CHORD ENERGY CORPORATION The following discussion and analysis of our financial condition and results of operations should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in our Annual Report on Form 10-K for the year endedDecember 31, 2020 ("2020 Annual Report"), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategic tactics, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "may," "continue," "predict," "potential," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Our forward-looking statements address the various risks and uncertainties associated with the extraordinary market environment and impacts resulting from the novel coronavirus 2019 ("COVID-19") pandemic and the related impacts to energy demand, our businesses, operations, earnings and results. In particular, the factors discussed below and detailed under "Part II, Item 1A. Risk Factors" in this Quarterly Report on Form 10-Q could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements. Forward-looking statements may include statements about: •crude oil, natural gas and natural gas liquids ("NGL") realized prices; •developments in the global economy as well as the public health crisis related to the COVID-19 pandemic and resulting demand and supply for crude oil and natural gas; •uncertainty regarding the worldwide response to COVID-19, including the impact of new virus strains, the administration of vaccines and the risks associated with restrictions on various commercial and economic activities; such restrictions are designed to protect public health but also have the effect of significantly reducing demand for crude oil and natural gas; •uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil and natural gas; •uncertainty regarding the timing, pace and extent of an economic recovery in theU.S. and elsewhere, which in turn will likely affect demand for crude oil and natural gas; •levels of crude oil and natural gas inventory stored in theU.S. and elsewhere; •general economic conditions; •inflation rates; •our business strategy; •estimated future net reserves and present value thereof; •timing and amount of future production of crude oil and natural gas; •drilling and completion of wells; •estimated inventory of wells remaining to be drilled and completed; •costs of exploiting and developing our properties and conducting other operations; •availability of drilling, completion and production equipment and materials; •availability of qualified personnel; •owning and operating a midstream company, including ownership interests in a master limited partnership; •infrastructure for produced and flowback water gathering and disposal; •gathering, transportation and marketing of crude oil and natural gas in theWilliston Basin and other regions in theU.S. ; •property acquisitions and divestitures; 30 -------------------------------------------------------------------------------- Table of Contents •integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness; •the recently announced merger ofOasis Midstream Partners LP ("OMP") and Crestwood Equity Partners LP ("Crestwood"), including risks that the proposed transaction may not be consummated or the benefits contemplated therefrom may not be realized, the ability to obtain requisite regulatory and unitholder approval and the satisfaction of the other conditions to the consummation of the proposed transaction, the ability of Crestwood to successfully integrate OMP's operations and employees and realize anticipated synergies and cost savings and the potential impact of the announcement or consummation of the proposed transaction on relationships, including with employees, suppliers, customers, competitors and credit rating agencies; •the amount, nature and timing of capital expenditures; •availability and terms of capital; •our financial strategic tactics, budget, projections, execution of business plan and operating results; •cash flows and liquidity; •our ability to return capital to shareholders; •our ability to utilize net operating loss carryforwards or other tax attributes in future periods; •our ability to comply with the covenants under our credit agreements and other indebtedness; •operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control; •interruptions in service and fluctuations in tariff provisions of third-party connecting pipelines; •potential effects arising from cyber threats, terrorist attacks and any consequential or other hostilities; •changes in environmental, safety and other laws and regulations; •execution of our environmental, social and governance ("ESG") initiatives; •effectiveness of risk management activities; •competition in the oil and gas industry; •counterparty credit risk; •environmental liabilities; •governmental regulation and the taxation of the oil and gas industry; •developments in crude oil-producing and natural gas-producing countries; •technology; •the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements; •uncertainty regarding future operating results; •our ability to successfully forecast future operating results and manage activity levels with ongoing macroeconomic uncertainty; •plans, objectives, expectations and intentions contained in this report that are not historical; and •certain factors discussed elsewhere in this Quarterly Report on Form 10-Q, in our 2020 Annual Report and in our other filings with theU.S Securities and Exchange Commission (the "SEC"). 31 -------------------------------------------------------------------------------- Table of Contents All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We disclaim any obligation to update or revise these statements unless required by securities law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in crude oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, the ability to realize the anticipated benefits from theWilliston Basin Acquisition or OMP Merger (each as defined herein), uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, inflation, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. 32 -------------------------------------------------------------------------------- Table of Contents Overview We are an independent exploration and production ("E&P") company focused on the acquisition and development of onshore, unconventional crude oil and natural gas resources inthe United States .Oasis Petroleum North America LLC conducts our E&P activities and owns our oil and gas properties located in theNorth Dakota andMontana regions of theWilliston Basin . During the second quarter of 2021, we sold our E&P assets in theTexas region of thePermian Basin . In addition to our E&P segment, we operate a midstream business through OMP, a leading gathering and processing master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets inNorth America . We ownOMP GP LLC , aDelaware limited liability company and the general partner of OMP ("OMP GP"), and approximately 70% of OMP. We derive significant cash flows from the midstream segment through distributions from our ownership of OMP limited partner units. Recent DevelopmentsWilliston Basin Acquisition OnOctober 21, 2021 , we completed our acquisition of approximately 95,000 net acres in theWilliston Basin , effectiveApril 1, 2021 , fromQEP Energy Company , a wholly-owned subsidiary of Diamondback Energy, Inc. for an adjusted purchase price of$585.8 million (the "Williston Basin Acquisition"). The adjusted purchase price included a deposit of$74.5 million paid onMay 3, 2021 and$511.3 million paid at closing onOctober 21, 2021 . We funded theWilliston Basin Acquisition with cash on hand, which included proceeds from the Permian Basin Sale (defined below) and our issuance of$400.0 million in aggregate principal amount of 6.375% senior unsecured notes due 2026 (the "Oasis Senior Notes"). Permian Basin Sale OnJune 29, 2021 , we completed the sale of our remaining upstream assets in theTexas region of thePermian Basin , effectiveMarch 1, 2021 , toPercussion Petroleum Operating II, LLC ("Percussion") for an aggregate purchase price of$450.0 million (the "Primary Permian Basin Sale"). The purchase price consisted of$375.0 million cash at closing and up to three earn-out payments of$25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX West Texas Intermediate ("NYMEX WTI") crude oil exceeds$60 per barrel for such year (the "Permian Basin Sale Contingent Consideration"). We received cash proceeds of$347.3 million , consisting of a deposit of$31.9 million onMay 20, 2021 and$315.4 million at closing onJune 29, 2021 . The total consideration remains subject to earn-out payments and customary post-closing adjustments. In addition to the Primary Permian Basin Sale, we also divested certain wellbore interests in theTexas region of thePermian Basin to separate buyers in the second quarter of 2021 (the "Additional Permian Basin Sale" and together with the Primary Permian Basin Sale, the "Permian Basin Sale"). We received cash proceeds from the Additional Permian Basin Sale of$24.0 million , and we expect to receive total aggregate cash proceeds of$30.0 million . Change in Chief Executive Officer OnApril 13, 2021 ,Daniel E. Brown was appointed Chief Executive Officer of the Company. At the same time,Mr. Brown was also appointed to the Company's Board of Directors.Mr. Brown replacedDouglas E. Brooks , who was previously appointed to serve as Chief Executive Officer on an interim basis.Mr. Brooks continues to serve in his role as Board Chair. Dakota Access PipelineThe U.S. Army Corps of Engineers (the "Corps") is currently conducting a court-ordered environmental review to determine whether the Dakota Access Pipeline ("DAPL") poses a threat to the drinking water supply of theStanding Rock Sioux Reservation . Once this review is finished, which completion is estimated by the Corps to occur by no later thanMarch 2022 , the Corps will determine whether DAPL is safe to operate or must be permanently shut down. OnApril 9, 2021 , theBiden Administration announced that the Corps will not take immediate action to shut down DAPL while it conducts the environmental review, and onMay 3, 2021 , the Corps filed a Status Report with the federal district court, confirming that it currently is not seeking a shutdown of DAPL while the agency conducts the environmental review. In a related legal proceeding involving theStanding Rock Sioux Tribe's request for an injunction to shut down DAPL while the environmental review is being conducted, U.S. District JudgeJames Boasberg ruled onMay 21, 2021 that DAPL will not be forced to shut down while the Corps conducts the environmental review, indicating that the tribe had failed to make a successful showing of irreparable harm based on the threat of an oil spill. The pipeline currently remains in operation while the Corps conducts its review. 33 -------------------------------------------------------------------------------- Table of Contents Midstream Transactions Midstream Simplification OnMarch 30, 2021 , we closed on the transactions contemplated by a contribution and simplification agreement pursuant to which we contributed our remaining 64.7% interest inBobcat DevCo LLC ("Bobcat DevCo") and remaining 30.0% interest inBeartooth DevCo LLC ("Beartooth DevCo") to OMP as well as eliminated OMP's incentive distribution rights for total consideration of approximately$512.5 million , including cash consideration of$231.5 million and 14.8 million OMP common units (the "Midstream Simplification"). The effective date for the Midstream Simplification wasJanuary 1, 2021 . See "Item 1. - Financial Statements (Unaudited)-Note 2-Summary of Significant Accounting Policies-Basis of Presentation" for more information. OMP Unit Redemption OnJune 29, 2021 , OMP completed an underwritten public offering of 3,623,188 common units representing limited partnership interests at a price to the public of$24.00 per common unit (the "OMP Equity Offering") and received net proceeds of$86.7 million , after deducting underwriting discounts, commissions and offering expenses. OMP used the proceeds from the OMP Equity Offering to redeem an equal number of common units held by Oasis (the "OMP Unit Redemption") for$87.0 million . Following the OMP Unit Redemption, we own approximately 70% of OMP's outstanding common units. OMP Merger OnOctober 25, 2021 , the Company, OMP and OMP GP entered into an Agreement and Plan of Merger (the "Merger Agreement"), with Crestwood,Project Falcon Merger Sub LLC , aDelaware limited liability company and direct wholly-owned subsidiary of Crestwood ("Merger Sub"),Project Phantom Merger Sub LLC , aDelaware limited liability company and direct wholly-owned subsidiary of Crestwood ("GP Merger Sub"), and, solely for the purposes of Section 2.1(a)(i) of the Merger Agreement,Crestwood Equity GP LLC , aDelaware limited liability company and the general partner of Crestwood ("Crestwood GP"). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into OMP (the "LP Merger"), with OMP surviving the LP Merger as a subsidiary of Crestwood, and GP Merger Sub will merge with and into OMP GP (the "GP Merger" and, together with the LP Merger, the "Mergers"), with OMP GP surviving the GP Merger as a wholly-owned subsidiary of Crestwood. Under the terms of the Merger Agreement, Oasis, as a unitholder of OMP, will receive$160.0 million in cash in addition to approximately 21.0 million common units of Crestwood in aggregate in exchange for its ownership of OMP common units and non-economic general partner stake in OMP GP. At the effective time of the Mergers (the "Effective Time"): (i) 6,520,944 common units representing limited partner interests in OMP ("OMP Common Units") issued and outstanding immediately prior to the Effective Time and owned byOMS Holdings LLC , aDelaware limited liability company ("OMS Holdings ") and subsidiary of the Company (such OMP Common Units, the "Sponsor Cash Units"), will be converted into and will thereafter represent the right to receive$150.0 million in cash in the aggregate and each other OMP Common Unit issued and outstanding immediately prior to the Effective Time owned by the Company or its subsidiaries (other than OMP) (together with the Sponsor Cash Units, the "Sponsor Units") will be converted into and will thereafter represent the right to receive 0.7680 common units representing limited partner interests in Crestwood ("Crestwood Common Units"); (ii) each OMP Common Unit issued and outstanding immediately prior to the Effective Time (other than the Sponsor Units) will be converted into and will thereafter represent the right to receive 0.8700 (the "Public Holder Exchange Ratio") Crestwood Common Units and (iii) all of the limited liability company interests of OMP GP issued and outstanding as of immediately prior to the Effective Time will be converted into and will thereafter represent the right to receive$10.0 million in cash. Upon completion of the Mergers, the Company is expected to own approximately 22% of the Crestwood Common Units. The Mergers were unanimously approved by the Board of Directors of both Oasis and Crestwood and have also been unanimously approved by the Board of Directors andConflicts Committee of OMP GP . We expect the Mergers will be completed in the first quarter of 2022, subject to customary closing conditions. Contemporaneously with the execution of the Merger Agreement, the Company, OMP, Crestwood,OMP GP and OMS Holdings entered into a support agreement (the "Support Agreement") regarding the OMP Common Units owned by the Company andOMS Holdings (or their affiliates). Pursuant to the Support Agreement, the Company andOMS Holdings have agreed to, among other things (and as applicable), following effectiveness of a registration statement of Crestwood on Form S-4 in connection with the issuance of Crestwood Common Units in the LP Merger, execute and deliver, or cause an affiliate to execute and deliver, a written consent covering all of their OMP Units, approving the Merger Agreement and the transactions contemplated thereby. The Support Agreement and the Merger Agreement may be terminated in the event the written consent is not delivered. 34 -------------------------------------------------------------------------------- Table of Contents Market Conditions and COVID-19 COVID-19 remains a global health crisis and there continues to be considerable uncertainty regarding the extent to which COVID-19 and its variants will continue to spread. Public health and governmental authorities have commenced programs to administer vaccines and certain restrictions imposed to contain the spread of COVID-19 have been lifted. InSeptember 2021 ,President Biden announced a COVID-19 action plan that would have theOccupational Safety and Health Administration develop an Emergency Temporary Standard which may include new obligations for employers with one hundred or more employees with respect to vaccinations, testing and paid time off. We monitor mandates related to COVID-19 at both the federal and state levels on an ongoing basis and continue to assess the potential impacts of those mandates. Despite improvements in global economic activity levels and higher energy demand compared to 2020, the impacts of COVID-19 continue to be unpredictable, including the impacts of new virus strains, the risk of renewed restrictions and the uncertainty of successful administration of effective treatments and vaccines. We are unable to reasonably estimate the period of time that related conditions could exist or the extent to which they could impact our business, results of operations, financial condition or cash flows. Commodity prices have improved from historic lows in 2020, however, further negative impacts from COVID-19 may require us to adjust our business plan. In response to the impacts of COVID-19 and the economic environment, we reduced our workforce during the first quarter of 2021 to adjust our business to expected lower levels of activity and operate in a sustainable and cost-efficient manner. We are focused on the safety of our employees, contractors, and the communities where we work as we continue to operate during the COVID-19 pandemic. We have deployed additional safety protocols and training procedures, including enhanced daily cleaning in common spaces, use of face coverings, limiting use of conference rooms and group gatherings and adherence to social distancing requirements. Our Crisis Management Team continues to monitor public health data and guidance, engages with peer companies, and participates with industry associations to ensure alignment with guidance for employee health and safety. Commodity Prices Our revenue, profitability and ability to return cash to shareholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil, natural gas and NGLs have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future. In an effort to improve price realizations from the sale of our crude oil, natural gas and NGLs, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, natural gas and NGLs to a broader array of potential purchasers. We enter into crude oil, natural gas and NGL sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. During the third quarter of 2021, our crude oil price differentials averaged$0.43 per barrel discount to NYMEX WTI. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single crude oil or natural gas customer would have a material adverse effect on our results of operations or cash flows. Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As ofSeptember 30, 2021 , 93% of our gross operated crude oil production and substantially all of our gross operated natural gas production were connected to gathering systems. 35 -------------------------------------------------------------------------------- Table of Contents Recent Highlights: •Declared a dividend for third quarter of 2021 of$0.50 per share of common stock. The dividend will be payable onNovember 29, 2021 to shareholders of record as ofNovember 15, 2021 . •Production volumes averaged 51,804 barrels of oil equivalent per day ("Boepd") (62% oil) in the third quarter of 2021. •E&P capital expenditures were$41.9 million in the third quarter of 2021. •E&P lease operating expense ("LOE") was$9.42 per barrel of oil equivalent ("Boe") in the third quarter of 2021. •Crude oil differentials averaged$0.43 to NYMEX WTI in the third quarter of 2021. •Net cash provided by operating activities was$294.4 million for the three months endedSeptember 30, 2021 . Adjusted EBITDA attributable to Oasis, a non-GAAP financial measure, was$116.2 million for the three months endedSeptember 30, 2021 . See "Non-GAAP Financial Measures" below. Results of Operations Comparability Upon our emergence from bankruptcy onNovember 19, 2020 (the "Emergence Date"), we adopted fresh start accounting, which resulted in us becoming a new entity for financial reporting purposes. Accordingly, the condensed consolidated financial statements on or after the Emergence Date are not comparable to the condensed consolidated financial statements prior to the Emergence Date. References to "Successor" relate to our financial position and results of operations as of and subsequent to the Emergence Date. References to "Predecessor" relate to our financial position prior to, and our results of operations through and including, the Emergence Date. Upon adoption of fresh start accounting, our assets and liabilities were recorded at their estimated fair values as of the Emergence Date. As a result, the impact to the comparability of the Predecessor and Successor results is generally limited to those areas associated with the basis in and accounting for our oil and gas and other properties. Revenues Our crude oil and natural gas revenues are derived from the sale of crude oil and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Our purchased oil and gas sales are primarily derived from the sale of crude oil and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending at our crude oil terminal or to cover production shortfalls. Revenues and expenses from crude oil and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis. Our midstream revenues are primarily derived from natural gas gathering, compression, processing and gas lift supply; sales of residue gas and NGLs related to third-party natural gas purchase arrangements; produced and flowback water gathering and disposal; crude oil gathering, terminaling and transportation and fresh water distribution. Our other services revenues are derived from equipment rentals, and also include revenues from well completion services prior to our exit from the well services business in the first quarter of 2020 (the "Well Services Exit"). A significant portion of our midstream revenues and all of our other services revenues are from services performed for our operated wells. Intercompany revenues for work performed for our ownership interests are eliminated in consolidation, and only the revenues related to non-affiliated interest owners and other third-party customers are included in midstream and other services revenues. 36 -------------------------------------------------------------------------------- Table of Contents The following table summarizes our revenues, production data and sales prices for the periods presented: Successor Predecessor Three Months Three Months Nine Months Ended Nine Months Ended September Ended June 30, September 30, Ended September 30, 2021 2021 2021 30, 2020 Revenues (in thousands) Crude oil revenues$ 205,731 $ 206,729 $ 598,278 $ 448,904 Natural gas revenues 75,905 48,498 184,046 63,631 Purchased oil and gas sales 53,570 81,855 183,885 167,824 Midstream revenues 66,712 55,783 183,807 138,164 Other services revenues 121 195 542 6,686 Total revenues$ 402,039 $ 393,060 $ 1,150,558 $ 825,209 Production data Crude oil (MBbls) 2,934 3,155 9,402 12,263 Natural gas (MMcf) 10,989 10,703 32,707 35,881 Oil equivalents (MBoe) 4,766 4,939 14,853 18,243 Average daily production (Boepd) 51,804 54,271 54,407 66,581 Average sales prices Crude oil (per Bbl) Average sales price$ 70.12 $ 65.52 $ 63.63 $ 36.61 Effect of derivative settlements(1) (26.31) (17.75) (16.62)
13.17
Average realized price after the effect of$ 43.81 $ 47.77 $ 47.01 $ 49.78 derivative settlements(1) Natural gas (per Mcf)(2) Average sales price$ 6.91 $ 4.53 $ 5.63$ 1.77 Effect of derivative settlements(1) (0.39) - (0.12)
-
Average realized price after the effect of$ 6.52 $ 4.53 $ 5.51$ 1.77 derivative settlements(1) ____________________ (1)The effect of derivative settlements includes the cash received or paid for the gains or losses on commodity derivatives settled in the periods presented. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes. (2)Natural gas prices include the value for natural gas and NGLs. 37 -------------------------------------------------------------------------------- Table of Contents Three months endedSeptember 30, 2021 as compared to three months endedJune 30, 2021 Crude oil and natural gas revenues. Our crude oil and natural gas revenues increased$26.4 million to$281.6 million during the three months endedSeptember 30, 2021 . This increase was primarily driven by a$14.5 million increase due to higher crude oil realized prices and a$25.4 million increase due to higher natural gas realized prices, offset by a$13.5 million decrease driven by lower crude oil and natural gas production volumes sold quarter over quarter. Average crude oil sales prices, without derivative settlements, increased by$4.60 per barrel quarter over quarter to an average of$70.12 per barrel for the three months endedSeptember 30, 2021 . Average natural gas sales prices, which include the value for residue gas and NGLs and do not include derivative settlements, increased by$2.38 per Mcf quarter over quarter to an average of$6.91 per Mcf for the three months endedSeptember 30, 2021 . Average daily production volumes sold decreased by 2,467 Boepd to 51,804 Boepd quarter over quarter primarily driven by a decrease in crude oil production as a result of the Permian Basin Sale in the second quarter of 2021. Purchased oil and gas sales. Purchased oil and gas sales, which consist primarily of the sale of crude oil purchased to optimize transportation costs, for blending at our crude oil terminal or to cover production shortfalls, decreased$28.3 million to$53.6 million for the three months endedSeptember 30, 2021 . This decrease was primarily due to a reduction in crude oil volumes purchased and then subsequently sold in theWilliston Basin . Midstream revenues. Midstream revenues increased$10.9 million to$66.7 million during the three months endedSeptember 30, 2021 . This increase was primarily driven by a$7.0 million increase in natural gas revenues due to an increase in sales from natural gas purchase arrangements, coupled with a$2.9 million increase in produced and flowback water revenues and a$1.4 million increase in crude oil revenues. Nine months endedSeptember 30, 2021 as compared to nine months endedSeptember 30, 2020 Crude oil and natural gas revenues. Our crude oil and natural gas revenues increased$269.8 million to$782.3 million during the nine months endedSeptember 30, 2021 . This increase was primarily driven by a$469.7 million increase due to higher crude oil and natural gas realized prices, offset by a$199.9 million decrease due to the lower crude oil and natural gas production volumes sold period over period. Average crude oil sales prices, without derivative settlements, increased by$27.02 per barrel to an average of$63.63 per barrel, and average natural gas sales prices, which include the value for residue gas and NGLs and do not include derivative settlements, increased by$3.86 per Mcf to an average of$5.63 per Mcf for the nine months endedSeptember 30, 2021 . Average daily production sold decreased by 12,174 Boepd to 54,407 Boepd period over period. The decrease in average daily production volumes sold period over period was due to a reduction in new wells coming online as a result of fewer well completions, coupled with the Permian Basin Sale in the second quarter of 2021. Purchased oil and gas sales. Purchased oil and gas sales increased$16.1 million to$183.9 million for the nine months endedSeptember 30, 2021 . This increase was primarily due to higher crude oil sales prices period over period, partially offset by lower crude oil volumes purchased and then subsequently sold in theWilliston Basin andPermian Basin . Midstream revenues. Midstream revenues were$183.8 million for the nine months endedSeptember 30, 2021 , which was a$45.7 million increase period over period. This increase was driven by a$50.2 million increase in natural gas revenues due to an increase in sales from natural gas purchase arrangements due to higher residue gas and NGL prices. This was offset by a$2.6 million decrease in produced and flowback water revenues and a$1.2 million decrease in freshwater revenues. Other services revenues. Other services revenues decreased by$6.2 million to$0.5 million for the nine months endedSeptember 30, 2021 as compared to the nine months endedSeptember 30, 2020 , primarily driven by a decrease in well completion revenues due to the Well Services Exit. 38 -------------------------------------------------------------------------------- Table of Contents Expenses and other income (expenses) The following table summarizes our operating expenses and other income (expenses) for the periods presented (in thousands, except per Boe of production): Successor Predecessor Three Months Three Months Nine Months Nine Months Ended Ended September Ended June 30, Ended September September 30, 30, 2021 2021 30, 2021 2020 Operating expenses Lease operating expenses$ 29,307 $ 34,321 $ 98,888 $ 108,730 Midstream expenses 32,396 23,547 83,841 32,355 Other services expenses 26 21 47
5,968
Gathering, processing and transportation expenses 16,400
20,485 52,596 73,557
Purchased oil and gas expenses 53,880 85,455 187,745 165,932 Production taxes 18,445 16,208 50,933 39,129 Depreciation, depletion and amortization 33,623 38,968 112,581 272,885 Exploration expenses 263 1,250 1,936 3,061 Rig termination - - - 1,279 Impairment - 2 5 4,828,575 General and administrative expenses 19,514 20,210 60,461 117,868 Litigation settlement - - - 22,750 Total operating expenses 203,854 240,467 649,033 5,672,089 Gain on sale of properties 5,405 222,980 228,473 11,652 Operating income (loss) 203,590 375,573 729,998 (4,835,228) Other income (expense) Net gain (loss) on derivative instruments (101,790) (267,037) (550,342)
243,064
Interest expense, net of capitalized interest (18,153) (22,571) (49,421)
(177,534)
Gain on extinguishment of debt - - - 83,867 Reorganization items, net - - - (49,758) Other income (expense) (315) (1,002) (859) 2,373 Total other income (expense), net (120,258) (290,610) (600,622)
102,012
Income (loss) before income taxes 83,332 84,963 129,376 (4,733,216) Income tax benefit - (3,654) - 262,495 Net income (loss) including non-controlling 83,332 81,309 129,376
(4,470,721)
interests
Less: Net income (loss) attributable to 11,382 7,945 27,654
(11,218)
non-controlling interests Net income (loss) attributable to Oasis$ 71,950 $ 73,364 $ 101,722 $
(4,459,503)
Costs and expenses (per Boe of production) Lease operating expenses$ 6.15 $ 6.95 $ 6.66 $
5.96
Gathering, processing and transportation expenses 3.44 4.15 3.54 4.03
Production taxes 3.87 3.28 3.43 2.14
39-------------------------------------------------------------------------------- Table of Contents Three months endedSeptember 30, 2021 as compared to three months endedJune 30, 2021 Lease operating expenses. LOE decreased$5.0 million to$29.3 million for the three months endedSeptember 30, 2021 . This decrease was primarily due to a reduction of$6.4 million in thePermian Basin following the Permian Basin Sale in the second quarter of 2021, partially offset by a$1.3 million increase in LOE in theWilliston Basin due to an increase in produced and flowback water volumes and gas lift volumes. LOE per Boe decreased from$6.95 per Boe to$6.15 per Boe primarily due to higher production volumes in theWilliston Basin . E&P LOE, which excludes impacts from our midstream business segment, decreased$0.79 to$9.42 per BOE in the third quarter of 2021. Midstream expenses. Midstream expenses increased$8.9 million during the three months endedSeptember 30, 2021 , primarily due to a$7.3 million increase in natural gas purchases from third party producers and a$1.3 million increase in produced and flowback water expenses. Gathering, processing and transportation expenses. Gathering, processing and transportation ("GPT") expenses decreased$4.1 million during the three months endedSeptember 30, 2021 , primarily due to a decrease of$2.6 million in thePermian Basin following the Permian Basin Sale in the second quarter of 2021, coupled with a$2.3 million decrease due to lower natural gas gathering and transportation expenses in theWilliston Basin , partially offset by a$1.1 million increase in crude oil transportation expenses due primarily to an increase in volumes transported on DAPL. GPT per Boe decreased$0.71 to$3.44 for the three months endedSeptember 30, 2021 due to the lower aforementioned costs, coupled with higher production volumes in theWilliston Basin . E&P GPT per Boe, which excludes certain impacts from our midstream business segment, decreased to$3.95 for the three months endedSeptember 30, 2021 . Cash GPT per Boe, which excludes non-cash valuation adjustments, decreased to$3.56 for the three months endedSeptember 30, 2021 . E&P GPT and Cash GPT are non-GAAP financial measures. See "Non-GAAP Financial Measures" below. Purchased oil and gas expenses. Purchased oil and gas expenses, which represent crude oil purchased to optimize transportation costs, for blending at our crude oil terminal or to cover production shortfalls, decreased$31.6 million to$53.9 million for the three months endedSeptember 30, 2021 . This decrease was primarily due to a decrease in crude oil volumes purchased and then subsequently sold in theWilliston Basin , coupled with a reduction in purchased oil and gas expenses in thePermian Basin as a result of the Permian Basin Sale in the second quarter of 2021. Depreciation, depletion and amortization. Depreciation, depletion and amortization ("DD&A") expenses decreased$5.3 million to$33.6 million for the three months endedSeptember 30, 2021 due to a decrease in the DD&A rate to$4.02 per Boe during the three months endedSeptember 30, 2021 , compared to$4.67 per Boe during the three months endedJune 30, 2021 . General and administrative ("G&A") expenses. G&A expenses decreased$0.7 million to$19.5 million for the three months endedSeptember 30, 2021 as compared to the three months endedJune 30, 2021 primarily due to lower employee compensation related expenses. In addition, the Company incurred$2.3 million of non-recurring charges during the three months endedSeptember 30, 2021 related to theWilliston Basin Acquisition, OMP merger and restructuring consulting expenses. Gain on sale of properties. For the three months endedSeptember 30, 2021 , we recognized a$5.4 million net gain on the sale of properties related to customary post-close adjustments in connection with the Permian Basin Sale. For the three months endedJune 30, 2021 , we recognized a$223.0 million net gain on the sale of properties primarily related to the Permian Basin Sale, which closed onJune 29, 2021 . Derivative instruments. We recorded a$101.8 million net loss on derivative instruments during the three months endedSeptember 30, 2021 . The net loss was primarily due to a realized loss of$81.4 million and an unrealized loss of$27.2 million on our commodity derivatives. This was partially offset by an unrealized gain of$6.9 million related to the Permian Basin Sale Contingent Consideration. During the three months endedJune 30, 2021 , we recorded a$267.0 million net loss on derivative instruments, which included a realized loss on our commodity derivatives of$56.0 million . Interest expense, net of capitalized interest. Interest expense decreased$4.4 million to$18.2 million for the three months endedSeptember 30, 2021 . The decrease was primarily due to fees related to the Oasis Bridge Facility of$7.8 million which were incurred during the three months endedJune 30, 2021 , partially offset by interest expense under the Oasis Senior Notes which were issued onJune 9, 2021 . Income tax benefit (expense). We did not record a provision for income tax during the three months endedSeptember 30, 2021 . Our income tax expense for the three months endedJune 30, 2021 was recorded at 4.3% of pre-tax income. Our effective tax rate for the three months endedSeptember 30, 2021 of 0.0% was lower than the effective tax rate for the three months endedJune 30, 2021 primarily due to the impact of the change in the valuation allowance. 40 -------------------------------------------------------------------------------- Table of Contents Nine months endedSeptember 30, 2021 as compared to nine months endedSeptember 30, 2020 Lease operating expenses. LOE decreased$9.8 million to$98.9 million for the nine months endedSeptember 30, 2021 as compared to the nine months endedSeptember 30, 2020 . This decrease was primarily due to lower fixed costs, coupled with lower costs due to a decrease in produced and flowback water volumes transported and injected period over period. These decreases were partially offset by higher workover costs period over period. LOE per Boe increased$0.70 per Boe to$6.66 per Boe for the nine months endedSeptember 30, 2021 primarily due to lower production volumes. E&P LOE, which excludes impacts from our midstream business segment, increased$1.92 to$9.86 per Boe for the nine months endedSeptember 30, 2021 . Midstream expenses. Midstream expenses increased$51.5 million during the nine months endedSeptember 30, 2021 , primarily due to a$52.7 million increase in natural gas purchases from third party producers, driven by higher residue gas and NGL prices, offset by a$0.8 million decrease in freshwater expenses due to lower completion activity. Other services expenses. Other services expenses represent third party working interest owners' share of expenses incurred related to equipment rental services provided to our operated wells, and prior to the Well Services Exit, also included the non-affiliated share of well completion service costs and costs of goods sold. The$5.9 million decrease for the nine months endedSeptember 30, 2021 was primarily attributable to a decrease in well completion expenses due to the Well Services Exit. Gathering, processing and transportation expenses. GPT expenses decreased$21.0 million period over period, primarily due to a$14.6 million decrease in natural gas gathering and transportation expenses, a$3.3 million decrease in crude oil gathering and transportation expenses, and a$3.0 million decrease in pipeline imbalances. GPT per Boe decreased$0.49 to$3.54 for the nine months endedSeptember 30, 2021 due to the lower aforementioned expenses, offset by lower production volumes. E&P GPT per Boe was$4.02 for the nine months endedSeptember 30, 2021 as compared to$4.27 for the nine months endedSeptember 30, 2020 . Cash GPT per Boe decreased to$3.65 for the nine months endedSeptember 30, 2021 as compared to$3.96 for the nine months endedSeptember 30, 2020 . E&P GPT and Cash GPT are non-GAAP financial measures. See "Non-GAAP Financial Measures" below. Purchased oil and gas expenses. Purchased oil and gas expenses increased$21.8 million to$187.7 million for the nine months endedSeptember 30, 2021 as compared to the nine months endedSeptember 30, 2020 primarily due to higher crude oil prices period over period, partially offset by lower crude oil volumes purchased in theWilliston Basin andPermian Basin . Production taxes. Our production taxes as a percentage of crude oil and natural gas sales were 6.5% and 7.6% for the nine months endedSeptember 30, 2021 and 2020, respectively. Production taxes as a percentage of crude oil and natural gas sales decreased period over period primarily due to a lower crude oil production mix in theWilliston Basin . Depreciation, depletion and amortization. DD&A expenses decreased$160.3 million to$112.6 million for the nine months endedSeptember 30, 2021 as compared to the nine months endedSeptember 30, 2020 . This decrease was a result of a decrease in the DD&A rate to$7.58 per Boe for the nine months endedSeptember 30, 2021 as compared to$14.96 per Boe for the nine months endedSeptember 30, 2020 , coupled with decreased production during the nine months endedSeptember 30, 2021 . The decrease in the DD&A rate was primarily due to a lower basis in our proved oil and gas properties as a result of write-downs during 2020. Exploration expenses. Exploration expenses decreased$1.1 million to$1.9 million for the nine months endedSeptember 30, 2021 as compared to$3.1 million for the nine months endedSeptember 30, 2020 . This decrease was primarily due to lower cost write-offs related to exploratory well locations. Impairment. Impairment expense decreased$4.8 billion for the nine months endedSeptember 30, 2021 as compared to the nine months endedSeptember 30, 2020 . There were no material asset impairment charges taken during the nine months endedSeptember 30, 2021 . Impairment expense of$4.8 billion for the nine months endedSeptember 30, 2020 was primarily due to the following: •Proved oil and gas properties. We recorded an impairment charge of$4.4 billion on our proved oil and gas properties, including$3.8 billion in theWilliston Basin and$637.3 million in thePermian Basin , for the nine months endedSeptember 30, 2020 primarily due to a significant decline in commodity prices. •Unproved oil and gas properties. We recorded impairment losses on our unproved oil and gas properties of$293.0 million as a result of leases expiring or expected to expire as well as drilling plan uncertainty on certain acreage of unproved properties. •Other property and equipment. We recorded impairment charges of$108.8 million to reduce the carrying values of our midstream assets to their estimated fair values as a result of lower forecasted throughput volumes. 41 -------------------------------------------------------------------------------- Table of Contents •Assets held for sale. We recorded an impairment loss of$14.5 million to write-off the net book value of certain well services equipment held for sale as ofDecember 31, 2019 for which a sale was no longer probable to be completed within one year. In addition, we recorded an impairment loss of$1.4 million to adjust the carrying value of the remaining equipment held for sale related to the Well Services Exit to its estimated fair value less costs to sell. •Inventory. We recorded impairment losses of$7.2 million ,$1.3 million and$1.0 million to adjust the carrying values of our crude oil inventory, long-term linefill inventory and equipment and materials inventory, respectively, to their net realizable values. General and administrative expenses. G&A expenses decreased$57.4 million to$60.5 million for the nine months endedSeptember 30, 2021 as compared to the nine months endedSeptember 30, 2020 . This decrease was primarily due to lower employee compensation expenses due to a 26% decrease in employee headcount period over period, coupled with restructuring related expenses incurred during the nine months endedSeptember 30, 2020 . Gain on sale of properties. For the nine months endedSeptember 30, 2021 , we recognized a$228.5 million gain on sale of properties primarily related to the Permian Basin Sale (see Item 1. "Financial Statements (Unaudited) - Note 10 - Divestitures"). For the nine months endedSeptember 30, 2020 , we recognized a$11.7 million gain on sale of properties primarily related to the sale of certain oil and gas properties in theWilliston Basin . Derivative instruments. We recorded a$550.3 million net loss on derivative instruments during the nine months endedSeptember 30, 2021 . The net loss was primarily due to an unrealized loss of$397.2 million and a realized loss of$160.0 million on our commodity derivatives. This was partially offset by an unrealized gain of$6.9 million related to the Permian Basin Sale Contingent Consideration. During the nine months endedSeptember 30, 2020 , we recorded a$243.1 million net gain on derivative instruments, including net cash settlement receipts of$224.2 million from our commodity derivatives. Interest expense, net of capitalized interest. Interest expense decreased$128.1 million to$49.4 million for the nine months endedSeptember 30, 2021 as compared to the nine months endedSeptember 30, 2020 . During the nine months endedSeptember 30, 2020 , we recorded specified default interest charges of$30.3 million and$28.0 million related to the Amended and Restated Credit Agreement, datedOctober 16, 2018 , as amended prior to the Emergence Date and OMP Credit Facility (as defined below), respectively. These specified default interest charges were subsequently waived upon our emergence from bankruptcy inNovember 2020 . In addition, interest expense decreased$77.7 million period over period as a result of the cancellation of the Predecessor senior unsecured notes upon emergence from bankruptcy in 2020, partially offset by interest expense incurred under the Oasis Senior Notes which were issued in the second quarter of 2021. These decreases were offset by an$18.1 million increase in interest expense related to the OMP Senior Notes (as defined below) which were issued in the first quarter of 2021. For the nine months endedSeptember 30, 2021 , the weighted average debts outstanding under the Oasis Credit Facility (as defined below) and the OMP Credit Facility were$87.6 million and$290.0 million , respectively, and the weighted average interest rates incurred on the outstanding borrowings were 4.2% and 2.4%, respectively. For the nine months endedSeptember 30, 2020 , the weighted average debts outstanding under the Predecessor Credit Facility and the OMP Credit Facility were$450.5 million and$482.7 million , respectively, and the weighted average interest rates incurred on the outstanding borrowings, excluding additional interest charges, were 3.3% and 2.6%, respectively. Interest capitalized during the nine months endedSeptember 30, 2021 and 2020 was$1.5 million and$5.6 million , respectively. Gain on extinguishment of debt. There was no extinguishment of debt during the nine months endedSeptember 30, 2021 . During the nine months endedSeptember 30, 2020 , we repurchased an aggregate principal amount of$156.8 million of Predecessor senior unsecured notes for an aggregate cost of$68.0 million and recognized a pre-tax gain of$83.9 million . Income tax benefit. We did not record a provision for income tax during the nine months endedSeptember 30, 2021 . Our income tax benefit was recorded at 5.5% of pre-tax loss for the nine months endedSeptember 30, 2020 . Our effective tax rate for the nine months endedSeptember 30, 2021 of 0.0% was lower than the effective tax rate for the nine months endedSeptember 30, 2020 primarily due to the impacts of the change in the valuation allowance and the impacts of non-controlling interests. Liquidity and Capital Resources Our primary sources of liquidity during the period covered by this report have been from cash flows from operations, proceeds from the Permian Basin Sale, the issuance of the Oasis Senior Notes and OMP Senior Notes and proceeds from the OMP Equity Offering. Our primary uses of cash have been for net principal payments under our revolving credit facilities, derivative settlements and modifications, the acquisition and development of oil and gas properties and midstream infrastructure, deferred financing costs, interest payments on our long-term debt, dividends paid to our shareholders, share repurchases and distributions to non-controlling interests. We are committed to a disciplined capital strategy of investing within our cash flows from operations and cash settlements of 42 -------------------------------------------------------------------------------- Table of Contents derivative contracts. Our capital allocation committee provides for a rigorous, systematic framework for evaluating and approving capital projects, and we believe our asset base and strong balance sheet will allow us to generate significant free cash flow and corporate-level returns. Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, and obligations associated with our operating and finance leases. In addition, we have contracts which include provisions for the delivery, transport, or purchase of a minimum volume of crude oil, natural gas, NGLs and water within specified time frames, all of which are ten years or less, except for one agreement with a remaining term of approximately 24 years. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. However, we believe that our production and reserves are sufficient to fulfill the volume commitments, and therefore, we expect to avoid any material deficiency payments under these contracts. In connection with the Permian Basin Sale, certain of our agreements that contained volume commitments were assigned to Percussion. See "Item 1. - Financial Statements (Unaudited)-Note 18-Commitments and Contingencies" for more information. As ofSeptember 30, 2021 , we had$1,481.8 million of liquidity available, including$448.6 million in cash and cash equivalents and$633.2 million of aggregate unused borrowing capacity available under the Oasis Credit Facility and the OMP Credit Facility. AtSeptember 30, 2021 , we had$400.0 million of restricted cash that was held in a standalone account and was used to fund a portion of theWilliston Basin Acquisition that closed onOctober 21, 2021 . Oasis Credit Facility. We have a reserves-based credit agreement (the "Oasis Credit Facility"), which has an overall senior secured line of credit of$1,500.0 million , an aggregate amount of elected commitments of$450.0 million and a borrowing base of$400.0 million atSeptember 30, 2021 . OnOctober 21, 2021 , we entered into the Fifth Amendment to the Oasis Credit Facility (the "Fifth Amendment"). In connection with the Fifth Amendment, the semi-annual redetermination of the borrowing base was completed, which increased the borrowing base to$900.0 million and reaffirmed the aggregate amount of elected commitments of$450.0 million . The Oasis Credit Facility has a maturity date ofMay 19, 2024 . See "Item 1. - Financial Statements (Unaudited)-Note 11-Long-Term Debt" for more information. As ofSeptember 30, 2021 , we had no borrowings outstanding and$1.3 million of outstanding letters of credit under the Oasis Credit Facility, resulting in an unused borrowing capacity of$398.7 million . During the three months endedSeptember 30, 2021 , there were no borrowings outstanding under the Oasis Credit Facility. For the nine months endedSeptember 30, 2021 , the weighted average interest rate incurred on borrowings under the Oasis Credit Facility was 4.2%. The Company was in compliance with the financial covenants of the Oasis Credit Facility atSeptember 30, 2021 . Oasis Senior Notes. OnJune 9, 2021 , we issued in a private placement$400.0 million of 6.375% senior unsecured notes dueJune 1, 2026 . The Oasis Senior Notes were issued at par and resulted in net proceeds of$393.0 million . We used the proceeds from the Oasis Senior Notes offering to fund a portion of theWilliston Basin Acquisition. Interest on the Oasis Senior Notes is payable semi-annually onJune 1 andDecember 1 of each year, commencing onDecember 1, 2021 . See "Item 1. - Financial Statements (Unaudited)-Note 11-Long-Term Debt" for more information. OMP Credit Facility. We consolidate OMP and include OMP's revolving credit facility (the "OMP Credit Facility") in our condensed consolidated financial statements. OMP uses this credit facility to fund working capital and to finance acquisitions and other capital expenditures. The OMP Credit Facility does not mature until at leastSeptember 30, 2024 . OnMarch 22, 2021 , OMP entered into the Fourth Amendment to the OMP Credit Facility. See "Item 1. - Financial Statements (Unaudited)-Note 11-Long-Term Debt" for more information. As ofSeptember 30, 2021 , the OMP Credit Facility had an aggregate amount of commitments of$450.0 million with$210.0 million of outstanding borrowings and$5.5 million of outstanding letters of credit, resulting in an unused borrowing capacity of$234.5 million . For the three and nine months endedSeptember 30, 2021 , the weighted average interest rate incurred on borrowings under the OMP Credit Facility was 2.5% and 2.4%, respectively. OMP was in compliance with the financial covenants of the OMP Credit Facility atSeptember 30, 2021 . OMP Senior Notes. OnMarch 30, 2021 , OMP issued in a private placement$450.0 million of 8.00% senior unsecured notes dueApril 1, 2029 (the "OMP Senior Notes"). The OMP Senior Notes were issued at par and resulted in net proceeds of$442.1 million , which OMP used to (i) make a distribution of$231.5 million to Oasis in connection with the Midstream Simplification, (ii) repay approximately$204.0 million of outstanding principal borrowings under the OMP Credit Facility and$0.5 million of accrued interest under the OMP Credit Facility and (iii) pay approximately$6.1 million in fees and other expenses. Interest on the OMP Senior Notes is payable semi-annually onApril 1 andOctober 1 of each year, commencing onOctober 1, 2021 . See "Item 1. - Financial Statements (Unaudited)-Note 11-Long-Term Debt" for more information. 43 -------------------------------------------------------------------------------- Table of Contents OMP Equity Offering. OnJune 29, 2021 , OMP completed an underwritten public offering of 3,623,188 common units representing limited partnership interests at a price to the public of$24.00 per common unit and received net proceeds of$86.7 million , after deducting underwriting discounts and commissions. OMP used the proceeds from the OMP Equity Offering to redeem 3,623,188 common units held by Oasis for$87.0 million . Following the OMP Unit Redemption, the Company owns approximately 70% of OMP's outstanding common units. Cash flows Our cash flows for the nine months endedSeptember 30, 2021 and 2020 are presented below (in thousands): Successor Predecessor Nine months ended September 30, Nine Months Ended 2021 September 30, 2020 Net cash provided by operating activities$ 644,746 $ 154,905 Net cash used in investing activities (89,031) (52,365) Net cash provided by (used in) financing activities 272,667 (38,294)
Increase in cash, cash equivalents and restricted cash
$ 64,246
Cash flows provided by operating activities
Net cash provided by operating activities was $644.7 million for the nine months
ended September 30, 2021 . The increase in net cash provided by operating
activities from the nine months ended September 30, 2020 was due primarily to
higher crude oil and natural gas revenues, coupled with lower interest expense
related to the cancellation of the Predecessor senior unsecured notes. In
addition, G&A, GPT and LOE expenses decreased period over period. Refer to
"Results of Operations" above for more information on the impact of volumes and
prices on revenues and for more information on increases and decreases in
certain expenses between periods.
Working capital. Our working capital fluctuates primarily as a result of changes
in commodity pricing and production volumes, capital spending to fund
development of our oil and gas properties and the impact of our outstanding
derivative instruments. We had a working capital surplus of $88.2 million and a
working capital deficit of $69.6 million at September 30, 2021 and December 31,
2020 , respectively. We believe we have adequate liquidity to meet our working
capital requirements. Our working capital increased due to higher cash and cash
equivalents and accounts receivable, partially offset by increases in the net
liability related to our short-term derivative instruments, accrued liabilities
and revenues and production taxes payable.
Cash flows used in investing activities
Net cash used in investing activities was $89.0 million for the nine months
ended September 30, 2021 . The increase in net cash used in investing activities
from the nine months ended September 30, 2020 was primarily due to payments made
related to the settlement of outstanding commodity derivatives, coupled with a
deposit made in connection with the Williston Basin Acquisition, offset by
proceeds from the Permian Basin Sale and a decrease in cash capital
expenditures, primarily for drilling and development costs.
Cash flows provided by (used in) financing activities
Net cash provided by financing activities was $272.7 million for the nine months
ended September 30, 2021 , which increased from net cash used in financing
activities for the nine months ended September 30, 2020 . The increase in cash
flows from financing activities was primarily due to the issuance of the Oasis
Senior Notes and OMP Senior Notes, partially offset by the net principal
repayments of outstanding borrowings under the Oasis Credit Facility and OMP
Credit Facility.
