PNRG 10-Q Quarter ended June 30, 2016

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period Ended June 30, 2016

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 August 11, 2016 was: Common Stock, $0.10 par value 2,293,964 shares.

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PrimeEnergy Corporation

Index to Form 10-Q

June 30, 2016

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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

Six Months Ended June 30, 2016 and 2015

(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

Six Months Ended June 30, 2016

(Thousands of dollars)

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

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PRIMEENERGY CORPORATION

Six Months Ended June 30, 2016 and 2015

(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

June 30, 2016

(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, 2015. 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 June 30, 2016 and December 31, 2015, the condensed consolidated results of operations for the three and six months ended June 30, 2016 and 2015, and the condensed consolidated results of cash flows and equity for the six months ended June 30, 2016 and 2015. 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:

The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) . This ASU supersedes the Revenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605. Extractivies – Oil and Gas Revenue Recognition. This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral or the Effective Date, to annual and interim periods beginning in 2018 and is required to be adopted using either the retrospective or cumulative effect (modified retrospective) transition method, with early adoption permitted in 2017. The Company is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures and does not plan on early adopting.

The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities such, as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The ASU is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This ASU adopted by the Company beginning January 1, 2016 did not have a material impact on the Company’s consolidated financial statements and related disclosures.

The FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASU’s require debt issuance costs related to a recognized debt liability, except for those related to revolving credit facilities, to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than an asset. These ASU’s adopted by the Company beginning January 1, 2016 did not have a material impact on the Company’s consolidated financial statements and related disclosures.

The FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. This ASU is effective for annual and interim periods beginning in 2017 and can be applied prospectively or retrospectively, with early adoption permitted. This ASU was early-adopted by the Company effective January 1, 2016 and applied retrospectively, and did not have a material impact on the Company’s financial statements and related disclosures.

The FASB issued ASU 2016-02, Leases (Topic 842). This ASU requires lessee recognition on the balance sheet of a right-of-use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statement of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. This ASU will not have a material impact on the Company’s financial statements and related disclosures.

(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 $176,000 and $5,000 for the six months ended June 30, 2016 and 2015, respectively.

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During the six months ended June 30, 2016, the Company has farmed out interests in certain non-core undeveloped oil and natural gas properties through a number of separate, individually negotiated transactions in exchange for cash and a royalty or working interest in both West Texas and Oklahoma. Proceeds under these agreements are $16.3 million. The Company has entered into an agreement to sell certain noncore West Texas acreage for an additional $10 million during the third quarter of 2016.

(3) Restricted Cash and Cash Equivalents:

Restricted cash and cash equivalents include $3.25 million and $3.51 million at June 30, 2016 and December 31, 2015, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at June 30, 2016 and December 31, 2015 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:

(5) Property and Equipment:

Property and equipment at June 30, 2016 and December 31, 2015 consisted of the following:

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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 June 30, 2016, the credit facility borrowing base was $95 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 (3.5% at June 30, 2016) plus applicable margin utilization rates that range from 1.75% to 2.50%, and LIBO rate loans at LIBO published rates plus applicable utilization rates (2.75% to 3.00% at June 30, 2016). At June 30, 2016, the Company had in place one LIBO rate loan with an effective rate of 3.47%. Effective July 22, 2016, the borrowing base was re-determined to be $80 million.

At June 30, 2016, the Company had a total of $88 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.72% and $7 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.66% for the six months ended June 30, 2016 as compared to 3.42% for the six months ended June 30, 2015. During July 2016, the Company paid down $8 million to reduce the outstanding borrowings to conform with the new borrowing base of $80 million.

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% and terminated in January 2016. The Company recorded interest expense and paid $7,000 and $146,000 related to the settlement of interest rate swaps for the six months ended June 30, 2016 and 2015, respectively.

Equipment Loans :

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 June 30, 2016, the Company had a total of $4.57 million outstanding on this Equipment Loan.

On July 29, 2014, the Company entered into additional equipment financing facilities (“Additional Equipment Loans”) 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 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. The remaining $1.2 million under the Additional Equipment Loans was available for interim draws to finance the acquisition of any future field service equipment. In December 2014, the Company made an interim draw of an additional $0.5 million on this facility that is secured by recently purchased field service equipment. Interim draws on this facility carried a floating interest rate, payable monthly at the LIBO published rate plus 2.50% and on June 26, 2015 converted into a fixed term loan requiring monthly payments (principal and interest) of $8,700 with a final maturity date of June 26, 2020. As of June 30, 2016, the Company had a total of $3.55 million outstanding on the Additional Equipment Loans.

