address of Principal Executive Offices	Zip Code

(281) 589-5200

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 the 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:

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 ☒

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock, $0.01 par value	CPE	New York Stock Exchange
10.0% Series A Cumulative Preferred Stock	CPE.A	New York Stock Exchange

The Registrant had 227,912,687 shares of common stock outstanding as of May 1, 2019.

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
Consolidated Statements of Stockholders’ Equity	7
Notes to Consolidated Financial Statements	8
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.  Quantitative and Qualitative Disclosures about Market Risk	30
Item 4.  Controls and Procedures	31
Part II.  Other Information
Item 1.  Legal Proceedings	32
Item 1A.  Risk Factors	32
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 3.  Defaults Upon Senior Securities	32
Item 4.  Mine Safety Disclosures	32
Item 5.  Other Information	32
Item 6.  Exhibits	33

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 natural gas.

• 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 1.  Financial Statements

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par and per share data)

	March 31, 2019			December 31, 2018
ASSETS	Unaudited
Current assets:
Cash and cash equivalents	$	10,482		$	16,051
Accounts receivable	137,110			131,720
Fair value of derivatives	11,372			65,114
Other current assets	12,034			9,740
Total current assets	170,998			222,625
Oil and natural gas properties, full cost accounting method:
Evaluated properties	4,760,071			4,585,020
Less accumulated depreciation, depletion, amortization and impairment	(2,333,589		)	(2,270,675		)
Evaluated oil and natural gas properties, net	2,426,482			2,314,345
Unevaluated properties	1,432,118			1,404,513
Total oil and natural gas properties, net	3,858,600			3,718,858
Operating lease right-of-use assets	40,977			—
Other property and equipment, net	22,413			21,901
Restricted investments	3,450			3,424
Deferred financing costs	5,742			6,087
Fair value of derivatives	385			—
Other assets, net	6,269			6,278
Total assets	$	4,108,834		$	3,979,173
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	230,990		$	261,184
Operating lease liabilities	29,134			—
Accrued interest	25,920			24,665
Cash-settleable restricted stock unit awards	1,060			1,390
Asset retirement obligations	3,771			3,887
Fair value of derivatives	24,550			10,480
Other current liabilities	8,512			13,310
Total current liabilities	323,937			314,916
Senior secured revolving credit facility	330,000			200,000
6.125% senior unsecured notes due 2024	595,971			595,788
6.375% senior unsecured notes due 2026	393,896			393,685
Operating lease liabilities	11,751			—
Asset retirement obligations	10,189			10,405
Cash-settleable restricted stock unit awards	2,252			2,067
Deferred tax liability	4,415			9,564
Fair value of derivatives	6,983			7,440
Other long-term liabilities	995			100
Total liabilities	1,680,389			1,533,965
Commitments and contingencies
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized; 1,458,948 shares outstanding	15			15
Common stock, $0.01 par value, 300,000,000 shares authorized; 227,884,091 and 227,582,575 shares outstanding, respectively	2,279			2,276
Capital in excess of par value	2,481,879			2,477,278
Accumulated deficit	(55,728		)	(34,361		)
Total stockholders’ equity	2,428,445			2,445,208
Total liabilities and stockholders’ equity	$	4,108,834		$	3,979,173

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 March 31,
	2019			2018
Operating revenues:
Oil sales	$	141,098		$	115,286
Natural gas sales	11,949			12,154
Total operating revenues	153,047			127,440
Operating expenses:
Lease operating expenses	24,067			13,039
Production taxes	10,813			8,463
Depreciation, depletion and amortization	59,767			35,417
General and administrative	11,753			8,769
Settled share-based awards	3,024			—
Accretion expense	241			218
Acquisition expense	157			548
Total operating expenses	109,822			66,454
Income from operations	43,225			60,986
Other (income) expenses:
Interest expense, net of capitalized amounts	738			460
Loss on derivative contracts	67,260			4,481
Other income	(81		)	(211		)
Total other (income) expense	67,917			4,730
Income (loss) before income taxes	(24,692		)	56,256
Income tax (benefit) expense	(5,149		)	495
Net income (loss)	(19,543		)	55,761
Preferred stock dividends	(1,824		)	(1,824		)
Income (loss) available to common stockholders	$	(21,367	)	$	53,937
Income per common share:
Basic	$	(0.09	)	$	0.27
Diluted	$	(0.09	)	$	0.27
Weighted average common shares outstanding:
Basic	227,784			201,921
Diluted	227,784			202,588

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

5

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)

	Three Months Ended March 31,
Cash flows from operating activities:	2019			2018
Net income (loss)	$	(19,543	)	$	55,761
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	60,672			36,066
Accretion expense	241			218
Amortization of non-cash debt related items	738			453
Deferred income tax (benefit) expense	(5,149		)	495
(Gain) loss on derivatives, net of settlements	66,970			(3,978		)
Loss on sale of other property and equipment	28			—
Non-cash expense related to equity share-based awards	4,545			1,131
Change in the fair value of liability share-based awards	1,881			1,012
Payments to settle asset retirement obligations	(664		)	(366		)
Payments for cash-settled restricted stock unit awards	(1,296		)	(3,089		)
Changes in current assets and liabilities:
Accounts receivable	(5,390		)	(8,067		)
Other current assets	(2,294		)	61
Current liabilities	(26,003		)	12,938
Other	(177		)	(420		)
Net cash provided by operating activities	74,559			92,215
Cash flows from investing activities:
Capital expenditures	(193,211		)	(111,330		)
Acquisitions	(27,947		)	(38,923		)
Acquisition deposit	—			900
Proceeds from sale of assets	13,879			—
Net cash used in investing activities	(207,279		)	(149,353		)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	220,000			80,000
Payments on senior secured revolving credit facility	(90,000		)	(30,000		)
Payment of preferred stock dividends	(1,824		)	(1,824		)
Tax withholdings related to restricted stock units	(1,025		)	(560		)
Net cash provided by financing activities	127,151			47,616
Net change in cash and cash equivalents	(5,569		)	(9,522		)
Balance, beginning of period	16,051			27,995
Balance, end of period	$	10,482		$	18,473
Supplemental cash flow information:
Non-cash investing activities:
Change in accrued capital expenditures	$	(7,854	)	$	20,727
Change in asset retirement costs	132			4,358
Operating leases	2,022			—
Net cash used in operating activities:
Interest paid, net of capitalized amounts	$	—		$	—
Income taxes paid	—			—
Cash paid for amounts included in the measurement of lease liabilities	9,565			—

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

6

Callon Petroleum Company

Consolidated Statements of Stockholders’ Equity

(Unaudited; in thousands)

	Preferred			Common			Capital in					Total
	Stock			Stock			Excess		Accumulated			Stockholders'
	Shares	$		Shares	$		of Par		Deficit			Equity
Balance at 12/31/2018	1,459	$	15	227,583	$	2,276	$	2,477,278	$	(34,361	)	$	2,445,208
Net loss	—	—		—	—		—		(19,543		)	(19,543		)
Shares issued pursuant to employee benefit plans	—	—		24	—		154		—			154
Restricted stock	—	—		277	3		4,447		—			4,450
Preferred stock dividend	—	—		—	—		—		(1,824		)	(1,824		)
Balance at 03/31/2019	1,459	$	15	227,884	$	2,279	$	2,481,879	$	(55,728	)	$	2,428,445

	Preferred			Common			Capital in					Total
	Stock			Stock			Excess		Accumulated			Stockholders'
	Shares	$		Shares	$		of Par		Deficit			Equity
Balance at 12/31/2017	1,459	$	15	201,836	$	2,018	$	2,181,359	$	(327,426	)	$	1,855,966
Net income	—	—		—	—		—		55,761			55,761
Shares issued pursuant to employee benefit plans	—	—		7	—		88		—			88
Restricted stock	—	—		105	1		1,152		—			1,153
Preferred stock dividend	—	—		—	—		—		(1,824		)	(1,824		)
Balance at 03/31/2018	1,459	$	15	201,948	$	2,019	$	2,182,599	$	(273,489	)	$	1,911,144

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

7

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

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 and Dispositions	9.	Equity Transactions
4.	Earnings Per Share	10.	Leases
5.	Borrowings	11.	Asset Retirement Obligations
6.	Derivative Instruments and Hedging Activities	12.	Other

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 and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. Since our entry into the Permian Basin in late 2009, we have been focused on the Midland Basin and entered the Delaware Basin through an acquisition completed in February 2017. The Company further expanded its presence in the Delaware Basin through acquisitions in 2018.

Basis of presentation

Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data.

The interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of Callon Petroleum Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has a subsidiary, namely Mississippi Marketing, Inc. Effective February 28, 2019, Callon Offshore Production, Inc. was merged with and into Callon Petroleum Operating Company.

These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2018. The balance sheet at December 31, 2018 has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2019.

In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, results of operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.

Summary of Significant Accounting Policies

Leases

We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. Based on our evaluation of leases for the three months ended March, 31, 2019, we have no leases that meet the criteria for classification as a finance lease. We capitalize operating leases on our consolidated balance sheets through a right-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments arising from the lease.

Operating leases are included in operating lease ROU assets, current operating lease liabilities, and long-term operating lease liabilities in our consolidated balance sheets.Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

8

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

Nature of Leases

In support of our operations, we lease certain drilling rigs, office space, office equipment, production facilities, compressors, vehicles and other ancillary drilling equipment under cancelable and non-cancelable contracts. A more detailed description of our material lease types is included below.

Drilling Rigs

The Company enters into daywork and long-term contracts for drilling rigs with third party service contractors to support the development of undeveloped reserves. Our daywork drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells, well pads or contractually stated extension terms by providing 30 days’ notice prior to the end of the original contract term.

The Company’s long-term drilling contracts are generally structured with an initial non-cancelable term of one to two years. We have concluded that our long-term drilling rig arrangements represent operating leases with a lease term greater than twelve months. Additionally, we have concluded that our daywork drilling rig arrangements represent short-term operating leases with a lease term that equals the period of time required to complete drilling operations on the contractually specified well or well pad (that is, generally one to a few months from commencement of drilling).

We do not include the option to extend the drilling rig contract in the lease term due to the continuously evolving nature of our drilling schedules, which requires significant flexibility in the structure of the term of these arrangements, and the potential volatility in commodity prices in an annual period. We have further elected to apply the practical expedient for short-term leases to our daywork drilling rig leases. Accordingly, we do not apply the lease recognition requirements to our daywork drilling rig contracts, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term.

Corporate and Field Offices

We enter into long-term contracts to lease corporate and field office space in support of company operations. These contracts are generally structured with an initial non-cancelable term of two to five years. To the extent that our corporate and field office contracts include renewal options, we evaluate whether we are reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. We have further determined that our current corporate and field office leases represent operating leases.

Transportation, Gathering and Processing Arrangements

We engage in various types of transactions in which midstream entities transport, gather and/or process our product leveraging integrated systems and facilities wholly-owned and operated by the midstream counterparty. Under most of these arrangements, we do not utilize substantially all of the underlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an identified asset.

Accounting Standards Updates (“ASUs”)

Recently adopted ASUs - Leases

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”).

ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.

9

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

The new standard was effective for us in the first quarter of 2019, and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized the cumulative effect of adoption in retained earnings as of January 1, 2019. We further utilized the package of practical expedients at transition to not reassess the following:

• Whether any expired or existing contracts were or contained leases;

• The lease classification for any expired or existing leases; and

• Initial direct costs for any existing leases.

Additionally, we elected the practical expedient under ASU 2018-01, which did not require us to evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. We also chose not to separate lease and non-lease components for the various classes of underlying assets. In addition, for all of our asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases. Accordingly, we recognize lease payments related to our short-term leases in profit or loss on a straight-line basis over the lease term.

Through our implementation process, we evaluated each of our lease arrangements and enhanced our systems to track and calculate additional information required upon adoption of this standard. The standard had an impact on our consolidated balance sheet at March 31, 2019, resulting from the recognition of right-of-use assets and lease liabilities for operating leases. We have no leases that meet the criteria for classification as a finance lease. See Note 10 for additional information regarding the impact of adoption of the new leases standard on our current period results.

Adoption of the new leases standard did not impact our consolidated statement of operations or cash provided from or used in operating, investing or financing in our consolidated statement of cash flows.

We note that the standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.

Recently adopted ASUs - Other

In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the timing and measurement of nonemployee awards. The Company adopted this update on January 1, 2019 and it did not have a material impact on its consolidated financial statements upon adoption of this guidance.

Recently issued ASUs

In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements (“ASU 2019-01”). The standard is intended to clarify the requirements related to interim transition disclosures upon adoption of ASC Topic 842. The guidance in ASU 2019-01 is effective for public entities for annual reporting periods beginning after December 15, 2019, including interim periods therein. 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 Company’s share of revenue received from the sale of NGLs is included in the natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. Gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company has modified the presentation of revenues and expenses to include these fees net of operating revenues. For the three months

10

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

ended March 31, 2019 and 2018, $2,408 and $1,252 of gathering and treating fees were recognized and recorded as a reduction to natural gas sales in the consolidated statement of operations, respectively.

Accounts receivable from revenues from contracts with customers

Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at March 31, 2019 and December 31, 2018 of $98,568 and $87,061, respectively, and does not currently include an allowance for doubtful accounts. Accounts receivable, net, from the sale of oil and natural gas are included in accounts receivable on the consolidated balance sheets.

Transaction price allocated to remaining performance obligations

For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Prior period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.

Note 3 - Acquisitions and Dispositions

2019 Acquisitions

During the first quarter of 2019, the Company completed various acquisitions and dispositions of additional working interests and acreage located in our existing core operating areas within the Permian Basin. The Company purchased mineral rights for $21,407 in the Spur operating area and received proceeds of $14,084 for certain leasehold interests in our WildHorse acreage, including customary purchase price adjustments.

2018 Acquisitions

On August 31, 2018, the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for $539,519, including customary purchase price adjustments (the “Delaware Asset Acquisition”). The Company issued debt and equity to fund, in part, the Delaware Asset Acquisition. See Notes 5 and 9 for additional information regarding the Company’s debt obligations and equity offerings. The following table summarizes the estimated acquisition date fair values of the acquisition:

Evaluated oil and natural gas properties	$	253,089
Unevaluated oil and natural gas properties	287,000
Asset retirement obligations	(570		)
Net assets acquired	$	539,519

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.

In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian Basin. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for $37,770, including customary purchase price adjustments. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for $87,865, including customary purchase price adjustments.

11

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

Subsequent Event

On April 8, 2019, the Company entered into a definitive agreement regarding the sale of certain non-core assets, the Ranger assets, in the Midland Basin for initial cash proceeds of $260,000, excluding customary purchase price adjustments. The agreement also provides for potential contingency payments of up to $60,000 based on WTI average annual pricing over a three-year period.

The sale of the Company’s Ranger assets will not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds will be recorded as adjustments to our full cost pool with no gain or loss recognized. We expect the transaction to close in the second quarter of 2019.

Note 4 - EarningsPer Share

Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share:

(share amounts in thousands)	Three Months Ended March 31,
	2019			2018
Net income (loss)	$	(19,543	)	$	55,761
Preferred stock dividends	(1,824		)	(1,824		)
Income (loss) available to common stockholders	$	(21,367	)	$	53,937
Weighted average common shares outstanding	227,784			201,921
Dilutive impact of restricted stock	—			667
Weighted average common shares outstanding for diluted income per share	227,784			202,588
Basic income per share	$	(0.09	)	$	0.27
Diluted income per share	$	(0.09	)	$	0.27
Restricted stock (a)	356			3

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

Note 5 - Borrowings

The Company’s borrowings consisted of the following:

	As of
Principal components:	March 31, 2019			December 31, 2018
Senior secured revolving credit facility	$	330,000		$	200,000
6.125% senior unsecured notes due 2024	600,000			600,000
6.375% senior unsecured notes due 2026	400,000			400,000
Total principal outstanding	1,330,000			1,200,000
Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization	6,187			6,469
Unamortized deferred financing costs	(16,320		)	(16,996		)
Total carrying value of borrowings (a)	$	1,319,867		$	1,189,473

(a) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $5,742 and $6,087 as of March 31, 2019 and December 31, 2018, respectively.

Senior secured revolving credit facility (the “Credit Facility”)

On May 25, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility 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.

12

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

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) amended various covenants and terms to reflect current market trends, 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) increased the elected commitment amount to $850,000, and (3) amended various covenants and terms to reflect current market trends. As of March 31, 2019, the Credit Facility’s borrowing base remained at $1,100,000 with an elected commitment amount of $850,000.

As of March 31, 2019, there was $330,000 principal and $17,675 in letters of credit outstanding under the Credit Facility. For the period ended March 31, 2019, the Credit Facility had a weighted-average interest rate of 4.00%, calculated as the LIBOR plus a tiered rate ranging from 1.25% to 2.25%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a current commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base. Effective May 1, 2019, the Company entered into the third amendment (the “Third Amendment”) to the Sixth Amended and Restated Credit Agreement to the Credit Facility to, among other things: (i) reaffirm the borrowing base at $1,100,000, excluding the Ranger assets; and (ii) amend various covenants and terms to reflect current market trends.

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 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.

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

13

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

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.

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 March 31, 2019.

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 and put and call options to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.

Counterparty risk and offsetting

The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 7 for additional information regarding fair value.

The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.

