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Item 7. Management’s Discussion and Analysis

2021-02-17 compared with 2020-03-02 · 123 added, 209 removed, 156 unchanged (68% 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 East Texas and North Louisiana, a premier natural gas basin with superior economics and geographic proximity to Gulf Coast markets.

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.

We own interests in 2,800 producing oil and natural gas wells (1,410.8 net to us) and we operate 1,430 of these wells.

We intend to maintain an operating plan in 2020 targeting leverage reduction and generation of free cash flow.

Our growth is driven primarily by our acquisition, development and exploration activities.

In 2019 our growth in natural gas production and proved reserves was primarily driven by the Covey Park Acquisition and our drilling activities.

We plan to spend approximately $421.0 million in 2020 for our development and exploration activities, which will be focused primarily on Haynesville and Bossier shale projects.

We own interests in 2,864 producing oil and natural gas wells (1,453.7 net) and we operate 1,480 of these wells.

We intend to maintain an operating plan in 2021 targeting 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.

Accordingly, our exploration costs consist of costs we incur to

acquire and reprocess 3-D seismic data, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.

Accordingly, our exploration costs consist of costs we incur to acquire seismic data, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.

We generally sell our oil and natural gas at current market prices at the point our wells connect to third party purchaser pipelines or terminals.

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Although in the past we have offset the effect of declining production rates from existing properties through successful acquisition and drilling efforts, there can be no assurance that we will be able to continue to offset production declines or maintain production at current rates through future acquisitions or drilling activity.

Our future growth will depend on our ability to continue to add new reserves in excess of production.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, and operating safety.

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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 $18.1 million as of December 31, 2019.

Prices for crude oil and natural gas have been highly volatile, and we are currently experiencing a period of low prices primarily due to an oversupply of natural gas.

As natural gas prices remain low, we will continue to experience lower revenues and cash flows.

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 declines.

The drilling activity level is dependent on commodity prices.

If we do not offset production declines from production from the new wells we plan to drill in 2020 and future periods, our production volumes and our cash flows from our operating activities may not be sufficient to fund our capital expenditures, and we may need to either curtail drilling activity or we may seek additional borrowings which would increase our interest expense in 2020 and in future periods.

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

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.

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

If we are unable to offset production declines resulting from the new wells we plan to drill in 2021 and future periods, our production volumes and cash flows from our operating activities may not be sufficient to fund our capital expenditures, and thus, we may need to either curtail drilling activity or seek additional borrowings, which would result in an increase in our interest expense in 2021 and future periods.

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

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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.

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

To enhance the analysis of our operating results for the periods presented, we have included a discussion of selected financial and operating data of the Predecessor and Successor on a combined basis for the year ended December 31, 2018.

This presentation consists of the mathematical addition of selected financial and operating data of the Predecessor for the period from January 1, 2018 to August 13, 2018 plus the comparable financial and operating data of the Successor for the period from August 14, 2018 to December 31, 2018.

There are no other adjustments made in the combined presentation.

The mathematical combination of selected financial and operating data is included below under the heading "Combined Year Ended December 31, 2018" and this data is a non-GAAP presentation.

Management believes that this selected financial and operating data provides investors with useful information upon which to assess our operating performance because the results of operations for a twelve-month period correspond to how we have reported our results in the past and how we will report our results in the future.

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").

In addition to the consideration paid, Comstock 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.

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.

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

Funding for the Covey Park Acquisition was provided by the sale of 50.0 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 amended and restated bank credit facility and cash on hand.

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

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

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

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

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.

Certain information to finalize the purchase price is not yet available, including the final tax return of Covey Park.

We expect to complete the purchase price allocation within the twelve month period following the acquisition date, during which time the value of the net assets and liabilities acquired may be revised as appropriate.

As of December 31, 2019, the Jones Group owned approximately 73% of our outstanding common stock and the former owners of Covey Park owned 15%.

The Jones Group and the former owners of Covey Park hold Series B and Series A Convertible Preferred Stock, respectively, that is convertible into in the aggregate of 96,250,000 shares of our common stock, if converted.

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

Year Ended December 31, 2019 Compared to 2018 Periods

Our operating data for the period January 1, 2018 through August 13, 2018 (the "2018 Predecessor Period"), the period August 14, 2018 through December 31, 2018 (the "2018 Successor Period"), the combined Predecessor and Successor 2018 periods and the year ended December 31, 2019 are summarized below:

January 1, 2018

August 14, 2018

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

Our operating data for the year ended December 31, 2019 and 2020 are summarized below:

Year Ended December 31,

Oil and Gas Sales (in thousands):

Natural gas sales $635,795 $809,399

Oil sales 132,894 48,796

Total oil and gas sales $768,689 $858,195

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

Oil sales (MMbls)

Oil sales (MBbls) 2,685 1,508

Total oil and gas (MMcfe) 308,944 459,883

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Natural gas sales $2.17 $1.80

Oil sales $49.49 $32.36

Total oil and gas sales $2.49 $1.87

Expenses ($ per Mcfe):

Production taxes

Production and ad valorem taxes $0.11 $0.08

Gathering and transportation $0.23 $0.23

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Depreciation, depletion and amortization $0.90 $0.91

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Includes ad valorem taxes.

Represents depreciation, depletion and amortization of oil and gas properties only.

The combined year ended December 31, 2018 information is a provided for comparative purposes only and is a non-GAAP presentation.

Oil and gas sales.

Oil and gas sales of $768.7 million in 2019 increased $378.4 million or 97% over the combined Predecessor and Successor Periods for 2018 oil and gas sales of $390.3 million.

The increase is due to higher production volumes that were partially offset by lower realized oil and natural gas prices in 2019.

Natural gas sales increased by $343.7 million (118%) from the combined 2018 periods due primarily to the increase in production related to the Covey Park Acquisition and our 2019 drilling activities.

The increased natural gas production was partially offset by a $0.74 per Mcf lower price realization from 2019 to 2018.

The increase in oil sales of $34.8 million was attributable to oil production from the Bakken shale properties.

Production taxes.

Production taxes of $29.2 million in 2019 increased $14.4 million or 97% from combined 2018 production taxes of $14.8 million.

This increase is primarily related to the 97% increase in oil and gas sales.

Gathering and transportation.

Gathering and transportation costs increased $49.0 million or 219% to $71.3 million in 2019 as compared to $22.4 million in the combined 2018 p eriods.

This increase primarily reflects the higher natural gas production from the acquired properties and the 2019 drilling activity .

Lease operating expenses.

Our lease operating expenses of $87.3 million in 2019 were $45.4 million or 108.4% higher than the combined 2018 periods lease operating expenses of $41.9 million.

Operating expenses from our natural gas operations was $0.22 per Mcfe in 2019 compared with $0.29 per Mcfe for the combined 2018 periods.

Operating expenses for our oil operations were $8.99 per BOE compared with $8.64 per BOE for the combined 2018 periods.

The increase is mostly attributed to higher operating costs in our Bakken shale region.

Total operating expenses of $0.28 per Mcfe in 2019 were 26% less than the $0.38 per Mcfe for the combined 2018 periods due to the increase in our natural gas production.

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

DD&A for 2019 was $276.5 million or $0.90 per Mcfe.

DD&A was $68.0 million or $1.18 per Mcfe for the 2018 Predecessor Period.

DD&A was $53.9 million or $1.01 per Mcfe for the 2018 Successor Period.

The decrease in DD&A in 2019 primarily resulted from the lower finding costs of the 2019 proved oil and gas reserve additions driven by the Covey Park Acquisition and our 2019 drilling activity.

General and administrative expenses.

General and administrative expense in 2019 of $29.2 million included $4.0 million of stock-based compensation.

General and administrative costs of $11.4 million and $15.7 million for the 2018 Successor Period and the 2018 Predecessor, respectively, included $1.0 million and $3.9 million for stock-based compensation, respectively.

The increase in 2019 is attributable to additional employees hired as part of the Covey Park Acquisition.

Derivative financial instruments.

We utilized oil and natural gas price swaps, collars, basis swaps and swaptions to manage our exposure to commodity prices and protect returns on investment from our drilling activities.

We had gains on derivative financial instruments of $51.7 million during 2019, $10.5 million during the 2018 Successor Period, and $0.9 million during the 2018 Predecessor Period.

Cash activity from derivative financial instruments included receipts of $52.7 million in 2019, $5.6 million of payments in the 2018 Successor Period and receipts of $2.8 million in the 2018 Predecessor Period.

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

January 1, 2018

August 14, 2018

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.

Our 2020 natural gas production was 450.8 billion cubic feet ("Bcf") (1.2 Bcf per day), which was sold at an average price of $1.80 per Mcf as compared to 292.8 Bcf (0.8 Bcf per day) sold at an average price of $2.17 in 2019.

Our 2020 oil production was 1.5 MMBbls (4,120 Bbls per day), which was sold at an average price of $32.36 per Bbl as compared to 2.7 MMBbls (7,356 Bbls per day) sold at an average price of $49.49 per Bbl in 2019.

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.

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

Year Ended December 31,

Average Realized Natural Gas Price:

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Price per Barrel, including cash settlements on derivative financial instruments $ 49.64 $ 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 $1.3 million (4%) to $37.0 million in 2020 from $35.7 million in 2019.

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

Gathering and transportation.

Gathering and transportation costs increased $35.3 million or 49% to $106.6 million in 2020 as compared to $71.3 million in 2019.

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.

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.

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.

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.

Stock-based compensation was $4.0 million and $6.5 million in 2019 and 2020, respectively.

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.

Interest expense.

Interest expense was $161.5 million for 2019 as compared to $43.6 million for the 2018 Successor Period and $ 101.2 million for the 2018 Predecessor Period.

Interest for 2019 includes interest payments on the 7½ % senior notes (the " 2025 Notes " ) that were assumed in the Covey Park Acq uisition, 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, which were valued at 71% of their par value in connection with the Covey Park Acquisition, the 2026 Notes, and the debt cost amortization associated with our outstanding debt.

The non-cash interest expense for 2019 totaled $16.3 million compared with non-cash interest expense of $ 2.4 million for the 2018 Successor Period and $ 29.5 million for the 2018 Predecessor Period .

Interest for the 2018 Successor Period reflects our debt refinancing transaction that closed concurrent with the Jones Contribution in which we refinanced all of our then existing debt with the issuance of $850.0 million of th e 2026 Notes and $450.0 million of borrowings under a new bank credit facility.

Interest expense was $234.8 million for 2020 as compared to $161.5 million for 2019.

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.

The non-cash interest expense for 2020 totaled $34.0 million compared with non-cash interest expense of $16.3 million for 2019.

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

Income taxes.

Income taxes were a provision of $27.8 million in 2019, a provision of $18.9 million in the 2018 Successor Period and a provision of $1.1 million in the 2018 Predecessor Period.

The effective tax rate of 22% in 2019 differed from the federal income tax rate of 21% primarily due to recognition of the effect state taxes and a tax benefit for the reduction of our valuation allowance.

The effective tax rate was 23% in the 2018 Successor Period, and a benefit of 1% for the 2018 Predecessor Period.

Income taxes for the 2018 Successor Period differed from the federal income tax rate primarily due to the effect of state taxes and a tax benefit for the reduction of our valuation allowance.

The effective tax rate for the 2018 Predecessor Period differs from the federal tax rate primarily due to a valuation allowance recognized on deferred tax assets and state taxes.

We reported net income of $96.9 million or $0.52 per diluted share in 2019, $64.1 million or $0.61 per diluted share in the 2018 Successor Period, a net loss of $92.8 million or $6.08 per share for the 2018 Predecessor Period.

The net income in the 2019 reflects higher operating profit from oil and gas operations due to the Covey Park Acquisition and our 2019 drilling activities.

The net income in the 2018 Successor Period reflects higher operating profit from oil and gas operations due to the contribution of the Bakken shale properties and lower interest expense due to our debt refinancing.

The loss in the 2018 Predecessor Period was mainly due to the high interest expense.

2018 Periods Compared to Year Ended December 31, 2017

Discussions of 2017 items and year-to-year comparisons between 2018 and 2017 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 the Company ' s Annual Report on Form 10-K for the fiscal year ended December 31, 2018 filed with the SEC on March 1, 2019.

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 from operations in 2020 was $163.0 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 and asset sales.

In 2019, our primary source of funds was operating cash flows and the issuance of common stock, preferred stock and borrowings to finance the Covey Park Acquisition.

Cash provided by operating activities in 2019 was $451.2 million compared with $188.0 million of combined operating cash flows for the 2018 periods.

The increase in operating cash flow during 2019 primarily reflects higher oil and gas sales resulting from the acquired Covey Park Acquisition and our 2019 drilling activities.

For the 2018 Successor Period our primary source of funds was operating cash flows and debt financings.

Cash provided by operating activities for the 2018 Successor Period was $102.3 million.

For the 2018 Predecessor Period our primary sources of funds was operating cash flow, proceeds from asset sales and debt financings.

Cash flow from operating activities for the 2018 Predecessor Period were $85.7 million.

The increase in operating cash flow during the 2018 Successor Period primarily reflects higher

oil and gas sal es resulting from the contributed Bakken shale properties and the growth in our natural gas production resulting from our Haynesville shale drilling activities.

For the Predecessor 2017 , our primary source of funds was operating cash flow .

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

(in thousands)

Property Acquisitions

Acquisitions $ 39,323 $ 21,013 $ 2,097,451 $ —

Exploration and development:

Exploratory leasehold costs — — — 7,949

Development leasehold costs 2,848 1,715 7,603 13,022

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Total exploration and development 146,882 185,085 2,608,018 491,570

Other 31 2 198 366

Total capital expenditures $ 146,913 $ 185,087 $ 2,608,216 $ 491,936

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

We currently expect to spend approximately $421.0 million in 2020 for development and exploration projects including drilling 46 (34.3 net to us) operated horizontal wells, completing 18 (12.6 net to us) wells drilled in 2019, and for other development projects.

Our operating cash flow and, therefore, our capital expenditures are highly dependent on oil and natural gas prices.

We operate most of the properties where we expect ongoing development and as a result have significant discretion over the amount and timing of our future capital expenditures.

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.

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.

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

In connection with the Jones Contribution, we completed a series of refinancing transactions to retire all of our other then-outstanding senior secured and unsecured notes.

On August 3, 2018, we issued $850.0 million of 2026 Notes for net proceeds of $815.9 million.

Interest on the 2026 Notes is payable on February 15 and August 15 at an annual rate of 9¾% and the 2026 Notes mature on August 15, 2026.

As a part of the Covey Park Acquisition, we assumed Covey Park's $625.0 million 7½% senior notes that were outstanding.

Interest on the assumed notes is payable on May 15 and November 15 at an annual rate of 7½% and these notes mature on May 15, 2025.

On August 14, 2018, we entered into a new bank credit facility with Bank of Montreal, as administrative agent, and the participating banks.

The bank credit facility was subject to a borrowing base of $700.0 million which was re-determined on a semi-annual basis and upon the occurrence of certain other events.

Concurrent with the closing of the Covey Park Acquisition, the bank credit facility

was amended and restated to provide for a $1.57 5 billion borrowing base which will be re-determined on a semi-annual basis and upon the occurrence of certain other events.

The maturity date was extended to July 16, 2024.

The initial committed borrowing base was set at $1,500.0 million, of which $1,2 5 0 .0 million of borrowings were outstanding as of December 31 , 2019.

The borrowing base was reaffirmed in November 2019.

As of December 31, 2020, we had $500.0 million outstanding under our bank credit facility that matures on July 16, 2024.

The borrowing base, which is currently set at $1.4 billion, is re-determined on a semi-annual basis and upon the occurrence of certain other events.

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 borrowing base.

The bank credit facility places certain restrictions upon our and our restricted 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.

The only financial covenants are the maintenance of a leverage ratio of less than 4.0 to 1.0 and a adjusted current ratio of at least 1.0 to 1.0.

The financial covenants are determined starting with the financial results for the three months ended Decemb er 31, 2019.

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.

The only financial covenants are the maintenance of a leverage ratio of less than 4.0 to 1.0 and an adjusted current ratio of at least 1.0 to 1.0.

We were in compliance with the covenants as of December 31, 2020.

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

2021 2022 2023 2024 2025 Thereafter Total

(In thousands)

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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

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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 have obligations to incur future payments for dismantlement, abandonment and restoration costs of oil and gas properties.

These payments are currently estimated to be incurred primarily after 2023.

We record a separate liability for these asset retirement obligations, which totaled $18.2 million as of December 31, 2019.

We believe that our cash on hand and cash flow from operations and available borrowings under our bank credit facility is sufficient to fund our 2020 planned drilling activities.

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 to replace any liquidity that may be lost from low oil and natural gas prices.

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 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 ye ar.

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 drill ing 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.

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.

We remeasured certain deferred federal tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%.

The amount recogniz ed related to the remeasurement of our deferred federal tax balance was $ 140.4 million in 2018 , which was subject to a valuation allowance.

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

In addition, 50% of any unused AMT credit carryforwards can be refunded during tax years 2018 through 2020.

We had $20.4 million of unused AMT credit carryforward s at December 31, 201 8, of which $10.2 million was refunded during 2019.

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.

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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.

The shares of our common stock issued in connection with the Covey Park Acquisition did not trigger another ownership change under Section 382.

As a result, no additional NOL limitations are expected.

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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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.

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Unproved properties are evaluated for impairment based upon the results of drilling, planned future drilling and the terms of our oil and gas leases.

It is reasonably possible that our estimates of undiscounted future net

cash flows attributable to its oil and gas properties may change in the future.

The primary factors that may affect estimates of futur e cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable oil and gas reserves, results of future drilling activities, future prices for oil and natural gas, and increases or decreases in producti on and capital costs.

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

It is reasonably possible that our estimates of undiscounted future net cash flows attributable to its oil and gas properties may change in the future.

The primary factors that may affect estimates of future cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable oil and gas reserves, results of future drilling activities, future prices for oil and natural gas, and increases or decreases in production and capital costs.

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.

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If the qualitative assessment indicates that it is more likely than not that our business is impaired, a quantitative analysis would be performed to assess our fair value and to determine the amount of impairment, if any, that requires recognition.

When performing a quantitative impairment assessment of goodwill, fair value is determined based on a combination of (i) recent market transactions, where available;

and (ii) projected discounted cash flows (an income approach).

Under the market approach, fair value would be estimated by a comparison to similar businesses whose securities are actively traded in the public market.

This requires our management to make certain judgments, including the selection of comparable companies, comparable recent company asset transactions, transaction premiums and selected financial metrics.

Under the income approach, fair value is based on the present value of expected future cash flows.

The income approach is dependent on a number of factors including estimates of forecasted revenues, estimates of future operating, administrative and capital costs adjusted for inflation, projected reserves quantities, the probability of success for future exploration for and development of proved and unproved reserves, discount rates and other variables.

Future cash flows are discounted using discount factors applied by us when assessing oil and gas acquisition opportunities and we believe provide a fair market value of our business.

Negative revisions of estimated reserves quantities, sustained decreases in crude oil or natural gas prices, increases in future cost estimates, or divestitures could lead to reductions in expected future cash flows that would indicate potential impairment of all or a portion of goodwill in future periods.

When performing a quantitative impairment assessment of goodwill, fair value is determined based on a market approach or an income approach.

If the carrying value of goodwill exceeds the fair value calculated using the quantitative approach, an impairment charge would be recorded for the difference between fair value and carrying value.

If oil or natural gas prices decrease, drilling efforts are unsuccessful or our market capitalization declines, it is reasonably possible that impairments would need to be recognized.

We performed our assessment of goodwill as of October 31, 2019 and determined there were no indicators of impairment.

We performed a quantitative assessment of goodwill as of October 1, 2020 and determined there was no goodwill impairment.

Income Taxes.

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The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change in rate is enacted.

In record ing deferred income tax assets, we consider whether it is more likely than not that some portion or all of our deferred income tax assets will be realized in the future.

The ultimate realization of deferred income tax assets is dependent upon the generati on of future taxable income during the periods in which those deferred income tax assets would be deductible.

We believe that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evide nce, we are not able to determine that it is more likely than not that all of our deferred tax assets will be realized.

In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of our deferred income tax assets will be realized in the future.

The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible.

We believe that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, we are not able to determine that it is more likely than not that all of our deferred tax assets will be realized.

As a result, we established valuation allowances for our deferred tax assets and U.S.

federal and state net operating loss carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods.

We will continue to assess the valuation allowance s against deferred tax assets considering all available inform ation obtained in future reporting periods.

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

Stock-based compensation.

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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 did not early adopt ASU 2017-04 and will implement ASU 2017-04 on our financial statements when we perform annual impairment assessments following adoption of this standard in 2020.

We do not expect the update to have a significant effect on our results of operations, liquidity or financial position.

In February 2016, the FASB issued ASU No.

2016-02, Leases ("ASU 2016-02").

ASU 2016-02 requires lessees to include most leases on their balance sheets, but recognize lease costs in their financial statements in a manner similar to accounting for leases prior to ASC 2016-02.

ASU 2016-02 is effective for annual periods ending after December 15, 2018 and interim periods thereafter.

We adopted ASC 2016-02 beginning January 1, 2019.

We used the modified retrospective method of adoption for this new standard and are utilizing certain practical expedients as part of our adoption.

The adoption of ASC 2016-02 did not have a significant effect on our results of operations, liquidity or financial position.

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.

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

The update is effective for us beginning in 2020.

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 are continuing to evaluate the provisions of this update, but we currently do not expect it will have a material impact on our results of operations, financial position and financial disclosures.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT M ARKET RISK

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas.

These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.

Factors influencing oil and natural gas prices include the level of global demand for oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions.

It is impossible to predict future oil and natural gas prices with any degree of certainty.

Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically.

Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities.

Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources.

Based on our oil and natural gas production in 2019 and taking into account any oil or natural gas price swap agreements we had in place, a $1.00 change in the price per barrel of oil would have resulted in a change in our cash flow for such period by approximately $2.6 million and a $0.10 change in the price per Mcf of natural gas would have changed our cash flow by approximately $20.2 million.

As of December 31, 2019, we have entered into natural gas price swap agreements to hedge approximately 138.3 Bcf of our 2020 through 2022 production at an average price of $2.81 per Mcf.

We have also entered into two-way natural gas collars to hedge approximately 16.4 Bcf of natural gas with an average floor price of $2.47 per Mcf and an average ceiling price of $3.46 per Mcf.

We also have two-way oil collars to hedge 1,262,600 barrels with an average floor price of $48.65 per barrel and an average ceiling price of $64.92 per barrel.

We have three-way collars to hedge 26.5 Bcf of natural gas with an average floor price of $2.65 per Mcf, an average ceiling price of $2.99 per Mcf and an average put price of $2.33.

We have entered into natural gas swaptions which hedge 65.8 Bcf of natural gas, with an additional 76.7 Bcf subject to option exercises, at an average price of $2.52 per Mcf.

None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.

The change in the fair value of our natural gas swaps that would result from a 10% change in commodities prices at December 31, 2019 would be $33.7 million.

Such a change in fair value could be a gain or a loss depending on whether prices increase or decrease.

Since December 31, 2019, we have entered into additional natural gas swaptions which hedge an additional 28.0 Bcf of natural gas to be produced from February 2020 to December 2021, with an additional 43.8 Bcf to be produced from January 2021 to December 2022, subject to option exercises, at an average price of $2.51 per Mcf.

Interest Rates

At December 31, 2019, we had approximately $2.7 billion principal amount of long-term debt outstanding.

The 2026 Notes of which $850.0 million was outstanding at December 31, 2019 bear interest at a fixed rate of 9¾%.

The 2025 Notes of which $625.0 million was outstanding at December 31, 2019 bear interest at a fixed rate of 7½%.

The fair market value of the 2026 Notes and 2025 Notes as of December 31, 2019 was $765.0 million and $534.4 million, respectively, based on the market price of approximately 90% and 85.5% of the face amount of such debt.

At December 31, 2019, we had $1,250 million outstanding under our bank credit facility, which is subject to variable rates of interest that are tied to LIBOR or the corporate base rate, at our option.

Any increase in these interest rates would have an adverse impact on our results of operations and cash flow.

Based on borrowings outstanding at December 31, 2019, a 100 basis point change in interest rates would change our interest expense on our variable rate debt by approximately $12.5 million.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our consolidated financial statements are included on pages F-1 to F-38 of this report.

We have prepared these financial statements in conformity with generally accepted accounting principles.

We are responsible for the fairness and reliability of the financial statements and other financial data included in this report.

In the preparation of the financial statements, it is necessary for us to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.

Our registered independent public accountants, Ernst & Young LLP, are engaged to audit our financial statements and to express an opinion thereon.

Their audit is conducted in accordance with auditing standards generally accepted in the United States to enable them to report whether the financial statements present fairly, in all material respects, our financial position and results of operations in accordance with accounting principles generally accepted in the United States.

The audit committee of our board of directors is comprised of three directors who are not our employees.

This committee meets periodically with our independent public accountants and management.

Our independent public accountants have full and free access to the audit committee to meet, with and without management being present, to discuss the results of their audits and the quality of our financial reporting.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

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