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Item 7. Management’s Discussion and Analysis

2024-03-07 compared with 2023-03-15 · 105 added, 113 removed, 193 unchanged (53% of the section changed)

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We are an independent oil and natural gas company with a principal focus on acquisition, development and production activities in the U.S.

Mid-Continent.

Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety.

Mid-Continent region ("Mid-Con").

Operational Activities

For the year ended December 31, 2022, there were eight operated wells drilled and six wells completed.

There was no drilling activity on our operated acreage during the year ended December 31, 2021.

However, we brought wells that were previously not producing on to production as part of our well reactivation program during the year ended December 31, 2021.

The chart below shows production by product for the years ended December 31, 2022 and 2021:

(1) For the year ended December 31, 2021, North Park Basin had 67 MBoe in oil production.

Total production for the Company in 2022 was composed of approximately 14.7% oil, 54.4% natural gas and 30.9% NGLs compared to 14.1% oil, 52.5% natural gas and 33.4% NGLs in 2021.

Mid-Continent total production for the years ended December 31, 2022 and 2021 was composed of the following:

For the year ended December 31, 2023, there were two operated wells drilled and four wells completed.

For the year ended December 31, 2022 there were eight operated wells drilled, six wells completed, and 50 wells reactivated.

The charts below show production and percent revenues by product for the years ended December 31, 2023 and 2022:

Total production for the years ended December 31, 2023 and 2022 was composed of the following:

Year Ended December 31,

Oil 17.0 % 14.7 %

NGL 30.9 % 33.7 %

Natural gas 55.3 % 54.4 %

NGL 27.7 % 30.9 %

Total 100.0 % 100.0 %

The increase in oil production was primarily driven by the newly drilled wells as part of our capital development program.

The decrease in total MBoe was primarily driven by a reduction of NGL production, as one of our purchasers elected to retain more ethane in the natural gas stream, which had more favorable market pricing at the time of sales, as well as natural decline of its producing assets.

These factors were partially offset by production added during the third quarter from an acquisition that closed on July 11, 2023, which increased our ownership interest in twenty-six wells we operate.

Highlighted Events

• Consistent with our 2022 capital development program, we drilled eight wells and completed six wells during the year ended December 31, 2022.

• On October 5, 2022 the Company’s Board of Directors appointed Ms.

Nancy Dunlap to serve as a member of the Board.

Dunlap also joined the Audit Committee.

• As part of our well reactivation program, we returned 50 wells to production for the year ended December 31, 2022.

We will continue to focus on growing the cash value and generation capability of our asset base in a safe, responsible and efficient manner, while exercising prudent capital allocations to projects we believe provide high rates of returns in the current commodity price environment.

These projects include (1) a continuation of our well reactivation program, (2) artificial lift conversions to more efficient and cost effective systems and (3) focused drilling in high-graded areas.

• In January 2024, the Board approved a one-time cash dividend of $1.50 per share of the Company's common stock, which was paid on February 20, 2024 to shareholders of record as of the close of business on February 5, 2024.

The aggregate total payout was approximately $55.6 million.

Additionally, in January 2024, the Board announced that it plans to increase its on-going quarterly dividend to $0.11 per share starting with the next quarterly payout, estimated to be first paid in March 2024, continuing every quarter thereafter until noticed, subject to quarterly approval by the Board.

• On July 11, 2023, the Company closed an acquisition that increased its ownership interest in twenty-six producing

wells operated by the Company within the Northwest Stack play for $10.6 million, after customary post-closing

adjustments, with an effective date of April 1, 2023.

The Company used its cash on hand to fund the acquisition.

• In May 2023, the Board approved a one-time cash dividend of $2.00 per share of the Company’s common stock, which was paid on June 7, 2023 to shareholders of record as of the close of business on May 24, 2023.

Additionally, in May 2023, the Board announced a regular quarterly dividend of $0.10 per share of the Company’s common stock, subject to quarterly approval by the Board.

Our dividend payment in May was $73.8 million and the $0.10 dividend payments made in August 2023 and November 2023 totaled $7.4 million.

• In May 2023, the Board approved a stock buyback program authorizing the repurchase of up to $75 million of the

Company’s outstanding common stock in open market transactions.

We will continue to focus on growing the value and cash generation capability of our asset base in a safe, responsible and efficient manner, while exercising prudent capital allocations to projects we believe provide high rates of returns in the current commodity price environment.

These projects include (1) artificial lift conversions to more efficient and cost effective systems, (2) high-graded re-fracturing and recompletion and (3) limited opportunistic leasing in proven areas around or adjacent to our area of operations that could further bolster future development.

While commodity price futures are not yet at preferred levels to resume drilling or further well reactivations at this time, we retain the development option over a reasonable tenor, since our assets are 99% held by production.

We will continue to monitor forward-looking commodity prices, results, costs and other factors that could influence returns on investments, which will continue to shape our disciplined development decisions in 2024 and beyond.

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Conversely, during periods of declining market prices of oil, natural gas and NGL, our commodity derivative contracts may partially offset declining revenues and cash flow to the extent strike prices for our contracts are above market prices at the time of settlement.

Acquisitions and Divestitures of Properties

2021 Acquisitions and Divestitures

On April 22, 2021, we announced the acquisition of all the overriding royalty interest assets of SandRidge Mississippian Trust I (the “Trust”).

The gross purchase price was $4.9 million (net $3.6 million, given our 26.9% ownership of the Trust).

On February 5, 2021, we sold all of our oil and natural gas properties and related assets of the North Park Basin ("NPB") in Colorado for a purchase price of $47 million in cash.

Net proceeds were $39.7 million in cash as a result of customary effective to close date adjustments and a $0.8 million post-close adjustment made during the second half of the year.

The sale resulted in an $18.9 million gain after the post-close adjustment.

Oil, Natural Gas and NGL Production and Pricing

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Year Ended December 31,

2022 2021 Change % Change

2023 2022 Change

Production data (in thousands)

Oil (MBbls) 1,047 949 98

NGL (MBbls) 1,997 2,267 (270) (12) %

Natural gas (MMcf) 20,403 21,101 (698)

NGL (MBbls) 1,705 1,997 (292)

Total volumes (MBoe) 6,152 6,463 (311)

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Oil (per Bbl) $ 74.69 $ 92.21 $ (17.52)

NGL (per Bbl) $ 31.88 $ 22.42 $ 9.46 42 %

Natural gas (per Mcf) $ 1.71 $ 4.88 $ (3.17)

NGL (per Bbl) $ 20.83 $ 31.88 $ (11.05)

Total (per Boe) $ 24.16 $ 39.34 $ (15.18)

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Oil (per Bbl) $ 74.69 $ 92.21 $ (17.52)

NGL (per Bbl) $ 31.72 $ 22.28 $ 9.44 42 %

Natural gas (per Mcf) $ 2.00 $ 4.97 $ (2.97)

NGL (per Bbl) $ 20.83 $ 31.72 $ (10.89)

Total (per Boe) $ 25.11 $ 39.58 $ (14.47)

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(1) Prices represent actual average prices for the periods presented and do not include the impact of derivative transactions.

The table below presents production by area of operation for the years ended December 31, 2022 and 2021.

Year Ended December 31,

Production (MBoe) % of Total Production Production (MBoe) % of Total Production

Mid-Continent 6,463 100.0 % 6,726 99.0 %

North Park Basin — — % 67 1.0 %

Total 6,463 100.0 % 6,793 100.0 %

Consolidated revenues for the years ended December 31, 2023 and 2022 are presented in the table below (in

Year Ended December 31,

2022 2021 Change % Change

2023 2022 Change

Oil $ 78,174 $ 87,528 $ (9,354)

NGL 63,663 50,836 12,827 25 %

Natural gas 34,941 103,067 (68,126)

NGL 35,526 63,663 (28,137)

Total revenues $ 148,641 $ 254,258 $ (105,617)

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2023 oil, natural gas and NGL revenues

Oil, natural gas and NGL revenues increased primarily due to improvements in realized commodity prices.

Production volumes for the year ended December 31, 2022 decreased slightly due to the natural declines of our producing wells, which were partially offset from the production from our well reactivations and new well activity for the year.

Oil, natural gas and NGL revenues decreased primarily due to lower commodity prices.

Production volumes for the year ended December 31, 2023 decreased slightly due to the natural declines of our producing wells, which were partially offset from the production from our new wells and increased ownership interest from our July 2023 acquisition.

Operating Expenses

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Year Ended December 31,

2022 2021 Change % Change

2023 2022 Change

Lease operating expenses $ 41,862 $ 41,286 $ 576

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Production, ad valorem, and other taxes (% of oil, natural gas, and NGL revenue) 7.3 % 6.2 % 1.1 %

The increase in lease operating expenses was primarily due to inflationary pressures, a higher number of producing wells and higher workover expenses due to our well reactivation program during the year ended December 31, 2022.

Production, ad valorem, and other taxes increased primarily due to the increase in production taxes as a result of increased revenues.

The increase in depreciation and depletion for oil and natural gas properties was primarily the result of increased capital expenditures from higher drilling and completion activity which increased our depletion rate.

The increase in lease operating expenses was primarily due to inflationary pressures and higher production costs associated with more producing wells from our prior well reactivations and development program as well as increased ownership interest from our July 2023 acquisition during the year ended December 31, 2023.

Production, ad valorem, and other taxes decreased primarily due to lower commodity prices and related revenues.

However, production, ad valorem, and other taxes increased as a percentage of oil, natural gas and NGL revenue primarily due to higher oil and gas property valuation assessments by local jurisdictions who use historical commodity price averages that included prior periods that were higher than current commodity prices, when determining ad valorem tax assessments.

The increase in depreciation and depletion for oil and natural gas properties was primarily the result of capital expenditures for 2023 and a decrease in proved reserves at December 31, 2023, primarily as a result of lower SEC prices (as defined below), which increased our depletion rate.

Full cost pool impairment.

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The SEC prices utilized in the calculation of proved reserves included in the full cost ceiling test at December 31, 2023 were $78.22 per barrel of oil and $2.64 per MMBtu of natural gas, before price differential adjustments.

Based on the SEC prices over the twelve months ended March 1, 2023, we anticipate the SEC prices utilized in the March 31, 2023 full cost ceiling test may be $90.97 per barrel of oil and $5.96 per MMBtu of natural gas, (the "estimated first quarter prices").

Applying these estimated first quarter prices, and holding all other inputs constant to those used in the

calculation of our December 31, 2022 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2023.

However, a full cost ceiling limitation impairment may still be realized in the first quarter of 2023 and in subsequent quarters based on the outcome of numerous other factors such as additional declines in the actual trailing twelve-month SEC prices, production, lower commodity prices, changes in estimated future development costs and operating expenses, and other revisions to our proved reserves.

Based on the SEC prices over the eleven months ended February 1, 2024 and NYMEX strip pricing for March 2024 as of March 1, 2024, we anticipate the SEC prices utilized in the March 31, 2024 full cost ceiling test may be $77.48 per barrel of oil and $2.44 per MMBtu of natural gas, (the "estimated first quarter prices").

Applying these estimated first quarter prices, and holding all other inputs constant to those used in the calculation of our December 31, 2023 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2024.

However, a full cost ceiling limitation impairment may still be realized in the future based on the outcome of numerous other factors such as additional declines in the actual trailing twelve-month SEC prices, production, lower commodity prices, changes in estimated future development costs and operating expenses, and other revisions to our proved reserves.

Any such ceiling test impairments in 2024 could be material to our net earnings.

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Year Ended December 31,

2022 2021 Change % Change

2023 2022 Change

General and administrative $ 10,735 $ 9,449 $ 1,286

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(Gain) loss on derivative contracts (1,447) (5,975) 4,528

(Gain) loss on sale of assets — (18,952) 18,952 (100.0) %

Other operating expense (income) (157) (99) (58)

Total other operating expenses $ 9,556 $ 3,757 $ 5,799

General and administrative expenses decreased for the year ended December 31, 2022 compared to the year ended December 31, 2021 due to continued efforts of cost control initiatives.

General and administrative expenses increased for the year ended December 31, 2023 primarily due to higher technology, service and personnel costs.

Restructuring expenses represent fees and costs associated with our predecessor company's 2016 bankruptcy filing and our exit from NPB in Colorado.

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(Gain) loss on derivative contracts $ (1,447) $ (5,975)

Cash paid (received) on settlements $ (1,525) $ 2,230

Realized settlement gains (losses) on derivative contracts $ 5,876 $ 1,525

Our derivative contracts are not designated as accounting hedges and, as a result, changes in the fair value of our commodity derivative contracts are recorded quarterly as a component of operating expenses.

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“Quantitative and Qualitative Disclosures about Market Risk” of this report for additional discussion of our commodity derivatives.

Gain on sale of assets for the year ended December 31, 2021 relates to the sale of our NPB assets in Colorado in February 2021.

See "Note 3-Acquisitions, Divestitures and Disposal of Assets and Oil and Gas Properties."

Interest (income) expense, net for the years ended December 31, 2023 and 2022 consisted of the following (in thousands):

Year Ended December 31,

Interest income (expense), net

Interest income $ 10,656 $ 2,026

Interest expense

Interest expense on debt and letters of credit $ 37 $ 377

Interest expense on letters of credit $ (37) $ (37)

Interest expense on right of use assets (64) (36)

Write off of debt issuance costs — 174

Amortization of debt issuance costs, premium and discounts — 57

Capitalized interest — (252)

Interest expense - other (3) (143)

Total 216 407

interest income (2,026) (3)

Total interest expense (104) (216)

Total interest income (expense), net $ 10,552 $ 1,810

Interest (income) expense, net during the year ended December 31, 2023 is primarily comprised of interest income received from cash deposits.

Interest (income) expense, net during the year ended December 31, 2022 is primarily comprised of interest income received from cash deposits partially offset by interest paid on royalty obligations of $0.1 million, interest on vehicle leases and letters of credit.

Interest expense incurred during the year ended December 31, 2021 is primarily comprised of interest and fees paid on the 2020 Credit Facility.

The 2020 Credit Facility has been fully repaid and terminated as of September 2, 2021.

As a result of the termination of the 2020 Credit Facility, $0.2 million of deferred financing costs were expensed to Interest expense.

Other income (expense), net

Other income (expense), net for the years ended December 31, 2022 and 2021 is reflected in the table below (in thousands):

Year Ended December 31,

Other income (expense), net

Other income, net $ 378 $ 3,055

Total other income $ 378 $ 3,055

The Other income (expense), net line item for the year ended December 31, 2022 is primarily comprised of gains on the sale of fleet vehicles and the removal of previously accrued liabilities due to a change in estimate.

For the year ended December 31, 2021, Other income (expense), net is primarily comprised of the removal of $2.4 million of an allowance for doubtful accounts as a result of the $2.4 million being collected in October 2021.

The Other income (expense), net line item was not significant for the year ended December 31, 2023.

For the year ended December 31, 2022, Other income (expense), net of $0.4 million is primarily comprised of gains on the sale of fleet vehicles and the removal of previously accrued liabilities due to a change in estimate.

Income tax (benefit)

We recorded income tax expense and benefit of $14.0 million and $64.5 million for the years ended December 31, 2023 and 2022, respectively, which directly relates to our partial valuation allowance release.

As the partial valuation allowance release as of December 31, 2023 was lower than the partial valuation allowance release as of December 31, 2022 of $64.5 million, we recognized $14.0 million of deferred federal and state income tax expense for the year ended December 31, 2023.

Liquidity and Capital Resources

At December 31, 2023, our cash and cash equivalents, including restricted cash, was $253.9 million.

For the next twelve months, we expect to have ample liquidity with cash on hand and cash from operations.

We expect our cash on hand and cash from operations to be adequate to meet our short and long-term liquidity needs.

As of March 1, 2024 , the Company had no outstanding term or revolving debt obligations.

Our commodity derivative contracts are subject to credit risk of our counterparties being financially able to settle the transaction.

We monitor the credit ratings of our derivative counterparties and consider our counterparties’ credit default risk ratings in determining the fair value of our derivative contracts.

However, any future failures by one or more counterparties could negatively impact our cash flow from operations.

Working Capital and Sources and Uses of Cash

Our principal sources of liquidity for 2022 included cash flow from operations and cash on hand.

Our working capital increased to $241.6 million at December 31, 2022, compared to $97.7 million at December 31, 2021.

The positive impact on working capital resulted primarily from an increase in cash and cash equivalents at December 31, 2022 as a result of cash flows from operations, partially offset by increased accrued liabilities driven largely by our increased capital expenditure activity in 2022.

We intend to spend between $26 million and $35 million in our 2023 capital budget plan, excluding any expenditures for acquisitions.

We intend to fund capital expenditures and other commitments for the next 12 months using cash flows from our operations and cash on hand.

We will endeavor to keep our capital spending within or very close to our projected cash flows from operations subject to changing industry conditions or events.

Our cash flows from operations are substantially dependent on current and future prices for oil and natural gas, which historically have been, and may continue to be, volatile.

For example, during the period from January 2018 through December 2022, the NYMEX WTI settled price for oil fluctuated between a high of $123.64 per Bbl and a low of $(36.98) per Bbl, and the month-end NYMEX Henry Hub settled price for gas fluctuated between a high of $24.74 per Mcf and a low of $1.38 per Mcf.

If oil or natural gas prices decline from current levels, they could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced.

Our principal sources of liquidity for 2024 include cash flow from operations and cash on hand.

Our working capital decreased to $228.5 million at December 31, 2023, compared to $241.6 million at December 31, 2022.

Dividend payments to shareholders of $81.5 million, $26.4 million in capital expenditures, and $11.2 million related to an acquisition of proved reserves were the primary drivers in the reduction of working capital.

These cash outflows were offset by $115.6 million in cash provided by operating activities.

In May 2023, the Board approved a one-time cash dividend of $2.00 per share of the Company’s common stock, which was paid on June 7, 2023 to shareholders of record as of the close of business on May 24, 2023.

The aggregate total payout was $73.8 million.

Additionally, in May 2023, the Board announced plans for a regular quarterly dividend of $0.10 per share, subject to quarterly approval by the Board.

The Company paid quarterly dividends of $3.7 million each on August 28, 2023 and November 27, 2023, totaling $7.4 million, as well as dividends on vested stock awards of $0.3 million for the year.

Total special and regular dividends for the year ended December 31, 2023 were $81.5 million.

See Note 13 for further discussion of the Company’s dividends.

Our cash flows from operations are substantially dependent on current and future prices for oil, natural gas and NGL, which historically have been, and may continue to be, volatile.

For example, during the period from January 2019 through December 2023, the NYMEX WTI settled price for oil fluctuated between a high of $123.64 per Bbl and a low of $(36.98) per Bbl, and the NYMEX Henry Hub spot prices for gas fluctuated between a high of $24.77 per Mcf and a low of $1.38 per Mcf.

If oil, natural gas and NGL prices decline from current levels, they could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced.

Further, if our future capital expenditures are limited or deferred, or we are unsuccessful in developing reserves and adding production through our capital program, the value of our oil and natural gas properties, financial condition and results of operations could be adversely affected.

Cash flows from operations are also affected by timing of cash receipts and disbursements and changes in other working capital assets and liabilities.

Cash flows for the years ended December 31, 2023, and 2022 are presented in the following table and discussed below (in thousands):

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Cash flows provided by operating activities $ 115,578 $ 164,696

Cash flows provided by (used in) investing activities (45,117) 22,973

Cash flows used in investing activities (36,164) (45,117)

Cash flows used in financing activities (82,938) (1,635)

Net increase in cash, cash equivalents and restricted cash $ 117,944 $ 111,258

Net (decrease) increase in cash, cash equivalents and restricted cash $ (3,524) $ 117,944

Cash Flows from Operating Activities

The $54.4 million increase in operating cash flows for the year ended December 31, 2022 compared to 2021, is primarily due to increased revenues which is the result of improved commodity prices as discussed above, offset by a slight decrease in production.

The $49.1 million decrease in operating cash flows for the year ended December 31, 2023 compared to 2022, is primarily due to a decrease in revenues from lower commodity prices.

The changes in operating assets and liabilities do not include changes in accounts payable or accrued expenses attributable to capital expenditures noted in the capital expenditure table below.

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Cash Flows from Investing Activities

During the year ended December 31, 2022, cash flows used in investing activities primarily reflects capital expenditures of $44.1 million related to drilling, capital workovers, well reactivations, and inventory purchases and $1.4 million related to an acquisition of proved reserves.

During the year ended December 31, 2023, cash flows used in investing activities primarily reflects capital expenditures of $26.4 million made for drilling and completions, capital workovers, and well reactivations and $11.2 million related to an acquisition of proved reserves, which increased ownership interests in properties operated by the Company.

Cash outflows were partially offset by $1.5 million of proceeds from the sale of equipment related to our oil and gas assets.

During the year ended December 31, 2022, cash flows used in investing activities primarily reflects capital expenditures of $44.1 million related to drilling and completions, capital workovers, well reactivations, and inventory purchases and $1.4 million related to an acquisition of proved reserves.

Cash outflows were partially offset by $0.4 million of proceeds from the sale of assets.

During the year ended December 31, 2021, cash flows provided by investing activities primarily reflects $38.2 million of net cash proceeds primarily from the sale of the NPB assets partially offset by capital expenditures of $11.6 million and the acquisition of overriding royalty interests for $3.6 million.

See "Note 3 — Acquisitions, Divestitures and Disposal of Assets and Oil and Gas Properties" to the accompanying consolidated financial statements included in Item 8 of this report for additional information.

See "Note 3 — Acquisitions and Divestitures of Assets and Oil and Gas Properties" to the accompanying consolidated financial statements included in Item 8 of this report for additional information.

Capital Expenditures.

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Acquisitions 11,232 1,431

Current year total capital expenditures, including acquisitions 50,639 14,495

Change in capital accruals (5,123) 633

Total cash paid for capital expenditures $ 45,516 $ 15,128

Capital expenditures, excluding acquisitions, for development activities increased for the year ended December 31, 2022 compared to 2021, which is in line with the planned drilling, completion, capital workover and well reactivation program.

Capital expenditures, including acquisitions 33,664 50,639

Changes in accounts payable and accrued expenses 5,232 (5,123)

Inventory material transfers to oil and natural gas properties $ (1,289) $ —

Total cash paid for capital expenditures, including acquisitions $ 37,607 $ 45,516

Capital expenditures, excluding acquisitions, for development activities decreased for the year ended December 31, 2023 compared to 2022, primarily due to the conclusion of our drilling program in the second quarter of 2023.

Cash Flows from Financing Activities

Our financing activities used $1.6 million of cash for the year ended December 31, 2022, consisted primarily of $1.2 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and finance lease payments of $0.5 million offset by $0.1 million of proceeds from the exercise of stock options.

Net exercises of stock awards allows the holder of a stock award to tender back to us a number of shares at fair value upon the vesting of such stock award, that equals the employee payroll tax obligation due.

Our financing activities used $82.9 million of cash for the year ended December 31, 2023, consisting primarily of $81.5 million in cash dividends, $0.9 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and finance lease payments of $0.6 million offset by $0.1 million of proceeds from the exercise of stock options.

Net exercises of stock awards allows the holder of a stock award to tender back to us a number of shares at fair value upon the vesting of such stock award, t

hat equals the employee payroll tax obligation due.

We then remit a cash payment to the relevant taxing authority on behalf of the employee for their payroll tax obligations resulting from the vesting of their stock award.

Our financing activities used $22.0 million in of cash for the year ended December 31, 2021, consisting primarily of repayments of borrowings under the 2020 Credit Facility of $20.0 million, finance lease payments of $1.0 million and cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise of $0.9 million.

Our financing activities used $1.6 million of cash for the year ended December 31, 2022, consisting primarily of $1.2 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and finance lease payments of $0.5 million offset by $0.1 million of proceeds from the exercise of stock options.

See discussion in above paragraph for additional information on net exercises of stock awards.

Share Repurchase Program

On August 16, 2021, our Board approved the initiation of a share repurchase program authorizing us to purchase up to an aggregate of $25.0 million of our common stock beginning as early as August 16, 2021.

We did not repurchase any common stock under the Program during the year ended 2022.

In May 2023, the Board approved a share repurchase program (the “Program”) authorizing the Company to repurchase up to an aggregate of $75.0 million of the Company’s outstanding common stock with the Company’s cash on hand.

The Program replaced the prior share repurchase program previously approved by the Board in August 2021.

Purchases under the Program are intended to meet the requirements of Rule 10b5-1 of the Exchange Act.

The Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board at any time.

The Company did not repurchase any common stock under the existing or prior Program during the years ended December 31, 2023 and 2022.

Contractual Obligations and Off-Balance Sheet Arrangements

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Therefore, no additional liability is reflected for the surety bonds or other instruments.

As of December 31, 2022, we had future contractual payment commitments under various agreements, which are summarized below.

As of December 31, 2023, we had future contractual commitments under various agreements, which are summarized below.

The short-term leases and operating lease are not recorded in the accompanying consolidated balance sheets.

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During the year ended December 31, 2023, plugging and abandonment costs incurred were $0.9 million.

Valuation Allowance

Upon emergence from bankruptcy and the application of fresh start accounting in 2016, our tax basis in property, plant, and equipment exceeded the book carrying value of our assets.

Additionally, we had significant U.S.

federal net operating losses remaining after the attribute reduction caused by the restructuring transactions.

As such, the successor Company had significant deferred tax assets to consume upon emergence.

In assessing the realizability of the deferred tax assets, we consider whether it is more likely than not that some or all of the deferred tax assets will not be realized.

The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized.

In prior years, we determined that the deferred tax assets did not meet the more likely than not threshold of being utilized and thus recorded a valuation allowance.

As of December 31, 2022, we have partially released our valuation allowance on our deferred tax assets by $64.5 million.

We anticipate being able to utilize these deferred tax assets based on the generation of future income.

A change in the estimate of future income could cause the valuation allowance to be adjusted in subsequent periods.

See “Note 13 — Income Taxes” to the accompanying consolidated financial statements for additional discussion of income tax related matters.

Critical Accounting Estimates

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In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change.

For the years ended December 31, 2022 and 2021, the Company revised its proved reserves from prior years’ reports by approximately 8.1 MMBoe and 43.3 MMBoe, respectively, due to increases in SEC prices used to value reserves at the end of the applicable period, production performance indicating more (or less) reserves in place, larger (or smaller) reservoir size than initially estimated or additional proved reserve bookings within the original field boundaries among other factors.

When excluding the effects of pricing, the Company revised its proved reserves an average of approximately 5% over the past five years and the revisions for the year ended December 31, 2023 were less than 3%.

In the future, estimates of proved reserves could also be influenced by production performance indicating more (or less) reserves in place, larger (or smaller) reservoir size than initially estimated or additional proved reserve bookings within the original field boundaries among other factors.

Estimates of proved reserves are key components of the Company’s financial estimates used to determine depreciation and depletion on oil and natural gas properties and its full cost ceiling limitation.

Future revisions to estimates of proved reserves may be material and could materially affect the Company’s future depreciation, depletion and impairment expenses.

See Proved Reserves discussion in Part I, Item 1 of this Form 10-K for additional detail.

Depreciation and Depletion of Oil and Natural Gas Properties.

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The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.

See above discussion on the uncertainty of proved reserves estimates.

If we maintain the same level of production year over year, the depreciation and depletion of oil and natural gas properties may be significantly different if our estimate of remaining reserves or future development costs changes significantly.

The average rates used for depreciation and depletion of oil and natural gas properties were $1.82 per Boe in 2023 and $1.18 per Boe in 2022.

Impairment of Oil and Natural Gas Properties.

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The Company calculates its full cost ceiling limitation using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves.

See above discussion on the uncertainty of proved reserves estimates.

If capitalized costs exceed the ceiling limitation, the excess must be charged to expense.

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The Company did not record any impairment for the years ended December 31, 2023 or 2022.

See “Consolidated Results of Operations” and “Note 9—Impairment” to the Company’s accompanying consolidated financial statements in Item 8 of this report for a discussion of the Company’s impairments.

Asset Retirement Obligations.

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Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration.

The Company employs a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions and requires significant judgment, including an inflation rate, its credit-adjusted, risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability based on third-party quotes and current actual costs.

The Company employs a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions and requires significant judgment, including an inflation rate, its credit-adjusted risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability based on current actual costs.

Inherent in the present value calculation are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change.

Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.

For the years ended December 31, 2023 and 2022, the Company revised its asset retirement obligations by approximately $0.9 million downwards and $2.7 million upwards, respectively, due primarily to changes in working interest and estimated well lives.

Income Taxes.

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The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized.

Upon emergence from bankruptcy and the application of fresh start accounting in 2016, our tax basis in oil and gas properties and property, plant, and equipment exceeded the book carrying value of our assets.

Additionally, we had significant U.S.

federal net operating losses remaining after the attribute reduction caused by the restructuring transactions.

As such, the successor Company had significant deferred tax assets to consume upon emergence.

In prior years, we determined that the deferred tax assets did not meet the more likely than not threshold of being utilized and thus recorded a valuation allowance.

As of December 31, 2022, we have partially released our valuation allowance on our deferred tax assets by $64.5 million.

Our partial valuation release of $64.5 million as of December 31, 2022 was partially offset by $14.0 million due to changes in expected future income, resulting in net deferred tax assets of $50.6 million as of December 31, 2023.

We anticipate being able to utilize these deferred tax assets based on the generation of future income.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis