PNRG 10-Q Quarter ended Sept. 30, 2013

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period Ended September 30, 2013

Or

For the Transition Period From to

Commission File Number 0-7406

PrimeEnergy Corporation

(Exact name of registrant as specified in its charter)

9821 Katy Freeway, Houston, Texas 77024

(Address of principal executive offices)

(713) 735-0000

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the 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 filings required for the past 90 days.    Yes x 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 x 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.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes ¨ No x

The number of shares outstanding of each class of the Registrant’s Common Stock as of October 30, 2013 was: Common Stock, $0.10 par value 2,405,879 shares.

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PrimeEnergy Corporation

Index to Form 10-Q

September 30, 2013

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PRIMEENERGY CORPORATION

(Thousands of dollars, except per share amounts)

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

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PRIMEENERGY CORPORATION

(Thousands of dollars, except per share amounts)

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

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PRIMEENERGY CORPORATION

C ONDENSED C ONSOLIDATED S TATEMENTS OF C OMPREHENSIVE I NCOME —Unaudited

Nine Months Ended September 30, 2013 and 2012

(Thousands of dollars)

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

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PRIMEENERGY CORPORATION

C ONDENSED C ONSOLIDATED S TATEMENT OF E QUITY —Unaudited

Nine Months Ended September 30, 2013

(Thousands of dollars)

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

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PRIMEENERGY CORPORATION

Nine Months Ended September 30, 2013 and 2012

(Thousands of dollars)

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

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PRIMEENERGY CORPORATION

N OTES TO C ONDENSED C ONSOLIDATED F INANCIAL S TATEMENTS

September 30, 2013

(Unaudited)

(1) Basis of Presentation:

The accompanying condensed consolidated financial statements of PrimeEnergy Corporation (“PEC” or the “Company”) have not been audited by independent public accountants. Pursuant to applicable Securities and Exchange Commission (“SEC”) rules and regulations, the accompanying interim financial statements do not include all disclosures presented in annual financial statements and the reader should refer to the Company’s Form 10-K for the year ended December 31, 2012. In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s condensed consolidated balance sheets as of September 30, 2013 and December 31, 2012, the condensed consolidated results of operations for the three and nine months ended September 30, 2013 and 2012, and the condensed consolidated results of cash flows and equity for the nine months ended September 30, 2013 and 2012. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.

Recently Issued Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, “Disclosures about Offsetting Assets and Liabilities.” This ASU requires enhanced disclosures including both gross and net information about financial and derivative instruments eligible for offset or subject to an enforceable master netting arrangement or similar agreement. This new guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” ASU 2013-01 clarifies the scope of ASU 2011-11 to apply to derivative instruments that are offset or subject to an enforceable master netting arrangement or similar agreement. This clarified guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. The revised requirements of ASU 2011-11 and ASU 2013-01 impacted the disclosures associated with the Company’s derivative instruments (Note 11) and did not have a material impact on the Company’s condensed consolidated financial position, results of operations or cash flows.

In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” (“AOCI”). ASU 2013-02 requires a rollforward of changes in AOCI by component and information about significant reclassifications from AOCI to net earnings to be presented in one location, either on the face of the financial statements or in the notes. This new guidance is effective for fiscal years beginning after December 15, 2012 and subsequent interim periods. The revised disclosure requirements of ASU 2013-02 are reflected in Note 11. The requirements of ASU 2013-02 did not have a material impact on the Company’s condensed consolidated financial position, results of operations or cash flows.

(2) Acquisitions and Dispositions:

Historically the Company has repurchased the interests of the partners and trust unit holders in the eighteen oil and gas limited partnerships (the “Partnerships”) and the two asset and business income trusts (the “Trusts”) managed by the Company as general partner and as managing trustee, respectively. The Company purchased such interests in amounts totaling $14,000 and $66,000 for the nine months ended September 30, 2013 and 2012, respectively.

(3) Restricted Cash and Cash Equivalents:

Restricted cash and cash equivalents include $3.21 million and $4.44 million at September 30, 2013 and December 31, 2012, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at September 30, 2013 and December 31, 2012 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the accompanying condensed consolidated balance sheets.

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(4) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

(5) Property and Equipment:

Property and equipment at September 30, 2013 and December 31, 2012 consisted of the following:

Bank Debt :

Effective July 30, 2010, the Company entered into a Second Amended and Restated Credit Agreement between Compass Bank as agent and a syndicated group of lenders (“Credit Agreement”). The Credit Agreement has a revolving line of credit and letter of credit facility of up to $250 million with a final maturity date of July 30, 2017. The credit facility is secured by substantially all of the Company’s oil and gas properties. The credit facility is subject to a borrowing base determined by the lenders taking into consideration the estimated value of PEC’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. This process involves reviewing PEC’s estimated proved reserves and their valuation. The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redetermination. In addition, PEC and the lenders each have at their discretion the right to request the borrowing base be redetermined with a maximum of one such request each year. A revision to PEC’s reserves may prompt such a request on the part of the lenders, which could possibly result in a reduction in the borrowing base and availability under the credit facility. At any time if the sum of the outstanding borrowings and letter of credit exposures exceed the applicable portion of the borrowing base, PEC would be required to repay the excess amount within a prescribed period.

At September 30, 2013, the credit facility borrowing base was $145.0 million with no required monthly reduction amount. The borrowings made within the credit facility may be placed in a base rate loan or LIBO rate loan. The Company’s borrowing rates in the credit facility provide for base rate loans at the prime rate (3.25% at September 30, 2013) plus applicable margin utilization rates that range from 1.75% to 2.00%, and LIBO rate loans at LIBO published rates plus applicable utilization rates (2.75% to 3.00% at September 30, 2013). At September 30, 2013, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.00% and 2.95%, respectively.

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At September 30, 2013, the Company had a total of $107.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.48% and $38.0 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.53% for the nine months ended September 30, 2013, as compared to 3.80% for the nine months ended September 30, 2012.

On July 31, 2013, the Company entered into a $10.0 million Loan and Security Agreement with JP Morgan Chase Bank (“Equipment Loan”). The Equipment Loan is secured by substantially all of the Company’s field service equipment, carries an interest rate of 3.95% per annum, requires monthly payments (principal and interest) of $184,000, and has a final maturity date of July 31, 2018. As of September 30, 2013, the Company had a total of $9.8 million outstanding on the Equipment Loan.

The Company has entered into interest rate hedge agreements to help manage interest rate exposure. These contracts include interest rate swaps. Interest rate swap transactions generally involve the exchange of fixed and floating rate interest payment obligations without the exchange of the underlying principal amounts. In July 2012, the Company entered into interest swap agreements for a period of two years, which commence in January 2014, related to $75 million of the Company’s bank debt resulting in a fixed rate of 0.563% plus the Company’s current applicable margin.

(7) Other Long-Term Obligations and Commitments:

Operating Leases:

The Company has several non-cancelable operating leases, primarily for rental of office space, that have a term of more than one year. The future minimum lease payments for the rest of fiscal 2013 and thereafter for the operating leases are as follows:

Rent expense for office space for the nine months ended September 30, 2013 and 2012 was $548,000 and $581,000, respectively.

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2013 is as follows:

The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates.

(8) Contingent Liabilities:

The Company, as managing general partner of the affiliated Partnerships, is responsible for all Partnership activities, including the drilling of development wells and the production and sale of oil and gas from productive wells. The Company also provides the administration, accounting and tax preparation work for the Partnerships, and is liable for all debts and liabilities of the affiliated Partnerships, to the extent that the assets of a given limited Partnership are not sufficient to satisfy its obligations. As of September 30, 2013, the affiliated Partnerships have established cash reserves in excess of their debts and liabilities and the Company believes these reserves will be sufficient to satisfy Partnership obligations.

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The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.

From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.

(9) Stock Options and Other Compensation:

In May 1989, non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At September 30, 2013 and 2012, remaining options held by two key executive officers on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.

(10) Related Party Transactions:

The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships or Trusts. The Company purchased such interests in amounts totaling $14,000 and $66,000 for the nine months ended September 30, 2013 and 2012, respectively.

Treasury stock purchases in any reported period may include shares from a related party, which may include members of the Company’s Board of Directors.

Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursement for property development and related costs. These receivables are due from joint venture partners, which may include members of the Company’s Board of Directors.

Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses.

(11) Financial Instruments:

Fair Value Measurements:

Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012:

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The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.

The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2013.

Derivative Instruments:

The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity based derivatives. Both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings.

Interest rate swap derivatives are treated as cash-flow hedges and are used to fix or float interest rates on existing debt. The value of these interest rate swaps at September 30, 2013 and December 31, 2012 is located in accumulated other comprehensive income (loss), net of tax. Settlement of the swaps, currently scheduled to begin in January 2014, will be recorded within interest expense.

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The following table sets forth the effect of derivative instruments on the condensed consolidated balance sheets at September 30, 2013 and December 31, 2012:

The following table sets forth the offsetting of asset and liability derivatives in the condensed consolidated balance sheets at September 30, 2013 and December 31, 2012:

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The following table sets forth the effect of derivative instruments on the condensed consolidated statements of operations for the nine months ended September 30, 2013 and 2012:

(12) Earnings Per Share:

Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the financial statements:

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This Report may contain statements relating to the future results of the Company that are considered “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 (the “PSLRA”). In addition, certain statements may be contained in the Company’s future filings with the SEC, in press releases, and in oral and written statements made by or with the approval of the Company that are not statements of historical fact and constitute forward-looking statements within the meaning of the PSLRA. Such forward-looking statements, in addition to historical information, which involve risk and uncertainties, are based on the beliefs, assumptions and expectations of management of the Company. Words such as “expects”, ‘believes”, “should”, “plans”, “anticipates”, “will”, “potential”, “could”, “intend”, “may”, “outlook”, “predict”, “project”, “would”, “estimates”, “assumes”, “likely” and variations of such similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve risks and uncertainties and are based on a number of assumptions that could ultimately prove inaccurate and, therefore, there can be no assurance that they will prove to be accurate. Actual results and outcomes may vary materially from what is expressed or forecast in such statements due to various risks and uncertainties. These risks and uncertainties include, among other things, the possibility of drilling cost overruns and technical difficulties, volatility of oil and gas prices, competition, risks inherent in the Company’s oil and gas operations, the inexact nature of interpretation of seismic and other geological and geophysical data, imprecision of reserve estimates, and the Company’s ability to replace and expand oil and gas reserves. Accordingly, stockholders and potential investors are cautioned that certain events or circumstances could cause actual results to differ materially from those projected. The forward looking statements are made as of the date of this report and other than as required by the federal securities laws, the Company assumes no obligation to update the forward-looking statement or to update the reasons why actual results could differ from those projected in the forward-looking statements.

The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contains additional information that should be referred to when reviewing this material.

OVERVIEW

We are an independent oil and natural gas company engaged in acquiring, developing and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, the Gulf of Mexico, New Mexico, Colorado and Louisiana. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.

We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. In order to diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets so as to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated income statement as changes occur in the NYMEX price indices.

RECENT ACTIVITIES

During 2013, we have invested approximately $14 million completing wells drilled in 2012 and continuing our drilling programs in our West Texas and Mid-Continent regions. Thru October 31, 2013, we have participated in the drilling of 18 gross (10.25 net) wells. Twelve of these wells are currently producing, 3 are currently being completed and 3 wells are currently drilling. We intend to drill a total of approximately 25 gross (14 net) wells this year, primarily in the West Texas and Mid-Continent areas at a net cost of approximately $20 million.

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RESULTS OF OPERATIONS

2013 and 2012 Compared

We reported net income attributable to PrimeEnergy for the three and nine months ended September 30, 2013 of $2.23 million, or $0.92 per share and $10.58 million, or $4.32 per share, respectively as compared to $1.34 million, or $0.51 per share and $10.09 million, or $3.81 per share for the three and nine months ended September 30, 2012, respectively. Net income increased by $0.89 million or 66% and $0.50 million or 5% for the three and nine months ended September 30, 2013 as compared to the same periods during 2012 primarily due to increases in oil and gas sales and field service income and decreased depreciation and depletion expense partially offset by increases in realized and unrealized losses on derivative instruments and increases in lease operating and field service expenses. Oil and gas sales increased by $4.14 million and $5.76 million for the three and nine months ended September 30, 2013, respectively as compared to the same periods in 2012 largely due to an increased production volumes and increases in commodity prices during the three and nine months ended September 30, 2013 as compared to production volumes and commodity prices during the three and nine months ended September 30, 2012. Field service income increased by $1.88 million and $3.00 million for the three and nine months ended September 30, 2013, respectively as compared to the same periods in 2012 with the addition of new service equipment during 2013. Depreciation and depletion decreased by $0.71 million and $3.52 million for the three and nine months ended September 30, 2013, respectively as compared to the same periods in 2012 largely due to decreased depletion rates associated with our offshore properties as several of our offshore properties were plugged and abandoned during 2012. Net realized and unrealized losses on derivative instruments increased by $2.46 million and $5.43 million for the three and nine months ended September 30, 2013, respectively as compared to the same periods in 2012 largely due to an increase in future crude oil commodity prices during the 2013 periods as compared to crude fixed price oil commodity contracts held at December 31, 2012 and 2011. Primarily due to recent drilling success in West Texas and resulting increase in activities with new wells coming on line, lease operating expenses increased by $1.98 million and $3.49 million for the three and nine months ended September 30, 2013, respectively as compared to the same periods in 2012. Field service expenses increased by $1.25 million and $2.20 million for the three and nine months ended September 30, 2013, respectively as compared to the same periods in 2012 corresponding to the increase in field service income and new service equipment added in 2013.

The significant components of net income are discussed below.

Oil and gas sales increased $4.14 million, or 19% from $21.81 million for the three months ended September 30, 2012 to $25.95 million for the three months ended September 30, 2013 and increased $5.76 million, or 9% from $65.68 million for the nine months ended September 30, 2012 to $71.44 million for the nine months ended September 30, 2013. Crude oil and natural gas sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices at the well head increased an average of $16.69 per barrel, or 19% and $2.82 per barrel, or 3% on crude oil during the three and nine months ended September 30, 2013, respectively from the same periods in 2012 while our average well head price for natural gas increased $0.30 per mcf, or 6% and $0.45 per mcf, or 10% during the three and nine months ended September 30, 2013, respectively from the same periods in 2012.

Our crude oil production increased by 3,000 barrels, or 2% from 185,000 barrels for the third quarter 2012 to 188,000 barrels for the third quarter 2013 and increased by 19,000 barrels, or 4% from 541,000 barrels for the nine months ended September 30, 2012 to 560,000 barrels for the nine months ended September 30, 2013. Our natural gas production increased by 51,000 mcf, or 4% from 1,191,000 mcf for the third quarter 2012 to 1,242,000 mcf for the third quarter 2013 and increased by 174,000 mcf, or 5% from 3,493,000 mcf for the nine months ended September 30, 2012 to 3,667,000 mcf for the nine months ended September 30, 2013. The net increase in crude oil and natural gas production volumes are a result of our continued drilling success in our West Texas and Mid-Continent regions as we place new wells into production, partially offset by the natural decline of existing properties.

The following table summarizes the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2013 and 2012 (excluding realized gains and losses from derivatives).

Realized net gains (losses) on derivative instruments include net gains of $0.24 million and net losses of $1.44 million on the settlements of natural gas and crude oil derivatives, respectively for the third quarter 2013 and net gains of $0.04 million on the settlements of crude oil derivatives for the third quarter 2012. Realized net gains on derivative instruments include net gains of $0.57 million and net losses of $1.70 million on the settlements of natural gas and crude oil derivatives, respectively for the nine months

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ended September 30, 2013 and net gains of $0.38 million on the settlements of crude oil derivatives for the nine months ended September 30, 2012. In the nine months ended September 30, 2012, we unwound and monetized crude oil swaps with original settlement dates from January 2012 through December 2013 for net proceeds of $1.03 million. The gains associated with these early settlement transactions are included in realized gain on derivative instruments for the nine months ended September 30, 2012.

Oil and gas prices received including the impact of derivatives but excluding the early settlement transactions were:

We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. During the three and nine months ended September 30, 2013, we recognized net unrealized losses of $0.06 million and $0.49 million, respectively associated with natural gas fixed swap contracts and net unrealized losses of $3.81 million and $0.98 million, respectively associated with crude oil fixed swaps and collars due to market fluctuations in natural gas and crude oil futures market prices between December 31, 2012 and September 30, 2013. During the three months ended September 30, 2012, we recognized unrealized losses of $2.65 million and a net unrealized gain of $2.45 million for the nine months ended September 30, 2012 associated with crude oil fixed swaps and collars due to market fluctuations in crude oil futures market prices between December 31, 2011 and September 30, 2012.

Field service income increased $1.88 million, or 38% from $4.89 million for the third quarter 2012 to $6.77 million for the third quarter 2013 and $3.00 million, or 20% from $15.34 million for the nine months ended September 30, 2012 to $18.35 million for the nine months ended September 30, 2013. This underlying increase is a result of adding service equipment and the market allowing us to charge slightly higher rates to customers. Workover rig services represent the bulk of our field service operations, and those rates have all increased between the periods in our most active districts.

Lease operating expense increased $1.98 million, or 21% from $9.35 million for the third quarter 2012 to $11.33 million for the third quarter 2013 and $3.49 million, or 12% from $28.82 million for the nine months ended September 30, 2012 to $32.31 million for the nine months ended September 30, 2013. This underlying increase is primarily due to higher pumper / labor costs and chemical expenses associated with new wells coming on line from the recent drilling success in West Texas and increased expensed workovers across all districts, partially offset by decreased operating expenses on the offshore properties during the first nine months of 2013 as compared to the same periods of 2012.

Field service expense increased $1.25 million, or 29% from $4.27 million for the third quarter 2012 to $5.52 million for the third quarter 2013 and $2.20 million, or 17% from $13.02 million for the nine months ended September 30, 2012 to $15.22 million for the nine months ended September 30, 2013. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased during the three and nine months ended September 30, 2013 over the same periods of 2012 as a direct result of increased services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities decreased $0.71 million, or 12% from $5.88 million for the third quarter 2012 to $5.18 million for the third quarter 2013 and $3.52 million, or 18% from $19.85 million for the nine months ended September 30, 2012 to $16.33 million for the nine months ended September 30, 2013. This decrease is primarily due to decreased depletion rates recognized during the three and nine months ended September 30, 2013 associated with offshore properties as our offshore properties were plugged and abandoned during 2012, partially offset by increased depletion expenses related to new wells coming on line from the recent drilling success in West Texas.

General and administrative expense increased $0.04 million, or 1% from $3.82 million for the three months ended September 30, 2012 to $3.86 million for the three months ended September 30, 2013 and $0.74 million, or 6% from $11.51 million for the nine months ended September 30, 2012 to $12.25 million for the nine months ended September 30, 2013. This increase in 2013 is largely due to increased personnel costs in 2013. The largest component of these personnel costs was salaries and employee related taxes and insurance.

Gain on sale and exchange of assets of $2.52 million and $0.72 million for the nine months ended September 30, 2013 and September 30, 2012, respectively consists of sales of non-essential oil and gas interests and field service equipment.

Interest expense increased $0.05 million, or 6% from $0.95 million for the third quarter 2012 to $1.00 million for the third quarter 2013 and $0.62 million, or 25% from $2.53 million for the nine months ended September 30, 2012 to $3.16 million for the nine months ended September 30, 2013. This increase relates to an increase in average debt outstanding during the three and nine months ended September 30, 2013 as compared to the same periods of 2012 slightly offset by a decrease in weighted average interest rates during the 2013 periods.

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A provision for income taxes of $1.28 million, or an effective tax rate of 35% was recorded for the third quarter 2013 verses a provision of $0.46 million, or an effective tax rate of 26% for the third quarter 2012 and a provision of $5.94 million, or an effective tax rate of 36% was recorded for the nine months ended September 30, 2013 verses a provision of $4.67 million, or an effective tax rate of 32% for the nine months ended September 30, 2012. Our provision for income taxes varies from the federal statutory tax rate of 34% primarily due to state taxes and percentage depletion deductions. We are entitled to percentage depletion on certain of our wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis it creates a permanent difference, which lowers our effective rate.

LIQUIDITY AND CAPITAL RESOURCES

Our primary capital resources are cash provided by our operating activities and our credit facility.

Net cash provided by our operating activities for the nine months ended September 30, 2013 was $30.71 million compared to $33.39 million for the nine months ended September 30, 2012. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.

Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the vast majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility we sometimes lock in prices for some portion of our production through the use of derivatives.

If our exploratory drilling results in significant new discoveries, we will have to expend additional capital in order to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing.

We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2013. For the nine month period ended September 30, 2013, we have spent $2.99 million under these programs.

We currently maintain a revolving credit facility totaling $250 million, with a final maturity date of July 30, 2017 and a current borrowing base of $145 million and $38.00 million in availability at September 30, 2013. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a redetermined estimate of proved oil and gas reserves. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.

On July 31, 2013, we executed an equipment financing facility totaling $10.0 million with an effective annual interest rate of 3.95% and requiring 60 monthly payments of $184,000. Our field service equipment is pledged as collateral for this facility. In August 2013, we used the $10.0 million in proceeds from this equipment facility to pay down on our revolving credit facility.

It is our goal to increase our oil and gas reserves and production through the acquisition and development of oil and gas properties. Our activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential. We continue our drilling programs in our West Texas and Mid-Continent regions. During 2013, we intend to drill a total of approximately 25 gross (14 net) wells, primarily in the West Texas and Mid-Continent areas at a net cost of approximately $20 million. We also continue to explore and consider opportunities to further expand our oilfield servicing revenues through additional investment in field service equipment. However, the majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

The Company is a smaller reporting company and no response is required pursuant to this Item.

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

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There were no changes in the Company’s internal control over financial reporting that occurred during the first nine months of 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

None.

The Company is a smaller reporting company and no response is required pursuant to this Item.

There were no sales of equity securities by the Company during the period covered by this report.

During the nine months ended September 30, 2013, the Company purchased the following shares of common stock as treasury shares.

None

None

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The following exhibits are filed as a part of this report: