GULFPORT ENERGY CORP (GPOR) FY 2021 MD&A

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2020 Annual Report on Form 10-K filing and analyzes the changes in the results of operations between the years ended December 31, 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2020.

Our results of operations as reported in our consolidated financial statements for the Successor Period and the Predecessor Period are in accordance with GAAP. Although GAAP requires that we report on our results for these periods separately, management views our operating results for the twelve months ended December 31, 2021, by combining the results of the Successor Period and the Predecessor Period ("Combined Period"). While these combined results do not comply with GAAP and have not been prepared as pro forma results under applicable regulations, they are presented because we believe they provide the most meaningful comparison of our results to prior periods. We do not believe reviewing these periods in isolation would be useful in identifying any trends in or reaching any conclusions regarding our overall operating performance. We believe the key performance indicators such as operating revenues and operating expenses for the Successor Period combined with the Predecessor Period provide more meaningful comparisons to other periods and are useful in understanding operational trends. Additionally, there were no material changes in policies between the periods and any material impacts as a result of fresh start accounting were included within the discussion of these changes.

Overview

Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in Eastern Ohio targeting the Utica and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders. To accomplish these goals, we allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts.

Recent Developments

Emergence from voluntary reorganization under Chapter 11

On November 13, 2020, we and our subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases were administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). The Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021, and the Debtors emerged from the Chapter 11 Cases on the Emergence Date. On May 18, 2021, we began trading on the New York Stock Exchange under the symbol "GPOR."

Although we are no longer a debtor-in-possession, we operated as debtors-in-possession through the pendency of the Chapter 11 Cases. See Note 1 and Note 2 of our consolidated financial statements for a complete discussion of the Chapter 11 Cases.

We believe we have emerged from the Chapter 11 Cases as a fundamentally stronger company, built to generate sustainable free cash flow with a strengthened balance sheet. As a result of the Chapter 11 Cases, we reduced our total indebtedness by $1.4 billion by issuing equity in a reorganized entity to the holders of our unsecured notes and allowed general unsecured claimants. In addition, we reassessed our organizational needs post emergence and significantly reduced our general and administrative expense to ensure our cost structure is competitive with industry peers. We continue to focus on reducing our operating costs, per well drilling costs, general and administrative costs and managing our liquidity. We believe our plan to

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generate free cash flow on an annual basis will allow us to further strengthen our balance sheet and return capital to shareholders.

Changes in Chief Executive Officer and Chief Financial Officer

On May 17, 2021, the Board reached agreements with David M. Wood and Quentin R. Hicks that Messrs. Wood and Hicks would no longer serve as Chief Executive Officer and a member of the Board, in the case of Mr. Wood, and Chief Financial Officer, in the case of Mr. Hicks.

On May 17, 2021, the Board appointed Timothy J. Cutt as Interim Chief Executive Officer and Chair of the Board. On September 2, 2021, we reached agreement with Mr. Cutt, effective immediately, to fully assume the role of Chief Executive Officer, dropping the "Interim" designation from his title.

On May 17, 2021, the Board appointed William J. Buese as Chief Financial Officer.

New Credit Facility

On October 14, 2021, we entered into the New Credit Facility for an aggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850.0 million and an initial aggregate elected commitment amount of $700.0 million. The New Credit Facility amended and refinanced the Exit Credit Facility. See Note 6 of our consolidated financial statements for additional discussion of the New Credit Facility.

Stock Repurchase Program

On November 1, 2021, our board of directors approved a stock repurchase program to acquire up to $100 million of our outstanding New Common Stock. Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require the Company to acquire any specific number of shares of New Common Stock. The Company intends to purchase shares under the Repurchase Program opportunistically with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program is authorized to extend through December 31, 2022, and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. Any shares of New Common Stock repurchased are expected to be cancelled. We have not repurchased any shares under this program as of December 31, 2021.

COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

As a result of our business continuity measures, we have not experienced significant disruptions in executing our business operations due to COVID-19. While we did not experience significant disruptions to our operations in 2021, we are unable to predict the impact on our business, including our cash flows, liquidity, and results of operations in future periods due to numerous uncertainties. Restrictions may cause us, our suppliers and other business counterparties to experience operational delays, or delays in the delivery of materials and supplies. We expect the principal areas of operational risk for us are the availability and reliability of service providers and potential supply chain disruption. Additionally, the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced natural gas, NGL and oil, may be disrupted or suspended in response to containing the outbreak, or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers. This may result in substantial discount in the prices we receive for our produced natural gas, NGL and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties.

We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments and the timing and extent to which normal economic and operating conditions resume.

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2021 Operational and Financial Highlights

During 2021, we had the following notable achievements:

•Emerged from Chapter 11 proceedings in May 2021 with improved balance sheet and fixed-cost structure.

•In September 2021, we finalized a settlement agreement with TC Energy which rejected the firm transportation contracts between us and TC Energy without any further payment or obligation by us or TC. In exchange, we paid $43.8 million in cash to TC and expect to receive back a significant portion of such amount through future distributions with respect to the assigned claims.

•In October 2021, we amended and refinanced our Exit Credit Facility with the New Credit Facility. The amendment increased our elected commitment from $580 million to $700 million and increased our liquidity by more than $160 million.

•In December 2021, we reached an agreement with Stingray Pressure Pumping LLC that fully resolved the longstanding litigation between the parties.

•Turned to sales 28 gross (26.4 net); including the Angelo pad which flowed at a sustained, gross peak rate of 250 MMcfe per day after it was brought online in early October.

•Reported year-end estimated net proved reserves of 3.9 Tcfe.

Business and Industry Outlook

As discussed above, we emerged from voluntary reorganization under Chapter 11 in May 2021. Through our restructuring we were able to emerge with a strengthened balance sheet and materially improved fixed-cost structure. Gulfport is beginning this new chapter with a strategy focused on continuing to reduce costs and generating sustainable free cash flow in an effort to drive shareholder value. In addition, we are committed to an emphasis on sustainability, and we will continue to prioritize safety, environmental stewardship, and maintaining strong relationships with the communities in which we operate. As we enter 2022, we believe we are positioned for sustainable long-term success.

In 2021, natural gas prices improved significantly, but continue to be volatile as spot prices ranged from $2.43 to $23.86 per MMBtu. Henry Hub averaged $3.89 per MMBtu in 2021 vs $2.03 per MMBtu in 2020. As we look into 2022, we expect continued volatility in natural gas prices. To mitigate our exposure to commodity market volatility and ensure our continued financial strength we have entered into financial hedges representing approximately 86% of our expected 2022 production.

Our 2022 capital expenditure program is expected to be in a range of $340 million to $380 million. Prior to 2021, general inflation was moderate; however, our capital and operating costs were influenced to a large extent by the volatility in commodity prices. With the improved commodity price environment, we have experienced and expect to continue to experience inflationary pressures during 2022. We continue to monitor and manage inflationary pressures caused by increased activities in the field as well as supply chain pressures.

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Results of Operations

Comparison of the Predecessor Period, Successor Period and the Year Ended December 31, 2020

We reported net income of $251.0 million for the Predecessor Period and a net loss of $112.8 million for the Successor Period, as compared to a net loss of $1.6 billion for the year ended December 31, 2020. The material changes that lead to the increase in net income are further discussed by category on the following pages. Some totals and changes throughout below section may not sum or recalculate due to rounding.

Natural Gas, Oil and NGL Sales (sales totals in thousands)

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(1) In November 2020, the Company early terminated certain gas fixed-price swaps which resulted in a cash payment of $60.2 million.

(2) In April 2020, the Company early terminated certain oil fixed-price swaps which resulted in a cash receipt of $40.5 million.