Financial statement presentation and settlements

Settlements of the Company’s 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: 

14

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

	Balance Sheet Presentation		Asset Fair Value				Liability Fair Value						Net Derivative Fair Value
Commodity	Classification	Line Description	3/31/2019		12/31/2018		3/31/2019			12/31/2018			3/31/2019			12/31/2018
Oil	Current	Fair value of derivatives	$	7,473	$	60,097	$	(24,550	)	$	(10,480	)	$	(17,077	)	$	49,617
Oil	Non-current	Fair value of derivatives	385		—		(6,190		)	(5,672		)	(5,805		)	(5,672		)
Natural gas	Current	Fair value of derivatives	3,899		5,017		—			—			3,899			5,017
Natural gas	Non-current	Fair value of derivatives	—		—		(793		)	(1,768		)	(793		)	(1,768		)
Totals			$	11,757	$	65,114	$	(31,533	)	$	(17,920	)	$	(19,776	)	$	47,194

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:

	As of March 31, 2019
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	20,540		$	(9,168	)	$	11,372
Long-term assets: Fair value of derivatives	829			(444		)	385
Current liabilities: Fair value of derivatives	$	(33,718	)	$	9,168		$	(24,550	)
Long-term liabilities: Fair value of derivatives	(7,427		)	444			(6,983		)

	As of December 31, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	78,091		$	(12,977	)	$	65,114
Current liabilities: Fair value of derivatives	$	(23,457	)	$	12,977		$	(10,480	)
Long-term liabilities: Fair value of derivatives	(7,440		)	—			(7,440		)

For the periods indicated, the Company recorded the following in the consolidated statements of operations as a gain or loss on derivative contracts:

	Three Months Ended March 31,
	2019			2018
Oil derivatives
Net loss on settlements	$	(1,542	)	$	(8,916	)
Net gain (loss) on fair value adjustments	(66,827		)	4,067
Total loss on oil derivatives	(68,369		)	(4,849		)
Natural gas derivatives
Net gain on settlements	1,252			457
Net loss on fair value adjustments	(143		)	(89		)
Total gain on natural gas derivatives	1,109			368
Total loss on oil & natural gas derivatives	$	(67,260	)	$	(4,481	)

15

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of March 31, 2019:  

	For the Remainder			For the Full Year
Oil contracts (WTI)	of 2019			of 2020
Puts
Total volume (Bbls)	687,500			—
Weighted average price per Bbl	$	65.00		$	—
Put spreads
Total volume (Bbls)	687,500			—
Weighted average price per Bbl
Floor (long put)	$	65.00		$	—
Floor (short put)	$	42.50		$	—
Collar contracts combined with short puts (three-way collars)
Total volume (Bbls)	3,484,000			915,000
Weighted average price per Bbl
Ceiling (short call)	$	67.56		$	65.02
Floor (long put)	$	56.58		$	55.00
Floor (short put)	$	43.62		$	45.00
Collar contracts (two-way collars)
Total volume (Bbls)	—			732,000
Weighted average price per Bbl
Ceiling (short call)	$	—		$	64.63
Floor (long put)	$	—		$	55.00
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	5,102,000			4,576,000
Weighted average price per Bbl	$	(3.95	)	$	(1.29	)
Natural gas contracts (Henry Hub)
Collar contracts (two-way collars)
Total volume (MMBtu)	2,697,500			—
Weighted average price per MMBtu
Ceiling (short call)	$	3.68		$	—
Floor (long put)	$	3.09		$	—
Swap contracts
Total volume (MMBtu)	1,852,000			—
Weighted average price per MMBtu	$	2.88		—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	5,961,000			4,758,000
Weighted average price per MMBtu	$	(1.19	)	$	(1.12	)

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.

16

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

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.

	March 31, 2019				December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit Facility (a)	$	330,000	$	330,000	$	200,000	$	200,000
6.125% Senior Notes (b)	595,971		604,008		595,788		558,000
6.375% Senior Notes (b)	393,896		402,264		393,685		372,000
Total	$	1,319,867	$	1,336,272	$	1,189,473	$	1,130,000

(a) Floating-rate debt.

(b) The fair value was based upon Level 2 inputs. See Note 5 for additional information about the Company’s 6.125% and 6.375% Senior Notes.

Assets and liabilities measured at fair value on a recurring basis

Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value:

Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 6 for additional information regarding the Company’s derivative instruments.

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

March 31, 2019	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	11,757		$	—	$	11,757
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(31,533		)	—		(31,533		)
Total net assets (liabilities)		$	—	$	(19,776	)	$	—	$	(19,776	)
December 31, 2018	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	65,114		$	—	$	65,114
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(17,920		)	—		(17,920		)
Total net assets		$	—	$	47,194		$	—	$	47,194

Assets 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 were based on Level 1, Level 2 and Level 3 inputs.

Note 8 - Income Taxes

The Company provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations:

17

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

	Three Months Ended
Components of income tax rate reconciliation	March 31, 2019		March 31, 2018
Income tax expense computed at the statutory federal income tax rate	21	%	21	%
State taxes net of federal expense	1	%	1	%
Section 162(m)	1	%	—	%
Valuation allowance	—	%	(21	)%
Effective income tax rate, before discrete items	23	%	1	%
Discrete items (a)	(2	)%	—	%
Effective income tax rate, after discrete items	21	%	1	%

(a) Accounts for the potential impact of periodic volatility of stock-based compensation tax deductions on future effective tax rates.

Note 9 - 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 of $1,824 for the three months ended March 31, 2019 remained consistent compared to the same period of 2018.

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 March 31, 2019, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $7.55 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 6.6 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 25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering costs) of approximately $287,988. The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter of 2018, described in Note 3.

Note 10 - Leases

As previously described in Note 1 - Summary of Significant Accounting Policies, we lease certain office space, office equipment, production facilities, compressors, drilling rigs, vehicles and other ancillary drilling equipment under cancelable and non-cancelable leases to support our operations. The following tables reflect the current period impact of our adoption of the new leases standard. As we have no leases that meet the criteria for classification as a finance lease, all information contained herein represents our operating leases.

The components of our total lease cost were as follows:

	Three Months Ended
	March 31, 2019
Operating lease cost	$	9,565
Short-term lease cost (a)	$	1,498

(a) Short-term lease cost excludes expenses related to leases with a contract term of one month or less.

18

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

Supplemental balance sheet information related to our operating leases is included in the table below:

	As of March 31, 2019
Operating lease right-of-use assets	$	40,977
Current operating lease liabilities	29,134
Operating lease liabilities	11,751
Total operating lease liabilities	$	40,885

As of March 31, 2019, our weighted average remaining lease term and our weighted average discount rate for our operating leases were 1.6 years and 4.02%, respectively.

Our operating lease liabilities with enforceable contract terms that are greater than one year mature as follows:

	As of March 31, 2019
Remainder of 2019	$	25,505
2020	13,765
2021	1,573
2022	534
2023	517
Thereafter	388
Total lease payments	42,282
Less imputed interest	1,397
Total	$	40,885

Note 11 - Asset Retirement Obligations

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

	Three Months Ended
	March 31, 2019
Asset retirement obligations at January 1, 2019	$	14,292
Accretion expense	241
Liabilities incurred	111
Liabilities settled	(618		)
Dispositions	(87		)
Revisions to estimate	21
Asset retirement obligations at end of period	13,960
Less: Current asset retirement obligations	(3,771		)
Long-term asset retirement obligations at March 31, 2019	$	10,189

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at March 31, 2019 as long-term restricted investments were $3,450. 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.

19

Notes to the Consolidated Financial Statements (Unaudited)

(All dollar amounts in thousands, except per share and per unit data)

Note 12 - Other

Other commitments

In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard, 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.

In January 2019, the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard, Ward, and Reagan counties and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. We will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

20

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 natural 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 capital and operating costs;

• production decline rates from our wells being greater than expected;

• 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; and

• prospect development and property acquisitions.

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;

• impairments;

• the impact of competition;

• the availability and cost of seismic, drilling and other equipment, waste and water disposal infrastructure, 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;

• the potential impact of future drilling on production from existing wells;

• difficulties encountered in delivering oil and natural gas to commercial markets;

• 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, 2018 (the “2018 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 above or in our 2018 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. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law.

21

Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

22

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 2018 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 Quarterly Report on Form 10-Q.

We are an independent oil and natural gas company incorporated in the State of Delaware in 1994, but our roots go back nearly 70 years to our Company’s establishment in 1950. We are focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. Since our entry into the Permian Basin in late 2009, we have historically been focused on the Midland Basin and more recently entered the Delaware Basin through an acquisition completed in February 2017. We further expanded our presence in the Delaware Basin through our acquisitions in 2018. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is 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 79% oil and 21% natural gas for the three months ended March 31, 2019.

Recent Developments

On April 8, 2019, the Company entered into a definitive agreement regarding the sale of certain non-core assets, the Ranger assets, in the Midland Basin for initial cash proceeds of $260 million, excluding customary purchase price adjustments. The agreement also provides for potential contingency payments of up to $60 million based on WTI average annual pricing over a three-year period.

The proceeds from this divestiture will accelerate our debt reduction initiatives and also provide the opportunity to retire our preferred stock, reducing our cash financing costs.

The sale of the Company’s Ranger assets will not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds will be recorded as adjustments to our full cost pool with no gain or loss recognized. We expect the transaction to close in the second quarter of 2019.

Operational Highlights

All of our producing properties are located in the Permian Basin. As a result of our horizontal development and acquisition efforts, our production grew 52% for the three months ended March 31, 2019, compared to the same period of 2018. Production increased to 3,628 MBOE for the three months ended March 31, 2019 from 2,391 MBOE for the three months ended March 31, 2018.

For the three months ended March 31, 2019, we drilled 21 gross (16.4 net) horizontal wells and completed 11 gross (10.1 net) horizontal wells. As of March 31, 2019, we had 21 gross (16.0 net) horizontal wells awaiting completion.

As of March 31, 2019, we had 940 gross (712.9 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.

23

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 March 31,
	2019			2018			Change			% Change
Net production
Oil (MBbls)	2,858			1,851			1,007			54	%
Natural gas (MMcf)	4,619			3,240			1,379			43	%
Total (MBOE)	3,628			2,391			1,237			52	%
Average daily production (BOE/d)	40,311			26,567			13,744			52	%
% oil (BOE basis)	79		%	77		%
Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)	$	49.37		$	62.28		$	(12.91	)	(21	)%
Natural gas (per Mcf)	2.59			3.75			(1.16		)	(31	)%
Total (per BOE)	42.18			53.30			(11.12		)	(21	)%
Average realized sales price (including impact of settled derivatives):
Oil (per Bbl)	$	48.83		$	57.47		$	(8.64	)	(15	)%
Natural gas (per Mcf)	2.86			3.89			(1.03		)	(26	)%
Total (per BOE)	42.11			49.76			(7.65		)	(15	)%
Oil and natural gas revenues (in thousands)
Oil revenue	$	141,098		$	115,286		$	25,812		22	%
Natural gas revenue	11,949			12,154			(205		)	(2	)%
Total	$	153,047		$	127,440		$	25,607		20	%
Additional per BOE data
Sales price (a)	$	42.18		$	53.30		$	(11.12	)	(21	)%
Lease operating expense (b)	6.63			5.45			1.18			22	%
Production taxes	2.98			3.54			(0.56		)	(16	)%
Operating margin	$	32.57		$	44.31		$	(11.74	)	(26	)%
Benchmark prices
WTI (per Bbl)	$	54.82		$	62.91		$	(8.09	)	(13	)%
Henry Hub (per Mcf)	2.92			3.08			(0.16		)	(5	)%

(a) Excludes the impact of settled derivatives.

(b) Excludes gathering and treating expense.

24

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Revenues

The following tables are intended to 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 March 31, 2018	$	115,286		$	12,154		$	127,440
Volume increase	62,716			5,171			67,887
Price decrease	(36,904		)	(5,376		)	(42,280		)
Net increase (decrease)	25,812			(205		)	25,607
Revenues for the three months ended March 31, 2019	$	141,098		$	11,949		$	153,047

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.

Oil revenue 

For the three months ended March 31, 2019, oil revenues of $141.1 millionincreased$25.8 million, or 22%, compared to revenues of $115.3 million for the same period of 2018. The increase was primarily attributable to a 54%increase in production offset by a 21%decrease in the average realized sales price, which fell to $49.37 per Bbl from $62.28 per Bbl.

Natural gas revenue (including NGLs)

For the three months ended March 31, 2019, natural gas revenues of $11.9 milliondecreased$0.2 million, or 2%, compared to $12.2 million for the same period of 2018. The decrease was primarily attributable to a 31%decrease in the average realized sales price, which fell to $2.59 per Mcf from $3.75 per Mcf. Offsetting the decrease in natural gas revenues was a 43%increase in natural gas volumes.

Operating Expenses

	Three Months Ended March 31,
			Per				Per		Total Change					BOE Change
(in thousands, except per unit amounts)	2019		BOE		2018		BOE		$			%		$			%
Lease operating expenses	$	24,067	$	6.63	$	13,039	$	5.45	$	11,028		85	%	$	1.18		22	%
Production taxes	10,813		2.98		8,463		3.54		2,350			28	%	(0.56		)	(16	)%
Depreciation, depletion and amortization	59,767		16.47		35,417		14.81		24,350			69	%	1.66			11	%
General and administrative	11,753		3.24		8,769		3.67		2,984			34	%	(0.43		)	(12	)%
Settled share-based awards	3,024		0.83		—		—		3,024			100	%	0.83			100	%
Accretion expense	241		0.07		218		0.09		23			11	%	(0.02		)	(22	)%
Acquisition expense	157		0.04		548		0.23		(391		)	(71	)%	(0.19		)	(83	)%

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. 

LOE for the three months ended March 31, 2019increased to $24.1 million compared to $13.0 million for the same period of 2018. For the three months ended March 31, 2019, LOE on a per unit basis increased to $6.63 per BOE compared to $5.45 per BOE for the same period of 2018 primarily due to a 52% increase in production related to our continued drilling program and acquisition activities, workovers and participation in non-operated wells.

25

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 March 31, 2019increased28% to $10.8 million compared to $8.5 million for the same period of 2018, due to an increase in severance taxes based on higher production volumes. Also attributable is the increase in ad valorem taxes due to a higher valuation of our oil and gas properties by the taxing jurisdictions resulting from an increased number of producing wells in the current period, as a result of our horizontal drilling program and acquisition efforts. On a per BOE basis, production taxes for the three months ended March 31, 2019 decreased by 16% compared to the same period of 2018.

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 forty years.

For the three months ended March 31, 2019, DD&A increased69% to $59.8 million compared to $35.4 million for the same period of 2018. For the three months ended March 31, 2019, DD&A on a per unit basis increased to $16.47 per BOE compared to $14.81 per BOE for the same period of 2018.The increase is primarily attributable to higher production levels and an increase in our depreciable base and assumed future development costs related to undeveloped proved reserves relative to our estimated proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions.

General and administrative, net of amounts capitalized (“G&A”). G&A for the three months ended March 31, 2019increased to $11.8 million compared to $8.8 million for the same period of 2018. The increase is primarily attributable to a rise in personnel costs resulting from the growth in our operating activities. G&A expenses for the periods indicated include the following (in thousands):

	Three Months Ended March 31,
	2019		2018		$ Change		% Change
G&A	$	8,364	$	6,673	$	1,691	25	%
Share-based compensation	1,500		1,105		395		36	%
Fair value adjustments of cash-settled RSU awards	1,889		991		898		91	%
Total G&A expenses	$	11,753	$	8,769	$	2,984	34	%

Settled share-based awards. During the first quarter of 2019, the Company settled certain of the outstanding share-based award agreements of two former officers of the Company, resulting in the $3.0 million recorded on the consolidated statements of operations as settled share-based awards.

Other Income and Expenses and Preferred Stock Dividends

	Three Months Ended March 31,
(in thousands)	2019			2018			$ Change			% Change
Interest expense	$	20,582		$	10,528		$	10,054		95	%
Capitalized interest	(19,844		)	(10,068		)	(9,776		)	97	%
Interest expense, net of capitalized amounts	738			460			278			60	%
(Gain) loss on derivative contracts	67,260			4,481			62,779			1,401	%
Other income	(81		)	(211		)	130			(62	)%
Total other (income) expense	$	67,917		$	4,730
Income tax (benefit) expense	$	(5,149	)	$	495		$	(5,644	)	(1,140	)%
Preferred stock dividends	(1,824		)	(1,824		)	—			—	%

Interest expense, net of capitalized amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements 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

26

Management’s Discussion and Analysis of Financial Condition and Results of Operations

fees in interest expense. Interest expense, net of capitalized amounts, incurred during the three months ended March 31, 2019 increased $0.3 million to $0.7 million compared to $0.5 million for the same period of 2018.

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 March 31, 2019, the net loss on derivative instruments was $67.3 million, compared to a $4.5 million net loss for the same period of 2018. The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands):

	Three Months Ended March 31,
	2019			2018
Oil derivatives
Net loss on settlements	$	(1,542	)	$	(8,916	)
Net gain (loss) on fair value adjustments	(66,827		)	4,067
Total loss on oil derivatives	(68,369		)	(4,849		)
Natural gas derivatives
Net gain on settlements	1,252			457
Net loss on fair value adjustments	(143		)	(89		)
Total gain on natural gas derivatives	1,109			368
Total loss on oil & natural gas derivatives	$	(67,260	)	$	(4,481	)

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 benefit of $5.1 million for the three months ended March 31, 2019, compared to income tax expense of $0.5 million for the same period of 2018. The change in income tax is primarily related to the change in our tax position in the current period, for which there is no longer a cumulative three year loss trend and booking of a valuation allowance for deferred tax benefits as compared to the prior period. See Note 8 in the Footnotes to the Financial Statements for additional information.