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(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 2016 and thereafter for the operating leases are as follows:

Rent expense for office space for the six months ended June 30, 2016 and 2015 was $465,000 and $424,000, respectively.

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the six months ended June 30, 2016 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. At June 30, 2016, 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.

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.

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(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 June 30, 2016 and 2015, 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 $176,000 and $5,000 for the six months ended June 30, 2016 and 2015, 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. In 2016, the Company purchased 10,000 shares from a related party.

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 June 30, 2016 and December 31, 2015:

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.

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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 six months ended June 30, 2016.

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 continue to be treated as cash-flow hedges and are used to fix our float interest rates on existing debt. The value of these interest rate swaps at June 30, 2016 and December 31, 2015 are located, if applicable, in accumulated other comprehensive loss, net of tax. Settlement of the swaps, which began in January 2014 and concluded in January 2016, are recognized within interest expense.

The following table sets forth the effect of derivative instruments on the condensed consolidated balance sheets at June 30, 2016 and December 31, 2015:

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The following table sets forth the effect of derivative instruments on the condensed consolidated statement of operations for the six-month periods ended June 30, 2016 and 2015:

(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, 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 are the operator of substantially all of our undeveloped acreage the majority of which is currently held by production. We have historically sold or farmed-out non-core acreage to supplement cashflow and finance our drilling program. Proceeds from these transactions through June 30, 2016 were approximately $16 million and we have entered into an agreement to sell certain non-core West Texas acreage for an additional $10 million during the third quarter of 2016.

Subsequent to these transactions we maintain an acreage position of over 24,600 gross (14,900 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties. We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for drilling opportunities. Our Oklahoma acreage position consists of over 18,000 net acres in 15 counties, with over 7,500 net acres in Kingfisher, Canadian, Grady and Grant counties. Additionally, our producing properties in West Virginia hold approximately 33,000 net acres and our Gulf Coast and Rocky Districts maintain approximately 13,000 net acres held by production.

We believe our balanced portfolio of assets positions 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, through our producing oil & gas properties, field services business and sales of non-core acreage.

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 may 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.

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RECENT ACTIVITIES

We began our West Texas, Upton County horizontal drilling program during 2015 and through the second quarter of 2016 we have drilled 5 wells in this phase. Discussions with our joint venture partner in that program, Apache Corporation, indicate that including additional phases of development the program will result in approximately 60 horizontal wells being drilled at a cost of approximately $470 million. We own various interests, ranging from 16% up to 50% interest in the lands to be developed in the program, and expect our share of these capital expenditures to be approximately $120 million. The actual number of wells to be drilled and the timing of the drilling may vary based on commodity market conditions. Currently the Company and Apache have agreed until oil and gas prices recover to limit drilling to those wells required to maintain our acreage position. Apache drilling plans indicated two of these wells will be drilled later this year at a cost of $12.6 million, of which our share is $4.5 million. The latest well drilled commenced production July 17, 2016 and is currently flowing at approximately 1,500 barrels of oil and 1,600 Mcf of gas per day.

During 2016 we commenced our Martin County, Texas horizontal drilling program, operated by RSP Permian, two wells have been drilled and are currently producing. One well was placed on production June 21, 2016 and is currently on an ESP, pumping at approximately 740 barrels of oil and 725 Mcf of gas per day. The second well was placed on production July 7, 2016 and is currently flowing at approximately 415 barrels of oil and 380 Mcf of gas per day. We expect this well to be put on an ESP resulting in increased production rates. RSP Permian’s drilling plans indicate possibly drilling two wells later this year for a cost of approximately $13 million, of which our share is $4.4 million.

In our Oklahoma drilling program the Sun Up well, operated by Devon Energy, was spudded on June 6, 2016 and is currently awaiting completion. We have a 26.65% working interest in this well and expect our share of the drilling and completion costs to be approximately $1.8 million.

During the first half of 2016 we have farmed out certain non-core acreage in exchange for cash and a royalty or working interest in both West Texas and Oklahoma. Proceeds under these agreements were approximately $16 million. In addition during August 2016 we entered into an agreement to sell additional non-core acreage in West Texas under which the Company would receive approximately $10 million, closing is expected during the third quarter of 2016.

RESULTS OF OPERATIONS

2016 and 2015 Compared

We reported a net income for the three and six months ended June 30, 2016 of $2.5 million, or $1.10 per share and $0.6 million, or $0.29 per share, respectively as compared to net losses of $1.9 million, or $0.84 per share and $1.9 million, or $0.83 per share for the three and six months ended June 30, 2015, respectively. The decrease in commodity prices reduced oil and gas sales compared to 2015 and all derivative instruments expired during 2015 therefore we incurred no gains or losses related to derivative instruments during 2016. The significant components of income and expense are discussed below.

Oil and gas sales decreased $5.55 million, or 38.9% from $14.26 million for the three months ended June 30, 2015 to $8.71 million for the three months ended June 30, 2016 and decreased $10.72 million, or 40.4% from $26.55 million for the six months ended June 30, 2015 to $15.84 million for the six months ended June 30, 2016. 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 $13.05 per barrel, or 24% and $14.77 per barrel, or 29.7% on crude oil during the three and six months ended June 30, 2016, respectively from the same periods in 2015 while our average well head price for natural gas decreased $0.39 per mcf, or 14.3% and $0.60 per mcf, or 20.9% during the three and six months ended June 30, 2016, respectively from the same periods in 2015.

Our crude oil production decreased by 49,000 barrels or 24% from 199,000 barrels for the second quarter 2015 to 150,000 barrels for the second quarter 2016 and decreased by 81,000 barrels, or 20% from 393,000 for the six months ended June 30, 2015 to 312,000 barrels for the six months ended June 30, 2016. Our natural gas production decreased by 189,000 mcf, or 15% from 1,268,000 mcf for the second quarter 2015 to 1,079,000 mcf for the second quarter 2016 and decreased by 269,000 mcf, or 11% from 2,453,000 mcf for the six months ended June 30, 2015 to 2,184,000 mcf for the six months ended June 30, 2016. The decreases in crude oil and natural gas production volumes are a result of the natural decline of existing properties combined with the shut in of marginally economic properties in a response to low commodity prices.

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The following table summarizes the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2016 and 2015 (excluding realized gains and losses from derivatives).

Realized gain (loss) on derivative instruments, net include net gains of $0.77 million and $3.53 million on the settlements of natural gas and crude oil derivatives, respectively for the second quarter 2015. Realized gain on derivative instruments include net gains of $1.36 million and $8.08 million on the settlements of natural gas and crude oil derivatives, respectively for the six months ended June 30, 2015. No such gains were recognized in 2016.

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 six months ended June 30, 2015, we recognized net unrealized losses of $0.81 million and $1.02 million, respectively associated with natural gas fixed swap contracts and net unrealized losses of $5.83 million and $8.08 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, 2014 and June 30, 2015. No such losses were recognized in 2016.

Field service income decreased $1.74 million, or 31.9% from $5.45 million for the second quarter 2015 to $3.7 million for the second quarter 2016 and $3.06 million, or 27.8% from $10.99 million for the six months ended June 30, 2015 to $7.9 million for the six months ended June 30, 2016. This decrease is a combined result of reduced utilization and the market requiring us to charge lower rates to customers during the 2016 period. Workover rig services represent the bulk of our field service operations, and working rates have all decreased between the periods in our most active districts.

Lease operating expense decreased $1.51 million, or 16.9% from $8.97 million for the second quarter 2015 to $7.46 million for the second quarter 2016 and decreased $2.74 million, or 15% from $18.21 million for the six months ended June 30, 2015 to $15.47 million for the six months ended June 30, 2016. This decrease is due to reduced production taxes related to reduced oil and natural gas prices, general rate reductions on vendor services and the delay of discretionary repairs and expenditures during the 2016 periods as compared to the same periods of 2015.

Field service expense decreased $1.04 million, or 23.6% from $4.40 million for the second quarter 2015 to $3.36 million for the second quarter 2016 and decreased $1.97 million, or 22.1% from $8.89 million for the six months ended June 30, 2015 to $6.92 million for the six months ended June 30, 2016. Field service expenses primarily consist of salaries and vehicle operating expenses which have decreased during the six months ended June 30, 2016 from the same period of 2015 as a direct result of decreased labor, services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $0.6 million, or 10.9% from $5.69 million for the second quarter 2015 to $6.31 million for the second quarter 2016 and $0.44 million, or 4% from $11.14 million for the six months ended June 30, 2015 to $11.58 million for the six months ended June 30, 2016.

