PNRG PrimeEnergy Resources Corporation

PART I—FINANCIAL INFORMATION

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

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PRIMEENERGY CORPORATION

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 ASU 2018-01, which permits an entity an optional election to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases prior to the adoption of ASU 2016-02. In July 2018, the FASB issued ASU 2018-11, which adds 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. Under this transition option, 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. The Company intends to elect both transitional practical expedients.

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.

In June 2018, the FASB issued ASU 2018-07, “Improvements to Nonemployee Share-Based Payment Accounting,” to simplify the accounting for share-based transactions by expanding the scope of Topic 718 from only being applicable to share-based payments to employees to also include share-based payment transactions for acquiring goods and services from nonemployees. As a result, the same guidance that provides for employee share-based payments, including most of the requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. ASU 2018-07 is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted. The Company anticipates adopting this guidance for the first quarter of 2019 and does not expect it to have a material impact on its consolidated financial statements.

In August 2018, the FASB issued ASU 2018-13, “Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement,” which changes the disclosure requirements for fair value measurements by removing, adding, and modifying certain disclosures. ASU 2018-13 is effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted. The company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.

In August 2018, the FASB issued ASU 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract.” This pronouncement clarifies the requirements for capitalizing implementation costs in cloud computing arrangements and aligns them with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. This pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. The Company is currently evaluating the impact of adoption of this ASU on its consolidated financial statements and does not expect it to have a material impact.

(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 nine months ended September 30, 2018 and 2017, respectively.

During the nine months ended September 30, 2018, The Company sold or farmed out interests in certain non-core undeveloped and developed oil and natural gas properties through a number of individually negotiated transactions in exchange for cash and a royalty or working interest in Oklahoma, Kansas, Colorado, Texas and Wyoming. Proceeds under these agreements were $3.0 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 a total of $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 September 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 companies’ 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 September 30, 2018, the Company had a total of $56.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 5.22% and $33.5 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 5.30% for the nine months ended September 30, 2018 as compared to 4.98% for nine months ended September 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 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, 2018, the Company had a total of $1.025 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 $922 thousand and $3.941 million at September 30, 2018 and 2017, respectively, using a discounted cash flow model.

(6) Other Long-Term Obligations and Commitments:

Rent expense for office space for the nine months ended September 30, 2018 and 2017 was $396,000 and $509,000, respectively.

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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 September 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 nine months ended September 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.

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(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 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 September 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 nine months ended September 30, 2018.

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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.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at September 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 nine month period ended September 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:

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

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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 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 in the remaining fourteen locations. Currently all 22 of these PUD locations have been drilled, and 20 are producing.

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. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements.

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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 3rd quarter of 2018, the Company has participated in 64 horizontal wells in West Texas; 46 of these were completed and producing by year-end 2017, and 10 more have been brought on-line in the first nine months 2018. Of the total 64 wells drilled and producing, the Company has an average of 28% interest in 49 wells, and less than one percent interest in 15 wells. Of the 10 wells brought on production in the first nine months of 2018, three are two-mile long horizontal laterals. The Company has 38.25% interest in these three wells and invested approximately $10.1 million. As to the remaining seven wells brought on production in the first nine months of 2018, the Company has less than 1% interest. In the 3 ^rd quarter of 2018, PrimeEnergy is participating in eight new horizontals wells, each having a one mile long lateral. The Company has 49% interest in these wells and will invest approximately $22.7 million including for production facilities. We anticipate these eight wells to be on line in the 1st quarter of 2019.

In Upton County, West Texas, we are developing a contiguous 3,900 acre block with our joint venture partner, Apache Corporation. In this block the Company has 2,543 leasehold acres with interest between 14% and 56%, depending on the formation or depth being developed. Through the 3rd quarter of 2018, 25 wells have been drilled and completed in this joint venture, including three two-mile long horizontals completed and put on production as of July 1, 2018. In addition, the Company is participating for 49% interest in eight wells that are in the process of being drilled and completed. 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 approximately $748 million in the contiguous 3900 acre block. The Company’s share of these future 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 4th quarter of 2018 include the drilling of three new horizontal wells that will develop target pay intervals other than the middle Wolfcamp. The gross drilling and completion costs for these three wells will be approximately $26 million. Prime holds between 5% and 48% working interest in various depths of this acreage and our share of these three wells will be approximately $8.5 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 $182 million with the Company’s share being approximately $60 million.

In Martin County, Texas we are developing a 960 acre block with Concho Resources. 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 this joint venture acreage where Concho Resources is the operator. No near-term additional drilling plans have been received from Concho Resources, 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 41 horizontal wells for approximately $35 million through September, 2018. Over this same time period the Company chose to retain an overriding royalty interest in 29 other horizontal wells that were being drilled. In the first nine months of 2018, the Company has participated in eleven wells to be completed this year at a net cost of $8.5 million. Also in the first nine months of 2018, the Company elected to retain an ORRI in 22 wells that are in the process of being drilled or completed located in various counties of central Oklahoma. In the 4th quarter of 2018 the Company anticipates participating in the drilling of six additional horizontal wells in central Oklahoma with interest of less than one percent. 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 63 new horizontal wells based on an estimate of only two wells per section with our share of the capital expenditure being approximately $33.3 million at an average 10.5% ownership level.

In the first nine months of 2018, in the Gulf Coast region of Texas, Unit Petroleum drilled and completed two successful wells and recompleted a third well in the Wilcox Formation of the Jazz field in Polk County. The Company has a 3.87% overriding royalty interest in both of the newly drilled wells and a 1.575% overriding royalty interest in the recompleted well. In addition, the Company successfully recompleted a shallow well in the Segno field of Polk County, Texas in which the company has a 72.5% working interest.

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RESULTS OF OPERATIONS

2018 and 2017 Compared

We reported a net income for the nine months ended September 30, 2018 of $7.1 million, or $3.38 per share and net income for the three months ended September 30, 2018 of $4.4 million, or $2.10 per share, as compared to net income of $20.6 million, or $9.29 per share and a loss of $2 million, or $(0.92) per share for the nine and three months ended September 30, 2017, respectively. Current year net income reflects an increase in production combined with commodity price changes over the three and nine months ended September 30, 2017, 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 $14.4 million, or 114.4% from $12.6 million for the three months ended September 30, 2017 to $27 million for the three months ended September 30, 2018 and increased $34.8 million, or 89% from $39 million for the nine months ended September 30, 2017 to $74 million for the nine months ended September 30, 2018.

Our realized prices at the well head increased an average of $18.04 per barrel, or 40% and $16.48 per barrel, or 35% on crude oil during the three and nine months ended September 30, 2018, respectively from the same periods in 2017. Our average price for natural gas decreased $0.24 per Mcf, or 9% and $0.55 per Mcf, or 19% during the three and nine months ended September 30, 2018, respectively from the same periods in 2017. Our average price for NGLs sold increased an average of $10.84 per barrel, or 51% and $7.27 per barrel, or 34% during the three and nine months ended September 30, 2018, respectively from the same periods in 2017.

Our crude oil production increased by 142,000 barrels or 75% from 190,000 barrels for the third quarter 2017 to 332,000 barrels for the third quarter 2018 and increased by 325,000 barrels, or 55% from 591,000 barrels for the nine months ended September 30, 2017 to 916,000 barrels for the nine months ended September 30, 2018. Our natural gas production decreased by 41,000 Mcf, or 4% from 947,000 Mcf for the third quarter 2017 to 906,000 Mcf for the third quarter 2018 and increased by 136,000 Mcf, or 5% from 2,641,000 Mcf for the nine months ended September 30, 2017 to 2,777,000 Mcf for the nine months ended September 30, 2018. Our NGL production increased by 49,000 barrels or 68% from 72,000 barrels for the third quarter 2017 to 121,000 barrels for the third quarter 2018 and increased by 152,000 barrels, or 83.5% from 182,000 barrels for the nine months ended September 30, 2017 to 334,000 barrels for the nine months ended September 30, 2018. The increase in production volumes reflect production from our Upton county horizontal wells added in late 2017 and mid 2018, offset with the natural decline of the previously existing properties.

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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 nine months ended September 2018 and 2017: