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Item 2. Management’s Discussion and Analysis

2021-05-06 compared with 2020-11-05 · 51 added, 92 removed, 72 unchanged (67% of the section changed)

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The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this report and in our annual report filed on Form 10-K for the year ended December 31, 2020.

In December 2019, a novel strain of coronavirus (SARS-CoV-2), which causes COVID-19, was reported to have surfaced in China.

The spread of this virus has caused business disruption beginning in January 2020, including disruption to the oil and natural gas industry.

In March 2020, the World Health Organization declared the outbreak of COVID-19 to be a pandemic, and the U.S.

economy began to experience pronounced effects.

The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and natural gas, and created significant volatility and disruption of financial and commodity markets.

The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives, is uncertain and depends on various factors, including the future demand for oil and natural gas, the availability of personnel, equipment and services critical to our ability to operate and develop our properties and the impact of potential governmental restrictions on travel, transports and operations.

Our natural gas operations, which are primarily in the Haynesville shale in North Louisiana and East Texas, have not been adversely affected so far in 2020.

Our non-operated oil operations have been substantially impacted by low oil prices.

Results of Operations

Three Months Ended

September 30, Nine Months Ended

September 30,

2020 2019 2020 2019

Three Months Ended March 31,

Net Production Data:

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113,293 122,786

354 603 1,168 2,108

Oil (MBbls) 326 454

Natural gas equivalent (MMcfe)

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$ 109,128 $ 110,425

$ — $ 241 $ 27 $ 241

Average Sales Price:

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$ 0.95 $ 0.88

Oil and natural gas sales of $178.0 million de creased by $46.4 million (21%) in the third quarter of 2020 as compared to $224.4 million for the third quarter of 2019 primarily due to lower oil and natural gas prices.

Our natural gas production for the third quarter of 2020 was 102.6 billion cubic feet ("Bcf"), which was sold at an average price of $1.64 per Mcf as compared to 97.2 Bcf sold at an average price of $1.99 per Mcf in the third quarter of 2019.

Oil production of 354 Mbbls (3,851 barrels per day) was sold at an average price of $27.20 per barrel in the third quarter of 2020 as compared to 603 Mbbls (6,563 barrels per day) sold at an average price of $51.24 per barrel in the third quarter of 2019.

Oil and natural gas sales of $583.4 million in creased by $104.0 million (22%) in the nine months ended September 30, 2020 as compared to $479.4 million for the nine months ended September 30, 2019.

Our natural gas production for the first nine months of 2020 was 341.8 Bcf, which was sold at an average price of $1.60 per Mcf as compared to 171.3 Bcf sold at an average price of $2.19 per Mcf in the first nine months of 2019.

Oil production of 1,168 Mbbls (4,263 barrels per day) was sold at an average price of $30.35 per barrel in the first nine months of 2020 as compared to 2,108 Mbbls (7,723 barrels per day) sold at an average price of $49.26 per barrel in the first nine months of 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.

Oil and natural gas sales of $340.5 million increased by $114.6 million (51%) in the first quarter of 2021 as compared to $225.9 million for the first quarter of 2020, which increase was primarily due to higher prices received for our oil and natural gas production.

Our natural gas production for the first quarter of 2021 was 113.3 billion cubic feet ("Bcf") (1.3 Bcf per day), which was sold at an average price of $2.86 per Mcf as compared to 122.8 Bcf (1.3 Bcf per day) sold at an average price of $1.69 per Mcf in the first quarter of 2020.

Oil production of 326 MBbls (3,617 Bbls per day) was sold at an average price of $50.69 per Bbl in the first quarter of 2021 as compared to 454 MBbls (4,994 Bbls per day) sold at an average price of $41.01 per Bbl in the first quarter of 2020.

We utilize natural gas and oil price derivative financial instruments to manage our exposure to changes in natural gas and oil prices and to 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:

Three Months Ended

September 30, Nine Months Ended

September 30,

2020 2019 2020 2019

Three Months Ended March 31,

Average Realized Natural Gas Price:

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Average Realized Oil Price:

Oil per Barrel $ 27.20 $ 51.24 $ 30.35 $ 49.26

Cash settlements on derivative financial instruments, per Barrel 6.32 0.03 9.49 0.18

Price per Barrel, including cash settlements on derivative financial instruments $ 33.52 $ 51.27 $ 39.84 $ 49.44

Oil, per Bbl $ 50.69 $ 41.01

Cash settlements on derivative financial instruments, per Bbl $ (2.82) $ 5.30

Price per Bbl, including cash settlements on derivative financial instruments $ 47.87 $ 46.31

Costs and Expenses –

Our production and ad valorem taxes in creased $0.4 million (4%) to $9.8 million for the third quarter of 2020 from $9.4 million in the third quarter of 2019.

Production and ad valorem taxes increased $5.1 million (22%) to $27.8 million for the first nine months of 2020 from $22.7 million in the first nine months of 2019.

The increases were primarily due to the increase in production in the periods.

Gathering and transportation costs for the third quarter of 2020 de creased $1.0 million (4%) to $22.4 million as compared to $23.4 million in the third quarter of 2019 due primarily to lower gathering and transportation rates on the Company's natural gas production.

Gathering and transportation costs for the first nine months of 2020 in creased $36.1 million (87%) to $77.4 million as compared to $41.3 million for the first nine months of 2019 due primarily to the in crease in our natural gas production resulting from our drilling activities and the 2019 acquisition of Covey Park Energy.

Our lease operating expense of $25.4 million for the third quarter of 2020 decreased $1.3 million (5%) from lease operating expense of $26.7 million for the third quarter of 2019.

This de crease relates to the decrease in our higher cost oil production in the third quarter of 2020.

Our lease operating expense of $79.1 million for the first nine months of 2020 increased $24.6 million (45%) from lease operating expense of $54.5 million for the first nine months of 2019.

Production in the same period increased 90% due to the Covey Park Energy acquisition.

Our lease operating expense of $0.23 per Mcfe produced for the first nine months of 2020 was $0.07 per Mcfe lower than the lease operating expense of $0.30 per Mcfe for the same period 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 ("DD&A") increased $18.8 million (23%) to $99.1 million in the third quarter of 2020 from $80.2 million in the third quarter of 2019.

Our DD&A per equivalent Mcf produced increased $0.15 (19%) to $0.95 per Mcfe for the three months ended September 30, 2020 from $0.80 per Mcfe for the three months ended

September 30, 2019.

DD&A increased $148.1 million (90%) to $312.8 million in the first nine months of 2020 from $164.7 million in the first nine months of 2019 due to the 90% increase in production in that period.

Our DD&A per equivalent Mcf produced was $0.90 per Mcfe for the first nine months of 2020, the same as the rate for the first nine months of 2019.

General and administrative expenses, which are reported net of overhead reimbursements, increased to $9.0 million for the third quarter of 2020 from $8.1 million in the third quarter of 2019 due primarily to higher stock-based compensation.

Stock-based compensation was $1.8 million and $1.1 million for the three months ended September 30, 2020 and 2019, respectively.

General and administrative expenses increased to $26.0 million for the first nine months of 2020 from $22.8 million in the first nine months of 2019 also mainly due to higher stock-based compensation and higher personnel costs.

Stock-based compensation was $4.7 million and $2.4 million for the nine months ended September 30, 2020 and 2019, respectively.

Our production and ad valorem taxes in creased $1.3 million (15%) to $9.7 million for the first quarter of 2021 from $8.4 million in the first quarter of 2020.

The increase was primarily due to higher oil and natural gas prices in 2021.

Gathering and transportation costs for the first quarter of 2021 increased $1.0 million (4%) to $29.5 million as compared to $28.4 million in the first quarter of 2020 due primarily to higher gathering and transportation rates on our natural gas production.

Our lease operating expense of $24.6 million for the first quarter of 2021 decreased $1.3 million (5%) from lease operating expense of $25.9 million for the first quarter of 2020.

This decrease relates to lower oil and natural gas production in the first quarter of 2021.

Depreciation, depletion and amortization ("DD&A") decreased $1.3 million (1%) to $109.1 million in the first quarter of 2021 from $110.4 million in the first quarter of 2020.

Our DD&A per equivalent Mcf produced increased $0.07 (8%) to $0.95 per Mcfe for the three months ended March 31, 2021 from $0.88 per Mcfe for the three months ended March 31, 2020.

General and administrative expenses, which are reported net of overhead reimbursements, decreased to $8.0 million for the first quarter of 2021 from $8.7 million in the first quarter of 2020.

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

During the three months ended September 30, 2020 and 2019, we had net losses on derivatives of $121.6 million and net gains on derivatives of $24.9 million, respectively.

The losses in the third quarter of 2020 are attributable to the continued improvement in future natural gas prices since June 30, 2020.

Our realized net gains from our price risk management program were $34.0 million and $26.0 million for the three months ended September 30, 2020 and 2019, respectively.

During the nine months ended September 30, 2020 and 2019, we had a net loss on derivatives of $72.0 million and and net gain on derivatives of $31.9 million, respectively.

Our realized net gains from our price risk management program were $132.7 million and $33.4 million for the nine months ended September 30, 2020 and 2019, respectively.

Interest expense was $63.9 million and $168.8 million for the three and nine months ended September 30, 2020, respectively, as compared to $51.0 million and $107.4 million for the three and nine months ended September 30, 2019, respectively.

During the three months ended March 31, 2021, we had net losses on derivative financial instruments of $21.7 million, as compared to net gains on derivative financial instruments of $61.9 million during the three months ended March 31, 2020.

Realized net losses from our oil and natural gas price risk management program were $8.4 million for the three months ended March 31, 2021 as compared to realized net gains of $45.4 million for the three months ended March 31, 2020.

Realized losses from our interest rate risk management program were $269 thousand for the three months ended March 31, 2021.

Interest expense was $63.8 million and $52.8 million for the three ended March 31, 2021 and 2020, respectively.

The increase in interest expense is due to the issuance of $800.0 million principal amount of 9.75% senior notes in the second and third quarters of 2020.

Income taxes for the three months ended September 30, 2020 and 2019 were a benefit of $46.1 million and a provision of $3.8 million, respectively.

Income taxes for the nine months ended September 30, 2020 and 2019 were a benefit of $46.2 million and a provision of $15.2 million, respectively.

The benefit for income taxes for the three months and nine months ended September 30, 2020 reflect an effective tax rate of 26.7% and 25.6%, respectively.

Income taxes for the three months ended March 31, 2021 and 2020 were a benefit of $30.0 million and a provision of $11.4 million, respectively.

The benefit and provision for income taxes for the three months ended March 31, 2021 and 2020 reflect an effective tax rate of 18.3% and 21.3%, respectively.

The difference between the federal statutory rate of 21% and our effective rate is primarily due to the impact of state income taxes.

We reported net loss available to common stockholders of $130.9 million or $0.57 per share, for the three months ended September 30, 2020.

Our net loss during this period includes income from operations of $12.4 million, $121.6 million in losses from derivative financial instruments, interest expense of $63.9 million and $4.4 million in preferred stock dividends.

We reported net loss available to common stockholders of $1.3 million or $0.01 per diluted share for the three months ended September 30, 2019.

In the first nine months of 2020, we reported net loss available to common stockholders of $160.9 million or $0.77 per share.

Our net loss during this period includes income from operations of $60.3 million and losses on derivative financial instruments of $72.0 million, interest expense of $168.8 million and $26.6 million in preferred stock dividends.

We reported net income available to common stockholders of $33.6 million or $0.26 per diluted share for the nine months ended September 30, 2019.

We reported net loss available to common stockholders of $138.4 million or $0.60 per share, for the three months ended March 31, 2021 primarily due to the $238.5 million pre-tax loss on early retirement of our 7.50% senior notes and 9.75% senior notes.

Income from operations was $159.7 million and we had $21.7 million in losses from derivative financial instruments, interest expense of $63.8 million and $4.3 million in preferred stock dividends.

We reported net income available to common stockholders of $30.0 million or $0.15 per diluted share for the three months ended March 31, 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.

For the nine months ended September 30, 2020, we generated $390.0 million in cash flow from operating activities.

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

The proceeds were used toward the redemption of our Series A Convertible Preferred Stock.

We also issued $800.0 million principal amount of our 9¾% senior notes in which we received net proceeds of $737.5 million.

The proceeds were used to repay outstanding borrowings under our bank credit facility.

For the nine months ended September 30, 2019, our primary source of funds were cash provided by operating activities of $282.8 million.

In the nine months ended September 30, 2020, we incurred capital expenditures of $315.7 million to fund our development and exploration activities.

For the three months ended March 31, 2021, we generated $193.3 million in cash flow from operating activities as compared to $150.1 million in cash flow from operating activities for the three months ended March 31, 2020.

The following table summarizes our capital expenditure activity:

Nine Months Ended

September 30,

Three Months Ended March 31,

(In thousands)

Property acquisitions $ — $ 2,055,623

Exploration and development:

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$ 168,851 $ 130,500

We drilled 54 (29.8 net) wells and completed 51 (27.1 net) Haynesville shale wells during the first nine months of 2020.

We expect to spend an additional $150.0 to $170.0 million in the remaining three months of 2020 to drill 17 (16.4 net) additional wells, to complete 22 (17.6 net) wells and for other development activity.

We drilled 25 (19.6 net) wells and completed 14 (9.5 net) Haynesville shale wells during the first three months of 2021.

We expect to spend an additional $350 million to $390 million in the remaining nine months of 2021 to drill 46 (37 net) additional wells, to complete 45 (40 net) wells and for other development activity.

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

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

As of September 30, 2020, we had six drilling rigs with minimum contractual payments of $5.2 million.

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.

In April and May 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.

As a result, we recognized a $0.9 million loss on early extinguishment of debt for the three and nine months ended September 30, 2020.

On June 23, 2020, we issued $500.0 million principal amount of our 9¾% Senior Notes due 2026 and received net proceeds of $441.1 million.

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

On August 19, 2020, we issued an additional $300.0 million principal amount of the 9¾% Senior Notes due 2026 and received net proceeds of $296.4 million.

The proceeds were used to further repay borrowings under our bank credit facility.

At September 30, 2020, we had $500.0 million outstanding under our bank credit facility with a $1.4 billion committed borrowing base which is re-determined on a semi-annual basis and upon the occurrence of certain other events which matures on July 16, 2024.

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.

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.

On March 4, 2021, we issued $1.25 billion principal amount of 6.75% senior notes due 2029 in a private placement and received net proceeds after offering costs of $1.24 billion, which were used to repurchase a portion of our 7.50% senior notes due 2025 and 9.75% senior notes due 2026 pursuant to a tender offer.

The new senior 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.

Under the tender offer, we repurchased $375 million principal amount of our 7.50% senior notes and $777.1 million principal amount of our 9.75% senior notes for an aggregate amount of $1.26 billion, which included premiums paid over face value of $97.9 million, accrued interest of $12.5 million and $1.1 million of costs related to the tender offer.

As a result of the early retirement of the senior notes repurchased in the tender offer, we recognized a $238.5 million loss on early retirement of debt in the three months ended March 31, 2021.

At March 31, 2021, we had $550.0 million outstanding under our bank credit facility with a $1.4 billion committed borrowing base, which is re-determined on a semi-annual basis and upon the occurrence of certain other events, and matures on July 16, 2024.

The borrowing base was redetermined at $1.4 billion on April 16, 2021.

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.

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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 September 30, 2020.

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

Federal Taxation

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 with the Coronavirus Aid, Relief and Economic Security ("CARES") Act, we received a $10.2 million refund for our outstanding AMT carryforwards in the third quarter of this year.

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.

Our NOLs are estimated to be limited to $3.3 million a year as a

result of this limitation.

At March 31, 2021, we had $1.0 billion in U.S.

federal net operating loss ("NOL") carryforwards and $1.5 billion in certain state NOL carryforwards.

As a result of the change of control in August 2018, our ability to use 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 recognized 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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If we do not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carryforward periods, then we will lose the ability to apply those NOLs as offsets to future taxable income.

We estimate that $822.3 million of the U.S.

federal NOL carryforwards and $1.4 billion of the estimated state NOL carrforwards will expire unused.

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-Q

Item 2. Management’s Discussion and Analysis