This report contains forward-looking statements that involve risks and
uncertainties that are made pursuant to the safe harbor provisions of the
Private Securities Litigation Reform Act of 1995. Actual results may differ
materially from those anticipated in our forward-looking statements due to many
factors. 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.
Results of Operations
                                                  Three Months Ended

September 30, Nine Months Ended September 30,


                                                      2021                2020                2021                 2020
Net Production Data:                                               (In thousands except per unit amounts)
Natural gas (MMcf)                                   128,896            102,560               366,272            341,823
Oil (MBbls)                                              346                354                 1,034              1,168
Natural gas equivalent (MMcfe)                       130,968            104,687               372,474            348,831
Revenues:
Natural gas sales                                 $  488,303          $ 168,374          $  1,133,783          $ 547,975
Oil sales                                             22,873              9,637                61,571             35,449
Total oil and gas sales                           $  511,176          $ 178,011          $  1,195,354          $ 583,424
Expenses:
Production and ad valorem taxes                   $   16,675          $   9,798          $     36,468          $  27,768
Gathering and transportation                      $   35,402          $  22,422          $     96,596          $  77,423
Lease operating                                   $   26,576          $  25,412          $     77,150          $  79,110
Depreciation, depletion and amortization          $  128,739          $  99,056          $    359,313          $ 312,828
Exploration                                       $        -          $       -          $          -          $      27
Average Sales Price:
Natural gas (per Mcf)                             $     3.79          $    1.64          $       3.10          $    1.60
Oil (per Bbl)                                     $    66.11          $   27.20          $      59.55          $   30.35
Average equivalent (Mcfe)                         $     3.90          $    1.70          $       3.21          $    1.67
Expenses ($ per Mcfe):
Production and ad valorem taxes                   $     0.13          $    0.09          $       0.09          $    0.08
Gathering and transportation                      $     0.27          $    0.21          $       0.26          $    0.22
Lease operating                                   $     0.20          $

0.25 $ 0.21 $ 0.23 Depreciation, depletion and amortization $ 0.98 $ 0.95 $ 0.96 $ 0.90




Revenues -
Oil and natural gas sales of $511.2 million for the third quarter of 2021
increased by $333.2 million (187%) as compared to $178.0 million for the third
quarter of 2020. The increase was primarily due to higher prices received for
our oil and natural gas production as well as higher natural gas production. Our
natural gas production for the third quarter of 2021 increased 26% to 128.9
billion cubic feet ("Bcf") (1.4 Bcf per day), and was sold at an average price
of $3.79 per Mcf as compared to 102.6 Bcf (1.1 Bcf per day) sold at an average
price of $1.64 per Mcf in the third quarter of 2020. Oil production of 346 MBbls
(3,761 Bbls per day) was sold at an average price of $66.11 per Bbl in the third
quarter of 2021 as compared to 354 MBbls (3,851 Bbls per day) sold at an average
price of $27.20 per Bbl in the third quarter of 2020.
Oil and natural gas sales of $1.2 billion increased by $611.9 million (105%) for
the nine months ended September 30, 2021 compared to $583.4 million for the nine
months ended September 30, 2020, due primarily to higher prices received for our
oil and natural gas production. Our natural gas production for the first nine
months of 2021 was 366.3 Bcf (1.3 Bcf per day), which was sold at an average
price of $3.10 per Mcf as compared to 341.8 Bcf (1.2 Bcf per day) sold at an
average price of $1.60 per Mcf in the first nine months of 2020. Oil production
of 1,034 Mbbls (3,788 Bbls per day) was sold at an average price of $59.55 per
Bbl in the first nine months of 2021 as compared to 1,168 Mbbls (4,263 Bbls per
day) sold at an average price of $30.35 per Bbl in the first nine months of
2020.
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We utilize natural gas and oil price derivative financial instruments to manage
our exposure to changes in prices of natural gas and oil 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 Three           Nine Months Ended September
                                                        Months Ended September 30,                      30,
                                                          2021               2020              2021              2020
Average Realized Natural Gas Price:
Natural gas, per Mcf                                  $     3.79          $

1.64 $ 3.10 $ 1.60 Cash settlements on derivative financial instruments, per Mcf

                                                    (0.89)         $  0.31          $   (0.38)         $  0.36
Price per Mcf, including cash settlements on
derivative financial instruments                      $     2.90          $  1.95          $    2.72          $  1.96
Average Realized Oil Price:
Oil, per Bbl                                          $    66.11          $

27.20 $ 59.55 $ 30.35 Cash settlements on derivative financial instruments, per Bbl

                                                    (7.53)            6.32              (5.31)            9.49
Price per Bbl, including cash settlements on
derivative financial instruments                      $    58.58          $

33.52 $ 54.24 $ 39.84




Costs and Expenses -
Our production and ad valorem taxes increased $6.9 million (70%) to $16.7
million for the third quarter of 2021 from $9.8 million in the third quarter of
2020. Production and ad valorem taxes increased $8.7 million (31%) to $36.5
million for the first nine months of 2021 from $27.8 million in the first nine
months of 2020. The increase was primarily related to the higher oil and natural
gas prices in 2021.
Gathering and transportation costs for the third quarter of 2021 increased $13.0
million (58%) to $35.4 million as compared to $22.4 million in the third quarter
of 2020. Gathering and transportation costs for the first nine months of 2021
increased $19.2 million (25%) to $96.6 million as compared to $77.4 million for
the first nine months of 2020. The increase is due primarily to higher average
rates and higher production in the third quarter and the first nine months of
2021.
Our lease operating expense of $26.6 million ($0.20 per Mcfe) for the third
quarter of 2021 increased $1.2 million (5%) from lease operating expense of
$25.4 million ($0.25 per Mcfe) for the third quarter of 2020. Our lease
operating expense of $77.2 million ($0.21 per Mcfe) for the first nine months of
2021 decreased $2.0 million (2%) from lease operating expense of $79.1 million
($0.23 per Mcfe) for the first nine months of 2020. The decrease in average per
unit cost is related to the growth in our lower cost natural gas production.
Depreciation, depletion and amortization ("DD&A") increased $29.7 million (30%)
to $128.7 million in the third quarter of 2021 from $99.1 million in the third
quarter of 2020 due to higher production and an increase in the average rate.
Our DD&A per equivalent Mcf produced increased $0.03 (3%) to $0.98 per Mcfe for
the three months ended September 30, 2021 from $0.95 per Mcfe for the three
months ended September 30, 2020. DD&A increased $46.5 million (15%) to $359.3
million in the first nine months of 2021 from $312.8 million in the first nine
months of 2020. Our DD&A per equivalent Mcf produced increased $0.06 (7%) to
$0.96 per Mcfe for the first nine months of 2021 from $0.90 per Mcfe for the
first nine months of 2020.
General and administrative expenses, which are reported net of overhead
reimbursements, decreased to $8.1 million for the third quarter of 2021 as
compared to $9.0 million in the third quarter of 2020. General and
administrative expenses decreased to $24.0 million for the first nine months of
2021 from $26.0 million in the first nine months of 2020. The decreases
primarily resulted from higher overhead reimbursements that we received in 2021.
We use derivative financial instruments as part of our price risk management
program to protect our capital investments. During the quarter ended
September 30, 2021, we had substantial losses related to our derivative
financial instruments of $510.3 million, as compared to net losses on derivative
financial instruments of $121.6 million during the quarter ended September 30,
2020. Realized net losses from our oil and natural gas price risk management
program were $117.1 million for the quarter ended September 30, 2020 as compared
to realized net gains of $34.2 million for the quarter ended September 30, 2021.
During the nine months ended September 30, 2021, we had total net losses on
derivative financial instruments of $756.0 million, as compared to net losses on
derivative financial instruments of $72.0 million during the the first nine
months of 2020. Realized net losses from our oil and natural gas price risk
management program were $144.4 million and net gains of $132.9 million for the
nine months ended September 30, 2021 and 2020, respectively.
Interest expense was $50.0 million and $63.9 million for the quarter ended
September 30, 2021 and 2020, respectively. The 22% decrease in interest expense
is due primarily to the retirement of our 9.75% and 7.50% senior notes
                                       21
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during the first six months of 2021. Interest expense was $170.6 million and
$168.8 million for the nine months ended September 30, 2021 and 2020,
respectively.
Income taxes for the quarter ended September 30, 2021 and 2020 were a provision
of $24.0 million and a benefit of $46.1 million, respectively. Income taxes for
the nine months ended September 30, 2021 and 2020 were a benefit of $74.2
million and $46.2 million, respectively. The provision and benefit for income
taxes for the three months and nine months ended September 30, 2021 reflect an
effective tax rate of (9.1)% and 11.0%, respectively. The income tax provision
for the three months ended September 30, 2021 is attributable to revisions to
the estimated future utilization of federal and state net operating loss
carryforwards resulting from the loss from derivative financial instruments that
was recognized in the period. 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. The difference between the federal statutory rate of
21% and our effective rate is primarily due to the increased valuation
allowances discussed above and the impact of state income taxes.
We reported net loss available to common stockholders of $292.7 million or $1.26
per share, for the quarter ended September 30, 2021 which was caused by the
$510.3 million net loss from derivative financial instruments. Income from
operations for the third quarter of 2021 was $295.7 million and we had interest
expense of $50.0 million and $4.4 million in preferred stock dividends. 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. In the first nine
months of 2021, we reported net loss available to common stockholders of $615.2
million or $2.66 per share. Our income from operations for the first nine months
of 2021 was $602.0 million, which was offset by losses on derivative financial
instruments of $756.0 million, $352.6 million in losses on early retirement of
debt and interest expense of $170.6 million. We reported net loss of $160.9
million or $0.77 per share for the nine months ended September 30, 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, 2021, we generated $618.6 million in cash flow from
operating activities as compared to $390.0 million in cash flow from operating
activities for the nine months ended September 30, 2020.
The following table summarizes our capital expenditure activity:
                                                                 Nine Months Ended September 30,
                                                                   2021                    2020
                                                                         (In thousands)

Exploration and development:
Exploratory leasehold costs                                 $         18,649          $      1,457
Development leasehold costs                                            6,794                 7,363
Development drilling and completion costs                            454,524               280,383
Other development costs                                               28,455                26,463
Total capital expenditures                                  $

508,422 $ 315,666




We drilled 81 (46.9 net) wells and completed 68 (47.2 net) Haynesville shale
wells during the first nine months of 2021. We expect to spend an additional
$115 million to $135 million in the remaining three months of 2021 to drill 9
(7.4 net) additional wells, to complete 10 (8.8 net) wells and for other
development activity. We expect to fund our future development and exploration
activities with future operating cash flow. The timing of most of our future
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. 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
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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 our 6.75% senior
notes due in 2029 (the "2029 Notes") in a private placement and received net
proceeds after offering costs of $1.24 billion, which were used to repurchase a
portion of our 7.5% senior notes due in 2025 (the "2025 Notes") and 9.75% senior
notes due in 2026 (the "2026 Notes") pursuant to a tender offer. 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.
Pursuant to the tender offer, we repurchased $375.0 million principal amount of
the 2025 Notes and $777.1 million principal amount of the 2026 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.
On June 28, 2021, we issued $965.0 million principal amount of our 5.875% senior
notes due in 2030 (the "2030 Notes") in a private placement and received net
proceeds after offering costs of $949.5 million, which were used along with cash
on hand to redeem all outstanding 2026 Notes. 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.
On June 29, 2021, we completed the redemption of all outstanding 2026 Notes for
$978.6 million, which included premiums paid over face value of $74.0 million
and accrued interest of $31.7 million. As a result of the early retirement of
the senior notes repurchased in the tender offer and the redemption of the 2026
Notes, we recognized a loss of $352.6 million on early retirement of debt for
the nine months ended September 30, 2021.
At September 30, 2021, we had $425.0 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 October
22, 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. We also pay a
commitment fee of 0.375% to 0.50% 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
September 30, 2021.
In April 2021, we 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.
On October 6, 2021, we entered into an agreement to sell certain wells producing
from the Bakken shale for $154 million in cash, subject to adjustment and
customary closing conditions. The sale is expected to close in the fourth
quarter of 2021 and has an effective date of October 1, 2021.
Income Taxes
At September 30, 2021, we had $960.3 million 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 by $117.0 million.
Effective June 30, 2021, Louisiana state tax law was amended to provide that all
NOL deductions claimed on any corporate income tax return filed on or after
January 1, 2022 for NOLs relating to loss years on or after January 1, 2001 may
be carried forward indefinitely until such losses are fully recovered, subject
to other limitations.
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. NOLs
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incurred prior to 2018 generally have a 20-year life until they expire. NOLs
generated in 2018 and after would be carried forward indefinitely. Our use of
new NOLs arising after the date of an ownership change would not be affected by
the 382 limitation. 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 $775.2 million of the U.S. federal NOL carryforwards and $1.2
billion of the estimated state NOL carryforwards will expire unused.

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