Preferred Stock dividends. Preferred Stock dividends of $1.8 million for the three months ended March 31, 2019 were consistent with dividends for the same period of 2018. Dividends reflect a 10% dividend yield. See Note 9 in the Footnotes to the Financial Statements for additional information.

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 and development 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 March 31, 2019, we had $330 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 March 31, 2019, we held cash and cash equivalents of $10.5 million as compared to $16.1 million at year ended December 31, 2018.

27

Management’s Discussion and Analysis of Financial Condition and Results of Operations

	Three Months Ended March 31,
(in thousands)	2019			2018
Net cash provided by operating activities	$	74,559		$	92,215
Net cash used in investing activities	(207,279		)	(149,353		)
Net cash provided by financing activities	127,151			47,616
Net change in cash and cash equivalents	$	(5,569	)	$	(9,522	)

Operating activities. For the three months ended March 31, 2019, net cash provided by operating activities was $74.6 million compared to net cash provided by operating activities of $92.2 million for the same period in 2018. The change was predominantly attributable to the following:

• An increase in revenues from an increase in production volumes, offset by a decrease in realized pricing, and

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

Production, realized prices, and operating expenses are discussed 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 three months ended March 31, 2019, net cash used in investing activities was $207.3 millioncompared to $149.4 million for the same period in 2018. The change was predominantly attributable to the following:

• A $63.7 million increase in operational expenditures due to increased activity and additional net wells drilled.

• An increase in cash interest expense capitalized during the three months ended March 31, 2019 due to the timing of interest payments related to our $400.0 million 6.375% Senior Notes that were issued during the second quarter of 2018. See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.375% Senior Notes.

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

	Three Months Ended March 31,
	2019			2018			$ Change
Operational expenditures	$	162,527		$	98,849		$	63,678
Seismic, leasehold and other	1,750			6,481			(4,731		)
Capitalized general and administrative costs	10,345			5,187			5,158
Capitalized interest	18,589			813			17,776
Total capital expenditures(a)	193,211			111,330			81,881
Acquisitions	27,947			38,923			(10,976		)
Acquisition deposits	—			(900		)	900
Proceeds from sale of assets	(13,879		)	—			(13,879		)
Total investing activities	$	207,279		$	149,353		$	57,926

(a) On an accrual (GAAP) basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the three months ended March 31, 2019 were $153.4 million. Inclusive of seismic, leasehold and other, capitalized general and administrative, and capitalized interest costs, total capital expenditures for the three months ended March 31, 2019 were $185.7 million.

General and administrative expenses and capitalized interest are discussed 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 three months ended March 31, 2019, net cash provided by financing activities was $127.2 million compared to net cash provided by financing activities of $47.6 million for the same period of 2018.The change was predominantly attributable to an $80.0 million increase in net borrowings on our Credit Facility.

28

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

	Three Months Ended March 31,
	2019			2018			$ Change
Net borrowings on Credit Facility	$	130,000		$	50,000		$	80,000
Payment of preferred stock dividends	(1,824		)	(1,824		)	—
Tax withholdings related to restricted stock units	(1,025		)	(560		)	(465		)
Net cash provided by financing activities	$	127,151		$	47,616		$	79,535

See Notes 5and 9 in the Footnotes to the Financial Statements for additional information on our Credit Facility and Preferred Stock.

Capital Plan and Year to Date 2019 Summary

Our operational capital budget for 2019 was established in the range of $500 to $525 million on an accrual, or GAAP, basis, running an average of five drilling rigs to support larger, and more efficient, multi-well pad development. Of this range, approximately 15% is comprised of infrastructure and facilities capital. In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $100 to $105 million for capitalized interest and general and administrative expenses.

Operational capital expenditures, including other items, on an accrual basis were $155.2 million for the three months ended March 31, 2019. During the three months ended March 31, 2019, we placed 13 gross (11.2 net) horizontal wells on production. As of March 31, 2019, we have built a drilled, uncompleted inventory of 16.0 net wells to support a transition to larger pad development in the Delaware Basin.In addition to the operational capital expenditures, $10.7 million of capitalized general and administrative and $19.8 million of capitalized interest expenses were accrued in the three months ended March 31, 2019.

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, 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.

Contractual Obligations

We had no material changes in our contractual obligations from amounts listed under “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2018.

29

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, 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 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.

The Company’s hedging portfolio as of March 31, 2019, linked to NYMEX benchmark pricing, covers approximately 4,859,000 Bbls and 4,549,500 MMBtu of our expected oil and natural gas production, respectively, for the remainder of 2019. We also have commodity hedging contracts linked to Midland WTI oil basis differentials relative to Cushing and Waha natural gas basis differentials covering approximately 5,102,000 Bbls and 5,961,000 MMBtu, respectively, of our expected oil and natural gas production for the remainder of 2019. See Note 6 in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at March 31, 2019.

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 from time to time 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 March 31, 2019, the Company had $330.0 million outstanding under the Credit Facility with a weighted average interest rate of 4.00%. 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 $3.3 million, based on the balance outstanding at March 31, 2019. 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.

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

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their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. At March 31, 2019 our total receivables from the sale of our oil and natural gas production were approximately $98.6 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 March 31, 2019 our joint interest receivables were approximately $37.2 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 March 31, 2019.

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 2018 Annual Report on Form 10-K and the risk factors and other cautionary statements contained in our other SEC filings, 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 2018 Annual Report on Form 10-K 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

Not applicable.

Item 5.  Other Information

Effective May 1, 2019, the Company entered into the Third Amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility to, among other things: (i) reaffirm the borrowing base at $1.1 billion, excluding the Ranger assets; and (ii) amend various covenants and terms to reflect current market trends.

The foregoing description is qualified in its entirety by reference to the Third Amendment, a copy of which is filed as Exhibit 10.9 to this Quarterly Report on Form 10-Q and is incorporated herein by reference.

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Item 6.  Exhibits

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

			Incorporated by reference (File No. 001-14039, unless otherwise indicated)
Exhibit Number		Description	Form	Exhibit	Filing Date
3.1		Certificate of Incorporation of the Company, as amended through May 12, 2016	10-Q	3.1	11/03/2016
3.2		Amended and Restated Bylaws of the Company	10-K	3.2	02/27/2019
4.1		Specimen Common Stock Certificate	10-K	4.1	02/28/2018
4.2		Certificate for the Company’s 10.00% Series A Cumulative Preferred Stock	8-A	4.1	05/23/2013
4.3		Registration Rights Agreement, dated May 26, 2016, among Callon Petroleum Company and each of the Persons set forth on Schedule A therein	8-K	10.1	05/31/2016
4.4		Certificate of Designation of Rights and Preferences of 10.00% Series A Cumulative Preferred Stock	8-A	3.5	05/23/2013
4.5		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	8-K	4.1	10/04/2016
4.6		Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated October 3, 2016, 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	8-K	4.2	10/04/2016
4.7		Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated May 24, 2017, 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	8-K	4.1	05/24/2017
4.8		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	8-K	4.1	06/07/2018
4.9		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	8-K	4.2	06/07/2018
10.1	(a)	Separation Agreement, dated March 13, 2019, by and between Jerry A. Weant and Callon Petroleum Company
10.2	†	Form of Change in Control Severance Compensation Agreement, dated as of January 1, 2019, by and between Callon Petroleum Company and its executive officers	10-K	10.17	02/27/2019
10.3	†	Change in Control Severance Compensation Agreement, dated as of January 1, 2019, by and between Joseph C. Gatto, Jr., and Callon Petroleum Company	10-K	10.18	02/27/2019
10.4		Separation Agreement, dated January 2, 2019, by and between Gary A. Newberry and Callon Petroleum Company	10-K	10.19	02/27/2019
10.5	†	Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan	10-K	10.20	02/27/2019
10.6	†	Form of Callon Petroleum Officer Cash-Settleable Performance Share Award Agreement,adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan	10-K	10.21	02/27/2019
10.7	†	Form of Callon Petroleum Company Officer Stock-Settleable Performance Share Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan	10-K	10.22	02/27/2019
10.8	†	Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan	10-K	10.23	02/27/2019
10.9	(a)	Amendment No. 3 to the Sixth Amended and Restated Credit Agreement, dated May 1, 2019, among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto
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)
32.1	(b)	Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b)

(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.

† Indicates management compensatory plan, contract, or arrangement.

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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	May 6, 2019
Joseph C. Gatto, Jr.	Chief Executive Officer

/s/ James P. Ulm, II	Senior Vice President and	May 6, 2019
James P. Ulm, II	Chief Financial Officer

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EX-10.1

Exhibit 10.1

SEPARATION AGREEMENT

Effective as of March 13, 2019, (the “Effective Date”), this Separation Agreement (this “Agreement”) is entered into by and between, and shall inure to the benefit of and be binding upon, the following parties (sometimes collectively referred to herein as “the Parties”):

JERRY A. WEANT, hereinafter referred to as “Employee”; and

Callon Petroleum Company, a Delaware corporation, and its direct and indirect subsidiaries, hereinafter collectively referred to as the “Company.”

WITNESSETH:

WHEREAS, Employee is currently an employee of the Company;

WHEREAS, the Parties mutually agree that the Employee ceased to serve as an officer of the Company and its direct and indirect subsidiaries effective as of March 31, 2019, and further agree that the Employee’s employment with the Company shall end effective March 31, 2019 (the “Resignation Date”);

WHEREAS, Employee and the Company mutually desire to establish and agree on the terms and conditions of Employee’s separation from service;

NOW, THEREFORE, in consideration of the premises and the mutual agreements, covenants and obligations set forth herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound, Employee and the Company hereby agree as follows:

Section 1.Separation Benefits and Payments. Following the Resignation Date, all entitlement to compensation and benefits will cease except as required by applicable law or provided below. Employee will be entitled to (i) a lump-sum payment in an amount equal to Employee’s accrued but unused vacation days and (ii) reimbursement for unpaid business expenses incurred in the ordinary course of business. In addition, subject to the execution of this Agreement by Employee on or after the Effective Date and the lapse of the seven (7) day revocation period following Employee’s execution of this Agreement (the “Revocation Period”) without revocation of this Agreement or any part hereof by Employee, Employee shall be entitled to receive the following payments and benefits, to which Employee would not otherwise be entitled, subject to the terms and conditions set forth in this Agreement:

(a)Employee shall receive a bonus in the amount of $222,600 the Company’s annual performance bonus program for 2018 performance. Any earned bonus will be awarded at the discretion of the Compensation Committee and will be paid, subject to Employee’s continued compliance with the terms of this Agreement, at the time that such bonus awards are normally paid for the year and in any event, no later than March 31, 2019.

(b)Company shall transfer to Employee the title to the Company vehicle currently used by Employee within ten (10) days following the Resignation Date.

(c)For purposes of the outstanding equity awards granted to Employee under the Callon Petroleum Company 2011 Omnibus Incentive Plan or the Callon Petroleum Company 2018 Omnibus Incentive Plan (as amended from time to time, the “Plans”):

(i) for the 31,431 restricted stock units that were awarded in 2016, 2017 and 2018, such awards shall vest in full as of the Resignation Date;

(ii) for the 8,162 stock-settled performance units that were awarded in 2017, such awards shall vest in full at the target performance level as of the Resignation Date; and

(iii) all other outstanding awards under the Plans, including outstanding performance shares and all awards granted in 2019, shall be forfeited as of the Resignation Date.

To the extent necessary to give effect to the provisions of Section 1(c) above, the applicable equity award grant agreements shall be deemed amended by the provisions of Section 1(c) above, as applicable. All payments made pursuant to this Section 1 shall be subject to appropriate tax withholding and are subject to all the terms and conditions of this Agreement.

(d)Callon shall, at its expense, maintain COBRA continuation coverage for Employee’s and family member’s continued benefit for twelve (12) months after the Resignation Date for all medical, dental, and vision insurance coverage to which Employee was entitled immediately prior to the Resignation Date. The continued coverage under this Section 1(d) shall be provided in a manner that is intended to satisfy an exception to Section 409A of the Internal Revenue Code (the “Code”), and therefore not treated as an arrangement providing for nonqualified deferred compensation that is subject to taxation under Code Section 409A.

Section 2.Release of Claims.

(a)General Release by Employee. In consideration of the foregoing, which Employee hereby expressly acknowledges as good and sufficient consideration for the releases provided below, Employee hereby unconditionally and irrevocably releases, acquits and forever discharges, to the fullest extent permitted by applicable law, the Company and each of its subsidiaries, divisions, affiliates, operating companies, predecessors and successors, as well as all of the current and former employees, officers, directors, owners, shareholders, partners, representatives, agents and affiliates of each of them (collectively, the “Released Parties”), from any and every action, cause of action, complaint, claim, demand, administrative charge, legal right, compensation, obligation, damages (including consequential, exemplary and punitive damages), liability, cost or expense (including attorney’s fees) that Employee has, may have or may be entitled to from or against any of the Released Parties, whether legal, equitable or administrative, whether known or unknown, which arises directly or indirectly out of, or is based on or related in any way to Employee’s employment with, compensation and benefits from, termination of employment from, service for or other affiliation with the Company, including any such matter arising from the negligence, gross negligence or reckless, willful or wanton misconduct of any of the

Released Parties (together, the “Released Claims”); provided, however, that this Release does not apply to, and the Released Claims do not include: (i) any claims arising solely and specifically under the U.S. Age Discrimination in Employment Act of 1967 after the date this Agreement is executed by Employee; (ii) any claim for indemnification (including under the Company’s organizational documents or insurance policies) arising in connection with an action instituted by a third party against the Company or any of its affiliates or Employee, in his capacity as an officer, director, manager, employee, agent or other representative of the Company or any of its affiliates; (iii) any claims for vested benefits under the Company’s 401(k) plan; (iv) any claims relating to Employee’s eligibility to continue participating in health coverage currently available to Employee in accordance with COBRA, subject to the terms, conditions and restrictions of that Act; (v) any claim arising from any breach or failure to perform any provision of this Agreement; or (vi) any claim for worker’s compensation benefits or any other claim that cannot be waived by a general release.

(b)Release to be Full and Complete; Waiver of Claims, Rights and Benefits. The parties intend this Release to cover any and all such Released Claims, whether they are contract claims, equitable claims, fraud claims, tort claims, discrimination claims, harassment claims, whistleblower or retaliation claims, personal injury claims, constructive or wrongful discharge claims, emotional distress claims, pain and suffering claims, public policy claims, claims for debts, claims for expense reimbursement, wage claims, claims with respect to any other form of compensation, claims for attorneys’ fees, other claims or any combination of the foregoing, and whether they may arise under any employment contract (express or implied), policies, procedures, practices or by any acts or omissions of any of the Released Parties or whether they may arise under any state, local or federal law, statute, ordinance, rule or regulation, including all Texas employment discrimination laws, Chapter 21 of the Texas Labor Code, the Texas Payday Act, all U.S. federal discrimination laws, the U.S. Age Discrimination in Employment Act of 1967, the U.S. Employee Retirement Income Security Act of 1974, Title VII of the U.S. Civil Rights Act of 1964, the U.S. Civil Rights Act of 1991, the U.S. Rehabilitation Act of 1973, the U.S. Americans with Disabilities Act of 1990, the U.S. Equal Pay Act, the U.S. National Labor Relations Act, the U.S. Older Workers Benefit Protection Act, the U.S. Worker Adjustment and Retraining Notification Act, the U.S. Family and Medical Leave Act, the U.S. Sarbanes-Oxley Act of 2002 or common law, without exception. As such, it is expressly acknowledged and agreed that this Release is a general release, representing a full and complete disposition and satisfaction of all of the Company’s and any Released Party’s real or alleged legal obligations to Employee except as explicitly provided for herein. Employee understands and agrees, in compliance with any law, statute, ordinance, rule or regulation which requires a specific release of unknown claims or benefits, that this Agreement includes a release of unknown claims, and Employee hereby expressly waives and relinquishes any and all Released Claims and any associated rights or benefits that Employee may have, including any that are unknown to Employee at the time of the execution this Agreement. On or after the Resignation Date, as a condition to receiving the benefits set forth in Section 1, Employee agrees that he shall execute another release covenant not to sue of all Released Claims against the Released Parties to be effective on the Resignation Date.

(c)Certain Representations of Employee. Employee represents and warrants that: (i) Employee is the sole and lawful owner of all rights, titles and interests in and to all Released Claims; and (ii) Employee has the fully legal right, power, authority and capacity to execute and deliver this Agreement.

(d)Covenant Not to Sue. Employee expressly agrees that neither Employee nor any person acting on Employee’s behalf will file or bring or permit to be filed or brought any lawsuit or other action before any court, agency or other governmental authority for legal or equitable relief against any of the Released Parties involving any of the Released Claims. In the event that such an action is filed against any of the Released Parties, Employee agrees that such Released Parties are entitled to legal and equitable remedies against Employee, including an award of attorney’s fees. However, it is expressly understood and agreed that the foregoing sentence shall not apply to any action filed by Employee that is narrowly limited to seeking a determination as to the validity of this Agreement and enforcement thereof.

