PRIMEENERGY RESOURCES CORP (PNRG)

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 of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.

We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. 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 been volatile in recent years 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.

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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 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.

Asset Retirement Obligation (ARO):

The Company has significant obligations to remove tangible equipment and restore land at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value

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, and available capacity under our revolving credit facility.

Net cash provided by operating activities for the year ended December 31, 2024, was $115.9 million compared to $109.0 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 2025, we will continue our focus on preserving financial flexibility and liquidity as we manage the risks facing our industry. Our 2025 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.

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The Company maintains a Credit Agreement with a maturity date of December 20, 2028, providing for a credit facility totaling $300 million, with a borrowing base of $115 million. As of April 8, 2025, the Company had $17.5 million in outstanding borrowings and $97.5 million in availability under this facility. The bank reviews the borrowing base semi-annually and, at its 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 June 2025. 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.

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. The credit agreement requires that as of the last day of any fiscal quarter, if the borrowing base utilization percentage on such a date is less than 15%, then the borrower shall not be required to enter into any swap agreements. As of the quarter ended December 31, 2024, the Company had $4 million in outstanding borrowings and $111 million in availability. Accordingly, the Company had no swap agreements in place for oil and natural gas.

Development and Other Activities

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. Horizontal development of our resource base provides superior returns relative to vertical development due to the ability of each horizontal wellbore to come in contact with a greater volume of reservoir rock across a greater distance, more efficiently draining the reserves with less infrastructure and thus at a lower cost per acre.

In 2024, the Company invested $113 million in 48 horizontals in West Texas: 47 of these are located in Reagan County and one is located in Upton County. In Reagan County, the Company joined Double Eagle in drilling and completing 33 new horizontal wells: on the “Honey RF” tract we completed 12 horizontals each being two-mile-long laterals, and participated with 50% interest investing $37 million; on the “Prime West” tract we have 50% interest in six wells and invested $20.5 million; on both the “Kramer” and “O’Bannion” tracts we participated in six horizontals, each with an average 8.3% interest and we invested approximately $7.8 million; and on the “Pink Floyd” tract we have less than 1% interest in two wells in which we invested approximately $174,900; and on our“Studley AV” tract we participated with Double eagle in testing the Wolfcamp “D” interval; in this well we have about 6.3% interest and invested approximately $600,000. Also in Reagan County, we participated with Civitas in 14 horizontal wells on the “Christi” tract, carrying an average of 39% interest and investing roughly $46.7 million. Also in 2024, in Upton County, we participated with Pioneer Natural Resources in one 2-mile-long horizontal with 3.94% interest, investing approximately $425,700. Of these 48 wells, 32 are 2-mile-long laterals, 14 are 2.5-mile-long laterals, and two are 3-mile-long laterals.

In addition to this activity, in June of 2024, we began participation with Apache in the drilling of six additional 3-mile-long laterals in Upton County on our “Mt. Moran” tract. Three of these wells were completed in late December 2024 and three were completed in January of 2025. All six new “Mt. Moran” wells are producing as of April 1, 2025. In these six Mt. Moran wells, the Company has an average of 51.16% interest and will in total invest approximately $40.5 million. In addition, in November of 2024, in Reagan County, we began participating with Double Eagle in 15 “OG” horizontal wells: eight are 2.5-mile-long laterals, and seven are 2-mile-long laterals. In each of these 15 “OG” wells the Company has approximately 23% interest and in total will invest roughly $29 million through completion of production facilities. These 15 horizontals are expected to be on production in mid to late April 2025. By the end of the second quarter of 2025, therefore, the Company will have invested approximately $70 million in these additional 21 horizontal wells.

In early March 2025, Ovintiv Mid-Continent spud two “Jennifer 1407” wells in Canadian County, Oklahoma; in these, we will participate for approximately 3.125% interest and invest $408,000. In the second and third quarters of 2025, we are anticipating the start of twenty new horizontals in the Midland Basin of West Texas: 15 wells operated by Double Eagle on our “Full House” tract in Reagan County in which the Company will participate with approximately 31% interest and invest $48.4 million, and five wells operated by ConocoPhillips on our “Schenecker” tract in Martin, County in which we plan to participate for 20.83% interest and invest $11.3 million. In total in these 22 wells, we will invest approximately $60 million.

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During 2024, to supplement cash flow and finance our future drilling programs, the Company sold 120 net mineral acres and 10 surface acres in Midland and Ector counties, Texas. For these, we received $1,386,000 in gross proceeds. In addition, we divested 37 producing and two saltwater injection wells in various counties of New Mexico and Texas. These divestments have extinguished a substantial amount in future plugging liability.  Also in 2024, we sold our South Texas oil field services company, Eastern Oil Well Service, for proceeds of $2.8 million.  Included with this sale were extensive oil field service equipment and transport trucks, as well as two commercial saltwater disposal wells.  Acquisitions in 2024, entailed the purchase of 381 net leasehold acres in West Texas for approximately $3.9 million.

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 a stock repurchase program in place, spending under this program in 2024 and 2023 was $13.4 million and $7.5 million, respectively. The Company expects continued spending under the stock repurchase program in 2025.

Results of Operations

2024 and 2023 Compared

We reported a net income of $55.4 million for 2024, or $31.43 per share, compared to $28.1 million, or $15.19 per share for 2023. The current year net income reflects production increases offset by commodity price decreases. The significant components of income and expense are discussed below.

Oil, NGL and gas sales increased $115 million, or 107.01% to $223.1 million for the year ended December 31, 2024 from $107.7 million for the year ended December 31, 2023. 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 $1.04 per barrel, or 1.35% on crude oil, increased an average of $0.61 per barrel, or 3.11% on NGL and decreased $1.49 per Mcf, or 77.6% on natural gas during 2024 as compared to 2023.

Our crude oil production increased by 1,412,000 barrels, or 123.43% to 2,556,000 barrels for the year ended December 31, 2024 from 1,144,000 barrels for the year ended December 31, 2023. Our NGL production increased by 678,000 or 111.88% to 1,284,000 for the year ended December 31, 2024 from 606,000 barrels for the year ended December 31, 2023. Our natural gas production increased by 3,639 MMcf, or 88.18% 7,766 MMcf for the year ended December 31, 2024 from 4,127 MMcf for the year ended December 31, 2023. The changes in crude oil, NGL and natural gas production volumes are a result of new wells placed in production offset by the natural decline of existing properties.

The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2024 and 2023 (excluding realized gains and losses from derivatives).

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.

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The following table summarizes the results of our derivative instruments for the years ended December 2024 and 2023:

Prices received for the years ended December 31, 2024 and 2023, respectively, including the impact of derivatives were:

Oil and gas production expense increased $15.8 million, or 49.6% to $47.7 million for the year ended December 31, 2024 from $31.9 million for the year ended December 31, 2023. These changes reflect the cost savings related to wells that have been plugged offset by rising service costs and additional costs related to the new wells that have been placed on production.

Field service income decreased $4.5 million or 29.5% to $10.9 million for the year ended December 31, 2024 from $15.4 million for the year ended December 31, 2023. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations. These changes reflect decreases in equipment utilization related to the sale of Eastern Oil Well Service Company, effective August 31, 2024.

Field service expense decreased $2.6 million, or 22.4% to $9.1 million for the year ended December 31, 2024 from $11.7 million for the year ended December 31, 2023. Field service expenses primarily consist of wages and vehicle operating expenses. These changes reflect decreases in equipment utilization related to the sale of Eastern Oil Well Service Company, effective August 31, 2024.

Depreciation, depletion, and amortization increased $45.5 million, or 147.0% to $76.5 million for the year ended December 31, 2024 from $31.0 million for the year ended December 31, 2023. These increases reflect the expense related to the new wells placed on production during the twelve months ended December 31, 2024.

General and administrative expense increased $3.2 million, or 21.0% to $18.8 million for the year ended December 31, 2024 from $15.6 million for the year ended December 31, 2023. This increase is primarily due to employee compensation, benefits and other corporate costs.

Gain on sale and exchange of assets of $3.7 million for the year ended December 31, 2024 consists of sales of net mineral and surface acres in various locations in Texas and Oklahoma as well as the sale of our South Texas oilfield service company, Eastern Oil Well Service.

Interest expense increased $1.0 million, or 189.0% to $1.5 million for the year ended December 31, 2024 from $0.5 million for the year ended December 31, 2023. This increase reflects the higher interest and fee rates combined with borrowings throughout the twelve months of 2024 under our revolving credit agreement.

Tax expense of $15.8 million and $6.1 million were recorded for the years ended December 31, 2024 and 2023, respectively. The change in our income tax provision was primarily due to the increase in pre-tax income for the year ended December 31, 2024.

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 of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.

We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. 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 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.

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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.

Asset Retirement Obligation (ARO):

The Company has significant obligations to remove tangible equipment and restore land at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value

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, and available capacity under our revolving credit facility.

Net cash provided by operating activities for the year ended December 31, 2023 was $109.0 million compared to $33.1 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 2024, we will continue our focus on preserving financial flexibility and liquidity as we manage the risks facing our industry. Our 2024 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.

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The Company maintains a Credit Agreement with a maturity date of June 1, 2026, providing for a credit facility totaling $300 million, with a borrowing base of $85 million. As of March 31, 2024, the Company had $4 million in outstanding borrowings and $81 million in availability under this facility. The bank reviews the borrowing base semi-annually and, at its 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 May 2024. 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.

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. The credit agreement requires that as of the last day of any fiscal quarter, if the borrowing base utilization percentage on such a date is less than the 15%, then the borrower shall not be required to enter into any swap agreements. As of the quarter ended December 31, 2023, the Company had no outstanding borrowings. Accordingly, the Company had no swap agreements in place for oil and natural gas.

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. Horizontal development of our resource base provides superior returns relative to vertical development due to the ability of each horizontal wellbore to come in contact with a greater volume of reservoir rock across a greater distance, more efficiently draining the reserves with less infrastructure and thus at a lower cost per acre.

In 2023, including 20 wells spud in the fourth quarter of 2023, the Company participated with five operators in 35 wells: 32 of these are located in West Texas and three are located in Oklahoma. The Company invested approximately $91 million in these wells, including in their production facilities, almost all attributable to wells drilled and completed in West Texas where we are focused on horizontal development of various proven pay intervals in the Wolfcamp and Spraberry formations. On December 31, 2023, we had 12 wells completed that were all brought into production in January of 2024. In addition to $7.9 million of the $91 million invested in these wells in 2023, the Company had an additional $15.5 million investment in these 12 wells. Also at year-end 2023, the Company was in the process of drilling and completing 34 wells in West Texas that carry an expense of $80.6 million, and planning for a 50% participation in an additional 12 wells to be drilled in 2024 that will require an investment of approximately $43 million. In total, the Company expects to invest $140 million in 54 wells in 2024 and, in 2025, to invest $95 million in an additional 23 wells in West Texas.

During 2023, to supplement cash flow and finance our future drilling programs, the Company sold 368 net mineral acres as well as 7.8 surface acres in Midland County, Texas receiving gross proceeds of $436,050 and recognizing a gain of $47,000.

In the second quarter of 2023, the Company acquired 55 net acres in the South Stiles area of Reagan County, Texas for $605,000, and in a separate agreement also in Reagan County, the Company sold 320 non-core acres for proceeds of $6,000,000. In addition, the Company sold 36.51% interest in one well in Midland County, Texas for proceeds of $60,000.

In the third quarter of 2023, the Company sold a non-core 38.25-acre leasehold tract in Martin County, Texas for proceeds of $899,000 and sold 3 surface acres in Liberty County, Texas for net proceeds of $37,053. Also in the third quarter, in various counties of Oklahoma, the Company divested its interest in 39 wells, reducing its future plugging liability by approximately $1.5 million. Effective July 1, 2023, the Company acquired the operations of 36 wells from DE Permian and 50% of DE Permian’s original ownership in such wells. In addition, in Reagan County, Texas, the Company acquired 114.52 net acres from DE Permian for $1,700,853 and assigned to them 203.23 net acres.

In the fourth quarter of 2023, the Company sold 136 surface acres in Oklahoma for net proceeds of $306,000 and in Midland Texas sold 9.35 net acres for proceeds of $280,423.

Proceeds from these sales in 2023, along with our cash flow, were used to eliminate the Company’s outstanding bank debt as of March 31, 2023. As noted above, as of March 31, 2024, the Company had $4 million outstanding borrowings and $81 million in availability under this facility.

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 a stock repurchase program in place, spending under this program in 2023 and 2022 was $7.5 million and $7.4 million, respectively. The Company expects continued spending under the stock repurchase program in 2024.

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Results of Operations

2023 and 2022 Compared

We reported a net income of $28.1 million for 2023, or $15.19 per share, compared to $48.7 million, or $24.91 per share for 2022. The current year net income reflects production increases offset by commodity price decreases. The significant components of income and expense are discussed below.

Oil, NGL and gas sales decreased $16.4 million, or 13.19% to $107.7 million for the year ended December 31, 2023 from $124.1 million for the year ended December 31, 2022. 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 $19.86 per barrel, or 20.54% on crude oil, decreased an average of $16.06 per barrel, or 44.99% on NGL and decreased $3.62 per Mcf, or 65.34% on natural gas during 2023 as compared to 2022.

Our crude oil production increased by 205,000 barrels, or 21.83% to 1,144,000 barrels for the year ended December 31, 2023 from 939,000 barrels for the year ended December 31, 2022. Our NGL production increased by 189,000 or 45.32% to 606,000 for the year ended December 31, 2023 from 417,000 barrels for the year ended December 31, 2022. Our natural gas production increased by 802 MMcf, or 24.12% to 4,127 MMcf for the year ended December 31, 2023 from 3,325 MMcf for the year ended December 31, 2022. The changes in crude oil, NGL and natural gas production volumes are a result of new wells placed in production offset by the natural decline of existing properties.

The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2023 and 2022 (excluding realized gains and losses from derivatives).

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 years ended December 2023 and 2022:

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Prices received for the years ended December 31, 2023 and 2022, respectively, including the impact of derivatives were:

Oil and gas production expense increased $1.0 million, or 4.0% to 3.11% for the year ended December 31, 2023 from $31.7 million for the year ended December 31, 2022. These changes reflect the cost savings related to wells that have been plugged offset by rising service costs and additional costs related to the new wells that have been placed on production.

Field service income increased $2.4 million or 18.5% to $15.4 million for the year ended December 31, 2023 from $13.0 million for the year ended December 31, 2022. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations. These changes reflect the variance in equipment utilization and service rates during these periods.

Field service expense increased $0.6 million, or 5.4% to $11.7 million for the year ended December 31, 2023 from $11.1 million for the year ended December 31, 2022. Field service expenses primarily consist of wages and vehicle operating expenses. The changes reflect the variance in equipment utilization during the periods represented.

Depreciation, depletion, and amortization increased $3.6 million, or 13.1% to $31 million for the year ended December 31, 2023 from $27.4 million for the year ended December 31, 2022. The DD&A expense is primarily attributable to our properties in West Texas and Oklahoma, reflecting the addition of new properties offset by the declining cost basis of existing properties.

General and administrative expense decreased $4.6 million, or 22.7% to $15.6 million for the year ended December 31, 2023 from $20.2 million for the year ended December 31, 2021. These changes are primarily related to employee compensation and benefits.

Gain on sale and exchange of assets of $8.9 million for the year ended December 31, 2023 consists of sales of net mineral and surface acres in various locations in Texas and Oklahoma. The $31.8 million for the year ended December 31, 2022 consists principally of sales of deep rights in undeveloped acreage in West Texas.

Interest expense decreased $0.4 million, or 41.0% to $0.5 million for the year ended December 31, 2023 from $0.9 million for the year ended December 31, 2022. This decrease reflects the increase in rates combined with reduced borrowings under our revolving credit agreement

Tax expense of $6.1 million and $10.3 million were recorded for the years ended December 31, 2023 and 2022, respectively. The change in our income tax provision was primarily due to the decrease in pre-tax income for the year ended December 31, 2023.

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 of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.

We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. 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.

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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 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.

Asset Retirement Obligation (ARO):

The Company has significant obligations to remove tangible equipment and restore land at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO

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liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value

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, 2022 was $33.1 million, compared to $28.6 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 2023, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2023 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.

The Company maintains a Credit Agreement with a maturity date of June 1, 2026, providing for a credit facility totaling $300 million, with a borrowing base of $60 million. As of March 31, 2023, the Company has no outstanding borrowings and $60 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 May 2023. 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.

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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 and natural gas.

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. Horizontal development of our resource base provides superior returns relative to vertical development due to the ability of each horizontal wellbore to come in contact with a greater volume of reservoir rock across a greater distance, more efficiently draining the reserves with less infrastructure and thus at a lower cost per acre.

In 2022 the Company participated with SEM Operating Company, LLC in four horizontal wells in Irion County, Texas with 10.3% interest for approximately $2.35 million and with Ovintiv Mid-Continent, Inc. in four horizontal wells in Canadian County with an average of 9% interest for $1.77 million. All eight wells were put into production in August of 2022.

In the fourth quarter of 2022, we began participation in the drilling of 20 horizontal wells located in West Texas operated by three different operators. In Martin County, we are participating with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest with a planned capital expense of $12.1 million. In Reagan County we are participating with Hibernia Energy III in 10 two-mile horizontals with 25% interest and an expected investment of $25.6 million. Also in Reagan County, we are participating with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying an expected net capital outlay of $23.4 million. All twenty of these West Texas wells are currently drilling or have been completed. All are expected to be on line in the second quarter of 2023.

In January of 2023, the Company joined Ovintiv USA, Inc. in the spudding of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest and an expected investment of $645,000. Production is expected to begin in May, 2023. In addition, in March of 2023, Apache Corporation has spud two 3-mile-long horizontals in Upton County, Texas in which the Company has 49.4% interest with an expected total capital investment of $16,1 million. We anticipate completion of these two 15,000’ long horizontals in Upton County in May and production to occur in June of 2023.

In total, the Company expects to invest $78 million dollars in these 25 horizontal wells. We prepaid drilling costs of $32 million in December of 2022 and the remaining $46 million estimated drilling and completion expenditures will occur in 2023. All 25 wells are expected to be completed and on-line in the second quarter of 2023.

We anticipate that success from the 22 horizontals in West Texas described above will lead to additional near-term horizontal drilling covering five leasehold blocks in three counties of West Texas: 29 additional 10,000’ long horizontals in Reagan County with Hibernia, Double Eagle and BTA Oil Producers, ten additional 12,500’ long horizontals in Martin County with ConocoPhillips, and six additional 15,000’ long horizontals in Upton County with Apache. These anticipated additional 42 drilling proposals will target various proven pay intervals of the Wolfcamp and Spraberry formations and will require an estimated $200 million in net capital investment. In addition, we have more than 200 drilling locations that could potentially be developed.

In West Texas the Company maintains an acreage position of 16,940 gross (9,969 net) acres, primarily in Reagan, Upton, Martin, and Midland counties where our horizontal activity is focused. We believe this acreage

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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 200 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 4,113 net leasehold acres in the Scoop/Stack Play. Of this acreage we believe 2,355 net acres holds significant additional resource potential that could support the drilling of as many as 46 new horizontal wells based on an estimate of four wells per multi-section drilling unit, two in the Mississippian and two in the Woodford Shale. In the near term, we anticipate nine new drilling proposals to be received with an estimated net expense of $5.2 million covering 338 net leasehold acres. Proposals may be received on the remaining 2,017 acres, however, rather than participate we may choose to sell the acreage or farm-out receiving cash and retaining an over-riding royalty interest.

During 2022, to supplement cash flow and finance our future drilling programs, the Company entered into an agreement with Double Eagle to create a 2,560-acre AMI for the joint development of horizontal wells; as part of this agreement, the Company sold a portion of its interest in this acreage for proceeds of $16.1 million. In addition, in 2022, we sold 240 net acres in Reagan County to BTA Oil Producers for proceeds of $1.8 million, and we sold 353 net acres in Canadian County, Oklahoma to Paloma Partners, IV, Inc. for $1.3 million. Through three other transactions, we divested a minor tract in Lea County, NM for a nominal cash consideration and assigned nine wellbores in West Texas to a third-party operator in exchange for a reduction in our future plugging liability. In this same year, the Company acquired 3.2 net mineral acres in Upton County, Texas for $16,000.

These sales along with our cash flow have allowed the Company to eliminate its bank debt as of March 31, 2023, with the right to borrow up to $60 million under its current revolving line of credit.

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 a stock repurchase program in place, spending under this program in 2022 and 2021 was $7.4 million and $145 thousand, respectively. The Company expects continued spending under the stock repurchase program in 2023.

Results of Operations:

2022 and 2021 Compared

We reported a net income of $48.7 million for 2022, or $24.91 per share, compared to $2.1 million, or $1.05 per share for 2021. The current year net income reflects production and commodity price increases, partially offset by losses related to derivative instruments. The significant components of income and expense are discussed below.

Oil, NGL and gas sales increased $51.1 million, or 69.7% to $124.1 million for the year ended December 31, 2022 from $73.1 million for the year ended December 31, 2021. 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 increased an average of $28.31 per barrel, or 41.40% on crude oil, increased an average of $8.73 per barrel, or 32.37% on NGL and increased $2.01 per Mcf, or 57.00% on natural gas during 2022 as compared to 2021.

Our crude oil production increased by 201,000 barrels, or 27.24% to 939,000 barrels for the year ended December 31, 2022 from 738,000 barrels for the year ended December 31, 2021. Our NGL production increased by 1,000 or 0.24% to 417,000 for the year ended December 31, 2022 from 416,000 barrels for the year ended

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December 31, 2021. Our natural gas production increased by 89 MMcf, or 2.75% to 3,325 MMcf for the year ended December 31, 2022 from 3,236 MMcf for the year ended December 31, 2021. The changes in crude oil, NGL and natural gas production volumes are a result of new wells placed in production offset by the natural decline of existing properties.

The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2022 and 2021 (excluding realized gains and losses from derivatives).

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 years ended December 2022 and 2021:

Prices received for the years ended December 31, 2022 and 2021, respectively, including the impact of derivatives were:

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Field service expense increased $1.9 million, or 20.7% to $11.1 million for the year ended December 31, 2022 from $9.2 million for the year ended December 31, 2021. Field service expenses primarily consist of wages and vehicle operating expenses which have increased during 2022 related to increased utilization of our equipment services.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $1.8 million, or 6.8% to $28.1 million for the year ended December 31, 2022 from $26.3 million for the year ended December 31, 2021. The DD&A expense is primarily attributable to our properties in West Texas and Oklahoma, reflecting the addition of new properties offset by the declining cost basis of existing properties.

General and administrative expense increased $11.1 million, or 122.0% to $20.2 million for the year ended December 31, 2022 from $9.1 million for the year ended December 31, 2021. This increase in 2022 is primarily due to increased employee count, compensation and benefits

Gain on sale and exchange of assets of $31.8 million for the year ended December 31, 2022 and $1.5 million for the year ended December 31, 2021 consists principally of sales of deep rights in undeveloped acreage in West Texas.

Interest expense decreased $1.1 million, or 55.0% to $0.9 million for the year ended December 31, 2022 from $2.0 million for the year ended December 31, 2021. This decrease reflects the reduced borrowings under our revolving credit agreement offset by an increase in rates.

Tax expense of $10.3 million and $2.5 million were recorded for the years ended December 31, 2022 and 2021, respectively. The change in our income tax provision was primarily due to the increase in pre-tax income for the year ended December 31, 2022.

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 of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.

We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. 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.

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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 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, 2021 was $28.6 million, compared to $16.4 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.

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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 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2022 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 11, 2023, providing for a credit facility totaling $300 million, with a borrowing base of $50 million. As of March 31, 2022, the Company has $9 million in outstanding borrowings and $41 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 May 2022. 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.

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 and natural gas.

The successful development of these reservoirs has
proven-up
drilling locations on our nearby
2,600-acre
leasehold 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
2,600-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.

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The Company is currently participating with SEM Operating Company, LLC in four horizontal wells in Irion County, Texas with 10.3% interest for an estimated investment of $2.35 million. These wells are expected to be online in the second quarter of 2022.

Additional Permian Basin development drilling plans in 2022 include the drilling of nine
2.5-mile
horizontal wells with BTA Oil Producers in Reagan County, Texas. The Company will have an average of 43.67 % interest in these wells with an expected capital outlay of $40.5 million through completion. These wells are scheduled to be drilled in June and completed in 2022.

Also in 2022, in the Permian Basin of West Texas, the Company plans to drill four horizontal wells with ConocoPhilips in Martin County with an average of 38% interest. The total capital expenditure for these wells is expected to be $15 million. 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.

The Company maintains an acreage position of 17,148 gross (10,640 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 2021, in the Scoop/Stack Play of Oklahoma, the Company participated for 11.25% interest in the drilling of four wells and the completion of three of these wells in December that were placed on production in early January of 2022. The Company had an expenditure of approximately $2.2 million. In the first quarter of 2022, the Company received and approved proposals from Ovintiv
Mid-Continent,
Inc. for the drilling of four horizontal wells in Canadian County, Oklahoma. Drilling will begin in April and completion of these wells are expected in June of this year. The Company will participate for 9.38% and expects total drilling and completion costs to be approximately $1.8 million.

In Oklahoma, the Company’s horizontal activity is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 200 net leasehold acres in the Scoop/Stack Play. We believe this acreage has significant additional resource potential that could support the drilling of as many as 54 new horizontal wells based on an estimate of six wells per section: two in the Mississippian and two in the Woodford Shale. Should we choose to participate in future development, our share of the capital expenditures would be approximately $36 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 2021, the Company sold leasehold rights through one transaction in Texas, receiving gross proceeds of approximately $1.45 million in exchange for 116 net leasehold acres. In the first quarter of 2022, The Company sold 1,809 net leasehold acres in Regan and Midland Counties, Texas through two transactions receiving gross proceeds of $14.1 million and retaining certain over-riding royalty interests. These sales have allowed the Company to reduce its bank debt to $9 million, as of March 31, 2022, with the right to borrow up to $50 million under its current revolving line of credit.

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 a stock repurchase program in place, spending under this program in 2021 and 2020 was $145 thousand and $710 thousand, respectively. The Company expects continued spending under the stock repurchase program in 2022.

