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Item 7. Management’s Discussion and Analysis

2022-02-17 compared with 2021-02-17 · 116 added, 132 removed, 147 unchanged (63% of the section changed)

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We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas in the United States.

Our assets are concentrated in the Haynesville and Bossier shale located in North Louisiana and East Texas, a premier natural gas basin with superior economics due to geographic proximity to Gulf Coast natural gas markets.

Approximately 95% of our December 31, 2020 proved reserves are located in the Haynesville and Bossier shale region.

Our assets are concentrated in the Haynesville and Bossier shale located in North Louisiana and East Texas, a premier natural gas basin with superior economics due to the geographic proximity to Gulf Coast natural gas markets.

We own interests in 2,557 producing oil and natural gas wells (1,459.6 net) and we operate 1,575 of these wells.

We intend to maintain an operating plan in 2021 targeting debt reduction and generation of free cash flow.

We intend to maintain an operating plan in 2022 targeting additional debt reduction and generation of free cash flow.

We use the successful efforts method of accounting, which allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration activities.

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Oil and natural gas prices have historically been volatile and are likely to remain volatile in the future.

Our operating costs are generally comprised of several components, including costs of field personnel, insurance, repair and maintenance costs, production supplies, fuel used in operations, transportation costs, workover expenses and state production and ad valorem taxes.

Our operating costs are generally comprised of several components, including costs of our field personnel, insurance, repair and maintenance costs, production supplies, fuel used in operations, transportation costs, workover expenses and state production and ad valorem taxes.

Like all oil and natural gas exploration and production companies, we face the challenge of replacing our reserves.

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Applicable environmental regulations require us to remove our equipment after production has ceased, to plug and abandon our wells and to remediate any environmental damage our operations may have caused.

The present value of the estimated future costs to plug and abandon our oil and gas wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $19.3 million of December 31, 2020.

Prices for oil and natural gas have been highly volatile in recent years, and we experienced a period of low prices in 2020 primarily due to an oversupply of oil and natural gas.

We expect our oil production to continue to

decline as we have limited future plans to participate in the drilling of new oil wells.

We expect our natural gas production to increase, assuming we maintain a sufficient development program to offset expected production declines from our producing wells.

Prices for oil and natural gas have been highly volatile in recent years but we expect our natural gas production to increase, assuming we maintain a sufficient development program to offset expected production declines from our producing wells.

The level of our drilling activity is dependent on natural gas prices.

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We may need to recognize impairments if oil and natural gas prices decline, and as a result, the expected future cash flows from these properties becomes insufficient to recover their carrying value.

Jones Contribution

On August 14, 2018, the Jones Partnerships contributed certain oil and gas properties in North Dakota and Montana in exchange for 88,571,429 newly issued shares of common stock representing 84% of our then outstanding common stock (the "Jones Contribution").

The Jones Partnerships are wholly owned and controlled by Dallas businessman Jerry Jones and his children (collectively, the "Jones Group").

References to "Successor" or "Successor Company" relate to the operations of the Company subsequent to August 13, 2018.

References to "Predecessor" or "Predecessor Company" relate to the operations of the Company on or prior to August 13, 2018.

Covey Park Acquisition

On July 16, 2019, we acquired Covey Park Energy LLC ("Covey Park") for total consideration of $700.0 million of cash, the issuance of Series A Convertible Preferred Stock with a redemption value of $210.0 million, and the issuance of 28,833,000 shares of common stock (the "Covey Park Acquisition").

Covey Park's operations were focused primarily in the Haynesville/Bossier shale in North Louisiana and East Texas.

In addition to the consideration paid, we assumed $625.0 million of Covey Park's 7.5% senior notes, repaid $380.0 million of Covey Park's then outstanding borrowings under its bank credit facility and redeemed all of Covey Park's preferred equity for $153.4 million.

Based on the fair value of the preferred stock issued and the closing price of our common stock of $5.82 per share on July 16, 2019, the transaction was valued at approximately $2.2 billion.

On May 20, 2020, we redeemed all of the outstanding shares of the Series A Convertible Preferred Stock for an aggregate redemption price of $210.0 million plus accrued and unpaid dividends of approximately $2.9 million.

Funding for the $700.0 million of cash consideration was provided by the sale of 50 million newly issued shares of our common stock for $300.0 million and 175,000 shares of newly issued Series B Convertible Preferred Stock for $175.0 million to our majority stockholder and by borrowings under our bank credit facility and cash on hand.

We incurred $41.0 million of advisory and legal fees and other acquisition-related costs in connection with the Covey Park Acquisition.

These costs are included in transaction costs in our consolidated statements of operations.

The acquisition included approximately 249,000 net acres and 2.9 Tcfe of proved reserves.

The acquisition added approximately 710 MMcfe of daily average production, at the date of the acquisition, and over 1,200 net future drilling locations.

The transaction was accounted for as a business combination, using the acquisition method.

As of December 31, 2020, our majority stockholder owned approximately 60% of our outstanding common stock and the former owners of Covey Park owned approximately 8% of our common stock.

The Jones Group also holds our Series B Convertible Preferred Stock that is convertible into 43,750,000 shares of our common stock.

Results of Operations

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Oil and Gas Sales (in thousands) :

Natural gas sales $635,795 $809,399

Oil sales 132,894 48,796

Natural gas $1,775,768 $809,399

Oil 74,962 48,796

Total oil and gas sales $1,850,730 $858,195

Net Production Data:

Natural gas sales (MMcf) 292,834 450,836

Oil sales (MBbls) 2,685 1,508

Natural gas (MMcf) 489,274 450,836

Oil (MBbls) 1,210 1,508

Total oil and gas (MMcfe) 496,534 459,883

Average Sales Price:

Natural gas sales $2.17 $1.80

Oil sales $49.49 $32.36

Total oil and gas sales $2.49 $1.87

Natural gas ($/Mcf) $3.63 $1.80

Oil ($/Bbl) $61.95 $32.36

Total oil and gas sales ($/Mcfe) $3.73 $1.87

Expenses ($ per Mcfe):

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Oil and gas sales.

Oil and gas sales of $858.2 million in 2020 increased $89.5 million or 12% over oil and gas sales in 2019 of $768.7 million.

The increase is due to a 49% increase in production volumes that was partially offset by lower realized oil and natural gas prices in 2020.

Oil and gas sales of $1.9 billion in 2021 increased $992.5 million or 116% over oil and gas sales in 2020 of $858.2 million.

The increase is due to a 9% increase in our natural gas production along with a 99% increase in realized oil and natural gas prices in 2021.

Our 2021 natural gas production was 489.3 billion cubic feet ("Bcf") (1.3 Bcf per day), which was sold at an average price of $3.63 per Mcf as compared to 450.8 Bcf (1.2 Bcf per day) sold at an average price of $1.80 in 2020.

Our 2021 oil production was 1.2 MMBbls (3,315 Bbls per day), which was sold at an average price of $61.95 per Bbl as compared to 1.5 MMBbls (4,120 Bbls per day) sold at an average price of $32.36 per Bbl in 2020.

We utilize natural gas and oil price derivative financial instruments to manage our exposure to natural gas and oil prices and protect returns on investment from our drilling activities.

We utilize natural gas and oil price derivative financial instruments to manage our exposure to changes in natural gas and oil prices and protect returns on investment from our drilling activities.

The following table presents our natural gas and oil prices before and after the effect of cash settlements of our derivative financial instruments:

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Price per Barrel, including cash settlements on derivative financial instruments $ 55.28 $ 40.88

Cash settlements for oil and natural gas derivative financial instruments totaled $52.7 million and $134.9 million for 2019 and 2020, respectively.

Production and ad valorem taxes.

Our production and ad valorem taxes increased $12.2 million (33%) to $49.1 million in 2021 from $37.0 million in 2020.

This increase is primarily related to the $89.5 million increase in oil and gas sales.

This increase is primarily related to the increase in oil and natural gas sales in 2021.

Gathering and transportation.

Gathering and transportation costs increased $24.4 million or 23% to $130.9 million in 2021 as compared to $106.6 million in 2020.

This increase was due primarily to the increase in our natural gas production resulting from our drilling activities and the Covey Park Acquisition completed in 2019.

This increase was due primarily to the higher natural gas production in 2021 combined with a higher average rate.

Lease operating expenses.

Our lease operating expenses of $102.5 million in 2020 was $21.7 million or 27% higher than the lease operating expenses in 2019 of $80.8 million.

Our lease operating expense of $0.22 per Mcfe produced for 2020 was 0.05 per Mcfe lower than the lease operating expense of $0.27 per Mcfe in 2019.

The lower average per unit cost is related to the growth in our lower cost natural gas production where much of the operating costs are fixed in nature.

Our lease operating expense of $103.5 million in 2021 was $1.0 million or 1% higher than the lease operating expenses in 2020 of $102.5 million due to the higher natural gas production.

Our lease operating expense of $0.21 per Mcfe produced for 2021 was comparable to the 2020 rate of $0.22 per Mcfe.

Depreciation, depletion and amortization expense ("DD&A").

DD&A increased $140.6 million (51%) to $417.1 million in 2020 from $276.5 million in 2019 due to the 49% increase in production.

Our DD&A per equivalent Mcf produced was $0.91 per Mcfe in 2020, which was comparable to the $0.90 per Mcfe rate for 2019.

DD&A increased $52.3 million (13%) to $469.4 million in 2021 from $417.1 million in 2020 and our DD&A per equivalent Mcf produced was $0.95 per Mcfe in 2021 as compared to $0.91 per Mcfe in 2020.

The increase in DD&A is primarily due to the 9% increase in natural gas production.

General and administrative expenses.

General and administrative expense, which is reported net of overhead reimbursements, increased to $32.0 million in 2020 from $29.2 million in 2019 due primarily to higher stock-based compensation and higher personnel costs.

General and administrative expense, which is reported net of overhead reimbursements, increased to $34.9 million in 2021 from $32.0 million in 2020 due primarily to higher personnel costs.

Stock-based compensation was $6.8 million and $6.5 million in 2021 and 2020, respectively.

Loss on sale of assets.

We reported a loss on the sale of assets of $162.1 million for 2021 which was primarily related to our divestiture of our Bakken shale assets.

In November 2021, we divested our assets in the Bakken shale for net proceeds of $138.1 million in cash.

Derivative financial instruments.

We use derivative financial instruments as part of our price risk management program to protect our capital investments.

We had net gains on derivative financial instruments of $51.7 million for 2019 and $10.0 million for 2020.

Realized net gains from our oil and natural gas price risk management program were $52.7 million and $134.9 million in 2019 and 2020, respectively.

Realized losses from our interest rate risk management program were none and $0.4 million in 2019 and 2020, respectively.

Unrealized loss on derivative financial instruments were $1.0 million in 2019 and $124.5 million in 2020.

We had net losses on derivative financial instruments of $560.6 million for 2021 as compared to net gains of $10.0 million for 2020.

Realized net losses from our oil and natural gas price risk management program were $419.9 million in 2021 as compared to realized net gains of $134.9 million in 2020.

Realized gains from our interest rate risk management program were $163 thousand in 2021 as compared to realized losses of $389 thousand in 2020.

Unrealized losses on derivative financial instruments were $140.9 million in 2021 and $124.5 million in 2020.

Interest expense.

Interest expense was $218.5 million for 2021 as compared to $234.8 million for 2020.

Interest expense for 2020 includes interest payments on the 7½% senior notes (the "2025 Notes") that were assumed in the Covey Park Acquisition, our 9¾% senior notes (the "2026 Notes") and our bank credit facility.

Included in interest expense was amortization of the discount on the 2025 Notes, the 2026 Notes and the debt cost amortization associated with our outstanding debt.

Included in interest expense was amortization of the discount on our senior notes and the debt cost amortization associated with our outstanding debt.

The non-cash interest expense for 2021 totaled $21.7 million compared with non-cash interest expense of $34.0 million for 2020.

The increase in interest expense was due to the issuance of an additional $800.0 million principal amount of the 2026 Notes during 2020.

The decrease in interest expense for 2021 is due primarily to the retirement of our 9.75% and 7.50% senior notes during 2021.

Loss on early retirement of debt.

We repurchased $375.0 million principal amount of our 7.50% senior notes and $1.65 billion principal amount of our 9.75% senior notes in 2021.

As a result of premiums paid over face value and costs associated with the repurchases, we recognized a loss on early retirement of debt of $352.6 million during 2021.

During 2020, we exchanged 767,096 shares of our common stock to retire $5.6 million aggregate principal amount of our 7.50% senior notes and recognized a $861 thousand loss on early retirement of debt.

Income taxes.

Income taxes were a benefit of $9.2 million in 2020 and a provision of $27.8 million in 2019.

The effective tax rate of 22% in 2019 and 15% in 2020 differed from the federal income tax rate of 21% primarily due to the impact of deferred state income taxes.

We reported a net loss available to common stockholders of $83.4 million or $0.39 per share in 2020 and net income available to common stockholders of $74.5 million or $0.52 per diluted share in 2019.

The net loss in 2020 is primarily due to the unrealized loss on derivative financial instruments of $124.5 million.

Income taxes were a provision of $11.4 million in 2021 and a benefit of $9.2 million in 2020.

The effective tax rate of -5% in 2021 and 15% in 2020 differed from the federal income tax rate of 21% primarily due to the impact of an increase to our valuation allowance on our federal and state net operating loss carryforwards and due to higher state current taxes.

We reported a net loss available to common stockholders of $259.2 million or $1.12 per diluted share in 2021 and net loss available to common stockholders of $83.4 million or $0.39 per diluted share in 2020.

The net loss in 2021 is primarily due to losses on derivative financial instruments of $560.6 million, the loss on early retirement of debt of $352.6 million and the $162.2 million loss on the Bakken shale divestiture.

Income from operations in 2021 was $900.8 million.

Year Ended December 31, 2019 Compared to 2018 Periods

Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this Annual Report on Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019 filed with the SEC on March 2, 2020.

Liquidity and Capital Resources

Funding for our activities has historically been provided by our operating cash flow, debt or equity financings or proceeds from asset sales.

In 2020, we generated $575.7 million in cash flow from operating activities as compared to $451.2 million in 2019.

We also completed a public offering of our common stock in which we received $196.5 million in net proceeds.

The proceeds from the offering were used together with cash on hand to redeem our Series A Convertible Preferred Stock for $210.0 million.

We also issued $800.0 million principal amount of our 9¾% senior notes for net proceeds of $737.1 million.

The proceeds from the senior note issuances were used to repay outstanding borrowings under our bank credit facility.

In addition in 2020, we exchanged 767,096 shares of our common stock, valued at approximately $5.0 million, to retire $5.6 million aggregate principal amount of our 7½% senior notes.

For 2019 our primary source of funds was operating cash flow and the issuance of common stock, preferred stock and borrowings to finance two acquisitions.

Our capital expenditure activity is summarized in the following table:

Predecessor Successor

January 1, 2018

August 13, 2018 Period from

August 14, 2018

December 31, 2018 Year Ended

December 31, 2019 Year Ended

December 31, 2020

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019

Discussions of 2020 items and year-to-year comparisons between 2020 and 2019 that are not included in this Annual Report on Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2020 filed with the SEC on February 17, 2021.

Cash Flows, Liquidity and Capital Resources

The following table summarizes sources and uses of cash and cash equivalents:

Year Ended December 31,

(in thousands)

Sources of cash and cash equivalents:

Operating activities $ 859,005 $ 575,701

Issuance of new senior notes 2,186,896 737,129

Proceeds from asset sales 138,394 287

Issuance of common stock — 196,380

Total $ 3,184,295 $ 1,509,497

Uses of cash and cash equivalents:

Retirement of senior notes $ (2,210,626) $ —

Capital expenditures (689,210) (509,690)

Repayments on bank credit facility, net of borrowings (265,000) (750,000)

Redemption of Series A convertible preferred stock — (210,000)

Preferred stock dividends (17,500) (25,580)

Other (1,568) (2,487)

Total $ (3,183,904) $ (1,497,757)

Cash flows from operating activities.

Net cash provided by our operating activities increased $283.3 million (49%) to $859.0 million in 2021 from $575.7 million in 2020.

The increase is primarily due to the 9% increase in our natural gas production and improved oil and natural gas prices in 2021.

Proceeds from asset sales.

In 2021, we sold our non-operated properties in the Bakken shale and certain other properties for $138.4 million after selling expenses.

The Bakken shale properties sold included non-operated interests in 442 producing wells (68.3 net) producing approximately 4,500 barrels of oil equivalent per day.

Issuance of common stock.

In 2020, we sold 41,325,000 shares of common stock in an unwritten public offering and used the net proceeds of $196.4 million to substantially fund the redemption of our Series A convertible preferred stock for $210.0 million.

Issuance of new senior notes and retirement of senior notes.

In March and June 2021, we issued $1.25 billion and $965.0 million principal amount of 6.75% senior notes due 2029 (the "2029 Notes") and 5.875% senior notes due 2030 (the "2030 notes"), respectively, in private placement offerings.

The 2029 Notes mature on March 1, 2029 and accrue interest at a rate of 6.75% per annum, payable semi-annually on March 1 and September 1 of each year.

The 2030 Notes mature on January 15, 2030 and accrue interest at a rate of 5.875% per annum, payable semi-annually on January 15 and July 15 of each year.

The proceeds from the offerings were used to repurchase $375.0 million principal amount of our 7.5% senior notes due 2025 and to repurchase $1.65 billion principal amount of our 9.75% senior notes due 2026.

The redemption of the senior notes included $171.9 million in premiums paid over face value, accrued interest of $44.2 million and $1.1 million of costs related to the offerings.

In 2020, we issued $800.0 million principal amount of our 9.75% Senior Notes due 2026 in an underwritten public offering and received net proceeds of $737.1 million.

The proceeds were used to reduce amounts outstanding under our bank credit facility.

Capital expenditures.

The increase in capital expenditures of $179.5 million is primarily due to higher drilling, completion and acquisition activities in 2021.

We spent $57.7 million in 2021 to acquire approximately 49,000 net undeveloped acres prospective for the Haynesville and Bossier shale through acquisitions or direct leasing.

In 2020, we acquired 13,519 net acres for $7.9 million.

Our capital expenditures are summarized in the following table:

Year Ended December 31,

(in thousands)

Acquisitions:

Proved property $ 21,781 $ —

Unproved property 35,871 7,949

Exploration and development:

Exploratory leasehold costs — — — 7,949

Development leasehold costs 12,953 13,022

Exploratory drilling and completion costs 6,966 —

Development drilling and completion costs 569,141 436,074

Other development costs 39,168 34,572

Change to asset retirement obligations 5,608 (47)

Total exploration and development 691,488 491,570

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Total capital expenditures $ 691,680 $ 491,970

Change in accrued capital expenditures and other 3,138 17,673

Change in asset retirement obligations (5,608) 47

Total cash capital expenditures $ 689,210 $ 509,690

We currently expect to spend approximately $750 million to $800 million in 2022 on our development and exploration projects primarily focused on the continued development of our Haynesville/Bossier shale properties, which includes $60 million to $65 million on infrastructure, workovers and other development costs.

Under our current operating plan, we expect to drill 67 operated horizontal wells (52.1 net) and to turn 69 wells (56.0 net) to sales in 2022.

The Company also expects to spend an additional $8 million to $12 million on leasing activities in 2022.

Liquidity and Capital Resources

As of December 31, 2021, we had $1.2 billion of liquidity, comprised of $1.17 billion of unused borrowing capacity under our bank credit facility and $30.7 million of cash and cash equivalents on hand.

Our short and long-term capital requirements consist primarily of funding our development and exploration activities, acquisitions, payments of contractual obligations, and debt service.

We expect to fund our future development and exploration activities with future operating cash flow.

The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments.

Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant.

Under our current operating plan, we expect to drill 62 operated horizontal wells (51.0 net), and complete an additional 19 wells (17.4 net) drilled in 2020.

We currently expect to spend approximately $517.0 million to $560.0 million in 2021 on our development and exploration projects.

We expect to fund our future development and exploration activities with future operating cash flow.

If our plans or assumptions change or our assumptions prove to be inaccurate, we may be required to seek additional capital, including additional equity or debt financings.

If our plans or assumptions change or prove to be inaccurate, we may be required to seek additional capital, including debt or equity financing.

We expect to fund future acquisitions, depending on the size and timing, with future operating cash flow, borrowings under our bank credit facility, or other debt or equity financings, to the extent available.

The availability and attractiveness of debt or equity financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, oil and natural gas prices and other market conditions.

We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.

We do not have a specific acquisition budget for 2021 because the timing and size of acquisitions are unpredictable.

We intend to use our cash flows from operations, borrowings under our bank credit facility, or other debt or equity financings to the extent available, to finance such acquisitions.

The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, oil and natural gas prices and other market conditions.

Lack of access to the debt or equity markets due to general economic conditions could impede our ability to complete acquisitions.

Our contractual obligations consist primarily of natural gas transportation and gathering contracts and drilling and completion contracts.

Our natural gas transportation and gathering contracts extend to 2031 and commitments under these contracts are $41.2 million for 2022, $41.5 million for 2023, $41.6 million for 2024, $29.8 million for 2025, $25.0 million for 2026 and $24.8 million for 2027 through 2030.

Terms of drilling contracts vary from well to well, or are for periods of less than one year.

Existing commitments under drilling contracts is $12.3 million for 2022.

In 2021, the Company entered into a well stimulation agreement that extends to 2024 for exclusive use of a natural gas powered pressure pumping fleet.

The minimum commitment under this contract is $19.2 million per year from 2022 through 2024.

As of December 31, 2021, we had $235.0 million outstanding under our bank credit facility that matures on July 16, 2024.

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Borrowings under the bank credit facility are secured by substantially all of our assets and those of our subsidiaries and bear interest at our option, at either LIBOR plus 2.25% to 3.25% or a base rate plus 1.25% to 2.25%, in each case depending on the utilization of the borrowing base.

We also pay a

commitment fee of 0.375% to 0.5% on the unused portion of the borrowing base.

We also pay a commitment fee of 0.375% to 0.5% on the unused portion of

the borrowing base.

The bank credit facility places certain restrictions upon our and our subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem the senior notes.

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We were in compliance with the covenants as of December 31, 2021.

The following table summarizes our aggregate liabilities and commitments by year of maturity:

2021 2022 2023 2024 2025 Thereafter Total

(In thousands)

Bank credit facility $ — $ — $ — $ 500,000 $ — $ — $ 500,000

7½% Senior Notes due 2025 — — — — 619,400 — 619,400

9¾% Senior Notes due 2026 — — — — — 1,650,000 1,650,000

Interest 220,630 220,630 220,630 214,534 178,296 100,547 1,155,267

Operating leases 2,682 795 196 — — — 3,673

Transportation 21,517 31,208 24,820 24,888 24,820 144,783 272,036

Drilling rigs and completion 6,031 — — — — — 6,031

$ 250,860 $ 252,633 $ 245,646 $ 739,422 $ 822,516 $ 1,895,330 $ 4,206,407

Future interest costs are based upon the effective interest rates of our outstanding senior notes and borrowings under our bank credit facility.

We also have obligations to incur future payments for dismantlement, abandonment and restoration costs of oil and gas properties which are currently estimated to be incurred primarily after 2023.

Federal and State Taxation

The Tax Cuts and Jobs Act, which was enacted on December 22, 2017, reduced the corporate income tax rate effective January l, 2018 from 35% to 21%.

Among the other significant tax law changes that potentially affect us are the elimination of the corporate alternative minimum tax ("AMT"), changes that require operating losses incurred in 2018 and beyond be carried forward indefinitely with no carryback up to 80% of taxable income in a given year, and limitations on the deduction for interest expense incurred in 2018 or later of up to 30% of its adjusted taxable income (defined as taxable income before interest and net operating losses) for the taxable year.

For the tax years beginning before January 1, 2022, the adjusted taxable income for these purposes is also adjusted to exclude the impact of depreciation, depletion and amortization.

The Tax Cuts and Jobs Act preserved deductibility of intangible drilling costs for federal income tax purposes, which allows us to deduct a portion of drilling costs in the year incurred and minimizes current taxes payable in periods of taxable income.

At December 31, 2018, we completed the accounting for the tax effects of enactment of the Tax Cuts and Jobs Act.

The Tax Cuts and Jobs Act repealed the AMT for tax years beginning on or after January 1, 2018 and provides that existing AMT credit carryforwards can be utilized to offset federal taxes for any taxable year.

Due to tax law enacted in 2020 with the Coronavirus Aid, Relief and Economic Security ("CARES") Act, we received $10.2 million in refunds for our outstanding AMT carryforwards in 2020.

At December 31, 2020, we had $0.9 billion in U.S.

At December 31, 2021, we had $906.6 million in U.S.

federal net operating loss carryforwards and $1.5 billion in certain state net operating loss carryforwards.

The shares of common stock issued as a result of the Jones Contribution triggered an ownership change under Section 382 of the Internal Revenue Code.

As a result, our ability to use net operating losses ("NOLs") to reduce taxable income is generally limited to an annual amount based on the fair market value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt interest rate.

As a result of a change of control in August 2018, our ability to use U.S.

federal net operating losses ("NOLs") to reduce taxable income is generally limited to an annual amount based on the fair market value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt interest rate.

Our NOLs are estimated to be limited to $3.3 million a year as a result of this limitation.

In addition to this limitation, IRC Section 382 provides that a corporation with a net unrealized built-in gain immediately before an ownership change may increase its limitation by the amount of built-in gain recognized during a recognition period, which is generally the five-year period immediately following an ownership change.

Based on the fair market value of our common stock immediately prior to the ownership change, we believe that we have a net unrealized built-in gain which will increase the Section 382 limitation during the five-year recognition period from 2018 to 2023.

NOLs that exceed the Section 382 limitation in any year continue to be allowed as carryforwards until they expire and can be used to offset taxable income for years within the carryover period subject to the limitation in each year.

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Therefore, we have not established any significant reserves for uncertain tax positions.

Critical Accounting Policies

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses.

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Because all reserve estimates are to some degree imprecise, the quantities and timing of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates.

Proved reserve estimates included in this report were prepared by the Company's engineers and audited by independent petroleum engineers.

The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.

Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year's estimates.

Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices.

changes in product prices.

Any future downward revisions could adversely affect our financial condition, our future prospects and the value of our common stock.

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Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes.

The projected production volumes are based on the property's proved and risk adjusted probable oil and natural gas

reserves estimates at the end of the period.

The projected production volumes are based on the property's proved and risk adjusted probable oil and natural gas reserves estimates at the end of the period.

The estimated future cash flows that we use in our assessment of the need for an impairment are based on a corporate forecast which considers forecasts from multiple independent price forecasts.

6 unchanged sentences

As a result of these changes, there may be impairments in the carrying values of our proved and unproved oil and gas properties in the future.

We have goodwill of $335.9 million as of December 31, 2020 that was recorded in connection with the Jones Contribution.

We have goodwill of $335.9 million as of December 31, 2021 that was recorded in 2018.

Goodwill represents the excess of purchase price over fair value of net tangible and identifiable intangible assets.

18 unchanged sentences

We will continue to assess the valuation allowances against deferred tax assets considering all available information obtained in future reporting periods.

Stock-based compensation.

We follow the fair value based method in accounting for equity-based compensation.

Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period.

Recent accounting pronouncements.

In January 2017, the FASB issued Accounting Standards Update No.

2017-04 (ASU 2017-04) "Intangibles-Goodwill and Other (Topic 350):

Simplifying the Test for Goodwill Impairment." ASU 2017-04 eliminates step two of the goodwill impairment test and specifies that goodwill impairment should be measured by comparing the fair value of a reporting unit with its carrying amount.

ASU 2017-04 is effective for annual or interim goodwill impairment tests performed in fiscal years beginning after December 15, 2019 and early adoption is permitted.

We implemented ASU 2017-04 during the fourth quarter of 2020 when we performed the annual goodwill impairment assessment and it did not have a significant effect on our results of operations, liquidity or financial position.

In June 2016, The FASB issued Accounting Standards Update ASU No.

2016-13 ("ASU 2016-13") that amends guidance on reporting credit losses for trade receivables, net investments in leases, debt securities, loans and certain other instruments.

ASU 2016-13 requires the use of a forward-looking expected loss model as opposed to existing incurred loss recognition.

The guidance requires a cumulative-effect adjustment to the statement of financial position as of the beginning of the first reporting period in which the standard is effective.

We implemented ASU 2016-13 during the first quarter of 2020.

We concluded there was no cumulative-effect adjustment required and the other provisions of the standard did not have a significant effect on our results of operations, liquidity or financial position.

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