(e)Protected Disclosures. Notwithstanding the foregoing or any other provision in this Agreement to the contrary, including any provision in Sections 4, 5 or 6, the Company and Employee further agree that nothing in this Agreement (i) limits Employee’s ability to file a charge or complaint with the EEOC, the NLRB, OSHA, the SEC or any other federal, state or local governmental agency or commission (“Government Agencies”); (ii) limits Employee’s ability to communicate with any Government Agencies or otherwise participate in any investigation or proceeding that may be conducted by any Government Agency, including providing documents or other information and reporting possible violations of law or regulation or other disclosures protected under the whistleblower provisions of applicable law or regulation, without notice to the Company; or (iii) limits Employee’s right to receive an award for information provided to any Government Agencies. Should Employee file a charge or complaint with any Government Agency, or should any governmental entity, agency or commission file a charge, action, complaint or lawsuit against any of the Released Parties based on any Released Claim, Employee agrees not to seek or accept any resulting payment from the Released Parties.

Section 3.Return of Materials, Nondisparagement, Noncompetition, Nonsolicitation, Confidentiality and Other Undertakings.

(a)Return of Materials. On or promptly after the Resignation Date, Employee shall return to the Company with no request being required of the Company: (i) any and all documents, records, files, reports, memoranda, plans, letters and any other data in Employee’s possession regardless of the medium maintained, held or stored that relate in any way to the business or operations of the Company; and (ii) any credit cards, keys, access cards, calling cards, computer equipment and software, telephone, facsimile or other equipment or property of the Company.

(b)Nondisparagement.

(i)    Employee shall refrain from making, directly or indirectly, in any public or private communication any criticisms or negative or disparaging

comments about the Company or any of the other Released Parties, or about any aspect of the respective businesses, operations, financial results or prospects of the Company, including comments relating to Employee’s separation from employment.

(ii) The directors and officers of the Company shall refrain from making, directly or indirectly, in any public or private, any criticisms or negative or disparaging comments about Employee, or about any aspect of the employment relationship between the Company and Employee, including comments relating to Employee’s separation from employment.

(iii) Notwithstanding the foregoing, it is understood and agreed that nothing in this Section 3(b) is intended to prevent either party or the Released Parties from (x) testifying truthfully in any legal proceeding brought by any governmental authority or other third party or interfere with any obligation to cooperate with or provide information to any government agency or commission or (y) consulting with legal counsel with respect to the interpretation or enforcement of this Agreement.

(c)Noncompetition. Employee agrees that during the term of the Employee’s employment with the Company and for a period of one (1) year following the Resignation Date, he shall not, directly or indirectly, compete with the Company personally or by providing services to any other person, partnership, association, corporation, or other entity that is an “Oil and Gas Business” in the Permian Basin; provided, however, that any leasehold interests, overriding royalty interests, royalty interests and/or mineral interests owned either in the county records of Eddy or Lea County, New Mexico or by any contractual agreement by the Employee or any entity he controls as of March 8, 2019, shall not be considered competition with the Company. As used herein, an “Oil and Gas Business” means owning, managing, acquiring, attempting to acquire, soliciting the acquisition of, operating, controlling, or developing Oil and Gas interests, or engaging in or being connected with, as a principal, owner, officer, director, employee, shareholder, promoter, consultant, contractor, partner, member, joint venture, agent, equity owner or in any other capacity whatsoever, any of the foregoing activities of the oil and gas exploration and production business. The parties agree that the above restrictions on competition are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further agree that any invalidity or unenforceability of any one or more of such restrictions on competition shall not render invalid or unenforceable any remaining restrictions on competition. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this Section 3(c) is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable.

(d)Nonsolicitation. During the term of Employee’s employment with the Company and for a period of one (1) year following the Resignation Date, Employee shall not, on his own behalf or on behalf of any other person, partnership, association, corporation,

or other entity: (a) directly, indirectly, or through a third party hire or cause to be hired; (b) directly, indirectly, or through a third party solicit; or (c) in any manner attempt to influence or induce any employee of the Company or its subsidiaries or affiliates to leave the employment of the Company or its subsidiaries or affiliates, nor shall he use or disclose to any person, partnership, association, corporation, or other entity any information obtained concerning the names and addresses the Company’s employees. The parties agree that the above restrictions on hiring and solicitation are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further agree that any invalidity or unenforceability of any one or more such restrictions on hiring and solicitation shall not render invalid or unenforceable any remaining restrictions on hiring and solicitation. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this Section 3(d) is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable.

(e)Cooperation. Employee agrees to be reasonably available to the Company Entities or their representatives (including their attorneys) to provide information and assistance as requested by the Company. Such information and assistance may include testifying (and preparing to testify) as a witness in any proceeding or otherwise providing information or reasonable assistance to the Company in connection with any investigation, claim or suit. The Employee further agrees not to voluntarily assist any non-governmental adverse party in an action or claim against the Company. Any cooperation required of Employee shall not unreasonably interfere with Employee’s other business endeavors. Company will pay for any pre-approved expenses incurred for such cooperation. If such cooperation shall take more than four (4) hours in any calendar week, Company shall compensate Employee, pro-rata, based upon Employee’s base salary at time of Resignation Date.

(f)Confidentiality and Trade Secrets. The Employee promises not to use in any way or disclose any of the Trade Secrets (as such term is defined in the 2019 Change in Control Severance Compensation Agreement between Employee and the Company, effective as of January 1, 2019 (hereinafter the “2019 Change in Control Agreement”)) or any other confidential and proprietary information that is not generally known to the public (collectively, and including Trade Secrets, “Confidential Information”) directly or indirectly, either during or after the term of his employment, except as required in the course of his employment with the Company, if required in connection with a judicial or administrative proceeding, or if the information becomes public knowledge other than as a result of an unauthorized disclosure by the Employee. All files, records, documents, information, data, and similar items relating to the business of Company, whether prepared by the Employee or otherwise coming into his possession, will remain the exclusive property of Company and may not be removed from the premises of Company under any circumstances without the prior written consent of Company (except in the ordinary course of business during the Employee’s period of active employment under this Agreement), and in any event must be promptly delivered to Company upon termination of the Employee’s employment with Company. The Employee agrees that upon his receipt of any subpoena,

process, or other requests to produce or divulge, directly or indirectly, any Confidential Information to any entity, agency, tribunal, or person, whether received during or after the term of the Employee’s employment with Company, the Employee shall timely notify and promptly deliver a copy of the subpoena, process, or other request to Company. For this purpose, the Employee irrevocably nominates and appoints Company (including any attorney retained by Company), as his true and lawful attorney-in-fact, to act in the Employee’s name, place, and stead to perform any act that the Employee might perform to defend and protect against any disclosure of any Confidential Information. The parties agree that the above restrictions on confidentiality and disclosure are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further agree that any invalidity or unenforceability of any one or more of such restrictions on confidentiality and disclosure shall not render invalid or unenforceable any remaining restrictions on confidentiality and disclosure. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this Section 3(f) is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable

(g)Enforcement of Covenants. Employee acknowledges that the injury that would be suffered by the Company as a result of a breach or threatened breach of the provisions of this Section 3 would be immediate and irreparable and that, because of the difficulty of measuring economic loss of any such breach or threatened breach, an award of monetary damages to the Company for any such breach would be an inadequate remedy. Accordingly, in the event that the Company determines that Employee has breached or attempted to breach or is threatening to breach any provision of this Section 3, in addition to any other remedies at law or in equity that any of the Company may have available to it, it is agreed that the Company shall be entitled, upon application to any court of proper jurisdiction, to temporary or permanent restraining orders or injunctions against Employee prohibiting such breach or attempted or threatened breach, without the necessity of: (i) proving immediate or irreparable harm; (ii) establishing that monetary damages are inadequate or that the Company does not have an adequate remedy at law; or (iii) posting any bond with respect thereto.

(h)Repayment and Forfeiture. Employee agrees that in the event that Employee breaches or challenges any term of Sections 2 or 3 hereof, and all or any part of Sections 2 or 3 are found invalid or unenforceable for any reason whatsoever by a court of competent jurisdiction or an arbitrator in a proceeding between Employee and Company, in addition to any other remedies at law or in equity the Company may have available to it, the Company shall not be obligated to make any of the payments and may cease to make such payments or to provide for any of the benefits specified in Section 1 hereof, and shall be entitled to recoup from Employee any and all of the value of the payments and benefits provided pursuant to Section 1 hereof that have vested or been paid pursuant to that Section.

Section 4.Entire Agreement; Amendment; Third-Party Beneficiaries. Employee and the Company agree and acknowledge that this Agreement contains and comprises the entire agreement and understanding between the parties with respect to the subject matter hereof,

that no other representation, promise, covenant or agreement of any kind whatsoever has been made to cause either party hereto to execute this Agreement, that all agreements and understandings between the parties with respect to the subject matter hereof are embodied and expressed in this Agreement and that this Agreement supersedes all prior agreements, negotiations, discussions, understandings and commitments, written or oral, between the parties hereto with respect to such subject matter including, without limitation, the 2019 Change in Control Agreement. The parties also agree that the terms of this Agreement shall not be amended or changed except in writing and signed by Employee and a duly authorized agent of the Company. The parties to this Agreement further agree that this Agreement shall be binding on and inure to the benefit of Employee and the Company and the Company’s successors and assigns. Except to the extent otherwise provided in this Agreement with respect to the Company and the Released Parties, the provisions of this Agreement shall not confer upon any third party any remedy, claim, liability, reimbursement or other right in excess of those existing without reference to this Agreement.

Section 5.Timing and Consultation with Counsel. Employee acknowledges that (i) he has been given a reasonable period of time, not less than twenty-one (21) days, to consider, and to request changes to, this Agreement and that if he signs this Agreement prior to the end of the 21-day time period he knowingly and voluntarily elected to do so; (ii) he has been advised to discuss the terms of this Agreement with legal counsel of his own choosing; (iii) he was advised that, if accepted, the Agreement could be revoked, in writing, for up to seven (7) days following the date of such acceptance; and (iv) if he revokes this Agreement, his separation from employment as of the Resignation Date shall nevertheless remain effective and he will not be entitled to any of the payments or benefits set forth in Sections 1(a), (b) or (c) hereof.

Section 6.Revocation. Notwithstanding any other provision in this Agreement to the contrary,Employee may revoke this Agreement, in writing, for up to seven (7) days following the date of Employee’s execution of this Agreement, by delivering a written notice of Employee’s revocation of this Agreement to the Company. Any such notice of revocation shall be delivered via email and certified mail to the General Counsel of the Company at 1401 Enclave Parkway, Houston, Texas 77077 (email address: mecklund@callon.com).

Section 7.Applicable Law; Venue. This Agreement shall be interpreted and construed in accordance with the substantive laws of the State of Texas, without giving effect to any conflicts of laws provisions thereof that would result in the application of the laws of any other jurisdiction. THE EXCLUSIVE VENUE FOR THE RESOLUTION OF ANY DISPUTE RELATING TO THIS AGREEMENT OR EMPLOYEE’S EMPLOYMENT (EXCEPT FOR ANY DISPUTE THAT MAY BE SUBJECTED TO ARBITRATION BY MUTUAL AGREEMENT OF THE PARTIES HERETO AFTER THE DATE HEREOF) SHALL BE IN THE STATE AND FEDERAL COURTS LOCATED IN HARRIS COUNTY, TEXAS AND THE PARTIES HEREBY EXPRESSLY CONSENT TO THE JURISDICTION OF THOSE COURTS.

Section 8.Section 409A; Other Tax Matters. This Agreement is intended to provide payments that are exempt from or compliant with the provisions of Section 409A of the U.S. Internal Revenue Code of 1986 (the “Code”) and related regulations and Treasury pronouncements (“Section 409A”), and the Agreement shall be interpreted accordingly. Notwithstanding anything herein to the contrary, if on the date of Employee’s separation from

service Employee is a “specified employee,” as defined in Section 409A, then all or a portion of any separation payments, or benefits under this Agreement that would be subject to the additional tax provided by Section 409A(a)(1)(B) of the Code if not delayed as required by Section 409A(a)(2)(B)(i) of the Code shall be delayed until the first day of the seventh month following Employee’s separation from service date (or, if earlier, Employee’s date of death) and shall be paid as a lump sum (without interest) on such date. For purposes of this Agreement, a termination of Employee’s employment must be a “separation from service” for purposes of Section 409A. For purposes of the application of Section 409A, each payment in a series of payments will be deemed a separate payment. Employee acknowledges and agrees that Employee has obtained no advice from the Company, or any of their respective officers, directors, employees, attorneys or other representatives, and that none of such persons or entities have made any representation regarding the tax consequences, if any, of Employee’s receipt of the payments, benefits and other consideration provided for in this Agreement. Employee further acknowledges and agrees that Employee is personally responsible for the payment of all federal, state and local taxes that are due, or may be due, for any payments and other consideration received by Employee under this Agreement. Employee agrees to indemnify the Company and hold the Company harmless for any and all taxes, penalties or other assessments that Employee is, or may become, obligated to pay on account of any payments made and other consideration provided to Employee under this Agreement (including, without limitation, any amounts relating to or imposed by the operation of Section 409A of the Code).

Section 9.Miscellaneous Provisions.

(a)Waivers. Any term or provision of this Agreement may be waived, or the time for its performance may be extended, by the party hereto entitled to the benefit thereof. Any such waiver shall be validly and sufficiently given for the purposes of this Agreement if, as to either party hereto, it is in writing signed by such party or an authorized representative thereof. Failure on the part of the Company or Employee at any time to insist on strict compliance by the other party with any provisions of this Agreement shall not constitute a waiver of the obligations of either party hereto in respect thereof, or of either such party’s right hereunder to require strict compliance therewith in the future. No waiver of any breach of this Agreement shall be deemed to constitute a waiver of any other or subsequent breach.

(b)Severability. If any provision of this Agreement is held to be illegal, invalid or unenforceable under applicable law, that provision shall be severable and this Agreement shall be construed and enforced as if that illegal, invalid or unenforceable provision never comprised a part hereof, and the remaining provisions hereof shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable provision, and there shall be added automatically as part of this Agreement a provision as similar in its terms to such illegal, invalid or unenforceable provision as may be possible and be legal, valid and enforceable.

(c)Further Assurances. Employee shall, on request by the Company from time to time after the date hereof, execute, acknowledge and deliver to the Company such other documents and instruments as the Company may require to give effect to the provisions of

this Agreement, including a confirmatory release of the Released Claims as of the Resignation Date.

(d)Execution in Counterparts. This Agreement may be executed in any number of counterparts, each of which when so executed and delivered shall be an original, but all such counterparts shall together constitute one and the same instrument.

[Signature page follows]

I HAVE READ THE FOREGOING SEPARATION AGREEMENT, I FULLY UNDERSTAND ITS TERMS AND THAT I MAY BE WAIVING SIGNIFICANT LEGAL RIGHTS BY EXECUTING IT, AND I HAVE VOLUNTARILY EXECUTED IT ON THE DATE WRITTEN BELOW, SIGNIFYING THEREBY MY ASSENT TO AND WILLINGNESS TO BE BOUND BY, ITS TERMS:

By:	/s/ Jerry A. Weant
	Jerry A. Weant
Date

CALLON PETROLEUM COMPANY

By:	/s/ Joseph C. Gatto, Jr.
Name:	Joseph C. Gatto, Jr.
Title:	President & Chief Executive Officer

EX-10.9

Exhibit 10.9

BORROWING BASE INCREASE AGREEMENT AND AMENDMENT NO. 3 TO

SIXTH AMENDED AND RESTATED CREDIT AGREEMENT

This BORROWING BASE INCREASE AGREEMENT AND AMENDMENT NO. 3 TO SIXTH AMENDED AND RESTATED CREDIT AGREEMENT (this “Amendment”) entered into and effective as of May 1, 2019 (the “Effective Date”), is among Callon Petroleum Company, a Delaware corporation (the “Borrower”), the subsidiaries of the Borrower party hereto (the “Guarantors”), the Lenders (as defined below) party hereto, and JPMorgan Chase Bank, N.A., as administrative agent (in such capacity, the “Administrative Agent”) and as issuing bank (in such capacity, the “Issuing Bank”).

RECITALS

A.The Borrower is party to that certain Sixth Amended and Restated Credit Agreement dated as of May 25, 2017, among the Borrower, the financial institutions party thereto from time to time, as lenders (the “Lenders”), the Administrative Agent, and the Issuing Bank (as amended by the Master Assignment, Borrowing Base Increase Agreement, and Amendment No. 1 to Sixth Amended and Restated Credit Agreement dated effective as of April 5, 2018 and the Borrowing Base Increase Agreement and Amendment No. 2 to Sixth Amended and Restated Credit Agreement dated effective as of September 27, 2018 and as the same may be further amended, restated, supplemented, or otherwise modified from time to time, the “Credit Agreement”).

B.Subject to the terms and conditions set forth herein, the parties hereto wish to amend the Credit Agreement and reaffirm the Borrowing Base, in each case, as provided herein.

NOW THEREFORE, in consideration of the premises and the mutual covenants, representations, and warranties contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

Section 1.    Defined Terms. As used in this Amendment, each of the terms defined in the opening paragraph and the Recitals above shall have the meanings assigned to such terms therein. Each term defined in the Credit Agreement and used herein without definition shall have the meaning assigned to such term in the Credit Agreement, as amended hereby, unless expressly provided to the contrary.

