UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period Ended June 30, 2018

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  ☒    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  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “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 Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The number of shares outstanding of each class of the Registrant’s Common Stock as August 15, 2018 was: Common Stock, $0.10 par value 2,061,963 shares.

PrimeEnergy Corporation

Index to Form 10-Q

June 30, 2018

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PART I—FINANCIAL INFORMATION

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – Unaudited

(Thousands of dollars)

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – Unaudited

Three and six months ended June 30, 2018 and 2017

(Thousands of dollars, except per share amounts)

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF EQUITY – Unaudited

Six months ended June 30, 2018 and 2017

(Thousands of dollars)

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited

Six months ended June 30, 2018 and 2017

(Thousands of dollars)

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

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PRIMEENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

(1) Basis of Presentation:

The accompanying condensed consolidated financial statements of PrimeEnergy Corporation (“PrimeEnergy” 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, 2017. 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, 2018 and December 31, 2017, the condensed consolidated results of operations, cash flows and equity for the six months ended June 30, 2018 and 2017.

As of June 30, 2018, PrimeEnergy’s significant accounting policies are consistent with those discussed in Note 1—Description of Operations and Significant Accounting Policies of its consolidated financial statements contained in PrimeEnergy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, with the exception of Accounting Standards Update (ASU) 2014-09, “Revenue from Contracts with Customers (Topic 606)” discussed below. 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 Adopted Accounting Pronouncements

On January 1, 2018, PrimeEnergy adopted ASU 2014-09, “Revenue from Contracts with Customers (ASC 606),” using the modified retrospective method. The Company elected to evaluate all contracts at the date of initial application. While there was no impact to the opening balance of retained earnings as a result of the adoption, certain items previously netted in revenue are now recognized as lease operating expense in the Company’s statement of consolidated operations. The amounts are immaterial to the financial statements, and prior comparative periods have not been restated and continue to be reported under the accounting standards in effect for those periods. Adoption of the new standard is not anticipated to have a material impact on the Company’s net earnings on an ongoing basis.

The Company applies the provisions of ASC 606 for revenue recognition to contracts with customers. Sales of crude oil, natural gas, and natural gas liquids (NGLs) are included in revenue when production is sold to a customer in fulfillment of performance obligations under the terms of agreed contracts. Performance obligations primarily comprise delivery of oil, gas, or NGLs at a delivery point, as negotiated within each contract. Each barrel of oil, million Btu (MMBtu) of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, the Company’s right to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant.

PrimeEnergy records trade accounts receivable for its unconditional rights to consideration arising under sales contracts with customers. The carrying value of such receivables, net of the allowance for doubtful accounts, represents estimated net realizable value. The Company routinely assesses the collectability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. PrimeEnergy has concluded that the disaggregation of revenue by product appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.

Practical Expedients and Exemptions

PrimeEnergy does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

PrimeEnergy will utilize the practical expedient to expense incremental costs of obtaining a contract if the expected amortization period is one year or less. Costs to obtain a contract with expected amortization periods of greater than one year will be recorded as an asset and will be recognized in accordance with ASC 340, “Other Assets and Deferred Costs.” Currently, the Company does not have contract assets related to incremental costs to obtain a contract.

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New Pronouncements Issued But Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted; however, the Company does not intend to early adopt. In January 2018, the FASB issued a proposed ASU update that would add a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. If finalized, comparative reporting would not be required and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. In the normal course of business, the Company enters into various lease agreements for office space and equipment related to its exploration and development activities that are currently accounted for as operating leases. At this time, the Company cannot reasonably estimate the financial impact this will have on its consolidated financial statements; however, the Company believes adoption and implementation of this ASU will not significantly impact its balance sheet.

(2) Acquisitions and Dispositions:

Historically the Company has repurchased the interests of the partners and trust unit holders in the oil and gas limited partnerships (the “Partnerships”) and the 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 $10,000 and $60,000 for the six months ended June 30, 2018 and 2017, respectively.

During the six months ended June 30, 2018, the Company sold or 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 Oklahoma, Kansas, Colorado and Texas. Proceeds under these agreements were $2.8 million. During this same time period the Company acquired approximately 464 net mineral acres and working interest in 53 oil and gas wells ranging from 16.6% to 33.4%, plus one commercial salt water disposal well, for $6,080,000. This acreage and group of wells are all operated by the Company and located in Reagan County, Texas, where future horizontal drilling will likely occur.

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3) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

(4) Property and Equipment:

Property and equipment at June 30, 2018 and December 31, 2017 consisted of the following:

(5) Long-Term Debt:

Bank Debt:

On February 15, 2017, the Company and its lenders entered into a Third Amended and Restated Credit Agreement (the “2017 Credit Agreement”) with a maturity date of February 15, 2021. The Second Amended and Restated Credit Agreement and subsequent amendments were amended and restated by the 2017 Credit Agreement. Pursuant to the terms and conditions of the 2017 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $300 million subject to a borrowing base that is determined semi-annually by the lenders 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 by substantially all of the Company’s oil and gas properties. The 2017 Credit Agreement includes terms and covenants that require the Company to maintain 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 payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.

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On December 22, 2017, the Company and its lenders entered into a First Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes the addition of a new lender and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $85 million.

On July 17, 2018, the Company and its lenders entered into a Second Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes modifications for the borrowing base utilization margins and rates by type of borrowing, revises minimum quantifications for individual borrowings, reduces the overall percentage required for commodity hedge agreements, modifies the requirements placed on the company’s ability to purchase equity interests and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $90 million.

At June 30, 2018, the Company had a total of $59.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 5.59% and $25.5 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 5.38% for the six months ended June 30, 2018 as compared to 5.20% for six months ended June 30, 2017. The Company’s borrowings under this credit facility approximates fair value because the interest rates are variable and reflective of market rates.

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, 2018 the Company had a total of $179 thousand 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. 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 June 30, 2018, the Company had a total of $1.302 million outstanding on the Additional Equipment Loans.

On January 12, 2018, the Company made a principal payment towards the third interim loan in the amount of $20,858. Effective with the payment due of January 26, 2018 the required monthly payments (principal and interest) on this loan changed to $7,986 with a continuing effective rate of 3.50% and a final maturity of June 26, 2020.

The Company determined these loans are Level 3 liabilities in the fair-value hierarchy and estimated their fair value as $1.346 million and $4.751 million at June 30, 2018 and 2017, respectively, using a discounted cash flow model.

(6) 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 2018 and thereafter for the operating leases are as follows:

Rent expense for office space for the six months ended June 30, 2018 and 2017 was $296,000 and $340,000, respectively.

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Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the six months ended June 30, 2018 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.

(7) 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.

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.

(8) 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, 2018 and 2017, 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.

(9) 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 and Trusts. The Company purchased interests totaling $10,000 and $60,000 for the six months ended June 30, 2018 and 2017, respectively.

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.

(10) 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 natural gas, crude oil price swaps and natural gas liquid swaps are designated

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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 at June 30, 2018 and December 31, 2017:

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 , crude oil, natural gas liquids, 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 six months ended June 30, 2018.

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.

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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.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at June 30, 2018 and December 31, 2017:

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The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the six month period ended June 30, 2018 and 2017:

(11) 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 and West Virginia. 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 the majority of our developed and undeveloped acreage which is nearly all held by production. In the Permian Basin of West Texas the Company maintains an acreage position of over 20,440 gross (13,100 net) acres, approximately 95% of which is located in Reagan, Upton, Martin and Midland counties of Texas where our current horizontal drilling activity is focused. Our West Texas acreage has significant resource potential in the Spraberry and Wolfcamp reservoirs that we believe could support the drilling of as many as 400 additional horizontal wells.

In Oklahoma we maintain an acreage position of approximately 82,012 gross (10,947 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 2,215 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 73 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.

District Information

The following table represents certain reserve and well information as of December 31, 2017.

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Reserve Information:

All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:

The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2017, are summarized as follows (in thousands of dollars):

The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV 10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV 10 of future income taxes represents the sole reconciling item between this non-GAAP PV 10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.

In accordance with SEC rules governing the scheduling of the drilling of PUD reserves we have only included in our year-end reserve report the 22 PUD locations for which we have definitive plans to drill. The Company has a working interest in eight of these PUD locations and an overriding royalty interest only in the remaining fourteen locations. Currently all 22 of these PUD locations have been drilled, 13 are producing and the remainder are awaiting completion.

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 operations, through our producing oil and gas properties, our field services business, and from sales of non-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.

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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.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2018, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2018 capital budget is reflective of current 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.

RECENT ACTIVITIES

Since the start of our West Texas horizontal drilling program in 2015 and through the 2^nd quarter of 2018, the Company has participated in 56 horizontal wells in West Texas. In 41 of these wells, the Company owns an average of 23.82% working interest and all 41 wells are on production. As to 15 wells of the 56 total, the Company participated with less than 1% working interest and these are also all on production. During 2017, the Company expended approximately $46.4 million in this program. Development of our West Texas resources continued in the first six months of 2018 with the drilling of three horizontal wells in Upton County Texas. These wells were recently fracture stimulated and as of July 1, have all been placed on production. Development plans for the second half of 2018 include drilling an additional 11 horizontal wells. This additional activity will bring the total drilling to 14 horizontal wells in 2018 in our West Texas horizontal drilling program.

In Upton County, Texas, we are developing a contiguous 3,900 acre block with our joint venture partner, Apache Corporation. Within this acreage block, the Company has 2,606 leasehold acres with interest between 14% and 56%, depending on the formation being developed. Through the 2nd quarter of 2018, twenty-five wells have been drilled and completed in this joint venture, including three wells completed and put on production as of July 1, 2018. The Company has a 38.25% interest in each of these three wells and our net cost will be approximately $10.1 million. Apache Corporation has indicated plans to continue PAD drilling of the acreage with future phases of development expected to result in the drilling of approximately 96 additional horizontal wells at a cost of about $748 million. The Company’s share of these capital expenditures would be approximately $284 million. The actual number of wells that will be drilled, the cost, and the timing of drilling will vary based upon many factors, including commodity market conditions. Also in Upton County, Texas, the Company is developing a separate 1,310 acre block with Apache Corporation as operator. Plans for the second half of 2018 include the drilling of three new horizontal wells exploring landing-zones outside of the Middle Wolfcamp. The gross drilling and completion costs will be approximately $23 million. Prime holds between 28% and 48% working interest in various depths of this acreage and our share of these three wells will be approximately $11 million. With favorable results from these three wells an additional 21 wells would likely be drilled in the near future at a gross cost of approximately $172 million with the Company’s share being approximately $71 million.

In Martin County, Texas we are developing a 960 acre block with RSP Permian. In 2016, two wells were drilled and completed and two additional wells were drilled and brought on line in 2017. The Company owns 35% to 38% interest in the acreage of this joint venture where RSP Permian is the operator. No near-term plans have been received from RSP Permian, however, offset operators have been actively drilling and their results appear encouraging for the future development of multiple landing zones within this acreage block.

With regard to our Oklahoma horizontal development program, which began in 2012, the Company has participated in 30 horizontal wells for approximately $28 million through June, 2018. Over this same time period the Company chose to retain an overriding royalty interest in 28 other horizontal wells that were drilled. In the first half of 2018 the Company participated in two horizontal wells operated by Linn Operating Inc. in Grady County, Oklahoma. The Company holds 10% interest in one well and 1% interest in the other. The cost for these wells is approximately $14,703,000, with our net share being $828,000. Both wells have been drilled, completed and placed on production. Also in 2018, the Company elected to retain an ORRI in 16 wells that are in the process of being drilled or completed in various counties of central Oklahoma. In the second half of 2018 the Company anticipates participating in the drilling of as many as five additional horizontal wells in central Oklahoma with interest between 6% and 12%. The horizontal activity on Company acreage in Oklahoma is primarily focused in Canadian, Grady, Kingfisher and Garvin counties where we have approximately 2,215 net acres. We believe this acreage has significant additional resource potential that could support the drilling of 73 new horizontal wells based on an estimate of only two wells per section with our share of the capital expenditure being about $42 million at an average 10.5% ownership level. We recently received Authorizations for Expenditures for four horizontal wells in Kingfisher county from the operator, Marathon Oil. Our share of this drilling will be approximately $5 million.

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In the first half of 2018, in the Gulf Coast region of Texas, Unit Petroleum drilled and completed two successful wells in the Wilcox Formation of the Segno Deep field in Polk County. The Company has a 3.87% overriding royalty interest in each of these wells.

RESULTS OF OPERATIONS

2018 and 2017 Compared

We reported a net income for the six months ended June 30, 2018 of $2.7 million, or $1.29 per share and a net loss for the three months ended June 30, 2018 of $0.6 million, or $0.27 per share, as compared to net income of $22.7 million, or $10.11 per share and $0.4 million, or $0.16 per share for the six and three months ended June 30, 2017, respectively. Current year net income reflects an increase in production combined with commodity price changes over the three and six months ended June 30, 2018, decrease in gains related to the sale of acreage and changes related to the valuation of derivative instruments. The significant components of income and expense are discussed below.

Oil, gas and NGLs sales increased $7.7 million, or 55% from $14.0 million for the three months ended June 30, 2017 to $21.7 million for the three months ended June 30, 2018 and increased $20.3 million, or 77% from $26.4 million for the six months ended June 30, 2017 to $46.8 million for the six months ended June 30, 2018.

Our realized prices at the well head increased an average of $18.39 per barrel, or 41% and $15.72 per barrel, or 33% on crude oil during the three and six months ended June 30, 2018, respectively from the same periods in 2017. Our average price for natural gas decreased $0.95 per Mcf, or 32% and $0.72 per Mcf, or 24% during the three and six months ended June 30, 2018, respectively from the same periods in 2017. Our average price for NGLs sold increased an average of $4.06 per barrel, or 17% and $5.23 per barrel, or 24% during the three and six months ended June 30, 2018, respectively from the same periods in 2017.

Our crude oil production increased by 35,000 barrels or 15% from 226,000 barrels for the second quarter 2017 to 261,000 barrels for the second quarter 2018 and increased by 183,000 barrels, or 46% from 401,000 barrels for the six months ended June 30, 2017 to 584,000 barrels for the six months ended June 30, 2018. Our natural gas production increased by 19,000 Mcf, or 1.8% from 1,079,000 Mcf for the second quarter 2016 to 1,060,000 Mcf for the second quarter 2017 and increased by 177,000 Mcf, or 10% from 1,694000 Mcf for the six months ended June 30, 2017 to 1,871,000 Mcf for the six months ended June 30, 2018. Our NGL production increased by 76,000 barrels or 50.7% from 150,000 barrels for the second quarter 2016 to 226,000 barrels for the second quarter 2017 and increased by 103,000 barrels, or 94% from 110,000 barrels for the six months ended June 30, 2017 to 213,000 barrels for the six months ended June 30, 2018. The increase in production volumes reflect production from our Upton county horizontal wells added in late 2017, offset with the natural decline of the previously existing properties. Production from these horizontal wells was negatively affected in the second quarter of 2018 due to shut-ins and frac hits from completion activities on additional wells drilled in the first quarter of 2018 and completed in the second quarter. The affected wells have now returned to pre-frac hit levels and the new wells were brought on production primarily in July 2018.

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Oil, Natural Gas and NGL Derivatives 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. The following table summarizes the results of our derivative instruments for the three and six months ended June 2017 and 2018:

Prices received for the six months ended June 30, 2018 and 2017, respectively, including the impact of derivatives were:

Field service income increased $0.1 million or 3.3% from $4.3 million for the second quarter 2017 to $4.4 million for the second quarter 2018 and $0.6 million, or 7.4% from $8.1 million for the six months ended June 30, 2017 to $8.7 million for the six months ended June 30, 2018. This increase is a combined result of increased utilization and rates charged to customers during the 2018 period. Workover rig services, hot oil treatments, salt water hauling and disposal represent the bulk of our field service operations.

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Lease operating expense increased $1.6 million, or 22.4% from $7.2 million for the second quarter 2017 to $8.8 million for the second quarter 2018 and increased $3.0 million, or 21.1% from $14.3 million for the six months ended June 30, 2017 to $17.3 million for the six months ended June 30, 2018. This increase is primarily due to costs related to new wells brought on-line, general rate increases on vendor services and increased production taxes related to increased prices and production during the first six months of 2018 as compared to the same period of 2017.

Field service expense increased $0.2 million or 5.7% from $3.0 million for the second quarter 2017 to $3.2 million for the second quarter 2018 and increased $0.4 million, or 6.7% from $6.0 million for the six months ended June 30, 2017 to $6.4 million for the six months ended June 30, 2018. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased during the six months ended June 30, 2018 over the same period of 2017 as a direct result of increased services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities decreased $0.1 million, or 1.3% from $8.0 million for the second quarter 2017 to $7.9 million for the second quarter 2018 and $0.2 million, or 1.3% from $16.0 million for the six months ended June 30, 2017 to $15.8 million for the six months ended June 30, 2018, reflecting the increased reserve base and production related to new wells placed on production late in 2017.

General and administrative expense increased $4.2 million, or 96% from $4.4 million for the six months ended June 30, 2017 to $8.5 million for the six months ended June 30, 2018, and decreased $50 thousand, or 1.9% from $2.62 million for the three months ended June 30, 2017 to $2.57 million for the three months ended June 30, 2018. This increase in 2018 reflects the combination of a reduction in reimbursements related to the decrease in gains on sales of properties from 2017 to 2018 and increases in personnel costs.

Gain on sale and exchange of assets of $2.7 million and $41.7 million for the six months ended June 30, 2018 and June 30, 2017, respectively consists of sales of non-essential oil and gas interests and field service equipment.

Interest expense increased from $0.5 million for the second quarter 2017 to $0.9 million for the second quarter 2018 and from $1.1 million for the six months ended June 30, 2017 to $1.8 million for the six months ended June 30, 2018. This increase reflects the increase in current borrowings under our revolving credit agreement.

Income tax expense decreased $12.9 million due to a lower effective tax rate and lower pre-tax income. The effective tax rates for the six months of 2018 and 2017 were 25.12% and 32.86%, respectively. The decrease in the effective tax rate is primarily due to the impact of the Tax Cuts and Jobs Act changes that are effective January 1, 2018.

LIQUIDITY AND CAPITAL RESOURCES

Our primary sources of liquidity are cash flows generated from operations, through our producing oil and gas properties, field services business and from sales of non-core acreage.

Net cash used in our operating activities for the six months ended June 30, 2018 was $7.4 million compared to $14.5 million provided by operating activities for the six months ended June 30, 2017. 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, we will be able to access sufficient additional capital through bank financing.

We currently maintain a credit facility totaling $300 million, with a borrowing base of $90 million. The Company currently has $64 million in outstanding borrowings and $26 million in availability under this facility. 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 2018. 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

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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 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 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 credit agreement required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. Accordingly the Company has in place the following swap agreements for oil, natural gas and natural gas liquids.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2018, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2018 capital budget is reflective of current 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.

We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2018. For the six month period ended June 30, 2018, we have spent $3.7 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.