Please read this discussion of our financial condition and results of operations with the consolidated financial statements and related notes in Item 8 of this report. General
We were founded in 1963 as a contract drilling company. Today, we operate, manage and analyze our operating results across our three main lines of business:
•Oil and Natural Gas - carried out by our subsidiaryUnit Petroleum Company . 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 . This segment contracts to drill onshore oil and natural gas wells for others and for our own account. •Mid-Stream - carried out by our subsidiarySuperior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account. We own 50% of this subsidiary.
Recent developments
Emergence of a voluntary reorganization under Chapter 11 of the Bankruptcy Code
OnMay 22, 2020 , the Debtors filed petitions for reorganization under Chapter 11 of Title 11 of the United States Code in theUnited States Bankruptcy Court for the Southern District of Texas , Houston Division. 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 authority of the bankruptcy court and under the Bankruptcy Code. The Debtors filed their Plan and the related disclosure statement with the bankruptcy court onJune 9, 2020 . OnAugust 6, 2020 , the bankruptcy 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. On the 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.
New start accounting
On the Effective Date, we qualified for and adopted fresh start accounting under the provisions set forth in FASB Topic ASC 852 as (i) the reorganization value of the company's assets immediately before 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 Successor financial statements will not be comparable to the financial statements prepared before the Effective Date.
Changes in accounting policies
On the Effective Date, we 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. •Regarding our Contract Drilling segment, we elected to depreciate all drilling assets using the straight-line method over the useful lives of the assets ranging from four to ten years. •We 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. 35 --------------------------------------------------------------------------------
Table of Contents Business Outlook Strategy
Following our exit from bankruptcy, we are focused on increasing value through free cash flow generation, debt repayment and selective investments in each of our business lines. Investments are expected to be funded from free cash flow from operations, proceeds from the disposal of non-core assets and capacity available 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 are optimizing production from our existing reserves and converting non-producing reserves to producing, with no exploratory drilling currently planned. We 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 are focused on increasing the use of our BOSS drilling rigs, as well as upgrading 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 are focused on generating predictable free cash flows with limited exposure to commodity prices. We also plan to continue seeking business development opportunities in our core areas using the Superior credit agreement (which Unit is not a party to nor guarantees) or other financing sources that are available to it.
COVID-19 pandemic and the 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 implemented various measures to ensure we are conducting our business in a safe and secure manner. COVID-19 and the response of governments around 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 in 2020. The global oil and natural gas supply and demand imbalance continues to be uncertain, with possible on-going and future adverse effects on the oil and gas industry. During the last two years, commodity prices have been volatile. We reduced our operated rig count in the first quarter of 2019 before getting as high as six drilling rigs in the second quarter of 2019. Due to declining prices, we shut down our own drilling program inJuly 2019 and used no drilling rigs for the remainder of 2019 and 2020. 36 -------------------------------------------------------------------------------- Table of Contents The following chart reflects the significant fluctuations in the prices for oil and natural gas:
[[Image Removed: unt-20201231_g2.jpg]]The following graph reflects the significant fluctuations in NGL prices:
[[Image Removed: unt-20201231_g3.jpg]] _________________________ 1.NGLs prices reflect a weighted-average, based on production, ofMont Belvieu andConway prices. 37
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Table of Contents Executive SummaryOil and Natural Gas Fourth quarter 2020 production from our oil and natural gas segment was 2,592 MBoe, a decrease of 9% and 38% from the third quarter of 2020 and the fourth quarter of 2019, respectively. The decreases came from fewer net wells being drilled in 2020 to replace the declines in existing drilled wells. Oil and NGLs production during the fourth quarter of 2020 and the fourth quarter of 2019 were each 48% of our total production. Fourth quarter 2020 oil and natural gas revenues increased 6% over the third quarter of 2020 and decreased 48% from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due an increase in commodity prices partially offset by a decrease in equivalent production. The decrease from the fourth quarter of 2019 was primarily due to a decrease in equivalent production and oil and NGLs prices. Our hedged natural gas prices for the fourth quarter of 2020 increased 56% over third quarter of 2020 and increased 1% over fourth quarter of 2019. Our hedged oil prices for the fourth quarter of 2020 increased 43% over the third quarter of 2020 and decreased 29% from the fourth quarter of 2019, respectively. Our hedged NGLs prices for the fourth quarter of 2020 increased 21% over the third quarter of 2020 and decreased 24% from the fourth quarter of 2019. Direct profit (oil and natural gas revenues less oil and natural gas operating expense) increased 35% over the third quarter of 2020 and decreased 52% from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due to an increase in commodity prices and a reduction in saltwater disposal expense and G&A partially offset by a decrease in equivalent production. The decrease from the fourth quarter of 2019 was primarily due to lower revenues due to lower commodity prices and volumes partially offset by lower LOE and G&A. Operating cost per Boe produced for the fourth quarter of 2020 decreased 10% from the third quarter of 2020 and decreased 3% from the fourth quarter of 2019. The decrease from the third quarter of 2020 was primarily due to lower G&A and saltwater disposal expense. The decrease from the fourth quarter of 2019 was primarily due to lower LOE and G&A partially offset by no longer capitalizing directly related overhead costs in 2020 due to the absence of drilling in 2020.
TO
Weighted Average Term Commodity Contracted Volume Fixed Price for Swaps Contracted Market Jan'21 - Dec'21 Natural gas - basis swap 30,000 MMBtu/day$(0.215) NGPL TEXOK Jan'21 - Oct'21 Natural gas - swap 50,000 MMBtu/day$2.82 IF - NYMEX (HH) Nov'21 - Dec'21 Natural gas - swap 45,000 MMBtu/day$2.90 IF - NYMEX (HH) Jan'22 - Dec'22 Natural gas - swap 5,000 MMBtu/day$2.61 IF - NYMEX (HH) Jan'23 - Dec'23 Natural gas - swap 22,000 MMBtu/day$2.46 IF - NYMEX (HH) Jan'22 - Dec'22 Natural gas - collar 35,000 MMBtu/day$2.50 -$2.68 IF - NYMEX (HH) 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 In westernOklahoma , annual production averaged 73 MMcfe per day (31% oil, 22% NGLs, 47% natural gas) which was a decrease of approximately 24% compared to 2019. During 2020, we did not drill any operated wells in this area and participated in one net non-operated well. In theTexas panhandle, annual production averaged 67 MMcfe per day (8% oil, 37% NGLs, 55% natural gas) which was a decrease of approximately 27% compared to 2019. During 2020, we did not drill any operated wells in this area, nor did we participate in any non-operated wells. In ourWilcox play located primarily inPolk ,Tyler ,Hardin andGoliad Counties,Texas , annual production averaged 45 MMcfe per day (9% oil, 29% NGL's, 62% natural gas) which is a decrease of approximately 41% compared to 2019. During 2020, we did not drill any operated wells in this area, nor did we participate in any non-operated wells. 38 -------------------------------------------------------------------------------- Table of Contents During the Successor Period and Predecessor Period of 2020, we participated in the drilling of three wells (0.30 net wells) and 16 wells (0.35 net wells), respectively. Contract Drilling The average number of drilling rigs we operated in the fourth quarter of 2020 was 7.6 compared to 5.1 and 18.3 in the third quarter of 2020 and fourth quarter of 2019, respectively. As ofDecember 31, 2020 , nine of our drilling rigs were operating. Revenue for the fourth quarter of 2020 increased 24% over the third quarter of 2020 and decreased 59% from the fourth quarter of 2019. The increase over the third quarter of 2020 was due to more drilling rigs operating and increasing dayrates. The decrease from the fourth quarter of 2019 was due to less drilling rigs operating and lower dayrates. Dayrates for the fourth quarter of 2020 averaged$17,923 , which was a 6% increase over the third quarter of 2020 and a 7% decrease from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due to more drilling rigs operating. The decrease from the fourth quarter of 2019 was primarily due to less drilling rigs operating. Operating costs for the fourth quarter of 2020 increased 29% over the third quarter of 2020 and decreased 59% from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due to more drilling rigs operating. The decrease from the fourth quarter of 2020 was primarily due to less drilling rigs operating. Operating cost per day for the fourth quarter of 2020 decreased 15% from the third quarter of 2020 and decreased 2% from the fourth quarter of 2019. Revenue days for the fourth quarter of 2020 increased 51% over the third quarter of 2020 and decreased 58% from the fourth quarter of 2019. Direct profit (contract drilling revenue less contract drilling operating expense) for the fourth quarter of 2020 increased 13% over the third quarter of 2020 and decreased 59% from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due to more drilling rigs operating. The decrease from the fourth quarter of 2019 was primarily due to less drilling rigs operating. The contract drilling segment has operations inOklahoma ,Texas ,New Mexico ,Wyoming , andNorth Dakota . As ofDecember 31, 2020 , three drilling rigs were working inOklahoma , three in thePermian Basin ofWest Texas , two inWyoming and one drilling rig in theBakken Shale ofNorth Dakota . During 2020, almost all our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates. As ofDecember 31, 2020 , we had five term drilling contracts with original terms ranging from two months to one year. Three of these contracts are up for renewal in 2021, (two in the first quarter and one in the second quarter) and two are up for renewal in 2022 and beyond. 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 and pay an early termination penalty for the remaining term of the contract. We recorded$9.2 million and$4.8 million in early termination fees in 2020 and 2019, respectively.
Six of our 14 existing BOSS rigs were under contract to
All of our contracts are day contracts.
For 2021, capital expenditures for this segment are expected to primarily be for maintenance capital on operating drilling rigs and the possible conversion of certain SCR drilling rigs to AC drilling rigs if practicable. We also plan to pursue the disposal or sale of our non-core, older drilling rig fleet.
Mid-stream
Fourth quarter 2020 liquids sold per day decreased 31% from the third quarter of 2020 and decreased 24% from the fourth quarter of 2019. The decreases were primarily due to declining volumes and fewer wells connected to our major systems resulting in lower liquids production. For the fourth quarter of 2020, gas processed per day decreased 11% from the third quarter of 2020 and decreased 19% from the fourth quarter of 2019. The decreases were primarily due to declining volumes and fewer wells connected to our major systems. For the fourth quarter of 2020, gas gathered per day decreased 11% from the third 39 -------------------------------------------------------------------------------- Table of Contents quarter of 2020 and decreased 20% from the fourth quarter of 2019. The decreases were primarily due to lower volumes from our major gathering and processing systems resulting from fewer wells connected and declining wellhead volumes. NGLs prices in the fourth quarter of 2020 increased 35% over the prices received in the third quarter of 2020 and increased 5% over the prices received in the fourth quarter of 2019. Because certain of the 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 NGLs prices. Direct profit (mid-stream revenues less mid-stream operating expense) for the fourth quarter of 2020 decreased 45% from the third quarter of 2020 and decreased 12% from the fourth quarter of 2019, respectively. The decrease from the third quarter of 2020 was primarily due to recognizing a shortfall fee in the third quarter of 2020 in the amount of$5.3 million and due to declining volumes on our major systems. The decrease from the fourth quarter of 2019 was primarily due to lower volume on our major systems and lower condensate prices. Total operating cost for this segment for the fourth quarter of 2020 increased 17% over the third quarter of 2020 and decreased 3% from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due to an increase in gas purchase cost due to higher purchase prices. The decrease from the fourth quarter of 2019 was primarily due to declining wellhead volumes and fewer wells connected resulting in lower purchased volumes. At theCashion processing facility in centralOklahoma , total throughput volume for the fourth quarter of 2020 averaged approximately 64.2 MMcf per day and total production of natural gas liquids averaged approximately 252,000 gallons per day. For 2020, we continued to connect new wells to this system for third party producers. Since the first of 2020, we connected 18 new wells to this system from producers. The total processing capacity of theCashion system is 105 MMcf per day.
In the Appalachian region, at the Pittsburgh Mills collection system, the average collected volume for the fourth quarter of 2020 was 131.7 MMcf per day and the average collected volume for 2020 was 152.3 MMcf per day. In 2020, we connected four new infill wells to an existing well pad.
Also, in the Appalachian area at ourSnow Shoe gathering system, the average gathering volume for the fourth quarter was 2.5 MMcf per day and the average gathered volume for 2020 was 3.0 MMcf per day. In 2020, we did not connect any new wells to this system. AtSnow Shoe for 2020, we also charged a demand fee based on a volume of 55 MMcf per day. This demand fee volume will be reduced in 2021 to 51 MMcf per day. Additionally, in 2020, we recognized a shortfall fee from a producer on this system for$5.3 million . This fee will be invoiced in the first quarter of 2021. At theHemphill processing facility located in theTexas panhandle, average total throughput volume for the fourth quarter of 2020 was 46.6 MMcf per day and average total throughput volume for 2020 was 51.3 MMcf per day. Total average production of natural gas liquids for the fourth quarter of 2020 decreased to approximately 110,000 gallons per day due to operating in ethane rejection. Total production of natural gas liquids for 2020 averaged approximately 152,000 gallons per day. The total processing capacity of theHemphill system is 135 MMcf per day. In 2020, we did not connect any new wells to this system. Currently there are no active rigs in the area, and we do not anticipate any new well connects for this system. At the Segno gathering system located inEast Texas , the average throughput volume for the fourth quarter of 2020 decreased to approximately 31.0 MMcf per day due to declining production volume along with no new drilling activity in the area. For 2020, the average throughput volume for this system was approximately 40 MMcf per day. During 2020, we did not connect any new wells to this system.
The planned capital spending in 2021 for this segment will be approximately
Critical accounting conventions and estimates
Summary
In this section, we identify those critical accounting policies we follow in preparing our financial statements and related disclosures. Many policies require us to make difficult, subjective, and complex judgments while making estimates of matters inherently imprecise. Some accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or had different assumptions been used. We evaluate our estimates and assumptions regularly. We base our estimates on historical experience and various other assumptions we believe are reasonable under the circumstances, the results of which support making judgments about the carrying values of assets and liabilities not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. In this discussion we explain the nature of these estimates, 40 -------------------------------------------------------------------------------- Table of Contents assumptions and judgments, and the likelihood that materially different amounts would be reported in our financial statements under different conditions or using different assumptions.
Significant estimates and assumptions
Full Cost Method of Accounting for Oil, NGLs, andNatural Gas Properties . Determining our oil, NGLs, and natural gas reserves is a subjective process. It entails estimating underground accumulations of oil, NGLs, and natural gas that cannot be measured in an exact manner. Accuracy of these estimates depends on several factors, including, the quality and availability of geological and engineering data, the precision of the interpretations of that data, and individual judgments. Each year, we hire an independent petroleum engineering firm to audit our internal evaluation of our reserves. That audit as ofDecember 31, 2020 covered those reserves we projected to comprise 85% of the total proved developed future net income discounted at 10% (based on theSEC's unescalated pricing policy). Included in Part I, Item 1 of this report are the qualifications of our independent petroleum engineering firm and our employees responsible for preparing our reserve reports. The accuracy of estimating oil, NGLs, and natural gas reserves varies with the reserve classification and the related accumulation of available data, as shown in this table: Type of Reserves Nature of Available Data Degree of Accuracy Proved undeveloped Data from offsetting wells, seismic data Less accurate Proved developed non-producing The above and logs, core samples,
test well,
pressure data More accurate Proved developed producing The above and production history, pressure data over time Most accurate Assumptions of future oil, NGLs, and natural gas prices and operating and capital costs also play a significant role in estimating these reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are influenced by the assumed prices and costs due to the economic limit (that point when the projected costs and expenses of producing recoverable oil, NGLs, and natural gas reserves are greater than the projected revenues from the oil, NGLs, and natural gas reserves). But more significantly, the estimated present value of the future cash flows from our oil, NGLs, and natural gas reserves is sensitive to prices and costs and may vary materially based on different assumptions. Companies, like ours, using full cost accounting use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements.
We calculate the DD&A on a production unit method. Each quarter, we use these formulas to calculate the DD&A allowance for our producing properties:
•DD&A Rate = Unamortized Cost / End of Period Reserves Adjusted for Current Period Production •Provision for DD&A = DD&A Rate x Current Period Production Unamortized cost includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved properties, and equipment not placed in service. Oil, NGLs, and natural gas reserve estimates have a significant impact on our DD&A rate. If future reserve estimates for a property or group of properties are revised downward, the DD&A rate will increase because of the revision. If reserve estimates are revised upward, the DD&A rate will decrease.
Depreciation and amortization costs for our oil and gas properties are calculated quarterly using end-of-period reserve quantities adjusted for production for the period.
We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, we capitalize all costs incurred in the acquisition, exploration, and development of oil and natural gas properties. At the end of each quarter, the net capitalized costs of our oil and natural gas properties are limited to that amount which is the lower of unamortized costs or a ceiling. The ceiling is defined as the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (based on the unescalated 12-month average price 41 -------------------------------------------------------------------------------- Table of Contents on our oil, NGLs, and natural gas adjusted for any cash flow hedges), plus the cost of properties not being amortized, plus the lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are required to write-down the excess amount. A ceiling test write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders' equity in the period of occurrence and results in lower DD&A expense in future periods. Once incurred, a write-down cannot be reversed. The risk we will be required to write-down the carrying value of our oil and natural gas properties increases when the prices for oil, NGLs, and natural gas are depressed or if we have large downward revisions in our estimated proved oil, NGLs, and natural gas reserves. Application of these rules during periods of relatively low prices, even if temporary, increases the chance of a ceiling test write-down. AtDecember 31, 2020 , our reserves were calculated based on applying 12-month 2020 average unescalated prices of$39.57 per barrel of oil,$18.70 per barrel of NGLs, and$1.98 per Mcf of natural gas (then adjusted for price differentials) over the estimated life of each of our oil and natural gas properties.
Deficiency of the succession period
As ofSeptember 1, 2020 , we adopted fresh start accounting and adjusted our assets to fair value. Although under fresh start accounting we recorded our assets at fair value on emergence, the application of the full cost accounting rules resulted in non-cash ceiling test write-downs of$26.1 million pre-tax during the Successor Period of 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. 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. We do not anticipate a non-cash ceiling test write-down in the first quarter of 2021 of our proved reserves. It is hard to predict with any 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 atDecember 31, 2020 , and only adjust the 12-month average price as ofMarch 2021 , our forward-looking expectation is that we will not recognize an impairment in the first quarter of 2021. 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 plans or financial results and the actual amount of any write-down may vary significantly from this estimate depending on the final future determination.
Impairments from the previous period
Oil and Natural Gas . During the Predecessor Period of 2020, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of$393.7 million pre-tax ($346.6 million net of tax) due to the reduction in the 12-month average commodity prices and the impairment of our unproved oil and gas properties described below. In 2019, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of$559.4 million pre-tax ($422.4 million net of tax) due to the reduction of the 12-month average commodity prices and the removal of proved undeveloped reserves due to the uncertainty regarding our ability to finance future capital expenditures. 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 no longer considered 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. Mid-stream. We determined that the carrying value of certain long-lived asset groups in our mid-stream segment, where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. 42 --------------------------------------------------------------------------------
Table of contents Based on the estimated fair value of the groups of assets, we recognized non-cash impairment charges of
Contract Drilling. On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, the expenditures necessary to bring them into working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utility to our other marketed rigs are transferred to rigs or to our yards to be used as spare equipment. The remaining components of these rigs are retired. AtMarch 31, 2020 , due to market conditions, we performed impairment testing on two asset groups which were comprised of our SCR diesel-electric drilling rigs and our 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 charges of$3.0 million for other miscellaneous drilling equipment. We used the income approach to determine the fair value of the SCR drilling rigs asset group. This approach uses significant assumptions including management's best estimates of the expected future cash flows and the estimated useful life of the asset group. Fair value determination requires a considerable amount of judgement and is sensitive to changes in underlying assumptions and economic factors. As a result, there is no assurance the fair value estimates made for the impairment analysis will be accurate in the future. 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 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.
We recorded expenses of
Costs Withheld from Amortization. Costs associated with unproved properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and related seismic data, the drilling of wells, and capitalized interest are initially excluded from our amortization base. Leasehold costs are transferred to our amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. Leasehold costs are transferred to our amortization base to the extent a reduction in value has occurred. Our decision to withhold costs from amortization and the timing of transferring those costs into the amortization base involve significant judgment determinations which may change over time based on several factors, including our drilling plans, availability of capital, project economics and results of drilling on adjacent acreage. 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. This resulted 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. In 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$73.9 million of costs being added to the total of our capitalized costs being amortized. AtDecember 31, 2020 , we had approximately$1.6 million of costs excluded from the amortization of our full cost pool. Accounting for ARO for Oil, NGLs, andNatural Gas Properties . We record the fair value of liabilities associated with the future plugging and abandonment of wells. In our case, when the reserves in each of our oil or gas wells deplete or the wells otherwise become uneconomical, we must incur costs to plug and abandon the wells. These costs are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). We have no assets restricted to settle these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs considering the type of well (either oil, natural gas, or both), the depth of the well, the physical location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to 43 -------------------------------------------------------------------------------- Table of Contents determine the current present value of this obligation. To the extent any change in these assumptions affect future revisions and impacts the present value of the existing ARO, a corresponding adjustment is made to the full cost pool. Drilling Contracts. The type of contract used determines our compensation. All our contracts in 2020 and 2019 were daywork contracts. Under a daywork contract, we provide the drilling rig with the required personnel and the operator supervises the drilling of the well. Our compensation is based on a negotiated rate to be paid for each day the drilling rig is used. Accounting for Value of Stock Compensation Awards. To account for stock-based compensation, compensation cost is measured at the grant date based on the fair value of an award and is recognized over the service period, which is usually the vesting period. We elected to use the modified prospective method, which requires compensation expense to be recorded for all unvested stock options and other equity-based compensation beginning in the first quarter of adoption. Determining the fair value of an award requires significant estimates and subjective judgments regarding the appropriate option pricing model, the expected life of the award and performance vesting criteria assumptions. As there are inherent uncertainties related to these factors and our judgment in applying them to the fair value determinations, there is risk that the recorded stock compensation may not accurately reflect the amount ultimately earned by the employee. All our previously reported awards were terminated because of our Chapter 11 Cases and no awards were outstanding as ofDecember 31, 2020 . Accounting for Derivative Instruments and Hedging. All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value before their maturity (i.e., temporary fluctuations in value) along with any derivatives settled are reported in gain (loss) on derivatives in our Consolidated Statements of Operations. Bankruptcy Reorganization. We have applied Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852) in preparing our consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 Cases, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings, are recorded in reorganization items, net on our accompanying consolidated statements of operations. Fresh Start. The company qualified for and adopted fresh start accounting under the provisions of ASC 852. When applying ASC 852, an entity determines its reorganization value and enterprise value. Reorganization value, as determined under ASC 820, Fair Value Measurement, represents the fair value of the entity's total assets before the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The entity's enterprise value represents the estimated fair value of an entity's long-term debt and equity. The assumptions used in estimating these values are inherently uncertain and require significant judgment.
New accounting standards
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 should 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 apply the amendments prospectively throughDecember 31, 2022 . The amendments will not have a material impact on our consolidated financial statements. Income Taxes (Topic 740)-Simplifying the Accounting for Income Taxes. The FASB issued ASU 2019-12 to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendments will be effective for reporting periods beginning afterDecember 15, 2020 . Early adoption is permitted. This standard will not have a material impact on our consolidated financial statements. 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 44 -------------------------------------------------------------------------------- Table of Contents in more timely recognition of credit losses. The amendment was effective for reporting periods afterDecember 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 afterDecember 15, 2019 . The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures.
Financial situation and liquidity
Summary
Our financial condition and liquidity primarily depend on the cash flow from our operations and borrowings under our credit agreements. The principal factors determining our cash flow are: •the amount of natural gas, oil, and NGLs we produce; •the prices we receive for our natural gas, oil, and NGLs production; •the use of our drilling rigs and the dayrates we receive for those drilling rigs; and •the fees and margins we obtain from our natural gas gathering and processing contracts. Our Chapter 11 Cases 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 available funds under the Exit Credit Agreement and the Superior credit agreement are adequate to cover our liquidity requirements for at least the next 12 months. Below is a summary of certain financial information for the periods indicated: Successor Predecessor Period September 1, Period 2020 January 1, For the Year through 2020 through Ended December 31, August 31, December 31, 2020 2020 2019 (In thousands) Net cash provided by operating activities$ 29,807 $ 44,956 $ 269,396 Net cash used in investing activities (2,258) (20,139) (394,563)
Net cash provided by (used in) financing activities (47,775)
7,552 119,286 Net increase (decrease) cash, restricted cash, and cash equivalents$ (20,226) $ 32,369 $ (5,881)
Cash flow from operating activities
Our operating cash flow is primarily influenced by the prices we receive for our oil, NGLs, and natural gas production, the oil, NGL, and natural gas we produce, settlements of derivative contracts, third-party use for our drilling rigs and mid-stream services, and the rates we can charge for those services. Our cash flows from operating activities are also affected by changes in working capital. Net cash provided by operating activities decreased by$194.6 million in 2020 compared to 2019 primarily due to lower revenues due to lower commodity prices and lower drilling rig utilization partially offset by an increase in operating assets and liabilities related to the timing of cash receipts and disbursements.
Cash flow from investing activities
We have historically dedicated a substantial portion of our capital budgets to our exploration for and production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells. Although we curtailed our spending in 2020, we expect that any future capital budgets would be focused on development or acquisitions of producing oil and gas properties, but not exploration.
Cash flow used in investing activities decreased by
45 -------------------------------------------------------------------------------- Table of Contents primarily to a decrease in capital expenditures due to a 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.
Cash flow from financing activities
Cash flow generated by (used in) financing activities decreased by
AtDecember 31, 2020 , we had unrestricted cash and cash equivalents totaling$12.1 million and had borrowed$99.0 million of the amounts available under the Exit Credit Agreement. We did not have any outstanding borrowings under our Superior credit agreement.
Below is a summary of certain financial information at
Successor Predecessor 2020 2019 (In thousands) Working capital$ 2,575 $ (154,998) Current portion of long-term debt$ 600 $
108,200
Long-term debt (1)$ 98,400 $
663,216
Equity attributable to
853 878
_________________________
1.Long-term debt is net of the unamortized discount and debt issuance costs for the prior period.
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$2.6 million atDecember 31, 2020 and negative working capital of$155.0 million as ofDecember 31, 2019 . The increase in working capital is primarily due to more cash and cash equivalents and lower accounts payable and accrued liabilities from to the settlement of the liabilities subject to compromise partially offset by lower accounts receivable. Both the Superior credit agreement and the Exit Credit Agreement are used for working capital. AtDecember 31, 2020 , we had borrowed$99.0 million under the Exit Credit Agreement and we did not have any outstanding borrowings under our Superior credit agreement. The effect of our derivatives decreased working capital by$1.0 million as ofDecember 31, 2020 and increased working capital by$0.6 million as ofDecember 31, 2019 .
Long-term debt
Our Exit Credit Agreement is primarily used for working capital purposes as it limits the amount that can be borrowed for capital expenditures. These limitations restrict future capital projects using the Exit Credit Agreement. The Exit Credit Agreement also requires that any proceeds from the disposition of certain assets be used to repay amounts outstanding.
Oil and 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, by worldwide oil price levels, and recently by the worldwide economic impact from the coronavirus. Domestic oil prices are primarily influenced by world oil market developments. These factors are beyond our control and we cannot predict nor measure their future influence on the prices we will receive.
Contract drilling operations
Many factors influence the number of drilling rigs we have working, 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, 46 -------------------------------------------------------------------------------- Table of Contents 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. Competition to keep qualified labor continues. Our drilling rig personnel are a key component to the overall success of our drilling services. With the present conditions in the drilling industry, we do not anticipate increases in the compensation paid to those personnel in the near term. During 2020, most of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The continuous fluctuations in commodity prices for oil and natural gas changes demand for drilling rigs. These factors ultimately affect the demand and mix of the type of 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 Successor Period and Predecessor Period of 2020, our average dayrate was$17,807 and$18,911 per day, respectively, compared to$18,762 per day for 2019. Our average number of drilling rigs used (utilization %) for the Successor Period and Predecessor Period of 2020 were 7.2 (12%) and 11.5 (20%), respectively, compared with 24.6 (43%) in 2019. Based on the average utilization of our drilling rigs during 2020, a$100 per day change in dayrates has a$1,010 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 statement of operations, 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. By providing drilling services for the oil and natural gas segment, we eliminated revenue of$15.8 million during 2019 from our contract drilling segment and eliminated the associated operating expense of$14.2 million yielding$1.6 million as a reduction to the carrying value of our oil and natural gas properties. We did not eliminate any revenue or expense in 2020.
No impairment trigger was identified during the 2020 succession period for our contract drilling assets.
Mid-term operations
This 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, 17 gathering systems, and approximately 2,090 miles of pipeline. Its operations are inOklahoma ,Texas ,Kansas ,Pennsylvania , andWest Virginia . This segment enhances our ability to gather and market not only our own natural gas and NGLs but also natural gas and NGLs owned by third parties and serves as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the Successor Period of 2020, Predecessor Period of 2020, and the year 2019, Superior purchased$10.6 million ,$11.8 million , and$40.6 million , respectively, of our oil and natural gas segment's natural gas and NGLs production, and provided gathering and transportation services of$1.2 million ,$2.8 million , and$6.9 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 consolidated financial statements. Our mid-stream segment gathered an average of 367,302 Mcf per day in 2020 compared to 435,646 Mcf per day in 2019. It processed an average of 150,559 Mcf per day in 2020 compared to 164,482 Mcf per day in 2019, and sold NGLs of 555,454 gallons per day in 2020 compared to 625,873 gallons per day in 2019. Gas gathering volumes per day in 2020 decreased primarily due to lower volumes from most of our major gathering and processing systems resulting from declining wellhead volumes and fewer wells connected except from theCashion facility. Volumes processed and NGLs sold in 2020 decreased mainly due to lower volumes from our processing facility in theTexas panhandle resulting from declines and not connecting any new wells in 2020.
Our predecessor credit and debt agreements
Exit Credit Agreement. On the Effective Date, under the Plan, we entered into an amended and restated credit agreement (the Exit Credit Agreement), providing for a$140.0 million senior secured revolving credit facility and a$40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC, (ii) the guarantors, including the company and all its subsidiaries existing as of the Effective Date (other thanSuperior Pipeline Company, L.L.C. and its subsidiaries), (iii) the lenders under the agreement, and (iv)BOKF, NA dbaBank of Oklahoma as administrative agent and collateral agent (the Administrative Agent). 47 -------------------------------------------------------------------------------- Table of Contents The maturity date of borrowings under the 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 that we comply with certain financial ratios, including a covenant that we 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 , we 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 we 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 the personal and real property assets of the borrowers and the guarantors, including our ownership interests inSuperior Pipeline Company, L.L.C. On the Effective Date, we had (i)$40.0 million in principal amount of Term Loans outstanding, (ii)$92.0 million in principal amount of Revolving Loans outstanding, and (iii) approximately$6.7 million of outstanding letters of credit. AtDecember 31, 2020 , we had$0.6 million and$98.4 million outstanding current and long-term borrowings, respectively, under the Exit Credit Agreement. Predecessor's Credit Agreement. Before the filing of the Chapter 11 Cases, the Unit credit agreement 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 Chapter 11 Cases 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, our debt associated with the Unit credit agreement is reflected as a current liability in our Consolidated Balance Sheets as ofDecember 31, 2019 . The classification as a current liability due to the Credit Agreement Extension Condition was based on the uncertainty regarding our ability to repay or refinance the Notes beforeNovember 16, 2020 . In addition, onMay 22, 2020 , the lenders' remaining commitments under the Unit credit agreement 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 termination of the remaining commitments of the lenders under the Unit credit agreement, the unamortized debt issuance costs of$2.4 million were written off during the second quarter of 2020. Under the Unit 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. Before filing the Chapter 11 Cases, any part of the outstanding debt under the Unit 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 Unit 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. 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. 48 -------------------------------------------------------------------------------- Table of Contents Filing the bankruptcy petitions onMay 22, 2020 constituted an event of default that accelerated our obligations under the Unit credit agreement, and the lenders' rights of enforcement under the Unit credit agreement were automatically stayed because of the Chapter 11 Cases. On the Effective Date, each lender under the Unit credit agreement and the DIP Credit Agreement received its pro rata share of revolving loans, term loans and letter-of-credit participations under the Exit Credit Agreement, in exchange for that lender's allowed claims under the Unit credit agreement or the DIP Credit Agreement. Superior Credit Agreement. OnMay 10, 2018 , Superior entered into 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 (the 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) third day LIBOR plus 1.00%) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by mortgage liens on certain of Superior's processing plants and gathering systems. The 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 to Lender in the London Interbank Market or if that index no longer exists or accurately reflects the rate available to the Administrative Agent in the London 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. Additionally, the Superior credit agreement contains several customary covenants that, among other things, restrict (subject to certain exceptions) Superior's ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, enter into sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, enter into hedging arrangements, and acquire or dispose of assets. As ofDecember 31, 2020 , Superior was in compliance with the Superior credit agreement covenants.
The borrowings from the Superior credit agreement will be used to finance capital expenditures and acquisitions, to provide general working capital and letters of credit for Superior.
Unit is not a party to and does not guarantee Superior’s credit agreement. Superior and its subsidiaries were not debtors in the Chapter 11 matters, and Superior’s credit agreement was not affected by Unit’s bankruptcy.
6.625% Senior Subordinated Notes. The Notes were issued under an Indenture dated as ofMay 18, 2011 , between the company andWilmington Trust, National Association (successor toWilmington Trust FSB ), as Trustee (Trustee), as supplemented by the First Supplemental Indenture dated as ofMay 18, 2011 , between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as ofJanuary 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 our liability under the Notes was discharged as of the Effective Date. Holders of the Notes were issued shares of New Common Stock in accordance with the Plan. DIP Credit Agreement. As contemplated by the Restructuring Support Agreement between the company and certain of the Note holders and our lenders, the company and the other Debtors entered into a Superpriority Senior Secured Debtor-in-Possession Credit Agreement datedMay 27, 2020 ( DIP credit agreement), among the Debtors, the lenders under the facility (the DIP lenders), andBOKF, NA dbaBank of Oklahoma , as administrative agent, under which the DIP lenders agreed to provide us with the$36.0 million multiple-draw loan facility (DIP credit facility). The bankruptcy court entered an interim order onMay 26, 2020 approving the DIP credit facility, permitting the Debtors to borrow up to$18.0 million on an interim basis. OnJune 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 the assets of the Debtors under Section 363 of the Bankruptcy Code or otherwise, (iii) the effective date of a 49 -------------------------------------------------------------------------------- Table of Contents plan of reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of an order by the bankruptcy court dismissing any 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 facility 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 Credit Agreement. In addition, each holder received (or was entitled to receive) its pro rata share of an equity fee under the Exit Credit Agreement equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and on exercise of the Warrants).
For more information on the DIP credit agreement, please see Note 2 – Exit from a voluntary reorganization in chapter 11.
Mandates
Each holder of the Old Common Stock outstanding before the Effective Date that did not opt out of the release under the Plan, is entitled to receive 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, we entered into a Warrant Agreement (Warrant Agreement) withAmerican Stock Transfer & Trust Company, LLC . The Warrants expire on the earliest of (i)September 3, 2027 , (ii) consummation of a Cash Sale (as defined in the Warrant Agreement) or (iii) the consummation of a liquidation, dissolutions or winding up of the company (such earliest date, the Expiration Date). Each Warrant that is not exercised on or before the Expiration Date will expire, and all rights under that Warrant and the Warrant Agreement will cease on the Expiration Date. OnDecember 21, 2020 , we issued approximately 1.8 million Warrants to the holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares of Old Common Stock in street name through the facilities of the DTC. OnFebruary 11, 2021 , we issued 42,511 Warrants to certain holders of the Old 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). We expect to issue approximately 37,000 additional Warrants to the holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares through Direct Registration. Under the Plan, additional Warrants will be issued in book-entry form through the facilities of the DTC, and each holder owning shares of Old Common Stock through Direct Registration must provide that holder's brokerage account information to the company to receive such holder's distribution of Warrants. Holders of shares of the Old 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 required
Oil and Natural Gas Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures in our oil and natural gas are discretionary and directed toward growth. Any decision to increase our oil, NGLs, and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential, and opportunities to obtain financing, which provide us flexibility in deciding when and if to incur these costs. During the Successor Period and Predecessor Period of 2020, we participated in the drilling of three wells (0.30 net wells) and 16 wells (0.35 net wells), respectively, compared to 115 gross wells (29.15 net wells) in 2019. During the Successor Period of 2020, capital expenditures by this segment for oil and gas properties on the full cost method, excluding a$1.7 million reduction in the ARO liability and no acquisitions, totaled$4.0 million . During the Predecessor Period of 2020, capital expenditures, excluding a$29.2 million reduction in the ARO liability and$0.4 million in acquisitions (including associated ARO), totaled$5.4 million compared to 2019 capital expenditures of$264.9 million (excluding a$0.1 million reduction in the ARO liability and$3.7 million in acquisitions).
For 2021, we plan to focus our capital expenditures on the development of proven properties and the acquisition of proven and producing properties.
We sold non-core oil and natural gas assets, net of related expenses, for$0.4 million ,$1.2 million and$21.8 million during the Successor Period, and Predecessor Period of 2020, and the year 2019, respectively. Proceeds from those dispositions 50 --------------------------------------------------------------------------------
The table of contents has reduced the net book value of our full cost pool without any gain or loss being recognized. We plan to pursue additional disposals of non-core assets in 2021.
Contract Drilling Dispositions, Acquisitions, and Capital Expenditures. During 2019, we completed construction and placed into service our 12th, 13th, and 14th BOSS drilling rigs. These drilling rigs were subject to long-term contracts with third party operators.
We have not built any new BOSS drilling rigs in 2020. We have no commitments or current plans to build additional BOSS drilling rigs in 2021.
For 2021, capital expenditures are expected to primarily be for maintenance capital on operating drilling rigs and the possible conversion of certain SCR drilling rigs to AC drilling rigs if practicable. We also plan to pursue the disposal or sale of our non-core, idle drilling rig fleet. For 2020, we incurred$0.6 million during the Successor Period and$2.4 million during the Predecessor Period in capital expenditures, compared to$40.6 million in 2019. Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. At theCashion processing facility in centralOklahoma , total throughput volume for the fourth quarter of 2020 averaged approximately 64.2 MMcf per day and total production of natural gas liquids averaged approximately 252,000 gallons per day. For 2020, we continued to connect new wells to this system for third party producers. Since the first of 2020, we connected 18 new wells to this system from producers. The total processing capacity of theCashion system is 105 MMcf per day.
In the Appalachian region, at the Pittsburgh Mills collection system, the average collected volume for the fourth quarter of 2020 was 131.7 MMcf per day and the average collected volume for 2020 was 152.3 MMcf per day. In 2020, we connected four new infill wells to an existing well pad.
Also, in the Appalachian area at ourSnow Shoe gathering system, the average gathering volume for the fourth quarter was 2.5 MMcf per day and the average gathered volume for 2020 was 3.0 MMcf per day. In 2020, we did not connect any new wells to this system. AtSnow Shoe for 2020, we also charged a demand fee based on a volume of 55 MMcf per day. This demand fee volume will be reduced in 2021 to 51 MMcf per day. Additionally, in 2020, we recognized a shortfall fee from a producer on this system for$5.3 million . This fee will be invoiced in the first quarter of 2021. At theHemphill processing facility located in theTexas panhandle, average total throughput volume for the fourth quarter of 2020 was 46.6 MMcf per day and average total throughput volume for 2020 was 51.3 MMcf per day. Total average production of natural gas liquids for the fourth quarter of 2020 decreased to approximately 110,000 gallons per day due to operating in ethane rejection. Total production of natural gas liquids for 2020 averaged approximately 152,000 gallons per day. The total processing capacity of theHemphill system is 135 MMcf per day. In 2020, we did not connect any new wells to this system. Currently there are no active rigs in the area, and we do not anticipate any new well connects for this system. At the Segno gathering system located inEast Texas , the average throughput volume for the fourth quarter of 2020 decreased to approximately 31.0 MMcf per day due to declining production volume along with no new drilling activity in the area. For 2020, the average throughput volume for this system was approximately 40 MMcf per day. During 2020, we did not connect any new wells to this system. Our mid-stream segment incurred$1.3 million during the Successor Period and$9.3 million during the Predecessor Period in capital expenditures as compared to$64.4 million in 2019, which included$16.1 million for an acquisition. For 2021, our estimated capital expenditures will be approximately$15.0 million which we expect to be primarily for the maintenance and operation of our assets and connection of new wells. 51 -------------------------------------------------------------------------------- Table of Contents Contractual Commitments
TO
Payments Due by Period Less Than 2-3 4-5 After Total 1 Year Years Years 5 Years (In thousands) Long-term debt (1)$ 118,637 $ 6,494 $ 12,696 $ 99,447 $ - Operating leases (2) 5,520 4,075 1,376 16 53 Finance lease interest and maintenance (3) 558 558 - - - Firm transportation commitments (4) 1,379 1,020 359 - - Total contractual obligations$ 126,094 $ 12,147 $ 14,431 $ 99,463 $ 53 _________________________ 1.See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Exit Facility and includes interest calculated using ourDecember 31, 2020 interest rates of 6.6% for our Exit Credit Agreement. The Exit Credit Agreement has a maturity date ofMarch 1, 2024 and had an outstanding balance as ofDecember 31, 2020 of$99.0 million ($0.6 million is reflected as a current liability in our Consolidated Balance Sheets). The Superior credit agreement has a maturity date ofMay 10, 2023 and had no outstanding balance as ofDecember 31, 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$0.2 million . This is lease office space or yards inOklahoma City, Oklahoma ;Houston andOdessa, Texas ;Englewood, Colorado ; andPinedale, Wyoming under the terms of operating leases expiring throughJanuary 2022 . Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. 3.Maintenance and interest payments are included in our finance lease agreements. The finance leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining are$0.5 million and less than$0.1 million , respectively. 4.We have firm transportation commitments to transport our natural gas from various systems for approximately$1.0 million over the next twelve months and$0.4 million for the one year thereafter. During the second quarter of 2018, as part of the Superior transaction (see Note 19 - Variable Interest Entity Arrangements), 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. AtDecember 31, 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 . The total amount spent towards the$150.0 million as ofDecember 31, 2020 was$24.8 million . We do not anticipate meeting the contractual obligation over the remaining commitment period. 52 -------------------------------------------------------------------------------- Table of Contents AtDecember 31, 2020 , we also had these commitments and contingencies that could create, increase or accelerate our liabilities: Estimated Amount
of commitment expiration per period
Less Total Than 1 2-3 4-5 After 5 Other Commitments Accrued Year Years Years Years (In thousands) Separation benefit plans (1)$ 4,201 $ 1,543 Unknown Unknown Unknown ARO liability (2)$ 23,356 $ 2,121
Passive gas balancing (3)
$ 3,997 Unknown Unknown Unknown Unknown
Civil liability for accidents at work (4)
Unknown Unknown Unknown
Finance lease obligations (5)
$ – $ – $ – Contractual liability (6)
$ 4,172 $ 2,583
Other long-term liabilities (7)
$ 1,321 $ - $ - Derivative liabilities-commodity hedges$ 5,706 $ 1,047 $ 4,659 $ - $ - _________________________ 1.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. 2.When a well is drilled or acquired, under ASC 410 "Accounting for Asset Retirement Obligations," we record the fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells). 3.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. 4.We have recorded a liability for future estimated payments related to workers' compensation claims primarily associated with our contract drilling segment. 5.This amount includes commitments under finance lease arrangements for compressors in our mid-stream segment. 6.We have recorded a liability related to the timing of the revenue recognized on certain demand fees in our mid-stream segment. 7.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, or natural gas production. Any change in the fair value of all our derivatives are reflected in our Consolidated Statements of Operations. Commodity Derivatives. Our commodity derivatives 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. As ofDecember 31, 2020 , based on our fourth quarter 2020 average daily production, the approximated percentages of our production under derivative contracts were as follows: 2021 2022 2023 Daily oil production 66 % 46 % 26 % Daily natural gas production 55 % 45 % 25 % For commodities subject to derivative contracts, those contracts limit the risk of downward price movements. But they also limit increases in future revenues that would otherwise result from price movements above the contracted prices. 53 -------------------------------------------------------------------------------- Table of Contents Derivative transactions carry with them the risk that the counterparties may not be able to meet their financial obligations under the transactions. Based on our evaluation atDecember 31, 2020 , we believe the risk of non-performance by our counterparties is not material. AtDecember 31, 2020 , the fair values of the net assets we had with each of the counterparties to our commodity derivative transactions was: December 31, 2020 (In millions) Bank of Oklahoma $ (5.4) Bank of Montreal (0.3) Total net liabilities $ (5.7) If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty in our Consolidated Balance Sheets. AtDecember 31, 2020 , we recorded the fair value of our commodity derivatives on our balance sheet as current derivative liabilities of$1.0 million and long-term derivative liabilities of$4.7 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 long-term derivative liabilities of less than$0.1 million . All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations. These gains (losses) as of the periods indicated were: Successor Predecessor Period Period January 1, For the Year September 1, 2020 2020 through Ended through August 31, December 31, December 31, 2020 2020 2019
(In thousands) Gain (loss) on derivatives, including amounts settled during the period of (
$ (985)$ (10,704) $ 4,225
Compensation in shares and incentives
During 2020, we did not grant any awards. We recognized compensation expense of$6.1 million for all 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 2019, we granted awards covering 1,500,213 shares of restricted stock. These awards were granted as retention incentive awards and are being recognized over the awards' three-year vesting period. These awards were granted as retention incentive awards and are being recognized over their two- and three-year vesting periods. On the Effective Date, all 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. 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 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 54 -------------------------------------------------------------------------------- Table of Contents 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 consolidated financial statements for the years prior to termination. 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.
Effects of inflation
The effect of inflation in the oil and natural gas industry is primarily driven by the prices for oil, NGLs, and natural gas. Increases in these prices increase the demand for our contract drilling rigs and services. This increase in demand affects the dayrates we can obtain for our contract drilling services. During periods of higher demand for our drilling rigs we have experienced increases in labor costs and the costs of services to support our drilling rigs. Historically, during this same period, when oil, NGLs, and natural gas prices declined, labor rates did not come back down to the levels existing before the increases. If commodity prices increase substantially for a long period, shortages in support equipment (like drill pipe, third party services, and qualified labor) can cause additional increases in our material and labor costs. Increases in dayrates for drilling rigs also increase the cost of drilling our oil and natural gas properties. How inflation will affect us in the future will depend on increases, if any, realized in our drilling rig rates, the prices we receive for our oil, NGLs, and natural gas, and the rates we receive for gathering and processing natural gas.
Off-balance sheet provisions
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or for any other purpose. However, as is customary in the oil and gas industry, we are subject to various contractual commitments. 55 -------------------------------------------------------------------------------- Table of Contents Results of Operations Provided below is a comparison of selected operating and financial data after eliminations (in thousands unless otherwise specified): Successor Predecessor Period Period September 1, 2020 January 1, 2020 Year Ended through through December 31, Percent December 31, 2020 August 31, 2020 2019 Change (1) Total revenue$ 133,528 $ 276,957 $ 674,634 (39) % Net loss$ (13,988) $ (890,624) $ (553,828) (63) % Net income attributable to non-controlling interest $ 4,152$ 40,388 $ 51 NM Net loss attributable to Unit Corporation$ (18,140) $ (931,012) $ (553,879) (71) % Oil and Natural Gas: Revenue $ 57,578$ 103,439 $ 325,797 (51) % Operating costs excluding depreciation, depletion, amortization, and impairment $ 25,256$ 117,691 $ 135,124 6 % Depreciation, depletion, and amortization $ 14,869$ 68,762 $ 168,651 (50) % Impairment of oil and natural gas properties $ 26,063$ 393,726 $ 559,867 (25) % Average oil price received (Bbl) $ 37.29$ 31.98 $ 57.49 (45) % Average oil price per barrel received excluding derivatives $ 39.23$ 35.14 $ 55.13 (36) % Average NGL price received (Bbl) $ 9.28$ 4.83 $ 12.42 (59) % Average NGLs price per barrel received excluding derivatives $ 9.28$ 4.83 $ 12.42 (59) % Average natural gas price received (Mcf) $ 1.92$ 1.14 $ 2.04 (41) % Average natural gas price per mcf received excluding derivatives $ 1.91$ 1.11 $ 1.88 (38) % Oil production (MBbls) 626 1,562 3,208 (32) % NGLs production (MBbls) 1,045 2,399 4,773 (28) % Natural gas production (MMcf) 11,006 26,563 53,065 (29) % Depreciation, depletion, and amortization rate (Boe) $ 4.21$ 7.77 $ 9.66 (30) % Contract Drilling: Revenue $ 19,413$ 73,519 $ 168,383 (45) % Operating costs excluding depreciation $ 13,852$ 51,810 $ 115,998 (43) % Depreciation $ 2,102$ 15,544 $ 51,552 (66) % 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 7.2 11.5 24.6 (59) % Total drilling rigs available for use at the end of the period 58 58 58 - % Average dayrate on daywork contracts $ 17,807$ 18,911 $ 18,762 (1) % 56 -------------------------------------------------------------------------------- Table of Contents Successor Predecessor Period Period January 1, Year Ended September 1, 2020 2020 through through August 31, December 31, Percent December 31, 2020 2020 2019 Change (1) Mid-Stream: Revenue $ 56,537$ 99,999 $ 180,454 (13) % Operating costs excluding depreciation and amortization $ 42,169$ 68,045 $ 133,606 (18) % Depreciation and amortization $ 10,659$ 29,371 $ 47,663 (16) % Impairment of gas gathering and processing equipment and line fill $ -$ 63,962 $ 3,040 NM Gas gathered-Mcf/day 324,892 388,506 435,646 (16) % Gas processed-Mcf/day 135,615 158,031 164,482 (8) % Gas liquids sold-gallons/day 441,761 612,301 625,873 (11) % Number of natural gas gathering systems 17 18 19 (7) % Number of processing plants 11 11 11 - % Corporate and other: Loss on abandonment of assets $ -$ 18,733 $ - - % General and administrative expense $ 6,702$ 42,766 $ 38,246 29 % Other depreciation $ 332$ 1,819 $ 7,707 (72) % Gain (loss) on disposition of assets $ 619$ 89 $ (3,502) 120 % Other income (expense): Interest income $ -$ 58 $ 49 18 % Interest expense, net $ (3,275)$ (22,882) $ (37,061) (29) %
Reorganization costs, net $ (2,273)$ 133,975 $ - - % Write-off debt issuance costs $ -$ (2,426) $ - - % Gain (loss) on derivatives $ (985)
$ (10,704) $ 4,225 NM Other $ 100$ 2,034 $ (236) NM Income tax benefit $ (302)$ (14,630) $ (132,326) 89 % Average interest rate 6.8 % 5.5 % 6.4 % (14) % Average long-term debt outstanding$ 121,740 $ 526,167 $ 744,978 (35) %
_________________________
1.NM – A percentage calculation does not make sense due to a denominator of zero value or a percentage change greater than 200.
57 -------------------------------------------------------------------------------- Table of ContentsOil and Natural Gas Oil and natural gas revenues decreased$164.8 million or 51% in 2020 as compared to 2019 due primarily to lower commodity prices and production. Oil production decreased 32%, NGLs production decreased 28%, and natural gas production decreased 29%. Average oil prices between the comparative years decreased 45% to$31.61 per barrel, NGLs prices decreased 59% to$5.10 per barrel, and natural gas prices decreased 41% to$1.20 per Mcf. Oil and natural gas operating costs increased$7.8 million or 6% between the comparative years of 2020 and 2019 primarily due to higher G&A expenses from the litigation settlements and no longer capitalizing directly related overhead costs in 2020 partially offset by lower LOE and gross production taxes. DD&A decreased$85.0 million or 50% primarily due to a 30% decrease in our DD&A rate and a 29% decrease in equivalent production. The decrease in our DD&A rate resulted primarily from the effect of the ceiling test write-downs during 2020. During the Successor Period of 2020, we recorded non-cash ceiling test write-downs of$26.1 million pre-tax 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. During the Predecessor Period of 2020, we recorded non-cash ceiling test write-downs of$393.7 million , pre-tax ($346.6 million , net of tax) due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties. We also recorded an expense of$17.6 million related to the write-down of our salt water disposal asset that we considered abandoned. During 2019, we recorded non-cash ceiling test write-downs of$559.4 million , pre-tax ($422.4 million , net of tax) due to the reduction of the 12-month average commodity prices and the removal of proved undeveloped reserves due to the uncertainty regarding our ability to finance future capital expenditures. We also recorded in 2019 a$0.5 million impairment on gathering systems with wells no longer producing.
Contract drilling
Drilling revenues have declined
Drilling operating costs decreased$50.3 million or 43% in 2020 compared to 2019. The decrease was due primarily to less drilling rigs operating. Contract drilling depreciation decreased$33.9 million or 66% also due primarily 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 Consolidated Statements of Operations. No impairment was needed on the BOSS drilling rigs asset group as the undiscounted cash flows exceeded the carrying value of the asset group. In 2019, we recognized goodwill impairment charges of$62.8 million , pre-tax ($59.8 million , net of tax) representing all our goodwill which is related to our contract drilling segment.
Mid-stream
Our mid-stream revenues decreased$23.9 million or 13% in 2020 as compared to 2019 primarily due to decreased NGLs, gas, and condensate sales as a result of lower prices and lower volumes resulting from fewer wells connected and declining wellhead volumes. Gas processing volumes per day decreased 8% between the comparative years primarily due to lower purchased volumes from our processing facility in theTexas panhandle. Gas gathering volumes per day decreased 16% primarily due to lower volumes from most of our major gathering and processing systems resulting from fewer wells connected and declining wellhead volumes except from theCashion facility. Operating costs decreased$23.4 million or 18% in 2020 compared to 2019 primarily due to a decrease in purchase prices. Depreciation and amortization decreased$7.6 million or 16% primarily due to lower depreciable net book value from the impairment recognized in the first quarter of 2020. 58 --------------------------------------------------------------------------------
Contents
During the first quarter of 2020, 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 2019, we recorded a$3.0 million impairment due to decreased value of line fill due to lower prices and from the retirement of two older systems.
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 the 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
General and administrative expenses increased$11.2 million or 29% in 2020 compared to 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 disposal of assets
(Gain) loss on disposition of assets decreased$4.2 million in 2020 compared to 2019. The loss in 2020 was primarily related to the sale of vehicles, drilling rigs, and other drilling equipment, while the gain in 2019 was primarily from the retirement of old rig inventory.
Other income (expenses)
Interest expense, net of capitalized interest, decreased$10.9 million between the comparative years of 2020 and 2019. We capitalized interest based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Because we are not currently undergoing any capital projects, we had no capitalized interest for 2020 compared to$16.2 million in 2019 that was netted against our gross interest of$53.2 million for 2019. Our average interest rate increased due to the new Exit Credit Agreement terms and our average debt outstanding was decreased primarily due to the Notes being settled with the Plan.
Elements of reorganization, 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 securities issuance costs
Due to the remaining commitments of the Unit credit agreement being terminated by the 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
Tax benefit
Income tax benefit decreased$117.4 million in 2020 compared to 2019. We recognized an income tax benefit of$14.9 million in 2020 compared to an income tax benefit of$132.6 million in 2019. The 2020 income tax benefit was lower primarily due to the recognition of a full valuation allowance against our net deferred tax assets due to our emergence from bankruptcy in 2020 and fresh start accounting principles. 59
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Table of Contents Our effective tax rate was 1.6% for 2020 compared to 19.3% for 2019. The effective tax rate for the current year was lower as compared to 2019 because of the recognition of a full valuation allowance as described above. The increase in our valuation allowance was due to determining it was more likely than not that the net deferred tax assets would not be fully realizable. We paid no federal or state income taxes during 2020.
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