UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

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

For The Quarterly Period Ended March 31, 2014

OR

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

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)

 

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  ☒

 

As of May 2, 2014,  40,449,884  shares of the Registrant’s common stock, par value $0.01 per share, were outstanding.

 

 

 

---

 

Table of Contents

 

 

---

 

 

DEFINITIONS

 

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

 

 

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.

 

---

 

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.

 

---

 

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.

 

---

 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)

 

 

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

 

---

 

Callon Petroleum Company

Notes to the Consolidated Financial Statements

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

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

 

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

Note 1 - Description of Business and Basis of Presentation

 

Description of business

 

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

 

Callon is focused on the acquisition, development, exploration and exploitation of unconventional oil and natural gas reserves in the Permian Basin in West Texas. In late 2013, with the sale of its remaining offshore assets in the Gulf of Mexico, the Company completed the onshore strategic repositioning it initiated in 2009. 

 

Basis of presentation

 

Unless otherwise indicated, all dollar amounts included within the footnotes to the financial statements are presented in thousands, except for per share and per unit data.

 

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

 

These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2013. The balance sheet at December 31, 2013 has been derived from the audited financial statements at that date.

 

Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2014.

 

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

 

 

 

---

 

Note 2 – Oil and Natural Gas Properties

 

Acquisitions

 

In the first quarter of 2014, the Company acquired 1,527 net acres in Upton and Reagan Counties, Texas, which are located in the southern portion of the Midland Basin near our existing core development fields, for an aggregate cash purchase price of $8,200. The properties bear a working interest of 100% and an average net revenue interest of 78%.

 

Acreage Expiration

 

During the first quarter of 2014, the Company transferred $9,855 from unevaluated properties to the full cost pool related to 5,924 net acres in the Northern Midland Basin  that expired or are scheduled to expire in the near future and are no longer included in the Company’s exploration and development plans. The Company continues to narrow its focus acreage for continued exploration and delineation efforts, which remains focused on horizontal development drilling in the Southern and Central portions of the Midland Basin. As of March 31, 2014, Callon has a remaining net acreage position in the Northern Midland Basin of 11,857 acres for which the Company is still evaluating potential future exploration activities.

 

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. The total amount available under the Credit Facility is $500,000,  with an initial associated borrowing base of $95,000 and a maturity 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. Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is

---

 

generally reviewed on a semi-annual basis. The first redetermination is scheduled with an effective date of May 30, 2014, with subsequent redeterminations occurring every six months beginning on September 1, 2014. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties.

 

As of March 31, 2014, the balance outstanding on the Credit Facility was $68,000 with a weighted interest rate of 2.41%, calculated as the London Interbank Offered Rate (“LIBOR”) plus a tiered rate ranging from 1.75% to 2.75%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base.

 

Second Lien Term Loan Facility (the “Second Lien Facility”)

 

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

 

There were no outstanding balances on the Second Lien Facility as of March 31, 2014. The initial draw amount of $62,500 was made on April 10, 2014 with an original issue discount of 1.0%. Subsequent draws, allowable during the first year, are subject to the same 1.0% original issue discount on the drawn amount, applied on the date such draw is funded. Beginning on April 10, 2014, the interest rate is 8.75%, calculated at a rate of LIBOR (subject to a floor rate of 1.0%) plus 7.75% per annum. In addition, the Second Lien Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the initial commitment amount until March 11, 2015.

 

13% Senior Notes due 2016 (“Senior Notes”) and Deferred Credit

 

On April 11, 2014, the Company completed a full redemption of the remaining $48,481 principal amount of outstanding Senior Notes using proceeds from the Second Lien Facility. The redemption, which will be accounted for in the quarter ending June 30, 2014, will result in a net $3,204 gain on the early extinguishment of debt (including $4,780 of accelerated deferred credit amortization). The gain represents the difference between the $50,047 paid for the redemption of the Senior Notes ($1,576 of redemption costs, primarily the call premium) and the carrying value of the remaining Senior Notes of $53,261 (inclusive of $4,780 of deferred credit). The Company also paid  $193 for accrued interest through the redemption date. Upon the redemption, the indenture governing the Senior Notes was discharged in accordance with its terms.

 

Interest on the Senior Notes was payable on the last day of each quarter. Certain of the Company’s subsidiaries guaranteed the Company’s obligations under the Senior Notes. The subsidiary guarantors were 100% owned, all of the guarantees were full and unconditional and joint and several, the parent company had no independent assets or operations, and any subsidiaries of the parent company other than the subsidiary guarantors were minor. Upon issuing the Senior Notes in November 2009, the Company recorded as a deferred credit the $31,507 difference between the adjusted carrying amount of the previous Senior Notes that were exchanged and the principal of the new Senior Notes. This deferred credit was being amortized as a reduction of interest expense over the life of the Senior Notes at an 8.5% effective interest rate.

 

As of March 31, 2014,  the deferred credit balance was $4,834, net of $26,673 of amortization through that date. Amortization recorded as a reduction of interest expense for the quarter ended March 31, 2014 was $433.

 

Restrictive Covenants

 

The indentures governing the Senior Notes, Credit Facility and Second Lien Facility contain various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, the Credit Facility and Second Lien Facility contain covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at March 31, 2014.

---

 

 

Note 5 - Derivative Instruments and Hedging Activities

 

Objectives and strategies for using derivative instruments

 

The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collar, swap, put, call 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 transactions exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining a derivative instruments’ fair value; see Note 6 for additional information regarding fair value.

 

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

 

Financial statement presentation and settlements

 

Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the New York Mercantile Exchange (“NYMEX”) price. To determine the fair value of the Company’s derivative instruments, depending on the type of instrument, the Company utilizes present value methods or standard option valuation models that include assumptions about commodity prices based on those observed in underlying markets. See Note 6 for additional information regarding fair value.

 

Derivatives not designated as hedging instruments

 

The Company has elected not to designate its derivative contracts as accounting hedges under Accounting Standards Codification 815. Consequently, the Company records its derivative contracts at their fair values on the balance sheet and marks-to-market these contracts at the end of each period. The Company records changes in fair values as a gain or loss on the statement of operations as a component of gain (loss) on derivative contracts. The gain (loss) on derivative contracts in the statement of operations includes the mark-to-market adjustments on outstanding contracts and the impact of cash settlements.

 

The following table reflects the fair values 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 based on the underlying commodity being hedged. The following presents the impact of this presentation to the Company’s recognized assets and liabilities at March 31, 2014:

 

For the periods indicated, the Company recorded the following related to its derivatives in the statement of operations as gain or loss on derivative contracts:

 

Derivative positions

 

Listed in the table below are the outstanding oil and natural gas derivative contracts as of March 31, 2014 (volumes in thousands):

 

Excluded from the table above are offsetting natural gas long and short call options of 38,000 MMBtu per month for the period Apr14 – Dec14, each at a strike price of $4.75 per MMBtu.

 

The following derivative contracts were executed subsequent to March 31, 2014 (volumes in thousands):

 

 

 

 

 

 

 

 

---

 

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 on its Consolidated Balance Sheet. The fair value of Callon’s fixed-rate debt, which is valued using Level 2 inputs, is based upon estimates provided by an independent investment banking firm. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.

 

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

 

 (a) Fair value is calculated only in relation to the $48,481 and $48,481 principal outstanding of the Senior Notes at the dates indicated above, respectively. The remaining $4,834 and $5,267, respectively, which the Company has recorded as a deferred credit, is excluded from the fair value calculation, and will be recognized in earnings as a reduction of interest expense over the remaining amortization period. See Note 4 for additional information.

 

Assets and Liabilities Measured at Fair Value on a Recurring Basis

 

Certain assets and liabilities are reported at fair value on a recurring basis (unless otherwise noted below) in Callon’s consolidated balance sheet. The following methods and assumptions were used to estimate the fair values:

 

Commodity Derivative Instruments. The fair value of commodity derivative instruments is derived using a valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract, and the values are corroborated by quotes obtained from counterparties to the agreements. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 5 for additional information regarding the Company’s derivative instruments.

 

---

 

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

 

The derivative fair values above are based on analysis of each contract. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 5 for a discussion of net amounts recorded in the consolidated balance sheet at March 31, 2014.

 

Note 7 - Income Taxes 

 

The Company provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to statutory depletion, non-deductible executive compensation expenses and state income taxes. The effective tax rate for the three months ended March 31, 2014 and 2013  was 42% and  17%, respectively.

 

Note 8 - Asset Retirement Obligations 

 

The table below summarizes the Company’s asset retirement obligations activity for the three months ended March 31, 2014: 

 

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded on the consolidated balance sheets as restricted investments were $3,806 at March 31, 2014 and December 31, 2013. These investments include primarily U.S. Government securities, and are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.

 

 

Note 9 – Preferred Stock

 

Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. For the quarter ended March 31, 2014, the Board declared a dividend of $1.25 per share, or a total of $1,974, on the Company’s Preferred Stock.

 

---

 

As defined in a provision of the Preferred Stock prospectus, the common shares reserved for issuance vary based on the number of authorized common shares. In January 2014, following a majority shareholder vote, the number of authorized shares of common stock was increased from 60,000,000 to 110,000,000 with a corresponding increase in the number of common shares reserved for a potential conversion to a maximum of 42,200,000 shares. Based on the Company’s closing common stock price of $8.37 per share on March 31, 2014, the Company reserved 9,432,186  shares to satisfy the potential conversion.

 

Note 10 – Other

 

Operating Leases

 

In April 2012, the Company contracted a drilling rig (the “Cactus 1 Rig”) for a term of two years, which it subsequently renewed in March 2014 for an additional two year term ending April 2016. In April 2014, the Company contracted an additional horizontal drilling rig (the “Cactus 2 Rig”) for a term of two years ending April 2016. The Cactus 2 Rig replaced a previously contracted horizontal drilling rig, which was cancelled in March 2014. The Cactus 1 and Cactus 2 Rig lease agreements include early termination provisions that would reduce the minimum rentals under the agreement, and also include early termination payments that would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee. Lease payments in 2014,  2015 and 2016 are expected to approximate $18,015 (with $13,758 remaining at March 31, 2014), $18,250 and $4,795, respectively.  

 

Other Property and Equipment

 

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

 

 

 

---

 

Special Note Regarding Forward Looking Statements

 

All statements, other than historical fact or present financial information, 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, 2013 (the 2013 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto (“Form 10-Qs”).

 

Should one or more of the risks or uncertainties described above or in our 2013 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

 

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

 

---

 

General

 

The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our 2013 Annual Report on Form 10-K, which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. Our website address is www.callon.com. All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this report on Form 10-Q.

 

We are an independent oil and natural gas company established in 1950. We are focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas, and more specifically, the Midland Basin. Our operations are 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 85% oil and 15%  natural gas for the three months ended March 31, 2014.  On March 31, 2014, our net acreage position in the Permian Basin was approximately 25,481 net acres. 

 

Recent Developments

 

 

Operational Highlights

 

Following the sale of our remaining offshore and Haynesville properties in the fourth quarter of 2013, all of our producing properties are located in the Permian Basin. Our Permian production grew 176% in the first quarter of 2014 compared to the same period of 2013, increasing to 392 MBOE from 142 MBOE, respectively.

 

 

---

 

The following table sets forth productive wells as of March 31, 2014:

 

 

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

 

The following table summarizes the Company’s drilling progress in the Permian Basin for the three months ended March 31, 2014:

 

 

Liquidity and Capital Resources

 

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties.

 

Based upon current commodity price expectations for 2014, we believe that our cash flow from operations and borrowings under our Credit Facility and Second Lien Facility will be sufficient to fund our operations for 2014, including any deficiencies in the Company’s current net working capital. However, future cash flows are subject to a number of variables, including forecasted production volumes and commodity prices. Our 2014 capital program is 100% operated and, as a result, the amount and timing of a large portion of our planned capital expenditures are largely discretionary in the event we needed to curtail drilling and completion operations due to capital constraints.

 

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

 

---

 

Cash and cash equivalents decreased $1.3 million in the first quarter of 2014 to $1.7 million compared to $3.0 million at December 31, 2013. At March 31, 2014, our available liquidity, inclusive of undrawn amounts on our Credit Facility ($27.0 million) and Second Lien Facility ($100.0 million), increased to $128.7 million,  a $64.7 million increase over year-end 2013.

 

Liquidity and Cash Flow

 

Operating Activities.  For the three months ended March 31, 2014, net cash provided by operating activities was $20.0 million, compared to $12.9 million for the same period in 2013.  The increase was primarily due to an increase in oil sales and a reduction in lease operating expense, partially offset by losses on derivatives, settled and an increase in production taxes. Production and realized prices are discussed below in Results of Operations. See Notes 5 and 6 for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.

 

Investing Activities.  For the three months ended March 31, 2014, net cash used in investing activities was $63.5 million as compared to $29.6 million for the same period in 2013.  The $36.1 million increase in cash used in investing activities was primarily attributable to a $25.0 million increase in drilling and completion activities in the Permian Basin driven by the addition of a second horizontal drilling rig in August 2013. In addition, the Company completed $8.2 million of acquisitions in the first three months of 2014, with no acquisition completed in the comparable 2013 period.

 

Capital expenditures for the three months ended March 31, 2014 include the following (in millions):

 

 

Financing Activities.  For the three months ended March 31, 2014, net cash provided by financing activities was $42.3 million compared to cash provided by financing activities of $17.0 million during the same period of 2013. Net cash provided by financing activities during the three months ended March 31, 2014 included a net $46 million of borrowings on our Credit Facility offset by approximately $2.0 million in preferred stock dividends.

 

2014 Capital Expenditures 

 

Our 2014 operational capital budget approximates $185 million, excluding $8 million of acquisitions completed in 2014 (see Note 2). This budgeted amount includes plans to drill up to 27 horizontal and nine vertical wells, while completing 26 horizontal and eight vertical wells. In the first quarter of 2014, we began testing larger horizontal well completion designs in an effort to improve production rates and the amount of recoverable resources. Based on satisfactory drilling, completion and well performance to date, we believe that these enhanced completion designs create the potential for increased total returns on

---

 

capital after adjusting for incremental costs of approximately $0.5 million to $0.8 million per completion depending on the depth of the well. Consequently, we are in the process of evaluating our 2014 operational capital budget in anticipation of modifying our completion plans for future horizontal wells in selected areas. We are also forming our development plans related to recently acquired acreage in Upton and Reagan Counties. We expect to finalize our 2014 operational plan and any related increase in our current operational capital budget during the second quarter of 2014.

 

Results of Operations

 

The following table sets forth certain unaudited operating information with respect to the Company’s oil and natural gas operations for the periods indicated:

 

 

---

 

Revenues

 

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

 

 

Oil Revenue

 

For the quarter ended March 31, 2014, oil revenues of $30.9 million increased $11.4 million, or 58%, compared to revenues of  $19.5 million for the same period of 2013. Contributing to the increase in oil revenue was a 61% increase in production partially offset by a 2% decrease in the average realized sales price. The increase in production was primarily attributable to a 221 MBbls increase in production from our Permian properties, partially offset by a 92 MBbls decline in production due to the sale of our deepwater Medusa field in the fourth quarter of 2013 as well as normal and expected declines from our existing wells.

 

Natural Gas Revenue (including NGLs)

 

Natural gas revenues of $2.4 million decreased $0.6 million, or 21%, during the three months ended months ended March 31, 2014 as compared to $3.0 million for the same period of 2013. The decrease primarily relates to a 51% decrease in natural gas volumes partially offset by a 61% increase in the average price realized, which rose to $6.54 per Mcf from $4.07 per Mcf. Our natural gas prices on an MMBtu equivalent basis exceeded the related NYMEX prices primarily due to the value of the NGLs in our natural gas stream from our Permian Basin and offshore production. The production declines were primarily attributable to the sale of our offshore fields and our Haynesville well in the fourth quarter of 2013 as well as normal and expected declines from our existing wells. Offsetting these declines was a 156 million cubic feet increase in horizontal well production from our Permian properties.

 

Operating Expenses

 

Principal components of our cost structure

 

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

 

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

---

 

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

 

Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.

 

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

 

Accretion expense. The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations.

 

 

*nm = not meaningful

 

Lease Operating Expenses (“LOE”)

 

LOE for the three months ended March 31, 2014 decreased by 24% to $4.2 million compared to $5.6 million for the same period of 2013 was primarily due to an estimated decrease of $2.3 million of LOE resulting from the previously discussed sale of our interests in Medusa, the Medusa Spar LLC, our Haynesville property and substantially all our remaining shelf properties. These decreases were partially offset by $1.0 million in LOE costs related to the growth in Permian production and operations, including an increase in workover expenses associated with accelerated horizontal well activity.

 

Production Taxes

 

For the three months ended March 31, 2014, production taxes increased 166%, or $1.2 million, to  $1.9 million compared to $0.7 million for the same period of 2013.  The increase was predominantly attributable to an increase of onshore production subject to these taxes accompanied by a decline in offshore production, resulting from the sale of our Gulf of Mexico position in 2013, which was exempt from production taxes.

 

Depreciation, Depletion and Amortization (“DD&A”)

 

DD&A for the three months ended March 31, 2014 decreased 20% per BOE to $26.88 per BOE compared to $33.66 per BOE for the same period of 2013 attributable to our increasing estimated proved reserves relative to our depreciable asset base (the full cost pool).

---

 

 

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

 

G&A for the three months ended March 31, 2014 increased to $10.8 million compared to $3.7 million  for the same period of 2013. Total G&A for the first quarter of 2014 also included $6.3 million of expense related to the following items:

 

 

Accretion Expense

 

Accretion expense related to our ARO decreased 60% for the three months ended March 31, 2014 compared to the same period of 2013. Accretion expense correlates directionally with the Company’s ARO which was $7.3 million at March 31, 2014 versus $14.3 million at March 31, 2013.  The reduction in ARO was primarily a result of our property divestiture in the fourth quarter of 2013. See Note 8 for additional information regarding the Company’s ARO.

 

Gain on sale of other property and equipment

 

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

 

Other Income and Expenses

 

Interest Expense

 

Interest expense incurred during the three months ended March 31, 2014 decreased $0.5 million compared to the same period of 2013 and is primarily related to $1.4 million lower interest expense related to our Senior Notes following a $48.5 million principal redemption during the fourth quarter of 2013. Offsetting the decrease is a $0.5 million decline in capitalized interest for the comparative three month period, resulting from a lower average unevaluated property balance period over period, and an additional $0.4 million interest expense related to additional draws on our Credit Facility in 2014 compared to the corresponding period of the prior year.

 

Loss (Gain) on Derivative Contracts

 

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

 

Income Tax Expense

 

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

 

---

 

Preferred Stock Dividends

 

Preferred Stock dividends for the three months ended March 31, 2014 increased $2.0 million compared to the same period of 2013 in which we had no dividend expense. The expense of $2.0 million for the three-month period is consistent with its 10% dividend rate and $75 million face value.