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Results of Operations:

2021 and 2020 Compared

We reported a net income of $2.1 million for 2021, or $1.05 per share, compared to a net loss of $2.3 million, or $1.16 per share for 2020. The current year net income reflects commodity price increases partially offset by losses related to the valuation of derivative instruments. The significant components of income and expense are discussed below.

Oil, NGL and gas sales

increased $36.1 million, or 97.6% to $73.1 million for the year ended December 31, 2021 from $37.0 million for the year ended December 31, 2020. 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 increased an average of $30.38 per barrel, or 79.9% on crude oil, increased an average of $15.75 per barrel, or 140.4% on NGL and increased $2.29 per Mcf, or 184.3% on natural gas during 2021 as compared to 2020.

Our crude oil production increased by 5,000 barrels, or 0.68% to 738,000 barrels for the year ended December 31, 2021 from 733,000 barrels for the year ended December 31, 2020. Our NGL production decreased by 21,000 or 4.85% to 416,000 for the year ended December 31, 2021 from 437,000 barrels for the year ended December 31, 2020. Our natural gas production decreased by 145 MMcf, or 4.29% to 3,236 MMcf for the year ended December 31, 2021 from 3,381 MMcf for the year ended December 31, 2020. The changes in crude oil, NGL and natural gas production volumes are a result of the natural decline of existing properties slightly offset by new wells placed in production.

The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2021 and 2020 (excluding realized gains and losses from derivatives).

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.

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The following table summarizes the results of our derivative instruments for the twelve months ended December 2021 and 2020:

Prices received for the twelve months ended December 31, 2021 and 2020, respectively, including the impact of derivatives were:

Field service income

increased $0.7 million, or 6.3% to $11.8 million for the year ended December 31, 2021 from $11.1 million for the year ended December 31, 2020. This increase is a combined result of increased utilization and rates charged to customers as oil and gas prices improved during 2021. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.

Lease operating expenses

increased $4.8 million, or 20.9% to $27.8 million for the year ended December 31, 2021 from $23.0 million for the year ended December 31, 2020. This increase is primarily due to returning higher lifting cost properties to production during 2021 as commodity prices improved, combined with higher production taxes related to higher commodity prices.

Field service expense

increased $2.6 million, or 28.9% to $11.6 million for the year ended December 31, 2021 from $9.0 million for the year ended December 31, 2020. Field service expenses primarily consist of wages and vehicle operating expenses which have increased during 2021 related to increased utilization of our equipment services.

Depreciation, depletion, amortization and accretion on discounted liabilities

decreased $1.9 million, or 6.7% to $26.3 million for the year ended December 31, 2021 from $28.2 million for the year ended December 31, 2020. 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 $4.6 million, or 30.7% to $10.4 million for the year ended December 31, 2021 from $15.0 million for the year ended December 31, 2020. This decrease in 2021 reflects cost reductions put in place during 2020 responding to sharply lower commodity prices, primarily reductions in staff and compensation.

Gain on sale and exchange of assets

of $1.5 million for the year ended December 31, 2021 and $15.8 million for the year ended December 31, 2020 consists principally of sales of deep rights in undeveloped acreage in West Texas and, in 2020, also included the sale of marginal wells in West Virginia.

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Interest

expense increased $0.1 million, or 5.3% to $2.0 million for the year ended December 31, 2021 from $1.9 million for the year ended December 31, 2020. The average interest rate paid on outstanding bank borrowings under its revolving credit facility during 2021 and 2020 were

5.29% and 3.95%, respectively. As of December 31, 2021 and 2020, the total outstanding borrowings under its revolving credit facility were $36.0 million and $37.0 million, respectively.

Tax

expense of $2.5 million and tax benefit of $0.5 million were recorded for the years ended December 31, 2021 and 2020, respectively. The change in our income tax provision was primarily due to the increase in
pre-tax
income for the year ended December 31, 2021.