PRIMEENERGY RESOURCES CORP - Quarter Report: 2014 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period Ended September 30, 2014

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 November 10, 2014 was: Common Stock, $0.10 par value 2,343,660 shares.

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PrimeEnergy Corporation

Index to Form 10-Q

September 30, 2014

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PART I—FINANCIAL INFORMATION

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – Unaudited

(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

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – Unaudited

(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

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – Unaudited

Nine Months Ended September 30, 2014 and 2013

(Thousands of dollars)

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

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF EQUITY – Unaudited

Nine Months Ended September 30, 2014

(Thousands of dollars)

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

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited

Nine Months Ended September 30, 2014 and 2013

(Thousands of dollars)

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

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PRIMEENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(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, 2013. 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, 2014 and December 31, 2013, the condensed consolidated results of operations for the three and nine months ended September 30, 2014 and 2013, and the condensed consolidated results of cash flows and equity for the nine months ended September 30, 2014 and 2013. 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 July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.” ASU 2013-11 provided guidance on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This guidance requires entities to present unrecognized tax benefits as a decrease in a net operating loss, similar tax loss, or tax credit carryforward if certain criteria are met. The guidance will eliminate the diversity in practice in the presentation of unrecognized tax benefits but will not alter the way in which entities assess deferred tax assets for realizability. ASU No. 2013-11 is effective for annual and interim reporting periods beginning after December 15, 2013. The requirements of ASU 2013-11 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 $233,000 and $14,000 for the nine months ended September 30, 2014 and 2013, respectively.

(3) Restricted Cash and Cash Equivalents:

Restricted cash and cash equivalents include $3.51 million and $2.01 million at September 30, 2014 and December 31, 2013, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at September 30, 2014 and December 31, 2013 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the accompanying condensed consolidated balance sheets.

(4) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

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(5) Property and Equipment:

Property and equipment at September 30, 2014 and December 31, 2013 consisted of the following:

(6) Long-Term Bank Debt:

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, 2014, the credit facility borrowing base was $160.0 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, 2014) plus applicable margin utilization rates that range from 1.50% to 2.00%, and LIBO rate loans at LIBO published rates plus applicable utilization rates (2.50% to 3.00% at September 30, 2014). At September 30, 2014, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 4.75% and 2.65%, respectively.

At September 30, 2014, the Company had a total of $86.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.32% and $73.5 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.48% for the nine months ended September 30, 2014 as compared to 3.53% for the nine months ended September 30, 2013.

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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 a portion 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, 2014, the Company had a total of $8.0 million outstanding on the Equipment Loan.

On July 29, 2014, the Company entered into additional equipment financing facilities totaling $6.0 million with JP Morgan Chase Bank. In August 2014, the Company drew down $4.8 million of this facility that is secured by recently purchased field service equipment, carries an interest rate of 3.40% per annum, requires monthly payments (principal and interest) of $87,800, and has a final maturity date of July 31, 2019. As of September 30, 2014, the Company had a total of $4.8 million outstanding on this facility. The remaining $1.2 million under this facility is available to finance the acquisition of any future field service equipment.

The Company 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 commenced in January 2014, related to $75 million of the Company’s bank debt resulting in a LIBO fixed rate of 0.563%. For the nine months ended September 30, 2014, the Company recorded interest expense and paid $210,000 related to the settlement of interest rate swaps.

(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 2014 and thereafter for the operating leases are as follows:

Rent expense for office space for the nine months ended September 30, 2014 and 2013 was $579,000 and $548,000, respectively.

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2014 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. In 2014, the Company recognized a gain on the settlement of asset retirement obligations associated with insurance recoveries related to obligations previously recognized on the plugging and abandonment of a well.

(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, 2014, 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, 2014 and 2013, 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 $233,000 and $14,000 for the nine months ended September 30, 2014 and 2013, 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, 2014 and December 31, 2013:

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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, 2014.

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, 2014 and December 31, 2013 is located in accumulated other comprehensive loss, net of tax. Settlement of the swaps, which began in January 2014, is 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, 2014 and December 31, 2013:

The following table sets forth the effect of derivative instruments on the condensed consolidated statement of operations for the nine-month periods ended September 30, 2014 and 2013:

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(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 statements 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 contain 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 2014, we continued our drilling program in our West Texas and Mid-Continent regions. It is our goal to increase our oil and gas reserves and production through the acquisition and development of oil and gas properties. Based upon the results of horizontal wells drilled by us and other offsetting operators and historical vertical well performance, we have decided to reduce the number of vertical wells in our drilling program and drill more horizontal wells. We believe horizontal development of our resource base will provide the opportunity to improve returns relative to vertical drilling by accessing a larger base of reserves in target zones with a lateral wellbore. Through November 10, 2014, we have participated in the drilling of 23 gross (10.9 net) wells; 14 of these wells are currently producing and the remainder are drilling or awaiting completion.

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We intend to drill a total of approximately 25 gross (11.5 net) wells this year, primarily in the West Texas and Oklahoma areas at a net cost of $30 million. During 2014 we have participated in the drilling of 10 horizontal wells in our Mid-Continent region under various joint venture agreements, and expect 7 more wells to be drilled in the fourth quarter of 2014 and first quarter of 2015. This horizontal development is primarily in Grant and Canadian counties where we have approximately 6,450 net acres which we believe has significant resource potential based on drilling results and those of offset operators. In addition, we expect to begin our West Texas, Upton County horizontal drilling program in the first quarter of 2015, drilling up to 9 wells in this phase at a net cost of approximately $35 million. Discussions with our joint venture partner, in that program, Apache Corporation, indicate that including additional phases of development in the program, will result in approximately 60 horizontal wells being drilled over the next 18 to 24 months at a cost of approximately $470 million. We own various interests, ranging from 33% up to 50% interest in the lands to be developed in the program, and expect our share of these capital expenditures to be approximately $150 million. We maintain an acreage position of over 26,000 gross (16,500 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties. We have currently identified 64 proved undeveloped drilling locations there and believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional drilling locations opportunities.

RESULTS OF OPERATIONS

2014 and 2013 Compared

We reported net income attributable to PrimeEnergy for the three and nine months ended September 30, 2014 of $10.80 million, or $4.58 per share and $16.84 million, or $7.11 per share, respectively as compared to $2.23 million, or $0.92 per share and $10.58 million, or $4.32 per share for the three and nine months ended September 30, 2013, respectively. Net income increased by $8.57 million or 384% and $6.26 million or 59% for the three and nine months ended September 30, 2014 as compared to the same periods during 2013 primarily due to an increase in unrealized gains on derivative instruments, gains on the sale of non-essential oil and gas interests and a $1.79 million net gain recognized in the third quarter of 2014 on insurance recoveries partially offset by an increase in related income tax provisions. Unrealized gains on derivative instruments increased by $12.23 million and $3.83 million for the three and nine months ended September 30, 2014, respectively as compared to the same periods in 2013 largely due to a decrease in future crude oil commodity prices during the 2014 periods as compared to crude oil commodity contracts held at December 31, 2013. During nine months ended September 30, 2014 we have recognized gains on the sale of non-essential oil and gas interests and field service equipment of $5.62 million as compared to $2.52 the same period in 2013.

The significant components of net income are discussed below.

Oil and gas sales decreased $2.58 million, or 10% from $25.95 million for the three months ended September 30, 2013 to $23.37 million for the three months ended September 30, 2014 and increased $2.20 million, or 3% from $71.44 million for the nine months ended September 30, 2013 to $73.64 million for the nine months ended September 30, 2014. 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 decreased an average of $15.16 per barrel, or 14% and $1.59 per barrel, or 2% on crude oil during the three and nine months ended September 30, 2014, respectively from the same periods in 2013 while our average well head price for natural gas increased $0.03 per mcf, or 1% and $0.61 per mcf, or 12% during the three and nine months ended September 30, 2014, respectively from the same periods in 2013.

Our crude oil production increased by 6,000 barrels, or 3% from 188,000 barrels for the third quarter 2013 to 194,000 barrels for the third quarter 2014 and increased by 17,000 barrels, or 3% from 560,000 for the nine months ended September 30, 2013 to 577,000 barrels for the nine months ended September 30, 2014. Our natural gas production decreased by 36,000 mcf, or 3% from 1,242,000 mcf for the third quarter 2013 to 1,206,000 mcf for the third quarter 2014 and decreased by 116,000 mcf, or 3% from 3,667,000 mcf for the nine months ended September 30, 2013 to 3,551,000 mcf for the nine months ended September 30, 2014. The increase in crude oil production volumes are a result of our continued drilling success in West Texas, Gulf Coast and Oklahoma 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, 2014 and 2013 (excluding realized gains and losses from derivatives).

Realized gain (loss) on derivative instruments, net include net gains of $0.02 million and $0.13 million on the settlements of natural gas and crude oil derivatives, respectively for the third quarter 2014 and 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. Realized gain (loss) on derivative instruments include net losses of $0.58 million and $1.99 million on the settlements of natural gas and crude oil derivatives, respectively for the nine months ended September 30, 2014 and 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 ended September 30, 2013. In the third quarter of 2014, we unwound and monetized crude oil swaps with original settlement dates from January 2016 through December 2016 for net proceeds of $0.70 million. The $0.70 million gain associated with this early settlement transaction is included in realized gain on derivative instruments for the three and nine months ended September 30, 2014. In addition, during the first quarter of 2014, we unwound and monetized natural gas swaps with original settlement dates from January 2015 through December 2015 for net proceeds of $0.28 million. The $0.28 million gain associated with this early settlement transaction is included in realized gain on derivative instruments for the nine months ended September 30, 2014.

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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 condensed 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, 2014, we recognized net unrealized gains of $0.88 million and $0.56 million, respectively associated with natural gas fixed swap contracts and net unrealized gains of $7.48 million and $1.80 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, 2013 and September 30, 2014. 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.

Field service income decreased $0.30 million, or 4% from $6.77 million for the third quarter 2013 to $6.47 million for the third quarter 2014 and increased $1.48 million, or 8% from $18.35 million for the nine months ended September 30, 2013 to $19.83 million for the nine months ended September 30, 2014. This underlying increase is a result of adding service equipment during the latter periods of 2013. Workover rig services represent the bulk of our field service operations, and with the upgrading of our rigs during late 2013, income from rigs has increased during 2014 in our most active districts. In addition, income from water hauling and disposal services in our South Texas district have generally recovered from a slight down turn due to increased competition in the area during the first half of 2013, and income from hot oiler services have increased in our West Texas district with the addition of service equipment in the area.

Lease operating expense decreased $0.35 million, or 3% from $11.33 million for the third quarter 2013 to $10.98 million for the third quarter 2014 and increased $0.81 million, or 3% from $32.31 million for the nine months ended September 30, 2013 to $33.12 million for the nine months ended September 30, 2014. This underlying increase is primarily due to higher pumper / labor costs and salt water disposal costs associated with new wells coming on line from the recent drilling success in West Texas partially offset by increased expensed workovers incurred during the third quarter 2013.

Field service expense decreased $0.37 million, or 7% from $5.52 million for the third quarter 2013 to $5.15 million for the third quarter 2014 and increased $0.50 million, or 3% from $15.22 million for the nine months ended September 30, 2013 to $15.72 million for the nine months ended September 30, 2014. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased during the nine months ended September 30, 2014 over the same period of 2013 as a direct result of increased services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $0.61 million, or 12% from $5.18 million for the third quarter 2013 to $5.79 million for the third quarter 2014 and $0.42 million, or 3% from $16.33 million for the nine months ended September 30, 2013 to $16.75 million for the nine months ended September 30, 2014. This increase is primarily due to increased depletion rates recognized during the first nine months of 2014 associated with the recent drilling success in West Texas as compared to the same periods of 2013, substantially offset with decreased depletion recognized during the first half of 2014 associated with our offshore properties.

General and administrative expense increased $0.43 million, or 11% from $3.86 million for the three months ended September 30, 2013 to $4.29 million for the three months ended September 30, 2014 and decreased $0.43 million, or 4% from $12.25 million for the nine months ended September 30, 2013 to $11.82 million for the nine months ended September 30, 2014. The underlying increase in general and administrative expense in 2014 is largely due to increased personnel costs in 2014, substantially offset in the first half of 2014 with the reimbursement of administrative expenses associated with development activities. The largest component of these personnel costs was salaries and employee related taxes and insurance.

Gain on sale and exchange of assets of $5.62 million and $2.52 million for the nine months ended September 30, 2014 and September 30, 2013, respectively consists of sales of non-essential oil and gas interests and field service equipment.

Interest expense decreased $0.02 million, or 2% from $1.00 million for the third quarter 2013 to $0.98 million for the third quarter 2014 and $0.06 million, or 2% from $3.16 million for the nine months ended September 30, 2013 to $3.10 million for the nine months ended September 30, 2014. This decrease relates to a decrease in average debt outstanding during the 2014 periods partially offset by the settlement of interest rate swaps during the 2014 periods and a slight increase in weighted average interest rates due to our Equipment Loans entered into in July 2013 and July 2014.

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A provision for income taxes of $5.62 million, or an effective tax rate of 34% was recorded for the third quarter 2014 versus a provision of $1.23 million, or an effective tax rate of 35% for the third quarter 2013 and a provision of $8.53 million, or an effective tax rate of 34% was recorded for the nine months ended September 30, 2014 versus a provision of $5.94 million, or an effective tax rate of 36% for the nine months ended September 30, 2013. Our provision for income taxes can vary 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 would have the effect of lowering 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, 2014 was $44.29 million compared to $30.71 million for the nine months ended September 30, 2013. 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 currently maintain a credit facility totaling $250 million, with a current borrowing base of $160 million and $73.50 million in availability at September 30, 2014. 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. 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. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months.

In July 2013, we obtained a $10 million loan secured by a portion of our field service equipment used in our field service operations. We used the funds from that loan to pay down our credit facility, and as a result, freed up additional funds under the credit facility for future acquisitions, development and operations. As of October 15, 2014, we had a total of $7.8 million outstanding on this loan.

On July 29, 2014, we executed additional equipment financing facilities totaling $6 million. In August 2014, we drew down $4.8 million of this facility that is secured by field service equipment recently purchased and these proceeds were used to pay down on our revolving credit facility, and as a result, free up additional funds under the credit facility for future acquisitions, development and operations. The remaining $1.2 million under this facility will be available to finance the acquisition of any future field service equipment. As of October 15, 2014, we had a total of $4.7 million outstanding on this loan.

It is our goal to increase our oil and gas reserves and production through the acquisition and development of oil and gas properties. During 2014, we continued our drilling program in our West Texas and Mid-Continent regions. Based upon the results of horizontal wells drilled by us and other offsetting operators and historical vertical well performance, we have decided to reduce the number of vertical wells in our drilling program and drill more horizontal wells. We believe horizontal development of our resource base will provide the opportunity to improve returns relative to vertical drilling by accessing a larger base of reserves in target zones with a lateral wellbore. Through November 10, 2014, we have participated in the drilling of 23 gross (10.9 net) wells; 14 of these wells are currently producing and the remainder are drilling or awaiting completion. During 2014, we intend to drill a total of approximately 25 gross (11.5 net) wells, primarily in the West Texas and Oklahoma areas, at a net cost of $30 million. During 2014 we have participated in the drilling of 10 horizontal wells in our Mid-Continent region under various joint venture agreements, and expect 7 more wells to be drilled in the fourth quarter of 2014 and first quarter of 2015. This horizontal development is primarily in Grant and Canadian counties where we have approximately 6,450 net acres which we believe has significant resource potential based on drilling results and those of offset operators. In addition, we expect to begin our West Texas, Upton County horizontal drilling program in the first quarter of 2015, drilling up to 9 wells in this phase at a net cost of approximately $35 million. Discussions with our joint venture partner in that program, Apache Corporation, indicate that including additional phases of development in the program will result in approximately 60 horizontal wells being drilled over the next 18 to 24 months at a cost of approximately $470 million. We own various interests, ranging from 33% up to 50% interest in the lands to be developed in the program, and expect our share of these capital expenditures to be approximately $150 million. We maintain an acreage position of over 26,000 gross (16,500 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties. We have currently identified 64 proved undeveloped drilling locations there and believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional drilling opportunities. 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.

We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2014. For the nine month period ended September 30, 2014, we have spent $2.79 million under these programs.

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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.

There were no changes in the Company’s internal controls over financial reporting that occurred during the three months ended September 30, 2014 that materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

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PART II—OTHER INFORMATION

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, 2014, 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:

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SIGNATURES

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

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