Edgar Filing: CALLON PETROLEUM CO

Q2 - Form 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



	FORM 10-Q

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

For The Quarterly Period Ended June 30, 2015

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

For the transition period from ____________ to ____________

Commission File Number 001-14039

Callon Petroleum Company

(Exact Name of Registrant as Specified in Its Charter)

Delaware

(State or Other Jurisdiction of

Incorporation or Organization)

64-0844345

(IRS Employer

Identification No.)

200 North Canal Street

Natchez, Mississippi

(Address of Principal Executive Offices)

39120

(Zip Code)

601-442-1601

(Registrant’s Telephone Number, Including Area Code)

Not Applicable

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 ☒

The Registrant had 66,279,074 shares of common stock outstanding as of July 31, 2015.

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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	16

Item 3. Quantitative and Qualitative Disclosures about Market Risk	25

Item 4. Controls and Procedures	26

Part II. Other Information

Item 1. Legal Proceedings	27

Item 1A. Risk Factors	27

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	27

Item 3. Defaults Upon Senior Securities	27

Item 4. Mine Safety Disclosures	27

Item 5. Other Information	27

Item 6. Exhibits	28

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DEFINITIONS

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

ARO: asset retirement obligation.

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

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

BBtu: billion Btu.

BOE/d: BOE per day.

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

LIBOR: London Interbank Offered Rate.

LOE: lease operating expense.

MBbls: thousand barrels of oil.

MBOE: thousand BOE.

Mcf: thousand cubic feet of natural gas.

MMBtu: million Btu.

MMcf: million cubic feet of natural gas.

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

NYMEX: New York Mercantile Exchange.

Oil: includes crude oil and condensate.

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, 2015		December 31, 2014
ASSETS		Unaudited
Current assets:
Cash and cash equivalents	$	2,028	$	968
Accounts receivable		34,499		30,198
Fair value of derivatives		6,889		27,850
Other current assets		1,525		1,441
Total current assets		44,941		60,457
Oil and natural gas properties, full cost accounting method:
Evaluated properties		2,207,999		2,077,985
Less accumulated depreciation, depletion and amortization		(1,514,036)		(1,478,355)
Net oil and natural gas properties		693,963		599,630
Unevaluated properties		131,121		142,525
Total oil and natural gas properties		825,084		742,155
Other property and equipment, net		7,874		7,118
Restricted investments		3,299		3,810
Deferred tax asset		46,497		44,688
Deferred financing costs		16,639		18,200
Other assets, net		658		342
Total assets	$	944,992	$	876,770
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	65,792	$	76,753
Accrued interest		5,974		5,993
Cash-settled restricted stock unit awards		8,172		3,856
Asset retirement obligations		872		4,747
Deferred tax liability		830		6,214
Fair value of derivatives		1,622		1,249
Total current liabilities		83,262		98,812
Senior secured revolving credit facility		75,000		35,000
Secured second lien term loan		300,000		300,000
Asset retirement obligations		3,249		1,927
Cash-settled restricted stock unit awards		3,086		7,175
Other long-term liabilities		219		121
Total liabilities		464,816		443,035
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 shares authorized; 66,190,660 and 55,225,288 shares outstanding, respectively		662		552
Capital in excess of par value		591,604		526,162
Accumulated deficit		(112,106)		(92,995)
Total stockholders’ equity		480,176		433,735
Total liabilities and stockholders’ equity	$	944,992	$	876,770

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,
		2015		2014		2015		2014
Operating revenues:
Oil sales	$	36,093	$	37,710	$	64,002	$	68,619
Natural gas sales		3,149		2,792		5,631		5,168
Total operating revenues		39,242		40,502		69,633		73,787
Operating expenses:
Lease operating expenses		6,575		4,363		13,534		8,593
Production taxes		2,952		2,265		5,217		4,182
Depreciation, depletion and amortization		17,587		11,982		35,691		22,520
General and administrative		5,763		9,639		17,865		20,446
Accretion expense		134		173		343		401
Rig termination fee		—		—		3,641		—
Gain on sale of other property and equipment		—		—		—		(1,080)
Total operating expenses		33,011		28,422		76,291		55,062
Income (loss) from operations		6,231		12,080		(6,658)		18,725
Other (income) expenses:
Interest expense		5,106		1,825		9,964		2,802
Gain on early extinguishment of debt		—		(3,205)		—		(3,205)
Loss on derivative contracts		8,249		4,685		5,820		7,198
Other income		(41)		(93)		(85)		(142)
Total other expenses		13,314		3,212		15,699		6,653
Income (loss) before income taxes		(7,083)		8,868		(22,357)		12,072
Income tax expense (benefit)		(2,116)		4,128		(7,193)		5,469
Net income (loss)		(4,967)		4,740		(15,164)		6,603
Preferred stock dividends		(1,973)		(1,973)		(3,947)		(3,947)
Income (loss) available to common stockholders	$	(6,940)	$	2,767	$	(19,111)	$	2,656
Income (loss) per common share:
Basic	$	(0.11)	$	0.07	$	(0.31)	$	0.07
Diluted	$	(0.11)	$	0.07	$	(0.31)	$	0.06
Shares used in computing income (loss) per common share:
Basic		66,038		40,606		61,759		40,467
Diluted		66,038		41,605		61,759		41,652