In the Combined Period, our total unhedged natural gas, oil and NGL revenues increased approximately $701.6 million, or 88%, as compared to the year ended December 31, 2020. The increase was primarily driven by significant increases in oil, natural gas and NGL indexes. Most notably, the Henry Hub index increased from $2.03 per MMBtu in 2020 to $3.89 per MMBtu in 2021. The impact of the realized price increases was partially offset by a decrease in volumes of 3%, or $28.7 million, as a result of natural declines partially offset by wells that were turned to sales during 2021.

The total natural gas, oil and NGL volumes hedged for the Combined Period and the year ended December 31, 2020, represented approximately 87% and 70%, respectively, of our total sales volumes for the applicable year.

Natural Gas, Oil and NGL Derivatives (in thousands)

Settlement (losses) gains in the table above represent realized cash gains or losses to the instruments described in Note 13 of our consolidated financial statements. Our hedging program incurred cash settlements of $326.2 million for the Combined Period, as compared to $159.4 million provided in 2020.

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Lease Operating Expenses (in thousands)

The decrease in total LOE when comparing the Combined Period to the year ended December 31, 2020, was primarily driven by a 3% decrease in our production. LOE on a per unit basis in 2021 was consistent with 2020.

Taxes Other Than Income (in thousands)

The increase in total and per unit taxes other than income when comparing the Combined Period to the year ended December 31, 2020, was primarily related to an increase in production taxes resulting from the significant increase in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.

Transportation, Gathering, Processing and Compression (in thousands)

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The decrease in transportation, gathering, processing and compression when comparing the Combined Period to the year ended December 31, 2020, was primarily related to a 3% decrease in our production and savings associated with midstream contract rejections and renegotiations through the bankruptcy process. The decrease in per unit transportation, gathering, processing and compression when comparing the Combined Period to the year ended December 31, 2020, was primarily related to midstream contract rejections and renegotiations through the bankruptcy process.

Depreciation, Depletion and Amortization (in thousands)

The decrease in depreciation, depletion and amortization of our oil and gas properties is primarily the result of impairments taken in 2020 which decreased the depletion rate, partially offset by an increase in the depletion rate for the Successor Period as a result of the fresh start valuations on our oil and gas properties. See Note 3 of our consolidated financial statements for more information on fresh start adjustments.

Impairment of Oil and Gas Properties. During the Successor Period, we had $117.8 million oil and natural gas properties impairment charges, compared to $1.4 billion impairment charges of oil and gas properties in 2020. Upon the application of fresh start accounting, the value of our oil and natural gas properties was determined using forward strip oil and natural gas prices as of the emergence date. These prices were higher than the 12-month weighted average prices used in the full cost ceiling limitation at June 30, 2021, which led to the Successor Period impairment charge.

Impairment of Other Property and Equipment. We recognized a $14.6 million impairment charge on the Company's corporate headquarters during the Predecessor Period as a result in a change in expected future use.

General and Administrative Expenses (in thousands)

The decrease in total general and administrative expenses during the Combined Period compared to the year ended December 31, 2020, was primarily driven by retention payments made in 2020 and our continued focus on workforce and leadership structure to ensure our cost structure is competitive with industry peers.

Restructuring and Liability Management Expenses. During the Successor Period and the year ended December 31, 2020, we incurred restructuring charges related to reductions in workforce as we continued to align our workforce and leadership structure to our current operating environment. Additionally, during the year ended December 31, 2020, we incurred liability

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management charges related to legal advisors engaged to assist with the evaluation of a range of liability management alternatives prior to our ultimate Chapter 11 filing.

The following table summarizes the restructuring and liability management charges incurred (in thousands):

Accretion Expense. Accretion expense decreased to $2.4 million for the Combined Period, from $3.1 million for the year ended December 31, 2020. The decrease in accretion expense stems primarily from a decrease in our asset retirement obligation as a result of fresh start adjustments upon emergence. See Note 3 of our consolidated financial statements for more information on fresh start adjustments.

Interest Expense (in thousands)

The decrease in interest expense during the Successor Period compared to the year ended December 31, 2020, was due the changes in our debt structure upon emergence from Chapter 11.

Loss (Gain) on Debt Extinguishment. During the Successor Period, the Company recognized a loss of $3.0 million associated with the extinguishment of capitalized commitment fees related to the Exit Credit Facility as discussed in Note 6 of our consolidated financial statements. During 2020, we repurchased in the open market $73.3 million aggregate principal amount of our Predecessor Senior Notes for $22.8 million in cash and recognized a $49.6 million gain on debt extinguishment.

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Equity Investments (in thousands)

We, through our wholly owned subsidiary Grizzly Holdings, own an approximate 24.5% interest in Grizzly, a Canadian unlimited liability company. Effective as of the Emergence Date, we evaluated our investment in Grizzly and determined that we no longer have the ability to exercise significant influence over operating and financial policies of Grizzly Holdings. As such, we discontinued the equity method of accounting for our investment in Grizzly and we will use our previous carrying value of zero as our initial basis and will subsequently measure at fair value while recording any changes in fair value in earnings.

During the year ended December 31, 2020, our share of net loss from Mammoth Energy Services, Inc. was in excess of the carrying value of our investment, which reduced our investment to zero. Our carrying value remained at zero through the Predecessor Period until the use of Mammoth Shares to settle Class 4A claims at the Emergence Date. See Note 15 of our consolidated financial statements for further discussion on our equity investments.

Reorganization Items, Net. The following table summarizes the components in reorganization items, net included in our consolidated statements of operations for the Combined Period and the year ended December 31, 2020 (in thousands):

We do not expect to incur any reorganization costs in 2022. See Note 3 of our consolidated financial statements for further discussion of the components of reorganization items, net.

Other Expense, Net (in thousands)

The decrease in other expense for the Combined Period compared to the year ended December 31, 2020 is primarily the result of a $16.6 million loss on the change in fair value of our contingent consideration agreement related to the sale of our SCOOP water infrastructure assets to a third-party water service provider during the year ended December 31, 2020.

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Income Taxes (in thousands)

For the Predecessor Period, we had an effective tax rate of (3.3)% and an income tax benefit of $8.0 million. The tax benefit is entirely attributable to an Oklahoma refund claim associated with an examination relating to historical tax returns. The effective tax rate differs from the statutory tax rate due to the Company’s valuation allowance position and the permanent adjustments relating to the Chapter 11 Emergence. For the Successor Period, we had an effective tax rate of 0.03% and tax expense of $39 thousand. The tax expense is entirely attributable to the Oklahoma refund claim that was filed during the third quarter, resulting in an adjustment to the benefit recorded during the Predecessor Period. We did not record any additional income tax expense for the Successor Period as a result of maintaining a full valuation allowance against our net deferred tax asset. The change in income tax expense relative to 2020 is primarily the result of the recognition of a valuation allowance against a state deferred tax asset.

Liquidity and Capital Resources

Overview. We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility, fund our development projects, operations and capital expenditures and return capital to shareholders. We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company's cash flows. Historically, we have generally funded our operations, planned capital expenditures and any debt or share repurchases with cash flow from our operating activities, cash on hand, borrowings under our revolving credit facility and issuances of equity and debt securities.

For the Successor Period, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, and our primary uses of cash have been for net principal payments under the New Credit Facility and the development of our oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under our credit agreements and issuances of equity and debt securities. Our ability to issue additional indebtedness, dispose of assets or access the capital markets was substantially limited or nonexistent during the Chapter 11 Cases and required court approval in most instances. Accordingly, our liquidity in the Predecessor periods depended mainly on cash generated from operating activities and available funds under the DIP Credit Facility in the 2021 Predecessor Period and Pre-Petition Revolving Credit Facility in the 2020 Predecessor Period.

We believe our annual free cash flow generation, borrowing capacity under the New Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense, debt repayments and any return of capital to shareholders authorized by the Board, during the next 12 months.

To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 6 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.

As of December 31, 2021, we had a cash balance of $3.3 million compared to $89.9 million as of December 31, 2020, and a net working capital deficit of $361.4 million as of December 31, 2021, compared to a net working capital deficit of $100.5 million as of December 31, 2020. As of December 31, 2021, our working capital deficit includes no debt due in the next 12 months. Our total principal debt as of December 31, 2021, was $714.0 million compared to $2.3 billion as of December 31, 2020. See Note 6 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.

As of February 25, 2022, we had $7.1 million of cash and cash equivalents, zero borrowings under our New Credit Facility, $109.8 million of letters of credit outstanding, and $550 million of outstanding 2026 Notes.

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Post-Emergence Debt. On the Emergence Date, pursuant to the terms of the Plan, we entered into a reserve-based credit agreement providing for the Exit Credit Facility, which featured an initial borrowing base of $580.0 million. The Exit Credit Facility consisted of the Exit Facility and the First-Out Term Loan. In October 2021, we amended and refinanced the Exit Credit Facility with the New Credit Facility.

As discussed in Note 6 of our consolidated financial statements, on October 14, 2021, we entered into the Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and various lender parties. The New Credit Facility provides for an aggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850.0 million and an initial aggregate elected commitment amount of $700.0 million. The credit agreement also provides for a $175.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit.

Additionally, on the Emergence Date, pursuant to the terms of the Plan, we issued $550 million aggregate principal amount of our Successor Senior Notes.

The Successor Senior Notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the New Credit Facility.

See Note 6 of our consolidated financial statements for additional discussion of our post-emergence debt.

Preferred Dividends. As discussed in Note 7 of our consolidated financial statements, holders of New Preferred Stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the liquidation preference with respect to cash dividends and 15% per annum of the liquidation preference with respect to dividends paid in kind as additional shares of New Preferred Stock (“PIK Dividends”).

Supplemental Guarantor Financial Information. The Successor Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our New Credit Facility or certain other debt (the “Guarantors”). The Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC (the “Non-Guarantors”). The Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The Successor Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the Successor Senior Notes.

SEC Regulation S-X Rule 13-01 requires the presentation of "Summarized Financial Information" to replace the "Condensed Consolidating Financial Information" required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.

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Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive. See Item 7A Quantitative and Qualitative Disclosures About Market Risk for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 13 of our consolidated financial statements for further discussion of derivatives and hedging activities. Subsequent to December 31, 2021 and as of February 25, 2022, we entered into the following natural gas, oil, and NGL derivative contracts:

(1) Volumes for gas instruments are presented in MMBtu while oil and NGL volumes are presented in Bbls.

Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2021 (in thousands):

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(1)    The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. See Note 6 of our consolidated financial statements for a description of our long-term debt.

(2)    Our commitments under our firm transportation and gathering contracts do not reflect contracts recently rejected or in the process of being rejected as discussed in the Litigation and Regulatory Proceedings section in Note 19 of our consolidated financial statements. See Note 18 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments.

(3)    See Note 10 of our consolidated financial statements for a description of our operating lease liabilities.

(4)    This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 13 and 5 of our consolidated financial statements, respectively.

Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2021, our material off-balance sheet arrangements and transactions include $122.1 million in letters of credit outstanding against our revolving credit facility and $32.7 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance on certain firm transportation agreements. The Company expects to enter into similar contractual arrangements in the future in order to support the Company's business plans. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources.

Capital Expenditures. Our capital expenditures have been primarily for the acquisition and development of oil and gas properties. Our capital investment strategy is focused on prudently developing our existing properties in an effort to generate sustainable cash flow considering current and forecasted commodity prices.

Our 2022 drilling and completion capital expenditure program is expected to be in a range of $320 million to $360 million. In addition, we expect to spend approximately $20 million on leasehold and land expenses, primarily associated with lease extensions in the Utica. The midpoint of the 2022 range of capital expenditures is approximately 23% higher than the $292.9 million spent in 2021, primarily due to inflation and our efforts to run a more continuous development program in the Utica, allowing for increased operational efficiencies and opportunities for incremental cost reductions.

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Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2021, WTI prices ranged from $47.47 to $85.64 per barrel and the Henry Hub spot market price of natural gas ranged from $2.43 to $23.86 per MMBtu. During 2020, WTI prices ranged from $(36.98) to $63.27 per barrel and the Henry Hub spot market price of natural gas ranged from $1.33 to $3.14 per MMBtu. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities.

See Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" for further information regarding our open derivative instruments at December 31, 2021.

Cash Flow from Operating Activities. Net cash flow provided by operating activities was $465.1 million for the Combined Period as compared to $95.3 million for the year ended December 31, 2020. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to an 88% increase in net natural gas, oil and NGL sales excluding the impact of derivatives.

Divestitures. During the Successor Period and 2020, we divested certain water infrastructure assets and non-core assets and interests in operated and non-operated oil and natural gas properties for approximately cash proceeds $4.3 million and $51.0 million, respectively. Proceeds from these transactions were primarily used to repay debt and fund our development program. See Note 4 of our consolidated financial statements for further discussion.

Uses of Funds. The following table presents the uses of our cash and cash equivalents for the Successor Period, Predecessor Period, and year ended December 31, 2020 (in thousands):

Drilling and Completion Costs. During the Combined Period, we spud 20 gross (19 net) wells and commenced sales from 17 gross and net wells in the Utica for a total cost of approximately $191.5 million.

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During the Combined Period, we spud 9 gross (7.7 net) and commenced sales from 11 gross (9.4 net) wells in the SCOOP for a total cost of approximately $83.5 million. In addition, 25 gross (1.77 net) wells were spud and 21 gross (0.05 net) wells were turned to sales by other operators on our SCOOP acreage during 2021 for a total cost to us of approximately $6.0 million.

Drilling and completion costs presented in this section reflect incurred costs while drilling and completion costs presented above in Uses of Funds section reflect cash payments for drilling and completions.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors.

Reorganization and Fresh Start Accounting. The Company applied FASB ASC Topic 852 - Reorganizations ("ASC 852") in preparing the consolidated financial statements, which specifies the accounting and financial reporting requirements for entities reorganizing through Chapter 11 bankruptcy proceedings. These requirements included distinguishing transactions associated with the reorganization separate from activities related to the ongoing operations of the business. Accordingly, pre-petition liabilities that may be impacted by the Chapter 11 proceedings were classified as liabilities subject to compromise on the consolidated balance sheet as of December 31, 2020. Additionally, certain expenses, realized gains and losses and provisions for losses that were realized or incurred during the Chapter 11 Cases, including adjustments to the carrying value of certain indebtedness were recorded as reorganization items, net in the consolidated statements of operations for the year ended December 31, 2020 and the Predecessor Period.

Upon emergence from the Chapter 11 Cases, ASC 852 required us to allocate our reorganization value to our individual assets based on their estimated fair values, resulting in a new entity for financial reporting purposes. After the Effective Date, the accounting and reporting requirements of ASC 852 are no longer applicable and have no impact on the Successor periods. Refer to Note 2 and Note 3 of our consolidated financial statements for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the reorganization.

Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized.

Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.

We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test.

Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2021. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. During the Successor Period, we recorded impairments of our oil and natural gas properties in the amount of $117.8 million compared to $1.4 billion during the year ended December 31, 2020. See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting.

Oil, Natural Gas and NGL Reserves. Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions.

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Index to Financial Statements

Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information.

Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Quarterly, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2021, a valuation allowance of $907.4 million had been established to fully offset our net deferred tax asset on our accompanying consolidated balance sheet.

Revenue Recognition. We derive almost all of our revenue from the sale of natural gas, crude oil and NGL produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. Historically, our actual payments received have not significantly deviated from our accruals.

Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.

The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Our current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.