UNIT CORPORATION Introduction
The following discussion should be read together with the condensed consolidated financial statements included in Item 1 of Part I of this report and in Item 8 of our 2020 Form 10-K filed with theSEC onMarch 31, 2021 .
We operate, manage, and analyze the results of our operations through our three principal business segments:
•Oil and Natural Gas - carried out by our subsidiary UPC. This segment develops, acquires, and produces oil and natural gas properties for our own account. •Contract Drilling - carried out by our subsidiary UDC. This segment contracts to drill onshore oil and natural gas wells for others and for our oil and natural gas segment. •Mid-Stream - carried out by Superior and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas and NGLs for third parties and for our own account. We presently own 50% of this subsidiary. In our oil and natural gas segment, we are optimizing production and converting non-producing reserves to producing, with selective drilling activities in core areas. At the beginning of 2021, the company initiated an asset divestiture program in UPC to sell certain non-core oil and gas properties and reserves. OnOctober 4, 2021 , the company announced the expansion of its divestiture efforts to now include the potential sale of additional properties, including up to all of UPC's oil and gas properties and reserves. Management continues to identify and execute on low cost capital projects to enhance production and reserves in this favorable price environment. In our contract drilling segment, management reduced the number of drilling rigs available for use from 58 atDecember 31, 2020 to 21 during the second quarter of 2021 in order to focus on utilization of our BOSS drilling rigs and certain SCR rigs that are either currently under contract or candidates for future upgrades. Of the 21 rigs available for use, 13 are currently working, 4 are actively being marketed, and the remaining 4 will be considered for upgrade and marketing as future conditions warrant. We also plan to continue seeking opportunities to divest non-core, idle drilling equipment. In our mid-stream segment, we are focused on continuing to generate predictable free cash flows with limited exposure to commodity prices. We also plan to continue seeking business development opportunities in our core areas utilizing the Superior credit agreement (which Unit is not a party to and does not guarantee) or other financing sources that are available to it. Upon our emergence from the Chapter 11 Cases onSeptember 3, 2020 , we adopted fresh start accounting as required by US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, our consolidated financial statements afterAugust 31, 2020 are not comparable with our consolidated financial statements prior to that date.
Recent Developments
COVID-19 Pandemic and Commodity Price Environment
Our success depends, among other things, on prices we receive for our oil and
natural gas production, the demand for oil, natural gas, and NGLs, and the
demand for our drilling rigs which influences the amounts we can charge for
those drilling rigs. While our operations are all within
We are continuously monitoring the current and potential impacts of the COVID-19
pandemic, including any new variants, on our business. This includes how it has
and may continue to impact our operations, financial results, liquidity,
customers, employees, and vendors as new COVID-19 variants may have undetermined
impacts to our business. In response to the pandemic, we have implemented
various measures to ensure we are conducting our business in a safe and secure
manner.
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During the last two years commodity prices have been volatile, and the outlook
for future oil and gas prices remains uncertain and subject to many factors. The
following chart reflects the significant fluctuations in the historical prices
for oil and natural gas:
[[Image Removed: unt-20210930_g2.jpg]] The following chart reflects the significant fluctuations in the prices for NGLs:
[[Image Removed: unt-20210930_g3.jpg]] _________________________ 1.NGLs prices reflect a weighted-average, based on production, of Mont Belvieu andConway prices. 42
-------------------------------------------------------------------------------- Table of Contents Stock Repurchase Program InJune 2021 , the Board authorized repurchasing up to$25.0 million of the company's outstanding common stock. InOctober 2021 , the Board authorized an increase from$25.0 million of authorized repurchases to$50.0 million . The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. The company has no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice.
As of
Subsequent toSeptember 30, 2021 , the company repurchased an additional 711,926 shares under the repurchase program at an average share price of$34.80 for an aggregate purchase price of$24.8 million bringing the aggregate shares repurchased under all methods since the Effective Date to 1,739,963 shares.
