What changed in this filing

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Item 7. Management’s Discussion and Analysis

2023-03-15 compared with 2022-03-10 · 101 added, 147 removed, 205 unchanged (55% of the section changed)

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We have applied the Securities and Exchange Commission’s adopted FAST Act Modernization and Simplification of Regulation S-K, which limits the discussion to the two most recent calendar years.

This discussion and analysis deals with comparisons of material changes in the consolidated financial statements for years ended 2021 and 2020.

For the comparison of years ended 2020 and 2019, see “Management's Discussion and Analysis of Consolidated Results of Operations” in Part II, Item 7 of our 2020 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 4, 2021.

This discussion and analysis deals with comparisons of material changes in the consolidated financial statements for years ended December 31, 2022 and 2021.

For the comparison of the years ended December 31, 2021 and 2020, see “Management's Discussion and Analysis of Consolidated Results of Operations” in Part II, Item 7 of our 2021 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 10, 2022.

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

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Operational Activities

There was no drilling activity on our operated acreage during the years ended December 31, 2021 and 2020.

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.

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

(2) For the year ended December 31, 2020, North Park Basin had 940 MBoe in oil production.

Total production for 2021 was comprised of approximately 14.1% oil, 52.5% natural gas and 33.4% NGLs compared to 23.9% oil, 45.1% natural gas and 31.0% NGLs in 2020.

Mid-Continent total production for the year ended December 31, 2021 and 2020 was comprised of the following:

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:

Year Ended December 31,

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Highlighted Events

• 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 date adjustments and a $0.8 million post-close adjustment made during the second half of the year.

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

• On March 3, 2021, we named Mr.

Salah Gamoudi, our Chief Financial Officer and Chief Accounting Officer, as a Senior Vice President.

We also named Mr.

Dean Parrish, formerly our Director of Operations, as our Vice President of Operations.

• 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 is $4.9 million (net $3.6 million, given our 26.9% ownership of the Trust).

• On July 9, 2021, Carl F.

submitted his resignation from his positions as CEO, President and as a member of the Board of the Company, effective July 16, 2021 in order to pursue another career opportunity.

Giesler did not resign as a result of any disagreement with the Company on any matter relating to the Company’s operations, policies or practices.

• The Board appointed Grayson Pranin as President and CEO effective July 16, 2021 and in addition will maintain his role as Chief Operating Officer.

Pranin, age 41, held the role of Senior Vice President and Chief Operating Officer since March 3, 2021.

• In August 2021, our Board of Directors approved the initiation of a share repurchase program (the "Program") authorizing us to purchase up to an aggregate of $25.0 million of our common stock beginning as early as August 16, 2021.

The Program is in accordance with Rule 10b-18 of the Exchange Act.

Subject to applicable rules and regulations, repurchases under the Program can be made from time to time in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions.

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.

We did not repurchase any common stock under the Program during the year ended December 31, 2021.

• On September 2, 2021, we repaid our $20.0 million term loan in full and terminated all commitments and obligations under the 2020 Credit Facility.

Our repayment of the term loan satisfied all of our remaining term debt and revolving debt obligations.

• On December 28, 2021, Patricia Agnello submitted her resignation from her positions as a member of the Board of Directors (the “Board”) our Company.

Agnello did not resign as a result of any disagreement with the Company on any matter relating to the Company’s operations, policies or practices.

As discussed in “Business— Our Business Strategy” in Item 1 of this report, we will 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 a continuation of our well reactivation program, artificial lift conversions to more efficient and cost effective systems, as well as focused drilling in high-graded areas, which will aide in partially offsetting the natural decline of our producing asset's.

Forward looking commodity prices, results, costs and other factors will shape our development decisions in 2022 and beyond.

We will also remain vigilant and maintain optionality for opportunistic, value-accretive acquisitions and business combinations.

As the impact of COVID-19 lessens, demand for commodities is continuing to rise to pre-pandemic levels within the United States.

The resurging demand led to favorable commodity prices during the year ended December 31, 2021.

However, the spread of COVID-19 variants and the effectiveness of the vaccines against these variants are significant risk factors to a full and sustained recovery.

If the vaccines currently available are not effective against COVID-19 or its other variants, Governments and other regulatory bodies may have to rely on mobility and activity restrictions to mitigate the spread, which could lead to reduced demand for certain commodities.

See “Item 1A.

Risk Factors” included in Part I of this Annual Report for additional discussion of the potential impact these events may have on our future revenues.

• 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.

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 2023 and beyond.

We will also continue to maintain optionality to execute on value accretive merger and acquisition opportunities that could bring synergies, leverage our core competencies, compliment our portfolio of assets, further utilize our NOLs or otherwise yield attractive returns for our shareholders.

Consolidated Results of Operations

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Year Ended December 31,

NYMEX Oil (per Bbl) $ 68.18 $ 39.19

NYMEX Natural gas (per MMBtu) $ 3.90 $ 2.13

NYMEX WTI Oil (per Bbl) $ 94.90 $ 68.18

NYMEX Henry Hub Natural gas (per Mcf) $ 6.68 $ 4.04

In order to reduce our exposure to price fluctuations, from time to time we enter into commodity derivative contracts for a portion of our anticipated future oil, natural gas, and NGL production as discussed in Item 7A.

“Quantitative and Qualitative Disclosures About Market Risk.” During periods where the strike prices for our commodity derivative contracts are below market prices at the time of settlement, we may not fully benefit from increases in the market price of oil, natural gas and NGL.

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.

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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 is $4.9 million (net $3.6 million, given our 26.9% ownership of 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 date adjustments and a $0.8 million post-close adjustment made during the second half of the year.

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

2020 Acquisitions and Divestitures

On September 10, 2020, the Company acquired all of the overriding royalty interests held by SandRidge Mississippian Royalty Trust II ("the Trust") for a net purchase price of $3.28 million, given our 37.6% ownership of the Trust.

accounted for this transaction as an asset acquisition and allocated the purchase price of the acquisition plus the transactions costs to oil and gas properties.

On August 31, 2020, the Company closed on the previously announced sale of its corporate headquarters building located in Oklahoma City, OK, for net proceeds of approximately $35.4 million.

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

Production data (in thousands)

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Total 6,463 100.0 % 6,793 100.0 %

Consolidated revenues for the years ended December 31, 2021 and 2020 are presented in the table below (in thousands).

Consolidated revenues for the years ended December 31, 2022 and 2021 are presented in the table below (in

Year Ended December 31,

2022 2021 Change % Change

Oil $ 87,528 $ 62,297 $ 25,231 41 %

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2022 oil, natural gas and NGL revenues

Oil, natural gas and NGL revenues increased by a combined $54.4 million, or 47.6% for the year ended December 31, 2021, compared to 2020.

The average prices for oil, natural gas and NGL's increased primarily due to increased oil, natural gas and NGL realized prices primarily as a result of increased economic activity and recovery from the COVID-19 pandemic and the related increase in energy demand, in addition to a contraction of differentials on realized commodity prices.

These increases were partially offset by an overall decline in production due to the natural declines in our existing producing wells and a decrease in oil production as a result of the sale of NPB.

Midcon production declines were reduced as a result of our well reactivation program that employs low cost capital workovers to return wells to production.

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.

Operating Expenses

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Year Ended December 31,

2022 2021 Change % Change

Lease operating expenses $ 41,286 $ 35,999 $ 5,287 14.7 %

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Production, ad valorem, and other taxes (% of oil, natural gas, and NGL revenue) 6.2 % 5.9 % 0.4 % 5.5 %

Lease operating expenses for 2021 decreased $7.4 million from 2020.

This decrease primarily resulted from field personnel reductions in force, the sale of NPB and other cost reduction efforts during the year ended December 31, 2021.

Production, ad valorem, and other taxes has increased primarily due to higher commodity prices in 2021 partially offset by a decline in ad valorem taxes due to the sale of NPB in Colorado and a difference in our accrued estimate and the actual last ad valorem tax payment made for NPB.

Production, ad valorem, and other taxes decreased as a percentage of oil, natural gas and NGL revenue for the year 2021 compared to 2020, primarily due to the difference between the estimate and actual payment for ad valorem taxes of NPB.

Depreciation and depletion for oil and natural gas properties decreased by $41.0 million for the year ended December 31, 2021 compared to 2020 due to a decrease in the average depreciation and depletion rate to $1.38 per Boe in 2021 compared to an average rate of $5.79 in 2020.

These decreases are primarily due to the sale of the North Park Basin properties and full cost ceiling test impairments recorded during 2020, which lowered the net cost basis of our oil and gas properties significantly.

Impairment expense for the years ended December 31, 2021 and 2020 consisted of the following (in thousands):

Year Ended December 31,

Full cost pool ceiling limitation $ — $ 218,399

Other — 38,000

Total impairment $ — $ 256,399

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.

Full cost pool impairment.

We did not record a full cost ceiling limitation impairment for the year ended December 31, 2021.

Impairment for the year ended December 31, 2020 largely resulted from an impairment charge of $256.4 million, which included a full cost ceiling limitation impairment charge of $218.4 million, and an impairment charge of $38 million to write down the value of the Company's building headquarters to its estimated fair value less estimated costs to sell the building headquarters.

We did not record a full cost ceiling limitation impairment for the years ended December 31, 2022 or 2021.

Calculation of the full cost ceiling test is based on, among other factors, trailing twelve-month SEC prices as adjusted for price differentials and other contractual arrangements.

The SEC prices utilized in the calculation of proved reserves included in the full cost ceiling test at December 31, 2021 were $66.56 per barrel of oil and $3.60 per Mcf of natural gas, before price differential adjustments.

Based on the SEC prices over the twelve months ended March 1, 2022, we anticipate the SEC prices utilized in the March 31, 2022 full cost ceiling test may be $75.24 per barrel of oil and $4.09 per Mcf 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, 2021 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2022.

The SEC prices utilized in the calculation of proved reserves included in the full cost ceiling test at December 31, 2022 were $93.67 per barrel of oil and $6.36 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.

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Year Ended December 31,

2022 2021 Change % Change

General and administrative $ 9,449 $ 9,675 (226) (2.3) %

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Other operating expense (income) (99) (382) 283 (74.1) %

Total non-operating expenses $ (6,567) $ 20,934

General and administrative expenses decreased $5.7 million, or 36.9%, for the year ended December 31, 2021 compared to 2020.

These decreases resulted primarily from a reduction in compensation related costs after completing reductions in force during 2020, significant reductions in information technology and software costs and overhead expenses related to the Company's previously held corporate headquarters building.

Part of the decrease is also due to reductions in professional costs such as legal expenses, audit fees and consulting services.

Restructuring expenses represent fees and costs associated with the 2016 bankruptcy and exit from NPB in Colorado.

Restructuring expenses decreased by $1.9 million, or 71.0% for the year ended December 31, 2021, compared to 2020.

These decreases are primarily related to previously accrued expenses for the 2016 Bankruptcy that were removed as a result of the notice of completion of final distribution being filed in the United States Bankruptcy Court for the Southern District of Texas on July 26, 2021.

Further, 2020 expenses included the relocation of company headquarters and outsourcing of corporate functions.

See "Note 13 - Commitments and Contingencies" in the accompanying consolidated financial statements in Item 8 of this report for additional discussion of these expenses.

Employee termination benefits for the years ended December 31, 2021 and 2020, includes cash and share-based severance costs incurred for reductions in force.

The decrease from 2020 to 2021 is primarily the result of separations of employment for Company employees during 2020, that did not occur in 2021.

As a result, the Company paid cash severance costs and incurred share-based compensation costs associated with the separations in 2020, with no recurrence of such costs in 2021.

See "Note 13 - Employee Termination Benefits" in the accompanying consolidated financial statements in Item 8 of this report for additional discussion of these expenses.

Loss on derivative contracts of $2.3 million and a gain of $5.8 million for the years ended December 31, 2021 and 2020, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash payments upon settlement of $2.2 million, and net cash received upon settlement of $5.9 million, respectively.

Total other operating expenses $ 3,757 $ (6,567) $ 10,324 (157.2) %

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.

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

The following table summarizes derivative activity for the years ended December 31, 2022 and 2021 (in thousands):

Year Ended December 31,

(Gain) loss on derivative contracts $ (5,975) $ 2,251

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

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) loss on sale of assets increased by $18.9 million for the year ended December 31, 2021 compared to 2020.

The increase is due to the gain on sale for the sale of NPB assets in Colorado in February 2021.

Other Income (Expense)

Other income (expense) for the years ended December 31, 2021 and 2020 is reflected in the table below (in thousands):

Year Ended December 31,

Other (expense) income

Interest expense, net $ (404) $ (1,998)

Other (expense) income , net 3,055 (2,494)

Total other (expense) income $ 2,651 $ (4,492)

Interest expense for the years ended December 31, 2021 and 2020 consisted of the following (in thousands):

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, 2022 and 2021 consisted of the following (in thousands):

Year Ended December 31,

Interest expense

Interest expense on debt $ 377 $ 2,386

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

Interest expense on right of use assets 36 26

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interest income (2,026) (3)

Total interest expense, net $ 404 $ 1,998

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

Total interest (income) expense, net $ (1,810) $ 404

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.

Interest expense incurred during the year ended December 31, 2020 is primarily comprised of interest and fees paid on the 2017 Credit Facility that was terminated on November 30, 2020.

See “Note 11—Long-Term Debt” to the accompanying consolidated financial statements in Item 8 of this report for additional discussion of our long-term debt transactions.

The Other (expense) income, net line item for the year ended December 31, 2021 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 October 2021.

For the year ended December 31, 2020, this line item includes an allowance for doubtful accounts of $2.5 million that was recorded as a result of conducting an assessment of governmental and other regulatory receivable balances, which we had previously deemed as potentially uncollectible.

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.

Liquidity and Capital Resources

At December 31, 2022, our cash and cash equivalents, including restricted cash, was $257.5 million.

The 2020 Credit Facility was terminated, as discussed below.

See "Note — 11 Long-Term Debt" to the accompanying consolidated financial statements in Item 8 of this report for further discussion.

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

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

Our working capital increased to $97.7 million at December 31, 2021, compared to $18.1 million at December 31, 2020, the positive impact on working capital resulted primarily from an increase in cash and cash equivalents at December 31, 2021 as a result of proceeds from the sale of NPB and cash flows from operations.

In addition, accounts payable and accrued liabilities decreased due to our continuous cost reduction efforts, the sale of NPB and the timing of payments.

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.

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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 2017 through December 2021, the NYMEX settled price for oil fluctuated between a high of $85.64 per Bbl and a low of $(36.98) per Bbl, and the month-end NYMEX settled price for gas fluctuated between a high of $23.86 per MMBtu and a low of $1.33 per MMBtu.

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.

This could result in full cost pool ceiling impairments.

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.

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Year Ended December 31,

Cash flows provided by (used in) operating activities $ 110,260 $ 36,162

Cash flows provided by operating activities $ 164,696 $ 110,260

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

Cash flows provided by (used in) financing activities (21,975) (38,957)

Net increase (decrease) in cash and cash equivalents $ 111,258 $ 22,298

Cash flows (used in) financing activities (1,635) (21,975)

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

Cash Flows from Operating Activities

The $74.1 million increase in operating cash flows for the year ended December 31, 2021 compared to 2020, is primarily due to net income of $116.7 million which is the result of improved revenue due to increased commodity prices and improved differentials as well as the well reactivation program which reduced production declines.

In addition, our cost reduction efforts resulted in decreases in lease operating expenses and general and administrative expenses.

The increase in net income was partially offset by the addback of the gain on sale of assets primarily related to NPB and a reduction of accrued liabilities over and above an increase in our receivable and other working capital balances.

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 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.

See “Consolidated Results of Operations” for further analysis of the changes in revenues and operating expenses.

Cash Flows from Investing Activities

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 NPB assets partially offset by capital expenditures of $11.6 million and the acquisition of overriding royalty interests for $3.6 million.

During the year ended December 31, 2020, cash flows provided by investing activities primarily reflects $35.4 million of net cash proceeds from the sale of the corporate office building, offset by cash payments made for capital expenditures coupled with the acquisition of $3.3 million primarily related to the purchase of overriding royalty interests.

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.

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.

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Capital Expenditures

Drilling, completion, and capital workovers $ 10,045 $ 3,563

Drilling and completions $ 38,077 $ 1,087

Capital workovers 10,322 8,958

Leasehold and geophysical 809 905

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

____________________

(1) Excludes $3.9 million for the year ended December 31, 2020, related to non-monetary transactions.

Capital expenditures, excluding acquisitions, for development and production activities increased for the year ended December 31, 2021 compared to 2020, which is in line with the planned increase in costs as result of our well reactivation program.

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.

Cash Flows from Financing Activities

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 paid for tax obligations on vested stock awards of $0.9 million.

Our financing activities used $39.0 million in cash for the year ended December 31, 2020, consisting primarily of repayments of borrowings under the 2017 Credit Facility of $96.5 million, finance lease payments of $1.2 million and cash paid for tax obligations on vested stock awards of $0.1 million partially offset by proceeds from borrowings of $59.0 million.

Credit Facility

On November 30, 2020, the Company entered into the $30 million 2020 Credit Facility with the lenders party thereto and Icahn Agency Services LLC, as administrative agent (the “New Administrative Agent”).

The 2020 Credit Facility consisted of a $10 million revolving loan facility and a $20 million term loan facility.

During the third quarter of 2021, the 2020 Credit Facility was terminated, as discussed below.

On September 2, 2021, we repaid our $20.0 million term loan in full and terminated all commitments and obligations under the 2020 Credit Facility, between us, as Borrower, IEP Energy Holding LLC, as Lender, and Icahn Agency Services LLC, as Administrative Agent.

Our payment to the Lender under the Credit Agreement satisfied all of our term debt and revolving debt obligations.

We did not incur any early termination penalties as a result of the repayment of indebtedness or termination of the Credit Agreement.

See “Note 11 — Long-Term Debt” to the accompanying consolidated financial statements included in Item 8 of this report for additional discussion of the Company’s debt during 2021 and 2020.

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.

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.

Share Repurchase Program

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Contractual Obligations and Off-Balance Sheet Arrangements

At December 31, 2021, our contractual obligations included asset retirement obligations, short and long-term leases and other individually insignificant obligations.

At December 31, 2022, our contractual obligations included asset retirement obligations and short and long-term leases.

Additionally, we have certain financial instruments representing potential commitments that were incurred in the normal course of business to support our operations, including surety bonds.

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

The operating leases are not recorded in the accompanying consolidated balance sheets.

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

Payments Due by Period

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Operating lease 167 167 — — —

Short-term leases 2,076 2,076 — — —

Finance lease 1,059 459 600 — —

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

We considered all available evidence and concluded that it was more likely than not that some or all of the deferred tax assets would not be fully realized and established a valuation allowance against our net deferred tax asset upon emergence and maintained the valuation allowance for the subsequent periods through December 31, 2021.

We continue to closely monitor all available evidence in considering whether to maintain a valuation allowance on our net deferred tax asset.

Factors considered include, but are not limited to, the reversal periods of existing deferred tax liabilities and deferred tax assets, our historical earnings and the prospects of future earnings.

For purposes of the valuation allowance analysis, “earnings” is defined as pre-tax earnings as adjusted for permanent tax adjustments.

In determining whether to maintain the valuation allowance at December 31, 2021, we concluded that the objectively verifiable negative evidence of the presumption of cumulative negative earnings upon emergence and actual cumulative negative earnings for the Successor Company period ending December 31, 2021, is difficult to overcome with any forms of positive evidence that may exist.

Accordingly, we have not changed our judgment regarding the need for a full valuation allowance against our net deferred tax asset for the period ending December 31, 2021.

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 Policies and Estimates

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, which have been prepared in accordance with accounting principles generally accepted in the United States of America.

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Proved Reserves.

Over 96.0% of the Company’s reserves were estimated by independent petroleum engineers for the year ended December 31, 2021.

Approximately 95.0% of the Company’s reserves were estimated by independent petroleum engineers as of December 31, 2022.

Estimates of proved reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions.

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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, 2021 and 2020, the Company revised its proved reserves from prior years’ reports by approximately 43.3 MMBoe and (44.8) MMBoe, respectively, due to increases (or decreases) 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.

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.

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.

Depreciation and depletion of Oil and Natural Gas Properties.

In accordance with full cost accounting rules, capitalized costs are amortized using the unit-of-production method.

Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate.

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.

Impairment of Oil and Natural Gas Properties.

In accordance with full cost accounting rules, capitalized costs are subject to a limitation.

The capitalized cost of oil and natural gas properties and electrical infrastructure costs, net of accumulated depreciation, depletion and impairment, less related deferred income taxes, may not exceed an amount equal to the ceiling limitation.

The capitalized cost of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes and electrical infrastructure costs, may not exceed an amount equal to the ceiling limitation.

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.

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Once incurred, a write-down cannot be reversed at a later date.

The Company recorded full cost ceiling did not record any impairment for the year ended December 31, 2021 and $218.4 million for the year ended December 31, 2020.

See “—Consolidated Results of Operations” for additional discussion of full cost ceiling impairments.

The Company did not record any impairment for the years ended December 31, 2022 or 2021.

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.

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Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards.

Deferred tax assets are reduced by a valuation

allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.

Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.

Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns.

As of December 31, 2021, the Company had a full valuation allowance against its net deferred tax asset.

The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence.

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.

New Accounting Pronouncements.

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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