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 March 31, 2015

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 definition 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’s had  65,871,037  shares of common stock outstanding as of April 30, 2015.

 

 

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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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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

 

 

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.

 

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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 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:

 

 

The following unaudited summary pro forma financial information for the three months ended March 31, 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. 

 

 

 

 

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Note 3 - Earnings Per Share

 

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

 

 

 

 

Note 4 – 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 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 March 31, 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 March 31, 2015, the balance outstanding on the Credit Facility was $37,000 with a weighted-average interest rate of 1.98%, 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, and (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 March 31, 2015, 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% 

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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 April 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 March 31, 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.

 

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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:

 

 

 

 

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:

 

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Derivative positions

 

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of March 31, 2015:

 

 

 

 

 

Subsequent Event

 

The following derivative contracts were executed subsequent to March 31, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

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Note 6 - Fair Value Measurements 

 

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

 

Fair Value of Financial Instruments

 

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

 

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

 

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:

 

 

 

Note 7 - Asset Retirement Obligations 

 

The table below summarizes the Company’s asset retirement obligations activity for the three months ended March 31, 2015:

 

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheets at March 31, 2015 as long-term restricted investments were $3,292. These assets, which primarily include

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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 $1,974 for the three months ended March 31, 2015 and 2014.

 

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, plus any accrued and unpaid dividends to the redemption date.

 

Following a change of control, 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 March 31, 2015, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of ($7.47) as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 6.7 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 March 31, 2015, the Company had contracts for two horizontal drilling rigs (the “Cactus 1 Rig” and “Cactus 2 Rig”) and one vertical rig. The horizontal rigs were initially contracted for a term of two years in April 2012, the terms of which were subsequently renewed 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 vertical drilling rig was initially contracted for a term of one year with an expiration of November 2015 to be used as part of our horizontal drilling program, drilling the vertical section of horizontal wells. 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 the 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 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 Income for the three months ended March 31, 2015.

 

 

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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: 

 

 

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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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 operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through acreage purchases, joint ventures and asset swaps. Our production was approximately 83% oil and 17% natural gas for the  three months ended March 31, 2015. On March 31, 2015, our net acreage position in the Permian Basin was approximately 25,854 net acres, including 7,496 net acres in the Northern Midland Basin that the Company plans to let expire in its entirety by 2016. As a result, no drilling or other capital expenditures are planned for the Northern Midland Basin in 2015.

 

Operational Highlights

 

Our production grew 97% for the three months ended March 31, 2015, compared to the same period of 2014, increasing to 771 MBOE from 392 MBOE.

 

 

 

The following table sets forth productive wells as of March 31, 2015:

 

 

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 the three months ended March 31, 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 any deficiencies in the Company’s current net working capital. However, future cash flows are subject to a number of variables, including forecast production volumes and commodity prices. 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 $1.2 million in the three months ended March 31, 2015 to $2.1 million compared to $1.0 million at December 31, 2014.  

 

Liquidity and cash flow

 

Operating activities.  For the three months ended March 31, 2015, net cash provided by operating activities was $6.1 million compared to net cash provided by operating activities of $20.0 million for the same period in 2014.  The decrease was primarily due to decreases in oil sales, which were partially offset by gains on the settlement of derivative contracts. Also contributing to the decrease were increases in lease operating expenses, production taxes, interest expenses, the impact on nonrecurring early retirement expenses, and payments on cash-settleable RSU 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.

 

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Investing activities.  For the three months ended March 31, 2015, net cash used in investing activities was $70.5 million compared to $63.5 million for the same period in 2014. The $7.0 million increase in cash used in investing activities was primarily attributable to a $13.3  million increase in capital expenditures, which was driven by the addition of the vertical rig added to our drilling program in August 2014. The increase in capital expenditures was significantly offset by acquisition costs, which were $8.0 million for the three months ended March 31, 2014. Also offsetting the increase was a $2.0 million reduction of proceeds resulting from the sale of certain specialized deep water equipment during the three months ended March 31, 2014.

 

Capital expenditures for the three months ended March 31, 2015 include the following (in millions):

 

 

Financing activities.  For the three months ended March 31, 2015, net cash provided by financing activities was $65.6 million compared to cash provided by financing activities of $42.3 million during the same period of 2014. Net cash provided by financing activities during the three months ended March 31, 2015 included $65.5 million of net proceeds from the issuance of common stock and a net $2.0 million of borrowings on our Credit Facility. In addition, the Company paid approximately $2.0 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 has 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 drilling efficiencies and the Company’s expected funding of non-consenting partners during the year. 

 

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 expenses 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:

 

 

 

 

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.

 

 

 

Oil revenue

 

For the quarter ended March 31, 2015, oil revenues of $27.9 million decreased $3.0 million, or 10%, compared to revenues of $30.9 million for the same period of 2014.  The decrease in oil revenue was primarily attributable to a 53% decrease in the average realized sales price offset by a 92% 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 $2.5 million increased $0.1 million, or 4%, during the three months ended March 31, 2015 compared to $2.4 million for the same period of 2014. The increase primarily relates to a  121% increase in natural gas volumes and was primarily offset by a  53% decrease in the average price realized, which fell to $3.10 per Mcf from $6.55 per Mcf due to decreases in both NYMEX

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benchmark 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.

 

Operating Expenses

 

 

*nm = not meaningful

 

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

 

LOE for the three months ended March 31, 2015 increased by  65% to $7.0 million compared to $4.2 million for the same period of 2014 primarily due to the growth in Permian production and operations. LOE per BOE for the three months ended March 31, 2015 decreased by 16% to $9.03 per BOE compared to $10.79 per BOE for the same period of 2014 resulting from a decrease in the number of workovers and cost reductions attributable to our existing producing properties. 

 

Production taxes. Production taxes include severance and ad valorem taxes. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.

 

Production taxes for the three months ended March 31, 2015 increased by 18% to $2.3 million compared to $1.9 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 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 March 31, 2015 decreased by 40% 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 months ended March 31, 2015, DD&A decreased 13% per BOE to $23.48 per BOE compared to $26.88 per BOE for the same period of 2014 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.

 

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G&A for the three months ended March 31, 2015 increased to $12.1 million compared to $10.8 million for the same period of 2014. G&A expenses for the periods indicated include the following (in millions): 

 

 

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.

 

Accretion expense related to our ARO decreased 8% for the three months ended March 31, 2015 compared to the same period of 2014. Accretion expense generally correlates with the Company’s ARO which was $6.3 million at March 31, 2015 versus $7.3 million at March 31, 2014. See Note 7 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO.

 

Rig termination fee.  For the three months ended March 31, 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 $1,080.

 

Other Income and Expenses and Preferred Stock Dividends

 

 

 

Interest expense.  Interest expense incurred during the three months ended March 31, 2015 increased $3.9 million compared to the same period of 2014. The increase is primarily attributable to $7.1 million in expense related to additional draws on our Credit Facility and Term Loan in 2015 compared to the corresponding period of the prior year. Offsetting the increase is a $2.1 million increase in capitalized interest compared to the 2014 period, resulting from a higher average unevaluated property balance period over period and a $1.1 million decrease in interest expense related to our Senior Notes following a $48.5 million partial redemption during the fourth quarter of 2013 and a full redemption of the remaining outstanding principal in April 2014.

 

Loss (gain) on derivative contracts.  For the three months ended March 31, 2015, the net gain on derivative instruments was $2.4 million, compared to a $2.5 million net loss for the same period of 2014. 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.

 

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Income tax expense (benefit). The Company had an income tax benefit of $5.1 million for the three months ended March 31, 2015 compared to income tax expense of $1.3 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 months ended March 31, 2015 was consistent with the same period of 2014. Dividends reflect a 10% dividend rate and $79 million liquidation value. See Note 8 in the Footnotes to the Financial Statements for additional information.