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,
		2015		2014
Cash flows from operating activities:
Net income (loss)	$	(15,164)	$	6,603
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization		36,557		22,976
Accretion expense		343		401
Amortization of non-cash debt related items		1,561		298
Amortization of deferred credit		—		(433)
Deferred income tax (benefit) expense		(7,193)		5,469
Net loss on derivatives, net of settlements		21,129		4,677
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		(668)		(36)
Change in the fair value of liability share-based awards		4,695		8,070
Payments to settle asset retirement obligations		(1,905)		(1,469)
Changes in current assets and liabilities:
Accounts receivable		(6,946)		(5,268)
Other current assets		(85)		265
Current liabilities		5,549		2,014
Payments to settle vested liability share-based awards related to early retirements		(3,538)		(1,417)
Payments to settle vested liability share-based awards		(3,925)		(2,052)
Change in other long-term liabilities		100		—
Change in other assets, net		(528)		(216)
Net cash provided by operating activities		29,982		35,597
Cash flows from investing activities:
Capital expenditures		(130,847)		(127,219)
Proceeds from sales of mineral interests and equipment		326		2,267
Net cash used in investing activities		(130,521)		(124,952)
Cash flows from financing activities:
Borrowings on credit facility		103,000		150,000
Payments on credit facility		(63,000)		(55,610)
Payment of deferred financing costs		—		(2,928)
Issuance of common stock		65,546		—
Payment of preferred stock dividends		(3,947)		(3,947)
Net cash provided by financing activities		101,599		87,515
Net change in cash and cash equivalents		1,060		(1,840)
Balance, beginning of period		968		3,012
Balance, end of period	$	2,028	$	1,172

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

Callon Petroleum Company

Notes to the Consolidated Financial Statements

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

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

Note 1 - Description of Business and Basis of Presentation

Description of business

Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

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

Basis of presentation

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

The interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of 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, 2014. The balance sheet at December 31, 2014 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, 2015.

In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts 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 April 2015, the Financial Accounting Standards Board issued accounting standards update (“ASU”) No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The standard requires that the costs for issuing debt should appear on the balance sheet as direct reduction from the debt’s value. The guidance in ASU No. 2015-03 is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is 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 – Acquisitions

On October 8, 2014, the Company completed the acquisition of certain undeveloped acreage and producing oil and gas properties located in Midland, Andrews, Ector and Martin Counties, Texas (the “Central Midland Basin Acquisition”) for an aggregate cash purchase price of $210,205. The Company assumed operatorship of the properties on November 1, 2014, and acquired a 62% working interest (46.5% net revenue interest) in the Central Midland Basin Acquisition. The aggregate cash purchase price was funded with a combination of the net proceeds from an equity offering of $122,450 and a portion of the net proceeds from borrowings under a secured second lien term loan.

The Central Midland Basin Acquisition was accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed. The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired:


Oil and natural gas properties	$	91,895
Unevaluated oil and natural gas properties		118,450
Asset retirement obligations		(140)
Net assets acquired	$	210,205

The following unaudited summary pro forma financial information for the three and six months ended June 30, 2014 has been presented for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Central Midland Basin Acquisition had occurred as presented, or to project the Company’s results of operations for any future periods. The pro forma financial information was prepared assuming the Central Midland Basin Acquisition occurred as of January 1, 2013. The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest.


	Three Months Ended		Six Months Ended
	June 30, 2014		June 30, 2014
Revenues	$	50,819	$	94,003
Income from operations		17,941		30,298
Income available to common stockholders		4,752		5,543

Net income per common share:
Basic	$	0.09	$	0.10
Diluted	$	0.08	$	0.10

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 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,
		2015		2014		2015		2014
Net income (loss)	$	(4,967)	$	4,740	$	(15,164)	$	6,603
Preferred stock dividends		(1,973)		(1,973)		(3,947)		(3,947)
Income (loss) available to common stockholders	$	(6,940)	$	2,767	$	(19,111)	$	2,656

Weighted average shares outstanding		66,038		40,606		61,759		40,467
Dilutive impact of restricted stock		—		999		—		1,185
Weighted average shares outstanding for diluted loss per share		66,038		41,605		61,759		41,652

Basic income (loss) per share	$	(0.11)	$	0.07	$	(0.31)	$	0.07
Diluted income (loss) per share	$	(0.11)	$	0.07	$	(0.31)	$	0.06

Stock options (a)		15		30		15		30
Restricted stock (a)		284		—		284		—

(a)

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

Note 4 – Borrowings

The Company’s borrowings consisted of the following at:


	June 30, 2015		December 31, 2014
Principal components:
Senior secured revolving credit facility	$	75,000	$	35,000
Secured second lien term loan		300,000		300,000
Total carrying value of borrowings	$	375,000	$	335,000

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. As of June 30, 2015, the Credit Facility’s borrowing base was $250,000. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties.

As of June 30, 2015, the balance outstanding on the Credit Facility was $75,000 with a weighted-average interest rate of 2.19%, 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.

Secured second lien term loan (the “Term Loan”)

On October 8, 2014, the Company entered into the Term Loan with an aggregate amount of up to $300,000 and a maturity date of October 8, 2021. The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. The Term Loan 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 October 8, 2015, (ii) 101% if the prepayment event occurs on or after October 8, 2015 but before October 8, 2016, and (iii) 100% for prepayments made on or after October 8, 2016. The Term Loan is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. As of June 30, 2015, the balance outstanding on

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 Term Loan was $300,000 with an interest rate of 8.5%, calculated at a rate of LIBOR (subject to a floor rate of 1.0%) plus 7.5% per annum. The Company can elect a LIBOR rate based on various tenors, and is currently incurring interest based on an underlying three-month LIBOR rate, which was last elected in July 2015.

Restrictive covenants

The Company’s Credit Facility and Term Loan 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, 2015.

