10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For The Quarterly Period Ended June 30, 2014

OR

☐TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

For the transition period ____________ 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, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting 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	☐

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

As of August 1, 2014,  40,843,827 shares of the Registrant’s common stock, par value $0.01 per share, were outstanding.

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	17
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 statutorily prescribed meanings when used in this report. As used in this document:

· ARO:  Asset retirement obligation.

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

· BBtu:  billion Btu

· Bcf:  billion cubic feet.

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

· BOE/d:  BOE per day.

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

· LIBOR:  London Interbank Offered Rate.

· LOE:  lease operating expense.

· MBbls:  thousand barrels of oil.

· MBOE:  thousand BOE.

· MBOE/d:  MBOE per day.

· Mcf:  thousand cubic feet of natural gas.

· Mcfe:  thousand cubic feet of natural gas equivalents.

· Mcf/d:  Mcf per day.

· MMBbls:  million barrels of oil.

· MMBOE:  million BOE.

· MMBtu:  million Btu.

· MMcf:  million cubic feet of natural gas.

· MMcf/d:  MMcf per day.

· 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.

· GAAP: Generally Accepted Accounting Principles in the United States

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)

	June 30, 2014		December 31, 2013
ASSETS		Unaudited
Current assets:
Cash and cash equivalents	$	1,172	$	3,012
Accounts receivable		26,951		20,586
Deferred tax asset		5,846		3,843
Other current assets		1,798		2,123
Total current assets		35,767		29,564
Oil and natural gas properties, full cost accounting method:
Evaluated properties		1,844,691		1,701,577
Less accumulated depreciation, depletion and amortization		(1,444,169)		(1,420,612)
Net oil and natural gas properties		400,522		280,965
Unevaluated properties		36,957		43,222
Total oil and natural gas properties		437,479		324,187
Other property and equipment, net		7,388		7,255
Restricted investments		3,806		3,806
Deferred tax asset		50,421		57,765
Other assets, net		5,057		1,376
Total assets	$	539,918	$	423,953
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	61,028	$	53,464
Market-based restricted stock unit awards		6,683		4,173
Asset retirement obligations		2,846		4,120
Fair value of derivatives		5,306		1,036
Total current liabilities		75,863		62,793
13% senior notes:
Principal outstanding		—		48,481
Deferred credit, net of accumulated amortization of $0 and $26,239, respectively		—		5,267
Total 13% senior notes		—		53,748
Senior secured revolving credit facility		84,000		22,000
Second lien term loan facility		82,500		—
Asset retirement obligations		2,752		2,612
Market-based restricted stock unit awards		10,717		3,409
Other long-term liabilities		1,497		297
Total liabilities		257,329		144,859
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,578,948 and 1,578,948 shares outstanding, respectively		16		16
Common stock, $0.01 par value, 110,000,000 and 60,000,000 shares authorized; 40,785,751 and 40,345,456 shares outstanding, respectively		408		404
Capital in excess of par value		402,375		401,540
Accumulated deficit		(120,210)		(122,866)
Total stockholders’ equity		282,589		279,094
Total liabilities and stockholders’ equity	$	539,918	$	423,953

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 June 30,				Six Months Ended June 30,
		2014		2013		2014		2013
Operating revenues:
Oil sales	$	37,710	$	19,061	$	68,619	$	38,601
Natural gas sales		2,792		3,699		5,168		6,700
Total operating revenues		40,502		22,760		73,787		45,301
Operating expenses:
Lease operating expenses		4,363		5,259		8,593		10,836
Production taxes		2,265		812		4,182		1,532
Depreciation, depletion and amortization		11,982		10,654		22,520		21,696
General and administrative		9,639		4,545		20,446		8,284
Accretion expense		173		533		401		1,098
Gain on sale of other property and equipment		—		—		(1,080)		—
Total operating expenses		28,422		21,803		55,062		43,446
Income from operations		12,080		957		18,725		1,855
Other (income) expenses:
Interest expense		1,825		1,537		2,802		3,052
Gain on early extinguishment of debt		(3,205)		—		(3,205)		—
Loss (gain) on derivative contracts		4,685		(1,981)		7,198		(1,563)
Other (income) expense		(93)		(44)		(142)		(89)
Total other expenses		3,212		(488)		6,653		1,400
Income before income taxes		8,868		1,445		12,072		455
Income tax expense		4,128		663		5,469		494
Income (loss) before equity in earnings of Medusa Spar  LLC		4,740		782		6,603		(39)
Loss from Medusa Spar LLC		—		(24)		—		(3)
Net income (loss)		4,740		758		6,603		(42)
Preferred stock dividends		(1,973)		(680)		(3,947)		(680)
Income (loss) available to common stockholders	$	2,767	$	78	$	2,656	$	(722)
Income (loss) per common share:
Basic	$	0.07	$	0.00	$	0.07	$	(0.02)
Diluted	$	0.07	$	0.00	$	0.06	$	(0.02)
Shares used in computing income (loss) per common share:
Basic		40,606		40,089		40,467		39,941
Diluted		41,605		40,323		41,652		39,941

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

5

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)

	Six Months Ended June 30,
		2014		2013
Cash flows from operating activities:
Net income	$	6,603	$	(42)
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization		22,976		22,405
Accretion expense		401		1,098
Amortization of non-cash debt related items		298		228
Amortization of deferred credit		(433)		(1,615)
Equity in earnings of Medusa Spar LLC		—		3
Deferred income tax expense		5,469		494
Net loss (gain) on derivatives, net of settlements		4,677		(249)
Gain on sale of other property and equipment		(1,080)		—
Non-cash gain for early debt extinguishment		(3,205)		—
Non-cash expense related to equity share-based awards		(36)		734
Change in the fair value of liability share-based awards		8,070		(852)
Payments to settle asset retirement obligations		(1,469)		(615)
Changes in current assets and liabilities:
Accounts receivable		(5,268)		789
Other current assets		265		598
Current liabilities		2,014		(324)
Payments to settle vested liability share-based awards		(3,469)		(239)
Change in other long-term liabilities		—		(386)
Change in other assets, net		(216)		(1,790)
Net cash provided by operating activities		35,597		20,237
Cash flows from investing activities:
Capital expenditures		(127,219)		(58,385)
Acquisition		—		(11,000)
Proceeds from sales of mineral interest and equipment		2,267		1,389
Distribution from Medusa Spar LLC		—		616
Net cash used in investing activities		(124,952)		(67,380)
Cash flows from financing activities:
Borrowings on debt		150,000		31,000
Payment of deferred financing costs		(2,928)		—
Payments on debt		(55,610)		(41,000)
Issuance of preferred stock		—		70,090
Payment of preferred stock dividends		(3,947)		(680)
Net cash provided by financing activities		87,515		59,410
Net change in cash and cash equivalents		(1,840)		12,267
Balance, beginning of period		3,012		1,139
Balance, end of period	$	1,172	$	13,406

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

6

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Description of Business and Basis of Presentation	6.	Fair Value Measurements
2.	Oil and Natural Gas Properties	7.	Income Taxes
3.	Earnings Per Share	8.	Asset Retirement Obligations
4.	Borrowings	9.	Preferred Stock
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 oil and natural gas reserves in the Permian Basin in West Texas. In late 2013, with the sale of its remaining offshore assets in the Gulf of Mexico, the Company completed the onshore strategic repositioning it initiated in 2009. 

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 the 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, 2013. The balance sheet at December 31, 2013 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, 2014.

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. When necessary to ensure consistent presentation, certain prior year amounts may be reclassified to conform to presentation in the current period. Certain prior year amounts have been reclassified to conform to current year presentation.

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Footnotes to the Financial Statements (continued) (Unless otherwise indicated, dollar amounts included in the footnotes to the financial statements are presented in thousands, except for per share and per unit data)     Table of Contents

Recently issued accounting policies

In May 2014, the Financial Accounting Standards Board issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. The guidance in ASU No. 2014-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted.  The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.

Note 2 – Oil and Natural Gas Properties

Acquisitions

In the first quarter of 2014, the Company acquired1,527 net acres in Upton and Reagan Counties, Texas, which are located in the southern portion of the Midland Basin near our existing core development fields, for an aggregate cash purchase price of $8,200. The properties bear a working interest of 100% and an average net revenue interest of 78%.

Acreage expiration

During the six months ended June 30, 2014, the Company transferred $12,940  from unevaluated properties to the full cost pool related to 8,028 net acres in the Northern Midland Basin that expired or are scheduled to expire in the near future and are no longer included in the Company’s exploration and development plans. As of June 30, 2014,  net of these expirations, Callon had a remaining net acreage position in the Northern Midland Basin of 9,480 acres which the Company is still evaluating for potential future exploration activities.

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 June 30,				Six Months Ended June 30,
		2014		2013		2014		2013
Net income (loss)	$	4,740	$	758	$	6,603	$	(42)
Preferred stock dividends		(1,973)		(680)		(3,947)		(680)
Income (loss) available to common stockholders	$	2,767	$	78	$	2,656	$	(722)
Weighted average shares outstanding		40,606		40,089		40,467		39,941
Dilutive impact of restricted stock		999		234		1,185		—
Weighted average shares outstanding for diluted income (loss) per share		41,605		40,323		41,652		39,941
Basic income (loss) per share	$	0.07	$	0.00	$	0.07	$	(0.02)
Diluted income (loss) per share	$	0.07	$	0.00	$	0.06	$	(0.02)
The following were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive:
Stock options		30		52		30		52
Restricted stock		—		267		—		267

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Footnotes to the Financial Statements (continued) (Unless otherwise indicated, dollar amounts included in the footnotes to the financial statements are presented in thousands, except for per share and per unit data)     Table of Contents

Note 4 – Borrowings

The Company’s borrowings consisted of the following at:

	June 30, 2014		December 31, 2013
Principal components:
Senior secured revolving credit facility	$	84,000	$	22,000
Second lien term loan facility		82,500		—
13% Senior Notes, principal		—		48,481
Total principal outstanding		166,500		70,481
13% Senior Notes unamortized deferred credit		—		5,267
Total carrying value of borrowings	$	166,500	$	75,748

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 participating lenders include Regions Bank, Citibank, N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, IberiaBank, N.A., OneWest Bank, N.A., SunTrust Bank and Royal Bank of Canada.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.In June 2014, the Credit Facility’s borrowing base was increased to $155,000 following a redetermination based upon a May 1, 2014 internally estimated reserve report. Subsequent redeterminations are scheduled to occur at six month intervals beginning on September 1, 2014. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties.

As of June 30, 2014, the balance outstanding on the Credit Facility was $84,000 with a weighted-average interest rate of 2.43%, calculated as the LIBOR plus a tiered rate ranging from 1.75% to 2.75%, 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.

Second lien term loan facility (the “Second Lien Facility”)

In connection with the Credit Facility, the Company also entered into the Second Lien Facility in an aggregate amount of up to $125,000, including initial commitments of $100,000 and additional availability of $25,000 subject to the consent of two-thirds of the lenders and compliance with financial covenants after giving effect to such increase. The Second Lien Facility matures on September 11, 2019, and is not subject to mandatory prepayments unless new debt or preferred stock is issued. The Second Lien Facility may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount is (i) 102% if the prepayment event occurs prior to March 11, 2015, and (ii) 101% if the prepayment event occurs on or after March 15, 2015 but before March 15, 2016, and (iii) 100% for prepayments made on or after March 15, 2016. The Second Lien Facility is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement.

On April 10, 2014, the Company drew an initial amount of $62,500 with an original issue discount of 1.0%. Subsequent draws, allowable during the first year, are subject to the same 1.0% original issue discount on the drawn amount, applied on the date such draw is funded. In addition, the Second Lien Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the initial commitment amount until March 11, 2015. As of June 30, 2014, the balance outstanding on the Second Lien Facility was $82,500 with an interest rate of8.75%, calculated at a rate of LIBOR (subject to a floor rate of 1.0%) plus 7.75% per annum.

13% senior notes due 2016 (“Senior Notes”) and deferred credit

On April 11, 2014, the Company completed a full redemption of the remaining $48,481 principal amount of outstanding Senior Notes using proceeds from the Second Lien Facility. The redemption resulted in a net $3,205 gain on the early extinguishment of debt (including $4,780 of accelerated deferred credit amortization). The gain represents the difference between the $50,057 paid for the redemption of the Senior Notes ($1,576 of redemption costs, primarily the call premium) and the carrying value of the remaining

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Footnotes to the Financial Statements (continued) (Unless otherwise indicated, dollar amounts included in the footnotes to the financial statements are presented in thousands, except for per share and per unit data)     Table of Contents

Senior Notes of $53,261 (inclusive of $4,780 of deferred credit). The Company also paid $193in accrued interest through the redemption date. Upon the redemption, the indenture governing the Senior Notes was discharged in accordance with its terms.

Restrictive covenants

The Company’s Credit Facility and Second Lien Facility contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at June 30, 2014

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, puts, calls 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 a derivative instruments’ fair value; seeNote 6 for additional information regarding fair value.

The Company executes commodity derivative contracts under master agreements that have netting provisions that provide for offsetting payables against receivables. 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, depending on the type of instrument, the Company utilizes present value methods or standard option valuation models 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 elected not to designate its derivative contracts as accounting hedges under Accounting Standards Codification 815.Consequently, the Company records its derivative contracts at fair value in the consolidated balance sheet and records changes in fair value as a gain or loss on derivative contracts in the consolidated statement of operations.Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statement of operations.

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Footnotes to the Financial Statements (continued) (Unless otherwise indicated, dollar amounts included in the footnotes to the financial statements are presented in thousands, except for per share and per unit data)     Table of Contents

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	06/30/14		12/31/2013		06/30/2014		12/31/2013		06/30/2014		12/31/2013
Natural gas	Current	Fair value of derivatives	$	—	$	—	$	(114)	$	—	$	(114)	$	—
Natural gas	Current	Other current assets		—		60		—		—		—		60
Natural gas	Non-current	Other long-term liabilities		—		—		(29)		(72)		(29)		(72)
Oil	Current	Fair value of derivatives		—		—		(5,192)		(1,036)		(5,192)		(1,036)
Oil	Non-current	Other long-term assets		851		—		—		—		851		—
Oil	Non-current	Other long-term liabilities		—		—		(1,242)		—		(1,242)		—
	Totals		$	851	$	60	$	(6,577)	$	(1,108)	$	(5,726)	$	(1,048)

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 at June 30, 2014:

	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	26	$	(26)	$	—
Long-term assets: Fair value of derivatives		851		—		851
Current liabilities: Fair value of derivatives		(5,332)		26		(5,306)
Long-term liabilities: Fair value of derivatives	$	(1,271)	$	—	$	(1,271)

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 June 30,				Six Months Ended June 30,
		2014		2013		2014		2013
Natural gas derivatives
Net loss on settlements	$	(77)	$	(156)	$	(179)	$	(107)
Net gain (loss) on fair value adjustments		58		485		(132)		97
Total gain (loss)	$	(19)	$	329	$	(311)	$	(10)
Oil derivatives
Net gain (loss) on settlements	$	(1,569)	$	849	$	(2,341)	$	1,422
Net gain (loss) on fair value adjustments		(3,097)		803		(4,546)		151
Total gain (loss)	$	(4,666)	$	1,652	$	(6,887)	$	1,573
Total gain (loss) on derivative instruments	$	(4,685)	$	1,981	$	(7,198)	$	1,563

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Footnotes to the Financial Statements (continued) (Unless otherwise indicated, dollar amounts included in the footnotes to the financial statements are presented in thousands, except for 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 June 30, 2014:

	For the Six Months Ending December 31,		For the Year Ending December 31,
Oil contracts	2014		2015
Collar contracts combined with short puts (three-way collar):
Volume (MBbls)		—		317
Price per Bbl
Ceiling (short call)		—	$	99.10
Floor (long put)		—	$	90.00
Short put		—	$	75.00
Swap contracts:
Total volume (MBbls)		304		—
Weighted average price per Bbl	$	95.10		—
Put spreads:
Volume (MBbls)		—		276
Long put price per Bbl		—	$	90.00
Short put price per Bbl		—	$	75.00
Swap contracts combined with short put:
Volume (MBbls)		184		—
Swap price per Bbl	$	93.35		—
Short put price per Bbl	$	70.00		—
	For the Six Months Ending December 31,		For the Year Ending December 31,
Natural gas contracts	2014		2015
Call contracts:
Volume (MMBtu)		230		—
Short call price per MMBtu (a)	$	4.75		—
Long call price per MMBtu (a)	$	4.75		—
Swap contracts combined with short calls:
Swap volume (MMBtu)		368		—
Swap price per MMBtu	$	4.25		—
Short call volume (MMBtu)		—		438
Short call price per MMBtu		—	$	5.00

(a)Offsetting contracts.

Note 6 - Fair Value Measurements

The fair value hierarchy outlined in the relevant accounting guidance 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, restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.

Debt. The Company’s debt is recorded at the carrying amount in the consolidated balance sheet. The carrying amount of floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates.

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Footnotes to the Financial Statements (continued) (Unless otherwise indicated, dollar amounts included in the footnotes to the financial statements are presented in thousands, except for per share and per unit data)     Table of Contents

The following table summarizes the respective carrying and fair values at:

						`
	June 30, 2014				December 31, 2013
	Carrying Value		Fair Value			Carrying Value	Fair Value
Credit Facility	$	84,000	$	84,000	$	22,000	$	22,000
Second Lien Facility		82,500		82,500		—		—
13% Senior Notes due 2016 (a)		—		—		53,748		50,299
Total	$	166,500	$	166,500	$	75,748	$	72,299

(a) Fair value is calculated only in relation to the $48,481 principal outstanding of the Senior Notes at December 31, 2013 and excludes the remaining $5,267 deferred credit. The fair value of the Senior Notes, which is valued using Level 2 inputs, is based upon estimates provided by an independent investment banking firm. See Note 4 for additional information.

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, and the values are corroborated by quotes obtained from counterparties to the agreements. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 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:

June 30, 2014	Balance Sheet Presentation		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments (non-current)	Other long-term assets	$	—	$	851	$	—	$	851
Sub-total assets		$	—	$	851	$	—	$	851
Liabilities
Derivative financial instruments (current)	Fair value of derivatives	$	—	$	(5,306)	$	—	$	(5,306)
Derivative financial instruments (non-current)	Other long-term liabilities		—		(1,271)		—		(1,271)
Sub-total liabilities		$	—	$	(6,577)	$	—	$	(6,577)
Total net assets (liabilities)		$	—	$	(5,726)	$	—	$	(5,726)
December 31, 2013	Balance Sheet Presentation		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments (current)	Other current assets	$	—	$	60	$	—	$	60
Sub-total assets		$	—	$	60	$	—	$	60
Liabilities
Derivative financial instruments (current)	Fair value of derivatives	$	—	$	(1,036)	$	—	$	(1,036)
Derivative financial instruments (non-current)	Other long-term liabilities		—		(72)		—		(72)
Sub-total liabilities		$	—	$	(1,108)	$	—	$	(1,108)
Total net assets (liabilities)		$	—	$	(1,048)	$	—	$	(1,048)

The derivative fair values above are based on analysis of each contract. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 5 for a discussion of net amounts recorded in the consolidated balance sheet at June 30, 2014.

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Footnotes to the Financial Statements (continued) (Unless otherwise indicated, dollar amounts included in the footnotes to the financial statements are presented in thousands, except for per share and per unit data)     Table of Contents

Note 7 - Income Taxes

The Company provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. The effective tax rate for the six months ended June 30, 2014 and 2013 was  45% and 109%, respectively.

Note 8 - Asset Retirement Obligations

The table below summarizes the Company’s asset retirement obligations activity for the six months ended June 30, 2014:

Asset retirement obligations at January 1, 2014	$	6,732
Accretion expense		401
Liabilities incurred		404
Liabilities settled		(1,747)
Revisions to estimate		(192)
Asset retirement obligations at end of period		5,598
Less: Current asset retirement obligations		2,846
Long-term asset retirement obligations at June 30, 2014	$	2,752

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheets as restricted investments were $3,806 at June 30, 2014. These investments include primarily U.S. Government securities, and are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.

Note 9 – 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. For the quarter ended June 30, 2014, the Board declared a dividend of $1.25 per share, or a total of$1,973, on the Company’s Preferred Stock. Dividends for the six months ended June 30, 2014 were$3,947.

As defined in a provision of the Preferred Stock prospectus, the common shares reserved for issuance vary based on the number of authorized common shares. In January 2014, following a majority shareholder vote, the number of authorized shares of common stock was increased from 60,000,000 to 110,000,000 with a corresponding increase in the number of common shares reserved for a potential conversion to a maximum of 42,200,000 shares. Based on the Company’s closing common stock price of $11.65 per share on June 30, 2014, the Company has reserved 6,776,601 shares of its total authorized shares to satisfy a potential conversion that would be subject to the satisfaction of several conditions, including a change of control as defined in description of Preferred Stock.

Note 10 – Other

Operating leases

In April 2012, the Company contracted a drilling rig (the “Cactus 1 Rig”) for a term of two years, which it subsequently renewed in March 2014 for an additional two-year term ending in April 2016. In April 2014, the Company contracted an additional horizontal drilling rig (the “Cactus 2 Rig”) for a term of two years ending in April 2016. The Cactus 2 Rig replaced a previously contracted horizontal drilling rig, which was cancelled in March 2014. The Cactus 1 and Cactus 2 Rig lease agreements include early termination provisions that would reduce the minimum rentals under the agreement, and also include early termination payments that would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee. Lease payments in 2014,  2015 and 2016 are expected to approximate $18,111 (with $9,200 remaining at June 30, 2014), $18,250 and $4,795, respectively.

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Footnotes to the Financial Statements (continued) (Unless otherwise indicated, dollar amounts included in the footnotes to the financial statements are presented in thousands, except for per share and per unit data)     Table of Contents

Other property and equipment

As disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, the Company made a decision to abandon certain specialized deep water property and equipment received as part of a prior settlement agreement related to various disputes with a previous joint interest partner as a result of the unsuccessful marketing of such assets. Accordingly, the Company recognized an impairment charge of $1,707 related to such property and equipment in the year ended December 31, 2013. Subsequent to the filing of the Annual Report on Form 10-K, the Company entered into an agreement to sell the property and equipment to a third party. While the third party had previously performed some initial inspection and evaluation of the equipment, based on the amount of time the equipment had been unsuccessfully marketed and the feedback from potential buyers, management concluded the likelihood of completing a sale of the equipment was low, resulting in the decision to abandon the equipment and recognize an impairment charge in 2013. As a result of the subsequent sale of the property and equipment, the Company recognized a gain of $1,080 in the first quarter 2014.

Subsequent Events

In August 2014, the Company signed a one-year contract for a vertical drilling rig to be used as part of our horizontal drilling program, drilling the vertical component of horizontal wells. Lease payments in 2014 and 2015 are expected to approximate $1,656 and $4,914, respectively, subject to customary termination provisions.

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

Special Note Regarding Forward Looking Statements

All statements, other than statements of historical fact, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve quantities, present value and growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance.

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-Q identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and 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 addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

· the timing and extent of changes in market conditions and prices for oil, natural gas and NGLs (including regional basis differentials),

· our ability to transport our production to the most favorable markets or at all,

· the timing and extent of our success in discovering, developing, producing and estimating reserves,

· our ability to fund our planned capital investments,

· the impact of government regulation, including regulation of endangered species, any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over-the-counter derivatives,

· the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services,

· our future property acquisition or divestiture activities,

· the effects of weather,

· increased competition,

· the financial impact of accounting regulations and critical accounting policies,

· the comparative cost of alternative fuels,

· conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed,

· credit risk relating to the risk of loss as a result of non-performance by our counterparties, and

· any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission.

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, 2013 (the 2013 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto.

Should one or more of the risks or uncertainties described above or in our 2013 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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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 2013 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, and more specifically, the Midland Basin. Our operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation. 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 acreage purchases, joint ventures and asset swaps. Our production was approximately  84% oil and 16% natural gas for the six months endedJune 30, 2014. On June 30, 2014, our net acreage position in the Permian Basin was approximately 25,208 net acres, including 9,480 exploratory net acres in the Northern Midland Basin.

Recent Developments

Redemption of Senior Notes

On April 11, 2014, the Company redeemed the remaining $48.5 million aggregate principal amount of its outstanding Senior Notes at a redemption price of 103.25% plus accrued and unpaid interest (approximately $50.3 million, including $0.2 million in accrued interest).

Acceleration of Horizontal Development Program

The Company recently entered into a one-year contract for a vertical drilling rig that will be used to drill the vertical sections of horizontal wells and facilitate the acceleration of its horizontal development program. The Company will take delivery of the rig in October 2014.

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Operational Highlights

Following the sale of our remaining offshore and Haynesville properties in the fourth quarter of 2013, all of our producing properties are located in the Permian Basin. Our Permian production grew 182% and 178% for the three and six months ended June 30, 2014, respectively, compared to the same periods of 2013  increasing to 480 MBOE from 170 MBOE and 873 MBOE from314 MBOE for the comparative three and six months periods, respectively.

	Net Production (MBOE)
	Three Months Ended June 30,
	2014	2013	Change	% Change
Onshore:
Southern Midland Basin	372	122	250	205%
Central Midland Basin	103	48	55	114%
Northern Midland Basin	5	—	5	100%
Total Permian	480	170	310	182%
Offshore and other (a)	—	159	(159)	(100)%
Total	480	329	151	46%

	Net Production (MBOE)
	Six Months Ended June 30,
	2014	2013	Change	% Change
Onshore:
Southern Midland Basin	688	216	472	218%
Central Midland Basin	174	98	76	78%
Northern Midland Basin	11	—	11	100%
Total Permian	873	314	559	178%
Offshore and other (a)	—	344	(344)	(100)%
Total	873	658	215	33%

(a) In late 2013, we sold the remaining interests in our offshore fields and in the Haynesville shale.

The following table sets forth productive wells as of June 30, 2014:

	Oil Wells		Natural Gas Wells
	Gross	Net	Gross	Net
Working interest	146	123.8	—	—
Royalty interest	3	0.0	—	—
Total	149	123.8	—	—

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 Mcfe basis. However, most of our wells produce both oil and natural gas.

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The following table summarizes the Company’s drilling progress in the Permian Basin for the  six months ended June 30, 2014:

	Drilled		Completed (a)		Awaiting Completion
	Gross	Net	Gross	Net	Gross	Net
Southern Midland Basin
Vertical wells	1	1.0	1	1.0	—	—
Horizontal wells	13	12.1	12	11.3	4	3.8
Total	14	13.1	13	12.3	4	3.8
Central Midland Basin
Vertical wells	2	0.8	1	0.4	1	0.4
Horizontal wells	2	1.7	4	3.4	—	—
Total	4	2.5	5	3.8	1	0.4
Northern Midland Basin
Vertical wells	2	1.5	1	0.8	—	—
Total	2	1.5	1	0.8	—	—
Total vertical wells	5	3.3	3	2.2	1	0.4
Total horizontal wells	15	13.7	16	14.6	4	3.8
Total	20	17.1	19	16.8	5	4.2

(a) Completions include wells drilled prior to 2014.

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.

We recently entered into an amended Credit Facility and Second Lien Facility to support the funding of our ongoing operations and acquisition initiatives, which are discussed in greater detail in Note 4 to the Consolidated Financial Statements. In addition, we regularly evaluate other sources of capital, including debt and equity securities, to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans in the Permian Basin.

Based upon current commodity price expectations for 2014, we believe that our cash flow from operations and borrowings under our Credit Facility and Second Lien Facility will be sufficient to fund our operations for 2014, including any deficiencies in the Company’s current net working capital. However, future cash flows are subject to a number of variables, including forecast production volumes and commodity prices. Over 95% of our current2014 capital program is allocated to properties we operate and, as a result, the amount and timing of a substantial portion of our planned capital expenditures is largely discretionary in the event we determine it prudent to curtail drilling and completion operations due to capital constraints.

Cash and cash equivalents decreased $1.8 million in the six months ended June 30, 2014 to$1.2 million compared to $3.0 million at December 31, 2013. At June 30, 2014, our available liquidity, inclusive of undrawn amounts on our Credit Facility ($71.0 million) and Second Lien Facility  ($17.5 million), increased to $89.7 million, a $25.7 million increase over year-end 2013. This liquidity amount excludes $25 million of availability under the Second Lien Facility, which is subject to lender consent and compliance with a maximum financial leverage covenant.

