CIMAREX ENERGY: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL POSITION AND OPERATING RESULTS (Form 10-Q)

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PREVIEW

Cimarex is an independent oil and gas exploration and production company. Our
operations are located entirely within the United States, mainly in Texas, New
Mexico, and Oklahoma. Currently our operations are focused in two main areas:
the Permian Basin and the Mid-Continent. Our Permian Basin region encompasses
west Texas and southeast New Mexico. Our Mid-Continent region encompasses
Oklahoma and the Texas Panhandle.

Our principal business objective is to increase shareholder value through the
profitable growth of our proved reserves and production while seeking to
minimize our impact on the communities in which we operate for the long-term.
Our strategy centers on maximizing cash flow from producing properties for
reinvestment in exploration and development activities and for providing cash
returns to shareholders through dividends and debt reduction. We consider merger
and acquisition opportunities that enhance our competitive position and we
occasionally divest non-core assets, such as our divestitures during the three
months ended June 30, 2021 of non-core oil and gas properties and related assets
in West Texas and Southern Oklahoma for which we received $111.0 million in net
cash proceeds.

We believe that detailed technical analysis, operational focus, and a
disciplined capital investment process mitigates risk and positions us to
continue to achieve profitable increases in proved reserves and production. Our
drilling inventory and limited long-term commitments provide the flexibility to
respond quickly to industry volatility. Our investments are generally funded
with cash flow provided by operating activities together with cash on hand, bank
borrowings, sales of non-core assets, and, from time to time, public financing
based on our monitoring of capital markets and our balance sheet.

Merger

On May 23, 2021, Cimarex entered into an Agreement and Plan of Merger (the
"Merger Agreement") with Cabot Oil & Gas Corporation ("Cabot") and Double C
Merger Sub, Inc., a wholly-owned subsidiary of Cabot ("Merger Sub"). The Merger
Agreement provides that, among other things and subject to the terms and
conditions of the Merger Agreement: (i) Merger Sub will be merged with and into
Cimarex (the "Merger"), with Cimarex surviving and continuing as a wholly-owned
subsidiary of Cabot in the Merger, and (ii) at the effective time of the Merger,
each outstanding share of common stock of Cimarex (other than certain Excluded
Shares, Converted Shares, or shares of Cimarex common stock subject to a Cimarex
Restricted Share Award (each as defined in the Merger Agreement)) will be
converted into the right to receive 4.0146 shares of common stock of Cabot.
Following the closing of the Merger, Cimarex's existing stockholders and Cabot's
existing stockholders will own approximately 50.5% and 49.5%, respectively, of
the issued and outstanding shares of the combined company. The transaction is
expected to close in the fourth quarter of 2021, subject to the approval of
Cimarex and Cabot stockholders and the satisfaction of other customary closing
conditions.

Market Conditions

The oil and gas industry is cyclical, and commodity prices can fluctuate widely. We expect this volatility to persist. Commodity prices are affected by many factors beyond our control, including changes in market supply and demand, inventory storage levels, weather conditions and other factors. Local market prices for oil and gas can be affected by pipeline capacity constraints that limit offtakes and increase base spreads.

In the first quarter of 2020, the highly transmissible and pathogenic
coronavirus known as severe acute respiratory syndrome coronavirus 2
(SARS-CoV-2) that causes the disease known as COVID-19 began to spread globally.
The reduction in economic activity from the COVID-19 pandemic resulted in
unprecedented demand destruction and inventory increases for oil and natural gas
liquids. In addition, in early March 2020, members of the Organization of the
Petroleum Exporting Countries ("OPEC") and Russia failed to reach an agreement
on oil production limits and Saudi Arabia unilaterally reduced the sales price
of its oil and announced that it would
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increase its oil production. As a result of these actions and the COVID-19
pandemic, WTI oil prices dropped and even became negative for a brief time in
April 2020. Oil prices have improved since then, coinciding with some recovery
of global economic activity, lower supply from major oil producing countries,
and moderating inventory levels. However, while COVID-19 vaccines have become
more widely available, variants of the virus that causes COVID-19 continue to
cause concerns that the demand recovery for oil and natural gas liquids could
stall. Additionally, OPEC has recently agreed to increase production beginning
in August 2021, which could lead to lower oil prices as supply increases.

Our average realized price for oil during the six months ended June 30, 2021
improved to $60.12 per barrel, increasing 84% over our average realized price
for oil during the six months ended June 30, 2020. In February 2021, Texas and
Oklahoma experienced an extreme winter weather event that included freezing
rain, sleet, snow, and freezing temperatures over an extended period. This event
caused gas demand to exceed gas supply as demand increased while supplies were
simultaneously curtailed by power outages, frozen equipment, impassable roads,
and other impacts of the severe weather, significantly increasing gas prices.
Our average realized price for gas during the six months ended June 30, 2021 was
$3.30 per Mcf, increasing 358% over our average realized price for gas during
the six months ended June 30, 2020.

The table below shows the average NYMEX prices and our company-wide average realized prices and price spreads for the periods shown.

                                                   Three Months Ended                                                Six Months Ended
                                                        June 30,                      Variance Between                   June 30,                   Variance Between
                                                  2021                2020              2021 / 2020                2021              2020             2021 / 2020
Average NYMEX price
Oil - per barrel                            $    66.07             $ 27.85                  137%               $   61.96          $ 37.01                 67%
Gas - per Mcf                               $     2.80             $  1.71                  64%                $    2.76          $  1.83                 51%

Average realized price
Oil - per barrel                            $    64.11             $ 19.57                  228%               $   60.12          $ 32.74                 84%
Gas - per Mcf                               $     2.51             $  0.91                  176%               $    3.30          $  0.72                 358%
NGL - per barrel                            $    23.16             $  7.52                  208%               $   22.83          $  8.71                 162%

Average price differential
Oil - per barrel                            $    (1.96)            $ (8.28)                 76%                $   (1.84)         $ (4.27)                57%
Gas - per Mcf                               $    (0.29)            $ (0.80)                 64%                $    0.54          $ (1.11)                149%



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The average price differentials that we realized in our two primary areas of
operation are shown in the table below for the periods indicated.
                                                  Average Price Differentials
                                2021                                         2020
                                                           Second        First                    Fourth        Third       Second        First
                      Year-to-date                         Quarter     

Quarter Year Quarter Quarter Quarter Quarter of the Permian Oil Basin $ (1.81)

                       $ (1.91)     $ 

(2.00) $ (3.74) $ (2.79) $ (2.71) $ (8.12) $ (2.00)
Mid-Continent $ (1.96)

                       $ (2.11)     $ 

(1.96) $ (4.43) $ (0.99) $ (5.06) $ (9.53) $ (2.02)
Total company $ (1.84)

                       $ (1.96)     $ 

(1.99) $ (3.81) $ (2.57) $ (2.99) $ (8.28) $ (1.99)

Gas

Permian Basin        $        0.39                        $ (0.44)     $  

1.29 $ (1.39) $ (1.34) $ (1.15) $ (1.09) $ (1.85)
Mid-Continent $ 0.82

                        $ (0.02)     $  

1.69 $ (0.41) $ (0.36) $ (0.31) $ (0.31) (0.57) $
Total company $ 0.54

                        $ (0.29)     $  

1.43 $ (1.03) $ (0.98) $ (0.84) $ (0.80) $ (1.40)



Pipeline expansion projects in the Permian Basin and reduced drilling activity
and production have eased take away constraints and improved price differentials
over prior year. However, if pipeline projects are delayed, production increases
faster than capacity increases, or the basin experiences pipeline disruptions or
other constraints, differentials could potentially worsen. Our revenue,
profitability, and future growth are highly dependent on the prices we receive
for our oil and gas production and can be adversely affected by realized price
decreases.

See RISK FACTORS in Item 1A of this Form 10-Q and in our Annual Report on Form
10-K for the year ended December 31, 2020, for a discussion of risk factors that
affect our business, financial condition, and results of operations. Also, see
CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS in this report for
important information about these types of statements.

Summary of operational and financial results for the closed semester June 30, 2021 Compared to the six months ended June 30, 2020:

• Total production volumes decreased 14% to 228.4 MBEP per day.

• Oil volumes decreased 16% to 70.7 MBbls per day.

• Gas volumes decreased by 15% to 572.2 MMcf per day.

• NGL volumes decreased 10% to 62.4MB per day.

• Total production turnover increased by 96% to reach $ 1.369 billion.

• Cash flow from operating activities increased by 69% to reach $ 766.6 million.

• Investments in exploration and development increased by 8% to $ 357.8 million.

• The net income was $ 241.5 million, or $ 2.35 per diluted share, for the first six months of 2021, compared to a net loss of $ 1.699 billion, or $ 17.05 per diluted share, for the first six months of 2020.

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RESULTS OF OPERATIONS

Three and six months over June 30, 2021 Compared to the three and six months ended
June 30, 2020

Revenues

Our revenues are derived from sales of our oil, gas, and NGL
production. Increases or decreases in our revenues, profitability, and future
production growth are highly dependent on the commodity prices we
receive. Prices are market driven and we expect that future prices will continue
to fluctuate due to supply and demand factors, availability of transportation,
seasonality, and geopolitical, economic, and other factors.

Production volumes were lower and realized prices were higher for all products
during the three and six months ended June 30, 2021 as compared to the three and
six months ended June 30, 2020. The decrease in production volumes is primarily
due to deliberate and immediate action that we took to reduce our drilling and
completion activity subsequent to the first quarter 2020 in response to the
unprecedented demand destruction and severe oil price decreases caused by the
COVID-19 pandemic and OPEC and other countries' actions. We have since increased
our drilling and completion activity, but have adjusted our capital reinvestment
rates to stay below operating cash flow. Although prices remain volatile, they
have improved over the levels seen in the first six months of 2020 as demand
increases with a recovering global economy. Additionally, gas prices during the
first quarter 2021 were boosted due to the February 2021 extreme winter weather
event in Texas and Oklahoma. Our production revenue increased 192%, or
$459.7 million, during the three months ended June 30, 2021 as compared to the
three months ended June 30, 2020 and increased 96%, or $670.3 million, during
the six months ended June 30, 2021 as compared to the six months ended June 30,
2020. The following tables show our production revenue for the periods indicated
as well as the changes in revenue due to changes in volumes and prices.
                                        Three Months Ended
                                             June 30,                                                                     Price/Volume Variance
Production Revenue                                                            Variance Between
(in thousands)                        2021               2020                    2021 / 2020                   Price              Volume             Total
Oil sales                         $ 424,175          $ 138,817          $  285,358            206%          $ 294,693          $  (9,335)         $ 285,358
Gas sales                           133,260             54,154              79,106            146%             85,060             (5,954)            79,106
NGL sales                           141,294             46,107              95,187            206%             95,400               (213)            95,187
                                  $ 698,729          $ 239,078          $  459,651            192%          $ 475,153          $ (15,502)         $ 459,651



                                          Six Months Ended
                                              June 30,                                                                       Price/Volume Variance
Production Revenue                                                              Variance Between
(in thousands)                         2021                2020                    2021 / 2020                   Price              Volume              Total
Oil sales                         $   768,879          $ 499,797          $  269,082             54%          $ 350,154          $  (81,072)         $ 269,082
Gas sales                             342,058             88,984             253,074            284%            267,216             (14,142)           253,074
NGL sales                             257,894            109,758             148,136            135%            159,519             (11,383)           148,136
                                  $ 1,368,831          $ 698,539          $  670,292             96%          $ 776,889          $ (106,597)         $ 670,292


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Contents

The table below shows our production volumes by region.

                                 Three Months Ended                    Six Months Ended
                                      June 30,                             June 30,
Production Volumes           2021                  2020            2021                 2020
Oil (Bbls per day)
Permian Basin              65,785                68,791          63,894                74,198
Mid-Continent               6,704                 9,063           6,604                 9,502
Other                         218                   102             158                   173
                           72,707                77,956          70,656                83,873
Gas (MMcf per day)
Permian Basin               379.6                 417.8           369.5                 433.4
Mid-Continent               203.2                 237.3           201.5                 240.7
Other                         1.4                   0.9             1.2                   1.1
                            584.2                 656.0           572.2                 675.2
NGL (Bbls per day)
Permian Basin              46,408                47,291          42,788                48,111
Mid-Continent              20,531                20,068          19,556                21,089
Other                          91                    43              73                    51
                           67,030                67,402          62,417                69,251
Total (BOE per day)
Permian Basin             175,453               185,717         168,260               194,548
Mid-Continent              61,101                68,675          59,748                70,705
Other                         551                   295             435                   396
                          237,105               254,687         228,443               265,649



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The table below presents our production volumes by commodity, our average
realized commodity prices, and certain major U.S. index prices. The sale of our
Permian Basin oil production is typically tied to the WTI Midland benchmark
price and the sale of our Mid-Continent oil production is typically tied to the
WTI Cushing benchmark price. During the six months ended June 30, 2021,
approximately 90% of our oil production was in the Permian Basin, up from
approximately 88% during the six months ended June 30, 2020. Our realized prices
do not include settlements of commodity derivative contracts.
                                           Three Months Ended                                              Six Months Ended
                                                June 30,                    Variance Between                   June 30,                   Variance Between
                                          2021              2020              2021 / 2020               2021              2020              2021 / 2020
Oil
Total volume - MBbls                      6,616            7,094                  (7)%                 12,789            15,265                (16)%
Total volume - MBbls per day               72.7             78.0                  (7)%                   70.7              83.9                (16)%
Percentage of total production               31  %            31  %                                        31  %             32  %
Average realized price - per
barrel                                $   64.11          $ 19.57                  228%               $  60.12          $  32.74                 84%
Average WTI Midland price - per
barrel                                $   66.50          $ 28.06                  137%               $  62.52          $  37.55                 66%
Average WTI Cushing price - per
barrel                                $   66.07          $ 27.85                  137%               $  61.96          $  37.01                 67%

Gas
Total volume - MMcf                      53,162           59,694                 (11)%                103,572           122,877                (16)%
Total volume - MMcf per day               584.2            656.0                 (11)%                  572.2             675.2                (15)%
Percentage of total production               41  %            43  %                                        42  %             42  %
Average realized price - per
Mcf                                   $    2.51          $  0.91                  176%               $   3.30          $   0.72                 358%
Average Henry Hub price - per
Mcf                                   $    2.80          $  1.71                  64%                $   2.76          $   1.83                 51%

NGL
Total volume - MBbls                      6,100            6,134                  (1)%                 11,297            12,604                (10)%
Total volume - MBbls per day               67.0             67.4                  (1)%                   62.4              69.3                (10)%
Percentage of total production               28  %            26  %                                        27  %             26  %
Average realized price - per
barrel                                $   23.16          $  7.52                  208%               $  22.83          $   8.71                 162%

Total

Total production - MBOE                  21,577           23,177                  (7)%                 41,348            48,348                (14)%
Total production - MBOE per day           237.1            254.7                  (7)%                  228.4             265.6                (14)%
Average realized price - per
BOE                                   $   32.38          $ 10.32                  214%               $  33.11          $  14.45                 129%



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Other revenues

Gas gathering and other revenue is earned when we transport, process, and market
some third-party gas that is associated with our equity gas. Gas marketing is
comprised of the fees we earn when we act as agent under short-term sales and
supply agreements and market and sell gas for other working interest owners, net
of the related expenses. Gas marketing also includes net pipeline settlements
incurred as a result of these activities. The table below presents revenues from
third-party gas gathering and other and our net marketing margin for marketing
other working interest owners' gas for the periods indicated.

                                               Three Months Ended                                       Six Months Ended
                                                    June 30,                     Variance                   June 30,                     Variance
Gas Gathering and Marketing                                                      Between                                              Between 2021 /
Revenues (in thousands)                      2021               2020           2021 / 2020           2021              2020                2020
Gas gathering and other                  $   13,530          $ 11,589          $   1,941          $ 25,745          $ 25,172          $       573
Gas marketing                            $      121          $ (1,284)         $   1,405          $ (2,730)         $ (1,498)         $    (1,232)



Fluctuations in revenues from gas gathering and gas marketing activities are
primarily a function of increases and decreases in volumes, commodity prices,
and gathering rate charges.

Operating Costs and Expenses

Costs associated with producing oil and gas are substantial. Among other
factors, some of these costs vary with commodity prices, some trend with the
volume of production, some are a function of the number of wells we own, some
depend on the prices charged by service companies, and some fluctuate based on a
combination of the foregoing.

Total operating costs and expenses for the three months ended June 30, 2021 were
lower by 61%, or $880.0 million, compared to the three months ended June 30,
2020. The primary reasons for the decrease were the $941.2 million ceiling test
impairment incurred during the three months ended June 30, 2020 (no ceiling test
impairment was incurred during the three months ended June 30, 2021) and the
$84.2 million decrease in depreciation, depletion, and amortization. These
decreases were partially offset by a $87.9 million increase in net losses on
derivative instruments and a $23.8 million increase in taxes other than income.
                                                     Three Months Ended
                                                          June 30,                       Variance                   Per BOE
Operating Costs and Expenses                                                             Between
(in thousands, except per BOE)                    2021                2020             2021 / 2020           2021            2020
Impairment of oil and gas properties          $       -          $   941,198          $  (941,198)               N/A             N/A
Depreciation, depletion, and
amortization                                    110,733              194,954              (84,221)         $ 5.13          $ 8.41
Asset retirement obligation                       2,514                1,661                  853          $ 0.12          $ 0.07

Production                                       77,408               64,337               13,071          $ 3.59          $ 2.78
Transportation, processing, and other
operating                                        59,285               53,282                6,003          $ 2.75          $ 2.30
Gas gathering and other                           9,549                3,526                6,023          $ 0.44          $ 0.15
Taxes other than income                          40,247               16,486               23,761          $ 1.87          $ 0.71
General and administrative                       24,978               26,226               (1,248)         $ 1.16          $ 1.13
Stock-based compensation                          7,878                6,747                1,131          $ 0.37          $ 0.29
Loss on derivative instruments, net             211,833              123,885               87,948                N/A             N/A
Other operating expense, net                      8,050                  130                7,920                N/A             N/A
                                              $ 552,475          $ 1,432,432          $  (879,957)



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Total operating costs and expenses for the six months ended June 30, 2021 were
lower by 61%, or $1.635 billion, compared to the six months ended June 30,
2020. The primary reasons for the decrease were the $1.275 billion in ceiling
test impairments incurred during the six months ended June 30, 2020 (no ceiling
test impairments were incurred during the six months ended June 30, 2021), the
$714.4 million goodwill impairment incurred during the six months ended June 30,
2020, and the $186.4 million decrease in depreciation, depletion, and
amortization, partially offset by a $476.8 million increase in net losses on
derivative instruments.
                                                       Six Months Ended
                                                           June 30,                                                         Per BOE
Operating Costs and Expenses                                                              Variance Between
(in thousands, except per BOE)                     2021                 2020                2021 / 2020              2021            2020

Depreciation of oil and gas properties $ – $ 1,274,849 $ (1,274,849)

               N/A             N/A
Depreciation, depletion, and
amortization                                      223,667              410,040                   (186,373)         $ 5.41          $ 8.48
Asset retirement obligation                         4,732                6,385                     (1,653)         $ 0.11          $ 0.13
Impairment of goodwill                                  -              714,447                   (714,447)               N/A             N/A
Production                                        152,214              151,573                        641          $ 3.68          $ 3.14
Transportation, processing, and other
operating                                         122,892              108,204                     14,688          $ 2.97          $ 2.24
Gas gathering and other                            20,027               11,824                      8,203          $ 0.48          $ 0.24
Taxes other than income                            81,233               47,447                     33,786          $ 1.96          $ 0.98
General and administrative                         50,238               51,735                     (1,497)         $ 1.22          $ 1.07
Stock-based compensation                           16,427               13,141                      3,286          $ 0.40          $ 0.27
Loss (gain) on derivative instruments,
net                                               373,768             (103,055)                   476,823                N/A             N/A
Other operating expense, net                        7,117                  381                      6,736                N/A             N/A
                                              $ 1,052,315          $ 2,686,971          $      (1,634,656)


Depreciation of Oil and gas properties

We use the full cost method of accounting for our oil and gas operations. Under
this method, we are required to perform quarterly ceiling test calculations to
test our oil and gas properties for possible impairment. If the net capitalized
cost of our oil and gas properties, as adjusted for income taxes, exceeds the
ceiling limitation, the excess is charged to expense.  The ceiling limitation is
equal to the sum of: (i) the present value discounted at 10% of estimated future
net revenues from proved reserves, (ii) the cost of properties not being
amortized, and (iii) the lower of cost or estimated fair value of unproven
properties included in the costs being amortized, as adjusted for income
taxes. We currently do not have any unproven properties that are being
amortized. Estimated future net revenues are determined based on trailing
twelve-month average commodity prices and estimated proved reserve quantities,
operating costs, and capital expenditures.

The quarterly ceiling test is primarily impacted by commodity prices, changes in
estimated reserve quantities, reserves produced, overall exploration and
development costs, depletion expense, and deferred taxes. If pricing conditions
decline, or if there is a negative impact on one or more of the other components
of the calculation, we may incur a full cost ceiling test impairment. The
calculated ceiling limitation is not intended to be indicative of the fair
market value of our proved reserves or future results. Impairment charges do not
affect cash flow from operating activities, but do adversely affect our net
income and various components of our balance sheet. Any impairment of oil and
gas properties is not reversible at a later date.

No ceiling test impairments were incurred during the six months ended June 30,
2021. At June 30, 2021, a decline in the value of the ceiling limitation of
approximately 34% or more would have resulted in an impairment. During the six
months ended June 30, 2020, we incurred ceiling test impairments totaling $1.275
billion primarily as a result of decreases in the 12-month average trailing
prices for oil, gas, and NGLs as well as significant basis differentials
utilized in determining the estimated future net cash flows from proved
reserves. We may recognize additional ceiling test impairments in the future.
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Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization ("DD&A") consisted of the following
for the periods indicated:

                                                    Three Months Ended
                                                         June 30,                     Variance                   Per BOE
DD&A Expense (in thousands, except per                                                 Between
BOE)                                              2021               2020            2021 / 2020          2021            2020
Depletion                                     $  93,822          $ 177,136          $  (83,314)         $ 4.35          $ 7.64
Depreciation                                     16,911             17,818                (907)           0.78            0.77
                                              $ 110,733          $ 194,954          $  (84,221)         $ 5.13          $ 8.41




                                                     Six Months Ended
                                                         June 30,                      Variance                   Per BOE
DD&A Expense (in thousands, except per                                                 Between
BOE)                                              2021               2020            2021 / 2020           2021            2020
Depletion                                     $ 189,522          $ 375,262          $  (185,740)         $ 4.58          $ 7.76
Depreciation                                     34,145             34,778                 (633)           0.83            0.72
                                              $ 223,667          $ 410,040          $  (186,373)         $ 5.41          $ 8.48



Depletion of our producing properties is computed using the units-of-production
method. The economic life of each producing well depends upon the estimated
proved reserves for that well, which in turn depend upon the assumed realized
sales price for future production. Therefore, fluctuations in oil and gas prices
will impact the level of proved reserves used in the calculation. Higher prices
generally have the effect of increasing reserves, which reduces depletion
expense. Conversely, lower prices generally have the effect of decreasing
reserves, which increases depletion expense. The cost of replacing production
also impacts our depletion expense. In addition, changes in estimates of reserve
quantities, estimates of operating and future development costs,
reclassifications of properties from unproved to proved, and impairments of oil
and gas properties will also impact depletion expense. Our depletion expense
decreased during the three and six months ended June 30, 2021 as compared to the
three and six months ended June 30, 2020 primarily due to a decrease in our
depletable basis, mostly resulting from the ceiling test impairments that we
recognized in each quarter of 2020, and secondarily due to decreased production
during the 2021 periods as compared to the 2020 periods.

