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Item 7. Management’s Discussion and Analysis

2021-03-04 compared with 2020-02-27 · 138 added, 166 removed, 250 unchanged (55% of the section changed)

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This discussion and analysis should be read in conjunction with other sections of this report, including:

“Business” in Item 1, “Selected Financial Data” in Item 6 and “Financial Statements and Supplementary Data” in Item 8.

Additionally, discussion of our operating and financial data for 2018 compared to 2017 can be found in "Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations" under Part II of our previously filed 2018 Annual Report on Form 10-K, which was filed with the SEC on March 5, 2019.

“Business” in Item 1 and “Financial Statements and Supplementary Data” in Item 8.

Our discussion and analysis includes the following subjects:

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• Critical Accounting Policies and Estimates.

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

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.

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

Operational Activities

Operational activities for the years ended December 31, 2019, and 2018 include the following:

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

Gross Wells Drilled(2) Net Wells Drilled(2) Average Rigs Drilling

Mid-Continent (1)

11 3.9 0.6 22 8.0 1.7

North Park Basin

____________________

21 13.9 1.0 36 22.0 2.4

____________________

(1) Eight and fifteen wells were drilled under our previous drilling participation agreement in the NW STACK during the years ended December 31, 2019 and 2018.

(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.

(2) Includes wells with a rig release date during the years ended December 31, 2019 or 2018, respectively.

The chart below shows production by product for the years ended December 31, 2019 and 2018, and 2017:

The chart below shows production by product for the years ended December 31, 2020 and 2019:

(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.

Total production for 2020 was comprised of approximately 23.9% oil, 45.1% natural gas and 31.0% NGLs compared to 29.4% oil, 46.2% natural gas and 24.4% NGLs in 2019.

Recent Events

• On December 12, 2019, the Board appointed John P.

Suter as Interim President and Chief Executive Officer in addition to his current role as Chief Operating Officer.

Suter succeeds Mr.

McKinney, who resigned from his position as President and Chief Executive Officer and as a director of the Company.

• On February 4, 2020, the Company issued Workers Adjustment and Retraining Notification (WARN) Act notices to approximately 63 of its 120 Oklahoma City based employees as a result of its workforce reduction at its corporate headquarters.

As discussed in “Business— Our Business Strategy” in Item 1 of this report, we will focus on maximizing free cash flow in 2020 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 currently depressed commodity price environment.

As a result, we have reduced our planned capital expenditures for 2020 to between $25.0 million and $30.0 million.

• 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 if commodity prices increase sufficiently.

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.

Consolidated Results of Operations

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Year Ended December 31,

2019 2018 2017 2016 2015

Oil (per Bbl) $ 39.19 $ 57.04

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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 for our capital expenditure programs.

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.

Acquisitions and Divestitures of Oil and Gas Properties

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

Acquisitions and Divestitures of Properties

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.

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.

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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.

Divestiture of Permian Basin Properties.

On November 1, 2018, we sold substantially all of our oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, primarily located in Andrews County, TX, along with all of our 13,125,000 common units representing a 25% equity interest in the Permian Trust, to an independent third party for $14.5 million in cash, subject to certain remaining post-closing adjustments, and reduced our asset retirement obligations by approximately $26.9 million.

The CBP assets and interest in the Permian Trust include 1,066 producing wells within the Permian Trust's area of mutual interest, certain wells not associated with the Permian Trust, a field office, and all equipment, inventory and yards associated with our CBP operations.

As a result of this divestiture, we no longer have any obligations associated with the Permian Trust.

This transaction did not result in a significant alteration of the relationship between our capitalized costs and proved reserves and, accordingly, the divestiture was accounted for as an adjustment to the full cost pool with no gain or loss recognized on the sale.

Acquisition of Oil and Natural Gas Interests.

On November 2, 2018, we acquired certain interests in oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $22.5 million in net consideration, net of post-closing adjustments, and assumed asset retirement obligations of approximately $6.4 million.

The acquired assets primarily consist of interests in 1,199 producing wells, approximately 80% of which we operate, an additional 11.1% working interest in approximately 397,000 gross (44,000 net) acres across the Mid-Continent, and an additional 13.2% working interest ownership in our saltwater gathering and disposal system in the Mississippian Lime.

Acquisition of NW STACK Properties.

On February 10, 2017, we acquired assets consisting of approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash, net of post-closing adjustments.

Also included in the acquisition were working interests in four wells previously drilled on the acreage.

2017 Oil and Natural Gas Property Divestitures.

In 2017, we divested various non-core oil and natural gas properties for approximately $17.1 million in cash.

All of these divestitures were accounted for as adjustments to the full cost pool with no gain or loss recognized.

Oil, Natural Gas and NGL Production and Pricing

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Year Ended December 31,

2019 2018 2017

Production data (in thousands)

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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, if any.

For a discussion of reserves, PV-10 and reconciliation to Standardized Measure, see “Business— Primary Operations—Proved Reserves” in Item 1 of this report.

The table below presents production by area of operation for the years ended December 31, 2019, 2018 and 2017, and illustrates the impact of (i) natural declines in existing producing wells in the Mid-Continent, (ii) the Permian Divestiture in November 2018 and drilling no new wells in the Permian and other regions during 2019, 2018 and 2017, and (ii) continued development of the North Park Basin properties, which were acquired in December 2015 and the NW STACK, which was acquired in February 2017.

(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.

Year Ended December 31,

2019 2018 2017

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

Mississippian Lime 9,403 78.6 % 10,003 81.1 % 12,838 86.2 %

NW STACK 1,020 8.6 % 925 7.5 % 882 5.9 %

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

Mid-Continent 7,763 89.2 % 10,423 87.2 %

North Park Basin 940 10.8 % 1,533 12.8 %

Permian Basin — — % 373 3.0 % 513 3.4 %

Total 8,703 100.0 % 11,956 100.0 %

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Year Ended December 31,

2019 2018 2017

Oil $ 73,621 $ 186,360

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2020 oil, natural gas and NGL revenues $ 114,450

Change due to production volumes in 2019 (1,059)

Change due to average prices in 2019 (81,563)

2019 oil, natural gas and NGL revenues $ 266,104

Oil, natural gas and NGL revenues decreased by a combined $82.6 million, or 23.7% for the year ended December 31, 2019, compared to 2018 due largely to a decrease in average prices received for our oil, natural gas, and NGL production in 2019, and a 0.4 MMBoe decrease in total production, primarily resulting from natural declines in existing producing wells and as a result of selling our Permian properties in the fourth quarter of 2018.

Partially offsetting these production declines were 10 wells drilled and brought to production within North Park and 11 wells brought to production in the NW STACK areas during 2019.

Additionally, in the fourth quarter of 2018 we acquired working interests in certain oil and natural gas properties in the Mississippian Lime and NW STACK areas of Oklahoma and Kansa s.

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.

Operating Expenses

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Year Ended December 31,

2019 2018 2017

Lease operating expenses $ 43,431 $ 90,938

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Production, ad valorem, and other taxes (% of oil, natural gas, and NGL revenue) 8.4 % 7.3 %

Lease operating expenses for 2019 increased $3.2 million, or $0.49/Boe from 2018.

This increase is primarily due to (i) an increase in workover expense in 2019 compared to 2018 largely resulting from artificial lift repairs in the Mid-Continent,

and (ii) bringing on several multi-well pads in the North Park Basin during 2019 which resulted in additional expenditures for trucking produced water to disposal wells in 2019.

Production, ad valorem, and other taxes as a percentage of oil, natural gas, and NGL revenue remained consistent in 2019 compared to 2018.

Depreciation and depletion for oil and natural gas properties increased by $19.6 million for the year ended December 31, 2019 compared to 2018 due to an increase in the average depreciation and depletion rate to $12.28 per Boe in 2019 compared to an average rate of $10.32 in 2018.

This rate increase is primarily due to a decrease in the trailing twelve-month weighted average SEC prices for oil and natural gas during 2019, which resulted in a decrease in reserve volumes.

The rate increase is also a result of development activities in 2019 taking place in areas where our finding and development costs are higher than those included in historical depreciation and depletion rates.

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.

Impairment expense for the years ended December 31, 2020, and 2019 consisted of the following (in thousands):

Year Ended December 31,

2019 2018 2017

Full cost pool ceiling limitation $ 218,399 $ 409,574

Drilling assets — 22 4,019

Midstream assets — 4,148 —

Other 38,000 —

Total impairment $ 256,399 $ 409,574

Full cost pool impairment.

Impairment for the year ended December 31, 2019 largely resulted from a decrease in the trailing twelve-month weighted average SEC prices for oil and natural gas in 2019, lower NGL prices, increases in expected operating expenses, and a decrease in PUDs due to a decrease in year-end SEC commodity pricing.

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.

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.

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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").

Applying these estimated first quarter prices, and holding all other inputs constant to those used in the calculation of our December 31, 2019 ceiling test, an additional full cost ceiling limitation impairment is not indicated for the first quarter of 2020.

Applying these estimated first quarter prices, and holding all other inputs constant to those used in the calculation of our December 31, 2020 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2021.

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.

Any such ceiling test impairments in 2021 could be material to our net earnings.

Midstream asset impairment.

Impairment recorded on midstream assets in 2018 primarily reflects the write-down of midstream generator assets classified as held for sale to estimated net realizable value.

Non-Operating Expenses

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Year Ended December 31,

2019 2018 2017

General and administrative $ 15,327 $ 32,058

Accelerated vesting of employment compensation — 6,545 —

Proxy contest — 7,139 —

Terminated merger costs — — 8,162

Restructuring expenses 2,733 —

Employee termination benefits 8,433 4,792

(Gain) loss on derivative contracts (1,094) 17,155 (24,090)

Other operating (income) expense (608) (998) 479

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

Other operating expense (income) 206 (608)

Total non-operating expenses $ 20,934 $ 35,148

General and administrative expenses decreased $8.6 million, or 21.1%, for the year ended December 31, 2019 compared to 2018 due primarily to a $7.5 million decrease in compensation-related costs largely resulting from a reduction in force during the second quarter of 2019 and additional declines in headcount throughout 2019.

The remainder of the decrease is substantially related to reductions in other corporate office and technology expenses.

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.

Employee termination benefits for the year ended December 31, 2018, include cash and share-based severance costs incurred primarily as a result of (i) the reduction in force in the first quarter of 2018 and (ii) severance costs associated with the departure of our former CEO, James Bennett, former CFO, Julian Bott, and other senior officers.

See "Note 20 - Employee Termination Benefits" to the consolidated financial statements in Item 8 of this report for additional information.

We recorded net (gain) loss on commodity derivative contracts of $(1.1) million and $17.2 million for the years ended December 31, 2019, and 2018, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash (receipts) payments upon settlement of $(6.3) million and $35.3 million, respectively.

On November 14, 2017, we entered into an Agreement and Plan of Merger with Bonanza Creek.

In contemplation of the proposed merger, which would have been partially financed with debt, we entered into several oil derivative contracts in November 2017.

Approximately $8.0 million of the total 2018 loss reported above related to net cash payments upon settlement for these oil derivatives.

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.

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

Accelerated vesting of employment compensation costs incurred during the year ended December 31, 2018 include compensation costs recognized for the accelerated vesting of certain share and incentive-based awards granted to our employees and directors related to the change in the composition of the Board resulting from the 2018 annual meeting as discussed in "Note 19 - Proxy Contest" to the consolidated financial statements in Item 8 of this report.

Proxy contest costs for the year ended December 31, 2018 include legal, consulting and advisory fees incurred in the proxy contest which were initiated in response to shareholder actions in 2018.

See "Note 19 - Proxy Contest" to the consolidated financial statements in Item 8 of this report for additional discussion of this matter.

Other Income (Expense)

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Year Ended December 31,

2019 2018 2017

Other (expense) income

Interest expense, net $ (1,998) $ (2,974)

Gain on extinguishment of debt — 1,151 —

Other income, net 436 2,865 2,550

Other (expense) income , net (2,494) 436

Total other (expense) income $ (4,492) $ (2,538)

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Year Ended December 31,

2019 2018 2017

Interest expense

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Total interest expense, net $ 1,998 $ 2,974

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

Interest expense incurred during the year ended December 31, 2018 is primarily comprised of interest recorded on the Building Note and commitment fees on the undrawn portion of the credit facility.

Gain on extinguishment of debt was recognized for the year ended December 31, 2018 as a result of writing off the unamortized premium in conjunction with the repayment of the Building Note during the first quarter of 2018.

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

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.

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.

Liquidity and Capital Resources

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

Additionally, we had $57.5 million outstanding under our $225.0 million credit facility which matures on April 1, 2021, and $2.9 million in outstanding letters of credit, which reduce the amount available under the credit facility.

As of February 21, 2020, the Company had approximately $2.7 million in cash and cash equivalents, excluding restricted cash, $48.5 million outstanding under our credit facility, and $2.9 million in outstanding letters of credit.

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.

Working Capital and Sources and Uses of Cash

Our principal sources of liquidity for 2020 include cash flow from operations, cash on hand and amounts available under our credit facility, as discussed in “—Credit Facility” below.

Our working capital deficit decreased to $49.8 million at December 31, 2019, compared to $63.9 million at December 31, 2018, largely due to a reduction in accounts payable and accrued expenses outstanding on those dates, which is primarily due to a decline in drilling and completions activity in the fourth quarter of 2019 compared to 2018.

This reduction was partially offset by fluctuations in the timing and amount of payments and borrowings on our revolving credit facility and in the levels of accounts receivable largely due to the decline in oil, natural gas and NGL revenues in 2019 compared to 2018.

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..

We intend to spend between $5 million and $10 million in our 2021 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 credit facility and cash on hand.

We intend to reduce our capital spending below our projected cash flows from operations for the year, subject to changing industry conditions or events.

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

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

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Year Ended December 31,

2019 2018 2017

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

Cash flows used in investing activities (189,849) (183,453) (245,724)

Cash flows provided by (used in) investing activities 25,093 (189,849)

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

Net (decrease) increase in cash and cash equivalents $ (13,677) $ (81,663) $ (72,763)

Net increase (decrease) in cash and cash equivalents $ 22,298 $ (13,677)

Cash Flows from Operating Activities

The $24.2 million decrease in operating cash flows for the year ended December 31, 2019 compared to 2018, is primarily due to (i) the decline in oil, natural gas and NGL revenues, and (ii) a decrease in accounts payable and accrued expenses outstanding resulting from a reduction in drilling and completions activity in the fourth quarter of 2019 compared to the fourth quarter of 2018.

These decreases in cash flow were partially offset by (i) receiving cash on the settlement of derivatives in 2019 compared to paying cash in 2018 (ii) a reduction in cash paid for employee termination benefits, (iii) a reduction in 2019 payroll, benefits and other headcount driven costs resulting from reductions in force during 2018 and 2019, and (iv) a reduction in production, ad valorem and other taxes largely resulting from declining production levels.

Additionally, in 2018 we incurred costs related to the proxy contest, which were non-recurring in 2019.

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.

Cash Flows from Investing Activities

During the year ended December 31, 2019, cash flows used in investing activities primarily consisted of capital expenditures for drilling and completion activities.

During the year ended December 31, 2018, cash flows used in investing activities primarily consisted of capital expenditures for drilling and completion activities and cash paid for the acquisition of interests in certain Mid-Continent properties.

These expenditures were partially offset by cash proceeds received for the Permian Divestiture and other non-core asset divestitures in 2018.

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.

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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Year Ended December 31,

2019 2018 2017

Capital Expenditures

Drilling and completion $ 157,999 $ 158,695 $ 194,388

Drilling, completion, and capital workovers $ 3,563 $ 157,999

Leasehold and geophysical 1,005 3,790

Other - operating — 419 854

Other - corporate — 245

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____________________

(1) Excludes $5.4 million for the year ended December 31, 2019 related to a nonmonetary transaction.

(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 exploration and development activities decreased for the year ended December 31, 2019 compared to 2018, 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 2019.

Due to continued depressed market prices for oil, natural gas and NGL prices, we have again reduced our expected capital expenditures budget and drilling plan for 2020 in order to focus on generating free cash flow in future periods.

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.

Cash Flows from Financing Activities

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 credit facility during each period.

Our financing activities used $43.7 million of cash for the year ended December 31, 2018, which consisted primarily of repaying the Building Note and cash paid for employee tax obligations in connection with the withholding of common shares upon vesting of employee share-based compensation awards.

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

We have approximately $164.6 million of available borrowing capacity under our credit facility at December 31, 2019.

The borrowing base under the credit facility is $225.0 million, which was reduced from $300.0 million during the borrowing base redetermination completed in November 2019.

The level of our credit facility's borrowing base is determined by our lenders in their sole discretion, and is largely based on the estimated value of our oil and natural gas properties in the Company's most recently delivered reserve report.

This reserve report takes into account the prevailing oil, natural gas, NGL prices at that time.

If future commodity prices are consistent or lower than those experienced in 2019, planned reductions in our 2020 drilling and completions capital budget may lead to a decrease in our future reserve base as we will continue to deplete our reserves with production from existing wells without adding significant additional reserves through capital development.

This may result in additional reductions in our borrowing capacity in future periods.

The 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.

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 credit facility as of December 31, 2019.

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.

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 2020 and 2019.

Contractual Obligations and Off-Balance Sheet Arrangements

At December 31, 2019, our contractual obligations included asset retirement obligations, operating 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 standby letters of credit and 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 letters of credit and surety bonds.

As of December 31, 2019, 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) 75,016 22,119 13,773 2,636 36,488

Long-term debt obligations (2) 57,500 — 57,500 — —

Leases and other(3) 5,124 2,074 2,014 399 637

Total $ 137,640 $ 24,193 $ 73,287 $ 3,035 $ 37,125

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(1) Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2019.

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 do not expect to incur all of the estimated costs for the current asset retirement obligation shown above in the next twelve months, and have budgeted $4.5 million for actual expected plugging and abandonment costs in 2020.

(2) Includes debt principal amounts and assumes debt principal amounts will be outstanding until their last contractual maturity.

(3) Includes trustee fees for SandRidge Mississippian Trust II, which announced on January 23, 2020, that it will be required to dissolve and commence winding up in the first quarter of 2020.

As a result, certain trustee fees included in the table above may not be incurred in future years.

Valuation Allowance

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

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

Additionally, we had significant U.S.

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

As such, the Successor Company had significant

deferred tax assets to consume upon emergence.

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 realized and established a valuation allowance against our net deferred tax asset upon emergence and maintained the valuation allowance for the subsequent periods through September 30, 2019.

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, 2020.

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

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The Company’s critical accounting policies and additional information on significant estimates are discussed below.

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

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.

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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.

However, there are numerous uncertainties inherent in

estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Company’s control.

However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Company’s control.

Estimating reserves is a complex process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data.

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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, 2019, 2018 and 2017, the Company revised its proved reserves from prior years’ reports by approximately (58.5) MMBoe, (33.2) MMBoe and 10.9 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, 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.

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.

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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.

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.

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.

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

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

No full cost ceiling impairment was recorded for the years ended December 31, 2018 and 2017.

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.

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

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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.

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 Emergence Date.

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

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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, other than the electrical infrastructure assets, is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset or asset group may not be recoverable.

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.

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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 consolidated financial statements in Item 8 of this report for a discussion of the Company’s impairments.

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

Asset Retirement Obligations.

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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 consolidated financial statements in Item 8 of this report for further information on the Company's accounting policies related to revenues.

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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New Accounting Pronouncements.

For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 1—Summary of Significant Accounting Policies” to the Company’s consolidated financial statements in Item 8 of this report.

For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 1—Summary of Significant Accounting Policies” to the Company’s accompanying consolidated financial statements in Item 8 of this report.

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