PRIMEENERGY RESOURCES CORP 10-K

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. Our common stock is listed and principally traded on the NASDAQ Stock Market under the ticker symbol “PNRG”. The following table presents the high and low prices per share of our common stock during certain periods, as reported in the consolidated transaction reporting system. High Low 2020 First Quarter $ 154.38 $ 47.68 Second Quarter 110.79 49.70 Third Quarter 79.13 62.60 Fourth Quarter 71.80 42.39 2019 First Quarter $ 184.20 $ 70.53 Second Quarter 154.00 118.56 Third Quarter 132.30 106.36 Fourth Quarter 170.99 113.43 The above quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not represent actual transactions. As of March 25, 2021, there were 251 registered holders of the common stock. Provisions of our line of credit agreement restrict our ability to pay dividends. Such dividends may be declared out of funds legally available therefore, when and as declared by our Board of Directors. Issuer Purchases of Equity Securities In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time, in open market transactions or negotiated sales. On October 31, 2012 and June 13, 2018, the Board of Directors of the Company approved an additional 500,000 and 200,000 respectively, shares of the Company’s stock to be included in the stock repurchase program. A total of 3,700,000 shares have been authorized, to date, under this program. Through December 31, 2020, a total of 3,552,279 shares have been repurchased under this program for $74,934,725 at an average price of $21.09 per share. Additional purchases of shares may occur as market conditions warrant. We expect future purchases will be funded with internally generated cash flow or from working capital. 2020 Month Number of Shares Average Price Paid per share Maximum Number of Shares that May Yet Be Purchased Under The Program at Month-End January 3,701 $ 149.30 148,821 February 900 143.31 147,921 March 200 139.68 147,921 April — — 147,921 May — — 147,921 June — — 147,921 July — — 147,921 August — — 147,921 September — — 147,921 October — — 147,921 November — — 147,921 December — — 147,921 Total / Average 4.801 $ 147.78 33 Table of Contents Item 6. SELECTED FINANCIAL DATA We are a smaller reporting company and therefore no response is required pursuant to this Item. Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Report contains additional information that should be referred to when reviewing this material. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements. 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, and Oklahoma. In addition, we own a substantial amount of well servicing equipment. All our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility. We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. 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 to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis. Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices. Market Conditions and Commodity Prices: Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. In addition, our realized prices are further impacted by our derivative and hedging activities. We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs. Index prices for oil,natural gas, and NGLs have improved since the lows of 2020 however we expect prices to remain volatile and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues. Critical Accounting Estimates: Proved Oil and Gas Reserves Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but 34 Table of Contents not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Depreciation, Depletion and Amortization for Oil and Gas Properties The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively. Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. The reserve base includes only proved developed reserves for lease and well equipment costs, which include development costs and successful exploration drilling costs. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Liquidity and Capital Resources: Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of acreage. Net cash provided by operating activities for the year ended December 31, 2020 was $16.4 million, compared to $27.2 million in the prior year. 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 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 to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing. Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2021, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2021 capital budget is reflective of 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 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. The Company maintains a Credit Agreement with a maturity date of February 15, 2023, providing for a credit facility totaling $300 million, with a borrowing base of $40 million. As of April 15, 2021, the Company has $35.95 million in outstanding borrowings and $4.05 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 re-determined estimate of proved oil and gas reserves. The next borrowing base review is scheduled for July 2021. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base. 35 Table of Contents Our credit agreement requires 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 and put agreements for oil and natural gas. 2021 2022 2023 2021 2022 2023 Swap Agreements Natural Gas (MMBTU) 1,219,000 928,000 131,000 $ 2.48 $ 2.67 $ 2.81 Oil (barrels) 157,500 196,200 27,200 $ 53.60 $ 51.99 $ 50.31 Put Agreements Oil (barrels) 30,000 $ 35.00 On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property. The Company’s activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential. In 2016, based upon the results of horizontal wells and historical vertical well performance, we decided to reduce the number of vertical wells in our drilling program and focus primarily on horizontal well drilling. We believe horizontal development of our resource base provides superior returns relative to vertical development, due to the ability of horizontals to come in contact with and drain from a greater volume of reservoir rock over more acreage, with less infrastructure, and thus at a lower cost of development per acre. In 2019, we participated in the drilling of three horizontal wells in Upton County, Texas, adding significantly to our proved reserves, as these probable undeveloped locations were the initial test wells in the Wolfcamp “A” the Jo Mill and the Lower Spraberry of this acreage. These tests proved-up these reservoirs for the 1,280 acre block in which they were drilled and led to the drilling of nine additional wells in 2020 and the first quarter of 2021. In early 2020, six of the nine horizontals mentioned above were drilled, and in the first quarter of 2021 the remaining three were drilled. All nine wells are slated for completion and to be on production by the end of the second quarter of 2021. We have an average 47.5% interest in these wells and our anticipated total investment is expected to be approximately $27 million. The successful development of these reservoirs has also proved-up locations to be drilled on our nearby 3,260-acre block in which the Company holds between 14% and 56% interest. It is anticipated that development of as many as 54 additional horizontal wells on this 3,260-acre block will occur over the coming years. The cost of such development will be approximately $370 million with the Company’s share being approximately $170 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 2020, in Upton County, Texas, we participated for 8.3% interest in the horizontal drilling of a well operated by Pioneer Natural Resources that was completed and on production in July of 2020. Our total net expenditure for this well was approximately $580,000. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility. 36 Table of Contents The Exploration, Development and Recent Activities section in Part I above describes in more detail the recent activities of the Company. The focus of our future activity will be on the continued development of our resource’s potential in the West Texas horizontal drilling program as well as our Scoop-Stack horizontal drilling program acreage in Oklahoma in order to maximize cash flow and return on investment. The Company maintains an acreage position of 19,679 gross (12,461 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties and we believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp that support the potential drilling of as many as 180 additional horizontal wells. In Oklahoma, the Company’s horizontal activity is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,460 net leasehold acres. We believe this acreage has significant additional resource potential that could support the drilling of as many as 52 new horizontal wells based on an estimate of six wells per section: three in the Mississippian and three in the Woodford Shale. Should we choose to participate in future development, our share of the capital expenditures would be approximately $40 million at an average 10% ownership level; the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest. To supplement cash flow and finance our drilling program during 2020, the Company sold or farmed-out leasehold rights through one transaction in Texas, receiving gross proceeds of approximately $10.8 million in exchange for 1950 net leasehold acres specific to certain depths, reserving rights to shallower and deeper formations for future development. The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general. The Company has in place both a stock repurchase program and a limited partnership interest repurchase program. Spending under these programs in 2020 and 2019 was $1,452 thousand and $5.9 million, respectively. The Company expects continued spending under these programs in 2021. Results of Operations: 2020 and 2019 Compared We reported a net loss of $2.3 million for 2020, or $1.16 per share, compared to net income of $3.5 million, or $1.72 per share for 2019. The current year net loss reflects decreases in production combined with commodity price decreases, increases 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, NGL and gas sales decreased $47.0 million, or 56% to $37.0 million for the year ended December 31, 2020 from $84.0 million for the year ended December 31, 2019. Crude oil, NGL and natural gas sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices at the well head decreased an average of $17.02 per barrel, or 30.9% on crude oil, decreased an average of $4.65 per barrel, or 29.3% on NGL and decreased $0.25 per Mcf, or 16.60% on natural gas during 2020 as compared to 2019. Our crude oil production decreased by 509,000 barrels, or 41.0% to 733,000 barrels for the year ended December 31, 2020 from 1,242,000 barrels for the year ended December 31, 2019. Our NGL production decreased by 137,000 or 23.9% to 437,000 for the year ended December 31, 2020 from 574,000 barrels for the year ended December 31, 2019. Our natural gas production decreased by 1,016 MMcf, or 23.1% to 3,381 MMcf for the year ended December 31, 2020 from 4,397 MMcf for the year ended December 31, 2019. The decreases in crude oil, NGL and natural gas production volumes are a result of the natural decline of existing properties combined with the shut in of marginal properties due to low commodity prices, slightly offset by new wells placed in production. 