19

Liquidity and cash flow

	Six Months Ended June 30,
	2014		2013
Net cash provided by operating activities	$	35.6	$	20.2
Net cash used in investing activities		(125.0)		(67.4)
Net cash provided by financing activities		87.5		59.4
Net change in cash	$	(1.9)	$	12.3

Operating activities.  For thesix months ended June 30, 2014, net cash provided by operating activities was $35.6 million, compared to $20.2 million for the same period in 2013.  The increase was primarily due to an increase in oil sales and a reduction in lease operating expense, partially offset by losses on the settlement of derivative contracts,  and an increase in production taxes. Production and realized prices are discussed below in Results of Operations. See Notes 5 and 6 for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.

Investing activities.  For the six months endedJune 30, 2014, net cash used in investing activities was $125.0 million compared to $67.4 million for the same period in 2013. The $57.6 million increase in cash used in investing activities was primarily attributable to a $68.8 million increase in drilling and completion activities in the Permian Basin driven by the addition of a second horizontal drilling rig in August 2013 and acreage acquisitions.  Offsetting these increases was an  $11.0 million acquisition completed in the 2013 period.

Capital expenditures for the six months ended June 30, 2014 include the following (in millions):

Southern Midland Basin	$	84
Central Midland Basin		27
Total operational expenditures		111
Capitalized general and administrative costs allocated directly to exploration and development projects		6
Capitalized interest		1
Total capitalized expenses		7
Total operational expenditures inclusive of capitalized amounts		118
Acquisitions		9
Total capital expenditures	$	127

Financing activities.  For the six months ended June 30, 2014, net cash provided by financing activities was $87.5 million compared to cash provided by financing activities of $59.4 million during the same period of 2013. Net cash provided by financing activities during the six months ended June 30, 2014 included a net $139.9 million of borrowings on our Credit Facility and Second Lien Facility offset by a $50.1 million redemption of our Senior Notes. In addition the Company paid approximately $3.9 million in preferred stock dividends.

2014 capital expenditures

Our 2014 operational capital budget approximates $215 million, excluding acquisitions completed in 2014 (see Note 2)and capitalized expenses. This budgeted amount includes plans to drill up to 30 gross(25.3 net) horizontal and seven gross (4.7 net) vertical wells, while completing 31 gross (26.7 net) horizontal and five gross(3.3 net) vertical wells. Our initial operational capital budget was established at $185 million, and has been subsequently adjusted for the items below.

In the first half of 2014, we began testing larger horizontal well completion designs in an effort to improve production rates and the amount of recoverable resources. Based on satisfactory drilling, completion and well performance to date, we believe that our enhanced completion designs create the potential for increased total returns on capital after adjusting for incremental costs of approximately $0.5 million to $0.8 million per completion depending on the depth of the well. While we continue to monitor the effectiveness of our enhanced completion designs, we increased our 2014 operational budget to include the incremental change in costs for the completion designs by approximately $10 million for this initiative.

20

We also recently commenced drilling a horizontal well in partnership with a large public company at our recently acquired acreage in Upton County. This non-operated well, of which we own a 57% working interest, is estimated to cost approximately $5.5 million on a net basis.

As described in Subsequent Events, we signed an agreement for a drilling rig to be used in our horizontal development program. We currently forecast that this initiative will add approximately $9 million to our original operational capital budget.

The remaining difference, approximately $5.5 million, is primarily due to a higher number of scheduled completions resulting from modifications to our original drilling schedule. We currently intend to complete 26.7 net horizontal wells relative to 24.7 net wells in our previous forecast.

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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 June 30,
		2014		2013		Change	% Change
Net production:
Oil (MBbls)		405		198		207	105%
Natural gas (MMcf)		452		787		(335)	(43)%
Total production (MBOE)		480		329		151	46%
Average daily production (BOE/d)		5,280		3,615		1,665	46%
% oil (BOE basis)		84%		60%		—	—
Average realized sales price:
Oil (Bbl)	$	93.10	$	96.27	$	(3.17)	(3)%
Natural gas (Mcf) (includes NGLs)		6.17		4.70		1.47	31%
Total (BOE)	$	84.30	$	69.18	$	15.12	22%
Oil and natural gas revenues (in thousands):
Oil revenue	$	37,710	$	19,061	$	18,649	98%
Natural gas revenue		2,792		3,699		(907)	(25)%
Total	$	40,502	$	22,760	$	17,742	78%
Additional per BOE data:
Sales price	$	84.30	$	69.18	$	15.12	22%
Lease operating expense		9.08		15.98		(6.90)	(43)%
Production taxes		4.71		2.47		2.24	91%
Operating margin	$	70.50	$	50.73	$	19.77	39%

		Six Months Ended June 30,
		2014			2013		Change	% Change
Net production:
Oil (MBbls)		737			404		333	82%
Natural gas (MMcf)		816			1,525		(709)	(47)%
Total production (MBOE)		873			658		215	33%
Average daily production (BOE/d)		4,823	-	-	3,596		1,227	34%
% oil (BOE basis)		84%			61%		—	—
Average realized sales price:
Oil (Bbl)	$	93.11		$	95.55	$	(2.44)	(3)%
Natural gas (Mcf) (includes NGLs)		6.34			4.39		1.95	44%
Total (BOE)	$	84.53		$	68.85	$	15.68	23%
Oil and natural gas revenues (in thousands):
Oil revenue	$	68,619		$	38,601	$	30,018	78%
Natural gas revenue		5,168			6,700		(1,532)	(23)%
Total	$	73,787		$	45,301	$	28,486	63%
Additional per BOE data:
Sales price	$	84.53		$	68.85	$	15.68	23%
Lease operating expense		9.84			16.47		(6.63)	(40)%
Production taxes		4.79			2.32		2.47	107%
Operating margin	$	69.90		$	50.06	$	19.84	40%

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Revenues

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

(in thousands)	Oil		Natural Gas		Total
Revenues for the three months ended June 30, 2013	$	19,061	$	3,699	$	22,760
Volume increase (decrease)		19,890		(1,573)		18,317
Price increase (decrease)		(1,241)		666		(575)
Net increase (decrease) in 2014		18,649		(907)		17,742
Revenues for the three months ended June 30, 2014	$	37,710	$	2,792	$	40,502

(in thousands)	Oil		Natural Gas		Total
Revenues for the six months ended June 30, 2013	$	38,601	$	6,700	$	45,301
Volume increase (decrease)		31,857		(3,116)		28,741
Price increase (decrease)		(1,839)		1,584		(255)
Net increase (decrease) in 2013		30,018		(1,532)		28,486
Revenues for the six months ended June 30, 2014	$	68,619	$	5,168	$	73,787

Oil revenue

For the quarter ended June 30, 2014, oil revenues of $37.7 million increased$18.6 million, or 98%, compared to revenues of  $19.1 million for the same period of 2013. Contributing to the increase in oil revenue was a 105% increase in production partially offset by a 3% decrease in the average realized sales price. The increase in production was primarily attributable to a 274 MBbls increase in production from our Permian properties as a result of an increased number of producing wells from acquisitions and our horizontal drilling program. Partially offsetting this increase was a 64 MBbls decline in production due to the sale of our deepwater Medusa field in the fourth quarter of 2013 as well as normal and expected declines from our existing wells.

For the six months ended June 30, 2014, oil revenues of $68.6 million increased$30.0 million, or 78%, compared to revenues of $38.6 million for the same period of 2013. The increase primarily related to an 82% increase in total production, while the average realized sales price decreased 3%. The increase in production was wholly attributable to a 495 MBbls increase in Permian production resulting from an increased number of producing wells as mentioned above. Partially offsetting the Permian increase was a 156 MBbls decline in production due to the sale of the Medusa field as well as normal and expected declines from our existing wells.

Natural gas revenue (including NGLs)

Natural gas revenues of $2.8 million decreased$0.9 million, or 25%, during the three months endedJune 30, 2014 compared to $3.7 million for the same period of 2013. The decrease primarily relates to a 43% decrease in natural gas volumes partially offset by a 31% increase in the average price realized, which rose to $6.17 per Mcf from $4.70 per Mcf. The decrease in production was primarily attributable to a 552 MMcf decrease in production due to the sale of our offshore fields and Haynesville well in the fourth quarter of 2013. Offsetting these declines was a 218 MMcf increase in production from our Permian properties resulting from an increased number of producing wells as mentioned above.

Natural gas revenues of $5.2 million decreased$1.5 million, or 23%, during the six months ended June 30, 2014 compared to $6.7 million for the same period of 2013. The average realized price increased to $6.34 from $4.39, or 44%, while total production decreased 47%.  The decrease in production was primarily attributable toa 1,083 MMcf decrease in production due to the sale of our

23

offshore fields and Haynesville well in the fourth quarter of 2013. Offsetting the production decline was a 374 MMcf increase in production from our Permian properties resulting from an increased number of producing wells as mentioned above.

Operating Expenses

Principal components of our cost structure

Lease operating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.

Production taxes. Production taxes include severance and ad valorem taxes. 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. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.

Depreciation, depletion and amortization. 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 unproved properties and major development projects for which proved reserves cannot yet be assigned, 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.

General and administrative. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services and legal compliance.

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 asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations.

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(in thousands, except per unit amounts)	Three Months Ended June 30,
			Per				Per		Total Change		BOE Change
	2014		BOE		2013		BOE		$	%	$	%
Lease operating expenses	$	4,363	$	9.08	$	5,259	$	15.98	(896)	(17)%	(6.91)	(43)%
Production taxes		2,265		4.71		812		2.47	1,453	179%	2.24	91%
Depreciation, depletion and amortization		11,982		24.96		10,654		32.38	1,328	12%	(7.42)	(23)%
General and administrative		9,639		20.08		4,545		13.81	5,094	112%	6.26	45%
Accretion expense		173		0.36		533		1.62	(360)	(68)%	(1.26)	(78)%

	Six Months Ended June 30,
			Per				Per		Total Change		Boe Change
	2014		BOE		2013		BOE		$	%	$	%
Lease operating expenses	$	8,593	$	9.84	$	10,836	$	16.47	(2,243)	(21)%	(6.63)	(40)%
Production taxes		4,182		4.79		1,532		2.33	2,650	173%	2.46	106%
Depreciation, depletion and amortization		22,520		25.79		21,696		32.97	824	4%	(7.19)	(22)%
General and administrative		20,446		23.41		8,284		12.59	12,162	147%	10.82	86%
Accretion expense		401		0.46		1,098		1.67	(697)	(63)%	(1.21)	(72)%
Gain on sale of other property and equipment		(1,080)		nm		—		nm	(1,080)	—	nm	nm

*nm = not meaningful

Lease operating expenses (“LOE”)

LOE for the three months endedJune 30, 2014 decreased by 17% to $4.4 million compared to $5.3 million for the same period of 2013primarily due to decreases of $2.5 million resulting from the previously discussed sale of our deepwater Medusa field and our other offshore fields. These decreases were partially offset by $1.5 million in costs related to the growth in Permian production and operations, including an increase in workover expenses associated with accelerated horizontal well activity.

LOE for the six months ended June 30, 2014 decreased by 21% to $8.6 million compared to $10.8 million for the same period of 2013. The decrease is primarily related to a $4.8 million decline in LOE resulting from the sale of our deepwater Medusa field and our other offshore fields, slightly offset by $2.5 million in costs related to the growth in Permian production and operations, including an increase in workover expenses associated with accelerated horizontal well activity.

Production taxes

For the three months endedJune 30, 2014, production taxes increased 179%, or $1.5 million, to $2.3 million compared to $0.8 million for the same period of 2013.  Similarly, for the six months ended June 30, 2014compared to the same period of 2013, production taxes increased 173%, or $2.7 million, to $4.2 million. The increases were predominantly attributable to an increase in onshore production subject to these taxes accompanied by a decline in offshore production, resulting from the sale of our Gulf of Mexico position in 2013, which was exempt from production taxes.

Depreciation, depletion and amortization (“DD&A”)

For the three months ended June 30, 2014,  DD&A decreased 23% per BOE to $ 24.96 per BOE compared to $32.38 per BOE for the same period of 2013. Similarly, for the six months ended June 30, 2014,  DD&A decreased 22% per BOE to $25.79 per BOE compared to $32.97 per BOE for the same period of 2013. These decreases are attributable to our increasing estimated proved reserves relative to our depreciable asset base (the full cost pool), as a result of our efforts on acquisition, development, exploration, and exploitation of onshore oil and natural gas reserves in the Permian Basin.

General and administrative, net of amounts capitalized (“G&A”)

G&A for the three months endedJune 30, 2014  increased to $9.6 million compared to $4.5 million for the same period of 2013. Total G&A for the second quarter of 2014 included $4.7 million of expense related to the following items:

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· $0.1 million in non-recurring, cash expense related to a threatened proxy contest

· $4.6 million in non-cash expense related to the fair value adjustment of performance-based phantom stock incentive awards

G&A for the six months ended June 30, 2014 increased to $20.4 million compared to $8.3 million for the same period of 2013. Total G&A for the period included $11.0 million of expense related to the following items:

· $1.3 million in non-recurring, cash expense related to a threatened proxy contest

· $2.5 million in non-recurring expenses (both non-cash and cash components) primarily related to the accelerated vesting of outstanding equity awards for early retirement of employees

· $7.2 million in non-cash expense related to the fair value adjustment of performance-based phantom stock incentive awards

Accretion expense

Accretion expense related to our ARO decreased 68% and 63%, respectively, for the three and six months ended June 30, 2014compared to the same periods of 2013. Accretion expense correlates with the Company’s ARO which was $5.6 million at June 30, 2014 versus $13.4  million at June 30, 2013. The reduction in ARO was primarily a result of the divestiture of our offshore fields in the fourth quarter of 2013. See Note 8 for additional information regarding the Company’s ARO.

Gain on sale of other property and equipment

See Note 10 for a discussion of the gain on the sale of equipment.

Other Income and Expenses

(in thousands)	Three Months Ended June 30,
	2014		2013			$ Change	% Change
Interest expense	$	1,825	$	1,537	$	288	19%
Gain on early extinguishment of debt		(3,205)		—		(3,205)	100%
Loss (gain) on derivative contracts		4,685		(1,981)		6,666	(336)%
Other income, net		(93)		(44)		(49)	111%
Income tax expense		4,128		663		3,465	523%
Equity in earnings of Medusa Spar LLC		—		(24)		24	(100)%
Preferred stock dividends		(1,973)		(680)		(1,293)	100%

	Six Months Ended June 30,
	2014		2013		$ Change	% Change
Interest expense	$	2,802	$	3,052	(250)	(8)%
Gain on early extinguishment of debt		(3,205)		—	(3,205)	100%
Loss (gain) on derivative contracts		7,198		(1,563)	8,761	(561)%
Other income, net		(142)		(89)	(53)	60%
Income tax expense		5,469		494	4,975	1,007%
Equity in earnings of Medusa Spar LLC		—		(3)	3	(100)%
Preferred stock dividends		(3,947)		(680)	(3,267)	100%

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Interest expense

Interest expense incurred during the three months endedJune 30, 2014 increased $0.3 million compared to the same period of 2013. The increase is primarily attributable to $1.1 million in expense related to additional draws on our Credit Facility and Second Lien Facility in 2014 compared to the corresponding period of the prior year, and a $0.6 million decrease in capitalized interest compared to the 2013 period, resulting from a lower average unevaluated property balance period over period. Offsetting the increase is  a  $1.4 million decrease in interest expense related to our Senior Notes following a $48.5 million partial redemption during the fourth quarter of 2013 and a full redemption of the remaining outstanding principal in April 2014.

Interest expense incurred during thesix months endedJune 30, 2014  decreased $0.3 million compared to the same period of 2013. The decrease is primarily related to  a  $2.3 million decrease in interest expense related to the $48.5 million partial redemption of the Senior Notes in the fourth quarter of 2013 and the full redemption of the remaining outstanding principal in April 2014. Offsetting the decrease is a $1.1 million decrease in capitalized interest compared to the 2013 six-month period, resulting from a lower average unevaluated property balance period over period, and an additional $0.9 million in interest expense related to additional draws on our Credit Facility and Second Lien Facility in 2014 compared to the corresponding period of the prior year.

Loss (gain) on derivative contracts

See Notes 5 and 6 for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.

Income tax expense

See Note 7 for a discussion of our effective tax rates for the periods presented above.

Preferred stock dividends

Preferred Stock dividends for thethree and six months ended June 30, 2014increased $1.3 million and $3.3 million, respectively, compared to the same periods of 2013.  We issued the Preferred Stock on May 30, 2013. Accordingly, the 2014 periods reflect dividends for the entire period compared to approximately one month of dividends in the 2013 periods. Dividendsreflect a 10% dividend rate and $79 million liquidation value. See Note 9 for additional information.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We 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. The total volumes which we hedge through the use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 50% to 75% of our anticipated internally forecast production for the next 12 to 24 months. 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.

As of August 1, 2014, we had commodity contracts covering approximately 57% and 29%of our expected oil and natural gas production for the remaining six months of 2014, respectively, based on the midpoint of publicly disclosed guidance as of August 6, 2014 and including the impact of derivative contracts established after June 30, 2014. Our actual production will vary from the amounts estimated, perhaps materially. See Note 5 to the Consolidated Financial Statements for a description of the Company’s outstanding derivative contracts at June 30, 2014  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. Additionally, the Company may sell put options or call options in conjunction with a swap and use the proceeds to increase the fixed price received.

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 options at a price lower than the floor price in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices.

The Company may purchase put 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

On June 30, 2014,  the Company’s debt consisted of $82.5 million related to its Second Lien Facility and$84.0 million related to its Credit Facility.  The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under the Credit Facility and Second Lien Facility. As of June 30, 2014, the weighted average interest rate on our Credit Facility borrowings was  2.43% and the interest rate on our Second Lien Facility borrowings was 8.75%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $1.7 million based on the $166.5 million outstanding in the aggregate under the two facilities on June 30, 2014.See Note 4 to the Consolidated Financial Statements for more information on the Company’s interest rates on debt.

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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 andreceivables resulting from derivative financial contracts.  

The Company markets receivables from the sale of our 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 receivableswith 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 affect our financial results. At June 30, 2014 our receivables from the sale of our oil and natural gas production were approximately $19.1 million in total.

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 June 30, 2014 our joint interest receivables were approximately $3.7 million.

The Company’s oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. 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 an 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 set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off 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 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 June 30, 2014.

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 2013 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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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 January 17, 2014 (filed herewith)
3.2	Certificate of Designation of Rights and Preferences of 10.0% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5 of the Company’s Form 8-A filed on May 23, 2013)
3.3	Bylaws of the Company (incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form S-4 filed 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 August 4, 1994, Reg. No. 33-82408)
4.2	Form of Certificate representing the 10.0% Series A Cumulative Preferred Stock (incorporated herein by reference to Exhibit 4.1 of the Company’s Form 8-A filed on May 23, 2013)

31.           Section 13a-14 Certifications

31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.           Section 1350 Certifications

32.1  Section 1350 Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.*        Interactive Data Files

* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 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	President and Chief Executive Officer	August 6, 2014
Fred L. Callon
/s/ Joseph C. Gatto, Jr.	Senior Vice President,	August 6, 2014
Joseph C. Gatto, Jr.	Chief Financial Officer and Treasurer

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EX-3.1

EXHIBIT 3.1

STATE OF DELAWARE

SECRETARY OF STATE

DIVISION OF CORPORATIONS

FILED 10:00 AM 03/29/1994

344051804 - 2390003

CERTIFICATE OF INCORPORATION

OF

CALLON PETROLEUM HOLDING COMPANY

ARTICLE ONE

The name of the Corporation is Callon Petroleum Holding Company.

ARTICLE TWO

The address of the Corporation's registered office in the State ofDelaware is 1209 Orange Street, Wilmington, New Castle County, Delaware, 19801,and the name of its registered agent at such address is The Corporation Trust

Company.

ARTICLE THREE

The nature of the business or purposes to be conducted or promoted isto engage in any lawful act or activity for which corporations may be organizedunder the General Corporation Law of Delaware ("Act"),

ARTICLE FOUR

The Corporation shall have authority to issue two classes of stock, andthe total number authorized shall be one (1) share of Common Stock of the parvalue of one cent ($.01) each, and one (1) share of Preferred Stock of the par

value of one cent ($.01) each. A description of the different classes of stockof the Corporation and a statement of the designations and the powers,preferences and rights, and the qualifications, limitations or restrictionsthereof, in respect of each class of such stock are as follows:

1. ISSUANCE IN CLASS OR SERIES. The Common Stock or Preferred Stock may be issued from time to time in one or more series, or either or both of the Common and Preferred Stock may be divided into additional classes and such classes into one or more series. The terms of a class or series, including all rights and preferences, shall be as specified in the resolution or resolutions adopted by the Board of Directors designating such class or series which resolution or resolutions the Board of Directors is hereby expressly authorized to adopt. Such resolution or resolutions with respect to a class or series shall specify all or such of the rights or preferences of such class or series as the Board of Directors shall determine, including, without limitation, any or all of the following, if applicable: (a) the number of shares to constitute such class or series and the distinctive designation thereof; (b) the dividend or manner for determining the dividend payable with respect to the shares of such class or series and the date or dates from which dividends shall accrue, whether such dividends shall be cumulative, and, if cumulative, the date or dates from which dividends shall accumulate and whether the shares in such class or series shall be entitled to preference or priority over any other class or series of stock of the Corporation with respect to payment of  dividends; (c) the terms and conditions, including price or a manner for determining the price, of redemption, if any, of the shares of such class or series; (d) the terms and conditions of a retirement or sinking fund, if any, for the purchase or redemption of the shares of such class or series; (e) the amount which the shares of such class or series shall be entitled to receive, if any, in the event of any liquidation, dissolution or winding up of the Corporation and whether such shares shall be entitled to a preference or priority over shares of another class or series with respect to amounts received in connection with any liquidation, dissolution or winding up of the Corporation; (f) whether the shares of such class or series shall be convertible into, or exchangeable for, shares of stock of any other class or classes, or any other series of the same or any other class or classes of stock, of the Corporation and the terms and conditions of any such conversion or exchange; (g) the voting rights, if any, of shares of stock of such class or series in addition to those granted herein, if any; (h) the status as to reissuance or sale of shares of such class or series redeemed, purchased or otherwise reacquired or surrendered to the Corporation on conversion; (i) the conditions and restrictions, if any, on the payment of dividends or on the making of other distributions on, or the purchase,  redemption or other acquisition by the Corporation or any subsidiary, of any other class or series of stock of the Corporation ranking junior to such shares as to dividends or upon liquidation; (j) the conditions, if any, on the creation of 1  

indebtedness of the Corporation, or any subsidiary, and (k) such other preferences, rights, restrictions and qualificationsas the Board of Directors may determine.

All shares of the Common Stock shall rank equally and allshares of the Preferred Stock shall rank equally, and be identicalwithin their classes in all respects regardless of series, except as toterms which may be specified by the Board of Directors pursuant to theabove provisions. All shares of any one series of a class of CommonStock or Preferred Stock shall be of equal rank and identical in allrespects, except that shares of any one series issued at differenttimes may differ as to the dates which dividends thereon shall accrueand be cumulative.

2. OTHER PROVISIONS. Shares of Common Stock or PreferredStock of any class or series may be issued with such voting powers,full or limited, or no voting powers, and such designations,preferences and relative participating, option or special rights, andqualifications, limitations or restrictions thereof, as shall be statedand expressed in the resolution or resolutions providing for theissuance of such stock adopted by the Board of Directors. Any of thevoting powers, designations, preferences, rights and qualifications,limitations or restrictions of any such class or series of stock may bemade dependent upon facts ascertainable outside the resolution orresolutions of the Board of Directors providing for the issue of suchstock by the Board of Directors, provided the manner in which suchfacts shall operate upon the voting powers, designations, preferences,rights and qualifications, limitations or restrictions of such class orseries is clearly set forth in the resolution or resolutions providingfor the issue of such stock adopted by the Board of Directors.

3. COMMON STOCK. Except as otherwise provided in anyresolution or resolutions adopted by the Board of Directors providingfor the issuance of a class or series of Preferred Stock or CommonStock, the Common Stock shall (a) have the exclusive voting power ofthe corporation; (b) entitle the holders thereof to one vote per shareat all meetings of the stockholders of the Corporation; (c) entitle theholders to share ratably, without preference over any other shares ofthe Corporation, in all assets of the Corporation in the event of anydissolution, liquidation or winding up of the Corporation; and (d)entitle the record holders thereof on such record dates as aredetermined, from time to time, by the Board of Directors to receivesuch dividends, if any, if, as and when declared by the Board ofDirectors.

ARTICLE FIVE

The Corporation is to have perpetual existence.

ARTICLE SIX

1. NUMBER, ELECTION AND TERM OF DIRECTORS. The businessand affairs of the Corporation shall be managed by a Board ofDirectors, which, subject to the rights of holders of shares of anyclass of series of Preferred Stock of the Corporation then outstandingto elect additional directors under specified circumstances, shallconsist of not less than three nor more than twenty-one persons. Theexact number of directors within the minimum and  maximum limitationsspecified in the preceding sentence shall be fixed from time to time byeither (i) the Board of Directors pursuant to a resolution adopted by amajority of the entire Board of Directors or (ii) the affirmative voteof the holders of 80% or more of the voting power of all of the sharesof the Corporation entitled to vote generally in the election ofdirectors voting together as a single class. No decrease in the numberof directors constituting the Board of Directors shall shorten the termof any incumbent director. The directors shall be divided into threeclasses as nearly equal in number as possible, with the term of officeof the first class to expire at the 1995 annual meeting ofstockholders, the term of office of the second class to expire at the1996 annual meeting of stockholders, and the term of office of thethird class to expire at the 1997 annual meeting of stockholders, andwith the members of each class to hold office until their successorsshall have been elected and qualified At each annual meeting ofstockholders following such initial classification and election,directors elected to succeed those directors whose terms expire shallbe elected for a term of office to expire at the third succeedingannual meeting of stockholders after their election.

2. STOCKHOLDER NOMINATION OF DIRECTOR CANDIDATES.Advance notice of stockholder nominations for the election of directorsshall be submitted to the Board of Directors at least 120 days inadvance of the scheduled date for the next annual meeting ofstockholders.

3. NEWLY CREATED DIRECTORSHIPS AND VACANCIES. Subject tothe rights of the holders of any series of any Preferred Stock thenoutstanding, newly created directorships resulting from any increase inthe authorized number of directors and any vacancies in the Board ofDirectors resulting from the death, resignation, retirement,disqualification, removal from office or other cause may be filled by amajority vote of the directors then in office even though less than aquorum, or by a sole remaining director.

2

4. REMOVAL. Subject to the rights of the holders of anyseries of any Preferred Stock then outstanding, any director or theentire Board of Directors, may be removed from office at any annual orspecial meeting called for such purpose, and then only for cause andonly by the affirmative vote of the holders of 80% or more of thevoting power of all of the shares of the Corporation entitled to votegenerally in the election of directors, voting together as a singleclass. As used herein, cause shall mean only the following: convictionof a felony or proof, beyond the existence of a reasonable doubt, thata director has committed grossly negligent or wilful misconductresulting in a material detriment to the Corporation or committed amaterial breach of his fiduciary duty to the Corporation resulting in amaterial detriment to the Corporation.

5. AMENDMENT, REPEAT, ETC. Notwithstanding anythingcontained in this Certificate of Incorporation to the contrary, theaffirmative vote of the holders of 80% or more of the voting power ofall of the shares of the Corporation entitled to vote generally in theelection of directors, voting together as a single class, shall berequired to alter, amend or adopt any provision inconsistent with orrepeal this Article Six, or to alter, amend, adopt any provisioninconsistent with or repeal comparable sections of the Bylaws of theCorporation.

ARTICLE SEVEN

Subject to the rights of the holders of any series of Preferred Sharesthen outstanding, Any action required or permitted to be taken by thestockholders of the Corporation must be effected at a duly called annual orspecial meeting of stockholders of the Corporation and may not be effected byany consent in writing by such stockholders unless all of the stockholdersentitled to vote thereon consent thereto in writing. Notwithstanding anythingcontained in this Certificate of Incorporation to the contrary, the affirmativevote of the holders of 80% or more of the voting power of all the shares of theCorporation entitled to vote generally in the election of directors, votingtogether as a single class, shall be required to call a special meeting ofstockholders or to alter, amend or adopt any provision inconsistent with orrepeal this Article Seven, or to alter, amend or adopt any provisioninconsistent with comparable sections of the Bylaws.

ARTICLE EIGHT

The Corporation shall have the power to indemnify its present or formerdirectors, officers, employees and agents or any person who served or is servingat the request of the Corporation as a director, officer, employee or agent ofanother corporation, partnership, joint venture, trust or other enterprise tothe fun extent permitted by the General Corporation Law of Delaware. Suchindemnification shall not be deemed exclusive of any other rights to which suchperson may be entitled, under any Bylaws, agreements, vote of stockholders ordisinterested directors, or otherwise.

ARTICLE NINE

A director of the Corporation shall not be personally liable to theCorporation or its stockholders for monetary damages or breach of fiduciary dutyas a director, except for liability (i) for any breach of the director's duty ofloyalty to the Corporation or its stockholders, (if) for acts or omissions notin good faith or which involved intentional misconduct or a knowing violation oflaw, (iii) under Section 174 of the Act, or, (iv) for any transaction from whichthe director derived an improper personal benefit.

ARTICLE TEN

In furtherance and not in limitation of the powers conferred bystatute, the board of directors is expressly authorized to make, alter or repealthe Bylaws of the corporation.

ARTICLE ELEVEN

The name and address of the incorporator is as follows:

George G. Young III

Butler & Binion

1700 First Interstate Bank Plaza

Houston, Texas 77002

3

In Witness Whereof, this certificate of incorporation was executed bythe above named individual on this 28th day of March, 1994.

/s/ George G. Young III

George G. Young III

4

STATE OF DELAWARE

SECRETARY OF STATE

DIVISION OF CORPORATIONS

FILED 04:30 PM 08/04/1994

944145890 - 2390003

CERTIFICATE OF AMENDMENT

OF

CERTIFICATE OF INCORPORATION

Callon Petroleum Holding Company, a corporation organized andexisting under and by virtue of the General Corporation Law of the State ofDelaware (the "Corporation"),

DOES HEREBY CERTIFY:

FIRST: That the Board of Directors of the Corporation, by theunanimous written consent of its members, filed with the minutes of the Board,adopted a resolution proposing and declaring advisable the following amendmentto the Certificate of Incorporation of the Corporation:

RESOLVED, that the Certificate of Incorporation of theCorporation be amended by chanting Section 1. of the Article thereofnumbered "SIX" so that, as amended, Section 1. of said Article shall beand read as follow:

"ARTICLE SIX

1. NUMBER, ELECTION AND TERM OF DIRECTORS. The businessand affairs of the Corporation shall be managed by a Board ofDirectors, which, subject to the rights of holders of shares of anyclass or series of Preferred Stock of the Corporation then outstandingto elect additional directors under specified circumstances, shallconsist of no more than twenty-one person. The number of initialdirectors shall be two. Thereafter, the exact number of directorwithin the maximum limitations as specified above shall be fixed fromtime to time by either (i) the Board of Directors pursuant to aresolution adopted by a majority of the entire Board of Directors or (ii) the affirmative vote of the holders of 80% or more of the votingpower of all of the shares of the Corporation entitled to votegenerally in the election of directors voting together as a singleclass. No decrease in the number of directors constituting the Board ofDirectors shall shorten the term of any incumbent director. Thedirectors shall be divided into three classes as nearly equal in numberas possible, with the term of office of the first class to expire atthe first annual meeting of stockholders following their election, theterm of office of the second class to expire at the second annualmeeting of stockholders following their election, and the term ofoffice of the third class to expire at the third annual meeting ofstockholders following their election, and with the members of eachclass to hold office until their successors shall have been elected andqualified. At each annual meeting of stockholders following suchinitial classification and election, directors elected to succeed thosedirectors whose terms expire shall be elected for a term of office toexpire at the third succeeding annual meeting of stockholders aftertheir election. Notwithstanding the foregoing, the above provisionsregarding classification of directors shall be applicable only in theevent that the Board of Directors is composed of three or moredirectors. Election of directors need not be by written ballot, exceptas otherwise provided in the Bylaws."

SECOND: That in lieu of a meeting and vote of stockholders,the sole stockholder of the Corporation has given its written consent to theamendment in accordance with the provisions of Section 228 of the GeneralCorporation Law of the State of Delaware.

THIRD: That the amendment was duly adopted in accordance withthe applicable provisions in Sections 242 and 228 of the General Corporation Lawof the State of Delaware.

5

IN WITNESS WHEREOF, the Corporation has caused thisCertificate to be signed by Fred L. Callon, its President, and attested by H.Michael Tatum, Jr., its Secretary, this 2nd day of August, 1994.

CALLON PETROLEUM HOLDING COMPANY

By /s/ Fred L. Callon

Fred L. Callon, President

ATTEST

/s/ H. Michael Tatum Jr.

H. Michael Tatum Jr., Secretary

6

STATE OF DELAWARE

SECRETARY OF STATE

DIVISION OF CORPORATIONS

FILED 04:30 PM 09/16/1994

944174625 - 2390003

CERTIFICATE OF MERGER

OF

CALLON CONSOLIDATED PARTNERS, L.P.

(a Delaware limited partnership)

with and into

CALLON PETROLEUM HOLDING COMPANY

(a Delaware corporation)

Callon Consolidated Partners, L.P., a Delaware limited partnership, forthe purpose of merging with Callon Petroleum Holding Company, a Delawarecorporation, hereby certifies as follows:

1. The name and jurisdiction of formation or organization of each of the constituent entities are:

Name                               Jurisdiction

Callon Petroleum Holding CompanyDelaware

                 Callon Consolidated Partners, L.P.            Delaware

2. An agreement and plan of consolidation has been approved, adopted, certified, executed and acknowledged by each of the constituent entities in accordance with section 263 of the Delaware General Corporation Law.

3. The name of the surviving corporation is Callon Petroleum Holding Company, which shall herewith be changed to Callon Petroleum Company.

4. The amendments or changes in the Certificate of Incorporation of the surviving corporation are as follows:

(i) Article One is amended and replaced in its entirety with the following Article One:

"ARTICLE ONE

The name of the Corporation is Callon PetroleumCompany."

(ii) The first sentence of Article Four is amended and replaced in its entirety with the following sentence:

"The Corporation shall have authority to issue twoclasses of stock, and the total number authorizedshall be 20,000,000 shares of Common Stock of the parvalue of one cent ($.01) each, and 2,500,000 sharesof Preferred Stock of the par value of one cent ($.01) each."

5. The executed agreement and plan of consolidation is on file at the principal place of business of the surviving corporation, the address of which is:

                                     Callon Petroleum Holding Company

                                     200 North Canal Street

                                     Natchez, Mississippi 39120

6. A copy of the agreement and plan of consolidation will be furnished by Callon Petroleum Holding Company, on request and without cost, to any partner or stockholder of a constituent entity.

7

IN WITNESS WHEREOF, this Certificate of Merger has been dulyexecuted as of the 16th day of September 1994, and is being filed by CallonPetroleum Holding Company, the surviving corporation.

CALLON PETROLEUM HOLDING COMPANY

By: /s/ FRED L. CALLON

FRED L. CALLON, President

Attest:

/s/ H. Michael Tatum, Jr.

H. Michael Tatum, Jr., Secretary

8

AMENDMENT

TO

CERTIFICATE OF INCORPORATION

OF

CALLON PETROLEUM COMPANY

The undersigned, Robert A. Mayfield, Corporate Secretary of CallonPetroleum Company, a corporation organized and existing under the laws of theState of Delaware (the "CORPORATION"), does hereby certify as follows:

FIRST:   The name of the Corporation is Callon Petroleum Company

SECOND:  This Amendment (the "AMENDMENT") to the Certificate ofIncorporation of the Corporation (the "CERTIFICATE") was duly adopted inaccordance with the provisions of Section 242 of the Delaware General

Corporation Law. The Board of Directors has duly adopted resolutions settingforth and declaring advisable this Amendment and the holders of a majority ofthe outstanding stock of the Corporation entitled to vote at the special meetingof the stockholders called for the purpose of voting on the Amendment have votedin favor of this Amendment.

THIRD:   The Certificate is hereby amended by amending and restatingthe first sentence of Article Four to be and read as follows:

"The Corporation shall have authority to issue two classes of stock,and the total number authorized shall be 30,000,000 shares of CommonStock, par value $.01 per share, and 2,500,000 shares of PreferredStock, par value $.01 per share."

9

IN WITNESS WHEREOF, the undersigned has executed this Amendment onbehalf of the Corporation and has attested such execution and does verify andaffirm, under penalty of perjury, that this Amendment is the act and deed ofthe Corporation and that the facts stated herein are true as of this 23rd day ofJanuary, 2004.

CALLON PETROLEUM COMPANY

By: /s/ Robert A. Mayfield

Robert A. Mayfield, Corporate Secretary

10

CERTIFICATE OF AMENDMENT

OF

CERTIFICATE OF INCORPORATION

OF

CALLON PETROLEUM COMPANY

The undersigned, Robert A. Mayfield, Corporate Secretary of Callon Petroleum Company, a corporation organized and existing under and by virtue of the General Corporation Law of the State of Delaware (the “Corporation”), does hereby certify as follows:

FIRST:The name of the Corporation is Callon Petroleum Company.

SECOND:This Amendment (the “Amendment”) to the Certificate of Incorporation of the Corporation (the “Certificate”) was duly adopted in accordance with the provisions of Section 242 of the Delaware General Corporation Law.  The Board of Directors has duly adopted resolutions setting forth and declaring advisable this Amendment and the holders of a majority of the outstanding stock of the Corporation entitled to vote at the special meeting of the stockholders called and held upon notice in accordance with Section 222 of the General Corporation Law of the State of Delaware for the purpose of voting on the Amendment have voted in favor of this Amendment.

THIRD:The Certificate is hereby amended by amending and restating the first sentence of Article Four to be and read as follows:

“The Corporation shall have authority to issue two classes of stock, and the total number authorized shall be 60,000,000 shares of Common Stock, par value $.01 per share, and 2,500,000 shares of Preferred Stock, par value $.01 per share.”

IN WITNESS WHEREOF, the undersigned has executed this Amendment on behalf of the Corporation and has attested such execution and does verify and affirm, under penalty of perjury, that this Amendment is the act and deed of the Corporation and that the facts stated herein are true as of this 31st day of December, 2009.

Callon Petroleum Company

By:  /s/ Robert A. Mayfield

Robert A. Mayfield, Corporate Secretary

11

CERTIFICATE OF AMENDMENT

OF

CERTIFICATE OF INCORPORATION

OF

CALLON PETROLEUM COMPANY

The undersigned, B.F. Weatherly, Corporate Secretary of Callon Petroleum Company, a corporation organized and existing under and by virtue of the General Corporation Law of the State of Delaware (the “Corporation”), does hereby certify as follows:

FIRST:The name of the Corporation is Callon Petroleum Company.

SECOND:This Amendment (the “Amendment”) to the Certificate of Incorporation of the Corporation (the “Certificate”) was duly adopted in accordance with the provisions of Section 242 of the Delaware General Corporation Law.  The Board of Directors has duly adopted resolutions setting forth and declaring advisable this Amendment and the holders of a majority of the outstanding stock of the Corporation entitled to vote at the special meeting of the stockholders called and held upon notice in accordance with Section 222 of the General Corporation Law of the State of Delaware for the purpose of voting on the Amendment have voted in favor of this Amendment.

THIRD:The Certificate is hereby amended by amending and restating the first sentence of Article Four to be and read as follows:

“The Corporation shall have authority to issue two classes of stock, and the total number authorized shall be 110,000,000 shares of Common Stock, par value $.01 per share, and 2,500,000 shares of Preferred Stock, par value $.01 per share.”

IN WITNESS WHEREOF, the undersigned has executed this Amendment on behalf of the Corporation and has attested such execution and does verify and affirm, under penalty of perjury, that this Amendment is the act and deed of the Corporation and that the facts stated herein are true as of this 15th day of January, 2014.

Callon Petroleum Company

By: /s/ B.F. Weatherly

B.F. Weatherly, Corporate Secretary

12

EX-31.1

EXHIBIT 31.1

Certification of Chief Executive Officer

Pursuant to Rule 13a - 14(a)/15d - 14(a) of the

Securities Exchange Act of 1934

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:		August 6, 2014			/s/ Fred L. Callon
					Fred L. Callon, President and Chief Executive Officer
					(Principal executive officer)

EX-31.2

EXHIBIT 31.2

Certification of Chief Financial Officer

Pursuant to Rule 13a - 14(a)/15d - 14(a) of the

Securities Exchange Act of 1934

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:		August 6, 2014			/s/ Joseph C. Gatto, Jr.
					Joseph C. Gatto, Jr., Chief Financial Officer, Senior Vice President and Treasurer
					(Principal Financial Officer)

EX-32

EXHIBIT 32

Certification of Periodic Financial Report Pursuant to 18 U.S.C. Section 1350

Pursuant to 18 U.S.C. Section 1350 and in connection with the Quarterly Report on Form 10-Q of Callon Petroleum Company for the quarterly period ended June 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned Fred L. Callon, the President and Chief Executive Officer, and Joseph C. Gatto, Jr., the Chief Financial Officer, Senior Vice President and Treasurer, hereby certify that this Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the registrant.
Date:	August 6, 2014	/s/ Fred L. Callon
		Fred L. Callon (Principal Executive Officer, Director)
Date:	August 6, 2014	/s/ Joseph C. Gatto, Jr.
		Joseph C. Gatto, Jr. (Principal Financial Officer)

XML

Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of the period	$ 6,732
Accretion expense	401
Liabilities incurred	404
Liabilities settled	(1,747)
Revisions to estimate	(192)
Asset retirement obligations at end of period	5,598
Less: current asset retirement obligations	2,846	4,120
Long-term asset retirement obligations at the end of the period	2,752	2,612
Restricted Investments
Restricted investments	$ 3,806	$ 3,806

XML

Borrowings (Second Lien Term Loan Facility) (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended		0 Months Ended			6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Apr. 10, 2014 Second Lien Term Loan Facility [Member]	Apr. 11, 2014 Second Lien Term Loan Facility [Member]	Jun. 30, 2014 Second Lien Term Loan Facility [Member]	Jun. 30, 2014 Second Lien Term Loan Facility [Member] Prior to First Anniversary [Member]	Jun. 30, 2014 Second Lien Term Loan Facility [Member] After First Anniversary but Prior to Second Anniversary [Member]	Jun. 30, 2014 Second Lien Term Loan Facility [Member] After Second Anniversary [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity					$ 125,000
Line of Credit Facility, Initial Commitment					100,000
Line of credit facility, additional availability					25,000
Line of Credit Facility, Prepayment Premium Percentage						102.00%	101.00%	100.00%
Initial amount drawn	150,000	31,000	62,500
Line of Credit Facility, Discount Percentage			1.00%
Interest rate at period end (as a percent)				8.75%
Floor rate				1.00%
Basis Spread on LIBOR (as a percent)				7.75%
Unused capacity, commitment fee (as a percent)			0.50%
Credit Facility					$ 82,500

XML

Borrowings

6 Months Ended

Jun. 30, 2014

Debt Disclosure [Abstract]

Borrowings

Note 4 – Borrowings

The Company’s borrowings consisted of the following at:

	June 30, 2014		December 31, 2013
Principal components:
Senior secured revolving credit facility	$	84,000	$	22,000
Second lien term loan facility		82,500		—
13% Senior Notes, principal		—		48,481
Total principal outstanding		166,500		70,481
13% Senior Notes unamortized deferred credit		—		5,267
Total carrying value of borrowings	$	166,500	$	75,748

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 participating lenders include Regions Bank, Citibank, N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, IberiaBank, N.A., OneWest Bank, N.A., SunTrust Bank and Royal Bank of Canada.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.In June 2014, the Credit Facility’s borrowing base was increased to $155,000 following a redetermination based upon a May 1, 2014 internally estimated reserve report. Subsequent redeterminations are scheduled to occur at six month intervals beginning on September 1, 2014. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties.

As of June 30, 2014, the balance outstanding on the Credit Facility was $84,000 with a weighted-average interest rate of 2.43%, calculated as the LIBOR plus a tiered rate ranging from 1.75% to 2.75%, 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.

Second lien term loan facility (the “Second Lien Facility”)

In connection with the Credit Facility, the Company also entered into the Second Lien Facility in an aggregate amount of up to $125,000, including initial commitments of $100,000 and additional availability of $25,000 subject to the consent of two-thirds of the lenders and compliance with financial covenants after giving effect to such increase. The Second Lien Facility matures on September 11, 2019, and is not subject to mandatory prepayments unless new debt or preferred stock is issued. The Second Lien Facility may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount is (i) 102% if the prepayment event occurs prior to March 11, 2015, and (ii) 101% if the prepayment event occurs on or after March 15, 2015 but before March 15, 2016, and (iii) 100% for prepayments made on or after March 15, 2016. The Second Lien Facility is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement.

On April 10, 2014, the Company drew an initial amount of $62,500 with an original issue discount of 1.0%. Subsequent draws, allowable during the first year, are subject to the same 1.0% original issue discount on the drawn amount, applied on the date such draw is funded. In addition, the Second Lien Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the initial commitment amount until March 11, 2015. As of June 30, 2014, the balance outstanding on the Second Lien Facility was $82,500 with an interest rate of8.75%, calculated at a rate of LIBOR (subject to a floor rate of 1.0%) plus7.75% per annum.

13% senior notes due 2016 (“Senior Notes”) and deferred credit

On April 11, 2014, the Company completed a full redemption of the remaining $48,481 principal amount of outstanding Senior Notes using proceeds from the Second Lien Facility. The redemption resulted in a net $3,205 gain on the early extinguishment of debt (including $4,780 of accelerated deferred credit amortization). The gain represents the difference between the $50,057 paid for the redemption of the Senior Notes ($1,576 of redemption costs, primarily the call premium) and the carrying value of the remaining Senior Notes of $53,261 (inclusive of $4,780 of deferred credit). The Company also paid $193in accrued interest through the redemption date. Upon the redemption, the indenture governing the Senior Notes was discharged in accordance with its terms.

Restrictive covenants

The Company’s Credit Facility and Second Lien Facility contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at June 30, 2014

XML

Derivative Instruments and Hedging Activities (Gain or loss on derivative contracts) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on fair value adjustments			$ (4,677)	$ 249
Total gain (loss) on derivative instruments	(4,685)	1,981	(7,198)	1,563
Natural Gas [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	(77)	(156)	(179)	(107)
Net gain (loss) on fair value adjustments	58	485	(132)	97
Total gain (loss) on derivative instruments	(19)	329	(311)	(10)
Crude Oil [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements	(1,569)	849	(2,341)	1,422
Net gain (loss) on fair value adjustments	(3,097)	803	(4,546)	151
Total gain (loss) on derivative instruments	$ (4,666)	$ 1,652	$ (6,887)	$ 1,573

XML

Derivative Instruments and Hedging Activities (Derivative Netting Adjustments) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Offsetting Assets and Liabilities [Line Items]
Derivative Assets	$ 851	$ 60
Derivative Liabilities	(6,577)	(1,108)
Current assets: Fair value of hedging contracts [Member]
Offsetting Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset	26
Derivative Asset, Fair Value, Gross Liability	(26)
Long-term assets: Fair value of hedging contracts [Member]
Offsetting Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset	851
Derivative Assets	851
Current liabilities: Fair value of hedging contracts [Member]
Offsetting Assets and Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(5,332)
Derivative Liability, Fair Value, Gross Asset	26
Derivative Liabilities	(5,306)
Long-term liabilities: Fair value of hedging contracts [Member]
Offsetting Assets and Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(1,271)
Derivative Liabilities	(1,271)
Not Designated as Hedging Instrument [Member]
Offsetting Assets and Liabilities [Line Items]
Derivative Assets	851	60
Derivative Liabilities	$ (6,577)	$ (1,108)

XML

Derivative Instruments and Hedging Activities (Derivative Positions) (Details) (Not Designated as Hedging Instrument [Member])	6 Months Ended
	Jun. 30, 2014 MBbls
Collar Contracts Combined With Short Puts 2015 [Member] | Crude Oil [Member]
Derivative [Line Items]
Total volume, oil contracts	317,000
Collar Contracts Combined With Short Puts 2015 [Member] | Crude Oil [Member] | Call Option [Member] | Short [Member]
Derivative [Line Items]
Strike price	99.10
Collar Contracts Combined With Short Puts 2015 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member]
Derivative [Line Items]
Strike price	75.00
Collar Contracts Combined With Short Puts 2015 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member]
Derivative [Line Items]
Strike price	90.00
Swap Contracts 2014 [Member] | Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Total volume, oil contracts	304,000
Average swap price	95.10
Put Spreads 2015 [Member] | Crude Oil [Member] | Put Option [Member]
Derivative [Line Items]
Total volume, oil contracts	276,000
Put Spreads 2015 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member]
Derivative [Line Items]
Strike price	75.00
Put Spreads 2015 [Member] | Crude Oil [Member] | Put Option [Member] | Long [Member]
Derivative [Line Items]
Strike price	90.00
Swap Contracts Combined With Short Put 2014 [Member] | Crude Oil [Member]
Derivative [Line Items]
Total volume, oil contracts	184,000
Swap Contracts Combined With Short Put 2014 [Member] | Crude Oil [Member] | Put Option [Member] | Short [Member]
Derivative [Line Items]
Strike price	70.00
Swap Contracts Combined With Short Put 2014 [Member] | Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Swap price	93.35
Call Contracts 2014 [Member] | Natural Gas [Member] | Call Option [Member]
Derivative [Line Items]
Total volume, natural gas contracts	230,000
Call Contracts 2014 [Member] | Natural Gas [Member] | Call Option [Member] | Short [Member]
Derivative [Line Items]
Strike price	4.75	[1]
Call Contracts 2014 [Member] | Natural Gas [Member] | Call Option [Member] | Long [Member]
Derivative [Line Items]
Strike price	4.75	[1]
Swap Contracts Combined With Short Calls 2014 [Member] | Natural Gas [Member] | Swap [Member] | Short [Member]
Derivative [Line Items]
Total volume, natural gas contracts	368,000
Swap price	4.25
Swap Contracts Combined With Short Calls 2015 [Member] | Natural Gas [Member] | Call Option [Member] | Short [Member]
Derivative [Line Items]
Total volume, natural gas contracts	438,000
Strike price	5.00

[1] (a)Offsetting contracts

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Fair Value Measurements (Fair Value) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
13% Senior Notes, principal	$ 166,500	$ 70,481
Derivative Assets
Derivative Assets	851	60
Liabilities
Derivative Liabilities, Current	(5,306)	(1,036)
Derivative Liabilities	(6,577)	(1,108)
Fair Value, Net Asset (Liability)	(5,726)	(1,048)
Carrying Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	166,500	75,748
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	166,500	72,299
Level 2 [Member]
Derivative Assets
Derivative Assets	851	60
Liabilities
Derivative Liabilities	(6,577)	(1,108)
Fair Value, Net Asset (Liability)	(5,726)	(1,048)
Senior Secured Revolving Credit Facility [Member] | Carrying Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Credit facility	84,000	22,000
Senior Secured Revolving Credit Facility [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Credit facility	84,000	22,000
Second Lien Term Loan Facility [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
13% Senior Notes, principal	82,500
Second Lien Term Loan Facility [Member] | Carrying Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Credit facility	82,500
Second Lien Term Loan Facility [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Credit facility	82,500
13% Senior Notes due 2016 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
13% Senior Notes, principal		48,481
Deferred credit		5,267
13% Senior Notes due 2016 [Member] | Carrying Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
13% Senior Notes due 2016		53,748	[1]
13% Senior Notes due 2016 [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
13% Senior Notes due 2016		50,299	[1]
Current assets - Fair market value of derivatives [Member]
Derivative Assets
Derivative Assets, Current		60
Liabilities
Derivative Liabilities, Current	(5,306)
Current assets - Fair market value of derivatives [Member] | Level 2 [Member]
Derivative Assets
Derivative Assets, Current		60
Liabilities
Derivative Liabilities, Current	(5,306)
Noncurrent assets - Other assets, net [Member]
Derivative Assets
Derivative Assets, Noncurrent	851
Noncurrent assets - Other assets, net [Member] | Level 2 [Member]
Derivative Assets
Derivative Assets, Noncurrent	851
Current liabilities - Fair market value of derivatives [Member]
Liabilities
Derivative Liabilities, Current		(1,036)
Current liabilities - Fair market value of derivatives [Member] | Level 2 [Member]
Liabilities
Derivative Liabilities, Current		(1,036)
Other long-term liabilities [Member]
Liabilities
Derivative Liabilities, Noncurrent	(1,271)	(72)
Other long-term liabilities [Member] | Level 2 [Member]
Liabilities
Derivative Liabilities, Noncurrent	$ (1,271)	$ (72)

[1] Fair value is calculated only in relation to the $48,481 principal outstanding of the Senior Notes at December 31, 2013 and excludes the remaining $5,267 deferred credit. The fair value of the Senior Notes, which is valued using Level 2 inputs, is based upon estimates provided by an independent investment banking firm. See Note 4 for additional information.

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Earnings Per Share

6 Months Ended

Jun. 30, 2014

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 June 30,				Six Months Ended June 30,
		2014		2013		2014		2013
Net income (loss)	$	4,740	$	758	$	6,603	$	(42)
Preferred stock dividends		(1,973)		(680)		(3,947)		(680)
Income (loss) available to common stockholders	$	2,767	$	78	$	2,656	$	(722)
Weighted average shares outstanding		40,606		40,089		40,467		39,941
Dilutive impact of restricted stock		999		234		1,185		—
Weighted average shares outstanding for diluted income (loss) per share		41,605		40,323		41,652		39,941
Basic income (loss) per share	$	0.07	$	0.00	$	0.07	$	(0.02)
Diluted income (loss) per share	$	0.07	$	0.00	$	0.06	$	(0.02)
The following were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive:
Stock options		30		52		30		52
Restricted stock		—		267		—		267

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Income Taxes (Narrative) (Details)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Income Tax Disclosure [Abstract]
Income tax expense computed at the statutory federal income tax rate	35.00%
Effective tax rate (as a percent)	45.00%	109.00%

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 1,172	$ 3,012
Accounts receivable	26,951	20,586
Deferred tax asset	5,846	3,843
Other current assets	1,798	2,123
Total current assets	35,767	29,564
Oil and natural gas properties, full-cost accounting method:
Evaluated properties	1,844,691	1,701,577
Less accumulated depreciation, depletion and amortization	(1,444,169)	(1,420,612)
Net oil and natural gas properties	400,522	280,965
Unevaluated properties	36,957	43,222
Total oil and natural gas properties	437,479	324,187
Other property and equipment, net	7,388	7,255
Restricted investments	3,806	3,806
Deferred tax asset	50,421	57,765
Other assets, net	5,057	1,376
Total assets	539,918	423,953
Current liabilities:
Accounts payable and accrued liabilities	61,028	53,464
Market-based restricted stock unit awards	6,683	4,173
Asset retirement obligations	2,846	4,120
Fair market value of derivatives	5,306	1,036
Total current liabilities	75,863	62,793
13% Senior Notes:
long term debt	166,500	70,481
Total 13% Senior Notes		53,748
Asset retirement obligations	2,752	2,612
Market-based restricted stock unit awards	10,717	3,409
Other long-term liabilities	1,497	297
Total liabilities	257,329	144,859
Stockholders' equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,578,948 and 1,578,948 shares outstanding, respectively	16	16
Common stock, $0.01 par value, 110,000,000 and 60,000,000 shares authorized; 40,785,751 and 40,345,456 shares outstanding, respectively	408	404
Capital in excess of par value	402,375	401,540
Retained deficit	(120,210)	(122,866)
Total stockholders' equity	282,589	279,094
Total liabilities and stockholders' equity	539,918	423,953
13% Senior Notes due 2016 [Member]
13% Senior Notes:
long term debt		48,481
Deferred credit, net of accumulated amortization of $0 and $26,239, respectively		5,267
Senior Secured Revolving Credit Facility [Member]
13% Senior Notes:
Credit facility	84,000	22,000
Second Lien Term Loan Facility [Member]
13% Senior Notes:
long term debt	82,500
Credit facility	$ 82,500

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Description of Business and Basis of Presentation

6 Months Ended

Jun. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [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 oil and natural gas reserves in the Permian Basin in West Texas. In late 2013, with the sale of its remaining offshore assets in the Gulf of Mexico, the Company completed the onshore strategic repositioning it initiated in 2009. 

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 the 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, 2013. The balance sheet at December 31, 2013 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, 2014.

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. When necessary to ensure consistent presentation, certain prior year amounts may be reclassified to conform to presentation in the current period. Certain prior year amounts have been reclassified to conform to current year presentation.

Recently issued accounting policies

In May 2014, the Financial Accounting Standards Board issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. The guidance in ASU No. 2014-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted.  The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.

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Other (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2014	Jun. 30, 2014	Dec. 31, 2013	Aug. 14, 2014 Subsequent Event [Member] Vertical Drilling [Member]
Operating Leases And Other Property Plant And Equipment [Line Items]
Lease payments in 2014		$ 18,111
Lease payments in 2014 in remainder of fiscal year		9,200		1,656
Lease payments in 2015		18,250		4,914
Lease payments in 2016		4,795
Impairment charge of equipment to be abondoned			1,707
Gain on sale of equipment	$ 1,080	$ 1,080

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Earnings Per Share (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Earnings Per Share, Basic and Diluted
Net income (loss)	$ 4,740	$ 758	$ 6,603	$ (42)
Preferred stock dividends	(1,973)	(680)	(3,947)	(680)
Income (loss) available to common shareholders	$ 2,767	$ 78	$ 2,656	$ (722)
Weighted average shares outstanding	40,606	40,089	40,467	39,941
Dilutive impact of restricted stock	999	234	1,185
Weighted average shares outstanding for diluted income (loss)	41,605	40,323	41,652	39,941
Basic income (loss) per share	$ 0.07	$ 0.00	$ 0.07	$ (0.02)
Diluted income (loss) per share	$ 0.07	$ 0.00	$ 0.06	$ (0.02)
Options [Member]
Earnings Per Share, Basic and Diluted
Excluded from the diluted EPS calculation because their effect would be anti-dilutive	30	52	30	52
Restricted Stock [Member]
Earnings Per Share, Basic and Diluted
Excluded from the diluted EPS calculation because their effect would be anti-dilutive		267		267

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Borrowings (Senior Secured Revolving Credit Facility) (Details) (Senior Secured Revolving Credit Facility [Member], USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Mar. 11, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Maximum borrowing capacity		$ 500,000
Current borrowing capacity	155,000
Credit Facility	$ 84,000		$ 22,000
Interest rate at period end (as a percent)	2.43%
Unused capacity, commitment fee (as a percent)	0.50%
Minimum [Member]
Line of Credit Facility [Line Items]
Basis Spread on LIBOR (as a percent)	1.75%
Maximum [Member]
Line of Credit Facility [Line Items]
Basis Spread on LIBOR (as a percent)	2.75%

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Oil and Natural Gas Properties

6 Months Ended

Jun. 30, 2014

Properties Acquisitions and Other Disclosure [Abstract]

Oil and Natural Gas Properties

Note 2 – Oil and Natural Gas Properties

Acquisitions

In the first quarter of 2014, the Company acquired1,527 net acres in Upton and Reagan Counties, Texas, which are located in the southern portion of the Midland Basin near our existing core development fields, for an aggregate cash purchase price of $8,200. The properties bear a working interest of 100% and an average net revenue interest of 78%.

Acreage expiration

During the six months ended June 30, 2014, the Company transferred $12,940  from unevaluated properties to the full cost pool related to 8,028 net acres in the Northern Midland Basin that expired or are scheduled to expire in the near future and are no longer included in the Company’s exploration and development plans. As of June 30, 2014,  net of these expirations, Callon had a remaining net acreage position in the Northern Midland Basin of 9,480 acres which the Company is still evaluating for potential future exploration activities.

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
LIABILITIES AND STOCKHOLDERS' EQUITY
Accumulated amortization of deferred credit	$ 0	$ 26,239
Stockholders' equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	110,000,000	60,000,000
Common stock, shares outstanding	40,785,751	40,345,456
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	1,578,948	1,578,948

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Borrowings (Tables)

6 Months Ended

Jun. 30, 2014

Debt Disclosure [Abstract]

Schedule of Borrowings

	June 30, 2014		December 31, 2013
Principal components:
Senior secured revolving credit facility	$	84,000	$	22,000
Second lien term loan facility		82,500		—
13% Senior Notes, principal		—		48,481
Total principal outstanding		166,500		70,481
13% Senior Notes unamortized deferred credit		—		5,267
Total carrying value of borrowings	$	166,500	$	75,748

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Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Aug. 01, 2014
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	Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,843,827

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Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

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	06/30/14		12/31/2013		06/30/2014		12/31/2013		06/30/2014		12/31/2013
Natural gas	Current	Fair value of derivatives	$	—	$	—	$	(114)	$	—	$	(114)	$	—
Natural gas	Current	Other current assets		—		60		—		—		—		60
Natural gas	Non-current	Other long-term liabilities		—		—		(29)		(72)		(29)		(72)
Oil	Current	Fair value of derivatives		—		—		(5,192)		(1,036)		(5,192)		(1,036)
Oil	Non-current	Other long-term assets		851		—		—		—		851		—
Oil	Non-current	Other long-term liabilities		—		—		(1,242)		—		(1,242)		—
	Totals		$	851	$	60	$	(6,577)	$	(1,108)	$	(5,726)	$	(1,048)

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 at June 30, 2014:

	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	26	$	(26)	$	—
Long-term assets: Fair value of derivatives		851		—		851
Current liabilities: Fair value of derivatives		(5,332)		26		(5,306)
Long-term liabilities: Fair value of derivatives	$	(1,271)	$	—	$	(1,271)

Schedule of Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance

	Three Months Ended June 30,				Six Months Ended June 30,
		2014		2013		2014		2013
Natural gas derivatives
Net loss on settlements	$	(77)	$	(156)	$	(179)	$	(107)
Net gain (loss) on fair value adjustments		58		485		(132)		97
Total gain (loss)	$	(19)	$	329	$	(311)	$	(10)
Oil derivatives
Net gain (loss) on settlements	$	(1,569)	$	849	$	(2,341)	$	1,422
Net gain (loss) on fair value adjustments		(3,097)		803		(4,546)		151
Total gain (loss)	$	(4,666)	$	1,652	$	(6,887)	$	1,573
Total gain (loss) on derivative instruments	$	(4,685)	$	1,981	$	(7,198)	$	1,563

Schedule of Outstanding Oil and Natural Gas Derivative Contracts

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of June 30, 2014:

	For the Six Months Ending December 31,		For the Year Ending December 31,
Oil contracts	2014		2015
Collar contracts combined with short puts (three-way collar):
Volume (MBbls)		—		317
Price per Bbl
Ceiling (short call)		—	$	99.10
Floor (long put)		—	$	90.00
Short put		—	$	75.00
Swap contracts:
Total volume (MBbls)		304		—
Weighted average price per Bbl	$	95.10		—
Put spreads:
Volume (MBbls)		—		276
Long put price per Bbl		—	$	90.00
Short put price per Bbl		—	$	75.00
Swap contracts combined with short put:
Volume (MBbls)		184		—
Swap price per Bbl	$	93.35		—
Short put price per Bbl	$	70.00		—
	For the Six Months Ending December 31,		For the Year Ending December 31,
Natural gas contracts	2014		2015
Call contracts:
Volume (MMBtu)		230		—
Short call price per MMBtu (a)	$	4.75		—
Long call price per MMBtu (a)	$	4.75		—
Swap contracts combined with short calls:
Swap volume (MMBtu)		368		—
Swap price per MMBtu	$	4.25		—
Short call volume (MMBtu)		—		438
Short call price per MMBtu		—	$	5.00

(a)Offsetting contracts.

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Consolidated Statements of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Operating revenues:
Total operating revenues	$ 40,502	$ 22,760	$ 73,787	$ 45,301
Operating expenses:
Lease operating expenses	4,363	5,259	8,593	10,836
Production taxes	2,265	812	4,182	1,532
Depreciation, depletion and amortization	11,982	10,654	22,520	21,696
General and administrative	9,639	4,545	20,446	8,284
Accretion expense	173	533	401	1,098
Gain on sale of other property and equipment			(1,080)
Total operating expenses	28,422	21,803	55,062	43,446
Income from operations	12,080	957	18,725	1,855
Other (income) expenses:
Interest expense	1,825	1,537	2,802	3,052
Gain on early extinguishment of debt	(3,205)		(3,205)
Loss (gain) on derivative contracts	4,685	(1,981)	7,198	(1,563)
Other (income) expense	(93)	(44)	(142)	(89)
Total other expenses	3,212	(488)	6,653	1,400
Income before income taxes	8,868	1,445	12,072	455
Income tax expense	4,128	663	5,469	494
Income (loss) before equity in earnings of Medusa Spar LLC	4,740	782	6,603	(39)
Loss from Medusa Spar LLC		(24)		(3)
Net income (loss)	4,740	758	6,603	(42)
Preferred stock dividends	(1,973)	(680)	(3,947)	(680)
Income (loss) available to common shareholders	2,767	78	2,656	(722)
income (loss) per common share:
Basic	$ 0.07	$ 0.00	$ 0.07	$ (0.02)
Diluted	$ 0.07	$ 0.00	$ 0.06	$ (0.02)
Shares used in computing income per common share:
Basic	40,606	40,089	40,467	39,941
Diluted	41,605	40,323	41,652	39,941
Crude Oil [Member]
Operating revenues:
Total operating revenues	37,710	19,061	68,619	38,601
Natural Gas [Member]
Operating revenues:
Total operating revenues	$ 2,792	$ 3,699	$ 5,168	$ 6,700

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Income Taxes

6 Months Ended

Jun. 30, 2014

Income Tax Disclosure [Abstract]

Income Taxes

Note 7 - Income Taxes

The Company provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. The effective tax rate for the six months ended June 30, 2014 and 2013 was  45% and109%, respectively.

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Fair Value Measurements

6 Months Ended

Jun. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 6 - Fair Value Measurements

The fair value hierarchy outlined in the relevant accounting guidance 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, restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.

Debt. The Company’s debt is recorded at the carrying amount in the consolidated balance sheet. The carrying amount of floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates.

The following table summarizes the respective carrying and fair values at:

						`
	June 30, 2014				December 31, 2013
	Carrying Value		Fair Value			Carrying Value	Fair Value
Credit Facility	$	84,000	$	84,000	$	22,000	$	22,000
Second Lien Facility		82,500		82,500		—		—
13% Senior Notes due 2016 (a)		—		—		53,748		50,299
Total	$	166,500	$	166,500	$	75,748	$	72,299

(a) Fair value is calculated only in relation to the $48,481 principal outstanding of the Senior Notes at December 31, 2013 and excludes the remaining $5,267 deferred credit. The fair value of the Senior Notes, which is valued using Level 2 inputs, is based upon estimates provided by an independent investment banking firm. See Note 4 for additional information.

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, and the values are corroborated by quotes obtained from counterparties to the agreements. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 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:

June 30, 2014	Balance Sheet Presentation		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments (non-current)	Other long-term assets	$	—	$	851	$	—	$	851
Sub-total assets		$	—	$	851	$	—	$	851
Liabilities
Derivative financial instruments (current)	Fair value of derivatives	$	—	$	(5,306)	$	—	$	(5,306)
Derivative financial instruments (non-current)	Other long-term liabilities		—		(1,271)		—		(1,271)
Sub-total liabilities		$	—	$	(6,577)	$	—	$	(6,577)
Total net assets (liabilities)		$	—	$	(5,726)	$	—	$	(5,726)
December 31, 2013	Balance Sheet Presentation		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments (current)	Other current assets	$	—	$	60	$	—	$	60
Sub-total assets		$	—	$	60	$	—	$	60
Liabilities
Derivative financial instruments (current)	Fair value of derivatives	$	—	$	(1,036)	$	—	$	(1,036)
Derivative financial instruments (non-current)	Other long-term liabilities		—		(72)		—		(72)
Sub-total liabilities		$	—	$	(1,108)	$	—	$	(1,108)
Total net assets (liabilities)		$	—	$	(1,048)	$	—	$	(1,048)

The derivative fair values above are based on analysis of each contract. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 5 for a discussion of net amounts recorded in the consolidated balance sheet at June 30, 2014.

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Borrowings (Schedule of Borrowings) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Principal components:
13% Senior Notes, principal	$ 166,500	$ 70,481
Non-cash components:
Total carrying value of borrowings	166,500	75,748
Senior Secured Revolving Credit Facility [Member]
Principal components:
Credit Facility	84,000	22,000
Second Lien Term Loan Facility [Member]
Principal components:
Credit Facility	82,500
13% Senior Notes, principal	82,500
13% Senior Notes due 2016 [Member]
Principal components:
13% Senior Notes, principal		48,481
Non-cash components:
Deferred credit		$ 5,267

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2014

Fair Value Disclosures [Abstract]

Summary of Fair Value of Financial Instruments at Carrying and Fair Value

The following table summarizes the respective carrying and fair values at:

						`
	June 30, 2014				December 31, 2013
	Carrying Value		Fair Value			Carrying Value	Fair Value
Credit Facility	$	84,000	$	84,000	$	22,000	$	22,000
Second Lien Facility		82,500		82,500		—		—
13% Senior Notes due 2016 (a)		—		—		53,748		50,299
Total	$	166,500	$	166,500	$	75,748	$	72,299

(a) Fair value is calculated only in relation to the $48,481 principal outstanding of the Senior Notes at December 31, 2013 and excludes the remaining $5,267 deferred credit. The fair value of the Senior Notes, which is valued using Level 2 inputs, is based upon estimates provided by an independent investment banking firm. See Note 4 for additional information.

Fair Value Liabilities Measured on Recurring Basis

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

June 30, 2014	Balance Sheet Presentation		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments (non-current)	Other long-term assets	$	—	$	851	$	—	$	851
Sub-total assets		$	—	$	851	$	—	$	851
Liabilities
Derivative financial instruments (current)	Fair value of derivatives	$	—	$	(5,306)	$	—	$	(5,306)
Derivative financial instruments (non-current)	Other long-term liabilities		—		(1,271)		—		(1,271)
Sub-total liabilities		$	—	$	(6,577)	$	—	$	(6,577)
Total net assets (liabilities)		$	—	$	(5,726)	$	—	$	(5,726)
December 31, 2013	Balance Sheet Presentation		Level 1		Level 2		Level 3		Total
Assets
Derivative financial instruments (current)	Other current assets	$	—	$	60	$	—	$	60
Sub-total assets		$	—	$	60	$	—	$	60
Liabilities
Derivative financial instruments (current)	Fair value of derivatives	$	—	$	(1,036)	$	—	$	(1,036)
Derivative financial instruments (non-current)	Other long-term liabilities		—		(72)		—		(72)
Sub-total liabilities		$	—	$	(1,108)	$	—	$	(1,108)
Total net assets (liabilities)		$	—	$	(1,048)	$	—	$	(1,048)

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Other

6 Months Ended

Jun. 30, 2014

Other [Abstract]

Other

Note 10 – Other

Operating leases

In April 2012, the Company contracted a drilling rig (the “Cactus 1 Rig”) for a term of two years, which it subsequently renewed in March 2014 for an additional two-year term ending in April 2016. In April 2014, the Company contracted an additional horizontal drilling rig (the “Cactus 2 Rig”) for a term of two years ending in April 2016. The Cactus 2 Rig replaced a previously contracted horizontal drilling rig, which was cancelled in March 2014. The Cactus 1 and Cactus 2 Rig lease agreements include early termination provisions that would reduce the minimum rentals under the agreement, and also include early termination payments that would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee. Lease payments in 2014,  2015 and 2016 are expected to approximate $18,111 (with $9,200 remaining at June 30, 2014), $18,250 and $4,795, respectively.

Other property and equipment

As disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, the Company made a decision to abandon certain specialized deep water property and equipment received as part of a prior settlement agreement related to various disputes with a previous joint interest partner as a result of the unsuccessful marketing of such assets. Accordingly, the Company recognized an impairment charge of $1,707 related to such property and equipment in the year ended December 31, 2013. Subsequent to the filing of the Annual Report on Form 10-K, the Company entered into an agreement to sell the property and equipment to a third party. While the third party had previously performed some initial inspection and evaluation of the equipment, based on the amount of time the equipment had been unsuccessfully marketed and the feedback from potential buyers, management concluded the likelihood of completing a sale of the equipment was low, resulting in the decision to abandon the equipment and recognize an impairment charge in 2013. As a result of the subsequent sale of the property and equipment, the Company recognized a gain of $1,080 in the first quarter 2014.

Subsequent Events

In August 2014, the Company signed a one-year contract for a vertical drilling rig to be used as part of our horizontal drilling program, drilling the vertical component of horizontal wells. Lease payments in 2014 and 2015 are expected to approximate $1,656 and $4,914, respectively, subject to customary termination provisions.

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2014

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

Note 8 - Asset Retirement Obligations

The table below summarizes the Company’s asset retirement obligations activity for the six months ended June 30, 2014:

Asset retirement obligations at January 1, 2014	$	6,732
Accretion expense		401
Liabilities incurred		404
Liabilities settled		(1,747)
Revisions to estimate		(192)
Asset retirement obligations at end of period		5,598
Less: Current asset retirement obligations		2,846
Long-term asset retirement obligations at June 30, 2014	$	2,752

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheets as restricted investments were $3,806 at June 30, 2014. These investments include primarily U.S. Government securities, and 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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Preferred Stock

6 Months Ended

Jun. 30, 2014

Equity [Abstract]

Preferred Stock

Note 9 – 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. For the quarter ended June 30, 2014, the Board declared a dividend of $1.25 per share, or a total of$1,973, on the Company’s Preferred Stock. Dividends for the six months ended June 30, 2014 were$3,947.

As defined in a provision of the Preferred Stock prospectus, the common shares reserved for issuance vary based on the number of authorized common shares. In January 2014, following a majority shareholder vote, the number of authorized shares of common stock was increased from 60,000,000 to 110,000,000 with a corresponding increase in the number of common shares reserved for a potential conversion to a maximum of 42,200,000 shares. Based on the Company’s closing common stock price of $11.65 per share on June 30, 2014, the Company has reserved 6,776,601 shares of its total authorized shares to satisfy a potential conversion that would be subject to the satisfaction of several conditions, including a change of control as defined in description of Preferred Stock.

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2014

Earnings Per Share [Abstract]

Computation of Earnings Per Share, Basic and Diluted

(share amounts in thousands)	Three Months Ended June 30,				Six Months Ended June 30,
		2014		2013		2014		2013
Net income (loss)	$	4,740	$	758	$	6,603	$	(42)
Preferred stock dividends		(1,973)		(680)		(3,947)		(680)
Income (loss) available to common stockholders	$	2,767	$	78	$	2,656	$	(722)
Weighted average shares outstanding		40,606		40,089		40,467		39,941
Dilutive impact of restricted stock		999		234		1,185		—
Weighted average shares outstanding for diluted income (loss) per share		41,605		40,323		41,652		39,941
Basic income (loss) per share	$	0.07	$	0.00	$	0.07	$	(0.02)
Diluted income (loss) per share	$	0.07	$	0.00	$	0.06	$	(0.02)
The following were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive:
Stock options		30		52		30		52
Restricted stock		—		267		—		267

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Preferred Stock (Details) (USD $) In Thousands, except Share data, unless otherwise specified				3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jan. 31, 2014	Dec. 31, 2013	Jun. 30, 2014 Series A Preferred Stock [Member]	Jun. 30, 2014 Series A Preferred Stock [Member]	Dec. 31, 2013 Series A Preferred Stock [Member]
Class of Stock [Line Items]
Preferred stock, shares outstanding				1,578,948	1,578,948	1,578,948
Preferred Stock, Dividend Rate, Percentage					10.00%
Preferred stock, liquidation preference (in dollars per share)				$ 50.00	$ 50.00	$ 50.00
Preferred Stock, Dividend Rate, Per-Dollar-Amount, Per Annum					$ 5.00
Preferred Stock, Dividends Per Share, Declared				$ 1.25
Dividends, Preferred Stock, Cash				$ 1,973	$ 3,947
Common stock, shares authorized	110,000,000	110,000,000	60,000,000
Convertible Preferred Stock, Shares Reserved for Future Issuance	42,200,000
Share Price	$ 11.65
Convertible Preferred Stock, Shares Reserved to Satisfy Potential Conversion	6,776,601

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Oil and Natural Gas Properties (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended
	Mar. 31, 2014 Reagan and Upton Counties Acreage Purchase [Member] acre	Jun. 30, 2014 Northern Midland Basin [Member] acre
Oil And Natural Gas Properties [Line Items]
Net acres	1,527	9,480
Acquisition price	$ 8,200
Working interest	100.00%
revenue interest	78.00%
Net acres to expire		8,028
Amount transferred from unevaluated properties to full cost pool		$ 12,940

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Borrowings (13% Senior Notes due 2016 (“Senior Notes”) and Deferred Credit) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended				0 Months Ended
	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2013 13% Senior Notes due 2016 [Member]	Apr. 11, 2014 13% Senior Notes due 2016 [Member] Senior Notes [Member]	Apr. 11, 2014 13% Senior Notes due 2016 [Member] Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of senior debt						$ 48,481
13% Senior Notes, principal	166,500	166,500		70,481	48,481
Gain on extinguishment of debt	3,205	3,205				3,205
Extinguishment of Debt, Amount						50,057
Redemption expenses						1,576
Carrying value	166,500	166,500		75,748			53,261
Deferred credit					(5,267)		4,780
Accumulated Amortization	0	0		26,239
Amortization of deferred credit		(433)	(1,615)			(4,780)
Payment for accrued interest on redemption of debt						$ 193

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Cash flows from operating activities:
Net income	$ 6,603	$ (42)
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	22,976	22,405
Accretion expense	401	1,098
Amortization of non-cash debt related items	298	228
Amortization of deferred credit	(433)	(1,615)
Equity in earnings of Medusa Spar LLC		3
Deferred income tax expense	5,469	494
Net loss (gain) on derivatives, net of settlements	4,677	(249)
Gain on sale of other property and equipment	(1,080)
Gain on early extinguishment of debt	(3,205)
Non-cash expense related to equity share-based awards	(36)	734
Change in the fair value of liability share-based awards	8,070	(852)
Payments to settle asset retirement obligations	(1,469)	(615)
Changes in current assets and liabilities:
Accounts receivable	(5,268)	789
Other current assets	265	598
Current liabilities	2,014	(324)
Payments to settle vested liability share-based awards	(3,469)	(239)
Change in other long-term liabilities		(386)
Change in other assets, net	(216)	(1,790)
Net cash provided by operating activities	35,597	20,237
Cash flows from investing activities:
Capital expenditures	(127,219)	(58,385)
Acquisition		(11,000)
Proceeds from sale of mineral interests and equipment	2,267	1,389
Distribution from Medusa Spar LLC		616
Net cash used in investing activities	(124,952)	(67,380)
Cash flows from financing activities:
Borrowings on debt	150,000	31,000
Payment of deferred financing costs	(2,928)
Payments on debt	(55,610)	(41,000)
Issuance of preferred stock		70,090
Payment of preferred stock dividends	(3,947)	(680)
Cash flows from financing activities:	87,515	59,410
Net change in cash and cash equivalents	(1,840)	12,267
Balance, beginning of period	3,012	1,139
Balance, end of period	$ 1,172	$ 13,406

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Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [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, puts, calls 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 a derivative instruments’ fair value; seeNote 6 for additional information regarding fair value.

The Company executes commodity derivative contracts under master agreements that have netting provisions that provide for offsetting payables against receivables. 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, depending on the type of instrument, the Company utilizes present value methods or standard option valuation models 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 elected not to designate its derivative contracts as accounting hedges under Accounting Standards Codification 815.Consequently, the Company records its derivative contracts at fair value in the consolidated balance sheet and records changes in fair value as a gain or loss on derivative contracts in the consolidated statement of operations.Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statement 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	06/30/14		12/31/2013		06/30/2014		12/31/2013		06/30/2014		12/31/2013
Natural gas	Current	Fair value of derivatives	$	—	$	—	$	(114)	$	—	$	(114)	$	—
Natural gas	Current	Other current assets		—		60		—		—		—		60
Natural gas	Non-current	Other long-term liabilities		—		—		(29)		(72)		(29)		(72)
Oil	Current	Fair value of derivatives		—		—		(5,192)		(1,036)		(5,192)		(1,036)
Oil	Non-current	Other long-term assets		851		—		—		—		851		—
Oil	Non-current	Other long-term liabilities		—		—		(1,242)		—		(1,242)		—
	Totals		$	851	$	60	$	(6,577)	$	(1,108)	$	(5,726)	$	(1,048)

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 at June 30, 2014:

	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	26	$	(26)	$	—
Long-term assets: Fair value of derivatives		851		—		851
Current liabilities: Fair value of derivatives		(5,332)		26		(5,306)
Long-term liabilities: Fair value of derivatives	$	(1,271)	$	—	$	(1,271)

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 June 30,				Six Months Ended June 30,
		2014		2013		2014		2013
Natural gas derivatives
Net loss on settlements	$	(77)	$	(156)	$	(179)	$	(107)
Net gain (loss) on fair value adjustments		58		485		(132)		97
Total gain (loss)	$	(19)	$	329	$	(311)	$	(10)
Oil derivatives
Net gain (loss) on settlements	$	(1,569)	$	849	$	(2,341)	$	1,422
Net gain (loss) on fair value adjustments		(3,097)		803		(4,546)		151
Total gain (loss)	$	(4,666)	$	1,652	$	(6,887)	$	1,573
Total gain (loss) on derivative instruments	$	(4,685)	$	1,981	$	(7,198)	$	1,563

Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of June 30, 2014:

	For the Six Months Ending December 31,		For the Year Ending December 31,
Oil contracts	2014		2015
Collar contracts combined with short puts (three-way collar):
Volume (MBbls)		—		317
Price per Bbl
Ceiling (short call)		—	$	99.10
Floor (long put)		—	$	90.00
Short put		—	$	75.00
Swap contracts:
Total volume (MBbls)		304		—
Weighted average price per Bbl	$	95.10		—
Put spreads:
Volume (MBbls)		—		276
Long put price per Bbl		—	$	90.00
Short put price per Bbl		—	$	75.00
Swap contracts combined with short put:
Volume (MBbls)		184		—
Swap price per Bbl	$	93.35		—
Short put price per Bbl	$	70.00		—
	For the Six Months Ending December 31,		For the Year Ending December 31,
Natural gas contracts	2014		2015
Call contracts:
Volume (MMBtu)		230		—
Short call price per MMBtu (a)	$	4.75		—
Long call price per MMBtu (a)	$	4.75		—
Swap contracts combined with short calls:
Swap volume (MMBtu)		368		—
Swap price per MMBtu	$	4.25		—
Short call volume (MMBtu)		—		438
Short call price per MMBtu		—	$	5.00

(a)Offsetting contracts.

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Derivative Instruments and Hedging Activities (Derivatives Fair Value By Balance Sheet Location) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Asset Fair Value	$ 851	$ 60
Liability Fair Value	(6,577)	(1,108)
Net Derivative Fair Value	(5,726)	(1,048)
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Asset Fair Value	851	60
Liability Fair Value	(6,577)	(1,108)
Net Derivative Fair Value	(5,726)	(1,048)
Current liabilities - Fair market value of derivatives [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Liability Fair Value	(114)
Net Derivative Fair Value	(114)
Current liabilities - Fair market value of derivatives [Member] | Not Designated as Hedging Instrument [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Liability Fair Value	(5,192)	(1,036)
Net Derivative Fair Value	(5,192)	(1,036)
Non-current liabilities - Other long-term liabilities [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Liability Fair Value	(29)	(72)
Net Derivative Fair Value	(29)	(72)
Non-current liabilities - Other long-term liabilities [Member] | Not Designated as Hedging Instrument [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Liability Fair Value	(1,242)
Net Derivative Fair Value	(1,242)
Current assets - Fair market value of derivatives [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Asset Fair Value		60
Net Derivative Fair Value		60
Non-current assets - Other long-term assets [Member] | Not Designated as Hedging Instrument [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Asset Fair Value	851
Net Derivative Fair Value	$ 851

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2014

Asset Retirement Obligation [Abstract]

Schedule of Change in Asset Retirement Obligation

Asset retirement obligations at January 1, 2014	$	6,732
Accretion expense		401
Liabilities incurred		404
Liabilities settled		(1,747)
Revisions to estimate		(192)
Asset retirement obligations at end of period		5,598
Less: Current asset retirement obligations		2,846
Long-term asset retirement obligations at June 30, 2014	$	2,752