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 the fair value of a derivative instrument; see Note 6 for additional information regarding fair value.

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

Financial statement presentation and settlements

Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See Note 6 for additional information regarding fair value.

Derivatives not designated as hedging instruments

The Company records its derivative contracts at fair value in the consolidated balance 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	06/30/2015		12/31/2014		06/30/2015		12/31/2014		06/30/2015		12/31/2014
Natural gas	Current	Fair value of derivatives	$	671	$	1,262	$	(1)	$	(7)	$	670	$	1,255
Oil	Current	Fair value of derivatives		6,218		26,588		(1,621)		(1,242)		4,597		25,346
Oil	Non-current	Other assets, net		205		—		—		—		205		—
	Totals		$	7,094	$	27,850	$	(1,622)	$	(1,249)	$	5,472	$	26,601

As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:


		June 30, 2015
	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	8,370	$	(1,481)	$	6,889
Long-term assets: Other assets, net		205		—		205
Current liabilities: Fair value of derivatives	$	(3,103)	$	1,481	$	(1,622)


		December 31, 2014
	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	27,850	$	—	$	27,850
Current liabilities: Fair value of derivatives	$	(1,249)	$	—	$	(1,249)

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,
		2015		2014		2015		2014
Oil derivatives
Net gain (loss) on settlements	$	4,511	$	(1,569)	$	14,464	$	(2,341)
Net loss on fair value adjustments		(12,755)		(3,097)		(20,544)		(4,546)
Total loss	$	(8,244)	$	(4,666)	$	(6,080)	$	(6,887)

Natural gas derivatives
Net gain (loss) on settlements	$	454	$	(77)	$	845	$	(179)
Net gain (loss) on fair value adjustments		(459)		58		(585)		(132)
Total gain (loss)	$	(5)	$	(19)	$	260	$	(311)

Total loss on derivative contracts	$	(8,249)	$	(4,685)	$	(5,820)	$	(7,198)

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, 2015:


	For the Three Months Ended
	September 30,		December 31,		March 31,		June 30,		September 30,		December 31,
Oil contracts	2015		2015		2016		2016		2016		2016
Swap contracts (NYMEX):
Total volume (MBbls)		520		442		91		91		92		92
Weighted average price per Bbl	$	67.22	$	64.93	$	63.50	$	63.50	$	63.50	$	63.50
Swap contracts (Midland basis
differential):
Volume (MBbls)		382		327		—		—		—		—
Weighted average price per Bbl	$	(2.39)	$	(2.38)	$	—	$	—	$	—	$	—
Collar contracts combined with
short puts (three-way collar):
Volume (MBbls)		—		—		91		91		92		92
Weighted average price per Bbl
Ceiling (short call)	$	—	$	—	$	70.00	$	70.00	$	70.00	$	70.00
Floor (long put)	$	—	$	—	$	60.00	$	60.00	$	60.00	$	60.00
Short put	$	—	$	—	$	45.00	$	45.00	$	45.00	$	45.00


	For the Three Months Ended
	September 30,		December 31,		March 31,		June 30,		September 30,		December 31,
Natural gas contracts	2015		2015		2016		2016		2016		2016
Collar contracts combined with
short puts (three-way collar):
Volume (BBtu)		207		161		—		—		—		—
Weighted average price per
MMBtu
Ceiling (short call)	$	4.32	$	4.32	$	—	$	—	$	—	$	—
Floor (long put)	$	3.85	$	3.85	$	—	$	—	$	—	$	—
Short put	$	3.25	$	3.25	$	—	$	—	$	—	$	—
Swap contracts:
Total volume (BBtu)		219		228		—		—		—		—
Weighted average price per
MMBtu	$	3.98	$	3.96	$	—	$	—	$	—	$	—
Short call contracts:
Short call volume (BBtu)		110		111		—		—		—		—
Short call price per MMBtu	$	5.00	$	5.00	$	—	$	—	$	—	$	—

Note 6 - Fair Value Measurements

The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.

Fair Value of Financial Instruments

Cash, cash equivalents, 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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Assets and liabilities measured at fair value on a recurring basis

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

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


Balance Sheet Presentation as of June 30, 2015	Classification		Level 1		Level 2		Level 3		Total
Fair value of derivatives	Current assets	$	—	$	6,889	$	—	$	6,889
Other assets, net	Long-term assets		—		205		—		205
Fair value of derivatives	Current liabilities		—		(1,622)		—		(1,622)
Total net assets		$	—	$	5,472	$	—	$	5,472

Balance Sheet Presentation as of December 31, 2014	Classification		Level 1		Level 2		Level 3		Total
Fair value of derivatives	Current assets	$	—	$	27,850	$	—	$	27,850
Fair value of derivatives	Current liabilities		—		(1,249)		—		(1,249)
Total net assets		$	—	$	26,601	$	—	$	26,601

Note 7 - Asset Retirement Obligations

The table below summarizes the Company’s asset retirement obligations activity for the six months ended June 30, 2015:


Asset retirement obligations at January 1, 2015	$	6,674
Accretion expense		343
Liabilities incurred		88
Liabilities settled		(2,533)
Revisions to estimate		(451)
Asset retirement obligations at end of period		4,121
Less: Current asset retirement obligations		(872)
Long-term asset retirement obligations at June 30, 2015	$	3,249

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheets at June 30, 2015 as long-term restricted investments were $3,299. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.

Note 8 – Equity Transactions

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

Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $1,973 and $3,947 for the three and six months ended June 30, 2015 and 2014, 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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The Preferred Stock has no stated maturity and is not be subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share in cash, plus any accrued and unpaid dividends to the redemption date.

Following a change of control, as defined in the prospectus supplement, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon a change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on June 30, 2015, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $8.32 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 6.0 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.

Common Stock

On March 13, 2015, the Company completed an underwritten public offering of 9,000,000 shares of its common stock at $6.55 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,350,000 additional shares of common stock at $6.55 per share, before underwriting discounts. The Company received net proceeds of approximately $65,546, after the underwriting discounts and estimated offering costs.

Note 9 – Other

Operating leases

As of June 30, 2015, the Company had contracts for two horizontal drilling rigs (the “Cactus 1 Rig” and “Cactus 2 Rig”). The Cactus 1 Rig was initially contracted for a term of two years in April 2012. The Cactus 2 Rig was initially contracted for a term of two years in April 2014. The Cactus 2 Rig replaced a previously contracted horizontal drilling rig, which was cancelled in March 2014. In March 2015, the Company extended the terms of its Cactus 1 Rig and Cactus 2 Rig to end in July 2018 and August 2018, respectively. The rig lease agreements include early termination provisions that obligate the Company to reduced minimum rentals pursuant to a “standby” dayrate for the term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee.

In March 2015, the Company decided to terminate its one-year contract for a vertical rig (effective April 2015) and will be required to pay approximately $3,641 in reduced rental payments over the remainder of the lease term ending November 2015, unless the lessor is able to re-charter the rig to another lessee. This amount was recognized as rig termination fee on the consolidated statements of operations for the three and six months ended June 30, 2015. As of June 30, 2015, the Company had paid $1,392 of the estimated $3,641 in reduced rental payments.

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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 SEC.

We caution you that the forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014 (the “2014 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 2014 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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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our 2014 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 operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity to date has been predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Lower Spraberry. 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 81% oil and 19% natural gas for the six months ended June 30, 2015. On June 30, 2015, our acreage position in the Permian Basin was approximately 18,225 net acres. The Company no longer holds an acreage position in the Northern Midland Basin after selling 40 gross and net acres around a producing well and releasing all remaining undeveloped acreage in the Northern Midland Basin in 2015.

Operational Highlights

Our production grew 80% and 88% for the three and six months ended June 30, 2015, respectively, compared to the same periods of 2014, increasing to 866 MBOE from 480 MBOE and 1,637 MBOE from 873 MBOE for the comparative three and six months periods, respectively.


	Net Production (MBOE)
	Three Months Ended June 30,
	2015	2014	Change	% Change
Southern Midland Basin	543	372	171	46%
Central Midland Basin	323	103	220	214%
Northern Midland Basin	—	5	(5)	(100)%
Total	866	480	386	80%


	Net Production (MBOE)
	Six Months Ended June 30,
	2015	2014	Change	% Change
Southern Midland Basin	988	688	300	44%
Central Midland Basin	648	174	474	272%
Northern Midland Basin	1	11	(10)	(91)%
Total	1,637	873	764	88%

The following table sets forth productive wells as of June 30, 2015:


	Oil Wells		Natural Gas Wells
	Gross	Net	Gross	Net
Working interest	343	255.1	—	—
Royalty interest	3	0.1	—	—
Total	346	255.2	—	—

A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas.

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The following table summarizes the Company’s drilling activity in the Permian Basin for periods indicated:


	For the Three Months Ended June 30, 2015
	Drilled		Completed (a)		Awaiting Completion
	Gross	Net	Gross	Net	Gross	Net
Southern Midland Basin
Horizontal wells	5	5.0	5	5.0	2	2.0
Total	5	5.0	5	5.0	2	2.0
Central Midland Basin
Vertical wells	—	—	—	—	—	—
Horizontal wells	4	2.6	3	2.0	2	1.3
Total	4	2.6	3	2.0	2	1.3

Total vertical wells	—	—	—	—	—	—
Total horizontal wells	9	7.6	8	7.0	4	3.3
Total	9	7.6	8	7.0	4	3.3

(a)

Completions include wells drilled prior to the second quarter of 2015.


	For the Six Months Ended June 30, 2015
	Drilled		Completed (a)		Awaiting Completion
	Gross	Net	Gross	Net	Gross	Net
Southern Midland Basin
Horizontal wells	11	10.8	12	11.8	2	2.0
Total	11	10.8	12	11.8	2	2.0
Central Midland Basin
Vertical wells	—	—	1	0.4	—	—
Horizontal wells	8	4.6	6	3.3	2	1.3
Total	8	4.6	7	3.7	2	1.3

Total vertical wells	—	—	1	0.4	—	—
Total horizontal wells	19	15.4	18	15.1	4	3.3
Total	19	15.4	19	15.5	4	3.3

(a)

Completions include wells drilled prior to 2015.

Liquidity and Capital Resources

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. We recently completed a common stock offering to raise additional capital, and we continue to evaluate other sources of capital to complement our cash flows from operations as we pursue our long-term growth plan in the Permian Basin.

Based upon current commodity price expectations for 2015, we believe that our cash flow from operations, proceeds from our March 2015 equity offering and borrowings under our Credit Facility and Term Loan will be sufficient to fund our operations for 2015, including working capital requirements. However, future cash flows are subject to a number of variables, including forecasted production volumes and commodity prices. We are the operator for 100% of our remaining 2015 capital program and, as a result, the amount and timing of a substantial portion of our planned capital expenditures is largely discretionary. Accordingly, we may determine it prudent to curtail drilling and completion operations due to capital constraints or reduced returns on investment as a result of commodity price weakness.

Cash and cash equivalents increased $1.1 million in the six months ended June 30, 2015 to $2.0 million compared to $0.9 million at December 31, 2014.

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Liquidity and cash flow


	Six Months Ended June 30,
(dollars in millions)	2015		2014
Net cash provided by operating activities	$	30.0	$	35.6
Net cash used in investing activities		(130.5)		(125.0)
Net cash provided by financing activities		101.6		87.5
Net change in cash	$	1.1	$	(1.9)

Operating activities. For the six months ended June 30, 2015, net cash provided by operating activities was $30.0 million compared to net cash provided by operating activities of $35.6 million for the same period in 2014. The decrease was predominantly attributable to a decline in oil revenues precipitated by a depressed commodity environment, offset by gains on the settlement of derivative contracts and an 80% increase in oil production. Also contributing to the decrease were increases in lease operating expenses, production taxes, interest expense, nonrecurring early retirement expenses, and payments on cash-settleable restricted stock unit awards. Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 5 and 6 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.

Investing activities. For the six months ended June 30, 2015, net cash used in investing activities was $130.5 million compared to $125.0 million for the same period in 2014. The $5.5 million increase in cash used in investing activities was primarily attributable to a $10.8 million increase in capital expenditures, driven by the addition of the vertical rig to our drilling program in August 2014. The increase in capital expenditures was offset by a $7.2 million decrease in acquisition costs relative to the prior period. Also offsetting the increase was a $1.9 million reduction of proceeds resulting from the sale of mineral interests and equipment.

Capital expenditures for the six months ended June 30, 2015 include the following (in millions):


Southern Midland Basin	$	85.9
Central Midland Basin		32.1
Total operational expenditures		118.0

Capitalized general and administrative costs allocated directly to exploration and development projects		5.3
Capitalized interest		5.7
Total capitalized general and administrative and interest costs		11.0

Total operational expenditures inclusive of capitalized general and administrative and interest costs		129.0

Acquisitions		1.8
Total capital expenditures	$	130.8

Financing activities. For the six months ended June 30, 2015, net cash provided by financing activities was $101.6 million compared to cash provided by financing activities of $87.5 million during the same period of 2014. Net cash provided by financing activities during the six months ended June 30, 2015 included $65.5 million of net proceeds from the issuance of common stock and a net $40.0 million of borrowings on our Credit Facility. In addition, the Company paid approximately $3.9 million in preferred stock dividends. See Note 8 in the Footnotes to the Financial Statements for additional information about the Company’s equity offering.

2015 capital expenditures

In early February 2015, we announced an operational capital budget for 2015 in the range of $150 to $165 million, on an accrual basis. The Company subsequently updated its operational capital guidance to $160 million to $165 million, which reflects a higher level of capital cost reductions realized to date, offset by greater than expected reduction in drilling and completion cycle times and the Company’s expected funding of non-consenting partners during the year. Operational capital expenditures on an accrual basis were $102.4 million for the six months ended June 30, 2015.

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We expect our 2015 horizontal drilling program will be primarily focused on program development of established Upper and Lower Wolfcamp B zones and the Lower Spraberry zones, in both the Southern and Central Midland Basin with lateral lengths ranging from approximately 5,000 feet to 10,000 feet.

In addition to the operational capital expenditures above, we budgeted a total of $17.2 million for (i) capitalized general and administrative costs and (ii) certain retained plugging and abandonment costs related to divested Gulf of Mexico shelf assets.

We are the operator for 100% of our remaining 2015 capital program and, as a result, the amount and timing of these capital expenditures are largely discretionary depending on commodity prices and other factors. We currently expect to fund our 2015 capital program through a combination of the net proceeds from the issuance of common stock discussed above, cash flow from operations and borrowings under our Credit Facility and Term Loan.

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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,
		2015		2014		Change	% Change
Net production:
Oil (MBbls)		685		405		280	69%
Natural gas (MMcf)		1,084		452		632	140%
Total (MBOE)		866		480		386	80%
Average daily production (BOE/d)		9,516		5,275		4,242	80%
% oil (BOE basis)		79%		84%
Average realized sales price:
Oil (Bbl) (excluding impact of cash settled derivatives)	$	52.69	$	93.11	$	(40.42)	(43)%
Oil (Bbl) (including impact of cash settled derivatives)		59.28		89.24		(29.96)	(34)%
Natural gas (Mcf) (excluding impact of cash settled derivatives)	$	2.90	$	6.18	$	(3.28)	(53)%
Natural gas (Mcf) (including impact of cash settled derivatives)		3.32		6.01		(2.69)	(45)%
Total (BOE) (excluding impact of cash settled derivatives)	$	45.31	$	84.38	$	(39.07)	(46)%
Total (BOE) (including impact of cash settled derivatives)		51.05		80.95		(29.90)	(37)%
Oil and natural gas revenues (in thousands):
Oil revenue	$	36,093	$	37,710	$	(1,617)	(4)%
Natural gas revenue		3,149		2,792		357	13%
Total	$	39,242	$	40,502	$	(1,260)	(3)%
Additional per BOE data:
Sales price (excluding impact of cash settled derivatives)	$	45.31	$	84.38	$	(39.07)	(46)%
Lease operating expense		7.59		9.09		(1.50)	(17)%
Production taxes		3.41		4.72		(1.31)	(28)%
Operating margin	$	34.31	$	70.57	$	(36.26)	(51)%


		Six Months Ended June 30,
		2015		2014		Change	% Change
Net production:
Oil (MBbls)		1,323		737		586	80%
Natural gas (MMcf)		1,885		816		1,069	131%
Total (MBOE)		1,637		873		764	88%
Average daily production (BOE/d)		9,044		4,823		4,221	88%
% oil (BOE basis)		81%		84%
Average realized sales price:
Oil (Bbl) (excluding impact of cash settled derivatives)	$	48.38	$	93.11	$	(44.73)	(48)%
Oil (Bbl) (including impact of cash settled derivatives)		59.31		89.93		(30.62)	(34)%
Natural gas (Mcf) (excluding impact of cash settled derivatives)	$	2.99	$	6.33	$	(3.34)	(53)%
Natural gas (Mcf) (including impact of cash settled derivatives)		3.44		6.11		(2.67)	(44)%
Total (BOE) (excluding impact of cash settled derivatives)	$	42.54	$	84.52	$	(41.98)	(50)%
Total (BOE) (including impact of cash settled derivatives)		51.89		81.63		(29.74)	(36)%
Oil and natural gas revenues (in thousands):
Oil revenue	$	64,002	$	68,619	$	(4,617)	(7)%
Natural gas revenue		5,631		5,168		463	9%
Total	$	69,633	$	73,787	$	(4,154)	(6)%
Additional per BOE data:
Sales price (excluding impact of cash settled derivatives)	$	42.54	$	84.52	$	(41.98)	(50)%
Lease operating expense		8.27		9.84		(1.57)	(16)%
Production taxes		3.19		4.79		(1.60)	(33)%
Operating margin	$	31.08	$	69.89	$	(38.81)	(56)%

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Revenues

The following table is 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, 2014	$	37,710	$	2,792	$	40,502
Volume increase		26,113		3,895		30,008
Price decrease		(27,730)		(3,538)		(31,268)
Net increase (decrease)		(1,617)		357		(1,260)
Revenues for the three months ended June 30, 2015	$	36,093	$	3,149	$	39,242


(in thousands)	Oil		Natural Gas		Total
Revenues for the six months ended June 30, 2014	$	68,619	$	5,168	$	73,787
Volume increase (decrease)		54,604		6,778		61,382
Price increase (decrease)		(59,221)		(6,315)		(65,536)
Net increase (decrease)		(4,617)		463		(4,154)
Revenues for the six months ended June 30, 2015	$	64,002	$	5,631	$	69,633

Oil revenue

For the quarter ended June 30, 2015, oil revenues of $36.1 million decreased $1.6 million, or 4%, compared to revenues of $37.7 million for the same period of 2014. The decrease in oil revenue was primarily attributable to a 43% decrease in the average realized sales price offset by a 69% increase in production. The increase in production was primarily attributable to increased production from our Permian properties resulting from an increased number of producing wells from acquisitions and our horizontal drilling program, offset by normal and expected declines from our existing wells.

For the six months ended June 30, 2015, oil revenues of $64.0 million decreased $4.6 million, or 7%, compared to revenues of $68.6 million for the same period of 2014. The decrease in oil revenue was primarily attributable to a 48% decrease in the average realized sales price offset by an 80% increase in production. The increase in production was primarily attributable to increased production from our Permian properties resulting from an increased number of producing wells from acquisitions and our horizontal drilling program, offset by normal and expected declines from our existing wells.

Natural gas revenue (including NGLs)

Natural gas revenues of $3.1 million increased $0.3 million, or 13%, during the three months ended June 30, 2015 compared to $2.8 million for the same period of 2014. The increase primarily relates to a 140% increase in natural gas volumes and was predominantly offset by a 53% decrease in the average price realized, which fell to $2.90 per Mcf from $6.18 per Mcf, reflecting decreases in both natural gas and natural gas liquids prices. The increase in production was primarily attributable to increased production from our Permian properties resulting from an increased number of producing wells as mentioned above.

Natural gas revenues of $5.6 million increased $0.4 million, or 9%, during the six months ended June 30, 2015 compared to $5.2 million for the same period of 2014. The increase primarily relates to a 131% increase in natural gas volumes and was predominantly offset by a 53% decrease in the average price realized, which fell to $2.99 per Mcf from $6.33 per Mcf, reflecting decreases in both natural gas and natural gas liquids prices. The increase in production was primarily attributable to increased production from our Permian properties resulting from an increased number of producing wells as mentioned above.

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Operating Expenses


(in thousands, except per unit amounts)	Three Months Ended June 30,
			Per				Per		Total Change		BOE Change
	2015		BOE		2014		BOE		$	%	$	%
Lease operating expenses	$	6,575	$	7.59	$	4,363	$	9.09	2,212	51%	(1.50)	(17)%
Production taxes		2,952		3.41		2,265		4.72	687	30%	(1.31)	(28)%
Depreciation, depletion and amortization		17,587		20.31		11,982		24.96	5,605	47%	(4.65)	(19)%
General and administrative		5,763		6.65		9,639		20.08	(3,876)	(40)%	(13.43)	(67)%
Accretion expense		134		0.15		173		0.36	(39)	(23)%	(0.21)	(58)%


	Six Months Ended June 30,
			Per				Per		Total Change		BOE Change
	2015		BOE		2014		BOE		$	%	$	%
Lease operating expenses	$	13,534	$	8.27	$	8,593	$	9.84	4,941	58%	(1.57)	(16)%
Production taxes		5,217		3.19		4,182		4.79	1,035	25%	(1.60)	(33)%
Depreciation, depletion and amortization		35,691		21.80		22,520		25.80	13,171	58%	(4.00)	(16)%
General and administrative		17,865		10.91		20,446		23.42	(2,581)	(13)%	(12.51)	(53)%
Accretion expense		343		0.21		401		0.46	(58)	(14)%	(0.25)	(54)%
Rig termination fee		3,641		nm		—		—	3,641	nm	nm	nm
Gain on sale of other property and equipment		—		—		(1,080)		nm	1,080	nm	nm	nm

*nm = not meaningful

Lease operating expenses (“LOE”). These are daily costs incurred to extract oil and natural gas out of the ground, 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.

LOE for the three months ended June 30, 2015 increased by 51% to $6.6 million compared to $4.4 million for the same period of 2014 primarily due to the growth in Permian production and operations as a result of our acquisition efforts and horizontal drilling program. LOE per BOE was $7.59 for the three months ended June 30, 2015, compared to LOE of $9.09 per BOE for the same period of 2014. Higher production volumes contributed to the 17% per BOE decrease for the three months ended June 30, 2015.

LOE for the six months ended June 30, 2015 increased by 58% to $13.5 million compared to $8.6 million for the same period of 2014 primarily due to the growth in Permian production and operations as a result of our acquisition efforts and horizontal drilling program. LOE per BOE was $8.27 for the six months ended June 30, 2015, compared to LOE of $9.84 per BOE for the same period of 2014. Higher production volumes contributed to the 16% per BOE decrease for the six months ended June 30, 2015.

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

Production taxes for the three months ended June 30, 2015 increased by 30% to $3.0 million compared to $2.3 million for the same period of 2014. The increase was primarily due to an increase in ad valorem taxes attributable to a greater number of producing wells as a result of our acquisition efforts and horizontal drilling program. Offsetting this increase was a reduction in severance taxes as a result of the decline of oil and natural gas revenues as previously mentioned. On a per BOE basis, production taxes for the three months ended June 30, 2015 decreased by 28% compared to the same period of 2014.

Production taxes for the six months ended, June 30, 2015 increased by 25% to $5.2 million compared to $4.2 million for the same period of 2014. The increase was primarily due to an increase in ad valorem taxes attributable to a greater number of producing wells as a result of our acquisition efforts and horizontal drilling program. Offsetting this increase was a reduction in severance taxes as a

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result of the decline of oil and natural gas revenues as previously mentioned. On a per BOE basis, production taxes for the six months ended, June 30, 2015 decreased by 33% compared to the same period of 2014.

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

For the three and six months ended June 30, 2015, DD&A increased 47% to $17.6 million and 58% to $35.7 million, respectively, over the comparative periods of 2014. These increases are primarily due to production increases of 80% and 88% for the respective periods as previously discussed. For the three months ended June 30, 2015, DD&A decreased 19% per BOE to $20.31 per BOE compared to $24.96 per BOE for the same period of 2014. Similarly, for the six months ended June 30, 2015, DD&A decreased 16% per BOE to $21.80 per BOE compared to $25.80 per BOE for the same period of 2014. The decreases for both periods are attributable to our increased estimated proved reserves relative to our depreciable asset base.

General and administrative, net of amounts capitalized (“G&A”). 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, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance.

G&A for the three months ended June 30, 2015 decreased to $5.8 million compared to $9.6 million for the same period of 2014. G&A expenses for the periods indicated include the following (in millions):


	For the Three Months Ended June 30,
	2015		2014		$ Change		% Change
Recurring expenses
G&A	$	3.5	$	4.1	$	(0.6)	(15)%
Share-based compensation		0.5		0.8		(0.3)	(38)%
Fair value adjustments of cash-settled RSU awards		1.6		4.6		(3.0)	(65)%
Non-recurring expenses
Expense related to a threatened proxy contest		0.2		0.1		0.1	100%
Total G&A expenses	$	5.8	$	9.6	$	(3.8)	(40)%

G&A for the six months ended, June 30, 2015 decreased to $17.9 million compared to $20.4 million for the same period of 2014. G&A expenses for the periods indicated include the following (in millions):


	For the Six Months Ended June 30,
	2015		2014		$ Change		% Change
Recurring expenses
G&A	$	7.7	$	8.1	$	(0.4)	(5)%
Share-based compensation		1.0		1.3		(0.3)	(23)%
Fair value adjustments of cash-settled RSU awards		4.2		7.2		(3.0)	(42)%
Non-recurring expenses
Early retirement expenses		3.6		1.4		2.2	157%
Early retirement expenses related to share-based compensation		1.1		1.1		—	—%
Expense related to a threatened proxy contest		0.3		1.3		(1.0)	(77)%
Total G&A expenses	$	17.9	$	20.4	$	(2.5)	(12)%

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 ARO and reported as accretion expense within operating expenses in the consolidated statements of operations.

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Accretion expense related to our ARO decreased 23% and 14% for the three and six months ended June 30, 2015, respectively, compared to the same periods of 2014. Accretion expense generally correlates with the Company’s ARO, which was $4.1 million at June 30, 2015 as compared to $5.6 million at June 30, 2014. See Note 7 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO.

Rig termination fee. During the first quarter of 2015, the Company recognized $3.6 million in expense related to the early termination of the contract for its vertical rig. See Note 9 in the Footnotes to the Financial Statements for additional information.

Gain on sale of other property and equipment. During 2014, the Company entered into an agreement to sell certain specialized deep water equipment that resulted in a gain on the sale of other property and equipment of $1.1 million.

Other Income and Expenses and Preferred Stock Dividends


(in thousands)	Three Months Ended June 30,
	2015		2014			$ Change	% Change
Interest expense	$	5,106	$	1,825	$	3,281	180%
Gain on early extinguishment of debt		—		(3,205)		3,205	(100)%
Loss on derivative contracts		8,249		4,685		3,564	76%
Other income		(41)		(93)		52	(56)%
Total	$	13,314	$	3,212

Income tax expense (benefit)	$	(2,116)	$	4,128	$	(6,244)	(151)%
Preferred stock dividends		(1,973)		(1,973)		—	—


	Six Months Ended June 30,
	2015		2014			$ Change	% Change
Interest expense	$	9,964	$	2,802	$	7,162	256%
Gain on early extinguishment of debt		—		(3,205)		3,205	(100)%
Loss on derivative contracts		5,820		7,198		(1,378)	(19)%
Other income, net		(85)		(142)		57	(40)%
Total	$	15,699	$	6,653

Income tax expense (benefit)	$	(7,193)	$	5,469	$	(12,662)	(232)%
Preferred stock dividends		(3,947)		(3,947)		—	—%

Interest expense. Interest expense incurred during the three months ended June 30, 2015 increased $3.3 million compared to the same period of 2014. The increase is primarily attributable to $5.6 million in expense related to a higher outstanding debt balance in 2015 compared to the corresponding period of the prior year. Offsetting the increase is a $2.2 million increase in capitalized interest compared to the 2014 period, resulting from a higher average unevaluated property balance for the three months ended, June 30, 2015 as compared to the same period of 2014, and a $0.1 million decrease in interest expense related to the full redemption of our Senior Notes in April 2014.

Interest expense incurred during the six months ended June 30, 2015 increased $7.2 million compared to the same period of 2014. The increase is primarily attributable to $12.9 million in expense related to a higher outstanding debt balance in 2015 compared to the corresponding period of the prior year. Offsetting the increase is a $4.4 million increase in capitalized interest compared to the 2014 period, resulting from a higher average unevaluated property balance for the six months ended, June 30, 2015 as compared to the same period of 2014, and a $1.3 million decrease in interest expense related to the full redemption of our Senior Notes in April 2014.

Gain on early extinguishment of debt. During April 2014, the Company completed a full redemption of the remaining $53.3 million carrying value of its outstanding Senior Notes. The carrying value included $48.5 million of principal value and $4.8 million of unamortized deferred credit. The Company recognized a net $3.2 million gain on early extinguishment of debt, comprised of the recognition of $4.8 million in deferred credit, offset by $1.6 million of redemption expenses.

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Loss on derivative contracts. For the three and six months ended June 30, 2015, the net loss on derivative contracts was $8.2 million and $5.8 million, respectively, compared to a $4.7 million and $7.2 million net loss for the same periods of 2014, respectively. See Note 5 and 6 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.

Income tax expense (benefit). The Company had an income tax benefit of $2.1 million for the three months ended June 30, 2015 compared to an income tax expense of $4.1 million for the same period of 2014. Similarly, the Company had an income tax benefit of $7.2 million for the six months ended June 30, 2015 compared to an income tax expense of $5.5 million for the same period of 2014. The change in income tax expense (benefit) is primarily related to the difference in the amount of income (loss) before income taxes between periods.

Preferred Stock dividends. Preferred Stock dividends for the three and six months ended June 30, 2015 were consistent with the same periods of 2014. Dividends reflect a 10% dividend rate and $78.9 million liquidation value. See Note 8 in the Footnotes to the Financial Statements for additional information.

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, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices, in addition to modification of our capital spending plans related to operational activities and acquisitions.

As of July 31, 2015, we had commodity contracts covering approximately 65% and 40% of our expected oil and natural gas production, respectively, for the combined third and fourth quarters of 2015, based on the midpoint of publicly disclosed guidance as of August 5, 2015. Our actual production will vary from the amounts estimated, perhaps materially. See Note 5 in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at June 30, 2015 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.

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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.

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

Interest rate risk

On June 30, 2015, the Company’s debt consisted of $300.0 million related to its Term Loan and $75.0 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 Term Loan and Credit Facility. As of June 30, 2015, the weighted average interest rate on our Credit Facility borrowings was 2.19% and the interest rate on our Term Loan borrowings was 8.50%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $3.8 million based on the $375.0 million outstanding in the aggregate under the two facilities on June 30, 2015. The Company is also subject to market risk exposure related to changes in the underlying LIBOR-based interest rate used for the Term Loan to the extent that available LIBOR election options exceed the 1.0% floor rate. See Note 4 to the Consolidated Financial Statements for more information on the Company’s interest rates on debt.

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, 2015 our receivables from the sale of our oil and natural gas production were approximately $25.6 million.

Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At June 30, 2015 our joint interest receivables were approximately $6.6 million.

The Company’s oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional derivative instruments with these or other lenders under our Credit Facility, representing institutions with 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

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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, 2015.

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.

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 2014 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 (a)		Certificate of Incorporation of the Company, as amended through May 14, 2015

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)

10. Material Contracts


10.1		First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed on May 18, 2015)

31. Section 13a-14 Certifications


31.1 (a)		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 (a)		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32. Section 1350 Certifications


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

101. (c) Interactive Data Files

(a)

Filed herewith.

(b)

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

(c)

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

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SIGNATURES

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


	Callon Petroleum Company

Signature	Title	Date

/s/ Fred L. Callon	President and Chief Executive Officer	August 5, 2015
Fred L. Callon

/s/ Joseph C. Gatto, Jr.	Senior Vice President,	August 5, 2015
Joseph C. Gatto, Jr.	Chief Financial Officer and Treasurer