We record our depreciable fixed assets at cost and depreciate them to
depreciation expense using the straight-line method based on the expected useful
lives of the individual assets, which range from 3 to 30 years. Depreciable
fixed assets whose depreciation is recorded to depreciation expense consist
primarily of gas gathering and plant facilities, water infrastructure, vehicles,
airplanes, office furniture, leasehold improvements, computer equipment, and the
right-of-use asset associated with our finance lease gas gathering system.

Depreciation of Good will

We concluded that goodwill was impaired at March 31, 2020 and expensed the entire balance of $ 714.4 million at this moment. See note 1 of the condensed consolidated financial statements for additional information regarding goodwill impairment.

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Production

Production expense generally consists of costs for labor, equipment,
maintenance, saltwater disposal, compression, power, treating, and miscellaneous
other costs (lease operating expense). Production expense also includes well
workover activity necessary to maintain production from existing wells.
Production expense consisted of lease operating expense and workover expense as
follows:

                                                    Three Months Ended
                                                         June 30,                     Variance                  Per BOE
Production Expense (in thousands,                                                     Between
except per BOE)                                   2021               2020           2021 / 2020          2021            2020
Lease operating expense                       $   61,567          $ 58,427          $   3,140          $ 2.85          $ 2.52
Workover expense                                  15,841             5,910              9,931            0.74            0.26
                                              $   77,408          $ 64,337          $  13,071          $ 3.59          $ 2.78




                                                     Six Months Ended
                                                         June 30,                     Variance                   Per BOE
Production Expense (in thousands,                                                      Between
except per BOE)                                   2021               2020            2021 / 2020          2021            2020
Lease operating expense                       $ 122,800          $ 132,896          $  (10,096)         $ 2.97          $ 2.75
Workover expense                                 29,414             18,677              10,737            0.71            0.39
                                              $ 152,214          $ 151,573          $      641          $ 3.68          $ 3.14



Lease operating expense for the second quarter of 2021 increased 5%, or $3.1
million, compared to the second quarter of 2020. Lease operating expense for the
six months ended June 30, 2021 decreased 8%, or $10.1 million, compared to the
six months ended June 30, 2020. The per BOE expense increased in the 2021
periods as compared to the 2020 periods as a result of decreased production. The
decrease in the absolute expense during the six months ended June 30, 2021 is
primarily due to our reduction in headcount through our 2020 voluntary early
retirement incentive program and involuntary reduction in workforce as well as
the use of less contract labor.

Workover expense for the second quarter of 2021 increased 168%, or $9.9 million,
compared to the second quarter of 2020. Workover expense for the six months
ended June 30, 2021 increased 57%, or $10.7 million, compared to the six months
ended June 30, 2020. During the 2020 periods we had fewer workover projects as a
result of a concerted effort to reduce activity and delay non-essential work.
With the improvement of demand and prices, we are now performing more and
costlier workover projects.

Transport, processing and other operations

Transportation, processing, and other operating costs principally consist of
expenditures to prepare and transport production from the wellhead, including
gathering, fuel, compression, and processing costs. Costs vary by region and
will fluctuate with increases or decreases in production volumes, contractual
fees, changes in fuel and compression costs, and the structure of sales
contracts. If the sales contract transfers control of the product at the
wellhead, transportation and processing costs are included as a reduction in the
revenue we record and are not included in transportation, processing, and other
operating costs. Transportation, processing, and other operating costs for the
second quarter of 2021 were 11%, or $6.0 million, higher than the same costs in
the second quarter of 2020. Transportation, processing, and other operating
costs for the six months ended June 30, 2021 were 14%, or $14.7 million, higher
than the same costs in the six months ended June 30, 2020. This expense
increased due primarily to higher gas prices, which cause higher fuel expense.
Additionally, the first quarter of 2021 included increased fuel gas and
electricity costs as a result of the February 2021 extreme winter weather event
in Texas and Oklahoma. Decreased volumes partially offset the increase in this
expense, but also contributed to the increase in the per BOE cost.

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Gas Gathering and Other

Gas gathering and other includes costs associated with operating our gas
gathering and processing infrastructure, including product costs and operating
and maintenance expenses. A portion of these costs are reclassified to
"Transportation, processing, and other operating" expense and "Production"
expense in order to reflect an allocation of the costs incurred to operate our
gas gathering facilities as a cost of transporting our equity share of gas
produced and operating our wells. Gas gathering and other in the second quarter
of 2021 was 171%, or $6.0 million, higher than gas gathering and other in the
second quarter of 2020. Gas gathering and other in the six months ended June 30,
2021 was 69%, or $8.2 million, higher than gas gathering and other in the six
months ended June 30, 2020. The increases in expense in the 2021 periods are
primarily due to higher gas prices and increased maintenance expense.

Taxes other than income

Taxes other than income consist of production (or severance) taxes, ad valorem
taxes, and other taxes. State and local taxing authorities assess these taxes,
with production taxes being based on the volume or value of production and ad
valorem taxes being based on the value of properties. The following table
presents taxes other than income for the periods indicated.
                                               Three Months Ended                                       Six Months Ended
                                                    June 30,                     Variance                   June 30,                     Variance
Taxes Other than Income                                                          Between                                              Between 2021 /
(in thousands)                               2021               2020           2021 / 2020           2021              2020                2020
Production                               $   35,022          $  6,868          $  28,154          $ 71,091          $ 28,455          $    42,636
Ad valorem                                    4,375             9,232             (4,857)            9,106            18,451               (9,345)
Other                                           850               386                464             1,036               541                  495
                                         $   40,247          $ 16,486          $  23,761          $ 81,233          $ 47,447          $    33,786

Taxes other than income as a
percentage of production revenue             5.8%               6.9%                                 5.9%              6.8%



Taxes other than income increased $23.8 million, or 144%, in the second quarter
of 2021 as compared to the second quarter of 2020 and increased $33.8 million,
or 71%, in the six months ended June 30, 2021 as compared to the six months
ended June 30, 2020. Production taxes typically make up the majority of our
taxes other than income and they increased significantly, primarily due to
increased revenues as a result of increased prices. Commodity prices were higher
in the 2021 periods as compared to the 2020 periods due primarily to the
increase in demand. The February 2021 extreme winter weather event in Texas and
Oklahoma also contributed to increased prices in the six months ended June 30,
2021. Ad valorem tax accruals are based on the most recent actual taxes paid
with adjustments made based on expected valuations, divestitures, and as better
information, including actual valuations, is received. Ad valorem tax expense
for the six months ended June 30, 2020 reflected accruals based on valuations
received in late 2019. Decreased valuations received in late 2020 resulted in
lower actual ad valorem taxes paid in the fourth quarter of 2020 and, therefore,
lower ad valorem accruals in the six months ended June 30, 2021. Other taxes are
comprised of franchise and consumer use and sales taxes.

General and administrative

General and administrative ("G&A") expense consists primarily of salaries and
related benefits, office rent, legal and consulting fees, systems costs, and
other administrative costs incurred. Our G&A expense is reported net of amounts
reimbursed to us by working interest owners of the oil and gas properties we
operate and net of amounts capitalized pursuant to the full cost method of
accounting. The amount of expense capitalized varies and depends on whether the
cost incurred can be directly identified with acquisition, exploration, and
development activities. The percentage of gross G&A capitalized was 30% and 31%
during the three and six months ended June 30, 2021, respectively, and was 35%
and 38% during the three and six months ended June 30, 2020, respectively. The
decreased capitalization rates in the 2021 periods are a result of decreased
acquisition, exploration, and development
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activities in response to the lower oil prices and demand destruction seen after
the first quarter of 2020. The table below shows our G&A costs for the periods
presented.
                                                 Three Months Ended                                       Six Months Ended
                                                      June 30,                     Variance                   June 30,                     Variance
General and Administrative Expense                                                 Between                                               Between 2021
(in thousands)                                 2021               2020           2021 / 2020           2021              2020               /2020
Gross G&A                                  $   35,608          $ 40,466          $  (4,858)         $ 73,055          $ 83,267          $   (10,212)
Less amounts capitalized to oil and
gas properties                                (10,630)          (14,240)             3,610           (22,817)          (31,532)               8,715
G&A expense                                $   24,978          $ 26,226          $  (1,248)         $ 50,238          $ 51,735          $    (1,497)



Gross G&A expense decreased $4.9 million, or 12%, in the second quarter of 2021
as compared to the second quarter of 2020 and decreased $10.2 million, or 12%,
in the six months ended June 30, 2021 as compared to the six months ended
June 30, 2020. Gross G&A expense decreased in the 2021 periods as compared to
the 2020 periods primarily due to decreases in severance costs incurred related
to the voluntary early retirement incentive program that we offered during the
first quarter of 2020 to employees who met certain eligibility criteria. The
three and six months ended June 30, 2020 included severance expense of $3.6
million and $14.5 million, respectively, related to this program. Salaries and
wages also decreased in the 2021 periods as compared to the 2020 periods as a
result of the headcount reductions in 2020. In addition to the voluntary early
retirement incentive program, we also had an involuntary reduction in workforce
in the third quarter of 2020. The decreases in gross G&A in the 2021 periods as
compared to the 2020 periods due to reduced severance and salaries and wages
expense were partially offset by increased annual bonus expense and decreased
amounts reimbursed to us by working interest owners.

Stock-based compensation

Stock-based compensation expense consists primarily of charges resulting from
the amortization of the cost of restricted stock and stock option awards, net of
amounts capitalized to oil and gas properties. We have recognized stock-based
compensation cost as follows:
                                                 Three Months Ended                                        Six Months Ended
                                                      June 30,                      Variance                   June 30,                    Variance
Stock-based Compensation Expense                                                    Between                                                Between
(in thousands)                                  2021                2020          2021 / 2020           2021              2020           2021 / 2020
Restricted stock awards:
Performance stock awards                  $    3,441             $ 4,059    

$ (618) $ 6,723 $ 8,119 $ (1,396)
Service-based share awards

                     6,543               6,585                (42)           14,842            13,962                880
                                               9,984              10,644               (660)           21,565            22,081               (516)
Stock option awards                              426                 416                 10               900               914                (14)
Total stock-based compensation cost           10,410              11,060               (650)           22,465            22,995               (530)
Less amounts capitalized to oil and
gas properties                                (2,532)             (4,313)             1,781            (6,038)           (9,854)             3,816
Stock-based compensation expense          $    7,878             $ 6,747          $   1,131          $ 16,427          $ 13,141          $   3,286



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Periodic stock-based compensation expense will fluctuate based on the grant-date
fair value of awards, the number of awards, the requisite service period of the
awards, employee forfeitures, and the timing of the awards. Our accounting
policy is to account for forfeitures in compensation cost when they occur. To
the extent compensation cost relates to employees directly involved in oil and
gas property acquisition, exploration, and development activities, such amounts
are capitalized to oil and gas properties. The amount of stock-based
compensation cost capitalized to oil and gas properties decreased as a
percentage of total stock-based compensation cost during the three and six
months ended June 30, 2021 as compared to the three and six months ended
June 30, 2020 as a result of decreased acquisition, exploration, and development
activities in response to the lower oil prices and demand destruction seen after
the first quarter of 2020. The decreased capitalization caused overall
stock-based compensation expense to increase.

Loss (gain) on derivative instruments, net

The following table presents the components of "Loss (gain) on derivative
instruments, net" for the periods indicated. See Note 3 to the Condensed
Consolidated Financial Statements for additional information regarding our
derivative instruments.

                                             Three Months Ended                                         Six Months Ended
                                                  June 30,                     Variance                     June 30,                     Variance
Loss (Gain) on Derivative                                                      Between                                                    Between
Instruments, Net (in thousands)            2021               2020           2021 / 2020            2021               2020             2021 / 2020
Decrease (increase) in fair
value of derivative instruments,
net:
Gas contracts                          $  40,026          $  19,826          $  20,200          $  39,579          $   32,319          $    7,260
Oil contracts                             85,671            168,000            (82,329)           185,519             (28,319)            213,838
                                         125,697            187,826            (62,129)           225,098               4,000             221,098
Cash payments (receipts) on
derivative instruments, net:
Gas contracts                             14,403             (5,870)            20,273             29,668             (17,589)             47,257
Oil contracts                             71,733            (58,071)           129,804            119,002             (89,466)            208,468
                                          86,136            (63,941)           150,077            148,670            (107,055)            255,725
Loss (gain) on derivative
instruments, net                       $ 211,833          $ 123,885          $  87,948          $ 373,768          $ (103,055)         $  476,823



Other Operating Expense, Net

Other net operating expenses during the half-year ended June 30, 2021 included
$ 8.1 million expenses related to the Cabot merger. These expenses mainly related to advisory and legal services. Also included in Other operating expenses, net for the three and six months ended June 30, 2021 and 2020 were litigation settlements and provisions for credit loss adjustments.

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Other Income and Expense
                                                  Three Months Ended                                       Six Months Ended
                                                       June 30,                     Variance                   June 30,                     Variance
Other Income and Expense                                                            Between                                                 Between
(in thousands)                                  2021               2020           2021 / 2020           2021              2020            2021 / 2020
Interest expense                            $   23,370          $ 23,047          $     323          $ 46,448          $ 46,228          $       220
Capitalized interest                           (11,386)          (12,939)             1,553           (22,951)          (26,121)               3,170

Other, net                                        (459)            3,496             (3,955)             (598)            2,625               (3,223)
                                            $   11,525          $ 13,604          $  (2,079)         $ 22,899          $ 22,732          $       167



The majority of our interest expense relates to interest on the borrowings under
our senior unsecured notes, with such interest totaling $21.0 million for the
three months ended June 30, 2021 and 2020 and $42.0 million for the six months
ended June 30, 2021 and 2020. Also included in interest expense is interest
expense on our Credit Facility borrowings, the amortization of debt issuance
costs and discounts, interest expense on our finance lease, and miscellaneous
interest expense. See LIQUIDITY AND CAPITAL RESOURCES Long-term Debt below for
further information regarding our debt.

We capitalize interest on non-producing leasehold costs, the in-progress costs
of drilling and completing wells, and constructing midstream assets. Capitalized
interest will fluctuate based primarily on the amount of costs subject to
interest capitalization and based on the rates applicable to borrowings
outstanding during the period. The amount of costs subject to interest
capitalization has decreased in the 2021 periods as compared to the 2020
periods, primarily due to the decrease in the balance of non-producing leasehold
costs as a result of transfers to proved properties outweighing additions to
non-producing leasehold costs.

Components of "Other, net" consist of miscellaneous income and expense items
that vary from period to period, including interest income, gain or loss related
to the sale or value of oil and gas well equipment and supplies, gain or loss on
miscellaneous fixed asset sales, and income and expense associated with other
non-operating activities.

Income Tax Expense (Benefit)

The elements of our provision for income taxes and our combined federal and state effective tax rates were as follows:

                                          Three Months Ended                                         Six Months Ended
                                               June 30,                     Variance                     June 30,                     Variance
Income Tax Expense (Benefit)                                                 Between                                                   Between
(in thousands)                         2021               2020             2021 / 2020           2021               2020             2021 / 2020

Current tax expense (profit) $ 442 $ 37 $

     405          $    442          $     (161)         $      603
Deferred tax expense
(benefit)                             34,550            (271,543)            306,093            74,720            (287,900)            362,620
                                    $ 34,992          $ (271,506)         $  306,498          $ 75,162          $ (288,061)         $  363,223

Combined federal and state
effective income tax rate              23.6%              22.7%                                  23.7%              14.5%



Our combined federal and state effective income tax rates differ from the U.S.
federal statutory rate of 21% primarily due to state income taxes,
non-deductible expenses, and changes in valuation allowances. The combined
federal and state effective income tax rate for the six months ended June 30,
2020 was impacted by the non-deductible impairment of goodwill recorded during
the first quarter 2020. See Note 9 to the Condensed Consolidated Financial
Statements for additional information regarding our income taxes.


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LIQUIDITY AND CAPITAL RESOURCES

Overview

With the volatility in commodity prices and recognizing the U.S. oil volume
growth impact on the overall world oil supply and demand balance, we have
adjusted our approach to our capital reinvestment rates to stay below operating
cash flow. With this investment approach, we will have cash flow available to
increase cash on our balance sheet, which we plan to initially target to reduce
debt and continue to fund and increase our regular common stock cash dividend.

We strive to maintain an adequate liquidity level to address volatility and
risk. Sources of liquidity include our cash flow from operations, cash on hand,
available borrowing capacity under our revolving credit facility, and proceeds
from sales of non-core assets.

Our liquidity is highly dependent on the prices we receive for the oil, gas, and
NGLs we produce. The prices we receive are determined by prevailing market
conditions and greatly influence our revenue, cash flow, profitability, access
to capital, and future rate of growth. See RESULTS OF OPERATIONS Revenues above
for further information regarding the impact realized prices have had on our
earnings.

We address volatility in commodity prices primarily by maintaining flexibility
in our capital investment program. We have a balanced and abundant drilling
inventory and limited long-term commitments, which enable us to respond quickly
to industry volatility. In response to the decline in oil prices in the second
quarter of 2020, we took immediate steps to reduce our capital investment,
including releasing drilling rigs and deferring well completion activity, which
resulted in an immediate reduction in capital investments that continued through
2020, increasing moderately as oil prices improved in the fourth quarter of 2020
and into 2021. We are currently running five drilling rigs and two completion
crews. See Capital Expenditures below for information regarding our capital
expenditures for the six months ended June 30, 2021 and our plans for annual
2021 capital expenditures.

We periodically use derivative instruments to mitigate volatility in commodity
prices. At June 30, 2021, we had derivative contracts covering a portion of our
2021 and 2022 production. Depending on changes in oil and gas futures markets
and management's view of underlying supply and demand trends, we may increase or
decrease our derivative positions from current levels. See Note 3 to the
Condensed Consolidated Financial Statements for information regarding our
derivative instruments.

At June 30, 2021, we had $799.3 million in cash and cash equivalents. At
June 30, 2021, our long-term debt consisted of $2.0 billion of senior unsecured
notes, with $750 million 4.375% notes due in 2024, $750 million 3.90% notes due
in 2027, and $500 million 4.375% notes due in 2029. At June 30, 2021, we had no
borrowings and $2.5 million in letters of credit outstanding under our credit
facility, leaving an unused borrowing availability of $1.248 billion. We expect
the investment approach discussed above will allow us to accumulate cash for the
future repayment of debt. See Long-term Debt below for more information
regarding our debt.

We may, from time to time, seek to repurchase shares of our outstanding
preferred stock through cash repurchases and/or exchanges for equity securities,
privately negotiated transactions, or otherwise. Such activities, if any, will
depend on prevailing market conditions, our liquidity requirements, contractual
restrictions, and other factors. See Note 5 to the Condensed Consolidated
Financial Statements for information regarding our preferred stock.

We expect our operating cash flow and other capital resources to be adequate to
meet our needs for planned capital expenditures, working capital, debt service,
and dividends declared for the next twelve months.

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Analysis of Cash Flow Changes

The following table presents the totals of the major cash flow classification categories from our condensed consolidated statements of cash flows for the periods indicated.

                                                     Six Months Ended
                                                         June 30,
(in thousands)                                     2021            2020

Net cash flow generated by operating activities $ 766,584 $ 453,497
Net cash used by investing activities $ (185,145) $ (454,614)
Net cash used by financing activities $ (55,269) $ (49,763)



Net cash provided by operating activities for the six months ended June 30, 2021
was $766.6 million, up $313.1 million, or 69%, from $453.5 million for the six
months ended June 30, 2020. The increase in net cash provided by operating
activities resulted primarily from increased revenues in the six months ended
June 30, 2021 as compared to the six months ended June 30, 2020 due to realized
prices increasing for all products. This increase was partially offset by
increased net cash payments for settlements of derivative instruments during the
six months ended June 30, 2021 as compared to net cash receipts for settlements
of derivative instruments during the six months ended June 30, 2020. See RESULTS
OF OPERATIONS above for more information regarding changes in revenues and
expenses.

Net cash used by investing activities for the six months ended June 30, 2021 and
2020 was $185.1 million and $454.6 million, respectively. The majority of our
cash flows used by investing activities are for oil and gas capital
expenditures, which totaled $298.3 million and $411.3 million for the six months
ended June 30, 2021 and 2020, respectively. In response to the decline in oil
prices in the second quarter of 2020, we took immediate steps to reduce our
capital investment, including releasing drilling rigs and deferring well
completion activity, which resulted in an immediate reduction in capital
investments that continued through 2020, increasing moderately as oil prices
improved in the fourth quarter of 2020 and into 2021. Net cash used by investing
activities also includes other capital expenditures of $5.8 million and $38.1
million for the six months ended June 30, 2021 and 2020, respectively, which are
primarily expenditures for midstream assets. The 2021 midstream expenditures
decreased from the 2020 midstream expenditures due to the reduction in capital
investments post-first quarter of 2020. Also included in net cash used by
investing activities are expenditures for acquisitions of oil and gas properties
and the proceeds of miscellaneous asset sales, including non-core oil and gas
properties and fixed assets. The six months ended June 30, 2021 included $118.7
million in proceeds from the sale of non-core oil and gas properties and related
assets in the Permian Basin and Mid-Continent.

Net cash used by financing activities was $55.3 million and $49.8 million during
the six months ended June 30, 2021 and 2020, respectively. During the six months
ended June 30, 2020, we borrowed and repaid an aggregate of $161.0 million on
our credit facility to meet cash requirements as needed. We have not had any
credit facility borrowings or repayments during the six months ended June 30,
2021. We declare cash dividends on both our common and preferred stock quarterly
and pay those dividends in the quarter following declaration. During the six
months ended June 30, 2021, we paid one $0.22 per share dividend and one $0.27
per share dividend on our common stock and two $20.3125 per share dividends on
our preferred stock, totaling $51.2 million. During the six months ended June
30, 2020, we paid one $0.20 per share dividend and one $0.22 per share dividend
on our common stock and two $20.3125 per share dividends on our preferred stock,
totaling $45.2 million. Future dividend payments will depend on our level of
earnings, financial requirements, and other factors considered relevant by our
Board of Directors. Also included in net cash used by financing activities are
finance lease payments, payments of employee income tax withholdings on the net
settlement of equity-classified stock awards, financing fee payments, and
proceeds from exercise of stock options.

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Capital Expenditures

The following table presents the capitalized expenditures for the acquisition, exploration and development of oil and gas properties.

                                                             Three Months Ended                     Six Months Ended
                                                                  June 30,                              June 30,
(in thousands)                                            2021                2020               2021               2020
Acquisitions:
Proved                                                $        -          $       -          $       -          $   7,250
Unproved                                                       -                  -                310                  -
                                                               -                  -                310              7,250
Exploration and development:
Land and seismic                                          10,074             12,116             22,047             26,040
Exploration and development                              186,868             71,666            335,764            306,394
                                                         196,942             83,782            357,811            332,434

Total acquisition, exploration, and development
capital expenditures                                  $  196,942          $  83,782          $ 358,121          $ 339,684



Amounts in the table above are presented on an accrual basis. Oil and gas
capital expenditures and acquisitions of oil and gas properties in the Condensed
Consolidated Statements of Cash Flows reflect activities on a cash basis, when
payments are made and proceeds received.

Based on current economic conditions, our 2021 total capital expenditures are
projected to range from $650 million to $750 million. This includes drilling and
completion capital investments of approximately $500 million to $600 million,
with the remaining investments being for midstream infrastructure and other,
including capitalized G&A and non-producing leasehold. The majority of our
planned 2021 drilling and completion capital is expected to be invested in the
Permian Basin, with the remainder in the Mid-Continent. We regularly review our
capital expenditures throughout the year and will adjust our investments based
on increases or decreases in our cash flow. We have the flexibility to adjust
our capital expenditures based upon market conditions.

We intend to continue to fund our 2021 capital investment program with cash flow
from our operating activities and potential sales of non-core assets. The timing
of capital expenditures and the receipt of cash flows do not necessarily match,
which may cause us to borrow and repay funds under our credit facility from time
to time. See Long-term Debt-Bank Debt below for further information regarding
our credit facility.

The following table reflects wells completed by region during the periods
indicated.
                        Three Months Ended              Six Months Ended
                             June 30,                       June 30,
                     2021               2020         2021              2020
Gross wells
Permian Basin         44                 17           52                 52
Mid-Continent          9                 20           14                 39
                      53                 37           66                 91
Net wells
Permian Basin       21.7               11.1         28.7               30.9
Mid-Continent        0.5                1.4          0.5                1.7
                    22.2               12.5         29.2               32.6



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As of June 30, 2021, we had 39 gross (12.3 net) wells in the process of being
drilled: 30 gross (12.3 net) in the Permian Basin and 9 gross (nil net) in the
Mid-Continent region. As of June 30, 2021, we had 88 gross (45.7 net) wells
waiting on completion: 75 gross (40.8 net) in the Permian Basin and 13 gross
(4.9 net) in the Mid-Continent region. By mid-May 2020, we had released all but
one rig and placed completion activities on hold due to economic conditions.
Since that time with the stabilization of commodity prices, we have added
additional drilling rigs and also began completing wells starting in September
2020. We are currently running five drilling rigs and two completion crews. We
maintain flexibility to adjust our activity as conditions change.

We have made, and will continue to make, expenditures to comply with
environmental and safety regulations and requirements. These costs are
considered a normal recurring cost of our ongoing operations. While we expect
pending legislation or regulations to increase the cost of business, we do not
anticipate that we will be required to expend amounts that will have a material
adverse effect on our financial position or operations, nor are we aware of any
pending legislative or regulatory changes that would have a material impact.
However, compliance with new legislation and regulations could increase our
costs and negatively affect demand for oil or gas and result in a material
adverse effect on our financial position or operations. See our Form 10-K for
the year ended December 31, 2020, Item 1A Risk Factors, for a description of
risks related to current and potential future environmental and safety
regulations and requirements that could adversely affect our operations and
financial condition.

Long-term debt

Long-term debt at June 30, 2021 and December 31, 2020 consisted of the
following:
                                                         June 30, 2021                                                 December 31, 2020
                                                          Unamortized                                                     Unamortized
                                                             Debt                                                            Debt
                                                        Issuance Costs                                                  Issuance Costs
                                                         and Discounts          Long-term                                and Discounts          Long-term
(in thousands)                       Principal                (1)               Debt, net            Principal                (1)               Debt, net
4.375% Notes due 2024              $   750,000          $     (2,254)         $   747,746          $   750,000          $     (2,672)         $   747,328
3.90% Notes due 2027                   750,000                (5,156)             744,844              750,000                (5,541)             744,459
4.375% Notes due 2029                  500,000                (4,259)             495,741              500,000                (4,488)             495,512
                                   $ 2,000,000          $    (11,669)         $ 1,988,331          $ 2,000,000          $    (12,701)         $ 1,987,299

________________________________________

(1)The 4.375% Notes due 2024 were issued at par, therefore, the amounts shown in
the table are for unamortized debt issuance costs only. At June 30, 2021, the
unamortized debt issuance costs and discount related to the 3.90% Notes due 2027
were $4.0 million and $1.2 million, respectively. At June 30, 2021, the
unamortized debt issuance costs and discount related to the 4.375% Notes due
2029 were $3.7 million and $0.6 million, respectively. At December 31, 2020, the
unamortized debt issuance costs and discount related to the 3.90% Notes due 2027
were $4.3 million and $1.3 million, respectively. At December 31, 2020, the
unamortized debt issuance costs and discount related to the 4.375% Notes due
2029 were $3.9 million and $0.6 million, respectively.

Bank debt

On June 3, 2020, we entered into the First Amendment to Amended and Restated
Credit Agreement (the "First Amendment") dated as of February 5, 2019 for our
senior unsecured revolving credit facility ("Credit Facility"). The Credit
Facility has aggregate commitments of $1.25 billion with an option for us to
increase the aggregate commitments to $1.5 billion, and matures on February 5,
2024. There is no borrowing base subject to the discretion of the lenders based
on the value of our proved reserves under the Credit Facility. The First
Amendment, among other things: (i) allows up to $3.5 billion of non-cash
impairment charge add-backs to Shareholders' Equity for covenant calculation
purposes, (ii) institutes traditional anti-cash hoarding provisions (if
borrowings are outstanding under the Credit Facility) at a consolidated cash
threshold of $175.0 million, (iii) reduces the priority lien debt basket from
15% of Consolidated Net Tangible Assets (as defined in the credit agreement) to
a
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$50.0 million cap, and (iv) adds an acknowledgement and consent to European
Union bail-in legislation. As of June 30, 2021, we had no bank borrowings
outstanding under the Credit Facility, but did have letters of credit of $2.5
million outstanding, leaving an unused borrowing availability of $1.248 billion.

At our option, borrowings under the Credit Facility may bear interest at either
(a) LIBOR (or an alternate rate determined by the administrative agent for the
Credit Facility in accordance with the Credit Facility when LIBOR is no longer
available) plus 1.125 - 2.0% based on the credit rating for our senior unsecured
long-term debt, or (b) a base rate (as defined in the credit agreement) plus
0.125 - 1.0%, based on the credit rating for our senior unsecured long-term
debt. Unused borrowings are subject to a commitment fee of 0.125 - 0.35%, based
on the credit rating for our senior unsecured long-term debt.

The Credit Facility contains representations, warranties, covenants, and events
of default that are customary for investment grade, senior unsecured bank credit
agreements, including a financial covenant for the maintenance of a defined
total debt-to-capitalization ratio of no greater than 65%. As of June 30, 2021,
we were in compliance with all of the financial and non-financial covenants.

At June 30, 2021 and December 31, 2020, we had $3.6 million and $4.3 million,
respectively, of unamortized debt issuance costs associated with our Credit
Facility, which were recorded as assets and included in "Other assets" on our
Condensed Consolidated Balance Sheets. These costs are being amortized to
interest expense ratably over the life of the Credit Facility.

Senior Notes

In March 2019, we issued $500.0 million aggregate principal amount of 4.375%
senior unsecured notes at 99.862% of par to yield 4.392% per annum. These notes
are due March 15, 2029 and interest is payable semiannually on March 15 and
September 15. The effective interest rate on these notes, including the
amortization of debt issuance costs and discount, is 4.50%.

In April 2017, we issued $750.0 million aggregate principal amount of 3.90%
senior unsecured notes at 99.748% of par to yield 3.93% per annum. These notes
are due May 15, 2027 and interest is payable semiannually on May 15 and November
15. The effective interest rate on these notes, including the amortization of
debt issuance costs and discount, is 4.01%.

In June 2014, we issued $750.0 million aggregate principal amount of 4.375%
senior unsecured notes at par. These notes are due June 1, 2024 and interest is
payable semiannually on June 1 and December 1. The effective interest rate on
these notes, including the amortization of debt issuance costs, is 4.50%.

Our senior unsecured notes are governed by indentures containing certain covenants, events of default and other restrictive provisions with which we comply with the June 30, 2021.

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Working Capital Analysis

At June 30, 2021, we had a working capital surplus of $243.2 million, an
increase of $246.1 million from a working capital deficit of $2.9 million at
December 31, 2020. Our working capital surplus increased primarily as a result
of the following:

Working Capital Increases

• Our cash balance increased by $ 526.2 million and our accounts receivable increased by $ 141.7 million, both mainly due to the increase in income due to the improvement in prices.

Working Capital Decreases

• An augmentation of $ 226.8 million in our net current derivative liabilities.

• Accounts payable and accrued liabilities related to operations increased by $ 140.3 millionmainly due to the increase in revenue payable and accounts payable.

• An increase in our exploration and development activities and mid-term capital accumulations of $ 39.8 million due to increased activity.

Accounts receivable are a major component of our working capital and include
amounts due from a diverse group of companies comprised of major energy
companies, pipeline companies, local distribution companies, and other
end-users. We conduct credit analyses prior to making any sales to new customers
or increasing credit for existing customers and may require parent company
guarantees, letters of credit, or prepayments when deemed necessary. For
properties we operate, we have the right to realize amounts due to us from
non-operators by netting the non-operators' share of production revenues from
those properties. We routinely assess the recoverability of all material
accounts receivable and accrue a reserve to the allowance for credit losses
based on our estimation of expected losses over the life of the receivables.
Historically, losses associated with uncollectible receivables have not been
significant. However, most of our accounts receivable balances are
uncollateralized and result from transactions with other companies in the oil
and gas industry. Concentration of customers may impact our overall credit risk
because our customers may be similarly affected by changes in economic or other
conditions within the industry, such as the impacts on the industry as a result
of the COVID-19 pandemic.

Dividends

A quarterly cash dividend has been paid on our common stock every quarter since
the first quarter of 2006. In May 2021, our Board of Directors declared a cash
dividend of $0.27 per common share, totaling $27.9 million, which is payable on
or before September 1, 2021 to stockholders of record on August 13, 2021. Also
in May 2021, our Board of Directors declared a cash dividend of $20.3125 per
preferred share, totaling $0.6 million. The dividend was paid in July to
preferred stockholders of record on July 1, 2021. Future dividend payments will
depend on our level of earnings, financial requirements, and other factors
considered relevant by our Board of Directors.

Off-balance sheet provisions

We may enter into off-balance sheet arrangements and transactions that can give
rise to material off-balance sheet obligations. As of June 30, 2021, our
material off-balance sheet arrangements consisted of operating lease agreements
for equipment used in connection with our exploration and development activities
with lease terms at commencement of 12 months or less. As an accounting policy,
we have elected not to apply the recognition requirements of Topic 842 to these
leases. As such, we have not recorded any lease liabilities associated with
these leases.

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Contractual Obligations and Material Commitments

TO June 30, 2021, we had the following significant contractual obligations and commitments:

                                                                                    Payments Due by Period
Contractual obligations                                          07/01/21 -           07/01/22 -             07/01/24 -              07/01/26 and
(in thousands)                                 Total              06/30/22             06/30/24               06/30/26                Thereafter
Long-term debt-principal (1)               $ 2,000,000          $        -          $   750,000             $        -             $   1,250,000
Long-term debt-interest (1)                    448,999              81,868              167,875                102,250                    97,006
Operating leases (2)                           252,001              24,774              111,851                 99,254                    16,122
Unconditional purchase obligations
(3)                                             16,067               6,560                6,167                  3,340                         -
Derivative liabilities                         382,758             366,591               16,167                      -                         -
Asset retirement obligation (4)                132,182              12,629                    -    (4)               -    (4)                  -    (4)
Other long-term liabilities (5)                 49,153               5,293               11,315                  6,053                    26,492
                                           $ 3,281,160          $  497,715          $ 1,063,375             $  210,897             $   1,389,620

________________________________________

(1)The interest payments presented above include the accrued interest payable on
our long-term debt as of June 30, 2021 as well as future payments calculated
using the long-term debt's fixed rates, stated maturity dates, and principal
amounts outstanding as of June 30, 2021. See Note 2 to the Condensed
Consolidated Financial Statements for additional information regarding our debt.
(2)Operating leases include the estimated remaining contractual payments under
lease agreements as of June 30, 2021. These lease agreements are primarily
comprised of leases for an electric hydraulic fracturing fleet (shown as
commencing on June 30, 2022 in the table), commercial real estate, which
consists primarily of office space, and compressor equipment.
(3)The unconditional purchase obligations are obligations for firm
transportation agreements for gas pipeline capacity.
(4)We have excluded the presentation of the timing of the cash flows associated
with our $119.6 million long-term asset retirement obligations because we cannot
make a reasonably reliable estimate of the future period of cash settlement. The
long-term asset retirement obligation is included in the total asset retirement
obligation presented.
(5)Other long-term liabilities include contractual obligations associated with
our employee supplemental savings plan, gas balancing liabilities, and other
miscellaneous liabilities. All of these liabilities are accrued on our Condensed
Consolidated Balance Sheet. The current portion associated with these long-term
liabilities is also presented in the table above.

The following discusses various commercial commitments that we have made that
may include potential future cash payments. These are not reflected in the table
above, unless otherwise noted.

TO June 30, 2021, we estimated the commitments to be around: (i) $ 224.8 million to complete the drilling, completion or execution of other work on wells and various other ongoing infrastructure projects and (ii) $ 4.8 million to complete construction midway through.

At June 30, 2021, we had firm sales contracts to deliver approximately 456.5 Bcf
of gas over the next 10.0 years. If we do not deliver this gas, our estimated
financial commitment, calculated using the July 2021 index prices, would be
approximately $1.433 billion. The value of this commitment will fluctuate due to
price volatility and actual volumes delivered. However, we believe no material
financial commitment will be due based on our current proved reserves and
production levels and our ability to make market purchases to fulfill these
volumetric obligations.

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In connection with gas gathering and processing agreements, we have volume
commitments over the next 15.0 years. If we do not deliver the committed gas or
NGLs, as applicable, the estimated maximum amount that would be payable under
these commitments, calculated as of June 30, 2021, would be approximately
$728.6 million. However, we believe no material financial commitment will be due
based on our current proved reserves and production levels from which we can
fulfill these volumetric obligations.

We have minimum volume delivery commitments associated with agreements to
reimburse connection costs to various pipelines. If we do not deliver this gas
or oil, as applicable, the estimated maximum amount that would be payable under
these commitments, calculated as of June 30, 2021, would be approximately
$104.0 million. Of this total, we have accrued a liability of $4.1 million
representing the estimated amount we will have to pay due to insufficient
forecasted volumes at particular connection points. This accrual is reflected in
the table above in Other long-term liabilities. We believe no material financial
commitment will be due based on our current proved reserves and production
levels from which we can fulfill these volumetric obligations.

We have minimum volume water delivery commitments associated with a water
services agreement that ends in 2030. If the water volumes are not delivered by
us or third parties, the estimated maximum amount that would be payable by us
under this commitment, calculated as of June 30, 2021, would be approximately
$60.8 million. Of this total, we have accrued a liability of $0.7 million
representing the estimated amount we will have to pay due to insufficient
forecasted volumes.

All of the commitments mentioned were current and made in the normal course of our operations.

Based on current commodity prices and expected production levels, we believe that our net cash flow from operations and other capital resources will be sufficient to meet our future obligations.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We consider accounting policies and estimates related to oil and gas reserves,
full cost accounting, and income taxes to be critical accounting policies and
estimates. These are summarized in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" in Item 7 of our Annual Report on
Form 10-K for the year ended December 31, 2020.

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