What changed in this filing

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Item 7. Management’s Discussion and Analysis

2022-03-10 compared with 2021-03-04 · 160 added, 196 removed, 192 unchanged (65% of the section changed)

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• Critical Accounting Policies and Estimates.

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.

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 and North Park Basin of Colorado.

Mid-Continent.

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

Operational Activities

There was no drilling activity during the year ended December 31, 2020.

Operational activities for the year ended December 31, 2019 included the following:

Year Ended December 31,

Gross Wells Drilled Net Wells Drilled Average Rigs Drilling

Mid-Continent (1)

North Park Basin

____________________

(1) Eight wells were drilled under our previous drilling participation agreement during the year ended December 31, 2019.

Under this agreement, we receive a 20% net working interest after funding 10% of the drilling and completion costs related to the subject wells.

The last well under this agreement was completed in the second quarter of 2019.

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

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, 2021 and 2020:

(1) For the year ended December 31, 2020, Mid-Continent production was 3,925 MBoe in natural gas, 2,694 MBoe in NGLs and 1,144 MBoe in oil totaling 7,763 MBoe.

North Park Basin had 940 MBoe in oil.

(2) For the year ended December 31, 2019, Mid-Continent production was 5,527 MBoe in natural gas, 2,908 MBoe in NGLs and 1,988 MBoe in oil totaling 10,423 MBoe.

North Park Basin had 1,531 MBoe in oil and 2 MBoe in NGLs totaling 1,533 MBoe.

(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.

Recent Events

• On March 3, 2021, the Company named Mr.

Grayson Pranin, formerly its Vice President for Reserves and Engineering, as Senior Vice President and Chief Operating Officer.

The Company also named Mr.

Salah Gamoudi, the Company’s Chief Financial Officer and Chief Accounting Officer, as a Senior Vice President.

It also named Mr.

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

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

The sale closed for net proceeds of $39.7 million in cash, which is net of effective to closing date adjustments.

• SandRidge Mississippian Trust I:

We are party to the Amended and Restated Trust Agreement of SandRidge Mississippian Trust I (the “SDT Trust”), dated April 12, 2011, by and among the Company, the Bank of New York Mellon Trust Company, N.A., and the Corporation Trust Company (the “Trust Agreement”).

Pursuant to the Trust Agreement, we have a right of first refusal with respect to any sale of assets of the SDT Trust to a third party following the occurrence of certain events (a “Triggering Event”).

On October 23, 2020, the SDT Trust announced the Trust will be required to dissolve and commence winding up beginning as of the close of business on November 13, 2020.

At December 31, 2020, the market capitalization of the SDT Trust was $5.1 million of which we own approximately 26.9%.

• On September 10, 2020, the Company closed on the acquisition of the overriding royalty interests of SandRidge Mississippian Trust II for a gross purchase price of $5.25 million (net purchase price of $3.28 million, given the Company's 37.6% ownership of the Trust).

• On August 31, 2020, SandRidge Realty, LLC, a wholly owned subsidiary of the Company, closed on the sale of the Company's 30-story office tower and annex with parking and ancillary uses located at 123 Robert S.

Kerr, Oklahoma City, Oklahoma 73102, for net proceeds of approximately $35.4 million.

• On July 1, 2020, the Board declared a dividend distribution of one right (a “Right”) for each outstanding share of Company common stock, par value $0.001 per share to stockholders of record at the close of business on July 13, 2020.

Each Right entitles its holder, under certain circumstances, to purchase from the Company one one-thousandth of a share of Series A Junior Participating Preferred Stock of the Company, par value $0.001 per share, at an exercise price of $5.00 per Right, subject to adjustment.

The description and terms of the Rights are set forth in the tax benefits preservation plan, dated as of July 1, 2020, between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (and any successor rights agent, the “Rights Agent”).

As discussed in “Business— Our Business Strategy” in Item 1 of this report, we will focus on maximizing free cash flow in 2021 through a combination of cost control measures and the continued exercise of financial discipline and prudent capital allocation, which includes limiting our drilling capital to locations we believe will provide high rates of return in the current commodity price environment.

As a result, our planned capital expenditures for 2021 will be similar to our 2020 levels.

Given this expected level of capital expenditures, our oil, natural gas and NGL production will likely decline in 2021.

We will be prepared to expand our capital program after considering all factors including commodity prices.

We will also continue our pursuit of acquisitions and business combinations which provide high margin properties with attractive returns at current commodity prices.

The COVID-19 pandemic and other pricing volatility caused by the announcement of production increases by Saudi Arabia-led OPEC and Russia caused a steep decline in oil prices in March 2020, which further decreased to historic lows in April 2020.

Although we cannot reasonably estimate what the full impact of the COVID-19 pandemic and other market volatility will have on our business, it could have a material, adverse impact on near-term future revenues and overall profitability.

Additionally, we have implemented several additional initiatives to maximize free cash flow, reduce our debt level, maximize our liquidity position and, ultimately realize greater shareholder value.

These initiatives included personnel and non-personnel cost reductions, the sale of the company headquarters during 2020.

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

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

Year Ended December 31,

Oil 13.2 % 14.7 %

NGL 33.7 % 34.7 %

Natural gas 53.1 % 50.6 %

Total 100.0 % 100.0 %

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.

Consolidated Results of Operations

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Year Ended December 31,

Oil (per Bbl) $ 39.19 $ 57.04

Natural gas (per Mcf) $ 2.13 $ 2.53

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

“Quantitative and Qualitative Disclosures About Market Risk.” Reducing the Company’s exposure to price volatility helps mitigate the risk that we will not have adequate funds available to support our operations.

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 and natural gas.

Conversely, during periods of declining market prices of oil and natural gas, 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.

However, as of December 31, 2020, the Company had no remaining open commodity derivative contracts.

NYMEX Oil (per Bbl) $ 68.18 $ 39.19

NYMEX Natural gas (per MMBtu) $ 3.90 $ 2.13

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.

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 is $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.

1 unchanged sentence

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.

See "Note 22 — Subsequent Event” to the accompanying consolidated financial statements in Item 8 of this report.

for information related to the February 5, 2021 sale of our North Park Basin assets.

2019 Acquisitions and Divestitures

Nonmonetary transaction.

During the three-month period ended September 30, 2019, the Company transferred its interest in certain proved oil and natural gas properties located in Comanche, Harper and Sumner counties in Kansas along with associated electrical infrastructure and an insignificant amount of accounts receivable with an aggregate estimated fair value of $5.4 million, for an interest in certain other proved oil and natural gas properties located in Comanche, Harper and Barber counties in Kansas.

The fair value of the non-oil and gas assets given in the transaction approximated their carrying value, therefore no gain or loss was recognized on the transfer.

Oil, Natural Gas and NGL Production and Pricing

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

(2) Excludes early settlements of commodity derivative contracts prior to their contractual maturity.

The table below presents production by area of operation for the years ended December 31, 2020 and 2019, and illustrates the impact of (i) natural declines in existing producing wells in the Mid-Continent, (ii) No new wells in 2020.

The table below presents production by area of operation for the years ended December 31, 2021 and 2020.

Year Ended December 31,

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Natural gas 55,749 22,867

Other 526 741

Total revenues $ 168,882 $ 114,976

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2021 oil, natural gas and NGL revenues $ 168,882

Oil, natural gas and NGL revenues decreased by a combined $151.7 million, or 57.0% for the year ended December 31, 2020, compared to 2019.

The average prices for oil, natural gas and NGL's declined significantly during 2020, due largely to an increase in anticipated global supplies of these commodities after a pledged increase in oil production from Saudi Arabia-led OPEC, and the reduction in demand stemming from the COVID-19 pandemic.

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.

The decline in production for the year ended December 31, 2020 compared to 2019, largely resulting from the absence of newly drilled wells in 2020 and natural production declines in our existing producing wells in the Mid-Continent and North Park Basin.

North Park Basin ("NPB") represented $31.1 million, or 27.0% of the Company's $115.0 million total consolidated Revenues for the year ended December 31, 2020.

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.

Operating Expenses

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Production, ad valorem, and other taxes (% of oil, natural gas, and NGL revenue) 5.9 % 8.4 %

Lease operating expenses for 2020 decreased $47.5 million, or $2.62/Boe from 2019.

This decrease primarily resulted from field personnel reductions in force, in addition to the shut-in of wells that had become uneconomic due to natural production declines and deteriorating pricing during the year ended December 31, 2020.

NPB represented $9.1 million, or 20.9% of the Company's $43.4 million consolidated Lease operating expense for the year ended December 31, 2020.

Production, ad valorem, and other taxes has decreased primarily due to declining production and revenues.

Further, they have increased as a percentage of oil, natural gas, and NGL revenue for the year 2020 compared to 2019, primarily due to ad valorem taxes remaining consistent throughout 2020 while revenues have declined during 2020.

NPB represented $1.8 million, or 18.7% of the Company's $9.6 million consolidated Production, ad valorem and other taxes for the year ended December 31, 2020.

Depreciation and depletion for oil and natural gas properties decreased by $96.5 million for the year ended December 31, 2020 compared to 2019 due to an decrease in the average depreciation and depletion rate to $5.11 per Boe in 2020 compared to an average rate of $12.28 in 2019.

This rate decrease is primarily due to the full cost ceiling test impairments recorded in the third and fourth quarters of 2019, as well as the ceiling test impairments recorded in 2020.

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):

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Full cost pool impairment.

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 office headquarters to its estimated fair value less estimated costs to sell the building.

For the quarter ended December 31, 2020, we recorded a full cost ceiling limitation impairment charge of $2.6 million.

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.

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 eleven months ended February 1, 2021, as well as the short-term pricing outlook for the remainder of the first quarter 2021, we anticipate the SEC prices utilized in the March 31, 2021 full cost ceiling test may be $39.42 per barrel of oil and $2.16 per Mcf of natural gas, (the "estimated first quarter prices").

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.

However, a full cost ceiling limitation impairment may still be realized in the first quarter of 2021 and in subsequent quarters based on the outcome of numerous other factors such as additional declines in the actual trailing twelve-month SEC prices, lower NGL pricing, changes in estimated future development costs and operating expenses, and other adjustments to our levels of proved reserves.

However, a full cost ceiling limitation impairment may still be realized in the first quarter of 2022 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.

Any such ceiling test impairments in 2022 could be material to our net earnings.

Non-Operating Expenses

Non-operating expenses for the years ended December 31, 2020, and 2019 consisted of the following (in thousands):

Full cost pool impairments have no impact to our cash flow or liquidity.

Other Operating Expenses

Other operating expenses for the years ended December 31, 2021 and 2020 consisted of the following (in thousands):

Year Ended December 31,

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Employee termination benefits 49 8,433

Gain on derivative contracts (5,765) (1,094)

(Gain) loss on derivative contracts 2,251 (5,765)

(Gain) loss on sale of assets (18,952) (100)

Other operating expense (income) (382) 306

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

General and administrative expenses decreased $16.7 million, or 52.2%, for the year ended December 31, 2020 compared to 2019 primarily from a reduction in compensation related costs after completing reductions in force during the second quarter of 2019 and the first three quarters of 2020.

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

Restructuring expenses represent fees and costs associated with our outsourcing and relocation of certain corporate specific functions that are of a non-recurring nature and expenses related to the 2016 bankruptcy.

Employee termination benefits for the year ended December 31, 2020, include cash and share-based severance costs incurred primarily as a result of the reduction in force.

On July 1, 2020, the Company's then current Chief Financial Officer, Michael A.

Johnson and Chief Operating Officer, John Suter, separated employment from the Company.

As a result, the Company paid cash severance costs and incurred share-based compensation costs associated with these separations during 2020.

Employee termination benefits for the year ended December 31, 2019, include cash and share-based severance costs incurred related to (i) a reduction in force in the second quarter of 2019 and (ii) severance costs associated with the departure of our former Executive Vice President, General Counsel and Corporate Secretary, Phil Warman, and former CEO, Paul McKinney.

See "Note 19 — Employee Termination Benefits" to the accompanying consolidated financial statements in Item 8 of this report for additional information.

We recorded a net gain on commodity derivative contracts of $5.8 million and $1.1 million for the years ended December 31, 2020, and 2019, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash receipts upon settlement of $5.9 million and $6.3 million, respectively.

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 each quarter as a component of operating expenses.

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.

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.

Internally, management views the settlement of commodity derivative contracts at contractual maturity as adjustments to the price received for oil and natural gas production to determine “effective prices.” In general, cash is received on settlement of contracts due to lower oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts, and cash is paid on settlement of contracts due to higher oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts.

“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)

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Capitalized interest (252) (750)

Interest expense - other 25 1

Total 407 2,017

1 unchanged sentence

Total interest expense, net $ 404 $ 1,998

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

Interest expense incurred during the year ended December 31, 2019 is primarily comprised of interest and fees paid on the Prior Credit Facility.

Interest expense incurred during the year ended December 31, 2021 is primarily comprised of interest 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, 2020 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 have deemed as potentially uncollectible.

This allowance is non-recurring in nature, and does not represent allowances for doubtful accounts related to joint interest billing receivables or other recurring items.

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.

Liquidity and Capital Resources

At December 31, 2020, our cash and cash equivalents, excluding restricted cash, were $22.1 million.

Additionally, we had a $20.0 million term loan outstanding and $10.0 million available under our $30.0 million New Credit Facility, which matures on November 30, 2023.

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

for further discussion.

As of March 1, 2021, the Company had, no outstanding balance under the New Credit Facility revolving line of credit, and a $20.0 million outstanding term loan under the New Credit Facility.

As discussed in “— Recent Events” and “— Outlook” above, we have undertaken several initiatives in 2020, which we believe have the potential to positively impact our liquidity.

These initiatives are expected to maximize free cash flow and ultimately realize greater shareholder value to address the negative impact of the COVID-19 pandemic and commodity price volatility on our financial position and future liquidity.

These initiatives included personnel and non-personnel cost reductions the sale of our corporate headquarters, and the signing of a purchase and sale agreement to sell our North Park Basin assets.

We are unable to project the full impact the COVID-19 pandemic will have on our financial position and results of operations at this time, but these measures, along with amounts available to be drawn on our New Credit Facility, cash on hand, and other cash flows from operations are expected to provide ample liquidity for the next 12 months.

At December 31, 2021, our cash and cash equivalents, including restricted cash, was $139.5 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.

As of March 9, 2022, 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 2020 included cash flow from operations, cash on hand and amounts available under our New Credit Facility, as discussed in “—Credit Facility” below.

As discussed in “— Outlook” above to the accompanying audited consolidated financial statements and “Item 1A.

Risk Factors” included in Part I of this Annual Report, we expect the COVID-19 pandemic and other market volatility factors to have a material, adverse impact on future revenue growth and overall profitability for the foreseeable future.

Our working capital deficit decreased to $18.1 million at December 31, 2020, compared to $49.8 million at December 31, 2019, the positive impact on working capital resulted primarily from an increase in cash and cash equivalents at December 31, 2020 as a result of proceeds from asset sales, cash from operations and the new term loan.

In addition, accounts payable decreased due to a decline in drilling and completions activity in 2020, in addition to our cost reduction efforts..

Our principal sources of liquidity for 2021 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.

We intend to spend between $41 million and $50 million in our 2022 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, borrowings under our New Credit Facility and cash on hand.

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.

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Year Ended December 31,

Cash flows provided by operating activities $ 36,162 $ 121,324

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

Cash flows provided by (used in) investing activities 22,973 25,093

Cash flows (used in) provided by financing activities (38,957) 54,848

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 from Operating Activities

The $85.2 million decrease in operating cash flows for the year ended December 31, 2020 compared to 2019, is primarily due the significant decline in revenues, which was partially offset by reductions in general and administrative costs and lease operating expenses as well as the other changes in working capital discussed previously.

See “—Consolidated Results of Operations” for further analysis of the changes in revenues and operating expenses, and see “Note 19 — Employee Termination Benefits” to the accompanying consolidated financial statements included in Item 8 of this report for additional detail on cash paid for employee termination benefits.

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.

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, 2020, cash flows provided by investing activities primarily reflects $35.4 million of net cash proceeds primarily 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 overriding royalty interests.

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.

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.

During the year ended December 31, 2019, cash flows used in investing activities primarily consisted of capital expenditures for drilling and completion activities partially offset by proceeds from the sale of assets.

Capital Expenditures.

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Leasehold and geophysical 905 1,005

Other - corporate — 245

Capital expenditures, excluding acquisitions (on an accrual basis) 10,950 4,568

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____________________

(1) Excludes $3.9 million and $5.4 million for the years ended December 31, 2020 and December 31, 2019, respectively, related to nonmonetary transactions.

(2) Reflects cash paid during the period presented for expenditures related to the prior year's capital program.

Capital expenditures, excluding acquisitions, for development and production activities decreased for the year ended December 31, 2020 compared to 2019, which is in line with the planned decrease in drilling and completion activity and related costs as reflected in our lower capital expenditures budget in 2020 and 2019.

(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.

Cash Flows from Financing Activities

Our financing activities used $39.0 in of cash for the year ended December 31, 2020, which consisted primarily of $57.5 million of net repayments of borrowings under the Prior Credit Facility partially offset by $20.0 million in proceeds from the New Credit Facility.

Our financing activities provided $54.8 million of cash for the year ended December 31, 2019, which consisted primarily of proceeds from borrowings from our Prior Credit Facility during each period.

Credit Facility

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 a $30 million New Credit Facility with the lenders party thereto and Icahn Agency Services LLC, as administrative agent (the “New Administrative Agent”).

The New Credit Facility consists of a $10 million revolving loan facility and a $20 million term loan facility.

The New Credit Facility has two significant covenants, which require us to maintain (i) a maximum consolidated total net leverage ratio, measured as of the end of any fiscal quarter, of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio, measured as of the end of any fiscal quarter, of no less than 2.25 to 1.00.

These financial covenants are subject to customary cure rights.

We were in compliance with all applicable financial covenants under the New Credit Facility as of December 31, 2020.

The New Credit Facility replaced the Company’s Prior Credit Facility, dated as of February 10, 2017, as amended which was terminated effective November 30, 2020 and otherwise would have matured on April 1, 2021.

The company used the $20.0 million term loan proceeds to repay the $12.0 million outstanding on the Prior Credit Facility on November 30, 2020.

We have approximately $10.0 million of available borrowing capacity under the New Credit Facility line of credit at December 31, 2020.

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.

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 2021.

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.

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.

The underlying liabilities insured by these instruments are reflected in our balance sheets, where applicable.

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

As of December 31, 2021, 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.

Payments Due by Period

Total Less than

1-3 years 3-5 years More than

(In thousands)

Asset retirement obligations (1) $ 59,368 $ 17,606 $ 116 $ 47 $ 41,599

Operating lease 167 167

Finance lease 779 351 428 — —

Total $ 60,314 $ 18,124 $ 544 $ 47 $ 41,599

____________________

(1) Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2021.

These estimates and assumptions can be inherently unpredictable and may differ from actual results given the uncertainty of when we may be required to plug and abandon a well or retire an asset.

As a result, we may not incur all of the estimated costs for the current asset retirement obligation as depicted above.

During the year ended December 31, 2021, plugging and abandonment costs incurred were $2.1 million.

Valuation Allowance

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See “Note 1—Summary of Significant Accounting Policies” to the Company’s accompanying consolidated financial statements in Item 8 of this report for additional discussion of significant accounting policies.

Derivative Financial Instruments.

To manage risks related to fluctuations in prices attributable to its expected oil and natural gas production, the Company enters into oil and natural gas derivative contracts.

Entrance into such contracts is dependent upon prevailing or anticipated market conditions.

The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates and issue long-term debt that contains embedded derivatives.

The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument.

The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings.

The Company’s earnings may fluctuate significantly as a result of changes in fair value.

Derivative assets and liabilities are netted whenever a legally enforceable master netting agreement exists with the counterparty to a derivative contract.

The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows.

Fair values of the substantial majority of the Company’s commodity derivative financial instruments are determined primarily by using discounted cash flow calculations or option pricing models, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be corroborated from active markets.

Estimates of future prices are based upon published forward commodity price curves for oil and natural gas instruments.

Valuations also incorporate adjustments for the nonperformance risk of the Company or its counterparties, as applicable.

Proved Reserves.

Approximately 91.5% of the Company’s reserves were estimated by independent petroleum engineers for the year ended December 31, 2020.

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

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, 2020 and 2019, the Company revised its proved reserves from prior years’ reports by approximately (44.8) MMBoe and (58.5) MMBoe, respectively, due to 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.

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.

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.

Method of Accounting for Oil and Natural Gas Properties.

The Company’s business is subject to accounting rules that are unique to the oil and natural gas industry.

There are two allowable methods of accounting for oil and natural gas business activities:

the successful efforts method and the full cost method.

The Company uses the full cost method to account for its oil and natural gas properties.

All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized.

Exploration and development costs include dry well costs,

geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil, natural gas and NGL reserves.

Amortization of oil and natural gas properties is calculated using the unit-of-production method based on estimated proved oil, natural gas and NGL reserves.

Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves.

A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center, unless it results in a greater than 10% change to the depletion rate.

Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred.

Costs of drilling exploratory wells that do not result in proved reserves are charged to expense.

Depreciation, depletion and impairment of oil and natural gas properties are generally calculated on a well by well, lease or field basis versus the aggregated “full cost” pool basis.

Additionally, gain or loss is generally recognized on all sales of oil and natural gas properties under the successful efforts method.

As a result, the Company’s financial statements will differ from companies that apply the successful efforts method since the Company will generally reflect a higher level of capitalized costs as well as a higher oil and natural gas depreciation and depletion rate, and the Company will not have exploration expenses that successful efforts companies frequently have.

Impairment of Oil and Natural Gas Properties.

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

The Company recorded full cost ceiling impairment of $218.4 million for the year ended December 31, 2020 and $409.6 million for the year ended December 31, 2019.

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.

Unproved Properties.

The balance of unproved properties consists primarily of costs to acquire unproved acreage.

These costs are initially excluded from the Company’s amortization base until it is known whether proved reserves will or will not be assigned to the property.

The Company assesses all properties, on an individual basis or as a group if properties are individually insignificant, classified as unproved on a quarterly basis for possible impairment or reduction in value.

The assessment includes consideration of various factors, including, but not limited to, the following:

intent to drill;

remaining lease term;

geological and geophysical evaluations;

drilling results and activity;

assignment of proved reserves;

and economic viability of development if proved reserves are assigned.

During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.

Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

For leases that do not have existing production that would otherwise extend the lease term, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a three to five year period from the original lease date.

For leases that are held by production, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a 10-year period from the original lease date.

Property, Plant and Equipment, Net.

Other capitalized costs including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or the amortized fair value established on the 2016 bankruptcy emergence date.

Renewals and improvements are capitalized while repairs and maintenance are expensed.

Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 7 to 39 years for buildings and 1 to 27 years for the electrical infrastructure assets and other equipment.

When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in operations.

The carrying value of property and equipment is reviewed for possible impairment annually or whenever events or changes in circumstances indicate that the carrying value of such asset or asset group may not be recoverable.

Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group.

If an asset or asset group is determined to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value.

Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances.

The Company may also determine fair value by using the present value of estimated future cash inflows and/or outflows, or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary.

Changes in such estimates could cause the Company to reduce the carrying value of property and equipment.

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

Revenue Recognition.

Sales of oil, natural gas and NGLs are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck, net of royalties, discounts and allowances, as applicable.

The Company deducts transportation costs from oil, natural gas and NGL revenues.

Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production, ad valorem and other taxes in the consolidated statements of operations.

See "Note 16—Revenues" to the Company's accompanying consolidated financial statements in Item 8 of this report for further information on the Company's accounting policies related to revenues.

Income Taxes.

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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.

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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