CIMAREX ENERGY CO. OVERVIEW
Cimarex is an independent oil and gas exploration and production company. Our operations are located entirely withinthe United States , mainly inTexas ,New Mexico , andOklahoma . Currently our operations are focused in two main areas: thePermian Basin and the Mid-Continent. OurPermian Basin region encompasses westTexas and southeastNew Mexico . Our Mid-Continent region encompassesOklahoma and the TexasPanhandle . 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 endedJune 30, 2021 of non-core oil and gas properties and related assets inWest Texas andSouthern 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
OnMay 23, 2021 , Cimarex entered into an Agreement and Plan of Merger (the "Merger Agreement") with Cabot Oil & Gas Corporation ("Cabot") andDouble 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 significantly. We expect this volatility to persist. Commodity prices are affected by many factors outside of 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 impacted by pipeline capacity constraints limiting takeaway and increasing basis differentials.
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 earlyMarch 2020 , members of theOrganization of the Petroleum Exporting Countries ("OPEC") andRussia failed to reach an agreement on oil production limits andSaudi Arabia unilaterally reduced the sales price of its oil and announced that it would 29 -------------------------------------------------------------------------------- Table of Contents 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 inApril 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 inAugust 2021 , which could lead to lower oil prices as supply increases. Our average realized price for oil during the six months endedJune 30, 2021 improved to$60.12 per barrel, increasing 84% over our average realized price for oil during the six months endedJune 30, 2020 . InFebruary 2021 ,Texas andOklahoma 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 endedJune 30, 2021 was$3.30 per Mcf, increasing 358% over our average realized price for gas during the six months endedJune 30, 2020 .
The table below presents average NYMEX prices and our company-wide average realized prices and price differentials for the periods indicated.
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
$ (1.91) $
(2.00)
$ (2.11) $
(1.96)
$ (1.96) $
(1.99)
Gas
Permian Basin$ 0.39 $ (0.44) $
1.29
$ (0.02) $
1.69
$ (0.29) $
1.43
Pipeline expansion projects in thePermian 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 endedDecember 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 Operating and Financial Results for the Six Months Ended
•Total production volumes decreased 14% to 228.4 MBOE per day.
•Oil volumes decreased 16% to 70.7 MBbls per day.
•Gas volumes decreased 15% to 572.2 MMcf per day.
•NGL volumes decreased 10% to 62.4 MBbls per day.
•Total production revenue increased 96% to
•Cash flow provided by operating activities increased 69% to
•Exploration and development investments increased 8% to
•Net income was
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RESULTS OF OPERATIONS
Three and Six Months Ended
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 endedJune 30, 2021 as compared to the three and six months endedJune 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 andOPEC 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 theFebruary 2021 extreme winter weather event inTexas andOklahoma . Our production revenue increased 192%, or$459.7 million , during the three months endedJune 30, 2021 as compared to the three months endedJune 30, 2020 and increased 96%, or$670.3 million , during the six months endedJune 30, 2021 as compared to the six months endedJune 30, 2020 . The following tables show our production revenue for the periods indicated as well as the changes in revenue due to changes in volumes and prices. Three Months Ended June 30, Price/Volume Variance Production Revenue Variance Between (in thousands) 2021 2020 2021 / 2020 Price Volume Total Oil sales$ 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 32
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The table below presents 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
33-------------------------------------------------------------------------------- Table of Contents The table below presents our production volumes by commodity, our average realized commodity prices, and certain majorU.S. index prices. The sale of ourPermian 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 endedJune 30, 2021 , approximately 90% of our oil production was in thePermian Basin , up from approximately 88% during the six months endedJune 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% AverageHenry 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% 34
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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)
35-------------------------------------------------------------------------------- Table of Contents Total operating costs and expenses for the six months endedJune 30, 2021 were lower by 61%, or$1.635 billion , compared to the six months endedJune 30, 2020 . The primary reasons for the decrease were the$1.275 billion in ceiling test impairments incurred during the six months endedJune 30, 2020 (no ceiling test impairments were incurred during the six months endedJune 30, 2021 ), the$714.4 million goodwill impairment incurred during the six months endedJune 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
Impairment of oil and gas properties $ -
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) Impairment of
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 endedJune 30, 2021 . AtJune 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 endedJune 30, 2020 , we incurred ceiling test impairments totaling$1.275 billion primarily as a result of decreases in the 12-month average trailing prices for oil, gas, and NGLs as well as significant basis differentials utilized in determining the estimated future net cash flows from proved reserves. We may recognize additional ceiling test impairments in the future. 36 -------------------------------------------------------------------------------- Table of Contents Depreciation, Depletion, and Amortization Depreciation, depletion, and amortization ("DD&A") consisted of the following for the periods indicated: Three Months Ended June 30, Variance Per BOE DD&A Expense (in thousands, except per Between BOE) 2021 2020 2021 / 2020 2021 2020 Depletion$ 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 endedJune 30, 2021 as compared to the three and six months endedJune 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.
Impairment of
We concluded that goodwill was impaired at
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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.
Transportation, Processing, and Other Operating
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 endedJune 30, 2021 were 14%, or$14.7 million , higher than the same costs in the six months endedJune 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 theFebruary 2021 extreme winter weather event inTexas andOklahoma . Decreased volumes partially offset the increase in this expense, but also contributed to the increase in the per BOE cost. 38 -------------------------------------------------------------------------------- Table of Contents 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 endedJune 30, 2021 was 69%, or$8.2 million , higher than gas gathering and other in the six months endedJune 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
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
40-------------------------------------------------------------------------------- Table of Contents 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 endedJune 30, 2021 as compared to the three and six months endedJune 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 operating expense, net during the six months ended
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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 components of our provision for income taxes and our combined federal and state effective income 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 (benefit)
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.
42
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LIQUIDITY AND CAPITAL RESOURCES
Overview
With the volatility in commodity prices and recognizing theU.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 endedJune 30, 2021 and our plans for annual 2021 capital expenditures. We periodically use derivative instruments to mitigate volatility in commodity prices. AtJune 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. AtJune 30, 2021 , we had$799.3 million in cash and cash equivalents. AtJune 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. AtJune 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. 43 -------------------------------------------------------------------------------- Table of Contents 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 provided by operating activities
Net cash provided by operating activities for the six months endedJune 30, 2021 was$766.6 million , up$313.1 million , or 69%, from$453.5 million for the six months endedJune 30, 2020 . The increase in net cash provided by operating activities resulted primarily from increased revenues in the six months endedJune 30, 2021 as compared to the six months endedJune 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 endedJune 30, 2021 as compared to net cash receipts for settlements of derivative instruments during the six months endedJune 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 endedJune 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 endedJune 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 endedJune 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 endedJune 30, 2021 included$118.7 million in proceeds from the sale of non-core oil and gas properties and related assets in thePermian Basin and Mid-Continent. Net cash used by financing activities was$55.3 million and$49.8 million during the six months endedJune 30, 2021 and 2020, respectively. During the six months endedJune 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 endedJune 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 endedJune 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 endedJune 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. 44 -------------------------------------------------------------------------------- Table of Contents Capital Expenditures
The following table presents capitalized expenditures for oil and gas property acquisition, exploration, and development activities.
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
45-------------------------------------------------------------------------------- Table of Contents As ofJune 30, 2021 , we had 39 gross (12.3 net) wells in the process of being drilled: 30 gross (12.3 net) in thePermian Basin and 9 gross (nil net) in the Mid-Continent region. As ofJune 30, 2021 , we had 88 gross (45.7 net) wells waiting on completion: 75 gross (40.8 net) in thePermian Basin and 13 gross (4.9 net) in the Mid-Continent region. Bymid-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 inSeptember 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 endedDecember 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 atJune 30, 2021 andDecember 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. AtJune 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. AtJune 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. AtDecember 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. AtDecember 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
OnJune 3, 2020 , we entered into the First Amendment to Amended and Restated Credit Agreement (the "First Amendment") dated as ofFebruary 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 onFebruary 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 46 -------------------------------------------------------------------------------- Table of Contents$50.0 million cap, and (iv) adds an acknowledgement and consent toEuropean Union bail-in legislation. As ofJune 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 ofJune 30, 2021 , we were in compliance with all of the financial and non-financial covenants. AtJune 30, 2021 andDecember 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
InMarch 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 dueMarch 15, 2029 and interest is payable semiannually onMarch 15 andSeptember 15 . The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.50%. InApril 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 dueMay 15, 2027 and interest is payable semiannually onMay 15 andNovember 15 . The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.01%. InJune 2014 , we issued$750.0 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are dueJune 1, 2024 and interest is payable semiannually onJune 1 andDecember 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
were in compliance as of
47
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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
Working Capital Decreases
•An increase of
•Operations-related accounts payable and accrued liabilities increased by
•An increase in our exploration and development and midstream capital accruals
of
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. InMay 2021 , our Board of Directors declared a cash dividend of$0.27 per common share, totaling$27.9 million , which is payable on or beforeSeptember 1, 2021 to stockholders of record onAugust 13, 2021 . Also inMay 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 onJuly 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 Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As ofJune 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. 48 -------------------------------------------------------------------------------- Table of Contents Contractual Obligations and Material Commitments
At
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 ofJune 30, 2021 as well as future payments calculated using the long-term debt's fixed rates, stated maturity dates, and principal amounts outstanding as ofJune 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 ofJune 30, 2021 . These lease agreements are primarily comprised of leases for an electric hydraulic fracturing fleet (shown as commencing onJune 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.
At
AtJune 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 theJuly 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. 49 -------------------------------------------------------------------------------- Table of Contents 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 ofJune 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 ofJune 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 ofJune 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 noted commitments were routine and made in the ordinary course of our business.
Taking into account current commodity prices and anticipated levels of production, we believe that our net cash flow generated from operations and our other capital resources will be adequate to meet 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 endedDecember 31, 2020 . 50
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