Edgar Filing: CALLON PETROLEUM CO

e720e34bc7844c4

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

☐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

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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.

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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.

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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.

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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.

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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.

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)

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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 acquired 1,527 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

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)

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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 of 8.75%, 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

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)

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Senior Notes of $53,261 (inclusive of $4,780 of deferred credit). The Company also paid $193 in 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; see Note 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.

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)

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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

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)

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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.

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)

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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.

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)

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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.

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)

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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 ended June 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 from 314 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 current 2014 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.

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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 the six 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 ended June 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.

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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 ended June 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 to a 1,083 MMcf decrease in production due to the sale of our

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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 ended June 30, 2014 decreased by 17% to $4.4 million compared to $5.3 million for the same period of 2013 primarily 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 ended June 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, 2014 compared 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 ended June 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, 2014 compared 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 ended June 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 the six months ended June 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 the three and six months ended June 30, 2014 increased $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. Dividends reflect 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 and receivables 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 receivables with several significant customers. We do not require any of our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely 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