General and administrative expense decreased $1.27 million, or 40.8% from $3.12 million for the three months ended June 30, 2015 to $1.85 million for the three months ended June 30, 2016 and $2.21 million, or 34% from $6.49 million for the six months ended June 30, 2015 to $4.28 million for the six months ended June 30, 2016. This decrease in 2016 reflects the cost cutting measures including reductions in workforce put in place throughout 2015 and the six months of 2016 and the reimbursement of administrative expenses associated with property activities. The largest component of these personnel costs are salaries and employee related taxes and insurance.

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Gain on sale and exchange of assets of $16.32 million and $1.22 million for the six months ended June 30, 2016 and June 30, 2015, respectively consists of sales of non-essential oil and gas interests and field service equipment.

Interest expense remained flat from $0.93 million for the second quarter 2015 to $0.94 million for the second quarter 2016 and from $1.87 million for the six months ended June 30, 2015 to $1.81 million for the six months ended June 30, 2016.

A tax provision of $369 thousand, or an effective rate of approximately 33% was recorded for the six months ended June 30, 2016, versus a tax benefit of $1.02 million for the six months ended June 30, 2015. 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 sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of non-core acreage.

Net cash provided by our operating activities for the six months ended June 30, 2016 was $4.9 million compared to $8.5 million for the six months ended June 30, 2015. 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.

We currently maintain a credit facility totaling $250 million, with a borrowing base of $80 million. 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. The next borrowing base review is scheduled for November 2016. 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 and expect to be in compliance over the next twelve months. 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. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the redetermined borrowing base.

Our most recent amendment to our credit agreement, effective July 22, 2016, required us to hedge a portion of our production as forecasted for our PDP reserves in our Spring borrowing base review engineering report for the period from November 2016 through December 2018. Accordingly in July 2016 the Company entered into the following swap agreements for oil and natural gas.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2016, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2016 capital budget is reflective of decreased commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures. We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices.

Due to the uncertainty of financing availability we have removed all but one PUD location from our yearend reserve report in accordance with the SEC rules governing the scheduling of the drilling of PUD reserves within 5 years. The one PUD included in our report was drilled in the first quarter of 2016 as part of our joint venture with Apache Corporation in Upton County, Texas.

We began our West Texas, Upton County horizontal drilling program during 2015 and through the second quarter of 2016 we have drilled 5 wells in this phase. Discussions with our joint venture partner in that program, Apache Corporation, indicate that including additional phases of development the program will result in approximately 60 horizontal wells being drilled at a cost of approximately $470 million. We own various interests, ranging from 16% up to 50% interest in the lands to be developed in the program, and expect our share of these capital expenditures to be approximately $120 million. The actual number of wells to be drilled and the timing of the drilling may vary based on commodity market conditions. Currently the Company and Apache have agreed until oil and gas prices recover to limit drilling to those wells required to maintain our acreage position. Apache drilling plans indicated two of these wells will be drilled later this year at a cost of $12.6 million, of which our share is $4.5 million. The latest well drilled commenced production July 17, 2016 and is currently flowing at approximately 1,500 barrels of oil and 1,600 Mcf of gas per day.

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During 2016 we commenced our Martin County, Texas horizontal drilling program, operated by RSP Permian, two wells have been drilled and are currently producing. One well was placed on production June 21, 2016 and is currently on an ESP, pumping at approximately 740 barrels of oil and 725 Mcf of gas per day. The second well was placed on production July 7, 2016 and is currently flowing at approximately 415 barrels of oil and 380 Mcf of gas per day. We expect this well to be put on an ESP resulting in increased production rates. RSP Permian’s drilling plans indicate possibly drilling two wells later this year for a cost of approximately $13 million, of which our share is $4.4 million.

In our Oklahoma drilling program the Sun Up well, operated by Devon Energy, was spudded on June 6, 2016 and is currently awaiting completion. We have a 26.65% working interest in this well and expect our share of the drilling and completion costs to be approximately $1.8 million.

During the first half of 2016 we have farmed out certain non-core acreage in exchange for cash and a royalty or working interest in both West Texas and Oklahoma. Proceeds under these agreements were approximately $16 million. In addition during August 2016 we entered into an agreement to sell additional non-core acreage in West Texas under which the Company would receive approximately $10 million, closing is expected during the third quarter of 2016.We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2016, subject to certain restrictions under Credit Agreement. For the six month period ended June 30, 2016, we have spent $685 thousand under these programs.

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 June 30, 2016 that materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

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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 six months ended June 30, 2016, 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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