10-Q

UNITED STATES

SECURITIES ANDEXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For The Quarterly Period Ended March 31, 2017

OR

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

For the transition period from ____________ to ____________

Commission File Number 001-14039

Callon Petroleum Company

(Exact Name of Registrant as Specified in Its Charter)

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

601-442-1601

(Registrant’s Telephone Number, Including Area Code)

Not Applicable

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).Yes  ☒No ☐

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

Large accelerated filer	☒	Accelerated filer	☐	Non-accelerated filer	☐	(Do not check if smaller reporting company)
Smaller reporting company	☐	Emerging growth company	☐

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

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

The Registrant had  201,061,366  shares of common stock outstanding as of April 28, 2017.

Table of Contents

Part I. Financial Information
Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheets	4
Consolidated Statements of Operations	5
Consolidated Statements of Cash Flows	6
Notes to Consolidated Financial Statements	7
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.  Quantitative and Qualitative Disclosures about Market Risk	28
Item 4.  Controls and Procedures	29
Part II.  Other Information
Item 1.  Legal Proceedings	30
Item 1A.  Risk Factors	30
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 3.  Defaults Upon Senior Securities	30
Item 4.  Mine Safety Disclosures	30
Item 5.  Other Information	30
Item 6.  Exhibits	31

2

DEFINITIONS

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.

· BBtu: billion Btu.

· 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.

· 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.

· LIBOR:  London Interbank Offered Rate.

· LOE:  lease operating expense.

· MBbls:  thousand barrels of oil.

· MBOE:  thousand BOE.

· MMBOE: million 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.

· SEC:  United States Securities and Exchange Commission.

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

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

3

Part I.  Financial Information

Item I.  Financial Statements

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par and per share values and share data)

	March 31, 2017		December 31, 2016
ASSETS		Unaudited
Current assets:
Cash and cash equivalents	$	35,273	$	652,993
Accounts receivable		75,959		69,783
Fair value of derivatives		3,093		103
Other current assets		1,671		2,247
Total current assets		115,996		725,126
Oil and natural gas properties, full cost accounting method:
Evaluated properties		3,009,059		2,754,353
Less accumulated depreciation, depletion, amortization and impairment		(1,972,091)		(1,947,673)
Net evaluated oil and natural gas properties		1,036,968		806,680
Unevaluated properties		1,154,850		668,721
Total oil and natural gas properties		2,191,818		1,475,401
Other property and equipment, net		18,067		14,114
Restricted investments		3,339		3,332
Deferred financing costs related to the senior secured revolving credit facility		2,744		3,092
Fair value of derivatives		2,939		—
Acquisition deposit		—		46,138
Other assets, net		676		384
Total assets	$	2,335,579	$	2,267,587
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	131,252	$	95,577
Accrued interest		12,114		6,057
Cash-settleable restricted stock unit awards		4,025		8,919
Asset retirement obligations		1,588		2,729
Fair value of derivatives		6,430		18,268
Total current liabilities		155,409		131,550
Senior secured revolving credit facility		—		—
6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs		390,536		390,219
Asset retirement obligations		4,652		3,932
Cash-settleable restricted stock unit awards		4,108		8,071
Deferred tax liability		556		90
Fair value of derivatives		—		28
Other long-term liabilities		285		295
Total liabilities		555,546		534,185
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 and 1,458,948 shares outstanding, respectively		15		15
Common stock, $0.01 par value, 300,000,000 and 300,000,000 shares authorized; 201,054,884 and 201,041,320 shares outstanding, respectively		2,011		2,010
Capital in excess of par value		2,173,243		2,171,514
Accumulated deficit		(395,236)		(440,137)
Total stockholders’ equity		1,780,033		1,733,402
Total liabilities and stockholders’ equity	$	2,335,579	$	2,267,587

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,
		2017		2016
Operating revenues:
Oil sales	$	72,008	$	27,443
Natural gas sales		9,355		3,255
Total operating revenues		81,363		30,698
Operating expenses:
Lease operating expenses		12,937		6,957
Production taxes		5,904		2,220
Depreciation, depletion and amortization		24,433		15,722
General and administrative		5,206		5,562
Accretion expense		184		180
Write-down of oil and natural gas properties		—		34,776
Acquisition expense		450		48
Total operating expenses		49,114		65,465
Income (loss) from operations		32,249		(34,767)
Other (income) expenses:
Interest expense, net of capitalized amounts		665		5,491
(Gain) loss on derivative contracts		(15,303)		932
Other income		(708)		(81)
Total other (income) expense		(15,346)		6,342
Income (loss) before income taxes		47,595		(41,109)
Income tax expense		466		—
Net income (loss)		47,129		(41,109)
Preferred stock dividends		(1,824)		(1,824)
Income (loss) available to common stockholders	$	45,305	$	(42,933)
Income (loss) per common share:
Basic	$	0.23	$	(0.51)
Diluted	$	0.22	$	(0.51)
Shares used in computing income (loss) per common share:
Basic		201,054		83,582
Diluted		201,740		83,582

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,
		2017		2016
Cash flows from operating activities:
Net income (loss)	$	47,129	$	(41,109)
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization		24,932		16,129
Write-down of oil and natural gas properties		—		34,776
Accretion expense		184		180
Amortization of non-cash debt related items		665		781
Deferred income tax expense		466		—
Net (gain) loss on derivatives, net of settlements		(17,794)		8,648
Non-cash expense related to equity share-based awards		930		516
Change in the fair value of liability share-based awards		(291)		709
Payments to settle asset retirement obligations		(765)		(161)
Changes in current assets and liabilities:
Accounts receivable		(4,066)		5,941
Other current assets		576		580
Current liabilities		9,903		(717)
Change in other long-term liabilities		—		11
Change in other assets, net		(523)		(233)
Payments to settle vested liability share-based awards		(8,662)		(9,807)
Net cash provided by operating activities		52,684		16,244
Cash flows from investing activities:
Capital expenditures		(66,154)		(50,775)
Acquisitions		(648,485)		(10,183)
Acquisition deposit		46,138		—
Net cash used in investing activities		(668,501)		(60,958)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility		—		45,000
Payments on senior secured revolving credit facility		—		(85,000)
Issuance of common stock		—		94,949
Payment of preferred stock dividends		(1,824)		(1,824)
Tax withholdings related to restricted stock units		(79)		(124)
Net cash provided by (used in) financing activities		(1,903)		53,001
Net change in cash and cash equivalents		(617,720)		8,287
Balance, beginning of period		652,993		1,224
Balance, end of period	$	35,273	$	9,511

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

6

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

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Description of Business and Basis of Presentation	6.	Fair Value Measurements
2.	Acquisitions	7.	Income Taxes
3.	Earnings Per Share	8.	Asset Retirement Obligations
4.	Borrowings	9.	Equity Transactions
5.	Derivative Instruments and Hedging Activities	10.	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 partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

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

Basis of presentation

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

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

These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2016. The balance sheet at December 31, 2016 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, 2017.

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

Recently adopted accounting policies

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. As of March 31, 2017, the Company adopted this ASU, which did not have a material impact on its financial statements.The Company has elected to no longer estimate forfeitures.

7

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

Note 2 - Acquisitions

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

2017 acquisitions

On February 13, 2017, the Company completed the acquisition of 29,175 gross (16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $632,947, excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 9 for additional information regarding the equity offering). The Company acquired an 82% average working interest in the properties acquired in the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of $46,138 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016. The following table summarizes the estimated acquisition date fair values of the acquisition:

Evaluated oil and natural gas properties	$	134,315
Unevaluated oil and natural gas properties		498,800
Asset retirement obligations		(168)
Net assets acquired	$	632,947

The preliminary purchase price allocation is 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.

2016 acquisitions

On October 20, 2016, the Company completed the acquisition of 6,904 gross (5,952 net) acres in the Midland Basin, primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of $339,687, excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (seeNote 9 for additional information regarding the equity offering). The Company acquired an 82% average working interest (62% average net revenue interest) in the properties acquired in the Plymouth Transaction.

On May 26, 2016, the Company completed the acquisition of 17,298 gross (14,089 net) acres in the Midland Basin, primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9,333,333 shares of common stock (at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date) for a total purchase price of $329,573, excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an 81% average working interest (61% average net revenue interest) in the properties acquired in the Big Star Transaction.

Unaudited pro forma financial statements

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

	Three Months Ended March 31,
	2017 (a)		2016 (a)
Revenues	$	84,416	$	42,615
Income (loss) from operations		34,907		(35,451)
Income (loss) available to common stockholders		47,963		(38,908)
Net income (loss) per common share:
Basic	$	0.24	$	(0.31)
Diluted	$	0.24	$	(0.31)

(a) The pro forma financial information was prepared assuming the Ameredev Transaction occurred as of January 1, 2016 and the Plymouth Transaction and Big Star Transactionoccurred as of January 1, 2015.

8

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

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

The properties associated with the Ameredev Transaction, Plymouth Transaction and Big Star Transaction have been comingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.

Subsequent event

In April 2017, the Company entered into an agreement to acquire 7,031 gross (2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for total cash consideration of $52,500, excluding customary purchase price adjustments. The Company plans to fund the cash purchase price with its available cash and borrowings on our senior secured revolving credit facility.

Note 3 - 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,
		2017		2016
Net income (loss)	$	47,129	$	(41,109)
Preferred stock dividends		(1,824)		(1,824)
Income (loss) available to common stockholders	$	45,305	$	(42,933)
Weighted average shares outstanding		201,054		83,582
Dilutive impact of restricted stock		686		—
Weighted average shares outstanding for diluted income (loss) per share		201,740		83,582
Basic income (loss) per share	$	0.23	$	(0.51)
Diluted income (loss) per share	$	0.22	$	(0.51)
Stock options (a)		15		15
Restricted stock (a)		—		25

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

Note 4 - Borrowings

The Company’s borrowings consisted of the following at:

	March 31, 2017		December 31, 2016
Principal components:
Senior secured revolving credit facility	$	—	$	—
6.125% senior unsecured notes due 2024		400,000		400,000
Total principal outstanding		400,000		400,000
6.125% senior unsecured notes due 2024, unamortized deferred financing costs		(9,464)		(9,781)
Total carrying value of borrowings	$	390,536	$	390,219

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

On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of March 11, 2019.  JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include several institutional lenders. The total notional amount available under the Credit Facility is$500,000. 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 November 21, 2016, the Company achieved an indication to increase the Credit Facility’s borrowing base to $500,000, but elected to maintain the borrowing base at $385,000. As of March 31, 2017, the Company continued to maintain the Credit Facility’s borrowing base at $385,000.

9

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

As of March 31, 2017, there was no balance outstanding on the Credit Facility. For the quarter ended March 31, 2017, the Credit Facility had a weighted-average interest rate of 2.83%, calculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base.

6.125% senior 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.

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; (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 104.594% of principal if the redemption occurs on or after October 1, 2019, but before October 1, 2020, and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020, but before October 1, 2021, and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022, and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022.

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

Restrictive covenants

The Company’s Credit Facility and the indenture governing our 6.125% 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, 2017.

Note 5 - Derivative Instruments and Hedging Activities

Objectives and strategies for using derivative instruments

The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, put and call options and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.

Counterparty risk and offsetting

The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; seeNote 6 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.

10

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

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 6 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. Cash settlements are also recorded as 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	03/31/2017		12/31/2016		03/31/2017		12/31/2016		03/31/2017		12/31/2016
Natural gas	Current	Fair value of derivatives	$	—	$	—	$	(64)	$	(593)	$	(64)	$	(593)
Oil	Current	Fair value of derivatives		3,093		103		(6,366)		(17,675)		(3,273)		(17,572)
Oil	Non-current	Fair value of derivatives		2,939		—		—		(28)		2,939		(28)
	Totals		$	6,032	$	103	$	(6,430)	$	(18,296)	$	(398)	$	(18,193)

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:

		March 31, 2017
	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	5,055	$	(1,962)	$	3,093
Long-term assets: Fair value of derivatives		2,939		—		2,939
Current liabilities: Fair value of derivatives	$	(8,392)	$	1,962	$	(6,430)

		December 31, 2016
	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	1,836	$	(1,733)	$	103
Current liabilities: Fair value of derivatives	$	(20,001)	$	1,733	$	(18,268)
Long-term liabilities: Fair value of derivatives		(28)		—		(28)

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

	Three Months Ended March 31,
		2017		2016
Oil derivatives
Net gain (loss) on settlements	$	(2,524)	$	7,507
Net gain (loss) on fair value adjustments		17,266		(9,137)
Total gain (loss) on oil derivatives	$	14,742	$	(1,630)
Natural gas derivatives
Net gain on settlements	$	33	$	209
Net gain on fair value adjustments		528		489
Total gain on natural gas derivatives	$	561	$	698
Total gain (loss) on oil & natural gas derivatives	$	15,303	$	(932)

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

Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of March 31, 2017:  

	For the Remainder of		For the Full Year of
Oil contracts	2017		2018
Swap contracts combined with short puts (WTI, enhanced swaps)
Total volume (MBbls)		550		—
Weighted average price per Bbl
Swap	$	44.50	$	—
Short put option	$	30.00	$	—
Deferred premium put option
Total volume (MBbls)		250		—
Premium per Bbl	$	2.05	$	—
Weighted average price per Bbl
Long put option	$	50.00	$	—
Deferred premium put spread option
Total volume (MBbls)		506		—
Premium per Bbl	$	2.45	$	—
Weighted average price per Bbl
Long put option	$	50.00	$	—
Short put option	$	40.00	$	—
Collar contracts (WTI, two-way collars)
Total volume (MBbls)		1,018		—
Weighted average price per Bbl
Ceiling (short call)	$	58.19	$	—
Floor (long put)	$	47.50	$	—
Call option contracts (short position)
Total volume (MBbls)		505		—
Weighted average price per Bbl
Call strike price	$	50.00	$	—
Swap contracts (Midland basis differential)
Volume (MBbls)		1,650		2,008
Weighted average price per Bbl	$	(0.52)	$	(1.02)
Collar contracts combined with short puts (WTI, three-way collars)
Total volume (MBbls)		—		2,738
Weighted average price per Bbl
Ceiling (short call option)	$	—	$	62.84
Floor (long put option)	$	—	$	50.00
Short put option	$	—	$	40.00

	For the Remainder of		For the Full Year of
Natural gas contracts	2017		2018
Collar contracts combined with short puts (Henry Hub, three-way collars)
Total volume (BBtu)		1,100		—
Weighted average price per MMBtu
Ceiling (short call option)	$	3.71	$	—
Floor (long put option)	$	3.00	$	—
Short put option	$	2.50	$	—
Collar contracts (Henry Hub, two-way collars)
Total volume (BBtu)		1,100		—
Weighted average price per MMBtu
Ceiling (short call option)	$	3.68	$	—
Floor (long put option)	$	3.00	$	—

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

Subsequent event

The following derivative contracts  were executed subsequent to March 31, 2017:

	For the Remainder of		For the Full Year of
Gas contracts	2017		2018
Collar contracts (Henry Hub, two-way collars)
Total volume (BBtu)		488		720
Weighted average price per MMBtu
Ceiling (short call option)	$	3.84	$	3.84
Floor (long put option)	$	3.40	$	3.40
Swap contracts
Total volume (BBtu)		736		—
Weighted average price per MMBtu	$	3.39	$	—

Note 6 - 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 of financial instruments

Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximated fair value due to the short-term nature or maturity of the instruments.

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

	March 31, 2017				December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit Facility (a)	$	—	$	—	$	—	$	—
6.125% Senior Notes (b)		390,536		416,000		390,219		412,000
Total	$	390,536	$	416,000	$	390,219	$	412,000

(a) Floating-rate debt.

(b) The fair value was based upon Level 2 inputs. See Note 4 for additional information about the Company’s 6.125% 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. SeeNote 5 for additional information regarding the Company’s derivative instruments.

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

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

March 31, 2017	Classification		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	6,032	$	—	$	6,032
Liabilities
Derivative financial instruments	Fair value of derivatives		—		(6,430)		—		(6,430)
Total net liabilities		$	—	$	(398)	$	—	$	(398)
December 31, 2016	Classification		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	103	$	—	$	103
Liabilities
Derivative financial instruments	Fair value of derivatives		—		(18,296)		—		(18,296)
Total net liabilities		$	—	$	(18,193)	$	—	$	(18,193)

Assets and liabilities measured at fair value on a nonrecurring basis

Acquisitions. The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 2 and Level 3 inputs.

Note 7 - Income Taxes

The Company typically provides for income taxes at a statutory rate of35%adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. As a result of the write-down of oil and natural gas properties in the latter part of 2015 and the first half of 2016,  the Company has incurred a cumulativethreeyear loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established afull valuation allowancefor all of the deferred tax asset. The valuation allowance was$127,073as of March 31, 2017.

The Company adopted a new accounting standard that simplifiedthe accounting for stock-basedcompensation. As a result, the Company recorded a cumulative-effect adjustment to retained earnings as of January 1, 2017 for all windfall tax benefits that were not previously recognized because the related tax deduction had not reduced current taxes payable. Due to the Company's valuation allowance position, a cumulative-effect adjustment was recorded to retained earnings as of January 1, 2017, and therefore, the net effect of this new accounting standard waszero. See Note 1 for additional information about this new accounting standard.

Note 8 - Asset Retirement Obligations

The table below summarizes the activity forthe Company’s asset retirement obligations:

	For the Three Months Ended
	March 31, 2017
Asset retirement obligations at January 1, 2017	$	6,661
Accretion expense		184
Liabilities incurred		195
Liabilities settled		(88)
Revisions to estimate		(712)
Asset retirement obligations at end of period		6,240
Less: Current asset retirement obligations		(1,588)
Long-term asset retirement obligations at March 31, 2017	$	4,652

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the Consolidated Balance Sheets at March 31, 2017 as long-term restricted investments were $3,339. 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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Callon Petroleum Company Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per share and per unit data) Table of Contents

Note 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 our 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 our Board of Directors. Preferred Stock dividends were $1,824for the three months ended March 31, 2017and 2016.

The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, 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, 2017, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $13.16 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 3.8 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.

On February 4, 2016,  the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of March 31, 2017, the Company had 1,458,948 shares of its Preferred Stock issued and outstanding.

Common stock

On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,917. Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in Note 2.

On September 6, 2016, the Company completed an underwritten public offering of 29,900,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $421,864. Proceeds from the offering were used to substantially fund the Plymouth Transaction, described in Note 2.

On May 26, 2016, the Company issued 9,333,333 shares of common stock to partially fund the Big Star Transaction, described in Note 2, at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date.

On April 25, 2016, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,869. Proceeds from the offering were used to fund the Big Star Transaction, described in Note 2, and other working interest acquisitions.

On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately $94,948. Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes.

Note 10 - Other

Operating leases

As of March 31, 2017, the Company had contracts for three horizontal drilling rigs (the “Cactus 1 Rig”, “Cactus 2 Rig” and “Cactus 3 Rig”). The contract terms, as amended through December 31, 2016, of the Cactus 1 Rig and Cactus 2 Rig will end in July 2018 and August 2018, respectively. The contract terms of the Cactus 3 Rig, that commenced drilling in mid-January 2017, will end in July 2017. The rig lease agreements include early termination provisions that obligate the Company to pay reduced minimum rentals for the remaining term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee.

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

Subsequent event

In April 2017 the Company entered into a contract for a fourth horizontal drilling rig. The contract term will begin July 2017 through July 2019 with a day rate of $18,000 per day.

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Callon Petroleum Company Table of Contents

Special Note Regarding Forward Looking Statements

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

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

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

· the amount and nature of our capital expenditures;

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

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

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

· business strategies and plans of management;

· our ability to efficiently integrate recently completed 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;

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

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

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

· 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 endangered species;

· any increase in severance or similar taxes;

· litigation relating to hydraulic fracturing, the climate and over-the-counter derivatives;

· 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;

· 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, 2016 (the  “2016 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto.

Should one or more of the risks or uncertainties described herein or in our 2016 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

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

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Callon Petroleum Company Table of Contents

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

General

The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our 2016 Annual Report on Form 10-K, which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. Our website address is www.callon.com. All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this report on Form 10-Q.

We are an independent oil and natural gas company established in 1950. We are focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. We have historically been focused on the Midland Basin and recently entered the Delaware Basin through an acquisition completed in February 2017. 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 predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and, more recently, 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 78% oil and 22% natural gas for the three months endedMarch 31, 2017. On March 31, 2017, our net acreage position in the Permian Basin was approximately  56,299 net acres.See Note 2 in the Footnotes to the Financial Statements for additional information about the Company’s acquisitions.

Operational Highlights

All of our producing properties are located in the Permian Basin. As a result of our acquisition and horizontal development efforts, our production grew62%for the three months ended March 31, 2017,  compared to the same period of 2016,  increasing to 1,838 MBOE from 1,132 MBOE.

For the three months ended March 31, 2017, we drillednine  gross (7.8net) horizontal wells and completed sevengross (4.9net) horizontal wells. As of March 31, 2017, we hadnine  gross (7.1net) horizontal wells awaiting completion.

As of March 31, 2017,  we had 539 gross (429 net) working interest oil wells,three  gross (0.1 net) royalty interest oil wells and no natural gas wells. A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas.

Liquidity and Capital Resources

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities, and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. We continue to evaluate other sources of capital to complement our cash flows from operations as we pursue our long-term growth plans. As of March 31, 2017, there was no balance outstanding on the Credit Facility, which has a borrowing base of $385 million. For the three months ended March 31, 2017, cash and cash equivalents decreased $617.6 million to $35.3 million compared to $652.9 million at December 31, 2016.  

Liquidity and cash flow

	For the Three Months Ended March 31,
(dollars in millions)	2017		2016
Net cash provided by operating activities	$	52.7	$	16.2
Net cash used in investing activities		(668.5)		(60.9)
Net cash provided by (used in) financing activities		(1.9)		53.0
Net change in cash	$	(617.7)	$	8.3

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

Operating activities. For the three months ended March 31, 2017, net cash provided by operating activities was $52.7 million compared to net cash provided by operating activities of$16.2 million for the same period in 2016. The change was predominantly attributable to the following:

· An increase in revenue offset by a decrease on settlements of derivative contracts;

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

· A decrease in payments in cash-setttled restricted stock unit (“RSU”) awards; and

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

Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 4, 5 and 6 in the Footnotes to the Financial Statements for additional information on our debt and 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, 2017, net cash used in investing activities was $668.5 million compared to $60.9 million for the same period in 2016. The change was predominantly attributable to the following:

· A  $12.7 million increase in operational expenditures due to the transition from a two-rig to a three-rig program in January 2017; and

· A $592.2 million increase in acquisition activity. See Note 2 in the Footnotes to the Financial Statements for additional information on the Company’s acquisitions.

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

	For the Three Months Ended March 31,
	2017		2016			$ Change
Operational expenditures	$	55.5	$	42.8	$	12.7
Seismic, leasehold and other		6.2		2.3		3.9
Capitalized general and administrative costs		3.9		3.3		0.6
Capitalized interest		0.5		2.3		(1.8)
Total capital expenditures (a)		66.1		50.7		15.4
Acquisitions		648.5		10.2		638.3
Acquisition deposits		(46.1)		—		(46.1)
Total investing activities	$	668.5	$	60.9	$	607.6

(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, 2017were $81.5 million. Inclusive of capitalized general and administrative and interest costs, total capital expenditures for the three months ended March 31, 2017 were $98.8 million.

General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Note 2 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, 2017, net cash used in financing activities was $1.9 million compared to cash provided by financing activities of $53.0 million during the same period of 2016. The change was predominantly attributable to the following:

· We had no borrowings on our Credit Facility during the three months ended March 31, 2017, a change of $40 million compared to the same period of 2016; and

· We had no issuance of common stock during the three months ended March 31, 2017,  a change of $94.9 million compared to the same period of 2016.

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

	For the Three Months Ended March 31,
	2017		2016		$ Change
Net borrowings on senior secured revolving credit facility	$	—	$	(40.0)	$	40.0
Issuance of common stock		—		94.9		(94.9)
Payment of preferred stock dividends		(1.8)		(1.8)		—
Tax withholdings related to restricted stock units		(0.1)		(0.1)		—
Net cash provided by (used in) financing activities	$	(1.9)	$	53.0	$	(54.9)

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

See Notes 4 and 9 in the Footnotes to the Financial Statements for additional information on our debt and equity offerings.

Capital Plan and First Quarter Summary

Our operational capital budget for 2017 was established at a range of $325 to $350 million on an accrual, or GAAP, basis, inclusive of a planned transition from a three-rig program that commenced in January 2017 to a four-rig program by July 2017 that would include horizontal development activity at our recent Delaware Basin acquisition (see Note 3 in the Footnotes to the Financial Statements for information on this acquisition).

In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $40 to $45 million for capitalized general and administrative expenses and capitalized interest expenses, both on an accrual, or GAAP, basis.

Operational capital expenditures on an accrual basis were $81.5 million for the three months ended March 31, 2017. In addition to the operational capital expenditures, $4.5 million of capitalized general and administrative and $6.5 million of capitalized interest expenses were accrued in the three months ended March 31, 2017.

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

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

Results of Operations

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

		Three Months Ended March 31,
		2017		2016		Change	% Change
Net production:
Oil (MBbls)		1,434		892		542	61%
Natural gas (MMcf)		2,422		1,443		979	68%
Total (MBOE)		1,838		1,132		706	62%
Average daily production (BOE/d)		20,422		12,440		7,982	64%
% oil (BOE basis)		78%		79%
Average realized sales price:
Oil (Bbl) (excluding impact of cash settled derivatives)	$	50.21	$	30.77	$	19.44	63%
Oil (Bbl) (including impact of cash settled derivatives)		48.45		39.18		9.27	24%
Natural gas (Mcf) (excluding impact of cash settled derivatives)	$	3.86	$	2.26	$	1.60	71%
Natural gas (Mcf) (including impact of cash settled derivatives)		3.88		2.40		1.48	62%
Total (BOE) (excluding impact of cash settled derivatives)	$	44.27	$	27.12	$	17.15	63%
Total (BOE) (including impact of cash settled derivatives)		42.91		33.93		8.98	26%
Oil and natural gas revenues (in thousands):
Oil revenue	$	72,008	$	27,443	$	44,565	162%
Natural gas revenue		9,355		3,255		6,100	187%
Total	$	81,363	$	30,698	$	50,665	165%
Additional per BOE data:
Sales price (excluding impact of cash settled derivatives)	$	44.27	$	27.12	$	17.15	63%
Lease operating expense (excluding gathering and treating		6.61		5.97		0.64	11%
expense)
Gathering and treating expense		0.43		0.18		0.25	135%
Production taxes		3.21		1.96		1.25	64%
Operating margin	$	34.02	$	19.01	$	15.01	79%

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

Revenues

The following table reconciles 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, 2016	$	27,443	$	3,255	$	30,698
Volume increase		16,677		2,213		18,890
Price increase		27,888		3,887		31,775
Net increase		44,565		6,100		50,665
Revenues for the three months ended March 31, 2017	$	72,008	$	9,355	$	81,363

Commodity prices

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

· our revenues, cash flows and earnings;

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

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

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

· the value of our oil and natural gas properties.

For the three months ended March 31, 2017, the average NYMEX price for a barrel of oil was $51.78 per Bbl compared to $33.58 per Bbl for the same period of 2016. The NYMEX price for a barrel of oil ranged from a low of $47.34 per Bbl to a high of $54.45 per Bbl for the three months ended March 31, 2017.

For the three months ended March 31, 2017, the average NYMEX price for natural gas was $3.32 per MMBtu compared to $2.09 per MMBtu for the same period of 2016. The NYMEX price for natural gas ranged from a low of $2.56 per MMBtu to a high of $3.42 per MMBtu for the three months ended March 31, 2017.

Oil revenue

For the quarter ended March 31, 2017, oil revenues of $72.0 million increased$44.6 million, or 162%, compared to revenues of $27.4 million for the same period of 2016.  The increase in oil revenue was primarily attributable to a61% increase in production and  a63%increase in the average realized sales price, which rose to $50.21 per Bbl in the first quarter of 2017 from $30.77 per Bbl in the first quarter of 2016.  The increase in production was comprised of 650 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 292 MBbls attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.

See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.

Natural gas revenue (including NGLs)

Natural gas revenues of $9.4 million increased $6.1 million, or 187%, during the three months endedMarch 31, 2017,  compared to $3.3 million for the same period of 2016. The increase primarily relates to a  68% increase in natural gas volumes and a 71% increase in the average realized sales price, which rose to $3.86 per Mcf from$2.26 per Mcf, reflecting both natural gas and natural gas liquids prices.The increase in production was comprised of 684 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 536  MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were and normal expected declines from our existing wells.

See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.

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

Operating Expenses

(in thousands, except per unit amounts)	Three Months Ended March 31,
			Per				Per		Total Change			BOE Change
	2017		BOE		2016		BOE		$		%	$		%
Lease operating expenses	$	12,937	$	7.04	$	6,957	$	6.15	$	5,980	86%	$	0.89	14%
Production taxes		5,904		3.21		2,220		1.96		3,684	166%		1.25	64%
Depreciation, depletion and amortization		24,433		13.29		15,722		13.89		8,711	55%		(0.60)	(4)%
General and administrative		5,206		2.83		5,562		4.91		(356)	(6)%		(2.08)	(42)%
Accretion expense		184		0.10		180		0.16		4	2%		(0.06)	(38)%
Acquisition expense		450		nm		48		nm		402	nm		nm	nm
Write-down of oil and natural gas properties		—		nm		34,776		nm		(34,776)	nm		nm	nm

nm = not meaningful

Lease operating expenses. These are daily costs incurred to extract oil and natural gas, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover expenses related to our oil and natural gas properties.

For the three months endedMarch 31, 2017,  LOE increased by 86% to$12.9 million compared to $7.0 million forthe same period of 2016.  Contributing to the increase was $4.8 million related to oil and natural gas properties acquired during 2016 and the first quarter of 2017 (see Note 2 in the Footnotes to the Financial Statements). Excluding LOE related to these acquired properties, LOE increased by  $1.2 million, or 18%, compared to the same period of 2016, which was primarily due to an increase in cost driven by higher production volumes from our legacy assets. For the three months endedMarch 31, 2017, LOE per BOE increased to$7.04per BOE compared to$6.15 per BOE for the same period of 2016,  which was primarily attributable toan increase in cost offset by higher production volumes.The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above.

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 endedMarch 31, 2017increased by 166% to $5.9 million compared to $2.2 million for the same period of 2016. The increase was primarily due to anincrease in severance taxes, which was attributable to the increase in revenue.Also contributing to the increase was an increase in ad valorem taxes, which was attributable to an increase in the valuation of our oil and gas properties by taxing jurisdictions as a result of an increased number of producing wells from our horizontal drilling program, acquisitions as discussed above, and an increase in commodity prices year over year.On a per BOE basis, production taxes for the three months ended March 31, 2017increased by 64% compared to the same period of 2016.

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

For the three months ended March 31, 2017,  DD&A increased 55% to $24.4 million compared to $15.7 million for the same period of 2016.  The increase is primarily attributable to a 62% increase in production offset by a  4% decrease in our per BOE DD&A rate.For the three months endedMarch 31, 2017,  DD&A on a per unit basis decreased to$13.29 per BOE compared to $13.89 per BOE for the same period of 2016.  The decrease is attributable to our increased estimated proved reserves relative to our depreciable base and assumed future development costs related to undeveloped proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions, offset by the write down of oil and natural gas properties in the first half of 2016.

General and administrative, net of amounts capitalized (“G&A”). These are costs incurred for overhead, including payroll and benefits for our corporate staff, severance and early retirement expenses, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability

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

awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance.

G&A for the three months endedMarch 31, 2017decreased to $5.2 million compared to $5.6 million for the same period of 2016. G&A expenses for the periods indicated include the following (in millions):

	For the Three Months Ended March 31,
	2017		2016		$ Change		% Change
Recurring expenses
G&A	$	4.6	$	4.2	$	0.4	10%
Share-based compensation		0.9		0.5		0.4	80%
Fair value adjustments of cash-settled RSU awards		(0.3)		0.7		(1.0)	(143)%
Non-recurring expenses
Expense related to a threatened proxy contest		—		0.2		(0.2)	(100)%
Total G&A expenses	$	5.2	$	5.6	$	(0.4)	(7)%

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

Accretion expense related to our ARO  increased 2% forthe three months ended March 31, 2017, compared to the same period of 2016. Accretion expense generally correlates with the Company’s ARO, which was $6.2 million at March 31, 2017as compared to$5.3 million at March 31, 2016. See Note 8 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO.

Acquisition expense. Acquisition expense for the three months ended March 31, 2017  was related to costs with respect to our acquisition efforts in the Permian Basin. See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.

Write-down of oil and natural gas properties. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling.

For thethree months endedMarch 31, 2017, the Company did not recognize a  write-down of oil and natural gas properties compared to a write-down of$34.8 million for the same period of 2016 as a result of the ceiling test limitation. At March 31, 2017, the average realized prices used in determining the estimated future net cash flows from proved reserves were $47.61 per barrel of oil and $2.73  per Mcf of natural gas.If commodity prices were to decline, we could incur additional ceiling test write-downs in the future.

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

The table below presents the cumulative results of the full cost ceiling test along with various pricing scenarios to demonstrate the sensitivity of our full cost ceiling to changes in 12-month average oil and natural gas prices. This sensitivity analysis is as of March 31, 2017, and accordingly, does not consider drilling results, production, changes in oil and natural gas prices, and changes in future development and operating costs subsequent to March 31, 2017 that may require revisions to our proved reserve estimates and resulting estimated future net cash flows used in the full cost ceiling test.

	12-Month Average Prices				Excess (Deficit) of Full Cost Ceiling Over Net Capitalized Costs
Pricing Scenarios	Oil ($/Bbl)		Natural gas ($/Mcf)		(in thousands)
March 31, 2017 Actual	$	47.61	$	2.73	$	149,000
Combined price sensitivity
Oil and natural gas +10%	$	52.37	$	3.00	$	353,137
Oil and natural gas -10%		42.85	$	2.46		(55,177)
Oil price sensitivity
Oil +10%	$	52.37	$	2.73	$	334,434
Oil -10%		42.85	$	2.73		(36,474)
Natural gas sensitivity
Natural gas +10%	$	47.61	$	3.00	$	167,683
Natural gas -10%		47.61	$	2.46		130,277

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

Other Income and Expenses and Preferred Stock Dividends

	Three Months Ended March 31,
(in thousands)	2017		2016			$ Change	% Change
Interest expense, net of capitalized amounts	$	665	$	5,491	$	(4,826)	(88)%
(Gain) loss on derivative contracts		(15,303)		932		(16,235)	(1,742)%
Other income, net		(708)		(81)		(627)	774%
Total	$	(15,346)	$	6,342
Income tax (benefit) expense	$	466	$	—	$	466	100%
Preferred stock dividends		(1,824)		(1,824)		—	—%

Interest expense, net of capitalized amounts. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.

Interest expense, net of capitalized amounts, incurred during the three months endedMarch 31, 2017decreased $4.8 million compared to the same period of 2016. The decrease is primarily attributable to a  $4.2 million increase in capitalized interest compared to the 2016 period, resulting from a higher average unevaluated property balance for the three months endedMarch 31, 2017 as compared to the same period of 2016.  The increase in unevaluated property was primarily due to acquired properties.Also contributing to the decrease was a $0.7 million decrease in interest expense on our Credit Facility and term debt.

See  Notes 2 and 4  in the Footnotes to the Financial Statements for additional information on our acquisitions and debt.

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 endedMarch 31, 2017, the net gain on derivative contracts was $15.3  million compared to a $0.9 million net loss for the same period of 2016. The net gain (loss) on derivative instruments for the periods indicated includes the following (in millions):

	For the Three Months Ended March 31,
	2017		2016		$ Change
Oil derivatives
Net gain (loss) on settlements	$	(2.5)	$	7.5	$	(10.0)
Net gain (loss) on fair value adjustments		17.2		(9.1)		26.3
Total gain (loss) on oil derivatives	$	14.7	$	(1.6)	$	16.3
Natural gas derivatives
Net gain on settlements	$	0.1	$	0.2	$	(0.1)
Net gainon fair value adjustments		0.5		0.5		—
Total gain on natural gas derivatives	$	0.6	$	0.7	$	(0.1)
Total gain (loss) on oil & natural gas derivatives	$	15.3	$	(0.9)	$	16.2

See Notes 5 and 6 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 expenseof $0.5 million for the three months ended March 31, 2017, compared tono benefit or expense for the same period of 2016. The change in income tax expense is primarily related to recording a valuation allowance of $127.1  million

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at March 31, 2017 and the difference in the amount of income (loss) before income taxes between periods. 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, 2017 were consistentwith dividends for the same period of 2016.  Dividends reflect a 10% dividend yield. See Note 9in the Footnotes to the Financial Statements for additional information.

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Callon Petroleum Company Table of Contents

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 address 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 extremely 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 approximately40%  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, in addition to modification of our capital spending plans related to operational activities and acquisitions.

The Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approximately  2,829MBbls and 3,424BBtu of our expected oil and natural gas production, respectively, for the remaining nine months of 2017.We  also have commodity hedging contracts linked to Midland WTI basis differentials relative to Cushing covering approximately 1,650MBbls  of our expected oil production for the remaining nine months of 2017.  See Note 5in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at March 31, 2017,  and derivative contracts established subsequent to that date.

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

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

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

The Company enters into these various agreements 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.Though we had no balance outstanding on our Credit Facility at March 31, 2017, based on a notional amount of $10 million outstanding under the facility, an increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $0.1 million.See Note 4 to the Consolidated 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.We do not require any of our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely

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Callon Petroleum Company Table of Contents

affect our financial results. At March 31, 2017 our total receivables from the sale of our oil and natural gas production were approximately $51.7 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, 2017 our joint interest receivables were approximately $23.6 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, 2017.

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 reasonable 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

There have been no material changes with respect to the risk factors disclosed in our 2016 Annual Report on Form 10-K.

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

None.

Item 3.  Defaults Upon Senior Securities

None.

Item 4.  Mine Safety Disclosures

None.

Item 5.  Other Information

None.

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Callon Petroleum Company Table of Contents

Item 6.  Exhibits

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

Exhibit Number		Description
3.		Articles of Incorporation and By-Laws
3.1		Certificate of Incorporation of the Company, as amended through May 12, 2016 (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q, filed on November 3, 2016)
3.2		Certificate of Designation of Rights and Preferences of 10% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5 of the Company’s Form 8-A, filed on May 23, 2013)
3.3		Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed on August 4, 1994, Reg. No. 33-82408)
4.		Instruments defining the rights of security holders, including indentures
4.1		Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company’s Registration Statement on Form S-4, filed on August 4, 1994, Reg. No. 33-82408)
4.2		Certificate for the Company’s 10% Cumulative Preferred Stock (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-A, filed on May 23, 2013)
4.3		Indenture of 6.125% Senior Notes Due 2024, dated as of October 3, 2016, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K, filed on October 4, 2016)
4.4		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 (incorporated by reference to Exhibit 4.2 of the Company's Current Report on Form 8-K, filed on October 4, 2016)
31.		Section 13a-14 Certifications
31.1	(a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	(a)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.		Section 1350 Certifications
32.1	(b)	Section 1350 Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.	(c)	Interactive Data Files
(a)	Filed herewith.
(b)	Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.
(c)	Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability.

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SIGNATURES

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

	Callon Petroleum Company
Signature	Title	Date
/s/ Fred L. Callon	Chief Executive Officer	May 2, 2017
Fred L. Callon
/s/ Joseph C. Gatto, Jr.	President and	May 2, 2017
Joseph C. Gatto, Jr.	Chief Financial Officer

32

EX-31.1

Exhibit 31.1

6
CERTIFICATIONS
I, Fred L. Callon, 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 officers 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 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 officers 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 function):
			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 controls over financial reporting;
Date:		May 2, 2017			/s/ Fred L. Callon
					Fred L. Callon, Chief Executive Officer
					(Principal executive officer)

EX-31.2

Exhibit 31.2

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 officers 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 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 officers 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 function):
			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 controls over financial reporting;
Date:		May 2, 2017			/s/ Joseph C. Gatto, Jr.
					Joseph C. Gatto, Jr., President andChief Financial Officer
					(Principal Financial Officer)

EX-32

Exhibit 32

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, 2017, 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) of 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 2, 2017	/s/ Fred L. Callon
		Fred L. Callon (Principal Executive Officer, Director)
Date:	May 2, 2017	/s/ Joseph C. Gatto, Jr.
		Joseph C. Gatto, Jr. (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, 2017	Apr. 28, 2017
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, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		201,061,366

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Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 35,273	$ 652,993
Accounts receivable	75,959	69,783
Fair value of derivatives	3,093	103
Other current assets	1,671	2,247
Total current assets	115,996	725,126
Oil and natural gas properties, full-cost accounting method:
Evaluated properties	3,009,059	2,754,353
Less accumulated depreciation, depletion, amortization and impairment	(1,972,091)	(1,947,673)
Net evaluated oil and natural gas properties	1,036,968	806,680
Unevaluated property	1,154,850	668,721
Total oil and natural gas properties	2,191,818	1,475,401
Other property and equipment, net	18,067	14,114
Restricted investments	3,339	3,332
Deferred financing costs related to the senior secured revolving credit facility	2,744	3,092
Fair value of derivatives	2,939
Acquisition deposit		46,138
Other assets, net	676	384
Total assets	2,335,579	2,267,587
Current liabilities:
Accounts payable and accrued liabilities	131,252	95,577
Accrued interest	12,114	6,057
Cash-settleable restricted stock unit awards	4,025	8,919
Asset retirement obligations	1,588	2,729
Fair value of derivatives	6,430	18,268
Total current liabilities	155,409	131,550
6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs	390,536	390,219
Asset retirement obligations	4,652	3,932
Cash-settleable restricted stock unit awards	4,108	8,071
Deferred tax liability	556	90
Fair value of derivatives		28
Other long-term liabilities	285	295
Total liabilities	555,546	534,185
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 and 1,458,948 shares outstanding, respectively	15	15
Common stock, $0.01 par value, 300,000,000 and 300,000,000 shares authorized; 201,054,884 and 201,041,320 shares outstanding, respectively	2,011	2,010
Capital in excess of par value	2,173,243	2,171,514
Accumulated deficit	(395,236)	(440,137)
Total stockholders' equity	1,780,033	1,733,402
Total liabilities and stockholders' equity	$ 2,335,579	$ 2,267,587

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
Stockholders' equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares outstanding	201,054,884	201,041,320
Series A Preferred Stock [Member]
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	2,500,000	2,500,000
Preferred stock, shares outstanding	1,458,948	1,458,948

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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Operating revenues:
Total operating revenues	$ 81,363	$ 30,698
Operating expenses:
Lease operating expenses	12,937	6,957
Production taxes	5,904	2,220
Depreciation, depletion and amortization	24,433	15,722
General and administrative	5,206	5,562
Accretion expense	184	180
Write-down of oil and natural gas properties		34,776
Acquisition expense	450	48
Total operating expenses	49,114	65,465
Income (loss) from operations	32,249	(34,767)
Other (income) expenses:
Interest expense, net of capitalized amounts	665	5,491
(Gain) loss on derivative contracts	(15,303)	932
Other income	(708)	(81)
Total other (income) expense	(15,346)	6,342
Income (loss) before income taxes	47,595	(41,109)
Income tax expense	466
Net income (loss)	47,129	(41,109)
Preferred stock dividends	(1,824)	(1,824)
Income (loss) available to common stockholders	$ 45,305	$ (42,933)
Income (loss) per common share:
Basic	$ 0.23	$ (0.51)
Diluted	$ 0.22	$ (0.51)
Shares used in computing income (loss) per common share:
Basic	201,054	83,582
Diluted	201,740	83,582
Crude Oil [Member]
Operating revenues:
Total operating revenues	$ 72,008	$ 27,443
Natural Gas And Natural Gas Liquids [Member]
Operating revenues:
Total operating revenues	$ 9,355	$ 3,255

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 47,129	$ (41,109)
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	24,932	16,129
Write-down of oil and natural gas properties		34,776
Accretion expense	184	180
Amortization of non-cash debt related items	665	781
Deferred income tax expense	466
Net (gain) loss on derivatives, net of settlements	(17,794)	8,648
Non-cash expense related to equity share-based awards	930	516
Change in the fair value of liability share-based awards	(291)	709
Payments to settle asset retirement obligations	(765)	(161)
Changes in current assets and liabilities:
Accounts receivable	(4,066)	5,941
Other current assets	576	580
Current liabilities	9,903	(717)
Change in other long-term liabilities		11
Change in other assets, net	(523)	(233)
Payments to settle vested liability share-based awards	(8,662)	(9,807)
Net cash provided by operating activities	52,684	16,244
Cash flows from investing activities:
Capital expenditures	(66,154)	(50,775)
Acquisitions	(648,485)	(10,183)
Acquisition deposit	46,138
Net cash used in investing activities	(668,501)	(60,958)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility		45,000
Payments on senior secured revolving credit facility		(85,000)
Issuance of common stock		94,949
Payment of preferred stock dividends	(1,824)	(1,824)
Tax withholdings related to restricted stock units	(79)	(124)
Net cash provided by (used in) financing activities	(1,903)	53,001
Net change in cash and cash equivalents	(617,720)	8,287
Balance, beginning of period	652,993	1,224
Balance, end of period	$ 35,273	$ 9,511

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Description of Business and Basis of Presentation

3 Months Ended

Mar. 31, 2017

Description of Business and Basis of Presentation [Abstract]

Description of Business and Basis of Presentation

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 partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

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

Basis of presentation

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

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

These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2016. The balance sheet at December 31, 2016 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, 2017.

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

Recently adopted accounting policies

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. As of March 31, 2017, the Company adopted this ASU, which did not have a material impact on its financial statements. The Company has elected to no longer estimate forfeitures.

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Acquisitions

3 Months Ended

Mar. 31, 2017

Acquisitions [Abstract]

Acquisitions

Note 2 - Acquisitions

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

2017 acquisitions

On February 13, 2017, the Company completed the acquisition of 29,175 gross (16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $632,947, excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 9 for additional information regarding the equity offering). The Company acquired an 82% average working interest in the properties acquired in the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of $46,138 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016. The following table summarizes the estimated acquisition date fair values of the acquisition:

Evaluated oil and natural gas properties	$	134,315
Unevaluated oil and natural gas properties		498,800
Asset retirement obligations		(168)
Net assets acquired	$	632,947

The preliminary purchase price allocation is 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.

2016 acquisitions

On October 20, 2016, the Company completed the acquisition of 6,904 gross (5,952 net) acres in the Midland Basin, primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of $339,687, excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 9 for additional information regarding the equity offering). The Company acquired an 82% average working interest (62% average net revenue interest) in the properties acquired in the Plymouth Transaction.

On May 26, 2016, the Company completed the acquisition of 17,298 gross (14,089 net) acres in the Midland Basin, primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9,333,333 shares of common stock (at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date) for a total purchase price of $329,573, excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an 81% average working interest (61% average net revenue interest) in the properties acquired in the Big Star Transaction.

Unaudited pro forma financial statements

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

	Three Months Ended March 31,
	2017 (a)		2016 (a)
Revenues	$	84,416	$	42,615
Income (loss) from operations		34,907		(35,451)
Income (loss) available to common stockholders		47,963		(38,908)
Net income (loss) per common share:
Basic	$	0.24	$	(0.31)
Diluted	$	0.24	$	(0.31)

(a) The pro forma financial information was prepared assuming the Ameredev Transaction occurred as of January 1, 2016 and the Plymouth Transaction and Big Star Transaction occurred as of January 1, 2015.

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

The properties associated with the Ameredev Transaction, Plymouth Transaction and Big Star Transaction have been comingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.

Subsequent event

In April 2017, the Company entered into an agreement to acquire 7,031 gross (2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for total cash consideration of $52,500, excluding customary purchase price adjustments. The Company plans to fund the cash purchase price with its available cash and borrowings on our senior secured revolving credit facility.

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Earnings Per Share

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Earnings Per Share

Note 3 - 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,
		2017		2016
Net income (loss)	$	47,129	$	(41,109)
Preferred stock dividends		(1,824)		(1,824)
Income (loss) available to common stockholders	$	45,305	$	(42,933)
Weighted average shares outstanding		201,054		83,582
Dilutive impact of restricted stock		686		—
Weighted average shares outstanding for diluted income (loss) per share		201,740		83,582
Basic income (loss) per share	$	0.23	$	(0.51)
Diluted income (loss) per share	$	0.22	$	(0.51)
Stock options (a)		15		15
Restricted stock (a)		—		25

(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, 2017

Borrowings [Abstract]

Borrowings

Note 4 - Borrowings

The Company’s borrowings consisted of the following at:

	March 31, 2017		December 31, 2016
Principal components:
Senior secured revolving credit facility	$	—	$	—
6.125% senior unsecured notes due 2024		400,000		400,000
Total principal outstanding		400,000		400,000
6.125% senior unsecured notes due 2024, unamortized deferred financing costs		(9,464)		(9,781)
Total carrying value of borrowings	$	390,536	$	390,219

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

On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of March 11, 2019.  JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include several institutional lenders. The total notional amount available under the Credit Facility is$500,000. 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 November 21, 2016, the Company achieved an indication to increase the Credit Facility’s borrowing base to $500,000, but elected to maintain the borrowing base at $385,000. As of March 31, 2017, the Company continued to maintain the Credit Facility’s borrowing base at $385,000.

As of March 31, 2017, there was no balance outstanding on the Credit Facility. For the quarter ended March 31, 2017, the Credit Facility had a weighted-average interest rate of 2.83%, calculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base.

6.125% senior 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.

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; (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 104.594% of principal if the redemption occurs on or after October 1, 2019, but before October 1, 2020, and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020, but before October 1, 2021, and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022, and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022.

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

Restrictive covenants

The Company’s Credit Facility and the indenture governing our 6.125% 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, 2017.

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Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities [Abstract]

Derivative Instruments and Hedging Activities

Note 5 - Derivative Instruments and Hedging Activities

Objectives and strategies for using derivative instruments

The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, put and call options and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.

Counterparty risk and offsetting

The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 6 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 6 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. Cash settlements are also recorded as 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	03/31/2017		12/31/2016		03/31/2017		12/31/2016		03/31/2017		12/31/2016
Natural gas	Current	Fair value of derivatives	$	—	$	—	$	(64)	$	(593)	$	(64)	$	(593)
Oil	Current	Fair value of derivatives		3,093		103		(6,366)		(17,675)		(3,273)		(17,572)
Oil	Non-current	Fair value of derivatives		2,939		—		—		(28)		2,939		(28)
	Totals		$	6,032	$	103	$	(6,430)	$	(18,296)	$	(398)	$	(18,193)

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:

		March 31, 2017
	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	5,055	$	(1,962)	$	3,093
Long-term assets: Fair value of derivatives		2,939		—		2,939
Current liabilities: Fair value of derivatives	$	(8,392)	$	1,962	$	(6,430)

		December 31, 2016
	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	1,836	$	(1,733)	$	103
Current liabilities: Fair value of derivatives	$	(20,001)	$	1,733	$	(18,268)
Long-term liabilities: Fair value of derivatives		(28)		—		(28)

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

	Three Months Ended March 31,
		2017		2016
Oil derivatives
Net gain (loss) on settlements	$	(2,524)	$	7,507
Net gain (loss) on fair value adjustments		17,266		(9,137)
Total gain (loss) on oil derivatives	$	14,742	$	(1,630)
Natural gas derivatives
Net gain on settlements	$	33	$	209
Net gain on fair value adjustments		528		489
Total gain on natural gas derivatives	$	561	$	698
Total gain (loss) on oil & natural gas derivatives	$	15,303	$	(932)

Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of March 31, 2017:  

	For the Remainder of		For the Full Year of
Oil contracts	2017		2018
Swap contracts combined with short puts (WTI, enhanced swaps)
Total volume (MBbls)		550		—
Weighted average price per Bbl
Swap	$	44.50	$	—
Short put option	$	30.00	$	—
Deferred premium put option
Total volume (MBbls)		250		—
Premium per Bbl	$	2.05	$	—
Weighted average price per Bbl
Long put option	$	50.00	$	—
Deferred premium put spread option
Total volume (MBbls)		506		—
Premium per Bbl	$	2.45	$	—
Weighted average price per Bbl
Long put option	$	50.00	$	—
Short put option	$	40.00	$	—
Collar contracts (WTI, two-way collars)
Total volume (MBbls)		1,018		—
Weighted average price per Bbl
Ceiling (short call)	$	58.19	$	—
Floor (long put)	$	47.50	$	—
Call option contracts (short position)
Total volume (MBbls)		505		—
Weighted average price per Bbl
Call strike price	$	50.00	$	—
Swap contracts (Midland basis differential)
Volume (MBbls)		1,650		2,008
Weighted average price per Bbl	$	(0.52)	$	(1.02)
Collar contracts combined with short puts (WTI, three-way collars)
Total volume (MBbls)		—		2,738
Weighted average price per Bbl
Ceiling (short call option)	$	—	$	62.84
Floor (long put option)	$	—	$	50.00
Short put option	$	—	$	40.00

	For the Remainder of		For the Full Year of
Natural gas contracts	2017		2018
Collar contracts combined with short puts (Henry Hub, three-way collars)
Total volume (BBtu)		1,100		—
Weighted average price per MMBtu
Ceiling (short call option)	$	3.71	$	—
Floor (long put option)	$	3.00	$	—
Short put option	$	2.50	$	—
Collar contracts (Henry Hub, two-way collars)
Total volume (BBtu)		1,100		—
Weighted average price per MMBtu
Ceiling (short call option)	$	3.68	$	—
Floor (long put option)	$	3.00	$	—

Subsequent event

The following derivative contracts were executed subsequent to March 31, 2017:

	For the Remainder of		For the Full Year of
Gas contracts	2017		2018
Collar contracts (Henry Hub, two-way collars)
Total volume (BBtu)		488		720
Weighted average price per MMBtu
Ceiling (short call option)	$	3.84	$	3.84
Floor (long put option)	$	3.40	$	3.40
Swap contracts
Total volume (BBtu)		736		—
Weighted average price per MMBtu	$	3.39	$	—

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Fair Value Measurements

3 Months Ended

Mar. 31, 2017

Fair Value Measurements [Abstract]

Fair Value Measurements

Note 6 - 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 of financial instruments

Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximated fair value due to the short-term nature or maturity of the instruments.

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

	March 31, 2017				December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit Facility (a)	$	—	$	—	$	—	$	—
6.125% Senior Notes (b)		390,536		416,000		390,219		412,000
Total	$	390,536	$	416,000	$	390,219	$	412,000

(a) Floating-rate debt.

(b) The fair value was based upon Level 2 inputs. See Note 4 for additional information about the Company’s 6.125% 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. SeeNote 5 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, 2017	Classification		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	6,032	$	—	$	6,032
Liabilities
Derivative financial instruments	Fair value of derivatives		—		(6,430)		—		(6,430)
Total net liabilities		$	—	$	(398)	$	—	$	(398)
December 31, 2016	Classification		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	103	$	—	$	103
Liabilities
Derivative financial instruments	Fair value of derivatives		—		(18,296)		—		(18,296)
Total net liabilities		$	—	$	(18,193)	$	—	$	(18,193)

Assets and liabilities measured at fair value on a nonrecurring basis

Acquisitions. The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 2 and Level 3 inputs.

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Income Taxes

3 Months Ended

Mar. 31, 2017

Income Taxes [Abstract]

Income Taxes

Note 7 - Income Taxes

The Company typically provides for income taxes at a statutory rate of35%adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. As a result of the write-down of oil and natural gas properties in the latter part of 2015 and the first half of 2016, the Company has incurred a cumulativethreeyear loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a full valuation allowance for all of the deferred tax asset. The valuation allowance was$127,073as of March 31, 2017.  

The Company adopted a new accounting standard that simplifiedthe accounting for stock-basedcompensation. As a result, the Company recorded a cumulative-effect adjustment to retained earnings as of January 1, 2017 for all windfall tax benefits that were not previously recognized because the related tax deduction had not reduced current taxes payable. Due to the Company's valuation allowance position, a cumulative-effect adjustment was recorded to retained earnings as of January 1, 2017, and therefore, the net effect of this new accounting standard waszero. See Note 1 for additional information about this new accounting standard.

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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2017

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

Note 8 - Asset Retirement Obligations

The table below summarizes the activity for the Company’s asset retirement obligations:

	For the Three Months Ended
	March 31, 2017
Asset retirement obligations at January 1, 2017	$	6,661
Accretion expense		184
Liabilities incurred		195
Liabilities settled		(88)
Revisions to estimate		(712)
Asset retirement obligations at end of period		6,240
Less: Current asset retirement obligations		(1,588)
Long-term asset retirement obligations at March 31, 2017	$	4,652

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the Consolidated Balance Sheets at March 31, 2017 as long-term restricted investments were $3,339. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.

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Equity Transactions

3 Months Ended

Mar. 31, 2017

Equity Transactions [Abstract]

Equity Transactions

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 our 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 our Board of Directors. Preferred Stock dividends were $1,824 for the three months ended March 31, 2017 and 2016.

The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, 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, 2017, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $13.16 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 3.8 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.

On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of March 31, 2017, the Company had 1,458,948shares of its Preferred Stock issued and outstanding.

Common stock

On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,917. Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in Note 2.

On September 6, 2016, the Company completed an underwritten public offering of 29,900,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $421,864. Proceeds from the offering were used to substantially fund the Plymouth Transaction, described in Note 2.  

On May 26, 2016, the Company issued 9,333,333 shares of common stock to partially fund the Big Star Transaction, described in Note 2, at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date.

On April 25, 2016, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,869. Proceeds from the offering were used to fund the Big Star Transaction, described in Note 2, and other working interest acquisitions.

On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately $94,948. Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes.

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Other

3 Months Ended

Mar. 31, 2017

Other [Abstract]

Other

Note 10 - Other

Operating leases

As of March 31, 2017, the Company had contracts for three horizontal drilling rigs (the “Cactus 1 Rig”, “Cactus 2 Rig” and “Cactus 3 Rig”). The contract terms, as amended through December 31, 2016, of the Cactus 1 Rig and Cactus 2 Rig will end in July 2018 and August 2018, respectively. The contract terms of the Cactus 3 Rig, that commenced drilling in mid-January 2017, will end in July 2017. The rig lease agreements include early termination provisions that obligate the Company to pay reduced minimum rentals for the remaining term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee.

Subsequent event

In April 2017 the Company entered into a contract for a fourth horizontal drilling rig. The contract term will begin July 2017 through July 2019 with a day rate of $18,000 per day.

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Acquisitions (Tables)

3 Months Ended

Mar. 31, 2017

Unaudited Summary Pro Forma Financial Information

	Three Months Ended March 31,
	2017 (a)		2016 (a)
Revenues	$	84,416	$	42,615
Income (loss) from operations		34,907		(35,451)
Income (loss) available to common stockholders		47,963		(38,908)
Net income (loss) per common share:
Basic	$	0.24	$	(0.31)
Diluted	$	0.24	$	(0.31)

(a) The pro forma financial information was prepared assuming the Ameredev Transaction occurred as of January 1, 2016 and the Plymouth Transaction and Big Star Transaction occurred as of January 1, 2015.

Delaware Basin in Ward and Pecos Counties, Texas [Member] | Ameredev Transaction [Member]

Fair Value of Net Assets Acquired

Evaluated oil and natural gas properties	$	134,315
Unevaluated oil and natural gas properties		498,800
Asset retirement obligations		(168)
Net assets acquired	$	632,947

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings Per Share

(share amounts in thousands)	Three Months Ended March 31,
		2017		2016
Net income (loss)	$	47,129	$	(41,109)
Preferred stock dividends		(1,824)		(1,824)
Income (loss) available to common stockholders	$	45,305	$	(42,933)
Weighted average shares outstanding		201,054		83,582
Dilutive impact of restricted stock		686		—
Weighted average shares outstanding for diluted income (loss) per share		201,740		83,582
Basic income (loss) per share	$	0.23	$	(0.51)
Diluted income (loss) per share	$	0.22	$	(0.51)
Stock options (a)		15		15
Restricted stock (a)		—		25

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, 2017

Borrowings [Abstract]

Schedule of Borrowings

	March 31, 2017		December 31, 2016
Principal components:
Senior secured revolving credit facility	$	—	$	—
6.125% senior unsecured notes due 2024		400,000		400,000
Total principal outstanding		400,000		400,000
6.125% senior unsecured notes due 2024, unamortized deferred financing costs		(9,464)		(9,781)
Total carrying value of borrowings	$	390,536	$	390,219

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Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities [Abstract]

Fair Value of Derivative Instruments

	Balance Sheet Presentation		Asset Fair Value				Liability Fair Value				Net Derivative Fair Value
Commodity	Classification	Line Description	03/31/2017		12/31/2016		03/31/2017		12/31/2016		03/31/2017		12/31/2016
Natural gas	Current	Fair value of derivatives	$	—	$	—	$	(64)	$	(593)	$	(64)	$	(593)
Oil	Current	Fair value of derivatives		3,093		103		(6,366)		(17,675)		(3,273)		(17,572)
Oil	Non-current	Fair value of derivatives		2,939		—		—		(28)		2,939		(28)
	Totals		$	6,032	$	103	$	(6,430)	$	(18,296)	$	(398)	$	(18,193)

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

		March 31, 2017
	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	5,055	$	(1,962)	$	3,093
Long-term assets: Fair value of derivatives		2,939		—		2,939
Current liabilities: Fair value of derivatives	$	(8,392)	$	1,962	$	(6,430)

		December 31, 2016
	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	1,836	$	(1,733)	$	103
Current liabilities: Fair value of derivatives	$	(20,001)	$	1,733	$	(18,268)
Long-term liabilities: Fair value of derivatives		(28)		—		(28)

Schedule of Gain or Loss on Derivative Contracts

	Three Months Ended March 31,
		2017		2016
Oil derivatives
Net gain (loss) on settlements	$	(2,524)	$	7,507
Net gain (loss) on fair value adjustments		17,266		(9,137)
Total gain (loss) on oil derivatives	$	14,742	$	(1,630)
Natural gas derivatives
Net gain on settlements	$	33	$	209
Net gain on fair value adjustments		528		489
Total gain on natural gas derivatives	$	561	$	698
Total gain (loss) on oil & natural gas derivatives	$	15,303	$	(932)

Schedule of Outstanding Oil and Natural Gas Derivative Contracts

	For the Remainder of		For the Full Year of
Oil contracts	2017		2018
Swap contracts combined with short puts (WTI, enhanced swaps)
Total volume (MBbls)		550		—
Weighted average price per Bbl
Swap	$	44.50	$	—
Short put option	$	30.00	$	—
Deferred premium put option
Total volume (MBbls)		250		—
Premium per Bbl	$	2.05	$	—
Weighted average price per Bbl
Long put option	$	50.00	$	—
Deferred premium put spread option
Total volume (MBbls)		506		—
Premium per Bbl	$	2.45	$	—
Weighted average price per Bbl
Long put option	$	50.00	$	—
Short put option	$	40.00	$	—
Collar contracts (WTI, two-way collars)
Total volume (MBbls)		1,018		—
Weighted average price per Bbl
Ceiling (short call)	$	58.19	$	—
Floor (long put)	$	47.50	$	—
Call option contracts (short position)
Total volume (MBbls)		505		—
Weighted average price per Bbl
Call strike price	$	50.00	$	—
Swap contracts (Midland basis differential)
Volume (MBbls)		1,650		2,008
Weighted average price per Bbl	$	(0.52)	$	(1.02)
Collar contracts combined with short puts (WTI, three-way collars)
Total volume (MBbls)		—		2,738
Weighted average price per Bbl
Ceiling (short call option)	$	—	$	62.84
Floor (long put option)	$	—	$	50.00
Short put option	$	—	$	40.00

	For the Remainder of		For the Full Year of
Natural gas contracts	2017		2018
Collar contracts combined with short puts (Henry Hub, three-way collars)
Total volume (BBtu)		1,100		—
Weighted average price per MMBtu
Ceiling (short call option)	$	3.71	$	—
Floor (long put option)	$	3.00	$	—
Short put option	$	2.50	$	—
Collar contracts (Henry Hub, two-way collars)
Total volume (BBtu)		1,100		—
Weighted average price per MMBtu
Ceiling (short call option)	$	3.68	$	—
Floor (long put option)	$	3.00	$	—

Subsequent event

The following derivative contracts were executed subsequent to March 31, 2017:

	For the Remainder of		For the Full Year of
Gas contracts	2017		2018
Collar contracts (Henry Hub, two-way collars)
Total volume (BBtu)		488		720
Weighted average price per MMBtu
Ceiling (short call option)	$	3.84	$	3.84
Floor (long put option)	$	3.40	$	3.40
Swap contracts
Total volume (BBtu)		736		—
Weighted average price per MMBtu	$	3.39	$	—

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value Measurements [Abstract]

Summary of Financial Instruments at Carrying and Fair Value

	March 31, 2017				December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit Facility (a)	$	—	$	—	$	—	$	—
6.125% Senior Notes (b)		390,536		416,000		390,219		412,000
Total	$	390,536	$	416,000	$	390,219	$	412,000

(a) Floating-rate debt.

(b) The fair value was based upon Level 2 inputs. See Note 4 for additional information about the Company’s 6.125% Senior Notes.

Fair Value of Assets and Liabilities Measured on Recurring Basis

March 31, 2017	Classification		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	6,032	$	—	$	6,032
Liabilities
Derivative financial instruments	Fair value of derivatives		—		(6,430)		—		(6,430)
Total net liabilities		$	—	$	(398)	$	—	$	(398)
December 31, 2016	Classification		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	103	$	—	$	103
Liabilities
Derivative financial instruments	Fair value of derivatives		—		(18,296)		—		(18,296)
Total net liabilities		$	—	$	(18,193)	$	—	$	(18,193)

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2017

Asset Retirement Obligations [Abstract]

Summary of Activity of Asset Retirement Obligations

	For the Three Months Ended
	March 31, 2017
Asset retirement obligations at January 1, 2017	$	6,661
Accretion expense		184
Liabilities incurred		195
Liabilities settled		(88)
Revisions to estimate		(712)
Asset retirement obligations at end of period		6,240
Less: Current asset retirement obligations		(1,588)
Long-term asset retirement obligations at March 31, 2017	$	4,652

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Acquisitions (Narrative) (Details) $ / shares in Units, $ in Thousands				1 Months Ended
	Feb. 13, 2017 USD ($) a	Oct. 20, 2016 USD ($) a	May 26, 2016 USD ($) a $ / shares shares	Apr. 30, 2017 USD ($) a	Dec. 31, 2016 USD ($)
Business Acquisition [Line Items]
Acquisition deposit | $					$ 46,138
Midland Basin in Howard County, Texas [Member] | October 20, 2016 Acquisitions [Member] | Plymouth Transaction [Member]
Business Acquisition [Line Items]
Consideration transferred | $		$ 339,687
Gas and oil area, developed and undeveloped, gross		6,904
Gas and oil area, developed and undeveloped, net		5,952
Working interest		82.00%
Net revenue interest		62.00%
Midland Basin in Howard County, Texas [Member] | May 26, 2016 Acquisitions [Member] | Big Star Transaction [Member]
Business Acquisition [Line Items]
Consideration transferred | $			$ 220,000
Aggregate purchase price | $			$ 329,573
Shares of common stock issued in acquisition | shares			9,333,333
Sales price of common stock | $ / shares			$ 11.74
Gas and oil area, developed and undeveloped, gross			17,298
Gas and oil area, developed and undeveloped, net			14,089
Working interest			81.00%
Net revenue interest			61.00%
Delaware Basin [Member] | February 13, 2017 Acquisitions [Member] | Ameredev Transaction [Member]
Business Acquisition [Line Items]
Consideration transferred | $	$ 632,947
Aggregate purchase price | $	$ 632,947
Gas and oil area, developed and undeveloped, gross	29,175
Gas and oil area, developed and undeveloped, net	16,688
Working interest	82.00%
Delaware Basin [Member] | April 2017 Acquisitions [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Consideration transferred | $				$ 52,500
Gas and oil area, developed and undeveloped, gross				7,031
Gas and oil area, developed and undeveloped, net				2,488

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Acquisitions (Fair Value of Net Assets Acquired ) (Details) - Delaware Basin [Member] - Ameredev Transaction [Member] - February 13, 2017 Acquisitions [Member] $ in Thousands	Feb. 13, 2017 USD ($)
Business Acquisition [Line Items]
Asset retirement obligations	$ (168)
Net assets acquired	632,947
Evaluated Oil and Natural Gas Properties [Member]
Business Acquisition [Line Items]
Oil and natural gas properties	134,315
Unevaluated Oil and Natural Gas Properties [Member]
Business Acquisition [Line Items]
Oil and natural gas properties	$ 498,800

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Acquisitions (Unaudited Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Acquisitions [Abstract]
Revenues	[1]	$ 84,416	$ 42,615
Income (loss) from operations	[1]	34,907	(35,451)
Income (loss) available to common stockholders	[1]	$ 47,963	$ (38,908)
Net income (loss) per common share Basic	[1]	$ 0.24	$ (0.31)
Net income (loss) per common share Diluted	[1]	$ 0.24	$ (0.31)

[1] The pro forma financial information was prepared assuming the Ameredev Transaction occurred as of January 1, 2016 and the Plymouth Transaction and Big Star Transaction occurred as of January 1, 2015.

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Earnings Per Share (Computation of Basic and Diluted Earnings Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share, Basic and Diluted
Net income (loss)		$ 47,129	$ (41,109)
Preferred stock dividends		(1,824)	(1,824)
Income (loss) available to common stockholders		$ 45,305	$ (42,933)
Weighted average shares outstanding		201,054	83,582
Weighted average shares outstanding for diluted income (loss) per share		201,740	83,582
Basic income (loss) per share		$ 0.23	$ (0.51)
Diluted income (loss) per share		$ 0.22	$ (0.51)
Options [Member]
Earnings Per Share, Basic and Diluted
Excluded from the diluted EPS calculation because their effect would be anti-dilutive	[1]	15	15
Restricted Stock [Member]
Earnings Per Share, Basic and Diluted
Dilutive impact		686
Excluded from the diluted EPS calculation because their effect would be anti-dilutive	[1]		25

[1] Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive

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Borrowings (Credit Facility) (Narrative) (Details) - Senior Secured Revolving Credit Facility [Member] $ in Thousands	3 Months Ended
	Mar. 31, 2017 USD ($)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 500,000
Credit facility borrowing base	$ 385,000
Credit facility maturity date	Mar. 11, 2019
Balance outstanding on credit facility	$ 0
Interest rate at period end (as a percent)	2.83%
Unused capacity, commitment fee (as a percent)	0.50%
Minimum [Member]
Line of Credit Facility [Line Items]
Debt instrument interest rate	2.00%
Maximum [Member]
Line of Credit Facility [Line Items]
Debt instrument interest rate	3.00%

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Borrowings (6.125% senior notes due 2024 (“6.125% Senior Notes”)) (Narrative) (Details) - USD ($) $ in Thousands		3 Months Ended
	Oct. 03, 2016	Mar. 31, 2017
Callon Petroleum Operating Company [Member]
Debt Instrument [Line Items]
Percentage of ownership in wholly-owned subsidiary		100.00%
Change Of Control [Member]
Debt Instrument [Line Items]
Debt instrument redemption price percent	101.00%
6.125% senior unsecured notes due 2024 [Member]
Debt Instrument [Line Items]
Debt instrument aggregate principal amount	$ 400,000
Debt instrument, interest rate, stated (as a percent)	6.125%
Debt instrument maturity date		Oct. 01, 2024
Debt instrument repayment beginning date		Apr. 01, 2017
Net proceeds from issuance of senior unsecured notes	$ 391,270
6.125% senior unsecured notes due 2024 [Member] | Prior to October 1, 2019, a Redemption of up to 35% of the Principal [Member]
Debt Instrument [Line Items]
Debt instrument redemption price percent	106.125%
Number of days to closing date of equity offerings	180 days
6.125% senior unsecured notes due 2024 [Member] | Prior to October 1, 2019, a Redemption of All or Part of the Principal [Member]
Debt Instrument [Line Items]
Debt instrument redemption price percent	100.00%
6.125% senior unsecured notes due 2024 [Member] | On or After October 1, 2019, but Before October 1, 2020 [Member]
Debt Instrument [Line Items]
Debt instrument redemption price percent	104.594%
6.125% senior unsecured notes due 2024 [Member] | On or After October 1, 2020, but Before October 1, 2021 [Member]
Debt Instrument [Line Items]
Debt instrument redemption price percent	103.063%
6.125% senior unsecured notes due 2024 [Member] | On or After October 1, 2021, but Before October 1, 2022 [Member]
Debt Instrument [Line Items]
Debt instrument redemption price percent	101.531%
6.125% senior unsecured notes due 2024 [Member] | On or After October 1, 2022 [Member]
Debt Instrument [Line Items]
Debt instrument redemption price percent	100.00%
6.125% senior unsecured notes due 2024 [Member] | Maximum [Member] | Prior to October 1, 2019, a Redemption of up to 35% of the Principal [Member]
Debt Instrument [Line Items]
Redemption principal amount percentage	35.00%
6.125% senior unsecured notes due 2024 [Member] | Minimum [Member] | Prior to October 1, 2019, a Redemption of up to 35% of the Principal [Member]
Debt Instrument [Line Items]
Redemption principal remaining amount percentage	65.00%

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Borrowings (Schedule of Borrowings) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Principal components:
Total principal outstanding	$ 400,000	$ 400,000
Total carrying value of borrowings	390,536	390,219
6.125% senior unsecured notes due 2024 [Member]
Principal components:
Total principal outstanding	400,000	400,000
Unamortized deferred financing costs	$ (9,464)	$ (9,781)

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Derivative Instruments and Hedging Activities (Fair Value of Derivative Instruments) (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Asset Fair Value	$ 6,032	$ 103
Liability Fair Value	(6,430)	(18,296)
Net Derivative Fair Value	(398)	(18,193)
Non-current assets -Fair value of derivatives [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Asset Fair Value	2,939
Non-current liabilities - Fair value of derivatives [Member]
Derivatives, Fair Value [Line Items]
Liability Fair Value		(28)
Non-current liabilities - Fair value of derivatives [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Liability Fair Value		(28)
Current assets - Fair value of derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Fair Value	3,093	103
Current assets - Fair value of derivatives [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Asset Fair Value	3,093	103
Current liabilities - Fair value of derivatives [Member]
Derivatives, Fair Value [Line Items]
Liability Fair Value	(6,430)	(18,268)
Current liabilities - Fair value of derivatives [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Liability Fair Value	(6,366)	(17,675)
Current liabilities - Fair value of derivatives [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Liability Fair Value	(64)	(593)
Balance Sheet Current [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	(3,273)	(17,572)
Balance Sheet Current [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	(64)	(593)
Balance Sheet Non Current [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Net Derivative Fair Value	$ 2,939	$ (28)

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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 [Member] - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Offsetting Assets and Liabilities [Line Items]
Derivative Assets	$ 6,032	$ 103
Derivative Liabilities	(6,430)	(18,296)
Current assets - Fair value of derivatives [Member]
Offsetting Assets and Liabilities [Line Items]
Derivative asset, fair value, gross asset	5,055	1,836
Derivative asset, fair value, gross liability	(1,962)	(1,733)
Derivative Assets	3,093	103
Long-term assets: Fair value of derivatives [Member]
Offsetting Assets and Liabilities [Line Items]
Derivative asset, fair value, gross asset	2,939
Derivative Assets	2,939
Current liabilities - Fair value of derivatives [Member]
Offsetting Assets and Liabilities [Line Items]
Derivative liability, fair value, gross liability	(8,392)	(20,001)
Derivative liability, fair value, gross asset	1,962	1,733
Derivative Liabilities	$ (6,430)	(18,268)
Non-current liabilities - Fair value of derivatives [Member]
Offsetting Assets and Liabilities [Line Items]
Derivative liability, fair value, gross liability		(28)
Derivative Liabilities		$ (28)

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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, 2017	Mar. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on fair value adjustments	$ 17,794	$ (8,648)
Total gain (loss) on derivative contracts	15,303	(932)
Crude Oil [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	(2,524)	7,507
Net gain (loss) on fair value adjustments	17,266	(9,137)
Total gain (loss) on derivative contracts	14,742	(1,630)
Natural Gas [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	33	209
Net gain (loss) on fair value adjustments	528	489
Total gain (loss) on derivative contracts	$ 561	$ 698

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Derivative Instruments and Hedging Activities (Schedule of Outstanding Oil and Natural Gas Derivative Contracts) (Details) - Not Designated as Hedging Instrument [Member] MMBTU in Thousands	1 Months Ended	3 Months Ended
	May 02, 2017 MMBTU $ / MMBTU	Mar. 31, 2017 MMBTU $ / MMBTU $ / bbl MBbls
Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Total volume | MBbls		550
Swap Contracts Combined with Short Puts (WTI, Enhanced Swaps) for Full Year of 2017 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member]
Derivative [Line Items]
Strike price		30.00
Swap Contracts Combined with Short Puts (WTI, Enhanced Swaps) for Full Year of 2017 [Member] | Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Average swap price		44.50
Deferred Premium Put Option for Full Year of 2017 [Member] | Crude Oil [Member] | Put Option [Member]
Derivative [Line Items]
Total volume | MBbls		250
Average swap price		2.05
Deferred Premium Put Option for Full Year of 2017 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member]
Derivative [Line Items]
Strike price		50.00
Deferred Premium Put Spread Option for Full Year of 2017 [Member] | Crude Oil [Member]
Derivative [Line Items]
Total volume | MBbls		506
Average swap price		2.45
Deferred Premium Put Spread Option for Full Year of 2017 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member]
Derivative [Line Items]
Strike price		50.00
Deferred Premium Put Spread Option for Full Year of 2017 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member]
Derivative [Line Items]
Strike price		40.00
Collar Contracts (WTI, Two-Way Collars) for Full Year of 2017 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member]
Derivative [Line Items]
Total volume | MBbls		1,018
Strike price		58.19
Collar Contracts (WTI, Two-Way Collars) for Full Year of 2017 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member]
Derivative [Line Items]
Strike price		47.50
Call Option Contracts (Short Position) for Full Year of 2017 [Member] | Crude Oil [Member] | Call Option [Member]
Derivative [Line Items]
Strike price		50.00
Call Option Contracts (Short Position) for Full Year of 2017 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member]
Derivative [Line Items]
Total volume | MBbls		505
Swap Contracts Differentials (Midland Basis Differential) for Full Year of 2017 [Member] [Member] | Crude Oil [Member]
Derivative [Line Items]
Total volume | MBbls		1,650
Average swap price		(0.52)
Swap Contracts Differentials (Midland Basis Differential) for Full Year of 2018 [Member] [Member] | Crude Oil [Member]
Derivative [Line Items]
Total volume | MBbls		2,008
Average swap price		(1.02)
Collar Contracts Combined With Short Puts (Henry Hub Three-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member]
Derivative [Line Items]
Total volume | MMBTU		1,100
Collar Contracts Combined With Short Puts (Henry Hub Three-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | Call Option [Member] | Short [Member]
Derivative [Line Items]
Strike price | $ / MMBTU		3.71
Collar Contracts Combined With Short Puts (Henry Hub Three-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | Put Option [Member] | Long [Member]
Derivative [Line Items]
Strike price | $ / MMBTU		3.00
Collar Contracts Combined With Short Puts (Henry Hub Three-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | Put Option [Member] | Short [Member]
Derivative [Line Items]
Strike price | $ / MMBTU		2.50
Collar Contracts Combined with Short Puts (WTI, Three-Way Collars) for Full Year of 2018 [Member] | Crude Oil [Member]
Derivative [Line Items]
Total volume | MBbls		2,738
Collar Contracts Combined with Short Puts (WTI, Three-Way Collars) for Full Year of 2018 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member]
Derivative [Line Items]
Strike price		62.84
Collar Contracts Combined with Short Puts (WTI, Three-Way Collars) for Full Year of 2018 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member]
Derivative [Line Items]
Strike price		50.00
Collar Contracts Combined with Short Puts (WTI, Three-Way Collars) for Full Year of 2018 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member]
Derivative [Line Items]
Strike price		40.00
Collar Contracts (Henry Hub, Two-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member]
Derivative [Line Items]
Total volume | MMBTU		1,100
Collar Contracts (Henry Hub, Two-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | Subsequent Event [Member]
Derivative [Line Items]
Total volume | MMBTU	488
Collar Contracts (Henry Hub, Two-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | Call Option [Member] | Short [Member]
Derivative [Line Items]
Strike price | $ / MMBTU		3.68
Collar Contracts (Henry Hub, Two-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | Call Option [Member] | Short [Member] | Subsequent Event [Member]
Derivative [Line Items]
Strike price | $ / MMBTU	3.84
Collar Contracts (Henry Hub, Two-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | Put Option [Member] | Long [Member]
Derivative [Line Items]
Strike price | $ / MMBTU		3.00
Collar Contracts (Henry Hub, Two-Way Collars) for Remainder of 2017 [Member] | Natural Gas [Member] | Put Option [Member] | Long [Member] | Subsequent Event [Member]
Derivative [Line Items]
Strike price | $ / MMBTU	3.40
Collar Contracts (Henry Hub, Two-Way Collars) for Remainder of 2018 [Member] | Natural Gas [Member] | Subsequent Event [Member]
Derivative [Line Items]
Total volume | MMBTU	720
Collar Contracts (Henry Hub, Two-Way Collars) for Remainder of 2018 [Member] | Natural Gas [Member] | Call Option [Member] | Short [Member] | Subsequent Event [Member]
Derivative [Line Items]
Strike price | $ / MMBTU	3.84
Collar Contracts (Henry Hub, Two-Way Collars) for Remainder of 2018 [Member] | Natural Gas [Member] | Put Option [Member] | Long [Member] | Subsequent Event [Member]
Derivative [Line Items]
Strike price | $ / MMBTU	3.40
Swap Contracts for Remainder of 2017 [Member] | Natural Gas [Member] | Subsequent Event [Member]
Derivative [Line Items]
Total volume | MMBTU	736
Average swap price | $ / MMBTU	3.39

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Fair Value Measurements (Summary of Financial Instruments at Carrying and Fair Value) (Details) - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016
Carrying Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total		$ 390,536	$ 390,219
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total		416,000	412,000
6.125% senior unsecured notes due 2024 [Member] | Carrying Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
6.125% Senior Notes	[1]	390,536	390,219
6.125% senior unsecured notes due 2024 [Member] | Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
6.125% Senior Notes	[1]	$ 416,000	$ 412,000

[1] The fair value was based upon Level 2 inputs. See Note 4 for additional information about the Company's 6.125% Senior Notes.

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Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Derivative Assets
Derivative Asset	$ 6,032	$ 103
Derivative Liabilities
Derivative Liabilities	(6,430)	(18,296)
Total net liabilities	(398)	(18,193)
Level 2 [Member]
Derivative Assets
Derivative Asset	6,032	103
Derivative Liabilities
Derivative Liabilities	(6,430)	(18,296)
Total net liabilities	$ (398)	$ (18,193)

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Income Taxes (Narrative) (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017 USD ($)
Income Taxes [Abstract]
Statutory income tax rate, percent	35.00%
Deferred tax assets, valuation allowance	$ 127,073
Cummulative loss incurred, period	3 years

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Asset Retirement Obligations (Summary of Activity of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Mar. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$ 6,661
Accretion expense	184	$ 180
Liabilities incurred	195
Liabilities settled	(88)
Revisions to estimate	(712)
Asset retirement obligations at end of period	$ 6,661		$ 6,240	$ 6,661
Less: Current asset retirement obligations			(1,588)	(2,729)
Long-term asset retirement obligations at the end of the period			4,652	3,932
Restricted Investments
Restricted investments			$ 3,339	$ 3,332

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Equity Transactions (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands							3 Months Ended
	Dec. 19, 2016	Sep. 06, 2016	May 26, 2016	Apr. 25, 2016	Mar. 09, 2016	Feb. 04, 2016	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Class of Stock [Line Items]
Preferred stock dividend							$ 1,824	$ 1,824
Preferred stock redemption, description							The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date.
Proceeds from issuance of common stock								94,949
Series A Preferred Stock [Member]
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							$ 5.00
Preferred stock dividend							$ 1,824	$ 1,824
Preferred stock, redemption price per share							$ 50.00
Value of a share of common stock							$ 13.16
Conversion ratio of preferred stock to common stock							3.8
Conversion of stock, shares converted						120,000
Preferred stock, shares outstanding							1,458,948		1,458,948
Preferred stock, shares issued							1,458,948
Common Stock
Class of Stock [Line Items]
Conversion of stock, shares issued						719,000
Shares of common stock issued in public offering	40,000,000	29,900,000		25,300,000	15,250,000
Proceeds from issuance of common stock	$ 634,917	$ 421,864		$ 205,869	$ 94,948
Common Stock | Big Star Transaction [Member]
Class of Stock [Line Items]
Shares of common stock issued in acquisition			9,333,333
Sales price of shares issued			$ 11.74

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Other (Narrative) (Details) - Horizontal Drilling Rig [Member]	1 Months Ended	3 Months Ended
	Apr. 30, 2017 $ / d	Mar. 31, 2017 contract
Operating Leases And Other Property Plant And Equipment [Line Items]
Number of contracts | contract		3
Subsequent Event [Member]
Operating Leases And Other Property Plant And Equipment [Line Items]
Operating lease rate per day beginning July 2017 through July 2019 | $ / d	18,000