37 Table of Contents The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2020 and 2019 (excluding realized gains and losses from derivatives). Twelve months ended December 31, Increase / (Decrease) Increase / (Decrease) 2020 2019 Barrels of Oil Produced 733,000 1,242,000 (509,000 ) (41.00 )% Average Price Received $ 38.02 $ 55.04 $ (17.02 ) (30.90 )% Oil Revenue (In 000’s) $ 27,865 $ 68,366 $ (40,501 ) (59.20 )% Mcf of Gas Sold 3,381,000 4,397,000 (1,016,000 ) (23.10 )% Average Price Received $ 1.24 $ 1.49 $ (0.25 ) (16.60 )% Gas Revenue (In 000’s) $ 4,202 $ 6,539 $ (2,337 ) (35.70 )% Barrels of Natural Gas Liquids Sold 437,000 574,000 (137,000 ) (23.90 )% Average Price Received $ 11.22 $ 15.87 $ (4.65 ) (29.30 )% Natural Gas Liquids Revenue (In 000’s) $ 4,906 $ 9,110 $ (4,204 ) (46.10 )% Total Oil & Gas Revenue (In 000’s) $ 36,973 $ 84,015 $ (47,042 ) (56.00 )% 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 twelve months ended December 2020 and 2019: Twelve months ended December 31, 2020 2019 Oil derivatives – realized gains (losses) $ 5,697 $ (1,814 ) Oil derivatives – unrealized gains (losses) 161 (2,776 ) Total gains (losses) on oil derivatives $ 5,858 $ (4,590 ) Natural gas derivatives – realized gains 476 90 Natural gas derivatives – unrealized (losses) gains (351 ) 123 Total gains on natural gas derivatives $ 125 $ 213 NGL derivatives – realized gains — 353 NGL derivatives – unrealized losses — (124 ) Total gains on NGL derivatives $ — $ 229 Total gains (losses) on oil, natural gas and NGL derivatives $ 5,983 $ (4,148 ) Prices received for the twelve months ended December 31, 2020 and 2019, respectively, including the impact of derivatives were: 2020 2019 Increase / (Decrease) Increase / (Decrease) Oil Price $ 45.79 $ 53.58 $ (7.79 ) (14.50 )% Gas Price $ 1.38 $ 1.51 $ (0.13 ) (8.40 )% NGL Price $ 11.22 $ 16.49 $ (5.27 ) (31.90 )% 38 Table of Contents Field service income decreased $8.1 million, or 42.1% to $11.1 million for the year ended December 31, 2020 from $19.2 million for the year ended December 31, 2019. This decrease is a combined result of decreased utilization and rates charged to customers as oil and gas prices declined during 2020. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations. Lease operating expenses decreased $10.4 million, or 31.2% to $23.0 million for the year ended December 31, 2020 from $33.5 million for the year ended December 31, 2019. This decrease is primarily due to the shut-in of high lifting cost properties during 2020 combined with lower production taxes related to lower commodity prices. Field service expense decreased $6.4 million, or 41.7% to $9.0 million for the year ended December 31, 2020 from $15.4 million for the year ended December 31, 2019. Field service expenses primarily consist of salaries and vehicle operating expenses which have decreased during 2020 related to decreased utilization of our equipment services. Depreciation, depletion, amortization and accretion on discounted liabilities decreased $8.0 million, or 22.1% to $28.2 million for the year ended December 31, 2020 from $36.2 million for the year ended December 31, 2019. The DD&A expense is primarily attributable to our properties in West Texas and Oklahoma, reflecting the declining cost basis of those properties. General and administrative expense decreased $0.6 million, or 3.91% to $15.0 million for the year ended December 31, 2020 from $15.6 million for the year ended December 31, 2019. This decrease in 2020 reflects cost reductions put in place responding to sharply lower commodity prices. Gain on sale and exchange of assets of $15.8 million for the year ended December 31, 2020 and $4.6 million for the year ended December 31, 2019 consists principally of sales of deep rights in undeveloped acreage in West Texas and marginal wells in West Virginia. Interest expense decreased $1.7 million, or 47.7% to $1.9 million for the year ended December 31, 2020 from $3.6 million for the year ended December 31, 2019. This decrease reflects reduced overall debt for 2020 as compared to 2019. The average interest rate paid on outstanding bank borrowings under its revolving credit facility during 2020 and 2019 were 3.95% and 5.34%, respectively. As of December 31, 2020 and 2019, the total outstanding borrowings under its revolving credit facility were $37.0 million and $53.5 million, respectively. Tax expense of $1.4 and tax benefit of $0.5 million were recorded for the years ended December 31, 2019 and 2020, respectively. The change in our income tax provision was primarily due to the decrease in pre-tax income for the year ended December 31, 2020 and the change in the deferred income tax assets and liabilities related to Alternative Minimum Tax Credit refunds during 2020. Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. We are a smaller reporting company and therefore no response is required pursuant to this Item. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. The consolidated financial statements and supplementary information included in this Report are described in the Index to Consolidated Financial Statements at Page F-1 of this Report. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None.