UNIT CORPORATION Management's Discussion and Analysis (MD&A) provides you with an understanding of our operating results and financial condition by focusing on changes in certain key measures from year to year or period to period. MD&A is organized into these sections: •General; •Recent Developments; •Business Outlook; •Executive Summary; •Financial Condition and Liquidity; •New Accounting Pronouncements; and •Results of Operations.
Please read the information in our most recent Annual Report on Form 10-K as part of your review of the information below and our unaudited condensed consolidated financial statements and related notes.
Unless otherwise indicated or required by the content, when used in this report the terms "company," "Unit," "us," "our," "we," and "its" refer toUnit Corporation or, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refers toSuperior Pipeline Company, L.L.C. of which we presently own 50%. General
We operate, manage, and analyze the results of our operations through our three principal business segments:
•Oil and Natural Gas - carried out by our subsidiaryUnit Petroleum Company (UPC). This segment explores, develops, acquires, and produces oil and natural gas properties for our own account. •Contract Drilling - carried out by our subsidiaryUnit Drilling Company (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 for third parties and for our own account. We presently own 50% of this subsidiary.
In addition to the companies identified above, our corporate headquarters is
owned by our wholly owned subsidiary
Recent Developments
Emergence From Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
OnMay 22, 2020 (Petition Date), Unit and its wholly owned subsidiaries UDC, UPC, 8200 Unit, Unit Drilling Colombia, andUnit Drilling USA filed Bankruptcy Petitions for reorganization under Chapter 11 of Title 11 ofthe United States Code (Bankruptcy Code) in theUnited States Bankruptcy Court for the Southern District of Texas , Houston Division (Bankruptcy Court ). The Chapter 11 proceedings were jointly administered under the caption In reUnit Corporation , et al., Case No. 20-32740 (DRJ) (Chapter 11 Cases). During the pendency of the Chapter 11 Cases, the Debtors operated their business as "debtors-in-possession" under the jurisdiction of theBankruptcy Court and under the provisions of the Bankruptcy Code and orders of theBankruptcy Court . The Debtors filed a Chapter 11 plan of reorganization (including all exhibits and schedules, and as may be amended, supplemented, or modified from time to time, the Plan) and the related disclosure statement with theBankruptcy Court onJune 9, 2020 . OnAugust 6, 2020 , theBankruptcy Court entered the "Findings of Fact, Conclusions of Law, and Order (I) Approving the Disclosure Statement on a Final Basis and (II) Confirming the Debtors' Amended Joint Chapter 11 Plan of Reorganization" [Docket No. 340] (Confirmation Order) confirming the Plan. OnSeptember 3, 2020 (Effective Date), the Debtors emerged from the Chapter 11 Cases. For more information regarding the Chapter 11 Cases and other related matters, please read Note 2 - Emergence From Voluntary Reorganization Under Chapter 11. 60
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Going Concern
AtJune 30, 2020 , the significant risks and uncertainties related to the company's liquidity and Chapter 11 Cases raised substantial doubt about the company's ability to continue as a going concern. The company, therefore, concluded as of that date there was substantial doubt about the company's ability to continue as a going concern. The company has since implemented changes that (i) minimize capital expenditures, (ii) aggressively manage working capital, and (iii) reduce recurring operating expenses. With the successful reorganization of our capital structure, in addition to these actions, there is no longer substantial doubt about the company's ability to continue as a going concern. Fresh Start Accounting In connection with emergence from the Chapter 11 Cases on the Effective Date, the company qualified for and adopted fresh start accounting in accordance with the provisions set forth in FASB Topic ASC 852 as (i) the reorganization value of the company's assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor prior to emergence received less than 50% of the voting shares of the emerging entity. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements of the Successor will not be comparable to the financial statements prepared before the Effective Date.
Changes in Accounting Policies
On emergence from bankruptcy, the company elected to change the accounting policies related to depreciation of fixed assets of our Contract Drilling segment and the allocation of earnings and losses between Unit and its partners in Superior.
In regards to our Contract Drilling segment, as of emergence, the company elected to depreciate all drilling assets using the straight-line method over the useful lives of the assets ranging from four to ten years.
On emergence, the company also elected to begin allocating earnings and losses between Unit and the partners in Superior using the Hypothetical Liquidation at Book Value (HLBV) method of accounting.
Leadership Changes
OnOctober 22, 2020 ,David T. Merrill stepped down as President, Chief Executive Officer and Director of the company.Philip B. Smith , the company's Chairman, currently serves as the company's President and Chief Executive Officer.
On
On
On
On
On
OnDecember 31, 2020 ,Don Hayes retired as Vice President and Chief Accounting Officer of the company. He was replaced byThomas Sell , who also serves as our Interim Chief Financial Officer.
For further information on the above leadership changes, please see the
company's Current Reports on Form 8-K filed on
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Delisting of Our Common Stock from the NYSE
On May 26, 2020 , trading in our common stock on the New York Stock Exchange
(NYSE) was suspended because of the Debtors' filing of the Chapter 11 Cases.
Effective May 27, 2020 , trades in our common stock began being quoted on the OTC
Pink Marketplace . On June 10, 2020 , the NYSE filed a Form 25 to delist our
common stock and deregister it under Section 12(b) of the Securities Exchange
Act of 1934, as amended (Exchange Act). On the Debtors' emergence from the
Chapter 11 Cases, the shares of Predecessor common stock outstanding immediately
before the Effective Date were cancelled.
Business Outlook
Post-Emergence Strategy
Our post-emergence strategy is focused on value accretion through generation of free cash flows, repayment of debt, and selective investment in each business segment. Investments are expected to be funded using free cash flows from operations, proceeds from divestments of non-core assets, and available capacity under the Exit credit agreement, all subject to the various terms and conditions of the Exit credit agreement as referenced in Note 9 - Long-Term Debt and Other Long-Term Liabilities. In our oil and natural gas segment we plan to optimize production and convert non-producing reserves to producing, with no exploratory drilling currently planned. We also plan to divest non-core properties and use those proceeds along with free cash flows to acquire producing properties in our core areas. In our contract drilling segment we plan to focus on utilization of our BOSS drilling rigs, as well as upgrades to certain of our SCR drilling rigs. We also plan to continue seeking opportunities to divest non-core, idle drilling equipment. In our mid-stream segment we plan to focus on 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 is not guaranteed by Unit) or other financing sources that are available to it.
COVID-19 Pandemic and Commodity Price Environment
As discussed in other parts of this report, among other things, our success depends, to a large degree, on the 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 withinthe United States , events outsidethe United States affect us and our industry. We are continuously monitoring the current and potential impacts of the COVID-19 pandemic on our business. This includes how it has and may continue to impact our operations, financial results, liquidity, customers, employees, and vendors. In response to the pandemic, we have reduced capital expenditures and implemented various measures to ensure we are conducting our business in a safe and secure manner. COVID-19 and the response of governments throughout the world to contain the pandemic have contributed to an economic downturn, reduced demand for oil and natural gas, and together with a price war betweenSaudi Arabia andRussia , depressed oil and natural gas prices to historically low levels. In April, theOrganization of the Petroleum Exporting Countries (OPEC),Russia and certain other oil producing states (commonly referred to as OPEC Plus) agreed to cut oil production by 9.7 million barrels per day in May andJune 2020 , however, in July, they agreed to increase production by 1.6 million barrels per day starting inAugust 2020 . With the combined effects of the increased production levels earlier in 2020, the recent increase in production and the reduction in demand caused by COVID-19, the global oil and natural gas supply and demand imbalance persists and continues to have a significant adverse effect on the oil and gas industry. During the last three years, commodity prices have been volatile. Our oil and natural gas segment used two to three drilling rigs throughout 2017. With improved commodity prices during the first quarter of 2018, our oil and natural gas segment put four of our drilling rigs to work and increased the number to six drilling rigs for a brief period during the third quarter of 2018. We reduced our operated rig count in the fourth quarter of 2018 and the first quarter of 2019 before getting as high as six drilling rigs again in the second quarter of 2019. Due to declining prices we shut down our drilling program inJuly 2019 and used no drilling rigs the remainder of 2019 or the first nine months of 2020. 62 -------------------------------------------------------------------------------- Table of Contents The following chart reflects the significant fluctuations in the prices for oil and natural gas:
[[Image Removed: unt-20200930_g2.jpg]] The following chart reflects the significant fluctuations in the prices for NGLs:
[[Image Removed: unt-20200930_g3.jpg]] _________________________ 1.NGLs prices reflect a weighted-average, based on production, ofMont Belvieu andConway prices. 63
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Table of Contents Executive SummaryOil and Natural Gas Third quarter 2020 production from our oil and natural gas segment was 2,858,000 barrels of oil equivalent (Boe), a decrease of 5% from the second quarter of 2020 and a decrease of 35% from the third quarter of 2019. The decreases came from fewer net wells being drilled in the nine months endedSeptember 30, 2020 to replace declines in existing drilled wells. Third quarter 2020 oil and natural gas revenues increased 54% over the second quarter of 2020 and decreased 47% from the third quarter of 2019. The increase over the second quarter of 2020 was primarily due to an increase in commodity prices partially offset by a decrease in production. The decrease from the third quarter of 2019 was primarily from a decrease in commodity prices and production.
Our oil prices for the third quarter of 2020 increased 81% over the second quarter of 2020 and decreased 33% from the third quarter of 2019. Our NGLs prices increased 99% over the second quarter of 2020 and decreased 4% from the third quarter of 2019. Our natural gas prices increased 19% over the second quarter of 2020 and decreased 30% from the third quarter of 2019.
Operating cost per Boe produced for the third quarter of 2020 decreased 67% from the second quarter of 2020 and decreased 4% from the third quarter of 2019. The decreases were primarily due to the estimated$45.0 million litigation accrual in the second quarter of 2020.
At
Weighted Average
Term Commodity Contracted Volume Fixed Price Contracted Market
Oct'20 - Dec'20 Natural gas - basis swap 30,000 MMBtu/day $(0.275) NGPL TEXOK
Oct'20 - Dec'20 Natural gas - basis swap 20,000 MMBtu/day $(0.455) PEPL
Jan'21 - Dec'21 Natural gas - basis swap 30,000 MMBtu/day $(0.215) NGPL TEXOK
Oct'20 - Dec'20 Natural gas - swap 30,000 MMBtu/day $2.753 IF - NYMEX (HH)
Jan'21 - Oct'21 Natural gas - swap 50,000 MMBtu/day $2.818 IF - NYMEX (HH)
Nov'21 - Dec'21 Natural gas - swap 75,000 MMBtu/day $2.880 IF - NYMEX (HH)
Jan'22 - Dec'22 Natural gas - swap 5,000 MMBtu/day $2.605 IF - NYMEX (HH)
Jan'23 - Dec'23 Natural gas - swap 22,000 MMBtu/day $2.456 IF - NYMEX (HH)
Oct'20 - Dec'20 Natural gas - collar 30,000 MMBtu/day $2.50 - $2.80 IF - NYMEX (HH)
Jan'22 - Dec'22 Natural gas - collar 35,000 MMBtu/day $2.50 - $2.68 IF - NYMEX (HH)
Oct'20 - Dec'20 Crude oil - swap 4,000 Bbl/day $43.35 WTI - NYMEX
Jan'21 - Dec'21 Crude oil - swap 3,000 Bbl/day $44.65 WTI - NYMEX
Jan'22 - Dec'22 Crude oil - swap 2,300 Bbl/day $42.25 WTI - NYMEX
Jan'23 - Dec'23 Crude oil - swap 1,300 Bbl/day $43.60 WTI - NYMEX
For the nine months ended September 30, 2020 , we participated in the completion
of 27 gross wells (6.16 net wells) drilled by other operators. We did not
participate in the completion of any wells during the third quarter of 2020. In
the fourth quarter, we plan to participate in the completion of one gross well
drilled by another operator.
Contract Drilling
The average number of drilling rigs we operated in the third quarter of 2020 was
5.1 compared to 9.1 and 20.4 in the second quarter of 2020 and the third quarter
of 2019, respectively. As of September 30, 2020 , six of our drilling rigs were
operating and two rigs were under stand-by contracts.
Revenue for the third quarter of 2020 decreased 59% from the second quarter of 2020 and decreased 68% from the third quarter of 2019. The decreases were primarily due to less drilling rigs operating.
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Dayrates for the third quarter of 2020 averaged $16,904 , an 8% decrease from the
second quarter of 2020 and a 12% decrease from the third quarter of 2019. The
decreases were both primarily due to less drilling rigs operating.
Operating costs for the third quarter of 2020 decreased 60% from the second quarter of 2020 and decreased 71% from the third quarter of 2019. The decreases were both primarily due to less drilling rigs operating.
We have five term drilling contracts with original terms ranging from six months to two years that are up for renewal after 2020. Term contracts may contain a fixed rate during the contract or provide for rate adjustments within a specific range from the existing rate. Some operators who had signed term contracts have opted to release the drilling rig early and pay an early termination penalty for the remaining term of the contract. Six of our 14 existing BOSS drilling rigs are under contract.
For 2020, we do not currently have an approved capital plan for this segment. Any capital expenditures incurred would be within anticipated cash flows.
Mid-Stream
Third quarter 2020 liquids sold per day decreased 2% from the second quarter of 2020 and increased 9% over the third quarter of 2019, respectively. The decrease from the second quarter of 2020 was due to lower purchased volumes due to fewer wells connected to our processing systems. The increase over the third quarter of 2019 was due to operating in ethane rejection for most of the third quarter of 2019 which resulted in lower amounts of liquids available for sale. For the third quarter of 2020, gas processed per day decreased 5% from the second quarter of 2020 and decreased 12% from the third quarter of 2019. The decreases were primarily due to declining volumes and fewer new well connects on our processing systems partially offset by increased gathered volume from theCashion system due to the acquisition at the end of 2019. For the third quarter of 2020, gas gathered per day decreased 12% from the second quarter of 2020 and decreased 17% from the third quarter of 2019, respectively. These decreases were due to declining volumes from most of our major systems and fewer well connects partially offset by increased gathered volume from theCashion system due to the acquisition at the end of 2019. NGLs prices in the third quarter of 2020 increased 45% over the prices received in the second quarter of 2020 and decreased 7% from the prices received in the third quarter of 2019. Because certain contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts, under which we receive a share of the proceeds from the sale of the NGLs, our revenues from those commodity-based contracts fluctuate based on the price of NGLs. Total operating cost for our mid-stream segment for the third quarter of 2020 increased 22% over the second quarter of 2020 and decreased 3% from the third quarter of 2019. The increase over the second quarter of 2020 was primarily due to higher purchase prices. The decrease from the third quarter of 2019 was primarily due to lower purchases prices along with less purchased volumes. At theCashion processing facility in centralOklahoma , total throughput volume for the third quarter of 2020 averaged approximately 75.5 MMcf per day and total production of natural gas liquids averaged approximately 354,000 gallons per day. Through the first nine months of 2020, we continued to connect new wells to this system for third party producers. Since the first of this year, we connected 14 new wells to this system from producers in the area. The acquired mid-continent production that was purchased at the end of 2019 is being processed at our Reeding facility on ourCashion system. Additionally, we are delivering thePerkins facility production to the Cashion Reeding facility. The total processing capacity on theCashion system is 105 MMcf per day. In the Appalachian region at the Pittsburgh Mills gathering system, average gathered volume for the third quarter of 2020 was 150.8 MMcf per day while the average gathered volume for second quarter of 2020 was approximately 181.8 MMcf per day as theBakerstown infill wells continue to decline. During the third quarter of 2020, we did not add any new wells to this system. At theHemphill processing facility located in theTexas panhandle, average total throughput volume for the third quarter of 2020 was 50.1 MMcf per day and total production of natural gas liquids averaged approximately 187,000 gallons per day. We did not connect any new wells to this system in the third quarter of 2020. At this time there are no active rigs in the area and we did not have any new well connects the rest of this year.
At the Segno gathering system located in
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third quarter of 2020, we did not connect any new wells to this system. We did
not connect any new wells to this system the rest of this year.
Anticipated 2020 capital expenditures for this segment will be approximately
Financial Condition and Liquidity
Summary
Our financial condition and liquidity depend on the cash flow from our operations and borrowings under our credit agreements. Our cash flow is based primarily on:
•the amount of natural gas, oil, and NGLs we produce; •the prices we receive for our natural gas, oil, and NGLs production; •the demand for and the dayrates we receive for our drilling rigs; and •the fees and margins we obtain from our natural gas gathering and processing contracts.
Our completion of the Chapter 11 Cases has allowed us to significantly reduce
our level of indebtedness and our future cash interest obligations. We currently
expect that cash and cash equivalents, cash generated from operations, and our
available funds under the Exit 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
(in thousands):
Successor Predecessor
One Month Eight Months Nine Months
Ended Ended Ended
September 30, August 31, September 30,
2020 2020 2019
Net cash provided by operating activities $ 9,674 $ 44,956 $ 219,450
Net cash used in investing activities (1,022) (20,139) (357,793)
Net cash provided by (used in) financing activities (4,350)
7,552 132,503
Net increase (decrease) in cash, restricted cash, and
cash equivalents $ 4,302 $ 32,369 $ (5,840) 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 quantity of oil, NGLs, and natural gas we produce, settlements of derivative contracts, and third-party demand for our drilling rigs and mid-stream services and the rates we obtain for those services. Our cash flows from operating activities are also affected by changes in working capital. Net cash provided by operating activities in the first nine months of 2020 decreased by$164.8 million as compared to the first nine months of 2019. The decrease was primarily due to lower revenues due to lower commodity prices and lower drilling rig utilization partially offset by an increase in 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 part of our capital budget to the exploration for and production of oil, NGLs, and natural gas. Those expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells. As previously noted, for 2020 we greatly restricted our capital spending in this segment. Net cash used in investing activities decreased by$336.6 million for the first nine months of 2020 compared to the first nine months of 2019. The change was due primarily to a decrease in capital expenditures due to decrease in operated wells drilled and a decrease in oil and gas property acquisitions partially offset by a decrease in the proceeds received from the disposition of assets. See additional information on capital expenditures below under Capital Requirements. 66 -------------------------------------------------------------------------------- Table of Contents Cash Flows from Financing Activities Net cash provided by (used in) financing activities decreased by$129.3 million for the first nine months of 2020 compared to the first nine months of 2019. The decrease was primarily due to a decrease in the net borrowings under our credit agreements and a decrease in bank overdrafts. AtSeptember 30, 2020 , we had unrestricted cash and cash equivalents totaling$29.8 million and had borrowed$132.0 million and$12.0 million of the amounts available under the Unit Exit credit agreement and Superior credit agreement, respectively. Below, we summarize certain financial information as ofSeptember 30, 2020 and 2019: Successor Predecessor September 30, September 30, % 2020 2019 Change (In thousands except percentages) Working capital$ 21,624 $ (56,116) 139 % Current portion of long-term debt $ 400 $ - - % Long-term debt (1)$ 143,600 $ 784,352 (82) %
Shareholders' equity attributable to
$ 1,188,747 (84) %
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1.In 2019, long-term debt is net of unamortized discount and debt issuance costs.
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 positive working capital of$21.6 million as ofSeptember 30, 2020 and negative working capital of$56.1 million as ofSeptember 30, 2019 . The increase in working capital is primarily due to more cash and cash equivalents and lower accounts payable and accrued liabilities due to the settlement of the liabilities subject to compromise partially offset by lower accounts receivable. The Superior credit agreement is used primarily for working capital and capital expenditures and the Exit credit agreement facility is used to primarily for working capital and has limitations on how much can be spent for capital expenditures. AtSeptember 30, 2020 , we had borrowed$131.6 million and$12.0 million under the Unit Exit credit agreement and Superior credit agreement, respectively. The effect of our derivative contracts increased working capital by$1.3 million as ofSeptember 30, 2020 and increased working capital by$6.0 million as ofSeptember 30, 2019 .
Long-Term Debt
Unit's Exit credit agreement facility is primarily used for working capital
purposes as it limits the amount that can be borrowed for capital expenditures.
These limitations will result in limited future capital projects utilizing the
Exit credit facility. The Exit credit facility also requires the company to use
proceeds from the disposition of certain assets to repay amounts outstanding.
This aligns with our free cash flow business model, enabling the company to
maintain reduced leverage through debt reduction in future periods.
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This table summarizes certain operating information:
Successor Predecessor Predecessor
One Month
Ended Eight Months Ended Nine Months Ended
September 30, August 31 September 30, %
2020 2020 2019 Change (1)
Oil and Natural Gas :
Oil production (MBbls) 167 1,562 2,341 (26) %
NGLs production (MBbls) 273 2,399 3,657 (27) %
Natural gas production (MMcf) 2,849 26,563 40,021 (27) %
Equivalent barrels (MBoe) 914 8,388 12,668 (27) %
Average oil price per barrel received $ 28.11 $ 31.98 $ 57.55 (45) %
Average oil price per barrel received excluding
derivatives $ 36.94 $ 35.14 $ 55.28 (36) %
Average NGLs price per barrel received $ 7.47 $ 4.83 $ 12.21 (58) %
Average NGLs price per barrel received excluding
derivatives $ 7.47 $ 4.83 $ 12.21 (58) %
Average natural gas price per Mcf received $ 1.72 $ 1.14 $ 2.07 (42) %
Average natural gas price per Mcf received
excluding derivatives $ 1.70 $ 1.11 $ 1.90 (38) %
Contract Drilling:
Average number of our drilling rigs in use during
the period 6.0 11.5 26.8 (59) %
Total drilling rigs available for service at the
end of the period 58 58 57 2 %
Average dayrate $ 17,361 $ 18,911 $ 18,635 1 %
Mid-Stream:
Gas gathered-Mcf/day 345,460 388,506 447,989 (13) %
Gas processed-Mcf/day 145,263 158,031 165,061 (5) %
Gas liquids sold-gallons/day 473,371 612,301 644,601 (7) %
Number of natural gas gathering systems 18 18 21 (14) %
Number of processing plants 11 11 12 (8) %
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1.This is a comparison between the sum of the one month ended Successor period
and the eight month ended Predecessor period in 2020 and the nine months ended
2019.
Oil and Natural Gas Operations
Any significant change in oil, NGLs, or natural gas prices has a material effect on our revenues, cash flow, and the value of our oil, NGLs, and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances, and by worldwide oil price levels. Global oil market developments primarily influence domestic oil prices. These factors are beyond our control and we cannot predict nor measure their future influence on the prices we will receive. Based on our first nine months of 2020 production, a$0.10 per Mcf change in what we are paid for our natural gas production, without the effect of derivatives, would cause a corresponding$279,000 per month ($3.4 million annualized) change in our pre-tax operating cash flow. The average price we received for our natural gas production, including the effect of derivatives, during the first nine months of 2020 was$1.20 compared to$2.07 for the first nine months of 2019. Based on our first nine months of 2020 production, a$1.00 per barrel change in our oil price, without the effect of derivatives, would have a$160,000 per month ($1.9 million annualized) change in our pre-tax operating cash flow and a$1.00 per barrel change in our NGLs prices, without the effect of derivatives, would have a$264,000 per month ($3.2 million annualized) change in our pre-tax operating cash flow. In the first nine months of 2020, our average oil price per barrel received, including the effect of derivatives, was$31.61 compared with an average oil price, including the effect of derivatives, of$57.55 in the first nine 68 -------------------------------------------------------------------------------- Table of Contents months of 2019 and our first nine months of 2020 average NGLs price per barrel received, including the effect of derivatives was$5.10 compared with an average NGLs price per barrel of$12.21 in the first nine months of 2019. Our natural gas production is sold to intrastate and interstate pipelines and to independent marketing firms and gatherers under contracts with terms ranging from one month to five years. Our oil production is sold to independent marketing firms generally under six-month contracts.
Successor Impairment
As ofSeptember 1, 2020 , we adopted fresh start accounting and adjusted our assets to fair value. Under full cost accounting rules we must review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value is called the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (using the most recent unescalated historical 12-month average price of our oil, NGLs, and natural gas), plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties in the costs being amortized, less related income taxes. If the net book value of the oil, NGLs, and natural gas properties being amortized exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short while. Once incurred, a write-down of oil and natural gas properties is not reversible. Although under fresh start accounting we recorded our assets at fair value on emergence, the application of the full cost accounting rules resulted in a non-cash ceiling impairment of$13.2 million pre-tax as ofSeptember 30, 2020 , primarily due to the use of average 12-month historical commodity prices for the ceiling test versus forward prices for our Fresh Start fair value estimates. We also anticipate a non-cash ceiling test write-down in the fourth quarter of 2020 of our proved reserves, again due to the use of historical 12-month average commodity prices for the ceiling test. It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed atSeptember 30, 2020 , and only adjust the 12-month average price as ofDecember 2020 , our forward looking expectation is that we would recognize an impairment in the range of$30 million to$35 million pre-tax in the fourth quarter of 2020. Given the uncertainty associated with the factors used in calculating our estimate of our future period ceiling test write-down, these estimates should not necessarily be construed as indicative of our future development plans or financial results and the actual amount of any write-down may vary significantly from this estimate depending on the final future determination.
Predecessor Impairments
During the first quarter of 2020, we determined that, because of the increased uncertainty in our business, our undeveloped acreage would not be fully developed and thus certain unproved oil and gas properties carrying values were not recoverable resulting in an impairment of$226.5 million , which had a corresponding increase to our depletion base and contributed to our full cost ceiling impairment recorded during the first quarter of 2020. We recorded a non-cash full cost ceiling test write-down of$267.8 million pre-tax in the first quarter of 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above. The 12-month average commodity prices decreased further, resulting in non-cash ceiling test write-downs of$109.3 million in the second quarter and$16.6 million in the two months endedAugust 31, 2020 . In the third quarter of 2019, we determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in$50.0 million of cost being added to the total of our capitalized costs being amortized in the third quarter of 2019. We incurred a non-cash ceiling test write-down of$169.3 million pre-tax ($127.9 million , net of tax) in the third quarter of 2019. In addition to the impairment evaluations of our proved and unproved oil and gas properties in the first quarter of 2020, we also evaluated the carrying value of our salt water disposal assets. Based on our revised forecast of asset utilization, we determined certain assets were no longer expected to be used and wrote off certain salt water disposal assets that we now consider abandoned. We recorded expense of$17.6 million related to the write-down of our salt water disposal assets in the first quarter of 2020. 69 -------------------------------------------------------------------------------- Table of Contents Contract Drilling Operations Many factors influence the number of drilling rigs we are able to put to work and the costs and revenues associated with that work. These factors include the demand for drilling rigs in our areas of operation, competition from other drilling contractors, the prevailing prices for oil, NGLs, and natural gas, availability and cost of labor to run our drilling rigs, and our ability to supply the equipment needed. Most of our working drilling rigs are drilling horizontal or directional wells for oil and NGLs. The continuous fluctuations in commodity prices changes the demand for drilling rigs. These factors ultimately affect the demand and mix of the drilling rigs used by our customers. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates. For the first nine months of 2020, our average dayrate was$18,814 per day compared to$18,635 per day for the first nine months of 2019. The average number of our drilling rigs used in the first nine months of 2020 was 10.9 drilling rigs compared with 26.8 drilling rigs in the first nine months of 2019. Based on the average utilization of our drilling rigs during the first nine months of 2020, a$100 per day change in dayrates has a$1,090 per day ($0.4 million annualized) change in our pre-tax operating cash flow. Our contract drilling segment provides drilling services for our exploration and production segment. Some of the drilling services we perform on our properties are, depending on the timing of those services, deemed associated with acquiring an ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in our income statements, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of$15.8 million for the first nine months of 2019, from our contract drilling segment and eliminated the associated operating expense of$14.2 million during the first nine months of 2019, yielding$1.6 million during the first nine months of 2019, as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue in our contract drilling segment for the first nine months of 2020.
There were no impairment triggering events identified in the one month Successor
period ended
Predecessor Impairments
AtMarch 31, 2020 , due to market conditions, we performed impairment testing on two asset groups comprised of our SCR diesel-electric drilling rigs and our BOSS drilling rigs. We concluded that the net book value of our SCR drilling rigs asset group was not recoverable through estimated undiscounted cash flows and recorded a non-cash impairment charge of$407.1 million in the first quarter of 2020. We also recorded an additional non-cash impairment charge of$3.0 million for other miscellaneous drilling equipment. These charges are included within impairment charges in our Unaudited Condensed Consolidated Statements of Operations. We concluded that no impairment was needed on our BOSS drilling rigs asset group as the undiscounted cash flows exceeded the carrying value of the asset group. The carrying value of the asset group was approximately$242.5 million atMarch 31, 2020 . The estimated undiscounted cash flows of the BOSS drilling rigs asset group exceeded the carrying value by a relatively minor margin, which means very minor changes in certain key assumptions in future periods may result in material impairment charges in future periods. Some of the more sensitive assumptions used in evaluating the contract drilling rigs asset groups for potential impairment include forecasted utilization, gross margins, salvage values, discount rates, and terminal values.
Mid-Stream Operations
Our mid-stream segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates three natural gas treatment plants, 11 processing plants, 18 gathering systems, and approximately 2,090 miles of pipeline. It operates inOklahoma ,Texas ,Kansas ,Pennsylvania , andWest Virginia . Besides serving third parties, this segment also enhances our ability to gather and market our own natural gas and NGLs and serving as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the first nine months of 2020 and 2019, our mid-stream operations purchased$13.9 million and$31.8 million , respectively, of our natural gas production and NGLs, and provided gathering and transportation services of$3.1 million and$5.4 million , respectively. Intercompany revenue from services and purchases of production between this business segment and our oil and natural gas segment has been eliminated in our unaudited condensed consolidated financial statements. 70 -------------------------------------------------------------------------------- Table of Contents This segment gathered an average of 383,793 Mcf per day in the first nine months of 2020 compared to 447,989 Mcf per day in the first nine months of 2019. It processed an average of 156,633 Mcf per day in the first nine months of 2020 compared to 165,061 Mcf per day in the first nine months of 2019. The NGLs sold was 597,090 gallons per day in the first nine months of 2020 compared to 644,601 gallons per day in the first nine months of 2019. Gas gathered volumes per day in the first nine months of 2020 decreased 14% compared to the first nine months of 2019 primarily due to declining volumes from most of our major systems partially offset by higher volumes on ourCashion system, due to new well connects along with the new acquisition at the end of 2019. Gas processed volumes for the first nine months of 2020 decreased 5% compared to the first nine months of 2019 due to connecting fewer wells to our processing systems along with declining volumes on most major systems, which was partially offset by added volumes from new well connects and from the new acquisition at ourCashion processing facility. NGLs sold in the first nine months of 2020 decreased 7% compared to the first nine months of 2019 due to declining volumes on several major processing systems and operating several of our processing facilities in ethane rejection mode.
There were no impairment triggering events identified in the one month Successor
period ended
Predecessor Impairments
We determined that the carrying value of certain long-lived asset groups in southernKansas , and centralOklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. Based on the estimated fair value of the asset groups, we recorded non-cash impairment charges of$64.0 million . These charges are included within impairment charges in our Consolidated Statement of Operations.
Our Credit Agreements and Predecessor Senior Subordinated Notes
Successor 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 (new term loan facility and together with the new RBL facility, the Exit 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 . Revolving Loans and Term Loans (each as defined in the Exit credit agreement) may be Eurodollar Loans or ABR Loans (each as defined in the Exit credit agreement). Revolving Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate (as defined in the Exit credit agreement) for the applicable interest period plus 525 basis points. Revolving Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate (as defined in the Exit credit agreement) plus 425 basis points. Term Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate for the applicable interest period plus 625 basis points. Term Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate plus 525 basis points. The Exit credit agreement requires the company to comply with certain financial ratios, including a covenant that the company will not permit the Net Leverage Ratio (as defined in the Exit credit agreement) as of the last day of the fiscal quarters ending (i)December 31, 2020 andMarch 31, 2021 , to be greater than 4.00 to 1.00, (ii)June 30, 2021 ,September 30, 2021 ,December 31, 2021 ,March 31, 2022 , andJune 30, 2022 , to be greater than 3.75 to 1.00, and (iii)September 30, 2022 and any fiscal quarter thereafter, to be greater than 3.50 to 1.00. In addition, beginning with the fiscal quarter endingDecember 31, 2020 , the company may not (a) permit the Current Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 0.50 to 1.00 or (b) permit the Interest Coverage Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 2.50 to 1.00. The Exit credit agreement also contains provisions, among others, that limit certain capital expenditures, restrict certain asset sales and the related use of proceeds, and require certain hedging activities. The Exit credit agreement further requires that the company provide Quarterly Financial Statements within 45 days after the end of each of the first three quarters of each fiscal year and Annual Financial Statements within 90 days after the end of each fiscal year. For the quarter endedSeptember 30, 2020 , the syndicate banks allowed for an extension. The Exit credit agreement is secured by first-priority liens on substantially all of the personal and real property assets of the Borrowers and the Guarantors, including without limitation the company's ownership interests inSuperior Pipeline Company, L.L.C. 71 -------------------------------------------------------------------------------- Table of Contents On the Effective Date, the Borrowers had (i)$40.0 million in principal amount of Term Loans outstanding under the Term Loan Facility, (ii)$92.0 million in principal amount of Revolving Loans outstanding under the RBL Facility and (iii) approximately$6.7 million of outstanding letters of credit. AtSeptember 30, 2020 , we had$0.4 million and$131.6 million outstanding current and long-term borrowings, respectively under the Exit Facility. Predecessor's Credit Agreement. Before the filing of the Chapter 11 Cases, the Unit credit facility had a scheduled maturity date ofOctober 18, 2023 that would have accelerated toNovember 16, 2020 if, by that date, all the Notes were not repurchased, redeemed, or refinanced with indebtedness having a maturity date at least six months followingOctober 18, 2023 (Credit Agreement Extension Condition). The Debtors' filing of the Bankruptcy Petitions constituted an event of default that accelerated the Debtors' obligations under the Unit credit agreement and the indenture governing the Notes. Due to the Credit Agreement Extension Condition and the acceleration of debt obligations resulting from filing the Chapter 11 Cases, the company's debt associated with the Predecessor's credit agreement is reflected as a current liability in its consolidated balance sheets as ofSeptember 30, 2020 andDecember 31, 2019 . The classification as a current liability due to the Credit Agreement Extension Condition was based on the filing of the Chapter 11 Cases and the uncertainty regarding the company's ability to repay or refinance the Notes beforeNovember 16, 2020 . In addition, onMay 22, 2020 , the RBL Lenders' remaining commitments under the Unit credit facility were terminated. Before filing the Chapter 11 Cases, we were charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varied based on the amount borrowed as a percentage of the total borrowing base. Total amendment fees of$3.3 million in origination, agency, syndication, and other related fees were being amortized over the life of the Unit credit agreement. Due to the remaining commitments under the Unit credit agreement being terminated by the RBL Lenders', the unamortized debt issuance costs of$2.4 million were written off during the second quarter of 2020. Under the Predecessor credit agreement, we pledged as collateral 80% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties. Under the mortgages covering those oil and gas properties, UPC also pledged certain items of its personal property. OnMay 2, 2018 , we entered into a Pledge Agreement withBOKF, NA (dbaBank of Oklahoma ), as administrative agent to benefit the secured parties, under which we granted a security interest in the limited liability membership interests and other equity interests we own in Superior as additional collateral for our obligations under the Predecessor credit agreement. Before to filing the Chapter 11 Cases, any part of the outstanding debt under the Predecessor credit agreement could be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest was computed as the LIBOR base for the term plus 1.50% to 2.50% depending on the level of debt as a percentage of the borrowing base and was payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest equal to the higher of the prime rate specified in the Predecessor credit agreement and the sum of the Federal Funds Effective Rate (as defined in the Unit credit agreement) plus 0.50%, but in no event would the interest on those borrowings be less than LIBOR plus 1.00% plus a margin. The Predecessor credit agreement provided that ifICE Benchmark Administration no longer reported the LIBOR or the Administrative Agent determined in good faith that the rate so reported no longer accurately reflected the rate available in the London Interbank Market or if the index no longer existed or accurately reflects the rate available to the Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index. Interest was payable at the end of each month or at the end of each LIBOR contract and the principal may be repaid in whole or in part at any time, without a premium or penalty. Filing the Bankruptcy Petitions onMay 22, 2020 constituted an event of default that accelerated the company's obligations under the Unit credit agreement, and the lenders' rights of enforcement regarding the Predecessor credit agreement were automatically stayed because of the Chapter 11 Cases. On the Effective Date, each lender under the Predecessor credit facility and the DIP credit facility received its pro rata share of revolving loans, term loans and letter-of-credit participations under the exit facility, in exchange for that lender's allowed claims under the Predecessor credit facility or the DIP credit facility. 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 amounts borrowed under the Superior credit agreement bear annual interest at a rate, at Superior's option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) the Thirty-Day LIBOR Rate (as defined in the Superior credit agreement plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by, among other things, mortgage liens on certain of Superior's processing plants and gathering systems. The Superior credit agreement provides that ifICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available in the London Interbank Market or if such index no longer exists or 72 -------------------------------------------------------------------------------- Table of Contents accurately reflects the rate available to the Administrative Agent in theLondon Interbank Market, the Administrative Agent may select a replacement index. Superior is charged a commitment fee of 0.375% on the amount available but not borrowed which varies based on the amount borrowed as a percentage of the total borrowing base. Superior paid$1.7 million in origination, agency, syndication, and other related fees. These fees are being amortized over the life of the Superior credit agreement. The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. The agreement also contains several customary covenants that restrict (subject to certain exceptions) Superior's ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, sign sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and acquire or dispose of assets. As ofSeptember 30, 2020 , Superior complied with these covenants.
The borrowings under the Superior credit agreement will fund capital expenditures and acquisitions and provide general working capital and letters of credit for Superior.
Superior's credit agreement is not guaranteed by Unit. Superior and its subsidiaries were not Debtors in the Chapter 11 Cases.
The lenders under the Superior credit agreement and their respective participation interests are:
Participation
Lender Interest
BOK (BOKF, NA , dba Bank of Oklahoma ) 17.50 %
Compass Bank 17.50 %
BMO Harris Financing, Inc. 13.75 %
Toronto Dominion (New York ), LLC 13.75 %
Bank of America, N.A . 10.00 %
Branch Banking and Trust Company 10.00 %
Comerica Bank 10.00 %
Canadian Imperial Bank of Commerce 7.50 %
100.00 %
Predecessor 6.625% Senior Subordinated Notes. The Predecessor's Notes were
issued under an Indenture dated as of May 18, 2011 , between us and Wilmington
Trust, National Association (successor to Wilmington Trust FSB ), as Trustee
(Trustee), as supplemented by the First Supplemental Indenture dated as of
May 18, 2011 , between us, the Guarantors, and the Trustee, and as further
supplemented by the Second Supplemental Indenture dated as of January 7, 2013 ,
between us, the Guarantors, and the Trustee (as supplemented, the 2011
Indenture), establishing the terms of and providing for issuing the Notes.
As a result of Unit's emergence from bankruptcy, the Notes were cancelled and
the Predecessor's liability thereunder discharged as of the Effective Date, and
the holders of the Notes were issued approximately 10.5 million shares New
Common Stock.
Predecessor DIP Credit Agreement. As contemplated by the RSA, the company and
the other Debtors entered into a Superpriority Senior Secured
Debtor-in-Possession Credit Agreement dated May 27, 2020 ( DIP credit
agreement), by and among the Debtors, the RBL Lenders (in such capacity, the DIP
Lenders), and BOKF, NA dba Bank of Oklahoma , as administrative agent, under
which the DIP Lenders agreed to provide the company with the $36.0 million
multiple-draw loan facility (DIP credit facility). The Bankruptcy Court entered
an interim order on May 26, 2020 approving the DIP credit facility, permitting
the Debtors to borrow up to $18.0 million on an interim basis. On June 19, 2020 ,
the Bankruptcy Court granted final approval of the DIP credit facility.
Before its repayment and termination on the Effective Date, borrowings under the
DIP credit facility matured on the earliest of (i) September 22, 2020 (subject
to a two-month extension to be approved by the DIP Lenders), (ii) the sale of
all or substantially all of the assets of the Debtors under Section 363 of the
Bankruptcy Code or otherwise, (iii) the effective date of a plan of
reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of an
order by the Bankruptcy Court dismissing any
73
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of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under
Chapter 7 of the Bankruptcy Code and (v) the date of termination of the DIP
Lenders' commitments and the acceleration of any outstanding extensions of
credit, in each case, under the DIP credit facility under and subject to the DIP
credit agreement and the Bankruptcy Court's orders.
On the Effective Date, the DIP credit agreement was paid in full and terminated.
On the Effective Date, each holder of an allowed claim under the DIP credit
facility received its pro rata share of revolving loans, term loans and
letter-of-credit participations under the exit facility. In addition, each such
holder was issued on the Effective Date (or promptly following the Effective
Date) its pro rata share of an equity fee under the exit facility equal to 5% of
the New Common Stock (subject to dilution by shares reserved for issuance under
a management incentive plan and upon exercise of the Warrants).
For further information about the DIP credit agreement, please see Note 2 - Emergence From Voluntary Reorganization Under Chapter 11.
Warrants
Each holder of the company's common stock outstanding before the Effective Date (Predecessor Common Stock) that did not opt out of the release under the Plan, is entitled to receive its pro rata share of seven-year warrants (Warrants) to purchase an aggregate of 12.5% of the shares of New Common Stock, at an aggregate exercise price equal to the$650.0 million principal amount of the Notes plus interest thereon to theMay 15, 2021 maturity date of the Notes. On the Effective Date, the company entered into a Warrant Agreement (Warrant Agreement) withAmerican Stock Transfer & Trust Company, LLC . The Warrants will expire on the earliest of (i)September 3, 2027 , (ii) the 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 such Warrant and the Warrant Agreement will cease on the Expiration Date. OnDecember 21, 2020 , the company issued approximately 1.8 million Warrants to the holders of the Predecessor Common Stock that did not opt out of the releases under the Plan and owned their shares of Predecessor Common Stock in street name through the facilities of the DTC. The company expects to issue approximately 79,000 more Warrants to the holders of the Predecessor Common Stock that did not opt out of the releases under the Plan and owned their shares through direct registration with the company's transfer agent (Direct Registration). Under the Plan, additional Warrants will be issued in book-entry form through the facilities of the DTC, and each holder owning shares of Predecessor Common Stock through Direct Registration must provide that holder's brokerage account information to the company to receive holder's distribution of Warrants. Holders of shares of the Predecessor Common Stock that owned shares through Direct Registration should contactPrime Clerk, LLC at (877) 720-6581 (Toll Free) or (646) 979-4412 (Local) to obtain the forms necessary to receive their distribution. Any distribution not made will be deemed forfeited at the first anniversary of the Effective Date.
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 under the circumstances which provide us with flexibility in deciding when and if to incur these costs. We participated in the completion of 27 gross wells (6.16 net wells) drilled by other operators in the first nine months of 2020 compared to 89 gross wells (28.59 net wells) drilled by Unit and other operators in which we participated in the first nine months of 2019. Capital expenditures for oil and gas properties on the full cost method for the first nine months of 2020 by this segment, excluding$0.4 million for acquisitions, totaled$10.3 million . Capital expenditures for the first nine months of 2019, excluding$3.3 million for acquisitions, totaled$246.0 million .
For 2020, we did not drill any company operated wells.
Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. During the first quarter of 2019, we completed construction and placed into service our 12th and 13th BOSS drilling rigs. One was delivered to an existing third-party operator inWyoming . Two additional BOSS drilling rigs under contract with the same customer were also extended. The other BOSS drilling rig was delivered to a new customer in thePermian Basin . This was following an early termination by the original third-party operator before the drilling rig's completion. Our 14th BOSS drilling rig was completed and placed into service in December of 2019 for a third-party under a long term contract. During the second quarter of 2019, two existing BOSS drilling rig contracts working for the same operator were also extended. 74 -------------------------------------------------------------------------------- Table of Contents We have no commitments or plans to build any additional BOSS drilling rigs in 2020. For 2020, we do not currently have an approved capital plan for this segment. Capital expenditures incurred would be within anticipated cash flows. We have spent$4.0 million for capital expenditures during the first nine months of 2020, compared to$36.6 million for capital expenditures during the first nine months of 2019. Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. At theCashion processing facility in centralOklahoma , total throughput volume for the third quarter of 2020 averaged approximately 75.5 MMcf per day and total production of natural gas liquids averaged approximately 354,000 gallons per day. Through the first nine months of 2020, we continued to connect new wells to this system for third party producers. Since the first of this year, we connected 14 new wells to this system from producers in the area. The acquired mid-continent production that was purchased at the end of 2019 is being processed at our Reeding facility on ourCashion system. Additionally, we are delivering thePerkins facility production to the Cashion Reeding facility. The total processing capacity on theCashion system is 105 MMcf per day. In the Appalachian region at the Pittsburgh Mills gathering system, average gathered volume for the third quarter of 2020 was 150.8 MMcf per day while the average gathered volume for second quarter of 2020 was approximately 181.8 MMcf per day as theBakerstown infill wells continue to decline. During the third quarter of 2020, we did not add any new wells to this system. At theHemphill processing facility located in theTexas panhandle, average total throughput volume for the third quarter of 2020 was 50.1 MMcf per day and total production of natural gas liquids averaged approximately 187,000 gallons per day. We did not connect any new wells to this system in the third quarter of 2020. At this time there are no active rigs in the area and we did not have any new well connects the rest of this year.
At the Segno gathering system located in
During the first nine months of 2020, our mid-stream segment incurred$10.2 million in capital expenditures as compared to$41.4 million in the first nine months of 2019. For 2020, our estimated capital expenditures is approximately$11.0 million . Contractual Commitments
At
Payments Due by Period
Less
Than 2-3 4-5 After
Total 1 Year Years Years 5 Years
(In thousands)
Long-term debt (1) $ 174,182 $ 9,282 $ 29,374 $ 135,526 $ -
Operating leases (2) 6,416 3,985 2,355 21 55
Finance lease interest and maintenance
(3) 1,051 1,051 - - -
Firm transportation commitments (4) 1,702 1,216 486 - -
Total contractual obligations $ 183,351 $ 15,534 _______________________
1.See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Unit Exit Facility and includes interest calculated using ourSeptember 30, 2020 interest rates of 6.6% for our Unit Exit Facility and 2.1% for our Superior credit agreement. The Unit Exit Facility has a maturity date ofMarch 1, 2024 and outstanding balance as ofSeptember 30, 2020 of$132.0 million ($0.4 million is reflected as a current liability in our consolidated balance sheet). Our Superior credit agreement has a maturity date ofMay 10, 2023 and an outstanding balance of$12.0 million as ofSeptember 30, 2020 . 2.We lease certain office space, land and equipment, including pipeline equipment and office equipment under the terms of operating leases under ASC 842 expiring throughMarch 2031 . We also have short-term lease commitments of$1.4 million . This is lease office space or yards inEdmond andOklahoma City, Oklahoma ;Houston, Texas ;Englewood, Colorado ; andPinedale, Wyoming under the terms of operating leases expiring throughJune 2021 . Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. 75 -------------------------------------------------------------------------------- Table of Contents 3.Maintenance and interest payments are included in our finance lease agreements. The finance leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining are$1.0 million and$0.1 million , respectively.
4.We have firm transportation commitments to transport our natural gas from
various systems for approximately
During the second quarter of 2018, as part of the Superior transaction, we entered into a contractual obligation committing us to spend$150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years startingJanuary 1, 2019 . For each dollar of the$150.0 million we do not spend (over the three-year period), we would forgo receiving$0.58 of future distributions from our ownership interest in our consolidated mid-stream subsidiary. AtSeptember 30, 2020 , if we elected not to drill or spend any additional money in the designated area beforeDecember 31, 2021 , the maximum amount we could forgo from distributions would be$72.6 million . Total spent towards the$150.0 million as ofSeptember 30, 2020 was$24.8 million .
At
Estimated Amount of Commitment Expiration Per Period
Less
Total Than 1 2-3 4-5 After 5
Other Commitments Accrued Year Years Years Years
(In thousands)
Deferred compensation plan (1) $ - $ - $ - $ - $ - Separation benefit plans (2)
$ 4,536 $ 1,374 Unknown Unknown Unknown Asset retirement liability (3)$ 24,922 $ 2,186
$ 3,824 Unknown Unknown Unknown Unknown
Workers' compensation liability (5)
Unknown Unknown Unknown Finance lease obligations (6)$ 4,272 $ 4,272
$ - $ - $ - Contract liability (7)
$ 4,899 $ 2,779
$ 1,997 $ -
_______________________
1.We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death, or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets, at the time of deferral. As ofSeptember 30, 2020 , this plan has been paid out to plan participants. 2.As of the Effective Date, the Board adopted (i) the Amended and Restated Separation Benefit Plan ofUnit Corporation and Participating Subsidiaries (Amended Separation Benefit Plan), (ii) the Amended and Restated Special Separation Benefit Plan ofUnit Corporation and Participating Subsidiaries (Amended Special Separation Benefit Plan) and (iii) the Separation Benefit Plan ofUnit Corporation and Participating Subsidiaries (New Separation Benefit Plan). In accordance with the Plan, the Amended Separation Benefit Plan and the Amended Special Separation Benefit Plan allow former employees or retained employees with vested severance benefits under either plan to receive certain cash payments in full satisfaction for their allowed separation claim under the Chapter 11 Cases. In accordance with the Plan, the New Separation Benefit Plan is a comprehensive severance plan for retained employees, including retained employees whose severance did not already vest under the Amended Separation Benefit Plan or the Amended Special Separation Benefit Plan. The New Separation Benefit Plan provides that eligible employees will be entitled to two weeks of severance pay per year of service, with a minimum of four weeks and a maximum of 13 weeks of severance pay.
3.When a well is drilled or acquired, under ASC 410 "Accounting for Asset Retirement Obligations," we record the discounted fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).
4.We have recorded a liability for those properties we believe do not have sufficient oil, NGLs, and natural gas reserves to allow the under-produced owners to recover their under-production from future production volumes.
5.We have recorded a liability for future estimated payments related to workers' compensation claims primarily associated with our contract drilling segment.
6.The amount includes commitments under finance lease arrangements for compressors in Superior.
7.We have recorded a liability related to the timing of revenue recognized on certain demand fees for Superior.
8.Due to the issuance of the Coronavirus Aid, Relief, and Economic Security Act (CARES Act), we have deferred our FICA tax payment.
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. AtSeptember 30, 2020 , based on our third quarter 2020 average daily production, the approximated percentages of our production under derivative contracts are as follows: 2020 2021 2022 2023 Daily oil production 72 % 54 % 41 % 23 %
Daily natural gas production 61 % 50 % 40 % 22 %
With respect to the commodities subject to derivative contracts, those contracts serve to limit the risk of adverse downward price movements. However, they also limit increases in future revenues that would otherwise result from price movements above the contracted prices. 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, 2020 evaluation, we believe the risk of non-performance by our counterparties is not material. AtSeptember 30, 2020 , the fair values of the net assets we had with each of the counterparties to our commodity derivative transactions are as follows: September 30, 2020 (In thousands) Bank of Oklahoma $ 726 Bank of America (196) Bank of Montreal (1,026) Total net liabilities $ (496) If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets. AtSeptember 30, 2020 , we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of$2.4 million and current derivative liabilities of$1.1 million and non-current derivative liabilities of$1.7 million . AtDecember 31, 2019 , we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of$0.6 million and non-current derivative liabilities of less than$0.1 million . For our economic hedges any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations. These gains (losses) atSeptember 30 are as follows: Successor Predecessor Predecessor One Month Ended Two Months Ended Three Months Ended September 30, August 31, September 30, 2020 2020 2019 (In thousands) Gain (loss) on derivatives: Gain (loss) on derivatives, included are amounts settled during the period of ($1,418 ), ($3,552 ), and$6,515 , respectively$ 3,939 $ (4,250) $ 4,237$ 3,939 $ (4,250) $ 4,237 77
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Successor Predecessor Predecessor
One Month
Ended Eight Months Ended Nine Months Ended
September 30, August 31, September 30,
2020 2020 2019
(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts
settled during the period of ($1,418 ), ($4,244 ), and
$11,829 , respectively $ 3,939 $ (10,704) $ 5,232
$ 3,939 $ (10,704) $ 5,232
Stock and Incentive Compensation
On the Effective Date, the company's equity-based awards that were outstanding immediately before the Effective Date were cancelled. The cancellation of the awards resulted in an acceleration of unrecorded stock compensation expense during the predecessor period. During the first nine months of 2020, we did not grant any awards. We recognized compensation expense of$6.1 million for all of our prior restricted stock awards including the acceleration of the unrecorded stock compensation expense. We did not capitalize any compensation cost to oil and natural gas properties since we are currently not drilling. During the first nine months of 2019, we granted awards covering 1,424,027 shares of restricted stock. These awards had an estimated fair value as of their grant date of$22.6 million . Compensation expense will be recognized over the three-year vesting periods, and during the nine months of 2019, we recognized$5.9 million in compensation expense and capitalized$1.0 million for these awards. During the first nine months of 2019, we recognized compensation expense of$13.0 million for all of our restricted stock and stock options and capitalized$2.0 million of compensation cost to oil and natural gas properties.
Insurance
We are self-insured for certain losses relating to workers' compensation, general liability, control of well, and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to$1.0 million . We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. There is no assurance that the insurance coverage we have will protect us against liability from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships
We were the general partner of 13 oil and natural gas partnerships formed privately or publicly. Each partnership's revenues and costs were shared under formulas set out in that partnership's agreement. The partnerships repaid us for contract drilling, well supervision, and general and administrative expense. Related party transactions for contract drilling and well supervision fees were the related party's share of such costs. These costs were billed the same as billings to unrelated third parties for similar services. General and administrative reimbursements consisted of direct general and administrative expense incurred on the related party's behalf and indirect expenses assigned to the related parties. Allocations are based on the related party's level of activity and were considered by us to be reasonable. Our proportionate share of assets, liabilities, and net income relating to the oil and natural gas partnerships is included in our unaudited condensed consolidated financial statements. The partnerships were terminated during the second quarter of 2019 with an effective date ofJanuary 1, 2019 at a repurchase cost of$0.6 million , net of Unit's interest. New Accounting Pronouncements Reference Rate Reform (Topic 848)-Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 which provides optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The ASU is intended to help stakeholders during the global market-wide reference rate transition period. The amendments within this ASU will be in effect for a limited time beginningMarch 12, 2020 , and an entity may elect to 78 -------------------------------------------------------------------------------- Table of Contents apply the amendments prospectively throughDecember 31, 2022 . The company is currently evaluating the impact this may have on its consolidated financial statements. Currently there are no accounting pronouncements that have been issued, but not yet adopted, that are expected to have a material impact on our consolidated financial statements or disclosures.
Adopted Standards
Measurement of Credit Losses on Financial Instruments (Topic 326). The FASB
issued ASU 2016-13 which replaces current methods for evaluating impairment of
financial instruments not measured at fair value, including trade accounts
receivable and certain debt securities, with a current expected credit loss
model ("CECL"). The CECL model is expected to result in more timely recognition
of credit losses. The amendment was effective for reporting periods after
December 15, 2019 . The adoption of this guidance did not have a material impact
on our consolidated financial statements or related disclosures.
Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the
Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13
to modify the disclosure requirements in Topic 820. Part of the disclosures were
removed or modified, and other disclosures were added. The amendment was
effective for reporting periods beginning after December 15, 2019 . Early
adoption is permitted. The adoption of this guidance did not have a material
impact on our consolidated financial statements or related disclosures.
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Results of Operations
Quarter Ended September 30, 2020 versus Quarter Ended September 30, 2019
Provided below is a comparison of selected operating and financial data after
eliminations (in thousands unless otherwise specified):
Successor Predecessor Predecessor
One Month Three Months
Ended Two Months Ended Ended
September 30, August 31, September 30, Percent
2020 2020 2019 Change (1)
Total revenue $ 32,846 $ 65,574 $ 155,439 (37) %
Net income (loss) $ (6,736) $ 128,615 $ (207,789) 159 %
Net income (loss) attributable to non-controlling
interest $ 2,232 $ 73,484 $ (903) NM
Net loss attributable to Unit Corporation $ (8,968) $ 55,131 $ (206,886) 122 %
Oil and Natural Gas:
Revenue $ 13,643 $ 27,961 $ 78,045 (47) %Operating costs excluding depreciation, depletion, and amortization
$ 6,674 $ 15,488 $ 35,364 (37) % Depreciation, depletion, and amortization$ 4,199 $ 9,975$ 43,587 (67) % Impairment of oil and natural gas properties$ 13,237 $ 16,572 $ 169,806 (82) % Average oil price (Bbl)$ 28.11 $ 29.59$ 56.62 (49) % Average NGLs price (Bbl)$ 7.47 $ 8.53$ 8.50 (4) % Average natural gas price (Mcf)$ 1.72 $ 1.07$ 1.83 (30) % Oil production (MBbls) 167 341 927 (45) % NGL production (MBbls) 273 572 1,240 (32) % Natural gas production (MMcf) 2,849 6,185 13,362 (32) % Depreciation, depletion, and amortization rate (Boe)$ 4.56 $ 4.74$ 9.54 (52) % Contract Drilling: Revenue$ 4,414 $ 7,685$ 37,596 (68) % Operating costs excluding depreciation$ 2,989 $ 5,410 28,796 (71) % Depreciation$ 526 $ 853$ 12,845 (89) % Impairment of goodwill $ - $ -$ 62,809 (100) % Percentage of revenue from daywork contracts 100 % 100 % 100 % - % Average number of drilling rigs in use 6.0 4.6 20.4 (75) % Average dayrate on daywork contracts$ 17,361 $ 16,596 $ 19,276 (12) % Mid-Stream: Revenue$ 14,789 $ 29,928 $ 39,798 12 % Operating costs excluding depreciation and amortization$ 9,852 $ 17,822 $ 28,493 (3) % Depreciation and amortization$ 2,658 $ 6,750$ 11,847 (21) % Gas gathered--Mcf/day 345,460 363,465 428,573 (17) % Gas processed--Mcf/day 145,263 149,483 167,687 (12) % Gas liquids sold--gallons/day 473,371 699,647 572,852 9 % 80
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Successor Predecessor Predecessor
One Month Three Months
Ended Two Months Ended Ended
September 30, August 31, September 30, Percent
2020 2020 2019 Change (1)
Corporate and Other:
Loss on abandonment of assets $ - $ 1,179 $ - - %
General and administrative expense $ 1,582 $ 5,399 $ 10,094 (31) %
Other depreciation $ 84 $ 341 $ 1,935 (78) %
Loss on disposition of assets $ 222 $ 1,356 $ (231) NM
Other income (expense):
Interest income $ - $ - $ 3 (100) %
Interest expense, net $ (826) $ (1,959) $ (9,537) (71) %
Reorganization costs, net $ (1,155) $ 141,002 $ - - %
Gain (loss) on derivatives $ 3,939 $ (4,250) $ 4,237 (107) %
Other $ 39 $ 1,931 $ (622) NM
Income tax benefit $ - $ (4,750) $ (50,763) 91 %
Average interest rate 5.9 % 2.7 % 6.3 % (41) %
Average long-term debt outstanding $ 146,267 $ 160,039 $ 775,837 (80) %
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1.This is a comparison between the sum of the one month ended Successor period
and the two month ended Predecessor period in 2020 and the three month ended
period in 2019. 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 decreased $36.4 million or 47% in the third quarter
of 2020 as compared to the third quarter of 2019 primarily due to lower
commodity volumes. In the third quarter of 2020, as compared to the third
quarter of 2019, oil production decreased 45%, natural gas production decreased
32%, and NGLs production decreased 32%. Including derivatives settled, average
oil prices decreased 33% to $37.98 per barrel, average natural gas prices
decreased 30% to $1.28 per Mcf, and NGLs prices decreased 4% to $8.19 per
barrel.
Oil and natural gas operating costs decreased
Depreciation, depletion, and amortization (DD&A) decreased$29.4 million or 67% due primarily to a 52% decrease in the DD&A rate and a 35% decrease in equivalent production. The decrease in our DD&A rate in the third quarter of 2020 compared to the third quarter of 2019 resulted primarily from reduced net book value due to ceiling test write-downs.
For the one month period ending
Contract Drilling
Drilling revenues decreased$25.5 million or 68% in the third quarter of 2020 versus the third quarter of 2019. The decrease was due primarily to a 75% decrease in the average number of drilling rigs in use and a 12% decrease in the average dayrate. Average drilling rig utilization decreased from 20.4 drilling rigs in the third quarter of 2019 to 5.1 drilling rigs in the third quarter of 2020. Drilling operating costs decreased$20.5 million or 71% between the comparative third quarters of 2020 and 2019. The decrease was due primarily to less drilling rigs operating. Contract drilling depreciation decreased$11.5 million or 89% in the third quarter of 2020 versus the third quarter of 2019 also due to less drilling rigs operating and from the lower depreciable net book value due to impairments in the first nine months of 2020.
Mid-Stream
Our mid-stream revenues increased$4.9 million or 12% in the third quarter of 2020 as compared to the third quarter of 2019 due primarily to recognizing a one-time shortfall fee from one of our producers partially offset by lower gas, NGLs, and condensate prices and volumes. Gas processed volumes per day decreased 12% between the comparative quarters primarily due to connecting fewer new wells and declining volumes on most of our major processing systems, partially offset by increased volumes from theCashion system due to the acquisition at the end of 2019. Gas gathered volumes per day decreased 17% between the comparative quarters due to fewer new well connects and declining volumes from most of our major systems partially offset by higher volume on ourCashion system. Operating costs decreased$0.8 million or 3% in the third quarter of 2020 compared to the third quarter of 2019 primarily due to lower purchase volumes and lower field operating expenses. Depreciation and amortization decreased$2.4 million , or 21%, primarily due to impairing the carrying value of several of our systems in the first quarter of 2020.
Loss on Abandonment of Assets
We recorded expense of
General and Administrative
Corporate general and administrative expenses decreased$3.1 million or 31% in the third quarter of 2020 as compared to the third quarter of 2019 primarily due to lower employee costs. 82 -------------------------------------------------------------------------------- Table of Contents Gain (Loss) on Disposition of Assets There was a$1.6 million gain on disposition of assets in the third quarter of 2020 primarily related to the sale of vehicles, drilling rigs, and other drilling equipment. For the third quarter of 2019, we had a loss of$0.2 million which was primarily related to assets held for sale that were sold which consisted of one drilling rig and miscellaneous drilling rig components.
Other Income (Expense)
Interest expense, net of capitalized interest, decreased$6.8 million between the comparative third quarters of 2020 and 2019 due to an 80% decrease in average long-term debt outstanding and no capitalized interest in the third quarter of 2020 and a lower average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, constructing additional drilling rigs, and constructing gas gathering systems. Because we are not currently undergoing any capital projects, we had no capitalized interest for the third quarter of 2020 compared to$4.2 million for the third quarter of 2019 which was netted against our gross interest of$2.8 million and$13.7 million for the third quarters of 2020 and 2019, respectively. Our average interest rate decreased from 6.3% in the third quarter of 2019 to 3.7% in the third quarter of 2020 and our average debt outstanding decreased$620.3 million in the third quarter of 2020 compared to the third quarter of 2019 primarily due to the Notes being settled with the Plan.
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. For more detail, see Note 2 - Emergence From Voluntary Reorganization Under Chapter 11. Gain (Loss) on Derivatives Gain (loss) on derivatives decreased by$4.5 million between the comparative third quarters of 2020 and 2019 primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.
Income Tax Benefit
Income tax benefit was$4.8 million in the third quarter of 2020 compared to$50.8 million in the third quarter of 2019 primarily due to the need of a valuation allowance against our income tax benefit. The income tax benefit was recognized in the Predecessor period endingAugust 31, 2020 . Due to changes in the book basis of our assets in conjunction with our fresh start accounting and our net operating losses, it was determined that a full valuation allowance against our net deferred tax asset was needed as of the Effective Date and the Successor period endingSeptember 30, 2020 . Our blended effective tax rate was (4.06%) for the third quarter of 2020 ((3.83%) for the Predecessor period endingAugust 31, 2020 and 0.00% for the Successor period endingSeptember 30, 2020 ) compared to 19.63% for the third quarter of 2019. The rate change was primarily due to the need of a valuation allowance against our income tax benefit for the third quarter of 2020. We did not have a current income tax benefit for the third quarter of 2020 or 2019. We paid no income taxes in the third quarter of 2020. 83 -------------------------------------------------------------------------------- Table of Contents Year EndedSeptember 30, 2020 versus Year EndedSeptember 30, 2019 Provided below is a comparison of selected operating and financial data after eliminations (in thousands unless otherwise specified): Successor Predecessor Predecessor One Month Eight Months Ended Ended Nine Months Ended August 31, September 30, Percent September 30, 2020 2020 2019 Change (1) Total revenue $ 32,846$ 276,957 $ 510,276 (39) % Net loss $ (6,736)$ (890,624) $ (218,088) NM Net income attributable to non-controlling interest $ 2,232$ 40,388 $ 811
NM
Net loss attributable to
$ (931,012) $ (218,899) NM Oil and Natural Gas: Revenue $ 13,643$ 103,439 $ 241,955
(52) % Operating costs excluding depreciation, depletion, and amortization
$ 6,674 $ 117,691 $ 104,320 19 %
Depreciation, depletion, and amortization $ 4,199 $ 68,762 $ 118,105 (38) %
Impairment of oil and natural gas properties $ 13,237 $ 393,726 $ 169,806 140 %
Average oil price (Bbl) $ 28.11 $ 31.98 $ 57.55 (45) %
Average NGLs price (Bbl) $ 7.47 $ 4.83 $ 12.21 (58) %
Average natural gas price (Mcf) $ 1.72 $ 1.14 $ 2.07 (42) %
Oil production (MBbls) 167 1,562 2,341 (26) %
NGL production (MBbls) 273 2,399 3,657 (27) %
Natural gas production (MMcf) 2,849 26,563 40,021 (27) %
Depreciation, depletion, and amortization rate
(Boe) $ 4.56 $ 7.80 $ 8.94 (49) %
Contract Drilling:
Revenue $ 4,414 $ 73,519 $ 131,788 (41) %
Operating costs excluding depreciation $ 2,989 $ 51,810 89,505 (39) %
Depreciation $ 526 $ 15,544 $ 39,048 (59) %
Impairment of contract drilling equipment $ - $ 410,126 $ - - %
Impairment of goodwill $ - $ - $ 62,809 (100) %
Percentage of revenue from daywork contracts 100 % 100 % 100 % - %
Average number of drilling rigs in use 6.0 11.5 26.8 (59) %
Average dayrate on daywork contracts $ 17,361 $ 18,911 $ 18,635 1 %
Mid-Stream:
Revenue $ 14,789 $ 99,999 $ 136,533 (16) %
Operating costs excluding depreciation and
amortization $ 9,852 $ 68,045 $ 100,339 (22) %
Depreciation and amortization $ 2,658 $ 29,371 $ 35,675 (10) %
Impairment $ - $ 63,962 $ 2,265 NM
Gas gathered--Mcf/day 345,460 388,506 447,989 (14) %
Gas processed--Mcf/day 145,263 158,031 165,061 (5) %
Gas liquids sold--gallons/day 473,371 612,301 644,601 (7) %
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Successor Predecessor Predecessor
One Month
Ended Eight Months Ended Nine Months Ended
September 30, August 31, September 30, Percent
2020 2020 2019 Change (1)
Corporate and Other:
Loss on abandonment of assets $ - $ 18,733 $ - - %
General and administrative expense $ 1,582 $ 42,766 $ 29,899 48 %
Other depreciation $ 84 $ 1,819 $ 5,804 (67) %
Gain (loss) on disposition of assets $ 222 $ 89 $ (1,424) 122 %
Other income (expense):
Interest income $ - $ 58 $ 47 23 %
Interest expense, net $ (826) $ (22,882) $ (27,114) (13) %
Reorganization costs, net $ (1,155) $ 133,975 $ - - %
Write-off of debt issuance costs $ - $ (2,426) $ - - %
Gain (loss) on derivatives $ 3,939 $ (10,704) $ 5,232 NM
Other $ 39 $ 2,034 $ (611) NM
Income tax benefit $ - $ (14,630) $ (53,081) 72 %
Average interest rate 5.9 % 5.5 % 6.4 % (15) %
Average long-term debt outstanding $ 146,267 $ 526,167 $ 732,515 (34) %
_________________________
1.This is a comparison between the sum of the one month ended Successor period
and the eight month ended Predecessor period in 2020 and the nine month ended
period in 2019. 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 decreased $124.9 million or 52% in the first nine
months of 2020 as compared to the first nine months of 2019 primarily due to
lower commodity prices and volumes. In the first nine months of 2020, as
compared to the first nine months of 2019, oil production decreased 26%, natural
gas production decreased 27%, and NGLs production decreased 27%. Including
derivatives settled, average oil prices decreased 45% to $31.61 per barrel,
average natural gas prices decreased 42% to $1.20 per Mcf, and NGLs prices
decreased 58% to $5.10 per barrel.
Oil and natural gas operating costs increased $20.0 million or 19% between the
comparative first nine months of 2020 and 2019 primarily due to lower LOE, and
gross production taxes partially offset by decreased G&G expenses capitalized.
Depreciation, depletion, and amortization (DD&A) decreased
During the first nine months of 2020, we recorded non-cash ceiling test write-downs of$393.7 million pre-tax ($346.6 million , net of tax). During the first nine months of 2019, we recorded a non-cash ceiling test write-down of$169.3 million pre-tax ($127.9 million , net of tax). We recorded expense of$17.6 million related to the write down of our salt water disposal asset that we consider abandoned in first nine months of 2020.
Contract Drilling
Drilling revenues decreased$53.9 million or 41% in the first nine months of 2020 versus the first nine months of 2019. The decrease was due primarily to a 59% decrease in the average number of drilling rigs in use partially offset by an 1% increase in the average dayrate. Average drilling rig utilization decreased from 26.8 drilling rigs in the first nine months of 2019 to 10.9 drilling rigs in the first nine months of 2020. Drilling operating costs decreased$34.7 million or 39% between the comparative first nine months of 2020 and 2019. The decrease was due primarily to less drilling rigs operating. Contract drilling depreciation decreased$23.0 million or 59% in the first nine months of 2020 versus the first nine months of 2019 also due to less drilling rigs operating and from lower depreciable net book value due to impairments recognized in the first half of 2020. AtMarch 31, 2020 , due to market conditions, we performed impairment testing on two asset groups which were comprised of the SCR diesel-electric drilling rigs and the BOSS drilling rigs. We concluded that the net book value of the SCR drilling rigs asset group was not recoverable through estimated undiscounted cash flows and recorded a non-cash impairment charge of$407.1 million in the first quarter of 2020. We also recorded an additional non-cash impairment charge of$3.0 million for other drilling equipment. These charges are included within impairment charges in our Unaudited Condensed Consolidated Statements of Operations. We concluded that no impairment was needed on the BOSS drilling rigs asset group as the undiscounted cash flows exceeded the carrying value of the asset group. The carrying value of the asset group was approximately$242.5 million atMarch 31, 2020 . The estimated undiscounted cash flows of the BOSS drilling rigs asset group exceeded the carrying value by a relatively minor margin, which means very minor changes in certain key assumptions in future periods may result in material impairment charges in future periods. Some of the more sensitive assumptions used in evaluating the contract drilling rigs asset groups for potential impairment include forecasted utilization, gross margins, salvage values, discount rates, and terminal values.
Mid-Stream
Our mid-stream revenues decreased$21.7 million or 16% in the first nine months of 2020 as compared to the first nine months of 2019 due primarily to lower gas, NGLs, and condensate prices and volumes partially offset by the recognition of a one-time shortfall fee from one of our producers. Gas processed volumes per day decreased 5% between the comparative periods primarily due to connecting fewer new wells to our processing systems and declining volumes on most of our processing systems partially offset by increased volume from theCashion system due to the acquisition at the end of 2019. Gas gathered volumes per day decreased 14% between the comparative periods due to fewer new well connects and declining volumes from most of our major systems partially offset by higher volume on ourCashion system. Operating costs decreased$22.4 million or 22% in the first nine months of 2020 compared to the first nine months of 2019 primarily due to lower purchase prices along with lower purchased volumes. Depreciation and amortization decreased$3.6 million , or 10%, primarily due to impairing the carrying value of several of our systems in the first quarter of 2020. 86
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We determined that the carrying value of certain long-lived asset groups located in southernKansas , and centralOklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. Based on the estimated fair value of the asset groups, we recorded non-cash impairment charges of$64.0 million in the first quarter of 2020. Loss on Abandonment of Assets During the first quarter of 2020, we evaluated the carrying value of our salt water disposal assets. Based on our revised forecast of asset utilization, we determined certain assets were no longer expected to be used and wrote off certain salt water disposal assets that we now consider abandoned. We recorded expense of$17.6 million related to the write-down of our salt water disposal asset in first quarter of 2020. In the third quarter of 2020, we recorded expense of$1.2 million related to the write-down of our drilling line asset.
General and Administrative
Corporate general and administrative expenses increased$14.4 million or 48% in the first nine months of 2020 as compared to the first nine months of 2019 primarily due to consulting fees paid prior to filing for bankruptcy and costs incurred for separation benefits provided to employees that were part of our reduction in force inApril 2020 . We incurred$20.2 million in advisory and restructuring fees.
Gain (Loss) on Disposition of Assets
There was a$0.3 million gain on disposition of assets in the first nine months of 2020 primarily related to the sale of vehicles, drilling rigs, and other drilling equipment. For the first nine months of 2019, we had a loss of$1.4 million . Of this amount, we had a gain of$0.5 million was related to assets held for sale that were sold which consisted of four drilling rigs and other drilling components. The remaining loss of$1.9 million was related to the sales of other drilling rig components and vehicles.
Other Income (Expense)
Interest expense, net of capitalized interest, decreased$3.4 million between the comparative first nine months of 2020 and 2019 due primarily to an 34% decrease in average long-term debt outstanding and no capitalized interest in the first nine months of 2020 and by a lower average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, constructing additional drilling rigs, and constructing gas gathering systems. Because we are not currently undergoing any capital projects, we had no capitalized interest for the first nine months of 2020 compared to$12.6 million for the first nine months of 2019 and was netted against our gross interest of$23.7 million and$39.7 million for the first nine months of 2020 and 2019, respectively. Our average interest rate decreased from 6.4% in the first nine months of 2019 to 5.5% in the first nine months of 2020 and our average debt outstanding decreased$247.9 million in the first nine months of 2020 compared to the first nine months of 2019 primarily due to the Notes being settled with the Plan.
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. For more detail, see Note 2 - Emergence From Voluntary Reorganization Under Chapter 11.
Write-off of Debt Issuance Costs
Due to the remaining commitments of the Unit credit agreement being terminated by the RBL Lenders', the unamortized debt issuance costs of$2.4 million were written off during the second quarter of 2020.
Gain (Loss) on Derivatives
Gain (loss) on derivatives decreased by
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Table of Contents Income Tax Benefit Income tax benefit was$14.6 million in the first nine months of 2020 compared to$53.1 million in the first nine months of 2019 primarily due the need of a valuation allowance against what would otherwise be a sizable income tax benefit due to our substantial pre-tax loss for the first nine months of 2020. The income tax benefit was recognized in the Predecessor period endingAugust 31,2020 . Due to changes in the book basis of our assets in conjunction with our fresh start accounting and our net operating losses, it was determined that a full valuation allowance against our net deferred tax asset was needed as of the Effective Date and the Successor period endingSeptember 30, 2020 . Our blended effective tax rate was 1.60% for the first nine months of 2020 (1.62% for the Predecessor period endingAugust 31, 2020 and 0.00% for the Successor period endingSeptember 30, 2020 ) compared to 19.57% for the first nine months of 2019. The rate change was primarily due to the need of a valuation allowance against our income tax benefit for the first nine months of 2020. We recognized$0.9 million of current income tax benefit for the first nine months of 2020 due to the acceleration of our alternative minimum tax credit refund as prescribed by the CARES act. We did not have a current income tax benefit for the first nine months of 2019. We paid no income taxes in the first nine months of 2020.
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