Section 2.    Other Definitional Provisions. Article, Section, Schedule, and Exhibit references are to Articles and Sections of and Schedules and Exhibits to this Amendment, unless otherwise specified. The words “hereof”, “herein”, and “hereunder” and words of similar import when used in this Amendment shall refer to this Amendment as a whole and not to any particular provision of this Amendment. The term “including” means “including, without limitation,”. Paragraph headings have been inserted in this Amendment as a matter of convenience for reference only and it is agreed that such paragraph headings are not a part of this Amendment and shall not be used in the interpretation of any provision of this Amendment. Section 1.04 of the Credit Agreement is incorporated herein mutatis mutandis.

Section 3.    Amendments to Credit Agreement.

(a)Section 1.02 (Certain Defined Terms) of the Credit Agreement is hereby amended by adding the following new definition:

“Applicable Hedge Percentage” means (a) for each month of the twelve (12) month period from the date such Swap Agreement is executed, ninety percent (90%), and (b) for each month of the forty-eight (48) month period immediately following the first anniversary of the date such Swap Agreement is executed, eighty-five percent (85%).

(b)Section 9.02 (Debt) of the Credit Agreement is hereby amended by replacing the reference to “$30,000,000” in clause (f) thereof with a reference to “$50,000,000”.

(c)Section 9.06 (Nature of Business; Organizational Changes) of the Credit Agreement is hereby amended by (i) adding the word “and” after the comma at the end of subsection (a) thereof, (ii) be replacing the phrase “, and” at the end of subsection (b) thereof with a period, and (iii) deleting subsection (c) thereof in its entirety.

(d)Section 9.16 (Swap Agreements) of the Credit Agreement is hereby amended by replacing the first reference to “eighty-five percent (85%)” in clause (a) thereof with a reference to “the Applicable Hedge Percentage”.

(e)Section 9.21 (Amendments to Organizational Documents) of the Credit Agreement is hereby deleted in its entirety and replaced with “[Reserved]”.

Section 4.    Borrowing Base Reaffirmation. Subject to the terms of this Amendment, the parties hereto hereby agree that, as of the Effective Date, the Borrowing Base is hereby redetermined and reaffirmed at $1,100,000,000.00, and the Borrowing Base shall remain in effect at such amount until the Borrowing Base is redetermined or adjusted in accordance with the Credit Agreement, as amended hereby. The redetermination and reaffirmation of the Borrowing Base pursuant to this Section 4 shall constitute the semi-annual Scheduled Redetermination to occur on or about May 1, 2019, as set forth in Section 2.06(b) of the Credit Agreement. For purposes the Credit Agreement, including Section 9.11 thereof, the parties hereto hereby acknowledge and agree that, until the next redetermination or adjustment of the Borrowing Base pursuant to the Credit Agreement, (a) the Borrower Base value of certain Oil and Gas Properties in the Midland Basin which the Borrower has identified to the Administrative Agent as the “Ranger Assets” and intends to dispose (the “Ranger Assets”) is $0 and (b) such Ranger Assets were not given any value in making the redetermination and reaffirmation of the Borrowing Base hereunder.

Section 5.    Representations and Warranties. The Borrower and each Guarantor hereby represents and warrants that: (a) after giving effect to this Amendment, the representations and warranties contained in the Credit Agreement, as amended hereby, and the representations and warranties contained in the other Loan Documents are true and correct in all material respects (unless already qualified by materiality in which case such applicable representation and warranty shall be true and correct) on and as of the date hereof as if made on and as of such date except to the extent that any such representation or warranty is expressly limited to an earlier date, in which case, on and as of the date hereof such representation or warranty continues to be true and correct in all material respects (unless already qualified by materiality in which case such applicable

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representation and warranty shall be true and correct) as of such specified earlier date; (b) after giving effect to this Amendment, no Default has occurred and is continuing; (c) the execution, delivery, and performance of this Amendment are within the limited liability company, limited partnership, or corporate power and authority of the Borrower and each Guarantor and have been duly authorized by appropriate limited liability company, limited partnership, or corporate action and proceedings; (d) this Amendment constitutes the legal, valid, and binding obligation of the Borrower and each Guarantor enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity; (e) there are no governmental or other third party consents, licenses, or approvals required in connection with the execution, delivery, performance, validity, or enforceability of this Amendment; and (f) the Liens under the Security Instruments are valid and subsisting and secure the Obligations, as amended hereby.

Section 6.    Conditions to Effectiveness. This Amendment shall become effective as of the Effective Date and enforceable against the parties hereto upon the occurrence of the following conditions precedent:

(a)Documentation. The Administrative Agent shall have received multiple original counterparts, as requested by the Administrative Agent, of this Amendment, duly and validly executed and delivered by duly authorized officers of the Borrower, the Guarantors, the Administrative Agent, the Issuing Bank, and Lenders constituting at least the Required Lenders;

(b)Closing Certificate. The Administrative Agent shall have received a certificate of a Responsible Officer of the Borrower certifying that (i) all consents, licenses, and approvals required in accordance with applicable Governmental Requirements, or in accordance with any document, agreement, instrument, or arrangement to which the Borrower, any Guarantor, or any of their respective subsidiaries is a party, in connection with the execution, delivery, performance, validity, and enforceability of this Amendment and the other Loan Documents have been obtained, (ii) the Borrower, the Guarantors, and their respective subsidiaries have all such material consents, licenses, and approvals required in connection with the continued operation of the Borrower, the Guarantors, and their respective subsidiaries and such approvals are in full force and effect, and all applicable waiting periods shall have expired without any action being taken or threatened by any competent authority which would restrain, prevent, or otherwise impose adverse conditions on this Amendment and the actions contemplated hereby, (iii) the representations and warranties in this Amendment and the other Loan Documents are true and correct in all material respects (unless already qualified by materiality in which case such applicable representation and warranty shall be true and correct) on and as of the date hereof as if made on as and as of such date except to the extent that any such representation or warranty is expressly limited to an earlier date, in which case, on and as of the date hereof such representation or warranty continues to be true and correct in all material respects (unless already qualified by materiality in which case such applicable representation and warranty shall be true and correct) as of such specified earlier date, (iv) immediately before and after giving effect to this Amendment, no Default shall occur and be continuing, and (v) no action, suit, investigation, or other proceeding (including the enactment or promulgation of a statute or rule) by or before any arbitrator or any Governmental Authority has been threatened or is pending and no preliminary or permanent injunction or order by a state or federal court has been entered (A) in connection with this Amendment or any transaction contemplated hereby or (B) which, in any case,

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in the judgment of the Administrative Agent, could reasonably be expected to have a Material Adverse Effect.

(c)Fees. On the Effective Date, the Borrower shall have paid any fees required under any separate agreement between the Borrower and the Administrative Agent, and all costs and expenses that have been invoiced prior to the Effective Date and are payable pursuant to Section 12.03 of the Credit Agreement, together with such additional amounts as shall constitute the Administrative Agent’s counsel’s reasonable estimate of expenses and disbursements to be incurred by such counsel in connection with the recording and filing of Mortgages and Uniform Commercial Code financing statements; provided, that such estimate shall not thereafter preclude further settling of accounts between the Borrower and the Administrative Agent.

Section 7.    Acknowledgments and Agreements.

(a)Each Credit Party acknowledges that on the date hereof all outstanding Obligations are payable in accordance with their terms and each Credit Party waives any set-off, counterclaim, recoupment, defense, or other right, in each case, existing on the date hereof, with respect to such Obligations.

(b)The Administrative Agent, the Issuing Bank, and the Lenders hereby expressly reserve all of their rights, remedies, and claims under the Loan Documents, as amended hereby. This Amendment shall not constitute a waiver or relinquishment of (i) any Default or Event of Default under any of the Loan Documents, as amended hereby, (ii) any of the agreements, terms, or conditions contained in any of the Loan Documents, as amended hereby, (iii) any rights or remedies of the Administrative Agent, the Issuing Bank, or any Lender with respect to the Loan Documents, as amended hereby, or (iv) the rights of the Administrative Agent, the Issuing Bank, or any Lender to collect the full amounts owing to them under the Loan Documents, as amended hereby.

(c)The Borrower, each Guarantor, Administrative Agent, the Issuing Bank and each Lender do hereby adopt, ratify, and confirm the Credit Agreement, as amended hereby, and acknowledge and agree that the Credit Agreement, as amended hereby, is and remains in full force and effect, and the Borrower and each Guarantor acknowledge and agree that their respective liabilities and obligations under the Credit Agreement, as amended hereby, the Guaranty Agreement, and the other Loan Documents are not impaired in any respect by this Amendment.

(d)From and after the date hereof, all references to the Credit Agreement and the Loan Documents shall mean such Credit Agreement and such Loan Documents as amended by this Amendment and the other documents executed pursuant hereto. This Amendment is a Loan Document for the purposes of the provisions of the other Loan Documents. Without limiting the foregoing, any breach of representations, warranties, and covenants under this Amendment shall be a Default or Event of Default, as applicable, under the Credit Agreement.

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(e)Within 60days of the Effective Date (or such longer period of time as may be agreed to by the Administrative Agent), the Borrower shall have delivered duly executed counterparts of Mortgages (or supplements thereto) which, together with all existing Mortgages delivered and in effect, are sufficient to grant a first priority, perfected security interest (subject to Liens permitted under Section 9.03 of the Credit Agreement) in favor of the Administrative Agent on at least 85% of the total value of the proved Oil and Gas Properties of the Credit Parties evaluated in the most recently delivered Reserve Report.

(f)Within 60 days of the Effective Date (or such longer period of time as may be agreed to by the Administrative Agent), the Borrower shall have delivered such title information as the Administrative Agent may reasonably require, all of which shall be reasonably satisfactory to the Administrative Agent in form and substance, on at least 85% of the total value of the proved Oil and Gas Properties of the Credit Parties evaluated in the most recently delivered Reserve Report.

Section 8.    Reaffirmation of the Guaranty. Each Guarantor hereby ratifies, confirms, acknowledges and agrees that its obligations under the Guaranty Agreement are in full force and effect and that such Guarantor continues to unconditionally and irrevocably guarantee the full and punctual payment, when due, whether at stated maturity or earlier by acceleration or otherwise, all of the Guaranteed Obligations (as defined in the Guaranty Agreement), as such Guaranteed Obligations may have been amended by this Amendment, and its execution and delivery of this Amendment does not indicate or establish an approval or consent requirement by such Guarantor under the Guaranty Agreement in connection with the execution and delivery of amendments, consents or waivers to the Credit Agreement, the Notes, or any of the other Loan Documents.

Section 9.    Reaffirmation of Liens. Each Credit Party (a) reaffirms the terms of and its obligations (and the security interests granted by it) under each Security Instrument to which it is a party, and agrees that each such Security Instrument will continue in full force and effect to secure the Obligations as the same may be amended, supplemented, or otherwise modified from time to time, and (b) acknowledges, represents, warrants and agrees that the Liens and security interests granted by it pursuant to the Security Instruments are valid, enforceable, and subsisting and create a first priority, perfected security interest (subject to Liens permitted under Section 9.03 of the Credit Agreement) in favor of the Administrative Agent to secure the Obligations.

Section 10.    Counterparts. This Amendment may be signed in any number of counterparts, each of which shall be an original and all of which, taken together, constitute a single instrument. This Amendment may be executed by facsimile or other electronic signature and all such signatures shall be effective as originals.

Section 11.    Successors and Assigns. This Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted pursuant to the Credit Agreement.

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Section 12.    Invalidity. In the event that any one or more of the provisions contained in this Amendment shall for any reason be held invalid, illegal, or unenforceable in any respect, such invalidity, illegality, or unenforceability shall not affect any other provision of this Amendment.

Section 13.    Governing Law. This Amendment shall be governed by, and construed and enforced in accordance with, the laws of the State of New York.

Section 14.    Entire Agreement.THIS AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES HERETO AND THERETO AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

[SIGNATURES BEGIN ON NEXT PAGE]

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IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly authorized as of the day and year first above written.

BORROWER:	CALLON PETROLEUM COMPANY
	By:	/s/ James P. Ulm, II
	Name:	James P. Ulm, II
	Title:	Senior Vice President and Chief Financial Officer

GUARANTOR:	CALLON PETROLEUM OPERATING COMPANY
	By:	/s/ James P. Ulm, II
	Name:	James P. Ulm, II
	Title:	Senior Vice President and Chief Financial Officer

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

ADMINISTRATIVE AGENT/ISSUING BANK/LENDER:	JPMORGAN CHASE BANK, N.A.
	as Administrative Agent, Issuing Bank, and a Lender
	By:	/s/ Anson Williams
	Name:	Anson Williams
	Title:	Authorized Officer

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	REGIONS BANK, as Lender
	By:	/s/ Nathalie Huet Rousset
	Name:	Nathalie Huet Rousset
	Title:	Director

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	THE BANK OF NOVA SCOTIA, HOUSTON BRANCH, as a Lender
	By:	/s/ Marc Graham
	Name:	Marc Graham
	Title:	Managing Director

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	CAPITAL ONE, NATIONAL ASSOCIATION, as a Lender
	By:	/s/ Chris Kuna
	Name:	Chris Kuna
	Title:	Director

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	CITIBANK, N.A., as a Lender
	By:	/s/ William McNeely
	Name:	William McNeely
	Title:	Senior Vice President

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	KEYBANK, NATIONAL ASSOCIATION, as a Lender
	By:	/s/ David M. Bornstein
	Name:	David M. Bornstein
	Title:	Senior Vice President

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	ROYAL BANK OF CANADA, as a Lender
	By:	/s/ Emilee Scott
	Name:	Emilee Scott
	Title:	Authorized Signatory

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	SUNTRUST BANK, as a Lender
	By:	/s/ Arize Agumadu
	Name:	Arize Agumadu
	Title:	Vice President

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	BOKF, NA DBA BANK OF OKLAHOMA, as a Lender
	By:	/s/ Paul J. Edmonds
	Name:	Paul J. Edmonds
	Title:	Senior Vice President

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	CIT BANK, N.A., as a Lender
	By:	/s/ Sean M. Murphy
	Name:	Sean M. Murphy
	Title:	Managing Director

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH, as a Lender
	By:	/s/ Judith E. Smith
	Name:	Judith E. Smith
	Title:	Authorized Signatory
	By:	/s/ Joan Park
	Name:	Joan Park
	Title:	Authorized Signatory

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	IBERIABANK, N.A., as a Lender
	By:	/s/ Moni Collins
	Name:	Moni Collins
	Title:	Senior Vice President

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	HANCOCK WHITNEY BANK, as a Lender
	By:	/s/ William Jochetz
	Name:	William Jochetz
	Title:	Senior Vice President

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	BARCLAYS BANK PLC, as a Lender
	By:	/s/ Sydney G. Dennis
	Name:	Sydney G. Dennis
	Title:	Director

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	BANK OF AMERICA, N.A., as a Lender
	By:	/s/ Kimberly Miller
	Name:	Kimberly Miller
	Title:	Vice President

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK BRANCH, as a Lender
	By:	/s/ Donovan C. Broussard
	Name:	Donovan C. Broussard
	Title:	Authorized Signatory
	By:	/s/ Megan Larson
	Name:	Megan Larson
	Title:	Authorized Signatory

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

LENDER:	COMPASS BANK, as a Lender
	By:	/s/ Gabriela Azcarate
	Name:	Gabriela Azcarate
	Title:	Senior Vice President

Signature page to

Amendment No. 3 to Sixth Amended and Restated Credit Agreement

(Callon Petroleum Company)

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:	May 6, 2019	/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:	May 6, 2019	/s/ James P. Ulm, II
		James P. Ulm, II
		Senior Vice President and Chief Financial Officer
		(Principal financial officer)

EX-32.1

Exhibit32.1

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 March 31, 2019, 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:	May 6, 2019	/s/ Joseph C. Gatto, Jr.
		Joseph C. Gatto, Jr.
		(Principal executive officer)
Date:	May 6, 2019	/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	3 Months Ended
	Mar. 31, 2019	May 01, 2019
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	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		227,912,687

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Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 10,482	$ 16,051
Accounts receivable	137,110	131,720
Fair value of derivatives	11,372	65,114
Other current assets	12,034	9,740
Total current assets	170,998	222,625
Oil and natural gas properties, full cost accounting method:
Evaluated properties	4,760,071	4,585,020
Less accumulated depreciation, depletion, amortization and impairment	(2,333,589)	(2,270,675)
Evaluated oil and natural gas properties, net	2,426,482	2,314,345
Unevaluated properties	1,432,118	1,404,513
Total oil and natural gas properties, net	3,858,600	3,718,858
Operating lease right-of-use assets	40,977
Other property and equipment, net	22,413	21,901
Restricted investments	3,450	3,424
Deferred financing costs	5,742	6,087
Fair value of derivatives	385	0
Other assets, net	6,269	6,278
Total assets	4,108,834	3,979,173
Current liabilities:
Accounts payable and accrued liabilities	230,990	261,184
Operating lease liabilities	29,134
Accrued interest	25,920	24,665
Cash-settleable restricted stock unit awards	1,060	1,390
Asset retirement obligations	3,771	3,887
Fair value of derivatives	24,550	10,480
Other current liabilities	8,512	13,310
Total current liabilities	323,937	314,916
Senior secured revolving credit facility	330,000	200,000
Operating lease liabilities	11,751
Asset retirement obligations	10,189	10,405
Cash-settleable restricted stock unit awards	2,252	2,067
Deferred tax liability	4,415	9,564
Fair value of derivatives	6,983	7,440
Other long-term liabilities	995	100
Total liabilities	1,680,389	1,533,965
Commitments and contingencies
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized; 1,458,948 shares outstanding	15	15
Common stock, $0.01 par value, 300,000,000 shares authorized; 227,884,091 and 227,582,575 shares outstanding, respectively	2,279	2,276
Capital in excess of par value	2,481,879	2,477,278
Accumulated deficit	(55,728)	(34,361)
Total stockholders’ equity	2,428,445	2,445,208
Total liabilities and stockholders’ equity	4,108,834	3,979,173
6.125% senior unsecured notes due 2024
Current liabilities:
Senior unsecured notes	595,971	595,788
6.375% senior unsecured notes due 2026
Current liabilities:
Senior unsecured notes	$ 393,896	$ 393,685

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
Stockholders’ equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	300,000,000	300,000,000
Common stock, shares outstanding (in shares)	227,884,091	227,582,575
6.125% senior unsecured notes due 2024
Debt instrument, interest rate, stated (as a percent)	6.125%
6.375% senior unsecured notes due 2026
Debt instrument, interest rate, stated (as a percent)	6.375%
Series A Preferred Stock
Stockholders’ equity:
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, liquidation preference (in dollars per share)	$ 50.00	$ 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 (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Operating revenues:
Total operating revenues	$ 153,047	$ 127,440
Operating expenses:
Lease operating expenses	24,067	13,039
Production taxes	10,813	8,463
Depreciation, depletion and amortization	59,767	35,417
General and administrative	11,753	8,769
Settled share-based awards	3,024	0
Accretion expense	241	218
Acquisition expense	157	548
Total operating expenses	109,822	66,454
Income from operations	43,225	60,986
Other (income) expenses:
Interest expense, net of capitalized amounts	738	460
Loss on derivative contracts	67,260	4,481
Other income	(81)	(211)
Total other (income) expense	67,917	4,730
Income (loss) before income taxes	(24,692)	56,256
Income tax (benefit) expense	(5,149)	495
Net income (loss)	(19,543)	55,761
Preferred stock dividends	(1,824)	(1,824)
Income (loss) available to common stockholders	$ (21,367)	$ 53,937
Income per common share:
Basic (in dollars per share)	$ (0.09)	$ 0.27
Diluted (in dollars per share)	$ (0.09)	$ 0.27
Weighted average common shares outstanding:
Basic (in shares)	227,784	201,921
Diluted (in shares)	227,784	202,588
Oil sales
Operating revenues:
Total operating revenues	$ 141,098	$ 115,286
Natural gas sales
Operating revenues:
Total operating revenues	$ 11,949	$ 12,154

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Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash flows from operating activities:
Net income (loss)	$ (19,543)	$ 55,761
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	60,672	36,066
Accretion expense	241	218
Amortization of non-cash debt related items	738	453
Deferred income tax (benefit) expense	(5,149)	495
(Gain) loss on derivatives, net of settlements	66,970	(3,978)
Loss on sale of other property and equipment	28	0
Non-cash expense related to equity share-based awards	4,545	1,131
Change in the fair value of liability share-based awards	1,881	1,012
Payments to settle asset retirement obligations	(664)	(366)
Payments for cash-settled restricted stock unit awards	(1,296)	(3,089)
Changes in current assets and liabilities:
Accounts receivable	(5,390)	(8,067)
Other current assets	(2,294)	61
Current liabilities	(26,003)	12,938
Other	(177)	(420)
Cash flows from investing activities:	74,559	92,215
Cash flows from investing activities:
Capital expenditures	(193,211)	(111,330)
Acquisitions	(27,947)	(38,923)
Acquisition deposit	0	900
Proceeds from sale of assets	13,879	0
Net cash used in investing activities	(207,279)	(149,353)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	220,000	80,000
Payments on senior secured revolving credit facility	(90,000)	(30,000)
Payment of preferred stock dividends	(1,824)	(1,824)
Tax withholdings related to restricted stock units	(1,025)	(560)
Net cash provided by financing activities	127,151	47,616
Net change in cash and cash equivalents	(5,569)	(9,522)
Balance, beginning of period	16,051	27,995
Balance, end of period	10,482	18,473
Non-cash investing activities:
Change in accrued capital expenditures	(7,854)	20,727
Change in asset retirement costs	132	4,358
Operating leases	2,022	0
Net cash used in operating activities:
Interest paid, net of capitalized amounts	0	0
Income taxes paid	0	0
Cash paid for amounts included in the measurement of lease liabilities	$ 9,565	$ 0

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Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) $ in Thousands	Total	Preferred Stock	Common Stock	Capital in Excess of Par	Retained Deficit
Balance (in shares) at Dec. 31, 2017		1,459,000	201,836,000
Balance at Dec. 31, 2017	$ 1,855,966	$ 15	$ 2,018	$ 2,181,359	$ (327,426)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	55,761				55,761
Shares issued pursuant to employee benefit plans (in shares)			7,000
Shares issued pursuant to employee benefit plans	88			88
Restricted stock (in shares)			105,000
Restricted stock	1,153		$ 1	1,152
Preferred stock dividend	(1,824)				(1,824)
Balance (in shares) at Mar. 31, 2018		1,459,000	201,948,000
Balance at Mar. 31, 2018	1,911,144	$ 15	$ 2,019	2,182,599	(273,489)
Balance (in shares) at Dec. 31, 2018		1,459,000	227,583,000
Balance at Dec. 31, 2018	2,445,208	$ 15	$ 2,276	2,477,278	(34,361)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(19,543)				(19,543)
Shares issued pursuant to employee benefit plans (in shares)			24,000
Shares issued pursuant to employee benefit plans	154			154
Restricted stock (in shares)			277,000
Restricted stock	4,450		$ 3	4,447
Preferred stock dividend	(1,824)				(1,824)
Balance (in shares) at Mar. 31, 2019		1,459,000	227,884,000
Balance at Mar. 31, 2019	$ 2,428,445	$ 15	$ 2,279	$ 2,481,879	$ (55,728)

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Description of Business and Basis of Presentation

3 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business and Basis of Presentation

Description of Business and Basis of Presentation

Description of business

Callon Petroleum Company 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 and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. Since our entry into the Permian Basin in late 2009, we have been focused on the Midland Basin and entered the Delaware Basin through an acquisition completed in February 2017. The Company further expanded its presence in the Delaware Basin through acquisitions in 2018.

Basis of presentation

Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data.

The interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of Callon Petroleum Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has a subsidiary, namely Mississippi Marketing, Inc. Effective February 28, 2019, Callon Offshore Production, Inc. was merged with and into Callon Petroleum Operating Company.

These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2018. The balance sheet at December 31, 2018 has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2019.

In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, results of operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.

Summary of Significant Accounting Policies

Leases

We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. Based on our evaluation of leases for the three months ended March, 31, 2019, we have no leases that meet the criteria for classification as a finance lease. We capitalize operating leases on our consolidated balance sheets through a right-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments arising from the lease.

Operating leases are included in operating lease ROU assets, current operating lease liabilities, and long-term operating lease liabilities in our consolidated balance sheets.Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

Nature of Leases

In support of our operations, we lease certain drilling rigs, office space, office equipment, production facilities, compressors, vehicles and other ancillary drilling equipment under cancelable and non-cancelable contracts. A more detailed description of our material lease types is included below.

Drilling Rigs

The Company enters into daywork and long-term contracts for drilling rigs with third party service contractors to support the development of undeveloped reserves. Our daywork drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells, well pads or contractually stated extension terms by providing 30 days’ notice prior to the end of the original contract term.

The Company’s long-term drilling contracts are generally structured with an initial non-cancelable term of one to two years. We have concluded that our long-term drilling rig arrangements represent operating leases with a lease term greater than twelve months. Additionally, we have concluded that our daywork drilling rig arrangements represent short-term operating leases with a lease term that equals the period of time required to complete drilling operations on the contractually specified well or well pad (that is, generally one to a few months from commencement of drilling).

We do not include the option to extend the drilling rig contract in the lease term due to the continuously evolving nature of our drilling schedules, which requires significant flexibility in the structure of the term of these arrangements, and the potential volatility in commodity prices in an annual period. We have further elected to apply the practical expedient for short-term leases to our daywork drilling rig leases. Accordingly, we do not apply the lease recognition requirements to our daywork drilling rig contracts, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term.

Corporate and Field Offices

We enter into long-term contracts to lease corporate and field office space in support of company operations. These contracts are generally structured with an initial non-cancelable term of two to five years. To the extent that our corporate and field office contracts include renewal options, we evaluate whether we are reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. We have further determined that our current corporate and field office leases represent operating leases.

Transportation, Gathering and Processing Arrangements

We engage in various types of transactions in which midstream entities transport, gather and/or process our product leveraging integrated systems and facilities wholly-owned and operated by the midstream counterparty. Under most of these arrangements, we do not utilize substantially all of the underlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an identified asset.

Accounting Standards Updates (“ASUs”)

Recently adopted ASUs - Leases

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”).

ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.

The new standard was effective for us in the first quarter of 2019, and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized the cumulative effect of adoption in retained earnings as of January 1, 2019. We further utilized the package of practical expedients at transition to not reassess the following:

• Whether any expired or existing contracts were or contained leases;

• The lease classification for any expired or existing leases; and

• Initial direct costs for any existing leases.

Additionally, we elected the practical expedient under ASU 2018-01, which did not require us to evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. We also chose not to separate lease and non-lease components for the various classes of underlying assets. In addition, for all of our asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases. Accordingly, we recognize lease payments related to our short-term leases in profit or loss on a straight-line basis over the lease term.

Through our implementation process, we evaluated each of our lease arrangements and enhanced our systems to track and calculate additional information required upon adoption of this standard. The standard had an impact on our consolidated balance sheet at March 31, 2019, resulting from the recognition of right-of-use assets and lease liabilities for operating leases. We have no leases that meet the criteria for classification as a finance lease. See Note 10 for additional information regarding the impact of adoption of the new leases standard on our current period results.

Adoption of the new leases standard did not impact our consolidated statement of operations or cash provided from or used in operating, investing or financing in our consolidated statement of cash flows.

We note that the standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.

Recently adopted ASUs - Other

In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the timing and measurement of nonemployee awards. The Company adopted this update on January 1, 2019 and it did not have a material impact on its consolidated financial statements upon adoption of this guidance.

Recently issued ASUs

In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements (“ASU 2019-01”). The standard is intended to clarify the requirements related to interim transition disclosures upon adoption of ASC Topic 842. The guidance in ASU 2019-01 is effective for public entities for annual reporting periods beginning after December 15, 2019, including interim periods therein. The Company does not expect a material impact on its consolidated financial statements upon adoption of this guidance.

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Revenue Recognition

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue Recognition

Revenue Recognition

Revenue from contracts with customers

Oil sales

Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.

Natural gas sales

Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. The Company’s share of revenue received from the sale of NGLs is included in the natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. Gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company has modified the presentation of revenues and expenses to include these fees net of operating revenues. For the three months ended March 31, 2019 and 2018, $2,408 and $1,252 of gathering and treating fees were recognized and recorded as a reduction to natural gas sales in the consolidated statement of operations, respectively.

Accounts receivable from revenues from contracts with customers

Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at March 31, 2019 and December 31, 2018 of $98,568 and $87,061, respectively, and does not currently include an allowance for doubtful accounts. Accounts receivable, net, from the sale of oil and natural gas are included in accounts receivable on the consolidated balance sheets.

Transaction price allocated to remaining performance obligations

For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Prior period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.

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Acquisitions and Dispositions

3 Months Ended

Mar. 31, 2019

Business Combinations [Abstract]

Acquisitions and Dispositions

Acquisitions and Dispositions

2019 Acquisitions

During the first quarter of 2019, the Company completed various acquisitions and dispositions of additional working interests and acreage located in our existing core operating areas within the Permian Basin. The Company purchased mineral rights for $21,407 in the Spur operating area and received proceeds of $14,084 for certain leasehold interests in our WildHorse acreage, including customary purchase price adjustments.

2018 Acquisitions

On August 31, 2018, the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for $539,519, including customary purchase price adjustments (the “Delaware Asset Acquisition”). The Company issued debt and equity to fund, in part, the Delaware Asset Acquisition. See Notes 5 and 9 for additional information regarding the Company’s debt obligations and equity offerings. The following table summarizes the estimated acquisition date fair values of the acquisition:

Evaluated oil and natural gas properties	$	253,089
Unevaluated oil and natural gas properties	287,000
Asset retirement obligations	(570		)
Net assets acquired	$	539,519

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.

In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian Basin. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for $37,770, including customary purchase price adjustments. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for $87,865, including customary purchase price adjustments.

Subsequent Event

On April 8, 2019, the Company entered into a definitive agreement regarding the sale of certain non-core assets, the Ranger assets, in the Midland Basin for initial cash proceeds of $260,000, excluding customary purchase price adjustments. The agreement also provides for potential contingency payments of up to $60,000 based on WTI average annual pricing over a three-year period.

The sale of the Company’s Ranger assets will not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds will be recorded as adjustments to our full cost pool with no gain or loss recognized. We expect the transaction to close in the second quarter of 2019.

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Earnings Per Share

3 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

Earnings Per Share

EarningsPer Share

Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share:

(share amounts in thousands)	Three Months Ended March 31,
	2019			2018
Net income (loss)	$	(19,543	)	$	55,761
Preferred stock dividends	(1,824		)	(1,824		)
Income (loss) available to common stockholders	$	(21,367	)	$	53,937
Weighted average common shares outstanding	227,784			201,921
Dilutive impact of restricted stock	—			667
Weighted average common shares outstanding for diluted income per share	227,784			202,588
Basic income per share	$	(0.09	)	$	0.27
Diluted income per share	$	(0.09	)	$	0.27
Restricted stock (a)	356			3

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

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Borrowings

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Borrowings

Borrowings

The Company’s borrowings consisted of the following:

	As of
Principal components:	March 31, 2019			December 31, 2018
Senior secured revolving credit facility	$	330,000		$	200,000
6.125% senior unsecured notes due 2024	600,000			600,000
6.375% senior unsecured notes due 2026	400,000			400,000
Total principal outstanding	1,330,000			1,200,000
Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization	6,187			6,469
Unamortized deferred financing costs	(16,320		)	(16,996		)
Total carrying value of borrowings (a)	$	1,319,867		$	1,189,473

(a) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $5,742 and $6,087 as of March 31, 2019 and December 31, 2018, respectively.

Senior secured revolving credit facility (the “Credit Facility”)

On May 25, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility 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) amended various covenants and terms to reflect current market trends, 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) increased the elected commitment amount to $850,000, and (3) amended various covenants and terms to reflect current market trends. As of March 31, 2019, the Credit Facility’s borrowing base remained at $1,100,000 with an elected commitment amount of $850,000.

As of March 31, 2019, there was $330,000 principal and $17,675 in letters of credit outstanding under the Credit Facility. For the period ended March 31, 2019, the Credit Facility had a weighted-average interest rate of 4.00%, calculated as the LIBOR plus a tiered rate ranging from 1.25% to 2.25%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a current commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base. Effective May 1, 2019, the Company entered into the third amendment (the “Third Amendment”) to the Sixth Amended and Restated Credit Agreement to the Credit Facility to, among other things: (i) reaffirm the borrowing base at $1,100,000, excluding the Ranger assets; and (ii) amend various covenants and terms to reflect current market trends.

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 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.

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.

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 March 31, 2019.

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Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2019

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 and put and call options to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.

Counterparty risk and offsetting

The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 7 for additional information regarding fair value.

The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.

Financial statement presentation and settlements

Settlements of the Company’s 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	3/31/2019		12/31/2018		3/31/2019			12/31/2018			3/31/2019			12/31/2018
Oil	Current	Fair value of derivatives	$	7,473	$	60,097	$	(24,550	)	$	(10,480	)	$	(17,077	)	$	49,617
Oil	Non-current	Fair value of derivatives	385		—		(6,190		)	(5,672		)	(5,805		)	(5,672		)
Natural gas	Current	Fair value of derivatives	3,899		5,017		—			—			3,899			5,017
Natural gas	Non-current	Fair value of derivatives	—		—		(793		)	(1,768		)	(793		)	(1,768		)
Totals			$	11,757	$	65,114	$	(31,533	)	$	(17,920	)	$	(19,776	)	$	47,194

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:

	As of March 31, 2019
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	20,540		$	(9,168	)	$	11,372
Long-term assets: Fair value of derivatives	829			(444		)	385
Current liabilities: Fair value of derivatives	$	(33,718	)	$	9,168		$	(24,550	)
Long-term liabilities: Fair value of derivatives	(7,427		)	444			(6,983		)

	As of December 31, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	78,091		$	(12,977	)	$	65,114
Current liabilities: Fair value of derivatives	$	(23,457	)	$	12,977		$	(10,480	)
Long-term liabilities: Fair value of derivatives	(7,440		)	—			(7,440		)

For the periods indicated, the Company recorded the following in the consolidated statements of operations as a gain or loss on derivative contracts:

	Three Months Ended March 31,
	2019			2018
Oil derivatives
Net loss on settlements	$	(1,542	)	$	(8,916	)
Net gain (loss) on fair value adjustments	(66,827		)	4,067
Total loss on oil derivatives	(68,369		)	(4,849		)
Natural gas derivatives
Net gain on settlements	1,252			457
Net loss on fair value adjustments	(143		)	(89		)
Total gain on natural gas derivatives	1,109			368
Total loss on oil & natural gas derivatives	$	(67,260	)	$	(4,481	)

Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of March 31, 2019:  

	For the Remainder			For the Full Year
Oil contracts (WTI)	of 2019			of 2020
Puts
Total volume (Bbls)	687,500			—
Weighted average price per Bbl	$	65.00		$	—
Put spreads
Total volume (Bbls)	687,500			—
Weighted average price per Bbl
Floor (long put)	$	65.00		$	—
Floor (short put)	$	42.50		$	—
Collar contracts combined with short puts (three-way collars)
Total volume (Bbls)	3,484,000			915,000
Weighted average price per Bbl
Ceiling (short call)	$	67.56		$	65.02
Floor (long put)	$	56.58		$	55.00
Floor (short put)	$	43.62		$	45.00
Collar contracts (two-way collars)
Total volume (Bbls)	—			732,000
Weighted average price per Bbl
Ceiling (short call)	$	—		$	64.63
Floor (long put)	$	—		$	55.00
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	5,102,000			4,576,000
Weighted average price per Bbl	$	(3.95	)	$	(1.29	)
Natural gas contracts (Henry Hub)
Collar contracts (two-way collars)
Total volume (MMBtu)	2,697,500			—
Weighted average price per MMBtu
Ceiling (short call)	$	3.68		$	—
Floor (long put)	$	3.09		$	—
Swap contracts
Total volume (MMBtu)	1,852,000			—
Weighted average price per MMBtu	$	2.88		—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	5,961,000			4,758,000
Weighted average price per MMBtu	$	(1.19	)	$	(1.12	)

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Fair Value Measurements

3 Months Ended

Mar. 31, 2019

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.

	March 31, 2019				December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit Facility (a)	$	330,000	$	330,000	$	200,000	$	200,000
6.125% Senior Notes (b)	595,971		604,008		595,788		558,000
6.375% Senior Notes (b)	393,896		402,264		393,685		372,000
Total	$	1,319,867	$	1,336,272	$	1,189,473	$	1,130,000

(a) Floating-rate debt.

(b) The fair value was based upon Level 2 inputs. See Note 5 for additional information about the Company’s 6.125% and 6.375% Senior Notes.

Assets and liabilities measured at fair value on a recurring basis

Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value:

Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 6 for additional information regarding the Company’s derivative instruments.

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

March 31, 2019	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	11,757		$	—	$	11,757
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(31,533		)	—		(31,533		)
Total net assets (liabilities)		$	—	$	(19,776	)	$	—	$	(19,776	)
December 31, 2018	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	65,114		$	—	$	65,114
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(17,920		)	—		(17,920		)
Total net assets		$	—	$	47,194		$	—	$	47,194

Assets 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 were based on Level 1, Level 2 and Level 3 inputs.

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Income Taxes

3 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations:

	Three Months Ended
Components of income tax rate reconciliation	March 31, 2019		March 31, 2018
Income tax expense computed at the statutory federal income tax rate	21	%	21	%
State taxes net of federal expense	1	%	1	%
Section 162(m)	1	%	—	%
Valuation allowance	—	%	(21	)%
Effective income tax rate, before discrete items	23	%	1	%
Discrete items (a)	(2	)%	—	%
Effective income tax rate, after discrete items	21	%	1	%

(a) Accounts for the potential impact of periodic volatility of stock-based compensation tax deductions on future effective tax rates.

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Equity Transactions

3 Months Ended

Mar. 31, 2019

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 of $1,824 for the three months ended March 31, 2019 remained consistent compared to the same period of 2018.

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 March 31, 2019, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $7.55 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 6.6 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 25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering costs) of approximately $287,988. The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter of 2018, described in Note 3.

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Leases

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Leases

Leases

As previously described in Note 1 - Summary of Significant Accounting Policies, we lease certain office space, office equipment, production facilities, compressors, drilling rigs, vehicles and other ancillary drilling equipment under cancelable and non-cancelable leases to support our operations. The following tables reflect the current period impact of our adoption of the new leases standard. As we have no leases that meet the criteria for classification as a finance lease, all information contained herein represents our operating leases.

The components of our total lease cost were as follows:

	Three Months Ended
	March 31, 2019
Operating lease cost	$	9,565
Short-term lease cost (a)	$	1,498

(a) Short-term lease cost excludes expenses related to leases with a contract term of one month or less.

Supplemental balance sheet information related to our operating leases is included in the table below:

	As of March 31, 2019
Operating lease right-of-use assets	$	40,977
Current operating lease liabilities	29,134
Operating lease liabilities	11,751
Total operating lease liabilities	$	40,885

As of March 31, 2019, our weighted average remaining lease term and our weighted average discount rate for our operating leases were 1.6 years and 4.02%, respectively.

Our operating lease liabilities with enforceable contract terms that are greater than one year mature as follows:

	As of March 31, 2019
Remainder of 2019	$	25,505
2020	13,765
2021	1,573
2022	534
2023	517
Thereafter	388
Total lease payments	42,282
Less imputed interest	1,397
Total	$	40,885

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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2019

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

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

	Three Months Ended
	March 31, 2019
Asset retirement obligations at January 1, 2019	$	14,292
Accretion expense	241
Liabilities incurred	111
Liabilities settled	(618		)
Dispositions	(87		)
Revisions to estimate	21
Asset retirement obligations at end of period	13,960
Less: Current asset retirement obligations	(3,771		)
Long-term asset retirement obligations at March 31, 2019	$	10,189

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at March 31, 2019 as long-term restricted investments were $3,450. 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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Other

3 Months Ended

Mar. 31, 2019

Other [Abstract]

Other

Other

Other commitments

In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard, 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.

In January 2019, the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard, Ward, and Reagan counties and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. We will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

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Description of Business and Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of presentation

Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data.

The interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of Callon Petroleum Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has a subsidiary, namely Mississippi Marketing, Inc. Effective February 28, 2019, Callon Offshore Production, Inc. was merged with and into Callon Petroleum Operating Company.

These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2018. The balance sheet at December 31, 2018 has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2019.

In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, results of operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.

Summary of Significant Accounting Policies and Accounting Standards Updates (ASUs)

Summary of Significant Accounting Policies

Leases

We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. Based on our evaluation of leases for the three months ended March, 31, 2019, we have no leases that meet the criteria for classification as a finance lease. We capitalize operating leases on our consolidated balance sheets through a right-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments arising from the lease.

Operating leases are included in operating lease ROU assets, current operating lease liabilities, and long-term operating lease liabilities in our consolidated balance sheets.Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

Nature of Leases

In support of our operations, we lease certain drilling rigs, office space, office equipment, production facilities, compressors, vehicles and other ancillary drilling equipment under cancelable and non-cancelable contracts. A more detailed description of our material lease types is included below.

Drilling Rigs

The Company enters into daywork and long-term contracts for drilling rigs with third party service contractors to support the development of undeveloped reserves. Our daywork drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells, well pads or contractually stated extension terms by providing 30 days’ notice prior to the end of the original contract term.

The Company’s long-term drilling contracts are generally structured with an initial non-cancelable term of one to two years. We have concluded that our long-term drilling rig arrangements represent operating leases with a lease term greater than twelve months. Additionally, we have concluded that our daywork drilling rig arrangements represent short-term operating leases with a lease term that equals the period of time required to complete drilling operations on the contractually specified well or well pad (that is, generally one to a few months from commencement of drilling).

We do not include the option to extend the drilling rig contract in the lease term due to the continuously evolving nature of our drilling schedules, which requires significant flexibility in the structure of the term of these arrangements, and the potential volatility in commodity prices in an annual period. We have further elected to apply the practical expedient for short-term leases to our daywork drilling rig leases. Accordingly, we do not apply the lease recognition requirements to our daywork drilling rig contracts, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term.

Corporate and Field Offices

We enter into long-term contracts to lease corporate and field office space in support of company operations. These contracts are generally structured with an initial non-cancelable term of two to five years. To the extent that our corporate and field office contracts include renewal options, we evaluate whether we are reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. We have further determined that our current corporate and field office leases represent operating leases.

Transportation, Gathering and Processing Arrangements

We engage in various types of transactions in which midstream entities transport, gather and/or process our product leveraging integrated systems and facilities wholly-owned and operated by the midstream counterparty. Under most of these arrangements, we do not utilize substantially all of the underlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an identified asset.

Accounting Standards Updates (“ASUs”)

Recently adopted ASUs - Leases

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”).

ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.

The new standard was effective for us in the first quarter of 2019, and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized the cumulative effect of adoption in retained earnings as of January 1, 2019. We further utilized the package of practical expedients at transition to not reassess the following:

• Whether any expired or existing contracts were or contained leases;

• The lease classification for any expired or existing leases; and

• Initial direct costs for any existing leases.

Additionally, we elected the practical expedient under ASU 2018-01, which did not require us to evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. We also chose not to separate lease and non-lease components for the various classes of underlying assets. In addition, for all of our asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases. Accordingly, we recognize lease payments related to our short-term leases in profit or loss on a straight-line basis over the lease term.

Through our implementation process, we evaluated each of our lease arrangements and enhanced our systems to track and calculate additional information required upon adoption of this standard. The standard had an impact on our consolidated balance sheet at March 31, 2019, resulting from the recognition of right-of-use assets and lease liabilities for operating leases. We have no leases that meet the criteria for classification as a finance lease. See Note 10 for additional information regarding the impact of adoption of the new leases standard on our current period results.

Adoption of the new leases standard did not impact our consolidated statement of operations or cash provided from or used in operating, investing or financing in our consolidated statement of cash flows.

We note that the standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.

Recently adopted ASUs - Other

In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the timing and measurement of nonemployee awards. The Company adopted this update on January 1, 2019 and it did not have a material impact on its consolidated financial statements upon adoption of this guidance.

Recently issued ASUs

In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements (“ASU 2019-01”). The standard is intended to clarify the requirements related to interim transition disclosures upon adoption of ASC Topic 842. The guidance in ASU 2019-01 is effective for public entities for annual reporting periods beginning after December 15, 2019, including interim periods therein. The Company does not expect a material impact on its consolidated financial statements upon adoption of this guidance.

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Acquisitions and Dispositions (Tables)

3 Months Ended

Mar. 31, 2019

Business Combinations [Abstract]

Fair Value of Net Assets Acquired

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

Evaluated oil and natural gas properties	$	253,089
Unevaluated oil and natural gas properties	287,000
Asset retirement obligations	(570		)
Net assets acquired	$	539,519

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings Per Share

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

(share amounts in thousands)	Three Months Ended March 31,
	2019			2018
Net income (loss)	$	(19,543	)	$	55,761
Preferred stock dividends	(1,824		)	(1,824		)
Income (loss) available to common stockholders	$	(21,367	)	$	53,937
Weighted average common shares outstanding	227,784			201,921
Dilutive impact of restricted stock	—			667
Weighted average common shares outstanding for diluted income per share	227,784			202,588
Basic income per share	$	(0.09	)	$	0.27
Diluted income per share	$	(0.09	)	$	0.27
Restricted stock (a)	356			3

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

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Borrowings (Tables)

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Schedule of Borrowings

The Company’s borrowings consisted of the following:

	As of
Principal components:	March 31, 2019			December 31, 2018
Senior secured revolving credit facility	$	330,000		$	200,000
6.125% senior unsecured notes due 2024	600,000			600,000
6.375% senior unsecured notes due 2026	400,000			400,000
Total principal outstanding	1,330,000			1,200,000
Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization	6,187			6,469
Unamortized deferred financing costs	(16,320		)	(16,996		)
Total carrying value of borrowings (a)	$	1,319,867		$	1,189,473

(a) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $5,742 and $6,087 as of March 31, 2019 and December 31, 2018, respectively.

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Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2019

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	3/31/2019		12/31/2018		3/31/2019			12/31/2018			3/31/2019			12/31/2018
Oil	Current	Fair value of derivatives	$	7,473	$	60,097	$	(24,550	)	$	(10,480	)	$	(17,077	)	$	49,617
Oil	Non-current	Fair value of derivatives	385		—		(6,190		)	(5,672		)	(5,805		)	(5,672		)
Natural gas	Current	Fair value of derivatives	3,899		5,017		—			—			3,899			5,017
Natural gas	Non-current	Fair value of derivatives	—		—		(793		)	(1,768		)	(793		)	(1,768		)
Totals			$	11,757	$	65,114	$	(31,533	)	$	(17,920	)	$	(19,776	)	$	47,194

Schedule of Offsetting Assets

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

	As of March 31, 2019
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	20,540		$	(9,168	)	$	11,372
Long-term assets: Fair value of derivatives	829			(444		)	385
Current liabilities: Fair value of derivatives	$	(33,718	)	$	9,168		$	(24,550	)
Long-term liabilities: Fair value of derivatives	(7,427		)	444			(6,983		)

	As of December 31, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	78,091		$	(12,977	)	$	65,114
Current liabilities: Fair value of derivatives	$	(23,457	)	$	12,977		$	(10,480	)
Long-term liabilities: Fair value of derivatives	(7,440		)	—			(7,440		)

Schedule of Offsetting Liabilities

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

	As of March 31, 2019
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	20,540		$	(9,168	)	$	11,372
Long-term assets: Fair value of derivatives	829			(444		)	385
Current liabilities: Fair value of derivatives	$	(33,718	)	$	9,168		$	(24,550	)
Long-term liabilities: Fair value of derivatives	(7,427		)	444			(6,983		)

	As of December 31, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of derivatives	$	78,091		$	(12,977	)	$	65,114
Current liabilities: Fair value of derivatives	$	(23,457	)	$	12,977		$	(10,480	)
Long-term liabilities: Fair value of derivatives	(7,440		)	—			(7,440		)

Schedule of Gain or Loss on Derivative Contracts

For the periods indicated, the Company recorded the following in the consolidated statements of operations as a gain or loss on derivative contracts:

	Three Months Ended March 31,
	2019			2018
Oil derivatives
Net loss on settlements	$	(1,542	)	$	(8,916	)
Net gain (loss) on fair value adjustments	(66,827		)	4,067
Total loss on oil derivatives	(68,369		)	(4,849		)
Natural gas derivatives
Net gain on settlements	1,252			457
Net loss on fair value adjustments	(143		)	(89		)
Total gain on natural gas derivatives	1,109			368
Total loss on oil & natural gas derivatives	$	(67,260	)	$	(4,481	)

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 March 31, 2019:  

	For the Remainder			For the Full Year
Oil contracts (WTI)	of 2019			of 2020
Puts
Total volume (Bbls)	687,500			—
Weighted average price per Bbl	$	65.00		$	—
Put spreads
Total volume (Bbls)	687,500			—
Weighted average price per Bbl
Floor (long put)	$	65.00		$	—
Floor (short put)	$	42.50		$	—
Collar contracts combined with short puts (three-way collars)
Total volume (Bbls)	3,484,000			915,000
Weighted average price per Bbl
Ceiling (short call)	$	67.56		$	65.02
Floor (long put)	$	56.58		$	55.00
Floor (short put)	$	43.62		$	45.00
Collar contracts (two-way collars)
Total volume (Bbls)	—			732,000
Weighted average price per Bbl
Ceiling (short call)	$	—		$	64.63
Floor (long put)	$	—		$	55.00
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	5,102,000			4,576,000
Weighted average price per Bbl	$	(3.95	)	$	(1.29	)
Natural gas contracts (Henry Hub)
Collar contracts (two-way collars)
Total volume (MMBtu)	2,697,500			—
Weighted average price per MMBtu
Ceiling (short call)	$	3.68		$	—
Floor (long put)	$	3.09		$	—
Swap contracts
Total volume (MMBtu)	1,852,000			—
Weighted average price per MMBtu	$	2.88		—
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	5,961,000			4,758,000
Weighted average price per MMBtu	$	(1.19	)	$	(1.12	)

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Summary of Financial Instruments at Carrying and Fair Value

The carrying amount of the Company’s floating-rate debt approximated fair value, because the interest rates were variable and reflective of market rates.

	March 31, 2019				December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit Facility (a)	$	330,000	$	330,000	$	200,000	$	200,000
6.125% Senior Notes (b)	595,971		604,008		595,788		558,000
6.375% Senior Notes (b)	393,896		402,264		393,685		372,000
Total	$	1,319,867	$	1,336,272	$	1,189,473	$	1,130,000

(a) Floating-rate debt.

(b) The fair value was based upon Level 2 inputs. See Note 5 for additional information about the Company’s 6.125% and 6.375% Senior Notes.

Fair Value of Assets and Liabilities Measured on Recurring Basis

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

March 31, 2019	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	11,757		$	—	$	11,757
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(31,533		)	—		(31,533		)
Total net assets (liabilities)		$	—	$	(19,776	)	$	—	$	(19,776	)
December 31, 2018	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	65,114		$	—	$	65,114
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(17,920		)	—		(17,920		)
Total net assets		$	—	$	47,194		$	—	$	47,194

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation

The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations:

	Three Months Ended
Components of income tax rate reconciliation	March 31, 2019		March 31, 2018
Income tax expense computed at the statutory federal income tax rate	21	%	21	%
State taxes net of federal expense	1	%	1	%
Section 162(m)	1	%	—	%
Valuation allowance	—	%	(21	)%
Effective income tax rate, before discrete items	23	%	1	%
Discrete items (a)	(2	)%	—	%
Effective income tax rate, after discrete items	21	%	1	%

(a) Accounts for the potential impact of periodic volatility of stock-based compensation tax deductions on future effective tax rates.

