PRIMEENERGY RESOURCES CORP - Quarter Report: 2015 March (Form 10-Q)

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period Ended March 31, 2015

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 May 11, 2015 was: Common Stock, $0.10 par value 2,314,094 shares.

Table of Contents

PrimeEnergy Corporation

Index to Form 10-Q

March 31, 2015

2

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

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

3

Table of Contents

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – Unaudited

Three Months Ended March 31, 2015 and 2014

(Thousands of dollars, except per share amounts)

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

4

Table of Contents

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – Unaudited

Three Months Ended March 31, 2015 and 2014

(Thousands of dollars)

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

5

Table of Contents

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF EQUITY – Unaudited

Three Months Ended March 31, 2015

(Thousands of dollars)

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

6

Table of Contents

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited

Three Months Ended March 31, 2015 and 2014

(Thousands of dollars)

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

7

Table of Contents

PRIMEENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2015

(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, 2014. 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 March 31, 2015 and December 31, 2014, the condensed consolidated results of operations, cash flows and equity for the three months ended March 31, 2015 and 2014. 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 May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. ASU 2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016, and can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. Early application is not permitted. In April 2015, the FASB proposed to delay the effective date one year. The proposal will be subject to the FASB’s due process requirement, which includes a period for public comments. The Company is currently evaluating the effect that the adoption of ASU 2014-09 will have on the Company’s 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 $1,000 and $48,000 for the three months ended March 31, 2015 and 2014, respectively.

(3) Restricted Cash and Cash Equivalents:

Restricted cash and cash equivalents include $3.88 million at March 31, 2015 and December 31, 2014 of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at March 31, 2015 and December 31, 2014 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:

8

Table of Contents

(5) Property and Equipment:

Property and equipment at March 31, 2015 and December 31, 2014 consisted of the following:

(6) Long-Term 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 March 31, 2015, the credit facility borrowing base was $130.0 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 March 31, 2015) 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 March 31, 2015). At March 31, 2015, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.00% and 2.91%, respectively.

At March 31, 2015, the Company had $90.0 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.46% and $40.0 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.41% for the three months ended March 31, 2015 as compared to 3.55% for the three months ended March 31, 2014.

9

Table of Contents

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%. The Company recorded interest expense and paid $74,000 and $54,000 related to the settlement of interest rate swaps for the three months ended March 31, 2015 and 2014, 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 March 31, 2015, the Company had a total of $7.0 million outstanding on this 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 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 this facility is available to finance the acquisition of any future field service equipment. In December 2014, the Company drew down an additional $0.5 million of this facility that is secured by recently purchased field service equipment. Interim draws on this facility carry a floating interest rate, payable monthly at the LIBO published rate plus 2.50% and in July 2015 will convert along with subsequent draws, if any, into a fixed term loan requiring monthly payments (principal and interest) and a final maturity date of June 30, 2020. As of March 31, 2015, the Company had a total of $4.8 million outstanding on this facility.

(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 2015 and thereafter for the operating leases are as follows:

Rent expense for office space for the three months ended March 31, 2015 and 2014 was $263,000 and $164,000, respectively.

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the three months ended March 31, 2015 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 March 31, 2015, 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.

10

Table of Contents

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 March 31, 2015 and 2014, 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 $1,000 and $48,000 for the three months ended March 31, 2015 and 2014, 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 March 31, 2015 and December 31, 2014:

11

Table of Contents

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 three months ended March 31, 2015.

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 March 31, 2015 and December 31, 2014 are located in accumulated other comprehensive loss, net of tax. Settlement of the swaps are recorded within interest expense.

The following table sets forth the effect of derivative instruments on the condensed consolidated balance sheets at March 31, 2015 and December 31, 2014:

12

Table of Contents

The following table sets forth the effect of derivative instruments on the condensed consolidated statement of operations for the three-month periods ended March 31, 2015 and 2014:

(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:

13

Table of Contents

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 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 condensed consolidated income statement as changes occur in the NYMEX price indices.

RECENT ACTIVITIES

During 2015, we continued our drilling program in our West Texas and Mid-Continent regions, completing wells spudded in 2014 and participating in the drilling of the first well in our Apache joint venture. That well was spudded on March 17, 2015 and we have a 12.5% interest in this horizontal well. 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.

14

Table of Contents

RESULTS OF OPERATIONS

2015 and 2014 Compared

We reported net income attributable to PrimeEnergy for the three months ended March 31, 2015 of $0.01 million, or $0.01 per share as compared to $2.81 million, or $1.18 per share for the three months ended March 31, 2014. Net income decreased in 2015 by $2.80 million or 100% primarily due to decreases in oil and gas sales and field service income and gain on the sale of non-essential oil and gas interests partially offset by an increase in realized gains on derivative instruments and decreases in lease operating expense, field service expense and general and administrative expense as well as related decreases in net income attributable to non-controlling interests and income tax provisions. Operating revenues decreased $7.59 million for the three months ended March 31, 2015 as compared to the same period in 2014 largely due to decreased commodity prices realized in 2015 and a decrease in field service income due to reduced rates and utilization during 2015 partially offset by an increase in gains realized on derivative instruments in 2015. Lease operating and field service expenses decreased $2.67 million and $1.04 million, respectively, for the three months ended March 31, 2015 as compared to the same period in 2014 primarily from decreased production taxes, delay of discretionary repairs and a general rate reduction on vendor service costs in 2015. General and administrative expenses decreased $1.08 million for the three months ended March 31, 2015 as compared to the same period in 2014 primarily due to reduced bonus accruals for the 2015 period. During the three months ended March 31, 2015 we recognized gains on the sale of non-essential oil and gas interests and field service equipment of $0.49 million as compared to $3.17 million during the same period in 2014.

The significant components of net income are discussed below.

Oil and gas sales decreased $11.90 million, or 49% from $24.20 million for the three months ended March 31, 2014 to $12.30 million for the three months ended March 31, 2015. 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 $49.35 per barrel, or 52% on crude oil during the three months ended March 31, 2015 from the same period in 2014 and our average well head price for natural gas decreased $3.09 per mcf, or 50% during the three months ended March 31, 2015 from the same period in 2014.

Our crude oil production increased by 12,000 barrels, or 7% from 182,000 barrels for the first quarter 2014 to 194,000 barrels for the first quarter 2015. Our natural gas production increased by 32,000 mcf, or 3% from 1,153,000 mcf for the first quarter 2014 to 1,185,000 mcf for the first quarter 2015. The net increase in crude oil and natural gas production volumes are a result of our continued drilling success in West Texas, Gulf Coast and Oklahoma regions as we placed new wells into production, partially offset by a natural decline of existing properties.

The following table summarizes the primary components of production volumes and average sales prices realized for the three months ended March 31, 2015 and 2014 (excluding realized gains and losses from derivatives).

Realized net gains on derivative instruments include net gains of $0.59 million and $4.55 million on the settlements of natural gas and crude oil derivatives, respectively for the first quarter 2015 and net losses of $0.24 million and $0.75 million on the settlements of natural gas and crude oil derivatives, respectively for the first quarter 2014. In 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 these early settlement transactions is included in realized gain on derivative instruments for the three months ended March 31, 2014.

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

15

Table of Contents

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 months ended March 31, 2015, we recognized net unrealized losses of $0.19 million associated with natural gas fixed swap contracts and $2.27 million in net unrealized losses associated with crude oil fixed swaps due to a decrease in natural gas and crude oil futures market prices between December 31, 2014 and March 31, 2015. During the three months ended March 31, 2014, we recognized net unrealized losses of $0.50 million associated with natural gas fixed swap contracts and $1.48 million in net unrealized losses 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 March 31, 2014.

Field service income decreased $1.23 million, or 18% from $6.77 million for the first quarter 2014 to $5.54 million for the first quarter 2015. This decrease is a combined result of slightly reduced utilization and the market requiring us to charge lower rates to customers during the 2015 period. Workover rig services represent the bulk of our field service operations, and while we were able to keep our rigs utilized during 2015, working rates have all decreased between the periods in our most active districts. In addition, income from water hauling and disposal services in our South Texas district have generally decreased during the first quarter of 2015 due to decreased activity in the area.

Lease operating expense decreased $2.67 million, or 22% from $11.91 million for the first quarter 2014 to $9.24 million for the first quarter 2015. This decrease is primarily 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 first three months of 2015 as compared to the same period of 2014.

Field service expense decreased $1.04 million, or 19% from $5.53 million for the first quarter 2014 to $4.49 million for the first quarter 2015. Field service expenses primarily consist of salaries and vehicle operating expenses which have decreased during the three months ended March 31, 2015 over the same period of 2014 as a direct result of decreased services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $0.10 million, or 2% from $5.35 million for the first quarter 2014 to $5.45 million for the first quarter 2015. This slight increase is primarily due to increased depletion recognized during the first three months of 2015 associated with the increased production in West Texas as compared to the same period of 2014.

General and administrative expense decreased $1.08 million, or 24% from $4.45 million for the three months ended March 31, 2014 to $3.37 million for the three months ended March 31, 2015. This decrease in 2015 is largely due to decreased bonus accruals in 2015 due to reduced oil and natural gas prices.

Gain on sale and exchange of assets of $0.49 million and $3.17 million for the three months ended March 31, 2015 and March 31, 2014, respectively consists of sales of non-essential oil and gas interests and field service equipment.

Interest expense decreased $0.14 million, or 13% from $1.08 million for the first quarter 2014 to $0.94 million for the first quarter 2015. This decrease relates to a decrease in average debt outstanding during the first quarter 2015 as compared to the same period of 2014.

A provision for income taxes of $0.01 million, or an effective tax rate of 54% was recorded for the three months ended March 31, 2015 versus a provision of $1.48 million, or an effective tax rate of 34% for the three months ended March 31, 2014. Our provision for income taxes for the three months ended March 31, 2015, varies from the federal statutory tax rate of 34% primarily due to state taxes and percentage depletion deductions. We are entitled to percentage depletion on certain of our wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis it creates a permanent difference, which 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 three months ended March 31, 2015 was $1.33 million compared to $11.13 million for the three months ended March 31, 2014. 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.

16

Table of Contents

We currently maintain a credit facility totaling $250 million, with a current borrowing base of $130 million and $40.00 million in availability at March 31, 2015. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a redetermined estimate of proved oil and gas reserves. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants 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.

It is our goal to increase our oil and gas reserves and production through the acquisition and development of oil and gas properties. During 2015 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.

During 2015, we intend to spend approximately $30 million in our drilling program, primarily in the West Texas area. In our Mid-Continent region, the horizontal development is primarily in Grant and Canadian counties where we have approximately 6,450 net acres which we believe have significant resources potential based on our drilling results and those of offset operators. We began our West Texas, Upton County horizontal drilling program in the first quarter of 2015, and will drill up to 4 wells in this phase at a net cost of approximately $10 million. The first well was spudded March 17, 2015 and discussions with our joint venture partner in the program, Apache Corporation, indicated that including additional phases of development in the program will result in approximately 60 horizontal wells being drilled over the next 36 to 48 months at a cost of approximately $470 million. The actual number of wells to be drilled and timing of the drilling may vary based on commodity market conditions. We own various interests, ranging from 16% to 50% interests in the lands to be developed in the program, and expect our share of these capital expenditures to be approximately $120 million. We maintain an acreage position of over 26,000 gross (16,500 net) acres in the Permian Basin in West Texas, primarily in Regan, Upton, Martin and Midland counties. We have currently identified 126 proved undeveloped drilling locations there and believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional drilling location opportunities.

We also continue to explore and consider opportunities to further expand our oilfield servicing revenues through additional investment in field service equipment. As of March 31, 2015, we have $11.8 million outstanding on our equipment financing facilities which are secured by substantially all of our field service equipment, with an additional $700,000 available for the acquisition of new 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 2015. For the three month period ended March 31, 2015, we have spent $1.28 million 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 control over financial reporting that occurred during the first three months of 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

17

Table of Contents

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 three months ended March 31, 2015, the Company purchased the following shares of common stock as treasury shares.

None

None

18

Table of Contents

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

19

Table of Contents

20

Table of Contents

21

Table of Contents

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.

22