UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM10-Q

For the Quarterly Period Ended September 30, 2016March 31, 2017

Or

For the Transition Period From                    to                    

Commission File Number0-7406

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  ☒    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 RegulationS-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”,filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The number of shares outstanding of each class of the Registrant’s Common Stock as of November 10, 2016May 11, 2017 was: Common Stock, $0.10 par value 2,293,8642,280,138 shares.

PrimeEnergy Corporation

Index to Form10-Q

September 30, 2016March 31, 2017

PART I—FINANCIAL INFORMATION

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – – Unaudited

(Thousands of dollars, except per share amounts)

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

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTSOF OPERATIONS –Unaudited

Three Months Ended March 31, 2017 and 2016

(Thousands of dollars, except per share amounts)

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

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTSOF COMPREHENSIVE INCOME –Unaudited

NineThree Months Ended September 30,March 31, 2017 and 2016 and 2015

(Thousands of dollars)

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

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTOF EQUITY –Unaudited

NineThree Months Ended September 30, 2016March 31, 2017

(Thousands of dollars)

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

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTSOF CASH FLOWS – – Unaudited

NineThree Months Ended September 30,March 31, 2017 and 2016 and 2015

(Thousands of dollars)

The accompanying notesNotes are an integral part of these condensed consolidated financial statementsCondensed Consolidated Financial Statements

PRIMEENERGY CORPORATION

NOTESTO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016March 31, 2017

(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 Form10-K for the year ended December 31, 2015.2016. In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s condensed consolidated balance sheets as of September 30, 2016March 31, 2017 and December 31, 2015,2016, the condensed consolidated results of operations, for the three and nine months ended September 30, 2016 and 2015, and the condensed consolidated results of cash flows and equity for the ninethree months ended September 30, 2016March 31, 2017 and 2015.2016. 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:Pronouncements

In August 2016, the FASB issued Accounting Standards Update (ASU)2016-15, Statement of Cash Flows (Topic 230). ASU2016-15 seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of ASU2016-15 and assessing the impact, if any, it may have on its statement of consolidated cash flows.

The FASB issued ASU2014-09,Revenue from Contracts with Customers (Topic 606). This ASU supersedes theRevenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic932-605.Extractivies Extractives – 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 ASU2014-09 was delayed through the issuance of ASU2015-14, Revenue from Contracts with Customers – Deferral orof theEffective 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 Costsand 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 aright-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.

In January 2017, the FASB issued ASUNo. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Venture (Topic 323), which states that registrants should consider additional qualitative disclosures if the impact of an issued but not yet adopted ASU is unknown or cannot be reasonably estimated and to include a description of the effect of the accounting policies that the registrant expects to apply, if determined. Transition guidance in certain issued but not yet adopted ASUs, including Leases and Revenue Recognition, was also updated to reflect this amendment. This guidance is effective immediately.

(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 $187,000$60,000 and $101,000$1,000 for the ninethree months ended September 30,March 31, 2017 and 2016, and 2015, respectively.

During the nine months ended September 30, 2016,first quarter of 2017, the Company has sold or farmed out interests in certainnon-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 $28were $46.4 million. The Company has entered into an agreement to sell additional acreage for an additional $4 million during the fourth quarter of 2016.

(3) Restricted Cash and Cash Equivalents:

Restricted cash and cash equivalents include $3.1 million and $3.51$3.54 million at September 30, 2016March 31, 2017 and December 31, 2015, respectively,2016 of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at September 30, 2016March 31, 2017 and December 31, 20152016 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 September 30, 2016March 31, 2017 and December 31, 20152016 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 hashad 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 iswas secured by substantially all of the Company’s oil and gas properties. The credit facility iswas 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

On February 15, 2017, the Company and their valuation. The borrowing base is redetermined semi-annually,its lenders entered into a Third Amended 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 redeterminedRestated Credit Agreement (the “ 2017 Credit Agreement”) with a maximummaturity date of one such request each year. A revisionFebruary 15, 2021. The Second Amended and Restated Credit Agreement and subsequent amendments were incorporated into the 2017 Credit Agreement. Pursuant to PEC’s reserves may prompt such a request on the partterms and conditions of the lenders, which could possibly result in2017 Credit Agreement, the Company has a reduction in the borrowing base and availability under therevolving line of credit facility. At any time if the sum of the outstanding borrowings and letter of credit exposures exceedfacility of up to $300 million subject to a borrowing base that is determined semi-annually by the applicable portionlenders based upon the Company’s financial statements and the estimated value of the Company’s oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. The credit facility is secured y substantially all of the Company’s oil and gas properties. Currently, the Company’s borrowing base PEC would be requiredis $75 million. The 2017 Credit Agreement includes terms and covenants that require the Company to repaymaintain a minimum current ratio, total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio and interest coverage ratio, as defined, and restrictions are placed on the excesspayment of dividends, the amount within a prescribed period.of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.

At September 30, 2016, the credit facility borrowing base was $80 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 September 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 3.50% at September 30, 2016). At September 30, 2016, the Company had in place one LIBO rate loan with an effective rate of 3.77%.

At September 30, 2016,March 31, 2017, the Company had a total of $65$24.8 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 4.49%4.68% and $15$50.2 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.82%5.32% for the ninethree months ended September 30, 2016March 31, 2017 as compared to 3.39%3.61% for the ninethree months ended September 30, 2015.March 31, 2016. The Company’s borrowings under its currentthis credit facility approximates fair value because the interest rates are considered short term debt as the maturity datevariable and reflective of the facility is July 30, 2017.market rates.

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 $217,000$7,070 related to the settlement of interest rate swaps for the ninethree months ended September 30, 2016 and 2015, respectively.March 31, 2016.

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 September 30, 2016,March 31, 2017, the Company had a total of $3.38$3.03 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, with a rate of 3.50% and requiring monthly payments (principal and interest) of $8,700 with a final maturity date of June 26, 2020. As of September 30, 2016,March 31, 2017, the Company had a total of $2.95$2.76 million outstanding on the Additional Equipment Loans. On September 22, 2016, with the lenders permission, the Company made any required installment payments due for the fourth quarter.

The Company paid all installment payments through Decemberdetermined these loans are Level 3 liabilities in the fair-value hierarchy and estimated their fair value as $5.5 million and $8.6 million at March 31, 2016.2017 and 2016, respectively, using a discounted cash flow model.

(7) Other Long-Term Obligations and Commitments:

Operating Leases:

The Company has severalnon-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 20152017 and thereafter for the operating leases are as follows:

Rent expense for office space for the ninethree months ended September 30,March 31, 2017 and 2016 was $181,000 and 2015 was $677,000 and 571,000,$207,000, respectively.

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the ninethree months ended September 30, 2016March 31, 2017 is as follows:

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

(8) Contingent Liabilities:

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

(9) Stock Options and Other Compensation:

In May 1989,non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At September 30,March 31, 2017 and 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 $187,000$60,000 and $101,000$1,000 for the ninethree months ended September 30,March 31, 2017 and 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:Instruments

Fair Value Measurements:

Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2016at March 31, 2017 and December 31, 2015:2016:

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 ninethree months ended September 30, 2016.March 31, 2017.

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 commodity derivative instruments are recognized in earnings.

Interest rate swap derivatives continue to beare treated as cash-flow hedges and are used to fix our floatfloating interest rates on existing debt. The value of these interest rate swaps at September 30, 2016 and December 31, 2015 are located, if applicable, in accumulated other comprehensive loss, net of tax. Settlements of the swaps, which began in January 2014 and concluded in January 2016, arewas recognized within interest expense. There were no remaining interest rate swaps for the periods ending March 31,2017 and December 31, 2016.The value of interest rate swaps if applicable, would be recorded in accumulated other comprehensive loss, net of tax.

The following table sets forth the effect of derivative instruments on the condensed consolidated balance sheets at September 30, 2016March 31, 2017 and December 31, 2015:2016:

The following table sets forth the effect of derivative instruments on the condensed consolidated statementstatements of operations for the nine-month periodsthree month period ended September 30, 2016March 31, 2017 and 2015:2016:

(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:

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.

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 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 acreage to supplement cashflow and finance our drilling program. Proceeds from these transactions through September 30, 2016 were approximately $28 million and during the fourth quarter of 2016 we have closed on transactions for an additional $4 million.

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 15,000 net acres in 15 counties, with over 4,500 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 Mountain Districts maintain approximately 13,000 net acres held by production.

We are an independent oil and natural gas company engaged in acquiring, developing and producing oil and natural gas. We presently own producing andnon-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.opportunities as well as newer properties with development and exploration potential.

We are the operator of the majority of our developed and undeveloped acreage which is nearly all held by production. In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of over 21,160 gross (13,020 net) acres, approximately 91% of which is in Reagan, Upton, Martin and Midland counties of Texas where our current horizontal drilling activity is focused. We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 250 additional horizontal wells. In Oklahoma we maintain an acreage position of approximately 77,741 gross (14,512 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady and Garvin counties. We believe approximately 2300 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 78 new horizontal wells based on an estimate of only two wells per section, with our share of such prospective future development being about $42 million based on an average 10.5% ownership level.

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 flows generated from our operations, through our producing oil and gas properties, our field services business, and from sales ofnon-core acreage.

The Company will continue to pursue the acquisition of leasehold acreage and producing properties in areas where we currently operate and believe there is additional exploration and development potential and will attempt to assume the position of operator in all such acquisitions. 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.

RECENT ACTIVITIES

WeOur West Texas, horizontal drilling program, which began in 2015, includes eight wells drilled, completed and placed on production as of December 31, 2016. Drilling activity has continued in the first quarter of 2017 with the Company participating in an additional 19 horizontal wells, eight of which were placed on production by March 31, 2017, and eleven that are in various stages of being drilled, completed, or are waiting on hydraulic fracture stimulation. In addition, we anticipate the drilling of eight more horizontal wells in 2017. This additional activity brings the anticipated total to 27 horizontal wells that are expected to be drilled in 2017 in our West Texas horizontal drilling program. The Company is also participating for less than 1% interest in thirteen other horizontal wells.

In Upton County, horizontal drilling program during 2015 and through the third quarter of 2016Texas, we have drilled 5 wells in this phase. Discussionsare developing a contiguous 3,900 acre block with our joint venture partner, in that program, Apache Corporation, where the Company holds approximately 48% interest in 2,606 gross acres. Through yearend 2016, six wells had been drilled and completed. In the first quarter of 2017, an additional eleven wells were spud and are in the process of being drilled or completed. Approximately $82 million will be invested in this group of wells, of which the Company’s share will be approximately $27.9 million. Apache drilling-plans indicate that includingan additional six wells will be drilled later this year at a cost of $38.9 million, of which our share is approximately $12.4 million. Apache Corporation has indicated plans to Pad drill the acreage and projects future phases of development the program will result in approximately 60 horizontal wells being drilled at a cost of approximatelyabout $470 million. We own various interests ranging from 16% up14% to 50% interest49% in the lands to be developed in the program,this project and expect our share of these capital expenditures to be approximately $120 million. The actualtotal number of wells tothat will be drilled and the timing of the drilling may vary based on drilling

schedule and commodity market conditions.prices. Also in Upton County, the Company is participating for 4% interest with 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 producing on an ESP at approximately 850 barrels of oil and 1,500 Mcf of gas per day.

We are also participating in the drillingdevelopment of a 640 acre block where six other West Texas horizontal wells that had been drilled in which we hold a 4.15% interest and expect our share2016, were placed on production in the first quarter of drilling and completion costs to be $1 million. Currently four of those wells are awaiting completion and two are in their final drilling stage.

During2017. In 2016, we commenced our Martin County, Texas horizontal drilling program with the drilling of two wells that began production in July, 2016. These wells were drilled on a 960 acre block that the Company is developing with RSP Permian. An additional two wells, spud in 2016, were placed on production in the first quarter of 2017. The Company owns 35% interest in these two wells. RSP Permian drilling-plans indicate an additional two wells will be drilled in 2017, however, definitive plans have not yet been received.

The Company maintains an acreage position of approximately 21,160 gross (13,020 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Midland and Martin counties. We believe this acreage has significant resource potential in multiple Spraberry and Wolfcamp intervals that support the potential drilling of as many as 250 additional wells.

Our Oklahoma horizontal development program, which began in 2012, has, through the first quarter of 2017 participated in 24 horizontal wells for approximately $23 million. Over this same time period the Company chose to retain an overriding royalty interest in 21 other horizontal wells. In the first quarter of 2017, we participated in two horizontal wells, one vertical well and retained an over-riding royalty interest in one other horizontal well. The Company participated with 17.6% interest in the drilling of a horizontal well in Canadian County operated by RSP Permian, two wells haveDevon Energy that was spud in November of 2016 and has been drilledcompleted and are currently producing. One well was placed on production June 21, 2016in early April 2017. The Company is currently participating with 11.8% interest in a horizontal well being drilled by Marathon Oil Company in Kingfisher County. This well was spud in February and is anticipated be completed and on production in the second quarter of 2017. Our share of this well was placed on production July 7, 2016. Two additional wells are currentlywill be approximately $1 Million. In addition, the Company is participating for 50% interest in a vertical well in Garvin County that has been drilled and is in the drilling phase and we expect themprocess of being tested. Our share of the cost of this will is expected to be completedapproximately $1.3 Million. One interval in this well is currently being tested and further completion work is anticipated for the second quarter of 2017. Also in the first quarter of 2017, atthe Company chose to retain an ORRI in a total costhorizontal well drilled in Garfield County that has been drilled and placed on production, and also chose to sell certain leasehold rights and instead retain an ORRI in a particular acreage block in Canadian County where eight horizontal wells are likely to be drilled in the future.