UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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

For The Quarterly Period Ended June 30, 2016

OR

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

For the transition period from ____________ to ____________

Commission File Number 001-14039





Callon Petroleum Company

(Exact Name of Registrant as Specified in Its Charter)







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 the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):





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  131,136,233 shares of common stock outstanding as of August 1, 2016.



 

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Table of Contents



 

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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:





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)



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)









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)





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









 

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INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





Note 1 - Description of Business and Basis of Presentation



Description of business



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



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



Basis of presentation



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



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



These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2015. The balance sheet at December 31, 2015 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, 2016.



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

 

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Recently issued accounting policies



In March 2016, the Financial Accounting Standards Board issued accounting standards update No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. The Company is currently evaluating the method of adoption and impact this standard may have on its financial statements and related disclosures.



Recently adopted accounting policies



In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which eliminates the current requirement to present deferred tax liabilities and assets as current and noncurrent amounts on the balance sheet. Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent on the balance sheet. The guidance in ASU 2015-17 is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted. As of June 30, 2016, the Company adopted this ASU, which does not have a material impact on its financial statements.



Note 2 – Oil and Natural Gas Properties



The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar 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). 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. At June 30, 2016, the prices used in determining the estimated future net cash flows from proved reserves were $40.62 per barrel of oil and $2.46 per Mcf of natural gas. For the three and six months ended June 30, 2016, the Company recognized write-downs of oil and natural gas properties of $61,012 and $95,788, respectively, as a result of the ceiling test limitation.



Note 3 - Acquisitions 



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



2016 acquisitions



On May 26, 2016, the Company completed the acquisition of 17,298 gross (14,089 net) acres primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9,333,333 shares of common stock for a total purchase price of $329,573,  excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an 81% average working interest (61% average net revenue interest) in the properties acquired in the Big Star Transaction.



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The preliminary purchase price allocation is subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material. The following table summarizes the estimated acquisition date fair values of the net assets to be acquired in the acquisition (in thousands):







The following unaudited summary pro forma financial information for the three and six months ended June 30, 2016 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 Big Star Transaction 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 Big Star Transaction occurred as of January 1, 2015. The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including those pertaining to revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest. 





From the date of the acquisition through the period ended June 30, 2016, the properties associated with the Big Star Transaction have been comingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.



On May 16, 2016, the Company completed the following transactions (collectively, the “AMI Transaction”) for an aggregate cash purchase price of $33,012,  excluding customary purchase price adjustments. Key elements of the AMI Transaction include:





The following table summarizes the acquisition date fair values of the net assets acquired, including customary purchase price adjustments: 







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On January 18, 2016, the Company completed the acquisition of an additional 4.9% working interest (3.7% net revenue interest) in the Casselman-Bohannon fields for an aggregate cash purchase price of $10,183,  including customary purchase price adjustments. Following the completion of this acquisition the Company owned 71.3% working interest (53.5% net revenue interest) in the Casselman-Bohannon fields. The following table summarizes the acquisition date fair values of the net assets acquired, including customary purchase price adjustments:







Subsequent event



On August 3, 2016, the Company entered into a definitive purchase and sale agreement for the acquisition of an additional 4.0% working interest (3.0% net revenue interest) in the Casselman-Bohannon fields for total cash consideration of  $13,000, excluding customary purchase price adjustments, with an effective date of August 1, 2016. Following the completion of this acquisition the Company will own approximately 75.3% working interest (58.5% net revenue interest) in the Casselman-Bohannon fields.







Note 4 - Earnings Per Share



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











 

Note 5 - Borrowings



The Company’s borrowings consisted of the following at:





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



On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of March 11, 2019.  JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include several institutional lenders. The total notional amount available under the Credit Facility is $500,000. Amounts borrowed under the Credit Facility may

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not exceed the borrowing base, which is generally reviewed on a semi-annual basis. As of June 30, 2016,  the Credit Facility’s borrowing base was $300,000. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. 

 

As of June 30, 2016, there was  a $40,000 balance outstanding on the Credit Facility. For the quarter ended June 30, 2016, the Credit Facility had a weighted-average interest rate of 2.21%, 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.



Effective July 13, 2016, the Credit Facility’s borrowing base was increased to $385,000 and the Company’s capacity to hedge oil and natural gas volumes was effectively increased with a change in the capacity calculation to a percentage of total proved reserves from proved producing reserves. In addition, the interest rate for borrowings under the Credit Facility was increased 0.25% across all tiers of the pricing grid, resulting in a range of interest costs equal to LIBOR plus 2.00% to 3.00%. There were no modifications to other terms or covenants of the Credit Facility.



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 (i) is 102% if the prepayment event occurs prior to October 8, 2016, (ii) 101% if the prepayment event occurs on or after October 8, 2016 but before October 8, 2017, and (iii) is 100% for prepayments made on or after October 8, 2017. The Term Loan is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement.



As of June 30, 2016, the balance outstanding on 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 2016.



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, 2016.



Note 6 - Derivative Instruments and Hedging Activities



Objectives and strategies for using derivative instruments



The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, 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 7 for additional information regarding fair value.



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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 7 for additional information regarding fair value.



Derivatives not designated as hedging instruments



The Company records its derivative contracts at fair value in the consolidated balance sheets and records changes in fair value as a gain or loss on derivative contracts in the consolidated statements of operations. Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statements of operations.



The following table reflects the fair value of the Company’s derivative instruments for the periods presented:



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:









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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:



Derivative positions



Listed in the tables below are the outstanding oil and natural gas derivative contracts as of June 30, 2016:  





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Subsequent event



The following derivative contract was executed subsequent to June 30, 2016:















Note 7 - Fair Value Measurements



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



Fair value of financial instruments



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



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

 

Assets and liabilities measured at fair value on a recurring basis



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



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



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



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Assets and liabilities measured at fair value on a nonrecurring basis



Acquisitions.  As discussed in Note 3, the Company completed three acquisitions during the six months ended June 30, 2016. The Company determined the fair value of the assets acquired using the income approach based on expected future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and gas forward prices. The fair value measurements were based on level 2 and level 3 inputs.



Note 8 - Income Taxes



The Company typically 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. As a result of the write-down of oil and natural gas properties in the latter part of 2015 the Company incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was $147,540 as of June 30, 2016.



Note 9 - Asset Retirement Obligations



The table below summarizes the Company’s asset retirement obligations activity for the six months ended June 30, 2016:  



Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at June 30, 2016 as long-term restricted investments were $3,323. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs.



Note 10 - 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 $1,823 and  $1,973  for the three months ended June 30, 2016 and 2015, respectively, and $3,647 and $3,947 for the six months ended June 30, 2016 and 2015, respectively.



The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share in cash, plus any accrued and unpaid dividends to the redemption date.



Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon such change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into

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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, 2016, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $11.23 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 4.5 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.



On February 4, 2016,  the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of June 30, 2016, the Company had 1,458,948 shares of its Preferred Stock issued and outstanding.



Common stock  



On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs)  of approximately $94,973. 



On April 25, 2016, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,874. Proceeds from the offering were used to fund the May 2016 acquisitions described in Note 3.



On May 26, 2016, the Company issued 9,333,333 shares of common stock to partially fund the Big Star Transaction, described in Note 3, at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date.



Note 11 - Other



Operating leases



As of June 30, 2016, the Company had contracts for two horizontal drilling rigs (the “Cactus 1 Rig” and “Cactus 2 Rig”). The contract terms of the Cactus 1 Rig and Cactus 2 Rig will end in July 2018 and August 2018, respectively. The rig lease agreements include early termination provisions that obligate the Company to pay reduced minimum rentals for the remaining term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee. In January 2016, the Company decided to place its Cactus 1 Rig on standby and is required to pay a “standby” day rate of $15,000 per day, pursuant to the terms of the agreement,  allowing the Company to retain the option to return the rig to service under the contract terms.



 



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Special Note Regarding Forward Looking Statements



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



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