Riley Exploration Permian, Inc. (REPX)

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the Company’s financial condition and results of operations should be read in conjunction with the Company’s consolidated financial statements and related notes thereto presented in this Annual Report. The following discussion contains “forward-looking statements” that reflect the Company’s future plans, estimates, beliefs and expected performance. The Company’s actual results could differ materially from those discussed in these forward-looking statements. See "Cautionary Statement Regarding Forward-Looking Statements" and "Part I. Item 1A. Risk Factors."

Overview

Riley Permian is a growth-oriented, independent oil and natural gas company focused on horizontal drilling of conventional oil-saturated and liquids-rich formations that produce long-term stable cash flows in the Permian Basin. The majority of our acreage is located in Yoakum County, Texas and Eddy County, New Mexico.

Our strategic business objectives include enhancing the rate of return on our invested capital, generating sustainable free cash flow, maintaining a strong and flexible balance sheet while maximizing our returns to shareholders. We implement this strategy primarily through identification and capture of attractive development opportunities, optimization of our assets and pursuing complementary growth opportunities that increase our scale and meet our strategic and financial objectives.

Recent Developments

Geopolitical and Economic Conditions

Commodity prices remain volatile. General domestic and international political and economic conditions, including the military conflict between Russia and Ukraine, conflicts in the Middle East, and the U.S. and global response to such conflicts, global economic growth, actions of OPEC+ countries, and implementation of tariffs could prolong market volatility or cause a decline in commodity prices.

Inflation continues to be an ongoing concern. Although inflation moderated somewhat, inflationary pressures remain elevated, which in turn may cause our capital expenditures and operating costs to increase. During inflationary periods, interest rates have historically increased. Increased interest rates could have the effects of raising our cost of capital and the potential for depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business.

The Company cannot estimate the length or gravity of the future impact these conditions will have on the Company's results of operations, financial position, liquidity and the value of the oil and natural gas reserves.

2024 New Mexico Asset Acquisition

On May 7, 2024, the Company completed the acquisition of oil and natural gas properties in Eddy County, New Mexico ("2024 New Mexico Asset Acquisition"), which included 13,900 contiguous net acres adjacent to the Company's existing acreage in Eddy County, for a cash purchase price of approximately $19.1 million plus $0.5 million in transaction costs. The 2024 New Mexico Asset Acquisition was accounted for as an asset acquisition, with the final purchase price and transaction costs being capitalized to oil and natural gas properties. The acquisition was funded through a combination of proceeds from the 2024 Equity Offering and cash on hand.

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RPC Power Joint Venture

In January 2023, the Company formed a joint venture, RPC Power, for the purpose of constructing, owning and operating power generation assets which became fully operational in September of 2024. These assets use the Company’s produced natural gas to power a portion of our oilfield operations in Yoakum County, Texas. In May 2024, the Company entered into the Second Amended and Restated Limited Liability Company Agreement ("A&R LLC Agreement") to expand the scope of our joint venture to include the constructing, owning, and operating of additional new power generation and storage assets, which are expected to be operational beginning in late 2025 through 2026, for the sale of energy and ancillary services to ERCOT. In November 2024, the Company signed the Second Amendment to the A&R LLC Agreement, which increased the capital commitment for each owner from $42.5 million to $51.5 million. As of December 31, 2024, the Company owned 50% of the joint venture. On February 28, 2025, the Company contributed an additional $6.3 million to the joint venture which increased our total capital contributions to $30 million.

2024 Equity Offering

On April 8, 2024, the Company issued and sold 1,015,000 shares of common stock at a price of $27.00 per share. Net proceeds from the issuance were approximately $25.4 million, after deducting underwriting discounts and commissions and expenses.

Credit Facility Amendment

On December 13, 2024, the Company entered into the sixteenth amendment to the Credit Facility to, among other things, extend the stated maturity date from April 2026 to December 2028 (or if any Senior Notes are then outstanding, the date that is 181 days prior to the earliest stated maturity date of such Senior Notes, in this case October 2027), increase the borrowing base from $375 million to $400 million, and add one new lender to the lending group.

Gas Purchase Agreement

We believe the successful execution of the Company's New Mexico development plan is dependent upon maintaining operational control and securing reliable processing and downstream markets for our natural gas. As part of this plan, the Company signed a long-term gas purchase agreement for our New Mexico field with a new midstream counterparty, which includes dedicated acreage for a significant portion of the Company’s oil and gas assets in New Mexico, reimbursement by the Company of construction costs incurred by the midstream counterparty to connect to the Company’s pipeline (subject to a monetary cap of $18.7 million) and an initial 15-year term from the in-service date. In conjunction with the agreement, the Company intends to construct, own and operate low and high-pressure gathering lines and compression facilities that will connect to our new high capacity 20-inch natural gas pipeline to be constructed by the Company and designed to handle gas volumes of up to 150 MMcf per day. We currently anticipate the in-service date will be before the end of 2026. The Board of Directors approved an aggregate of approximately $130 million in capital expenditures to complete these initial projects of our midstream development plan.

Oil & Gas Property Impairments

At December 31, 2024, we recognized a non-cash $11.3 million impairment of proved properties comprised of a $9.5 million impairment in Texas, outside of the Champions field, and a $1.8 million impairment in New Mexico, outside of the Red Lake field. The impairments were primarily driven by a reduction in reserve volume due to lower well performance assessments based on historical trends. The affected areas included nine operated producing wells.

Impairment of EOR Project

At September 30, 2024, the Company recorded a $30.2 million impairment related to the discontinuation of our EOR Project, including a $28.9 million non-cash impairment and a $1.3 million cash impairment related to the termination of the Kinder Morgan CO2 contract. Select equipment from the EOR Project was salvaged for use in the Company's conventional vertical and horizontal development programs.

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Results of Operations

Comparison for the years ended December 31, 2024, and 2023.

The following table sets forth selected operating data for the years ended December 31, 2024, and 2023:

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(1)The Company's oil, natural gas and NGL sales are presented net of gathering, processing and transportation costs. These costs, related to natural gas and NGLs, at times exceeded the price we received and resulted in negative average realized prices.

(2)The Company's calculation of the effects of derivative settlements includes gains and losses on the settlement of our commodity derivative contracts. These gains and losses are included under other income (expense) in the Company’s consolidated statements of operations.

(3)During the periods presented, the Company did not have any NGL derivative contracts in place.

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Oil and Natural Gas Revenues

Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Realized prices and revenues from product sales are a function of the volumes produced, product quality, market prices, gas Btu content, as well as gathering, processing and transportation costs. Gathering, processing and transportation costs are allocated across natural gas and NGLs based on revenue, which leads to heightened fluctuations in such cost allocations across periods. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in the volume of production sold or changes in commodity prices. The Company’s total oil and natural gas sales, net increased $37.2 million, or 10%, for the year ended December 31, 2024, compared to the year ended December 31, 2023. The following table presents the Company's oil and natural gas sales prior to and net of gathering, processing and transportation costs:

Oil revenues

For the year ended December 31, 2024, oil revenues increased by $45.8 million, or 13%, compared to the year ended December 31, 2023. The following table summarizes the effect of price and volume changes on oil revenues:

Our realized oil prices decreased by $1.52 during the year ended December 31, 2024, when compared to the year ended December 31, 2023, which corresponded with a $0.95 decrease in the average WTI price during the same period. An increase in basis differentials accounted for the remaining difference. Daily oil volumes increased by 15% due to increased production from new wells turned to sales in our Champions field as well as the 2023 and 2024 New Mexico Acquisitions.

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Natural gas revenues

For the year ended December 31, 2024, natural gas revenues decreased by $4.0 million compared to the year ended December 31, 2023. The following table summarizes the effect of price and volume changes on natural gas revenues:

Our realized natural gas prices, which were negative for the year ended December 31, 2024, decreased by $0.64 compared to the year ended December 31, 2023, due to weak Permian Basin natural gas prices that did not provide for full recovery of the Company's allocated gathering and processing costs. This corresponded with a $0.34 decrease in the average Henry Hub price during the year ended December 31, 2024, and an increase in basis differentials due to regional supply imbalances.

NGL revenues

For the year ended December 31, 2024, NGL revenues decreased by $4.6 million, or 67%, compared to the year ended December 31, 2023. The following table summarizes the effect of price and volume changes on NGL revenues:

Our realized NGL prices decreased by $5.34 during the year ended December 31, 2024, when compared to the year ended December 31, 2023. Realized prices decreased due to higher allocated gathering and processing costs from weak Permian Basin natural gas prices that limited the full recovery of the Company's allocated gathering and processing costs. This was partially offset by a 48% increase in volumes due to additional third party processing capacity that came online in 2024.

Contract Services - Related Party

The following table presents the Company's revenue and costs associated with our contract services - related party transactions:

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(1)The Company’s contract services - related parties revenue was derived from master services agreements with related parties to provide certain administrative support services.

(2)The Company's cost of contract services - related parties represented costs specifically attributable to the master service agreements the Company had in place with the respective related parties.

The management services agreement with Riley Exploration Group, LLC was terminated effective May 31, 2024, and the management services agreement with Combo Resources, LLC was terminated effective January 31, 2024. See Note 9 - Transactions with Related Parties in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules for more information.

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Costs and Expenses

The following table presents the Company's operating costs and expenses and other (income) expenses:

Lease Operating Expenses ("LOE")

LOE are the costs incurred in the operation and maintenance of producing properties. Certain operating cost components, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities or subsurface maintenance result in increased production expenses in periods during which they are performed. Certain operating cost components, such as saltwater disposal associated with produced water, are variable and increase or decrease as hydrocarbon production levels and the volume of water disposal increases or decreases.

The Company’s LOE increased by $12.6 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. This increase was driven by a $5.5 million increase due to more workovers primarily in our Red Lake field, a $4.5 million increase in our Champions field due to higher production volumes and a $3.4 million increase due to the inclusion of LOE expenses associated with our 2024 New Mexico Asset Acquisition, partially offset by a decrease in certain expenses, primarily chemical, fuel and repair costs. On a LOE per BOE basis, the additional volumes fully offset the $12.6 million increase as the 2024 LOE per BOE was flat when compared to 2023.

Production and Ad Valorem Tax Expense

Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate. In addition, the Company became subject to a waste emissions charge in 2024 related to methane emissions in excess of specified limits under new legislation from the EPA. This amount was recorded in production taxes for 2024.

Production and ad valorem taxes increased by $3.9 million for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily due to increases in our oil and natural gas sales, net and $0.8 million from the new waste emissions charge.

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Exploration Costs

Exploration costs consist of exploratory well expense, expiration of unproved leasehold, and geological and geophysical costs which include seismic survey costs. The following table presents exploration costs for the years ended December 31, 2024, and 2023:

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(1)The Company determined that an exploratory well was not capable of producing commercial quantities and expensed the associated drilling costs during the year ended December 31, 2023.

Depletion, Depreciation, Amortization and Accretion Expense

DD&A expense is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil, natural gas and NGLs. All costs incurred in the acquisition, exploration and development of properties (excluding costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration activities) are capitalized. Capitalized costs are depleted using the units-of-production method.

Accretion expense relates to ARO. We record the fair value of the liability for ARO in the period in which the liability is incurred (at the time the wells are drilled or acquired) with the offset to property cost. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed.

DD&A expense increased by $9.8 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. The increase for the year ended December 31, 2024, was primarily due to higher production in our Champions field and the inclusion of the 2023 New Mexico Acquisition for the full year as well as the 2024 New Mexico Asset Acquisition for part of the year.

Impairment of Oil and Natural Gas Properties

The cost of proved oil and natural gas properties are assessed on a field-by-field basis for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We compare the expected undiscounted future cash flows of the oil and natural gas properties to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil and natural gas properties to estimated fair value.

During the year ended December 31, 2024, the Company recognized a non-cash impairment loss on proved properties of $11.3 million relating to certain properties in Texas outside of the Company's acreage in the Champions field, in addition to historical properties in New Mexico outside of Red Lake. These impairments were primarily driven by a reduction in reserve volume due to lower well performance assessments based on historical trends. The affected areas included nine operated producing wells. The Company recognized a non-cash impairment loss on proved properties of $9.8 million for the year ended December 31, 2023, which related to a decrease in fair value of certain properties in Texas outside of the Company's acreage in the Champions field.

Other Impairments

The cost of proved and unproved oil and natural gas properties are assessed for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We compare the undiscounted future cash flows of the oil, natural gas and NGL properties to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil, natural gas and NGL properties to their estimated fair value.

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The Company recognized an impairment loss of $30.2 million for the year ended December 31, 2024, which consisted of a non-cash impairment loss of $28.9 million and a cash impairment loss of $1.3 million related to the termination of the Kinder Morgan CO2 contract. The impairment loss relates to the discontinuation of the Company's EOR project, in favor of redeploying the required future capital and salvaging certain assets for use in the Company's conventional vertical and horizontal development programs. There was no other impairment loss for the year ended December 31, 2023.

General and Administrative ("G&A") Expense

G&A expenses consist of administrative costs and share-based compensation expense. Administrative costs include corporate overhead such as payroll and benefits for our staff, office costs, fees for professional services such as audit and legal services, technology costs, insurance and other. Share-based compensation expense reflects costs associated with our stock granted to employees and members of our board of directors. G&A expenses are reported net of overhead recoveries.

Total G&A expense increased by $1.3 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. Administrative costs remained flat for the year ended December 31, 2024, compared to the year ended December 31, 2023. Share-based compensation expense increased by $1.3 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. The increase in share-based compensation expense was primarily due to a higher employee count and an increase in outstanding equity awards.

Transaction Costs

Transaction costs represent costs incurred on successful or unsuccessful commercial transactions, business combinations or unsuccessful acquisitions. The transaction costs of $1.6 million for the year ended December 31, 2024, primarily relate to the RPC Power Joint Venture, costs associated with the negotiation and closing of our new gas purchase agreement in addition to potential transactions that the Company evaluated but decided not to pursue further. During the year ended December 31, 2023, the transaction costs of $5.8 million related to the 2023 New Mexico Acquisition.

Interest Expense, net

Interest expense, net increased by $2.5 million during the year ended December 31, 2024, when compared to the year ended December 31, 2023. The increase in interest expense was primarily due to a full-year effect of the Senior Notes, which were the primary financing for the 2023 New Mexico Acquisition, including amortization of the discount.

Gain/Loss on Derivatives

The Company recognizes settlements and changes in the fair value of our derivative contracts as a single component within other income (expense) in our consolidated statements of operations. We have oil and natural gas derivative contracts, including fixed price swaps, basis swaps and collars, that settle against various indices. The following table presents the components of the Company's gain (loss) on derivatives, net for the years ended December 31, 2024, and 2023:

Cash gains or losses on settled derivative contracts relate to contracts that settle during the period and are a function of the difference in settled versus contractual prices and the associated hedged volumes for each underlying commodity. Non-cash gains or losses on derivatives relate to unsettled contracts and are a function of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities relative to contractual pricing and the associated hedged volumes for each underlying commodity for our derivative contracts outstanding.

Income Tax Expense

Current income taxes represent the amount the Company expects to owe to federal and state tax authorities in the current period, based on our taxable income. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted

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tax rates. See Note 12 - Income Taxes in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules for a full discussion of income taxes.

The decrease in deferred income tax expense from 2023 to 2024 is primarily due to the 2023 New Mexico Acquisition, which allowed for more accelerated tax depreciation in 2023.

Liquidity and Capital Resources

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, like all upstream operators, we must make capital investments to grow and even sustain production. The Company’s principal liquidity requirements are to finance our operations, fund capital expenditures and acquisitions, pay dividends and satisfy any indebtedness obligations. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our cash on hand, cash flow from operations, borrowings under our Credit Facility and the issuance of our Senior Notes. At times and as needed, we may also issue debt or equity securities, including through transactions under our shelf registration statement filed with the SEC. In April 2024, the Company issued equity securities and used the proceeds to finance an acquisition, repay outstanding debt and for general corporate purposes. We estimate the combination of the sources of capital discussed above will continue to be adequate to meet our short and long-term liquidity needs.

Cash on hand and operating cash flow can be subject to fluctuations due to trends and uncertainties that are beyond our control. Likewise, our ability to issue equity, debt and obtain credit facilities on favorable terms may be impacted by a variety of market factors as well as fluctuations in our results of operations.

For further discussion of risks related to our liquidity and capital resources, see "Item 1A. Risk Factors."

Working Capital

Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements is driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. As of December 31, 2024, we had a working capital deficit of $54.6 million compared to a deficit of $31.1 million as of December 31, 2023. The current portion of our Senior Notes, which includes our regularly scheduled principal payments of $5 million per quarter, accounts for $20 million of our working capital deficit at December 31, 2024, and December 31, 2023. We utilize our Credit Facility and cash on hand to manage the timing of cash flows and fund short-term working capital deficits. At December 31, 2024, we had cash on hand of $13.1 million and $285 million of undrawn capacity under our Credit Facility.

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Cash Flows

The following table summarizes the Company’s cash flows for the years ended December 31, 2024, and 2023:

Operating Activities

Net cash provided by operating activities were $246.3 million for the year ended December 31, 2024, compared to $207.2 million for the year ended December 31, 2023, and primarily consisted of the following:

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(1)Operating expenses include LOE, production and ad valorem taxes, administrative costs, transaction costs and other minor operating expenses.

Net cash provided by operating activities increased $39.1 million, or 19%, compared to year ended December 31, 2023. Oil and natural gas revenues increased $58.2 million due to an increase in our oil and natural gas production partially offset by a $21.1 million decrease due to lower realized pricing.

Investing Activities

Net cash flows used in investing activities were $147.8 million for the year ended December 31, 2024, compared to $469.6 million for the year ended December 31, 2023, and primarily consisted of the following:

Capital expenditures for oil and natural gas properties decreased $36.3 million due primarily to lower average well cost. Cash contributions to our joint venture, RPC Power, increased $14.3 million to fund additional new power generation for self-consumption and for the sale of energy and ancillary services to ERCOT, which is expected to be operational beginning in late 2025 through 2026. The Company also began construction of midstream infrastructure in New Mexico to increase our oil and natural gas volume capacity, and we currently anticipate the in-service date will be before the end of 2026.

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Financing Activities

Net cash flows used in financing activities were $100.6 million for the year ended December 31, 2024, compared to net cash flows provided by financing activities of $264.4 million for the year ended December 31, 2023, and primarily consisted of the following:

During 2024, the Company repaid $90 million of debt, net of proceeds compared to net borrowings of $302 million in 2023 and cash dividends increased $3 million, partially offset by our 2024 Equity Offering of $25.4 million.

Credit Facility and Senior Notes

The Company's borrowing base on our Credit Facility was $400 million with outstanding borrowings of $115 million at December 31, 2024, representing available borrowing capacity of $285 million.

On February 22, 2023, the Company amended our Credit Facility to, among other things, allow for the issuance of unsecured Senior Notes of up to $200 million. On April 3, 2023, and concurrent with the closing of the 2023 New Mexico Acquisition, the Company entered into the fourteenth amendment to the Credit Facility to, among other things, increase the maximum facility amount to $1.0 billion and the borrowing base from $225 million to $325 million, resulting in the addition of new lenders to the lending group. On November 14, 2023, through the semi-annual redetermination process and fifteenth amendment, the Company increased our borrowing base from $325 million to $375 million, resulting in the addition of two new lenders and the exit of one lender. On December 13, 2024, the Company entered into the sixteenth amendment to the Credit Facility to, among other things, extend the stated maturity date from April 2026 to December 2028 (or if any Senior Notes are then outstanding, the date that is 181 days prior to the earliest stated maturity date of such Senior Notes, in this case October 2027) and increase the borrowing base from $375 million to $400 million, resulting in the addition of one new lender to the lending group. Substantially all of the Company’s assets are pledged to secure the Credit Facility.

During the year ended December 31, 2023, the Company issued $200 million in principal amount of Senior Notes with a maturity date of April 2028. The proceeds from the Senior Notes were used to finance the 2023 New Mexico Acquisition. The principal balance of the Senior Notes as of December 31, 2024, was $165 million.

See Note 10 - Long-Term Debt in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our long-term debt.

Dividends

For the year ended December 31, 2024, the Company authorized and declared quarterly dividends totaling approximately $31.0 million, with $30.8 million paid in cash and $0.2 million accrued for the holders of restricted stock upon vesting. For the years ended December 31, 2024, and 2023, the Company paid cash dividends of approximately $0.7 million and $0.5 million, respectively, to holders of restricted stock upon vesting.

Contractual Obligations

As of December 31, 2024, the Company had a remaining volume commitment of less than seven years with our primary midstream counterparty in Texas. The Company also had natural gas delivery commitments under the A&R Tolling Agreement and a remaining equity commitment under the Second amendment to the A&R LLC Agreement of $27.7 million to fund our portion of the 2025 capital budget for the RPC Power joint venture. Further, the Company entered into a 15-year gas purchase agreement that required an acreage dedication to a midstream counterparty for a significant portion of our oil and gas assets in New Mexico. This agreement is expected to begin before the end of 2026. As a result of entering into the gas purchase agreement, the Company is committed to spend approximately $130 million in capital expenditures through 2026 to complete

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the initial projects of our midstream buildout plan. The Company incurred approximately $11 million in 2024. See Note 15 - Commitments and Contingencies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our commitments and contingencies.

Critical Accounting Estimates

The preparation of financial statements requires the Company to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

Changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and assumptions used in preparation of the Company’s consolidated financial statements and it is at least reasonably possible these estimates could be revised in the near term and these revisions could be material.

Method of Accounting for Oil and Natural Gas Properties

We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities which requires management's assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.

Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. At the end of each quarter, the status of all suspended exploratory drilling costs are reviewed to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program is considered.

Similar to the evaluation of suspended exploratory well costs, costs for unproved leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, unproved leasehold costs are assessed for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2024, the Company had approximately $101.0 million of unproved leasehold. Of the remaining unproved leasehold costs at December 31, 2024, approximately $2.2 million is scheduled to expire in 2025. The Company expects to renew or extend these leases in 2025. If our drilling is not successful, this leasehold could become partially or entirely impaired.

Once a well is drilled, capitalized well costs for drilling and completion activities must be evaluated at least yearly or whenever facts and circumstances indicate a decline in the recoverability of their carrying value may have occurred. At the end of each year, the undiscounted future cash flows are compared to the carrying value on a field basis to evaluate if the carrying value is recoverable. If the carrying value is not recoverable, the Company will compare the carrying value of the asset to its fair value and recognize any impairment loss in the period. Significant inputs and judgements are used in determining the fair value of the assets. The Company utilizes a discounted cash flow model in order to estimate fair value by modeling the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with the expected cash flow projected. During the year ended December 31, 2024, the Company recognized a proved property impairment of $11.3 million relating to certain properties in Texas outside of the Company's acreage in the Champions field and certain historical properties in New Mexico outside of the Company's acreage in the Red Lake field. The Company recognized an impairment loss on proved properties of $9.8 million for the year ended December 31, 2023, relating to certain properties in Texas outside of the Company's acreage in the Champions field.

See Note 7 - Fair Value Measurements in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our impairment analysis.

Oil and Natural Gas Reserves

Our estimates of proved and proved developed reserves are a major component of our depletion calculation. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process

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of estimating oil, natural gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. A third-party reservoir engineering firm prepares our reserve report, which the estimates are based off of technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. 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.

Business Combinations

The Company periodically acquires assets and assumes liabilities in transactions accounted for as business combinations, such as the 2023 New Mexico Acquisition. In connection with the 2023 New Mexico Acquisition, we allocated the purchase price consideration of $324.7 million to the assets acquired and liabilities assumed based on estimated fair values as of the date of the acquisition.

We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the 2023 New Mexico Acquisition. The most significant assumptions relate to the estimated fair values of proved and unproved oil and gas properties. The fair value of identifiable assets acquired and liabilities assumed is determined based on various valuation techniques, including market prices, discounted cash flow analysis, and independent appraisals. Significant judgments and assumptions are inherent in these valuation techniques and include, among other things, estimates of reserves, estimates of future commodity prices, expected development costs, lease operating costs and the discount rate that reflects the risk of the underlying cash flow estimates.

Estimated fair values assigned to assets acquired can have a significant impact on future results of operations presented in the Company's financial statements. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. In the event that future commodity prices or reserve quantities are lower than those used as inputs to determine estimates of acquisition date fair values, the likelihood increases that certain costs may be determined to not be recoverable.

See Note 4 - Acquisitions of Oil and Natural Gas Properties in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our acquisitions.

See Note 3 - Summary of Significant Accounting Policies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our significant accounting policies.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the Company’s financial condition and results of operations should be read in conjunction with the Company’s consolidated financial statements and related notes thereto presented in this Annual Report. The following discussion contains “forward-looking statements” that reflect the Company’s future plans, estimates, beliefs and expected performance. The Company’s actual results could differ materially from those discussed in these forward-looking statements. See "Cautionary Statement Regarding Forward-Looking Statements" and "Part I. Item 1A. Risk Factors."

Overview

We operate in the upstream segment of the oil and natural gas industry and are focused on steadily growing conventional reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas and NGLs primarily in the Permian Basin in West Texas and Southeastern New Mexico. We intend to continue to develop our reserves and increase production through development drilling and exploration activities and through acquisitions that meet our strategic and financial objectives.

Financial and Operating Highlights

Financial and operating results reflect the following:

•Increased total net equivalent production by 62% to 18.6 MBoe/d for the year ended December 31, 2023, as compared to the year ended December 31, 2022

•During the year ended December 31, 2023, 24 gross (18.2 net) horizontal wells were brought online to production

•Realized average combined price on production sold of $54.91 per Boe, before derivative settlements, during the year ended December 31, 2023, including $75.62 per barrel for oil

•Generated cash flow from operations of $207.2 million for the year ended December 31, 2023

•Incurred total accrual (activity based) capital expenditures before acquisitions of $135.8 million for the year ended December 31, 2023 as compared to $123.1 million for the year ended December 31, 2022

•Paid cash dividends on common shares of $27.7 million during the year ended December 31, 2023

•$15.3 million in cash and $356.0 million in total debt as of December 31, 2023

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Recent Developments

Market Conditions, Commodity Prices and Interest Rates

The U.S. and global economies and markets have experienced heightened volatility following impactful geopolitical events, the effects of widespread inflation and the impact of significantly higher interest rates. Prices for oil and natural gas are determined primarily by prevailing market conditions, which have been and could continue to be volatile.

The combination of geopolitical events, inflation and the rising interest rate environment has led to increasing forecasts of a U.S. or global recession. Any such recession could prolong market volatility or cause a decline in commodity prices, among other potential impacts.

The Company cannot estimate the length or gravity of the future impact these events will have on the Company's results of operations, financial position, liquidity and the value of oil and natural gas reserves.

New Mexico Acquisition

On April 3, 2023, the Company completed the New Mexico Acquisition from Pecos for an adjusted purchase price of $325 million. The New Mexico Acquisition was funded through a combination of borrowings under the Company's Credit Facility and proceeds from the issuance of $200 million of Senior Notes.

Power Joint Venture

In January 2023, the Company entered into an agreement to form a joint venture created for the purpose of constructing a new power infrastructure for onsite, baseload power generation using produced natural gas for its Champions Field. The Company has an initial 30% investment in the joint venture company, RPC Power LLC, and is committed to providing its portion of capital. Construction of the onsite power generation facility was predominately completed during 2023 with temporary power generation beginning in November 2023 and the onsite power generation facility expected to be operational in spring of 2024.

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Results of Operations

Comparison for the years ended December 31, 2023 and 2022

The following table sets forth selected operating data for the years ended December 31, 2023 and 2022:

_____________________

(1)The Company's calculation of the effects of derivative settlements includes losses on the settlement of its commodity derivative contracts. These losses are included under other income (expense) on the Company’s consolidated statements of operations.

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Oil and Natural Gas Revenues

Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Revenues from product sales are a function of the volumes produced, product quality, market prices, gas Btu content, as well as midstream counterparty fees and deducts. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in the volume of production sold or changes in commodity prices. The Company’s total oil and natural gas revenue, net increased $53.3 million, or 17%, for the year ended December 31, 2023 compared to the year ended December 31, 2022. The Company’s realized average combined price on its production for the year ended December 31, 2023 decreased by $21.14 per Boe, or 28% compared to the year ended December 31, 2022.

Oil revenues

•For the year ended December 31, 2023, oil revenues increased by $64.4 million, or 22%, compared to the year ended December 31, 2022. Of the increase, $147.2 million was attributable to an increase in volume, which was partially offset by $82.7 million attributable to a decrease in our realized price. Volumes increased by 49%, while realized prices decreased by 19% as compared to the year ended December 31, 2022. The oil and natural gas properties acquired in the New Mexico Acquisition contributed $71.9 million to the Company's oil revenues for the 2023 period.

•Oil volumes increased during the year ended December 31, 2023 due to oil and natural gas assets acquired in the New Mexico Acquisition, production from new wells and workovers performed on existing wells. During the year ended December 31, 2023, we brought online 24 gross (18.2 net) horizontal wells. The New Mexico Acquisition contributed oil volumes of approximately 931 MBbls for the 2023 period.

•The average WTI price decreased by $17.32 per Bbl during the year ended December 31, 2023 when compared to the year ended December 31, 2022.

Natural gas revenues

•For the year ended December 31, 2023, natural gas revenues decreased by $8.1 million, or 76%, compared to the year ended December 31, 2022. Realized natural gas prices decreased by 87% partially offset by an increase in volumes of 82% as compared to the year ended December 31, 2022. The oil and natural gas properties acquired in the New Mexico Acquisition contributed $2.1 million to the Company's natural gas revenues for the 2023 period.

•Natural gas sales volumes increased during the year ended December 31, 2023 compared to the year ended December 31, 2022 due to oil and natural gas properties acquired in the New Mexico Acquisition, production from new wells and workovers performed on existing wells. The New Mexico Acquisition contributed 2,179 MMcf to the Company's natural gas volumes for the 2023 period.

•The average Henry Hub price decreased by $3.92 per Mcf during the year ended December 31, 2023 compared to the year ended December 31, 2022.

NGLs revenues

•For the year ended December 31, 2023, NGL revenues decreased by $3.0 million, or 30%, compared to the year ended December 31, 2022. Realized prices decreased by 69%, partially offset by an increase in volumes of 126% as compared to the year ended December 31, 2022. The oil and natural gas properties acquired in the New Mexico Acquisition contributed $5.3 million to the Company's NGL revenues for the 2023 period.

•NGL sales volumes increased during the year ended December 31, 2023 compared to the year ended December 31, 2022 due to the New Mexico Acquisition, production from new wells and workovers performed on existing wells. The oil and natural gas properties acquired in the New Mexico Acquisition contributed 451 MBbls to the Company's NGL volumes for the 2023 period.

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Contract Services - Related Party

The following table presents the Company's revenue and costs associated with its contract services - related party transactions:

_____________________

(1)The Company’s contract services - related parties revenue is derived from master services agreements with related parties to provide certain administrative support services.

(2)The Company's cost of contract services - related parties represents costs specifically attributable to the master service agreements the Company has in place with the respective related parties.

Costs and Expenses

The following table presents the Company's operating costs and expenses and other (income) expenses:

Lease Operating Expenses ("LOE")

LOE are the costs incurred in the operation and maintenance of producing properties. Expenses for electricity, compression, direct labor, saltwater disposal and materials and supplies comprise the most significant portion of our lease operating expenses. Certain operating cost components, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities or subsurface maintenance result in increased production expenses in periods during which they are performed. Certain operating cost components, such as saltwater disposal associated with produced water, are variable and increase or decrease as hydrocarbon production levels and the volume of completion water disposal increases or decreases.

The Company’s LOE increased by $26.4 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. For the year ended December 31, 2023, the increase was driven by a $20.0 million increase due to higher production, including $13.3 million attributable to the New Mexico Acquisition, and a $10.1 million increase due to higher

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workover expense, including $7.6 million attributable to the New Mexico Acquisition, partially offset by a $3.7 million decrease primarily related to lower utility rates.

Production and Ad Valorem Tax Expense

Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate.

Production and ad valorem taxes increased by $6.3 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Production taxes increased primarily due to increases in our oil and natural gas sales, net, including revenues from production associated with the oil and natural gas properties acquired in the New Mexico Acquisition, partially offset by lower commodity prices. Ad valorem taxes increased for the year ended December 31, 2023 based on higher estimated property values and higher tax rates for the current taxable period.

Exploration Costs

Exploration costs consist of exploratory well expense, expiration of unproved leasehold, and geological and geophysical costs which include seismic survey costs. The following table presents exploration costs for the years ended December 31, 2023 and 2022:

_____________________

(1)The Company determined that an exploratory well was not capable of producing commercial quantities and expensed the associated drilling costs during the year ended December 31, 2023,

Depletion, Depreciation, Amortization and Accretion Expense

Depletion, depreciation and amortization is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil, natural gas and NGLs. All costs incurred in the acquisition, exploration and development of properties (excluding costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration activities) are capitalized. Capitalized costs are depleted using the units-of-production method.

Accretion expense relates to ARO. We record the fair value of the liability for ARO in the period in which the liability is incurred (at the time the wells are drilled or acquired) with the offset to property cost. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed.

Depletion, depreciation, amortization and accretion expense increased by $32.9 million for the year ended December 31, 2023, compared to the year ended December 31, 2022. The increase for the year ended December 31, 2023 was primarily due to depletion associated with the oil and natural gas acquired in the New Mexico Acquisition and higher production on historical properties along with a higher depletion rate on the historical properties.

Impairment of Oil and Natural Gas Properties

The cost of proved oil and natural gas properties are assessed on a field-by-field basis for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We compare the expected undiscounted future cash flows of the oil and natural gas properties to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil and natural gas properties to estimated fair value.

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During the year ended December 31, 2023, the Company recognized an impairment loss on proved properties of $9.8 million relating to certain properties in Texas outside of the Company's acreage in the Champions Field. This impairment was primarily driven by notably lower commodity pricing at the time of measurement of fair value at year-end 2023. The Company recognized an impairment loss on proved properties of $7.3 million for the year ended December 31, 2022, which related to a decrease in fair value of its historical properties in New Mexico.

General and Administrative Expense ("G&A")

G&A expenses include corporate overhead such as payroll and benefits for our corporate staff, share-based compensation expense, office rent for our headquarters, audit and other fees for professional services and legal compliance. G&A expenses are reported net of overhead recoveries.

Total G&A expense increased by $11.5 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Administrative costs, which include payroll, benefits and non-payroll costs, increased by $8.1 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. The increase in administrative costs was primarily attributable to increased employee count, professional services, insurance, technology and office costs, which were impacted by additional needs as a result of the New Mexico Acquisition. Share-based compensation expense increased by $3.4 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. The increase in share-based compensation expense resulted from the increase in outstanding equity awards due in part to higher employee count as well as expense associated with equity awards attributable to a separation agreement with a former Company executive.

Transaction Costs

Transaction costs represent costs incurred on successful or unsuccessful business combinations or unsuccessful property acquisitions. The transaction costs of $5.8 million for the year ended December 31, 2023 relate to the New Mexico Acquisition. During the year ended December 31, 2022, the transaction costs of $2.6 million primarily related to a potential business combination and related financing that the Company pursued but ultimately chose not to consummate due to changing market conditions.

Interest Expense

Interest expense increased by $30.7 million during the year ended December 31, 2023 when compared to the year ended December 31, 2022. The increase in interest expense was primarily due to the higher debt balances as a result of financing for the New Mexico Acquisition, along with higher interest rates on borrowings under our Credit Facility for the year ended December 31, 2023 when compared to rates for the year ended December 31, 2022. Additionally, interest expense decreased during 2022 as a result of the Company settling the remaining open position on its previous interest rate swap resulting in a settlement benefit of $1.5 million.

Gain/Loss on Derivatives

The Company recognizes settlements and changes in the fair value of its derivative contracts as a single component within other income (expense) on its consolidated statements of operations. We have oil and natural gas derivative contracts, including fixed price swaps, basis swaps and collars, that settle against various indices. The following table presents the components of the Company's gain (loss) on derivatives, net for the years ended December 31, 2023 and 2022:

Our earnings are affected by the changes in value of our derivative portfolio between periods and the related cash received or paid upon settlement of our derivatives. To the extent the future commodity price outlook declines between periods, we will have mark-to-market gains, while future commodity price increases between measurement periods result in mark-to-market losses.

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The gain on derivatives for the year ended December 31, 2023 was $6.2 million compared to a loss on derivatives of $51.6 million for the year ended December 31, 2022. The change was primarily driven by a $58.0 million decrease in the cash payments on settlements of derivatives due to the decrease in oil and natural gas prices for the year ended December 31, 2023 compared to the year ended December 31, 2022.

Income Tax Expense

Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. See Note 11 - Income Taxes in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules for a full discussion of income taxes.

The rise in our effective income tax rate was primarily due to the New Mexico Acquisition increasing our apportionment in New Mexico, which has a higher state tax rate than where we have historically operated.

Liquidity and Capital Resources

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, like all upstream operators, we must make capital investments to grow and even sustain production. The Company’s principal liquidity requirements are to finance its operations, fund capital expenditures and acquisitions, make cash distributions and satisfy any indebtedness obligations. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our cash on hand, cash flow from operations, borrowings under our Credit Facility and the issuance of our Senior Notes. At times and as needed, we may also issue debt or equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of the sources of capital discussed above will continue to be adequate to meet our short and long-term liquidity needs.

Cash on hand and operating cash flow can be subject to fluctuations due to trends and uncertainties that are beyond our control. Likewise, our ability to issue equity and obtain credit facilities on favorable terms may be impacted by a variety of market factors as well as fluctuations in our results of operations. For further discussion of risks related to our liquidity and capital resources, see "Item 1A. Risk Factors."

Working Capital

Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements is driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. As of December 31, 2023, we had a working capital deficit of $31.1 million compared to a deficit of $25.3 million as of December 31, 2022. The current portion of our Senior Notes, which includes our regularly scheduled principal payments of $5 million per quarter, accounts for $20.0 million of our working capital deficit at December 31, 2023. Additionally, increases in our revenue payable, resulting from revenue suspense associated with oil and natural gas properties acquired in the New Mexico Acquisition, contributed to the working capital deficit. Partially offsetting these higher current liabilities was an increase of $5.0 million in current derivative assets and higher accounts receivable associated with increased oil and natural gas sales. We utilize our Credit Facility and cash on hand to manage the timing of cash flows and fund short-term working capital deficits. Our current derivative assets and liabilities represent the mark-to-market value as of December 31, 2023 of future commodity production

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which will settle on a monthly basis through the end of their contractual terms. This aligns with the receipt of oil and natural gas revenues on a monthly basis.

Cash Flows

The following table summarizes the Company’s cash flows for the years ended December 31, 2023 and 2022:

Operating Activities

The Company’s net cash provided by operating activities increased by $36.9 million, or 22%, to $207.2 million for the year ended December 31, 2023 from $170.3 million for the year ended December 31, 2022. The increase was primarily driven by a decrease of $58.0 million in payments to settle commodity derivative contracts and an increase in revenues, partially offset by an increase in operating expenses.

Investing Activities

The Company's cash flows used in investing activities increased by $341.3 million to $469.6 million for the year ended December 31, 2023 from $128.3 million for the year ended December 31, 2022. The increase was primarily due to the $324.7 million for the New Mexico Acquisition. Investing activities also increased due to higher year-over-year capital spending for additions to oil and natural gas properties of $23.1 million, or 21%, related to the Company's increased drilling and completion activity during the year ended December 31, 2023 compared to the year ended December 31, 2022, partially attributable to the larger asset base following the New Mexico Acquisition.

Financing Activities

Net cash flow provided by financing activities increased by $301.4 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. During the year ended December 31, 2023, the Company had net borrowings on its Credit Facility of $129.0 million and proceeds from issuance of its Senior Notes, net of repayments, of $173.0 million, compared to a net paydown of $9.0 million on its Credit Facility for the same period in 2022. The increase in proceeds from borrowings was primarily attributable to the New Mexico Acquisition. In addition, the Company distributed an additional $2.6 million of dividends on common stock during the year ended December 31, 2023 compared to the same period in 2022 as a result of higher outstanding share count and a higher dividend per share.

Credit Facility and Senior Notes

The Company's borrowing base on its Credit Facility was $375 million with outstanding borrowings of $185 million on December 31, 2023, representing available borrowing capacity of $190 million.

On February 22, 2023, the Company amended its Credit Facility to, among other things, allow for the issuance of unsecured Senior Notes of up to $200 million. On April 3, 2023, and concurrent with the closing of the New Mexico Acquisition, the Company entered into the fourteenth amendment to the Credit Facility to, among other things, increase the maximum facility amount to $1.0 billion and the borrowing base from $225 million to $325 million, resulting in the addition of new lenders to the lending group. On November 14, 2023, through the semi-annual redetermination, the Company increased its borrowing base to $375 million, resulting in the addition of two new lenders and the exit of one lender. The Credit Facility is set to mature in April 2026. Substantially all of the Company’s assets are pledged to secure the Credit Facility.

During the year ended December 31, 2023, the Company issued $200 million in principal amount of Senior Notes with a maturity date of April 2026. The proceeds from the Senior Notes were used to finance the New Mexico Acquisition. The principal balance of the Senior Notes as of December 31, 2023 was $185 million.

See Note 9 - Long-Term Debt in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our long-term debt.

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Distributions

For the year ended December 31, 2023, the Company authorized and declared quarterly dividends totaling approximately $27.9 million, with $27.3 million paid in cash and $0.6 million payable to holders of restricted stock upon vesting. For the years ended December 31, 2023 and 2022, the Company paid cash dividends of approximately $0.5 million and $0.2 million, respectively, to holders of restricted stock upon vesting.

Contractual Obligations

As of December 31, 2023, the Company has commitments with its primary midstream counterparty and has purchase commitments totaling $13.1 million related to its 2024 drilling program. In addition, the Company entered into an agreement to form a joint venture and is committed to contributing its portion of capital expenditures into the joint venture company and further entered into a tolling agreement to commit to providing the natural gas needed for the joint venture. See Note 13 - Commitments and Contingencies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our commitments and contingencies.

Critical Accounting Estimates

The preparation of financial statements requires the Company to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

Changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and assumptions used in preparation of the Company’s consolidated financial statements and it is at least reasonably possible these estimates could be revised in the near term and these revisions could be material.

Method of Accounting for Oil and Natural Gas Properties

We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities which requires management's assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.

Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. At the end of each quarter, the status of all suspended exploratory drilling costs are reviewed to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program is considered.

Similar to the evaluation of suspended exploratory well costs, costs for unproved leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, unproved leasehold costs are assessed for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2023, the Company had approximately $100.2 million of unproved leasehold. Of the remaining unproved leasehold costs at December 31, 2023, approximately $2.3 million is scheduled to expire in 2024. The Company expects to renew or extend these leases in 2024. If our drilling is not successful, this leasehold could become partially or entirely impaired.

Once a well is drilled, capitalized well costs for drilling and completion activities must be evaluated at least yearly or whenever facts and circumstances indicate a decline in the recoverability of their carrying value may have occurred. At the end of each year, the undiscounted future cash flows are compared to the carrying value on a field basis to evaluate if the carrying value is recoverable. If the carrying value is not recoverable, the Company will compare the carrying value of the asset to its fair value and recognize any impairment loss in the period. Significant inputs and judgements are used in determining the fair value of the assets. The Company utilizes a discounted cash flow model in order to estimate fair value by modeling the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk

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and current market conditions associated with the expected cash flow projected. During the year ended December 31, 2023, the Company recognized a proved property impairment of $9.8 million relating to certain properties in Texas outside of the Company's acreage in the Champions Field. The Company recognized an impairment loss on proved properties of $7.3 million for the year ended December 31, 2022, which related to a decrease in fair value of its historical properties in New Mexico.

Oil and Natural Gas Reserves

Our estimates of proved and proved developed reserves are a major component of our depletion calculation. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, natural gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. A third-party reservoir engineering firm prepares our reserve report, which the estimates are based off of technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. 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.

Business Combinations

The Company periodically acquires assets and assumes liabilities in transactions accounted for as business combinations, such as the New Mexico Acquisition. In connection with the New Mexico Acquisition, we allocated the purchase price consideration of $324.7 million to the assets acquired and liabilities assumed based on estimated fair values as of the date of the acquisition.

We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the New Mexico Acquisition. The most significant assumptions relate to the estimated fair values of proved and unproved oil and gas properties. The fair value of identifiable assets acquired and liabilities assumed is determined based on various valuation techniques, including market prices, discounted cash flow analysis, and independent appraisals. Significant judgments and assumptions are inherent in these valuation techniques and include, among other things, estimates of reserves, estimates of future commodity prices, expected development costs, lease operating costs and the discount rate that reflects the risk of the underlying cash flow estimates.

Estimated fair values assigned to assets acquired can have a significant impact on future results of operations presented in the Company's financial statements. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. In the event that future commodity prices or reserve quantities are lower than those used as inputs to determine estimates of acquisition date fair values, the likelihood increases that certain costs may be determined to not be recoverable.

See Note 4 - Acquisitions of Oil and Natural Gas Properties in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our acquisitions.

See Note 3 - Summary of Significant Accounting Policies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our significant accounting policies.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the Company’s financial condition and results of operations should be read in conjunction with the Company’s consolidated financial statements and related notes thereto presented in this Annual Report. The following discussion contains “forward-looking statements” that reflect the Company’s future plans, estimates, beliefs and expected performance. The Company’s actual results could differ materially from those discussed in these forward-looking statements. See "Cautionary Statement Regarding Forward-Looking Statements" and "Part I. Item 1A. Risk Factors."

Overview

We operate in the upstream segment of the oil and natural gas industry and are focused on steadily growing conventional reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas and NGLs primarily in the Permian Basin in West Texas. The Company’s activities are primarily focused on the San Andres Formation, a shelf margin deposit on the Northwest Shelf of the Permian Basin. We intend to continue to develop our reserves and increase production through development drilling and exploration activities and through acquisitions that meet our strategic and financial objectives.

Financial and Operating Highlights

Financial and operating results reflect the following:

•Increased total net equivalent production by 33% to 11.5 MBoe/d for the year ended December 31, 2022, as compared to the year ended September 30, 2021

•During the year ended December 31, 2022, 15 gross (11.8 net) horizontal wells brought online to production

•Realized average combined price on production sold of $76.05 per Boe, before derivative settlements, during the year ended December 31, 2022, including $92.86 per barrel for oil

•Generated cash flow from operations of $170.3 million for the year ended December 31, 2022

•Incurred total accrual (activity based) capital expenditures before acquisitions of $123.1 million for the year ended December 31, 2022 as compared to $71.3 million for the year ended September 30, 2021

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•Paid cash dividends on common shares of $25.1 million during the year ended December 31, 2022, and announced latest dividend of $0.34 per share with a record date of January 25, 2023, which was paid on February 8, 2023, for a total of $6.7 million

•Exited the year with $13.3 million in cash and $56.0 million drawn on our revolving credit facility

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Recent Developments

Fiscal Year Change

On August 16, 2022, the Company's Board acting by written consent resolved to amend and restate the Company's Second Amended and Restated Bylaws to change the Company's fiscal year period from October 1st through September 30th each year to January 1st through December 31st each year commencing with the 2022 calendar year. On August 19, 2022, the holders of approximately 75% of our outstanding Common Stock acting by written consent approved Bylaws Restatement and adopted the Third Amended and Restated Bylaws. In accordance with Rule 14c-2 under the Exchange Act, the aforementioned actions taken by written consent became effective on September 23, 2022. As a result, the Company's 2022 fiscal year was the period from January 1, 2022 to December 31, 2022.

Market Conditions, Commodity Prices and Interest Rates

U.S. and global markets are experiencing heightened volatility following impactful geopolitical events, consistent evidence of widespread inflation, as well as increased fears of an economic recession. However, commodity prices have continued to remain high during 2022 due to OPEC+ and other oil and natural gas producers not rapidly increasing production levels, as well as from the recovery in demand related to the COVID-19 pandemic. The full-scale military invasion of Ukraine by Russian troops has continued unabated since February 2022 coupled with related economic sanctions imposed on Russia further exacerbating supply shortages, leading to disruptions in the credit and capital markets, including significant uncertainty in commodity prices, during 2022.

In addition, global markets are experiencing significant inflation attributable to a number of factors. Certain of our capital expenditures and expenses are affected by general inflation and we expect costs for 2023 to continue to be a function of supply and demand. Specifically, costs for oilfield equipment and services continue to experience impacts from significant inflation, which we expect to continue for the foreseeable future.

In response to inflation concerns, the U.S. Federal Reserve initiated a monetary tightening policy in 2022, increasing interest rates in June, July, September and November 2022 with public estimates of potential further increases in the future. The Company's floating-rate credit facility is impacted by such rate increases.

The combination of geopolitical events, inflation and the rising rate environment has led to increasing forecasts of a U.S. or global recession. Any such recession could prolong market volatility or cause a decline in commodity prices, among other potential impacts.

The Company cannot estimate the length or gravity of the future impact these events will have on the Company's results of operations, financial position, liquidity and the value of oil and natural gas reserves.

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Results of Operations

Comparison for the years ended December 31, 2022 and September 30, 2021.

The following table sets forth selected operating data for the years ended December 31, 2022 and September 30, 2021:

_____________________

(1)The Company's calculation of the effects of derivative settlements includes losses on the settlement of its commodity derivative contracts. These losses are included under other income (expense) on the Company’s consolidated statements of operations.

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Oil and Natural Gas Revenues

Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Revenues from product sales are a function of the volumes produced, product quality, market prices, and gas Btu content. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The Company’s total oil and natural gas revenue, net increased $170.7 million, or 115%, for the year ended December 31, 2022 compared to the year ended September 30, 2021. The Company’s realized average combined price on its production for the year ended December 31, 2022 increased by $28.93 per Boe, or 61% compared to the year ended September 30, 2021.

Oil revenues

•For the year ended December 31, 2022, oil revenues increased by $162.3 million, or 119%, compared to the year ended September 30, 2021. Of the increase, $111.2 million was attributable to an increase in our realized price and $51.1 million was attributable to an increase in volume. Volumes increased by 37%, while realized prices increased by 59% compared to the year ended September 30, 2021.

•Oil volumes increased during the year ended December 31, 2022 due to production from new wells and workovers performed on existing wells. During the year ended December 31, 2022, we brought online 15 gross (11.8 net) horizontal wells.

•The average WTI price increased by $35.50 per Bbl during the year ended December 31, 2022 when compared to the year ended September 30, 2021, respectively.

Natural gas revenues

•For the year ended December 31, 2022, natural gas revenues increased by $3.3 million, compared to the year ended September 30, 2021, to $10.8 million from $7.5 million. Volumes increased by 24%, while realized prices increased by $0.45 per Mcf compared to the year ended September 30, 2021.

•Natural gas sales volumes increased during the year ended December 31, 2022 compared to the year ended September 30, 2021 due to production from new wells and workovers performed on existing wells.

•The average Henry Hub price increased by $3.11 per Mcf during the year ended December 31, 2022 compared to the year ended September 30, 2021.

Natural gas liquids revenues

•For the year ended December 31, 2022, NGL revenues increased by $5.2 million, compared to the year ended September 30, 2021, to $9.9 million from $4.7 million. Volumes increase by 17%, while realized prices increased $9.81 per Bbl compared to the year ended September 30, 2021.

•NGL sales volumes increased during the year ended December 31, 2022 compared to the year ended September 30, 2021 due to production from new wells and workovers performed on existing wells.

Contract Services - Related Party

The following table presents the Company's revenue and costs associated with its contract services - related party transactions:

_____________________

(1)The Company’s contract services - related parties revenue is derived from master services agreements with related parties to provide certain administrative support services.

(2)The Company's cost of contract services - related parties represents costs specifically attributable to the master service agreements the Company has in place with the respective related parties.

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Costs and Expenses

The following table presents the Company's operating costs and expenses and other (income) expenses:

Lease Operating Expenses ("LOE")

LOE are the costs incurred in the operation and maintenance of producing properties. Expenses for compression, direct labor, saltwater disposal and materials and supplies comprise the most significant portion of our lease operating expenses. Certain operating cost components, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities or subsurface maintenance result in increased production expenses in periods during which they are performed. Certain operating cost components, such as compression and saltwater disposal associated with completion water, are variable and increase or decrease as hydrocarbon production levels and the volume of completion water disposal increases or decreases.

The Company’s LOE increased by $10.5 million for the year ended December 31, 2022 compared to the year ended September 30, 2021. For the year ended December 31, 2022, $5.4 million of the increase was due to higher workover expense as additional workovers were performed in the 2022 period, and $4.2 million of the increase was due to electricity and chemical rate increases, increase in field payroll, saltwater disposal charges, and new wells coming online.

Production and Ad Valorem Tax Expense

Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate.

Production and ad valorem taxes increased by $10.6 million for the year ended December 31, 2022 compared to the year ended September 30, 2021. Production taxes increased primarily due to increases in our oil and natural gas sales, net, as discussed above. Ad valorem taxes increased for the year ended December 31, 2022 based on higher estimated property values for the current taxable period.

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Exploration Expense

Exploration expense consists of expiration of unproved leasehold and geological and geophysical costs which include seismic survey costs. The following table presents exploration expense by area for the year ended December 31, 2022 and the year ended September 30, 2021:

_____________________

(1)For the year ended December 31, 2022, exploration expense includes $1.8 million and $0.2 million related to expiration of unproved leasehold costs in Texas and New Mexico, respectively. For the year ended September 30, 2021, exploration expense included $3.5 million and $5.8 million related to expiration of unproved leasehold costs in Texas and New Mexico, respectively.

(2)The Company did not renew any net acreage after expiration in New Mexico during the year ended December 31, 2022 and the year ended September 30, 2021.

Depletion, Depreciation, Amortization and Accretion Expense

Depletion, depreciation and amortization is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil, natural gas and NGLs. All costs incurred in the acquisition, exploration and development of properties (excluding costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration activities) are capitalized. Capitalized costs are depleted using the units of production method.

Accretion expense relates to ARO. We record the fair value of the liability for ARO in the period in which the liability is incurred (at the time the wells are drilled or acquired) with the offset to property cost. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed.

Depletion, depreciation, amortization and accretion expense increased by $6.1 million for the year ended December 31, 2022, respectively, compared to the year ended September 30, 2021. The increase for the year ended December 31, 2022 was primarily due to higher production, partially offset by a lower depletion rate. The depletion rate is a function of capitalized cost and related underlying reserves. The lower depletion rate was primarily driven by an increase in reserves as a result of the Company's drilling activity and improved commodity prices.

Impairment of Oil and Natural Gas Properties

The cost of proved oil and natural gas properties are assessed on a field-by-field basis for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We compare the expected undiscounted future cash flows of the oil and natural gas properties to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil and natural gas properties to estimated fair value.

The Company recognized an impairment loss on proved properties of $7.3 million for the year ended December 31, 2022. The impairment loss relates to the New Mexico field and was driven by the Company focusing its drilling efforts on its acreage in Yoakum County. No impairment loss was recognized for the year ended September 30, 2021.

General and Administrative Expense ("G&A")

G&A expenses include corporate overhead such as payroll and benefits for our corporate staff, equity-based compensation expense, office rent for our headquarters, audit and other fees for professional services and legal compliance. G&A expenses are reported net of overhead recoveries.

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Total G&A expense increased by $1.2 million for the year ended December 31, 2022 compared to the year ended September 30, 2021. Administrative costs, which include payroll, benefits and non-payroll costs, increased by $4.5 million for the year ended December 31, 2022 compared to the year ended September 30, 2021. The increase in administrative costs was primarily attributable to increased employee count, professional services, insurance, technology, investor relations, and costs related to transitioning fiscal year-ends. Equity-based compensation expense decreased by $3.3 million for the year ended December 31, 2022 compared to the year ended September 30, 2021. The higher equity-based compensation during the year ended September 30, 2021 relates to restricted shares awarded to certain employees following completion of the Merger that immediately vested.

Transaction Costs

Transaction costs represent costs incurred on successful or unsuccessful business combinations or unsuccessful property acquisitions. The transaction costs of $2.6 million for the year ended December 31, 2022 primarily relate to a potential business combination and related financing that the Company pursued but ultimately chose not to consummate due to changing market conditions. During the year ended September 30, 2021, the transaction costs of $3.7 million primarily relate to costs incurred on the Merger with Tengasco in February 2021.

Interest Expense

Interest expense decreased by $3.4 million during the year ended December 31, 2022 when compared to the year ended September 30, 2021. The Company had a lower outstanding average balance on the revolving credit facility as well as an increase in the capitalized interest related to the Company's EOR project, partially offset by an increase in interest rates, during the year ended December 31, 2022 when compared to the year ended September 30, 2021. Additionally, interest expense decreased due to the Company settling the remaining open position on its interest rate swap resulting in a settlement of $1.5 million during 2022.

Gain/Loss on Derivatives

The Company recognizes settlements and changes in the fair value of its derivative contracts as a single component within other income (expense) on its consolidated statements of operations. We have oil and natural gas derivative contracts, including fixed price swaps, basis swaps and collars, that settle against various indices. The following table presents the components of the Company's loss on derivatives for the year ended December 31, 2022 and the year ended September 30, 2021:

Our earnings are affected by the changes in value of our derivative portfolio between periods and the related cash received or paid upon settlement of our derivatives. To the extent the future commodity price outlook declines between periods, we will have mark-to-market gains, while future commodity price increases between measurement periods result in mark-to-market losses.

The loss on derivatives for the year ended December 31, 2022 was $51.6 million, which decreased by $37.6 million compared to the year ended September 30, 2021. The change in the non-cash gain (loss) on derivatives was impacted by the decrease in total contract volumes for our open derivative contracts and the change in the estimated forward-looking oil and natural gas prices used at the end of the period to calculate the fair value of the open derivative contracts for the year ended December 31, 2022 compared to the year ended September 30, 2021. The increase in the loss on settlements on derivatives was due to the increase in oil and natural gas prices for the year ended December 31, 2022 compared to the year ended September 30, 2021. For example, the average WTI price was $94.90 per Bbl for the year ended December 31, 2022 compared to $59.40 per Bbl for the year ended September 30, 2021.

Income Tax Expense

The Company became a taxable entity as a result of its Merger with Tengasco on February 26, 2021. See further discussion in Note 4 - Acquisitions and Divestitures to the Company's consolidated financial statements included herein. While REP LLC was organized as a limited liability company, taxable income passed through to its unitholders. Accordingly, a provision for

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federal and state corporate income taxes has been made for the operations of the Company beginning February 27, 2021 in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon consummation of the Merger in February 2021, the Company established a $13.6 million provision for deferred income taxes with the conversion to a C-corporation. The majority of this deferred tax liability was established by a change in tax status which primarily was attributable to the oil and natural gas properties. See Note 11 - Income Taxes to the Company's consolidated financial statements included herein for further discussion of income taxes.

Liquidity and Capital Resources

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, like all upstream operators, we must make capital investments to grow and even sustain production. The Company’s principal liquidity requirements are to finance its operations, fund capital expenditures and acquisitions, make cash distributions and satisfy any indebtedness obligations. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our cash on hand, cash flow from operations and borrowings under our revolving credit facility. At times and as needed, we may also issue debt or equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of the sources of capital discussed above will continue to be adequate to meet our short and long-term liquidity needs.

Cash on hand and operating cash flow can be subject to fluctuations due to trends and uncertainties that are beyond our control. Likewise, our ability to issue equity and obtain credit facilities on favorable terms may be impacted by a variety of market factors as well as fluctuations in our results of operations. For further discussion of risks related to our liquidity and capital resources, see "Item 1A. Risk Factors."

Working Capital

Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements is driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. As of December 31, 2022, we had a working capital deficit of $25.3 million compared to a deficit of $32.8 million as of December 31, 2021. The working capital deficit at December 31, 2022 reflects $16.5 million in current derivative liabilities compared to $31.0 million in current derivative liabilities at December 31, 2021. As of December 31, 2022, we had an increase of $14.1 million in accrued capital expenditures and ad valorem tax. We utilize our revolving credit facility and cash on hand to manage the timing of cash flows and fund short-term working capital deficits. Our current derivative assets and liabilities represent the mark-to-market value as of December 31, 2022 of future commodity production which will settle on a monthly basis through the end of their contractual terms. This aligns with the receipt of oil and natural gas revenues on a monthly basis.

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Cash Flows

The following table summarizes the Company’s cash flows from continuing operations:

Operating Activities

The Company’s net cash provided by operating activities increased by $84.2 million or 98% to $170.3 million for the year ended December 31, 2022 from $86.1 million for the year ended September 30, 2021. The increase was primarily driven by an increase in revenues of $170.7 million, partially offset by an increase of $59.0 million on settlements for commodity derivative contracts and an increase in operating expenses of $24.4 million, which excludes non-cash expenses such as equity-based compensation, expiration of unproved leasehold costs, impairment of oil and natural gas properties and depreciation, depletion, accretion and amortization expense.

Investing Activities

The Company's cash flows used in investing activities increased by $68.6 million or 115% to $128.3 million for the year ended December 31, 2022 from $59.6 million for the year ended September 30, 2021. The increase was primarily due to higher capital spending of $53.3 million related to the Company's increased drilling and completion activity and activity on its EOR Project during the year ended December 31, 2022 compared to the year ended September 30, 2021, in addition to $15.3 million for the purchase of land during the year ended December 31, 2022.

Financing Activities

Net cash flow used in financing activities increased by $22.1 million or 148% to $37.0 million for the year ended December 31, 2022 from $14.9 million for the year ended September 30, 2021. During the year ended September 30, 2021, the Company issued $46.7 million of equity, net of offering costs. These proceeds were primarily used to paydown amounts outstanding on the revolving credit facility. There was no equity issued in 2022. During the year ended December 31, 2022, the Company had a net paydown on its revolving credit facility of $9.0 million, which compares to a net paydown of $41.0 million for the same period in 2021. In addition, the Company distributed an additional $6.8 million of dividends on common stock during the year ended December 31, 2022 compared to the same period in 2021.

Revolving Credit Facility

The Company's borrowing base was $225 million with outstanding borrowings of $56 million on December 31, 2022, representing available borrowing capacity of $169 million. See further discussion in Note 9 - Revolving Credit Facility to the Company's consolidated financial statements included herein.

On April 29, 2022, the Company amended its Credit Agreement to, among other things, increase the borrowing base from $175 million to $200 million, extend the maturing date to April 2026, replace LIBOR with the SOFR and change the requirements for hedging to be based on utilization of the borrowing base and the Company's leverage ratio. On October 25, 2022, the Company subsequently amended its Credit Agreement to, among other things, increase the borrowing base from $200 million to $225 million and change the semi-annual redeterminations to April 1 and October 1 to align with the Company's new fiscal year end of December 31st.

Distributions

For the year ended December 31, 2022, the Company authorized and declared a quarterly dividend totaling approximately $25.3 million, with $24.7 million paid in cash and $0.6 million payable to restricted shareholders upon vesting.

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Contractual Obligations

The Company has commitments with its primary midstream counterparty and has entered into purchase commitments throughout the year ended December 31, 2022. See Note 14 - Commitments and Contingencies in our notes to the consolidated financial statements.

Critical Accounting Estimates

The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s consolidated financial statements and accompanying notes included herein, which have been prepared in accordance with U.S. GAAP. The preparation of financial statements requires the Company to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

Changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and assumptions used in preparation of the Company’s consolidated financial statements and it is at least reasonably possible these estimates could be revised in the near term and these revisions could be material.

Method of Accounting for Oil and Natural Gas Properties

We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities which requires management's assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.

Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. Development wells are always capitalized. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. At the end of each quarter, the status of all suspended exploratory drilling costs are reviewed to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program is considered. If future development activities and the determination of proved reserves are unlikely to occur, the associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the consolidated statements of operations. Otherwise, the costs of exploratory wells remain capitalized.

Similar to the evaluation of suspended exploratory well costs, costs for unproved leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, unproved leasehold costs are assessed for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2022, the Company had approximately $12.8 million of unproved leasehold. Of the remaining unproved leasehold costs at December 31, 2022, approximately $0.6 million is scheduled to expire in 2023. The Company will renew or extend the lease if the leasehold expiring in 2023 relates to areas in which the Company is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.

Once a well is drilled, capitalized well costs for drilling and completion activities must be evaluated at least yearly or whenever facts and circumstances indicate a decline in the recoverability of their carrying value may have occurred. At the end of each year, the undiscounted future cash flows are compared to the carrying value on a field basis to evaluate if the carrying value is recoverable. If the carrying value is not recoverable, the Company will compare the carrying value of the asset to its fair value and recognize any impairment loss in the period. Significant inputs and judgements are used in determining the fair value of the assets. The Company utilizes a discounted cash flow model in order to estimate fair value by modeling the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with the expected cash flow projected. During the year ended December 31, 2022, the Company recognized a proved property impairment of $7.3 million related to the oil and natural gas properties in New Mexico.

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Oil and Natural Gas Reserves

Our estimates of proved and proved developed reserves are a major component of our depletion calculation. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, natural gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. A third-party consulting firm prepares our reserve report which the estimates are based off of technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. 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.

Goodwill

We test goodwill for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. If the fair value is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available, the fair value is estimated based upon a valuation analyses including comparable companies and transactions and premiums paid. An impairment loss is recognized if the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill.

The Company recognized goodwill of $19.0 million from the result of the Merger, all of which was allocated to the oil and natural gas properties acquired from the Merger. The Company bypassed the qualitative analysis to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying value amount, including goodwill, since the Company entered into a PSA shortly after acquiring the oil and natural gas properties. The Company compared the reporting unit fair value of $3.5 million with its carrying amount, including goodwill, of $19.0 million and recognized a goodwill impairment of $18.5 million. The impairment loss was recognized within loss from discontinued operations for the year ended September 30, 2021 in our consolidated statement of operations.

See Note 3 - Summary of Significant Accounting Policies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our significant accounting policies.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the Company’s financial condition and results of operations should be read in conjunction with the Company’s consolidated financial statements and related notes thereto presented in this Annual Report. The following discussion contains “forward-looking statements” that reflect the Company’s future plans, estimates, beliefs and expected performance. The Company’s actual results could differ materially from those discussed in these forward-looking statements. See "Cautionary Statements Regarding Forward-Looking Statements" and "Part I. Item 1A. Risk Factors".

Overview

We operate in the upstream segment of the oil and gas industry and are focused on steadily growing conventional reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas and NGLs primarily in the Permian Basin. The Company’s activities are primarily focused on the San Andres Formation, a shelf margin deposit on the Central Basin Platform and Northwest Shelf. We intend to continue to develop our reserves and increase production through development drilling and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives.

Financial and Operating Highlights

Financial and operating results reflect the following:

•Increased total net equivalent production by 22% to 8.6 MBoe/d for the year ended September 30, 2021, as compared to the same period in 2020

•During the year ended September 30, 2021, 20 gross (14 net) horizontal wells brought online to production

•Began initial, planning, permitting and drilling operations on the EOR Project

•Realized average combined price on production sold of $47.12 per Boe, before derivative settlements, during the year ended September 30, 2021, including $58.29 per barrel for oil

•Completed common stock issuance in fiscal fourth quarter 2021 resulting in approximately $46.7 million of proceeds after underwriter costs and other offering costs

•Generated cash flow from continuing operations of $86.1 million for the year ended September 30, 2021

•Total cash capital expenditures before acquisitions of $60.1 million for the year ended September 30, 2021

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•Paid cash dividends on common units/shares of $18.3 million during the year ended September 30, 2021 and announced latest dividend of $0.31 per share with a record date of October 21, 2021, which was paid on November 4, 2021, for a total of $6.0 million

•Exited the fourth quarter with $17.1 million in cash and $60.0 million drawn on our revolving credit facility; subsequently increased our borrowing base from $135 million to $175 million in October 2021

Recent Developments

EOR Project

The Company began initial planning, permitting and drilling operations on its EOR Project, which will utilize a combination of water and CO2 injection through vertical wells, applied to horizontal producing wells at its core asset in Yoakum County, Texas. These wells are directly adjacent to several of the largest EOR projects in the U.S., which have employed EOR techniques for many decades.

Common Stock Offering

In July 2021, the Company issued 1.67 million shares of its common stock for total proceeds net of underwriter fees and other offering costs of approximately $46.7 million.

Market Conditions and Commodity Prices

The COVID-19 pandemic and the measures being taken to address and limit the spread of the virus significantly reduced global economic activity, resulting in a significant decline in the demand for and prices of oil, natural gas and NGLs.

The Company cannot estimate the full length or gravity of the future impacts at this time and if there is another significant decline in oil price, it could have a material adverse effect on the Company’s results of operations, financial position, liquidity and the value of oil and natural gas reserves.

The Company has developed and implemented a number of safety measures, which have successfully kept our workforce healthy and safe. The Company has established an informational campaign to provide employees an understanding of the virus risk factors and safety measures, as well as timely updates from governmental stay-at-home regulations. Expectations have also been set for employees to communicate immediately if they, or someone they have been in contact with, has experienced symptoms or tested positive for COVID-19. Additional measures include distribution of educational material regarding health and safety guidance, limiting access to common areas within the office, ensuring social distancing guidance by relocating personnel, and other guidelines as recommended by the Center for Disease Control and Prevention and local authorities.

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Results of Operations

Comparison for the Years Ended September 30, 2021 and 2020

The following table sets forth selected operating data for the years ended September 30, 2021 and 2020:

_____________________

(1)The Company's natural gas and NGL sales are presented net of gathering, processing and transportation fees which at times exceed the price received and result in negative average prices.

(2)The Company's calculation of the effects of derivative settlements includes gains (losses) on the settlement of its commodity derivative contracts. These gains (losses) are included under other income and expense on the Company’s consolidated statement of operations.

(3)During the years ended September 30, 2021 and 2020, the Company did not have any natural gas liquids derivative contracts in place. During the year ended September 30, 2020, the Company did not have any natural gas derivative contracts in place.

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Oil and Natural Gas Revenues

Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Revenues from product sales are a function of the volumes produced, product quality, market prices, and gas Btu content. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The Company’s total oil and natural gas revenue, net increased $75.5 million, or 103%, for the year ended September 30, 2021 compared to the same period in 2020. The Company’s realized average combined price on its production for the year ended September 30, 2021 increased by $18.90 or 67%, respectively, compared to the same period of 2020.

Oil revenues

•For the year ended September 30, 2021, oil revenues increased by $61.5 million, or 82%, compared to the same period in 2020. Of the increase, $51.3 million was attributable to an increase in our realized price and $10.2 million was attributable to an increase in volume. Volumes increased by 14% while prices increased by 60% compared to the same period in 2020.

•Oil volumes increased during the year ended September 30, 2021 due to production from new wells and workovers performed on existing wells. During the year ended September 30, 2021, we brought online 20 new gross (14 net) wells.

Natural gas revenues

•For the year ended September 30, 2021, natural gas revenues increased by $8.8 million, compared to the same period in 2020, to $7.5 million from $(1.3) million. Volumes increased by 60% and realized prices increased by $3.66/Mcf from negative effective prices experienced in 2020.

•Natural gas sales volumes increased during the year ended September 30, 2021 due to increased production from new wells brought online and increased gas processing capacity available from the Company's midstream gathering and processing partner.

Natural gas liquids revenues

•For the year ended September 30, 2021, natural gas liquids revenues increased by $5.2 million, compared to the same period in 2020, to $4.7 million from $(0.5) million. Volumes increased by 46% and realized prices increased by $14.31/Bbl from negative effective prices experienced in 2020.

•Natural gas liquids sales volumes increased during the year ended September 30, 2021 due to increased production from new wells brought online and increased gas processing capacity available from the Company's midstream gathering and processing partner.

Contract Services - Related Party Revenue

The following tables present the Company's revenue and costs associated with its related party transactions:

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(1)The Company’s contract services – related parties revenue is derived from master services agreements with related parties to provide certain administrative support services.

(2)The Company's cost of contract services - related parties represents costs specifically attributable to the master service agreements the Company has in place with the respective related parties.

The Company's contract services - related parties decreased for the year ended September 30, 2021 due to the restructuring of the monthly fee in the fourth quarter of fiscal 2020. The monthly fee decreased by $150 thousand per month.

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The following table presents the Company's operating costs and expenses and other (income) expenses:

Lease Operating Expenses

Lease operating expenses ("LOE") are the costs incurred in the operation and maintenance of producing properties. Expenses for compression, direct labor, saltwater disposal and materials and supplies comprise the most significant portion of our lease operating expenses. Certain operating cost components, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities or subsurface maintenance result in increased production expenses in periods during which they are performed. Certain operating cost components, such as compression and salt water disposal associated with completion water, are variable and increase or decrease as hydrocarbon production levels and the volume of completion water disposal increases or decreases.

The Company’s LOE increased by $1.7 million for the year ended September 30, 2021 compared to the same period in 2020. LOE for the year ended September 30, 2020 reflected the reduced activity following the sharp downturn in commodity prices at the time, partially offset by higher workover costs and the addition of new wells in 2021. For the year ended September 30, 2021, LOE reflects additional costs due to higher produced volumes as well as higher costs for certain services due to increased activity in the Permian Basin.

Production and Ad Valorem Tax Expense

Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate. Production and ad valorem taxes increased by $4.4 million for the year ended September 30, 2021 compared to the same period in 2020, primarily due to increases in our production sold resulting from additional wells brought online, workovers performed on existing wells and significantly higher commodity prices. Also contributing to the increase is higher ad valorem taxes based on the increase in property values during the year ended September 30, 2021.

Exploration Expense

Exploration expense, which consists of expiration of unproved leasehold and geological and geophysical costs that include seismic survey costs, decreased by $0.4 million, or 4%, for the year ended September 30, 2021, as compared to the same period in 2020. For the year ended September 30, 2021, the Company incurred lower seismic expense compared to the same period in 2020.

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The following table presents exploration expense by area for the years ended September 30, 2021 and 2021:

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(1)As of September 30, 2021 exploration expense includes $3,516 and $5,831 related to expiration of unproved leasehold costs in Texas and New Mexico, respectively. As of September 30, 2020 exploration expense includes $1,206 and $6,696 related to expiration of unproved leasehold costs in Texas and New Mexico, respectively.

(2)The Company did not renew any net acreage after expiration in New Mexico for the years ended September 30, 2021 and 2020.

Depletion, Depreciation, and Accretion Expense

Depreciation, depletion and amortization is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil, natural gas and NGLs. All costs incurred in the acquisition, exploration and development of properties (excluding costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration activities) are capitalized. Capitalized costs are depleted using the units of production method.

Accretion expense relates to ARO. We record the fair value of the legal liability for ARO in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the asset’s inception, with the offsetting increase to property cost. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed.

Depletion, depreciation, amortization and accretion expense increased by $4.5 million for the year ended September 30, 2021, respectively, compared to the same period for 2020. The increase for the year ended September 30, 2021 was due to higher production in addition to a higher depletion rate due to additional capitalized costs.

General and Administrative Expense ("G&A")

G&A expenses include corporate overhead such as payroll and benefits for our corporate staff, equity-based compensation expense, office rent for our headquarters, audit and other fees for professional services and legal compliance. G&A expenses are reported net of recoveries from other owners in properties operated by us and amounts capitalized pursuant to the successful efforts method. During the year ended September 30, 2021, we incurred, and we expect that we will continue to incur, additional general and administrative expenses as a result of being a publicly-traded company.

Total G&A expense increased by $9.0 million, for the year ended September 30, 2021, compared to the same period for 2020. Administrative costs, which includes payroll, benefits and non-payroll costs, increased by $3.1 million, for the year ended September 30, 2021, compared to the same period for 2020. The increase in administrative costs was primarily attributable to increased audit, filing, legal and professional service costs following completion of the Merger. Equity compensation expense increased by $5.8 million for the year ended September 30, 2021, compared to the same periods for 2020. The increase is primarily attributable to restricted shares awarded to certain executives and employees following completion of the Merger.

Transaction Costs

Transaction costs were $3.7 million and $1.4 million for the year ended September 30, 2021 and 2020, which reflects expenses associated with the Merger.

Interest Expense

Interest expense was $4.5 million and $5.3 million for the years ended September 30, 2021 and 2020, respectively. The decrease in interest expense in the 2021 period was primarily attributable to a lower average balance on the Company's revolving credit facility during the year ended September 30, 2021 when compared to the same period for 2020.

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Gain/Loss on Derivatives

The Company recognizes settlements and changes in the fair value of its derivative contracts as a single component within other income (expenses) on its consolidated statement of operations. We have oil and natural gas derivative contracts, including fixed price swaps, basis swaps and collars, that settle against various indices. The following table presents the components of the Company's gain (loss) on derivatives for the years ended September 30, 2021 and 2020:

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash received or paid upon settlement of our derivatives. To the extent the future commodity price outlook declines between periods, we will have mark-to-market gains; while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

Income Tax Expense

The Company became a taxable entity as a result of its Merger with Tengasco on February 26, 2021. See further discussion in Note 4 - Acquisitions and Divestitures to the Company's consolidated financial statements included herein. While REP LLC was organized as a limited liability company, taxable income passed through to its unit holders. Accordingly, a provision for federal and state corporate income taxes has been made for the operations of REP LLC only from February 27, 2021 through September 30, 2021 in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon consummation of the Merger, the Company established a $13.6 million provision for deferred income taxes with the conversion to a C-corporation. The majority of this deferred tax liability was established by a change in tax status which primarily was attributable to the oil and natural gas properties. See Note 12 - Income Taxes to the Company's consolidated financial statements included herein for further discussion of income taxes.

Liquidity and Capital Resources

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, like all upstream operators, we must make capital investments to grow and even sustain production. The Company’s principal liquidity requirements are to finance its operations, fund capital expenditures and acquisitions, make cash distributions and satisfy any indebtedness obligations. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our cash on hand, cash flow from operations and borrowings under our revolving credit facility. At times and as needed, we may also issue debt or equity securities, including through transactions under our shelf registration statement filed with the SEC. In October 2021, the revolving credit facility was further amended to, among other things increase the borrowing base to $175 million. We estimate the combination of the sources of capital discussed above will continue to be adequate to meet our short and long-term liquidity needs.

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Cash on hand and operating cash flow can be subject to fluctuations due to trends and uncertainties that are beyond our control. Likewise, our ability to issue equity and our ability to obtain credit facilities on favorable terms may be impacted by a variety of market factors as well as fluctuations in our results of operations. For more information on conditions impacting our liquidity and capital resources, see "—Recent Developments." For further discussion of risks related to our liquidity and capital resources, see "Item 1A. Risk Factors."

On July 2, 2021 the Company completed the offering of 1,666,667 shares of common stock at a price to the public of $30.00 per common share. The Company received net proceeds of $46.7 million from the sale of the common stock, after deducting underwriting discounts and commissions, and offering expenses paid by the Company. The Company utilized $35.5 million to pay down its revolving credit facility during its fiscal fourth quarter. The Company intends to draw on the revolving credit facility in order to fund drilling and infrastructure for normal operations as well as for the EOR Project. The remaining net proceeds are expected to be used for working capital purposes and other general corporate purposes, which may include financing of capital expenditures, financing acquisitions or investments, repayment or refinancing of outstanding debt, financing other business opportunities, and working capital purposes.

Working Capital

Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. As of September 30, 2021, we had a working capital deficit of $46.9 million compared to working capital surplus of $13.9 million as of September 30, 2020. The working capital deficit at September 30, 2021 reflects $42.1 million in current derivative liabilities compared to $18.8 million in current derivative assets at September 30, 2020. Additionally, there was an increase of $18.2 million in accounts payable and accrued liabilities as of September 30, 2021 due to increased drilling and completion activity as well as costs incurred for work on the EOR Project. We utilize our revolving credit facility and cash on hand to manage the timing of cash flows and fund short-term working capital deficits.

Cash Flows

The following table summarizes the Company’s cash flows from continuing operations:

Operating Activities

The Company’s net cash provided by operating activities increased by $23.5 million or 38% to $86.1 million for the year ended September 30, 2021 from $62.6 million for the same periods in 2020. The increase was primarily driven by an increase in revenues of $74.1 million, partially offset by a $43.2 million decrease in net cash received for settlements of commodity derivative contracts and an increase in operating expenses, excluding equity based compensation, of $9.7 million.

Investing Activities

The Company's cash flows used in investing activities increased by $8.1 million or 16% to $59.6 million for the year ended September 30, 2021 from $51.5 million for the same period in 2020. The increase was primarily due to higher capital spending of $11.1 million related to the Company's drilling and completion activity in 2021 and additions to other property and equipment by $1.5 million, partially offset by lower acquisitions of oil and natural gas properties by $3.7 million.

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Financing Activities

Net cash flow used in financing activities was $14.9 million during the year ended September 30, 2021, or an increase of $1.8 million, as compared to the same period in 2020. The most significant cash outflow from financing activities was the net repayment of $41.0 million on the revolving credit facility, as compared to net proceeds of $4.0 million in the same period in 2020. Also contributing to the cash outflow from financing activities was $18.3 million for the payment of dividends on common stock and units during the year ended September 30, 2021. Partially offsetting these cash outflows was the $46.7 million in net proceeds during the year ended September 30, 2021 from the issuance of common stock, after deducting underwriter fees and other offering costs.

Revolving Credit Facility

The Company's borrowing base was $135 million with outstanding borrowings of $60 million on September 30, 2021 representing available borrowing capacity of $75 million. In October 2021, the revolving credit facility was further amended to, among other things, increase the borrowing base to $175 million. See further discussion in Note 9 — Revolving Credit Facility to the Company's consolidated financial statements included herein.

Distributions

For the year ended September 30, 2021, the Company authorized and declared quarterly dividends totaling approximately $18.1 million, with $17.8 million paid in cash and $0.3 million payable to restricted shareholders upon vesting.

Contractual Obligations

In July 2021, as part of a planned expansion of Stakeholder’s primary gas processing plant, the Company committed to annually drill, complete and connect a minimum number of wells or deliver an annual target volume to Stakeholder's gathering system. While the minimum number of wells is below our planned development activity, there are financial penalties if the minimum activity levels are not met. The annual well or volume target is for each of five years beginning January 2022. The additional capacity from the gas processing plant expansion is expected to lead to increased natural gas sales and decreased gas flaring for the Company.

In August 2021, the Company entered into a purchase agreement for supplies for its EOR project. Under the agreement, the Company has committed to purchasing supplies totaling approximately $1.2 million and $3.3 million by January 2022 and April 2022, respectively.

Critical Accounting Estimates

The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s consolidated financial statements and accompanying notes included herein, which have been prepared in accordance with U.S. GAAP. The preparation of financial statements requires the Company to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

Changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and assumptions used in preparation of the Company’s consolidated financial statements and it is at least reasonably possible these estimates could be revised in the near term and these revisions could be material.

Method of Accounting for Oil and Natural Gas Properties

We utilize the successful effort method of accounting for our oil and natural gas exploration and development activities which requires management's assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.

Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. Development wells are always capitalized. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have

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been found. At the end of each quarter, the status of all suspended exploratory drilling costs are reviewed to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program is considered. If future development activities and the determination of proved reserves are unlikely to occur, the associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the consolidated statements of operations. Otherwise, the costs of exploratory wells remain capitalized. At September 30, 2021, all suspended well costs have been suspended for greater than one year but less than two years.

Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, undeveloped leasehold costs are assessed for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At September 30, 2021, the Company had approximately $20.6 million of undeveloped leasehold. Of the remaining undeveloped leasehold costs at September 30, 2021, approximately $0.3 million is scheduled to expire in 2022. The Company will renew or extend the lease if the leasehold expiring in 2022 relates to areas in which the Company is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.

Oil and Natural Gas Reserves

Our estimates of proved and proved developed reserves are a major component of our depletion calculation. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. A third-party consulting firm prepares our reserve report which the estimates are based off of technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. 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.

Derivatives

From time to time, we have used commodity derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of oil and natural gas. We exercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, and the prices at which we enter into commodity derivative contracts.

We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.

Income Taxes

The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, and provincial tax jurisdictions. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards.

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Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment. These assumptions and judgments are reviewed and adjusted as facts and circumstances change, with our projection of earnings or losses during the current calendar year being the most significant judgement. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.

Goodwill

We test goodwill for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. If the fair value is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available, the fair value is estimated based upon a valuation analyses including comparable companies and transactions and premiums paid. An impairment loss is recognized if the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill.

The Company recognized goodwill of $19.0 million from the result of the Merger, all of which was allocated to the oil and natural gas properties acquired from the Merger. The Company bypassed the qualitative analysis to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying value amount, including goodwill, since the Company entered into a PSA shortly after acquiring the oil and natural gas properties. The Company compared the reporting unit fair value of $3.5 million with its carrying amount, including goodwill, of $19.0 million and recognized a goodwill impairment of $18.5 million. The impairment loss was recognized within loss from discontinued operations for the year ended September 30, 2021 in our consolidated statement of operations.

See Note 3 - Summary of Significant Accounting Policies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our significant accounting policies.