Allocation of New Common Stock
As contemplated by the Plan, the company distributed 683,038 and 161,328 additional shares of New Common Stock to holders of the subordinated notes claims onJuly 26, 2021 andOctober 20, 2021 , respectively, as a result of the pro rata distribution of shares of New Common Stock out of the equity reserves established under the Plan for certain disputed claims against the company and UPC. The shares of New Common Stock were distributed pursuant to Section 1145 of the Bankruptcy Code (which generally exempts from registration under the federal and state securities laws the issuance of securities in exchange for interests in or claims against a debtor under a plan of reorganization). Pursuant to the Plan, all shares of New Common Stock were distributed in book-entry form through the facilities ofThe Depository Trust Company (DTC).
Warrants
Each holder of the Old Common Stock outstanding before the Effective Date that did not opt out of the release under the Plan, is entitled to receive 0.03460447 warrants for every share of Old Common Stock owned. Each warrant will initially be exercisable for one share of New Common Stock, subject to adjustment as provided in the Warrant Agreement. The exercise price of the Warrants will be determined, and the Warrants will become exercisable, once the Debtors have completed the claims reconciliation process and resolved any objections to disputed claims under the Bankruptcy Petitions. The initial exercise price per share for the Warrants will be set at an amount that implies a recovery by holders of the Subordinated Notes of the$650 million principal amount of the Subordinated Notes plus interest thereon to theMay 15, 2021 maturity date of the Notes. The Warrants expire on the earliest of (i)September 3, 2027 , (ii) consummation of a Cash Sale (as defined in the Warrant Agreement) or (iii) the consummation of a liquidation, dissolutions or winding up of the company (such earliest date, the Expiration Date). Each Warrant that is not exercised on or before the Expiration Date will expire, and all rights under that Warrant and the Warrant Agreement will cease on the Expiration Date. The warrants issued to holders of the company's Old Common Stock that did not opt-out of the releases under the Plan and that owned their shares of old common stock through Direct Registration are outlined below: Issuance Date Warrants IssuedDecember 21, 2020 1,770,552February 11, 2021 42,511July 29, 2021 10,521October 13, 2021 5,005 Total 1,828,589 The company expects to issue approximately 14,729 more Warrants to the holders of the Old Common Stock that did not opt-out of the releases under the Plan and owned their shares through Direct Registration. 43 -------------------------------------------------------------------------------- Table of Contents Financial Condition and Liquidity
Summary
Our financial condition and liquidity primarily depend on the cash flow from our
operations and borrowings under our credit agreements. The principal factors
determining our cash flow are:
•the amount of natural gas, oil, and NGLs we produce;
•the prices we receive for our natural gas, oil, and NGLs production;
•the use of our drilling rigs and the rates we receive for those drilling rigs;
and
•the fees and margins we obtain from our natural gas gathering and processing
contracts.
We currently expect that cash and cash equivalents, cash generated from
operations, and available funds under the Exit credit agreement and the Superior
credit agreement are adequate to cover our liquidity requirements for at least
the next 12 months.
Below is a summary of certain financial information for the periods indicated:
Successor Successor Predecessor
Nine Months
Ended September One Month Ended Eight Months Ended Percent
30, 2021 September 30, 2020 August 31, 2020 Change (1)
(In thousands except percentages)
Net cash provided by (used in) operating
activities $ 124,426 $ 9,674 $ 44,956 128 %
Net cash provided by (used in) investing
activities 50,233 (1,022) (20,139) NM
Net cash provided by (used in) financing
activities (137,807) (4,350) 7,552 NM
Net increase (decrease) in cash, restricted
cash and cash equivalents $ 36,852 $ 4,302 $ 32,369
_________________________1.NM - A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
Cash Flows from Operating Activities
Our operating cash flow is primarily influenced by the prices we receive for our oil, NGLs, and natural gas production, the oil, NGL, and natural gas we produce, settlements of derivative contracts, third-party use for our drilling rigs and mid-stream services, and the rates we can charge for those services. Our cash flows from operating activities are also affected by changes in working capital. Net cash provided by (used in) operating activities in the first nine months of 2021 increased by$69.8 million as compared to the first nine months of 2020. The increase resulted from increased operating profit in all three segments partially offset by changes in operating assets and liabilities related to the timing of cash receipts and disbursements.
Cash Flows from Investing Activities
We have historically dedicated a substantial portion of our capital budgets to our exploration for and production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells. Although we have curtailed our spending throughout 2020 and into 2021, we expect the majority of future capital budgets to be focused on low cost capital projects to enhance production and reserves in this favorable price environment. Net cash provided by (used in) investing activities increased by$71.4 million for the first nine months of 2021 compared to the first nine months of 2020. The change was primarily due to proceeds received from the disposition of our corporate headquarters building and land, an increase in proceeds received from the disposition of other non-core assets, and a decrease in capital expenditures resulting from a decrease in the number of wells drilled and oil and gas property acquisitions. 44
-------------------------------------------------------------------------------- Table of Contents Cash Flows from Financing Activities Net cash provided by (used in) financing activities decreased by$141.0 million for the first nine months of 2021 compared to the first nine months of 2020. The decrease was primarily due to higher payments on our credit agreements, lower net borrowings under our credit agreements, distributions made to non-controlling interests, the repurchase of common stock, and lower bank overdrafts. AtSeptember 30, 2021 , we had unrestricted cash and cash equivalents totaling$49.6 million , which includes$12.3 million of cash and cash equivalents held by Superior, and$3.1 million of outstanding borrowings, all of which was borrowed under the Superior credit agreement. Unit had no outstanding borrowings under the Exit credit agreement.
Below, we summarize certain financial information as of
Successor Successor
2021 2020
(In thousands)
Working capital $ (30,367) $ 21,624
Current portion of long-term debt $ - $ 400
Long-term debt $ 3,100 $ 143,600
Shareholders' equity attributable to Unit Corporation $ 149,504 $ 188,364
Working Capital
Typically, our working capital balance fluctuates, in part, because of the
timing of our trade accounts receivable and accounts payable and the fluctuation
in current assets and liabilities associated with the mark to market value of
our derivative activity. We had negative working capital of $30.4 million and
positive working capital of $21.6 million as of September 30, 2021 and 2020,
respectively. The decrease in working capital is primarily due to higher current
derivative liabilities, warrant liability, and accounts payable, partially
offset by increases in cash and cash equivalents and accounts receivable. The
effect of our derivative contracts decreased working capital by $60.0 million as
of September 30, 2021 and increased working capital by $1.3 million as of
September 30, 2020 .
Our Credit Agreements
Exit Credit Agreement. On the Effective Date, under the terms of the Plan, the company entered into an amended and restated credit agreement (the Exit credit agreement), providing for a$140.0 million senior secured revolving credit facility (RBL Facility) and a$40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC (together, the Borrowers), (ii) the guarantors party thereto, including the company and all of its subsidiaries existing as of the Effective Date (other thanSuperior Pipeline Company, L.L.C. and its subsidiaries), (iii) the lenders party thereto from time to time (Lenders), and (iv)BOKF, NA dbaBank of Oklahoma as administrative agent and collateral agent (in such capacity, the Administrative Agent). The maturity date of borrowings under this Exit credit agreement isMarch 1, 2024 . Our Exit credit agreement is primarily used for working capital purposes as it limits the amount that can be borrowed for capital expenditures. These limitations restrict future capital projects using the Exit credit agreement. The Exit credit agreement also requires that proceeds from the disposition of certain assets be used to repay amounts outstanding.
At
OnApril 6, 2021 , the company finalized the first amendment to the Exit credit agreement. Under the first amendment, the company reaffirmed its borrowing base of$140.0 million of the RBL, amended certain financial covenants, and received less restrictive terms as it relates to the disposition of assets and the use of proceeds from those dispositions. OnJuly 27, 2021 , the company finalized the second amendment to the Exit credit agreement. Under the second amendment, the company obtained confirmation that the Term Loan had been paid in full prior to the amendment date and received one-time waivers related to the disposition of assets. 45 -------------------------------------------------------------------------------- Table of Contents OnOctober 19, 2021 , the company finalized the third amendment to the Exit credit agreement. Under the third amendment, the company requested, and was granted, a reduction in the RBL borrowing base from$140.0 million to$80.0 million in addition to less restrictive terms as it relates to capital expenditures, required hedges, and the use of proceeds from the disposition of certain assets, while also amending certain financial covenants. Superior Credit Agreement. OnMay 10, 2018 , Superior signed a five-year,$200.0 million senior secured revolving credit facility with an option to increase the credit amount up to$250.0 million , subject to certain conditions (Superior credit agreement). The maturity date of borrowings under the Superior credit agreement isMarch 10, 2023 . As ofSeptember 30, 2021 , we had$3.1 million of borrowings and$1.4 million of letters of credit outstanding under the Superior credit agreement. Capital Requirements Oil and Natural Gas Segment Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this segment are discretionary and directed toward growth. Our decisions to increase our oil, NGLs, and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential, and opportunities to obtain financing, which provide us flexibility in deciding when and if to incur these costs. We participated in the completion of 10 gross wells (0.77 net wells) drilled by other operators in the first nine months of 2021 compared to 27 gross wells (6.16 net wells) drilled by other operators in which we participated in the first nine months of 2020. Capital expenditures for oil and gas properties on the full cost method for the first nine months of 2021 by this segment, excluding a$1.6 million increase in the ARO liability, totaled$7.1 million . Capital expenditures for the first nine months of 2020, excluding$0.4 million for acquisitions and a$28.2 million reduction in the ARO liability, totaled$10.3 million . OnJune 25, 2021 , the company entered into a purchase and sale agreement to which we agreed to sell substantially all of our wells and the leases related thereto located nearOklahoma City, Oklahoma for$19.5 million , subject to customary closing and post-closing adjustments. The divestiture closed onAugust 16, 2021 , with an effective date ofMay 1, 2021 . The sale of these assets did not result in a significant alteration of the full cost pool, and therefore no gain or loss was recognized. OnMarch 30, 2021 , the company entered into a purchase and sale agreement to which we agreed to sell substantially all of our wells and the leases related thereto located inReno andStafford Counties,Kansas for$7.1 million , subject to customary closing and post-closing adjustments. This divestiture closed onMay 6, 2021 , with an effective date ofFebruary 1, 2021 . The sale of these assets did not result in a significant alteration of the full cost pool and therefore, no gain or loss was recognized. We sold$5.0 million of other non-core oil and natural gas assets, net of related expenses, during the nine months endedSeptember 30, 2021 , compared to$1.2 million during the eight months endedAugust 31, 2020 and none during the one month endedSeptember 30, 2020 . These proceeds reduced the net book value of our full cost pool with no gain or loss recognized. Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. For 2021, capital expenditures are expected to primarily be for maintenance capital on operating drilling rigs. We also plan to pursue the disposal or sale of our non-core, idle drilling rig fleet. We incurred$0.9 million in capital expenditures during the first nine months of 2021, compared to$4.0 million for capital expenditures during the first nine months of 2020. We sold non-core contract drilling assets for proceeds of$8.2 million , net of related expenses, during the nine months endedSeptember 30, 2021 , compared to proceeds of$4.8 million during the eight months endedAugust 31, 2020 and none during the one month endedSeptember 30, 2020 . These proceeds resulted in net gains of$5.2 million during the nine months endedSeptember 30, 2021 , compared to$1.4 million during the eight months endedAugust 31, 2020 . Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. During the first nine months of 2021, our mid-stream segment incurred$8.6 million in capital expenditures as compared to$10.2 million in the first nine months of 2020. For 2021, we estimate total capital expenditures of approximately$24.2 million , primarily for the gas gathering and processing assets acquired inNovember 2021 as well as the maintenance and operation of our assets, and connection of new wells.
Derivative Activities
Periodically we enter into derivative transactions locking in the prices to be received for a portion of our oil, NGLs, and natural gas production.
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Commodity Derivatives. Our commodity derivatives are intended to reduce our
exposure to price volatility and manage price risks. Our decision on the type
and quantity of our production and the price(s) of our derivative(s) is based,
in part, on our view of current and future market conditions. At September 30,
2021 , based on our third quarter 2021 average daily production, the approximated
percentages of our production under derivative contracts are as follows:
2021 2022 2023
Daily oil production 87% 64% 36%
Daily natural gas production 63% 54% 30%
The use of derivative transactions carries with it the risk that the counterparties may not be able to meet their financial obligations under the transactions. Based on ourSeptember 30, 2021 evaluation, we believe the risk of non-performance by our counterparties is not material. AtSeptember 30, 2021 , the fair values of the net liabilities we had with each of the counterparties to our commodity derivative transactions are as follows: September 30, 2021 (In thousands) Bank of Oklahoma $ (87,826) Bank of Montreal (205) Total net liabilities $ (88,031)
Below is the effect of derivative instruments on the unaudited condensed consolidated statements of operations for the periods indicated:
Successor Successor Predecessor Successor Predecessor
Three Months Nine Months
Ended September One Month Ended Two Months Ended Ended September Eight Months Ended
30, 2021 September 30, 2020 August 31, 2020 30, 2021 August 31, 2020
(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included
are amounts settled during the period
of $(12,940) , $(1,418) , $(3,552) ,
$(22,647) , and $(4,244) , respectively $ (39,742) $ 3,939 $ (4,250) $ (104,973) $ (10,704)
$ (39,742) $ 3,939 $ (4,250) $ (104,973) $ (10,704)
47-------------------------------------------------------------------------------- Table of Contents Results of Operations Quarter EndedSeptember 30, 2021 versus Quarter EndedSeptember 30, 2020 Provided below is a comparison of selected operating and financial data: Successor Successor Predecessor Quarter Ended One Month Ended Two Months Ended Percent September 30, 2021 September 30, 2020 August 31, 2020 Change (1) (In thousands unless otherwise specified) Total revenue, before inter-segment eliminations$ 177,382 $ 35,342 $ 69,779 69 % Total revenue, after inter-segment eliminations$ 163,248 $ 32,846 $ 65,574 66 % Net income (loss)$ (2,805) $ (6,736) $ 128,615
(102) %
Net income (loss) attributable to non-controlling interest
$ 2,232 $ 73,484 (112) % Net income (loss) attributable to Unit Corporation$ 6,295 $ (8,968) $ 55,131
(86) %
Oil and Natural Gas : Revenue, before inter-segment eliminations$ 66,202 $ 13,644 $ 27,962 59 % Operating costs, before inter-segment eliminations$ 22,022 $ 6,892 $ 15,895 (3) % Average oil price (Bbl)$ 47.66 $ 28.11 $ 28.64 67 % Average oil price excluding derivatives (Bbl)$ 70.53 $ 36.94 $ 38.55 86 % Average NGLs price (Bbl)$ 27.42 $ 7.47 $ 8.53 NM Average NGLs price excluding derivatives (Bbl)$ 27.42 $ 7.47 $ 8.53 NM Average natural gas price (Mcf)$ 2.88 $ 1.72 $ 1.07 125 % Average natural gas price excluding derivatives (Mcf)$ 3.69 $ 1.70 $ 1.10 186 % Oil production (MBbls) 329 167 341 (35) % NGL production (MBbls) 649 273 572 (23) % Natural gas production (MMcf) 6,805 2,849 6,184
(25) %
Contract Drilling: Revenue, before inter-segment eliminations$ 19,158 $ 4,414 $ 7,685 58 % Operating costs, before inter-segment eliminations$ 15,357 $ 2,989 5,410 83 % Average number of drilling rigs in use 11.0 6.0 4.6
116 % Total drilling rigs available for use at the end of the period
21 58 58 (64) %
Average dayrate on daywork contracts $ 17,502 $ 17,361 $ 16,596 4 %
Mid-Stream:
Revenue, before inter-segment eliminations$ 92,022 $ 17,284 $ 34,132 79 % Operating costs, before inter-segment eliminations$ 76,823 $ 12,130 $ 21,620 128 % Gas gathered--Mcf/day 318,304 345,460 363,465 (11) % Gas processed--Mcf/day 128,161 145,263 149,483 (13) % Gas liquids sold--gallons/day 456,971 473,371 699,647 (27) % Number of natural gas gathering systems 17 18 18 (6) % Number of processing plants 11 11 11 - % Corporate and Other: General and administrative expense, before inter-segment eliminations$ 4,246 $ 1,582 $ 5,399 (39) % Other income (expense): Interest expense, net$ (702) $ (826) $ (1,959) (75) % Reorganization items, net$ (971) $ (1,155) $ 141,002 101 % Gain (loss) on derivatives$ (39,742) $ 3,939 $ (4,250) NM Loss on change in fair value of warrants$ (9,054) $ - $ - - % Income tax benefit $ - $ -$ (4,750) 100 % Average interest rate 6.5 % 5.9 % 2.7 % 76 % Average long-term debt outstanding$ 18,393 $ 146,267 $ 160,039 (88) %
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1.NM - A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
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Oil and Natural Gas
Oil and natural gas revenues increased $24.6 million or 59% in the third quarter
of 2021 as compared to the third quarter of 2020 primarily due to higher
commodity prices, partially offset by lower production volumes. In the third
quarter of 2021, as compared to the third quarter of 2020, oil production
decreased 35%, natural gas production decreased 25%, and NGLs production
decreased 23%. The decrease in volumes was due to normal well production
declines and divestitures of producing properties which have not been offset by
new drilling or acquisitions. Including derivatives settled, average oil prices
increased 67% to $47.66 per barrel, average natural gas prices increased 125% to
$2.88 per Mcf, and NGLs prices increased over 200% to $27.42 per barrel.
Oil and natural gas operating costs decreased 0.8 million or 3% between the
comparative third quarters of 2021 and 2020 primarily due to the settlement of
Predecessor Period liabilities subject to compromise under the Plan offset by
increased production tax expenses due to increased revenues.
Contract Drilling
Drilling revenues increased$7.1 million or 58% in the third quarter of 2021 versus the third quarter of 2020. The increase was driven primarily by an increase in average number of rigs in use from 5.1 in the third quarter of 2020 to 11.0 in the third quarter of 2021. Drilling operating costs increased$7.0 million or 83% between the comparative third quarters of 2021 and 2020. The change was primarily due to an increase in the average number of operating rigs and the associated start up costs bringing stacked rigs back into service.
Mid-Stream
Our mid-stream revenues increased$40.6 million or 79% in the third quarter of 2021 as compared to the third quarter of 2020 primarily due to higher gas, NGL, and condensate prices, partially offset by lower volumes. Gas processed volumes per day decreased 13% between the comparative quarters primarily due to connecting fewer new wells and declining volumes on most of our major processing systems. Gas gathered volumes per day decreased 11% between the comparative quarters due to declining volumes and fewer new well connections.
Operating costs increased 43.1 million or 128% in the third quarter of 2021 compared to the third quarter of 2020 primarily due to higher gas, NGL, and condensate prices, partially offset by lower purchase volumes.
General and Administrative
Corporate general and administrative expenses decreased$2.7 million or 39% in the third quarter of 2021 as compared to the third quarter of 2020 primarily due to reductions in payroll and benefits as well as the absence of separation benefits recognized in the third quarter of 2020.
Other Income (Expense)
Interest expense decreased$2.1 million between the comparative third quarters of 2021 and 2020 primarily due to an 88% decrease in average long-term debt outstanding, partially offset by a higher average interest rate. Our average interest rate increased from 3.7% in the third quarter of 2020 to 6.5% in the third quarter of 2021 and our average debt outstanding decreased$137.2 million in the third quarter of 2021 compared to the third quarter of 2020 primarily due to payments made under the Exit credit agreement, partially offset by borrowings under the Superior credit agreement.
Reorganization Items, Net
Reorganization items, net represent any of the expenses, gains, and losses incurred subsequent to and as a direct result of the Chapter 11 proceedings.
Loss on Derivatives
Loss on derivatives increased by
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Loss on Change in Fair Value of Warrants
Loss on change in fair value of warrants increased by$9.1 million primarily due to changes in the underlying assumptions used to estimate the fair value, including estimated strike price, entity value, duration to exercise and other inputs. Income Tax Benefit We did not record an income tax benefit in the third quarter of 2021 compared to$4.8 million in the third quarter of 2020 due to the company's full valuation allowance against our net deferred tax asset. We paid no income taxes in the third quarter of 2021. 50
-------------------------------------------------------------------------------- Table of Contents Results of Operations Nine Months EndedSeptember 30, 2021 versus Nine Months EndedSeptember 30, 2020 Provided below is a comparison of selected operating and financial data: Successor Successor Predecessor Nine Months Ended One Month Ended Eight Months Ended
Percent
September 30, 2021 September 30, 2020 August 31st, 2020 Change (1)
(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations $ 451,850 $ 35,342 $ 291,493 38 %
Total revenue, after inter-segment eliminations $ 418,202 $ 32,846 $ 276,957 35 %
Net loss $ (13,511) $ (6,736) $ (890,624) 99 %
Net income (loss) attributable to non-controlling interest
$ 2,232 $ 40,388 (111) % Net loss attributable to Unit Corporation$ (8,636) $ (8,968) $ (931,012) 99 % Oil and Natural Gas: Revenue, before inter-segment eliminations$ 181,003 $ 13,644 $ 103,443 55 % Operating costs, before inter-segment eliminations$ 58,365 $ 6,892 $ 119,664 (54) % Average oil price (Bbl)$ 47.77 $ 28.11 $ 32.02 51 % Average oil price excluding derivatives (Bbl)$ 63.15 $ 36.94 $ 35.18 79 % Average NGLs price (Bbl)$ 21.10 $ 7.47 $ 4.83 NM Average NGLs price excluding derivatives (Bbls)$ 21.10 $ 7.47 $ 4.83 NM Average natural gas price (Mcf)$ 2.87 $ 1.72 $ 1.14 139 % Average natural gas price excluding derivatives (Mcf)$ 3.12 $ 1.70 $ 1.11 167 % Oil production (MBbls) 1,130 167 1,560 (35) % NGLs production (MBbls) 1,952 273 2,399 (27) % Natural gas production (MMcf) 21,750 2,849 26,561 (26) % Contract Drilling: Revenue, before inter-segment eliminations$ 52,893 $ 4,414 $ 73,519 (32) % Operating costs, before inter-segment eliminations$ 41,308 $ 2,989 $ 51,811 (25) % Average number of drilling rigs in use 10.1 6.0 11.5
(7) % Total drilling rigs available for use at the end of the period
21 58 58 (64) %
Average dayrate on daywork contracts $ 17,944 $ 17,361 $ 18,911 (5) %
Mid-Stream:
Revenue, before inter-segment eliminations$ 217,954 $ 17,284 $ 114,531 65 % Operating costs, before inter-segment eliminations$ 181,109 $ 12,130 $ 80,607 95 % Gas gathered--Mcf/day 300,484 345,460 388,506 (22) % Gas processed--Mcf/day 124,263 145,263 158,031 (21) % Gas liquids sold--gallons/day 431,474 473,371 612,301 (28) % Number of natural gas gathering systems 17 18 18 (6) % Number of processing plants 11 11 11 - % Corporate and Other: General and administrative expense, before inter-segment eliminations$ 15,406 $ 1,582 $ 42,766 (65) % Other income (expense): Interest expense, net$ (3,895) $ (826) $ (22,882) (84) % Write-off of debt issuance costs $ - $ -$ (2,426) (100) % Reorganization items, net$ (3,959) $ (1,155) $ 133,975 (103) % Gain (loss) on derivatives$ (104,973) $ 3,939 $ (10,704) NM Loss on change in fair value of warrants$ (12,628) $ - $ - - % Income tax benefit $ - $ -$ (14,630) 100 % Average interest rate 6.7 % 5.9 % 5.5 % 21 % Average long-term debt outstanding$ 57,815 $ 146,267 $ 526,167 (88) %
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1.NM - A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
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Oil and Natural Gas
Oil and natural gas revenues increased $63.9 million or 55% in the first nine
months of 2021 as compared to the first nine months of 2020 primarily due to
higher commodity prices partially offset by lower production volumes. The
decrease in volumes was due to normal well production declines and divestitures
of producing properties which have not been offset by new drilling or
acquisitions.
Oil and natural gas operating costs decreased 68.2 million or 54% between the
comparative first nine months of 2021 and 2020 primarily due to the settlement
of Predecessor Period liabilities subject to compromise under the Plan offset by
increased production tax expenses due to increased revenues.
Contract Drilling
Drilling revenues decreased$25.0 million or 32% in the first nine months of 2021 versus the first nine months of 2020. The decrease was due primarily to lower rig termination and standby fees of$0.1 million in 2021 compared to$16.7 million in 2020. Additionally, there was a 7% decrease in the average number of drilling rigs in use and a 5% decrease in the average dayrate. Average drilling rig utilization decreased from 10.9 drilling rigs in the first nine months of 2020 to 10.1 drilling rigs in the first nine months of 2021.
Drilling operating costs decreased 13.5 million or 25% between the comparative first nine months of 2021 and 2020. The decrease was due primarily to the reduced number of drilling rigs operating.
Mid-Stream
Our mid-stream revenues increased$86.1 million or 65% in the first nine months of 2021 as compared to the first nine months of 2020 primarily due to higher prices, partially offset by lower volumes. Gas processed volumes per day decreased 21% between the comparative periods primarily due to declining volumes and fewer new wells connected to our processing systems. Gas gathered volumes per day decreased 22% between the comparative periods also due to declining volumes and fewer new wells connected to our gathering systems. We also experienced overall lower volumes due to theFebruary 2021 winter storm. Operating costs increased 88.4 million or 95% in the first nine months of 2021 compared to the first nine months of 2020 primarily due to higher gas, NGLs, and condensate prices, partially offset by lower purchase volumes.
General and Administrative
Corporate general and administrative expenses decreased$28.9 million or 65% in the first nine months of 2021 as compared to the first nine months of 2020 primarily due to reductions in payroll and benefits, the absence of separation benefits recognized in the third quarter of 2020 as well as lower legal and office spend.
Other Income (Expense)
Interest expense decreased$19.8 million between the comparative first nine months of 2021 and 2020 primarily due to a reduction in average long-term debt outstanding, partially offset by a higher average interest rate. Our average interest rate increased from 5.5% in the first nine months of 2020 to 6.7% in the first nine months of 2021 and our average debt outstanding decreased$426.8 million in the first nine months of 2021 compared to the first nine months of 2020 primarily due to the Notes being settled with the Plan and payments made under the Exit credit agreement.
Write-off of Debt Issuance Costs
Due to the termination of the remaining commitments of the Predecessor Period
Unit credit agreement, unamortized debt issuance costs of
Reorganization Items, Net
Reorganization items, net represent any of the expenses, gains, and losses incurred subsequent to and as a direct result of the Chapter 11 proceedings.
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Loss on Derivatives
Loss on derivatives increased by
Loss on Change in Fair Value of Warrants
Loss on change in fair value of warrants increased by$12.6 million primarily due to changes in the underlying assumptions used to estimate the fair value, including estimated strike price, entity value, duration to exercise and other inputs. Income Tax Benefit We did not record an income tax benefit in the first nine months of 2021 compared to$14.6 million in the first nine months of 2020 due to the company's full valuation allowance against our net deferred tax asset. We paid no income taxes in the first nine months of 2021.
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