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Leases (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Lease, Cost

The components of our total lease cost were as follows:

	Three Months Ended
	March 31, 2019
Operating lease cost	$	9,565
Short-term lease cost (a)	$	1,498

(a) Short-term lease cost excludes expenses related to leases with a contract term of one month or less.

Assets And Liabilities, Lessee

Supplemental balance sheet information related to our operating leases is included in the table below:

	As of March 31, 2019
Operating lease right-of-use assets	$	40,977
Current operating lease liabilities	29,134
Operating lease liabilities	11,751
Total operating lease liabilities	$	40,885

Lessee, Operating Lease, Liability, Maturity

Our operating lease liabilities with enforceable contract terms that are greater than one year mature as follows:

	As of March 31, 2019
Remainder of 2019	$	25,505
2020	13,765
2021	1,573
2022	534
2023	517
Thereafter	388
Total lease payments	42,282
Less imputed interest	1,397
Total	$	40,885

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2019

Asset Retirement Obligation [Abstract]

Summary of Activity of Asset Retirement Obligations

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

	Three Months Ended
	March 31, 2019
Asset retirement obligations at January 1, 2019	$	14,292
Accretion expense	241
Liabilities incurred	111
Liabilities settled	(618		)
Dispositions	(87		)
Revisions to estimate	21
Asset retirement obligations at end of period	13,960
Less: Current asset retirement obligations	(3,771		)
Long-term asset retirement obligations at March 31, 2019	$	10,189

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Description of Business and Basis of Presentation (Details)	3 Months Ended
	Mar. 31, 2019
Drilling Rigs
Lessee, Lease, Description [Line Items]
Extension period notice	30 days
Drilling Rigs | Minimum
Lessee, Lease, Description [Line Items]
Term of contract	1 year
Drilling Rigs | Maximum
Lessee, Lease, Description [Line Items]
Term of contract	2 years
Offices | Minimum
Lessee, Lease, Description [Line Items]
Term of contract	2 years
Offices | Maximum
Lessee, Lease, Description [Line Items]
Term of contract	5 years

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Revenue Recognition (Gathering and Treating Fees) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Accounts Receivable
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Contract with customer, asset, gross, current	$ 98,568		$ 87,061
Natural Gas, Gathering and Treating Fees | Natural Gas Revenue
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of goods and services sold	$ 2,408
Natural Gas, Gathering and Treating Fees | Lease Operating Expense
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of goods and services sold		$ 1,252

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Revenue Recognition (Performance Obligation) (Details)	3 Months Ended
	Mar. 31, 2019
Revenue from Contract with Customer [Abstract]
Performance obligation, description of timing	The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product.

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Acquisitions and Dispositions (Narrative) (Details) a in Thousands, $ in Thousands		3 Months Ended
	Aug. 31, 2018 USD ($) a	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Mar. 31, 2018 USD ($)
WildHorse acreage
Business Acquisition [Line Items]
Proceeds from leasehold interest		$ (14,084)
Spur operating areas
Business Acquisition [Line Items]
Consideration transferred		$ 21,407
Cimarex Energy Company
Business Acquisition [Line Items]
Consideration transferred	$ 539,519
Gas and oil area, developed and undeveloped, net (in acres) | a	28
Monarch and Wildhorse
Business Acquisition [Line Items]
Consideration transferred				$ 37,770
Wildhorse and Spur
Business Acquisition [Line Items]
Consideration transferred			$ 87,865

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

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Acquisitions and Dispositions (Subsequent Event) (Details) - Subsequent Event - Certain Non-core Assets in the Midland Basin $ in Thousands	Apr. 08, 2019 USD ($)
Subsequent Event [Line Items]
Consideration	$ 260,000
Potential contingency payments	$ 60,000
Potential contingency payments, period	3 years

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Earnings Per Share, Basic and Diluted
Net income	$ (19,543)	$ 55,761
Preferred stock dividends	(1,824)	(1,824)
Income (loss) available to common stockholders	$ (21,367)	$ 53,937
Weighted average common shares outstanding (in shares)	227,784	201,921
Dilutive impact of restricted stock (in shares)	0	667
Weighted average common shares outstanding for diluted income per share (in shares)	227,784	202,588
Basic income per share (in dollars per share)	$ (0.09)	$ 0.27
Diluted income per share (in dollars per share)	$ (0.09)	$ 0.27
Restricted Stock
Earnings Per Share, Basic and Diluted
Excluded from the diluted EPS calculation because their effect would be anti-dilutive (in shares)	356	3

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Borrowings (Schedule of Borrowings) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Principal components:
Total principal outstanding	$ 1,330,000	$ 1,200,000
Premium on senior unsecured notes, net of accumulated amortization	6,187	6,469
Unamortized deferred financing costs	(16,320)	(16,996)
Total carrying value of borrowings (a)	1,319,867	1,189,473
Deferred financing costs	5,742	6,087
Senior secured revolving credit facility
Principal components:
Total principal outstanding	330,000	200,000
6.125% senior unsecured notes due 2024
Principal components:
Total principal outstanding	$ 600,000	600,000
Debt instrument, interest rate, stated (as a percent)	6.125%
6.375% senior unsecured notes due 2026
Principal components:
Total principal outstanding	$ 400,000	$ 400,000
Debt instrument, interest rate, stated (as a percent)	6.375%

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Borrowings (Credit Facility) (Narrative) (Details)	3 Months Ended
	Mar. 31, 2019 USD ($)	May 01, 2019 USD ($)	Dec. 31, 2018 USD ($)	Sep. 27, 2018 USD ($)	Apr. 05, 2018 USD ($)	May 25, 2017 USD ($) lender
Line of Credit Facility [Line Items]
Balance outstanding on credit facility	$ 330,000,000		$ 200,000,000
Senior secured revolving credit facility | Secured debt
Line of Credit Facility [Line Items]
Institutional lenders | lender						17
Maximum borrowing capacity						$ 2,000,000,000
Credit facility borrowing base	1,100,000,000			$ 1,100,000,000	$ 825,000,000
Increase limit	850,000,000			$ 850,000,000	$ 650,000,000
Balance outstanding on credit facility	330,000,000
Letters of credit outstanding	$ 17,675,000
Interest rate at period end (as a percent)	4.00%
Unused capacity, commitment fee (as a percent)	0.375%
Senior secured revolving credit facility | Secured debt | Subsequent Event
Line of Credit Facility [Line Items]
Credit facility borrowing base		$ 1,100,000
Senior secured revolving credit facility | Secured debt | Minimum
Line of Credit Facility [Line Items]
Debt instrument interest rate (as a percent)	1.25%
Senior secured revolving credit facility | Secured debt | Maximum
Line of Credit Facility [Line Items]
Debt instrument interest rate (as a percent)	2.25%

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Borrowings (6.125% Senior Notes) (Narrative) (Details) - USD ($)	May 19, 2017	Oct. 03, 2016	Mar. 31, 2019
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, interest rate, stated (as a percent)			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%
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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Borrowings (6.375% Senior Notes) (Details) - USD ($)	Jun. 07, 2018	Mar. 31, 2019
Unsecured debt | Callon Petroleum Operating Company
Debt Instrument [Line Items]
Percentage of ownership in wholly-owned subsidiary (as a percent)		100.00%
6.375% senior unsecured notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)		6.375%
6.375% senior unsecured notes due 2026 | 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
6.375% senior unsecured notes due 2026 | Unsecured debt | Change Of Control
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	101.00%
6.375% senior unsecured notes due 2026 | 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%
6.375% senior unsecured notes due 2026 | 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%
6.375% senior unsecured notes due 2026 | 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%
6.375% senior unsecured notes due 2026 | 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%
6.375% senior unsecured notes due 2026 | 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%
6.375% senior unsecured notes due 2026 | 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%
6.375% senior unsecured notes due 2026 | 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%
6.375% senior unsecured notes due 2026 | 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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Derivative Instruments and Hedging Activities (Fair Value of Derivative Instruments) (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Asset Fair Value	$ 11,757	$ 65,114
Liability Fair Value	(31,533)	(17,920)
Net Derivative Fair Value	(19,776)	47,194
Current assets: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Asset Fair Value	11,372	65,114
Current liabilities: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Liability Fair Value	(24,550)	(10,480)
Long-term assets: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Asset Fair Value	385
Long-term liabilities: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Liability Fair Value	(6,983)	(7,440)
Oil | Current assets: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Asset Fair Value	7,473	60,097
Oil | Current liabilities: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Liability Fair Value	(24,550)	(10,480)
Oil | Current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	(17,077)	49,617
Oil | Long-term assets: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Asset Fair Value	385	0
Oil | Long-term liabilities: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Liability Fair Value	(6,190)	(5,672)
Oil | Non-current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	(5,805)	(5,672)
Natural gas | Current assets: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Asset Fair Value	3,899	5,017
Natural gas | Current liabilities: Fair value of derivatives
Derivatives, Fair Value [Line Items]
Liability Fair Value	0	0
Natural gas | Current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	3,899	5,017
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	(793)	(1,768)
Natural gas | Non-current
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	$ (793)	$ (1,768)

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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	Mar. 31, 2019	Dec. 31, 2018
Offsetting Assets and Liabilities [Line Items]
Derivative asset	$ 11,757	$ 65,114
Derivative liability	(31,533)	(17,920)
Current assets: Fair value of derivatives
Offsetting Assets and Liabilities [Line Items]
Derivative asset, fair value, gross asset	20,540	78,091
Derivative asset, fair value, gross liability	(9,168)	(12,977)
Derivative asset	11,372	65,114
Long-term assets: Fair value of derivatives
Offsetting Assets and Liabilities [Line Items]
Derivative asset, fair value, gross asset	829
Derivative asset, fair value, gross liability	(444)
Derivative asset	385
Current liabilities: Fair value of derivatives
Offsetting Assets and Liabilities [Line Items]
Derivative liability, fair value, gross liability	(33,718)	(23,457)
Derivative liability, fair value, gross asset	9,168	12,977
Derivative liability	(24,550)	(10,480)
Long-term liabilities: Fair value of derivatives
Offsetting Assets and Liabilities [Line Items]
Derivative liability, fair value, gross liability	(7,427)	(7,440)
Derivative liability, fair value, gross asset	444	0
Derivative liability	$ (6,983)	$ (7,440)

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Derivative Instruments and Hedging Activities (Schedule of Gain or Loss on Derivative Contracts) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on fair value adjustments	$ (66,970)	$ 3,978
Total gain (loss) on oil & natural gas derivatives	(67,260)	(4,481)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on oil & natural gas derivatives	(67,260)	(4,481)
Not Designated as Hedging Instrument | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	(1,542)	(8,916)
Net gain (loss) on fair value adjustments	(66,827)	4,067
Total gain (loss) on oil & natural gas derivatives	(68,369)	(4,849)
Not Designated as Hedging Instrument | Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	1,252	457
Net gain (loss) on fair value adjustments	(143)	(89)
Total gain (loss) on oil & natural gas derivatives	$ 1,109	$ 368

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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	9 Months Ended	12 Months Ended
	Dec. 31, 2019 MMBTU $ / bbl $ / MMBTU bbl	Dec. 31, 2020 MMBTU $ / bbl $ / MMBTU bbl
Oil | Put spreads
Derivative [Line Items]
Total volume (Bbls) | bbl	687,500	0
Oil | Collar contracts combined with short puts (three-way collars)
Derivative [Line Items]
Total volume (Bbls) | bbl	3,484,000	915,000
Oil | Collar contracts (two-way collars)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	732,000
Oil | Oil contracts (Midland basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl	5,102,000	4,576,000
Weighted average swap price (in dollars per share)	(3.95)	(1.29)
Oil | Put option
Derivative [Line Items]
Total volume (Bbls) | bbl	687,500	0
Strike price (in dollars per share)	65	0
Oil | Put option | Put spreads | Long
Derivative [Line Items]
Strike price (in dollars per share)	65	0
Oil | Put option | Put spreads | Short
Derivative [Line Items]
Strike price (in dollars per share)	42.50	0
Oil | Put option | Collar contracts combined with short puts (three-way collars) | Long
Derivative [Line Items]
Strike price (in dollars per share)	56.58	55
Oil | Put option | Collar contracts combined with short puts (three-way collars) | Short
Derivative [Line Items]
Strike price (in dollars per share)	43.62	45
Oil | Put option | Collar contracts (two-way collars) | Long
Derivative [Line Items]
Strike price (in dollars per share)	0	55
Oil | Call option | Collar contracts combined with short puts (three-way collars) | Short
Derivative [Line Items]
Strike price (in dollars per share)	67.56	65.02
Oil | Call option | Collar contracts (two-way collars) | Short
Derivative [Line Items]
Strike price (in dollars per share)	0	64.63
Natural gas | Swap contracts
Derivative [Line Items]
Strike price (in dollars per share) | $ / MMBTU	2.88	0
Total volume (MMBtu) | MMBTU	1,852,000	0
Natural gas | Collar contracts (two-way collars)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	2,697,500	0
Natural gas | Collar contracts (two-way collars) | Long
Derivative [Line Items]
Strike price (in dollars per share) | $ / MMBTU	3.09	0
Natural gas | Collar contracts (two-way collars) | Short
Derivative [Line Items]
Strike price (in dollars per share) | $ / MMBTU	3.68	0
Natural gas | Waha basis differential | Swap contracts
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	5,961,000	4,758,000
Weighted average swap price (in dollars per share) | $ / MMBTU	(1.19)	(1.12)

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Fair Value Measurements (Summary of Financial Instruments at Carrying and Fair Value) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018	Jun. 07, 2018	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% 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	$ 330,000	$ 200,000
Total	1,319,867	1,189,473
Carrying Value | 6.125% senior unsecured notes due 2024 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	595,971	595,788
Carrying Value | 6.375% senior unsecured notes due 2026 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	393,896	393,685
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Credit Facility	330,000	200,000
Total	1,336,272	1,130,000
Fair Value | 6.125% senior unsecured notes due 2024 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	604,008	558,000
Fair Value | 6.375% senior unsecured notes due 2026 | Unsecured debt
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	$ 402,264	$ 372,000

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Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - Recurring Basis - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Assets
Derivative financial instruments	$ 11,757	$ 65,114
Liabilities
Derivative financial instruments	(31,533)	(17,920)
Net Derivative Fair Value	(19,776)	47,194
Level 1
Assets
Derivative financial instruments	0	0
Liabilities
Derivative financial instruments	0	0
Net Derivative Fair Value	0	0
Level 2
Assets
Derivative financial instruments	11,757	65,114
Liabilities
Derivative financial instruments	(31,533)	(17,920)
Net Derivative Fair Value	(19,776)	47,194
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)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Components of income tax rate reconciliation
Income tax expense computed at the statutory federal income tax rate	21.00%	21.00%
State taxes net of federal expense	1.00%	1.00%
Section 162(m)	1.00%	0.00%
Valuation allowance	0.00%	(21.00%)
Effective income tax rate, before discrete items	23.00%	1.00%
Discrete items (a)	(2.00%)	0.00%
Effective income tax rate, before discrete items	21.00%	1.00%

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Equity Transactions (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended
	May 30, 2018	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Class of Stock [Line Items]
Preferred stock dividend		$ (1,824)	$ (1,824)
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
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)		$ 7.55
Conversion ratio of preferred stock to common stock		6.6
Shares of common stock issued in public offering (in shares)	25,300,000
Payment of preferred stock dividends	$ 287,988

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Leases (Cost) (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Leases [Abstract]
Operating lease cost	$ 9,565
Short-term lease cost	$ 1,498

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Leases (Balance Seets) (Details) $ in Thousands	Mar. 31, 2019 USD ($)
Leases [Abstract]
Operating lease right-of-use assets	$ 40,977
Current operating lease liabilities	29,134
Operating lease liabilities	11,751
Total operating lease liabilities	$ 40,885

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Leases (Narrative) (Details)	Mar. 31, 2019
Leases [Abstract]
Weighted average remaining lease term	1 year 7 months 6 days
Weighted average discount rate, percent	4.02%

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Leases (Maturities) (Details) $ in Thousands	Mar. 31, 2019 USD ($)
Leases [Abstract]
Remainder of 2019	$ 25,505
2020	13,765
2021	1,573
2022	534
2023	517
Thereafter	388
Total lease payments	42,282
Less imputed interest	1,397
Total	$ 40,885

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1, 2019	$ 14,292
Accretion expense	241	$ 218
Liabilities incurred	111
Liabilities settled	(618)
Dispositions	(87)
Revisions to estimate	21
Asset retirement obligations at end of period	13,960
Less: Current asset retirement obligations	(3,771)		$ (3,887)
Long-term asset retirement obligations at March 31, 2019	10,189		10,405
Restricted Investments
Restricted investments	$ 3,450		$ 3,424

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Other (Details) - bbl / d		1 Months Ended
	Aug. 06, 2018	Jan. 31, 2019
Other [Abstract]
Delivery commitments per day	15,000	10,000