44
--------------------------------------------------------------------------------
Table of Contents
Capital expenditures
Our capital expenditures are summarized in the following table:
Nine Months
Three Months Ended Ended
September 30, September 30,
March 31, 2021 June 30, 2021 2021 2021
(In thousands)
Capital expenditures:
E&P $ 28,595 $ 52,355 $ 41,945 $ 122,895
Other capital expenditures(1) 414 660 606 1,680
Total E&P and other capital expenditures 29,009 53,015 42,551 124,575
Midstream 259 13,392 16,135 29,786
Total capital expenditures(2) $ 29,268 $ 66,407 $ 58,686 $ 154,361 ___________________
(1)Other capital expenditures include such items as administrative capital and capitalized interest. Capitalized interest totaled$0.6 million and$1.5 million for the three and nine months endedSeptember 30, 2021 . (2)Total capital expenditures reflected in the table above differs from the amounts shown in the statements of cash flows in our unaudited condensed consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis. Dividends We have paid quarterly cash dividends totaling$22.5 million during 2021. In addition, we paid a special dividend of$4.00 per share of common stock onJuly 21, 2021 totaling$80.0 million . OnOctober 26, 2021 , we declared a dividend of$0.50 per share of common stock payable onNovember 29, 2021 to shareholders of record as ofNovember 15, 2021 . Future dividend payments will depend on the Company's earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant. Share Repurchase Program InMarch 2021 , the Board of Directors authorized a share-repurchase program covering up to$100.0 million of the Company's common stock which expires onDecember 31, 2022 . During the nine months endedSeptember 30, 2021 , the Company repurchased 190,783 shares of common stock at a weighted average price of$76.30 per common share for a total cost of$14.6 million . There were no share repurchases made subsequent toSeptember 30, 2021 , except fromOctober 28, 2021 throughNovember 2, 2021 , the Company repurchased 156,519 shares of common stock at a weighted average price of$121.22 per common share for a total cost of$19.0 million . Tax Benefits Preservation Plan The Company has determined that it qualifies for an exception to the limitation on its net operating loss carryforwards ("NOLs") and other tax attributes (collectively, the "Tax Benefits") under Section 382(l)(5) of the Internal Revenue Code (the "Code"), as of its emergence from Chapter 11 restructuring. This qualification resulted in reducing cash taxes to zero for the nine months endedSeptember 30, 2021 , and we do not expect to owe cash taxes for the fiscal year endingDecember 31, 2021 . Under Section 382(l)(5) of the Code, if the Company were to experience an "ownership change" as defined by Section 382 of the Code within the two-year period immediately following the Emergence Date, the Company would be precluded from utilizing the Tax Benefits following such ownership change. If Oasis is unable to use its Tax Benefits in years in which the Company has taxable income, the Company will pay significantly more in cash tax than if it were able to utilize the Tax Benefits, and those tax costs would negatively impact the Company's financial position, results of operations and cash flows. As a result, the Board of Directors has adopted a Tax Benefits Preservation Plan (the "Tax Plan") designed to protect the availability of the Company's Tax Benefits, which may be utilized in certain circumstances to reduce the Company's future income tax obligations. The Tax Plan reduces the likelihood that any changes in the Company's investor base, including an ownership change, would limit the Company's future use of its Tax Benefits. 45 -------------------------------------------------------------------------------- Table of Contents In adopting the Tax Plan, the Board of Directors declared a dividend of one preferred share purchase right (a "Right") for each outstanding share of the Company's common stock. The Rights will trade with the Company's common stock and will expire at the close of business on the earlier ofAugust 3, 2024 (three years from adoption) and the date upon which the Board of Directors determines that no Tax Benefits remain available or earlier as described in more detail in the Tax Plan. The Rights will be exercisable if, among other things, a person or group of persons acquires 4.95% or more of the Company's outstanding common stock. The Tax Plan adopted by the Board of Directors is similar to plans adopted by other publicly-held companies with significant NOLs or other substantial tax benefits and is not designed to prevent any action that the Board of Directors determines to be in the best interest of the Company and its shareholders. The Company expects to submit the Tax Plan for ratification by the Company's shareholders at the Company's 2022 Annual Meeting. For more information regarding the Company's Tax Benefits, please refer to the 2020 Annual Report. Non-GAAP Financial Measures The following measures described below are supplemental non-GAAP financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP financial measures should not be considered in isolation or as a substitute for gas revenues, GPT expenses, G&A expenses, interest expense, net income (loss), operating income (loss) and net cash provided by (used in) operating activities or any other measures prepared under GAAP. Because these non-GAAP financial measures exclude some but not all items that affect net income (loss) and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies. E&P Adjusted Gas Revenue We define E&P Adjusted Gas Revenue as total natural gas revenues less benefits from our midstream business segment related to natural gas gathering and processing services recorded to consolidated GPT expenses.E&P Adjusted Gas Revenue is not a measure of natural gas revenues as determined by GAAP. Management believes that the presentation of E&P Adjusted Gas Revenue provides useful additional information to investors and analysts to evaluate the natural gas revenues derived from our E&P business. This non-GAAP measure is intended to provide investors and analysts an indication of the natural gas revenues we would receive if our natural gas volumes were serviced by a third-party midstream operator. The following table presents a reconciliation of the GAAP financial measure of natural gas revenues to the non-GAAP financial measure ofE&P Adjusted Gas Revenue for the periods presented (in thousands): Successor Predecessor Successor Predecessor Three Months Ended Nine Months September Three Months Ended Ended September Nine Months Ended 30, 2021 September 30, 2020 30, 2021 September 30, 2020 Natural gas revenues$ 75,905 $ 24,525$ 184,046 $ 63,631 Intercompany impacts from midstream segment (11,773) (9,710) (32,869) (26,579) E&P Adjusted Gas Revenue$ 64,132 $ 14,815$ 151,177 $ 37,052 Cash GPT and E&P GPT We define Cash GPT as total GPT expenses less non-cash valuation charges on pipeline imbalances. We define E&P GPT as Cash GPT less the benefits from our midstream business segment related to crude oil gathering and transportation services. Cash GPT and E&P GPT are not measures of GPT expenses as determined by GAAP. Management believes that the presentation of Cash GPT and E&P GPT provide useful additional information to investors and analysts to assess the cash costs incurred to market and transport our commodities from the wellhead to delivery points for sale without regard for certain benefits of our midstream business segment, as well as the change in value of our pipeline imbalances, which vary monthly based on commodity prices. 46 -------------------------------------------------------------------------------- Table of Contents The following table presents a reconciliation of the GAAP financial measure of GPT expenses to the non-GAAP financial measures of Cash GPT and E&P GPT for the periods presented (in thousands): Successor Predecessor Successor Predecessor Three Months Three Months Ended Ended Nine Months Nine Months September September Ended September Ended September 30, 2021 30, 2020 30, 2021 30, 2020 GPT$ 16,400 $ 20,328 $ 52,596 $ 73,557 Pipeline imbalances 547 90 1,656 (1,377) Cash GPT 16,947 20,418 54,252 72,180 Intercompany impacts from midstream segment 1,856 1,965 5,455 5,761 E&P GPT$ 18,803 $ 22,383 $ 59,707 $ 77,941 E&P Cash G&A We define E&P Cash G&A as total G&A expenses less non-cash equity-based compensation expenses, other non-cash charges and G&A expenses attributable to our midstream business segment. E&P Cash G&A is not a measure of G&A expenses as determined by GAAP. Management believes that the presentation of E&P Cash G&A provides useful additional information to investors and analysts to assess our operating costs in comparison to peers without regard to equity-based compensation programs, which can vary substantially from company to company. The following table presents a reconciliation of the GAAP financial measure of G&A expenses to the non-GAAP financial measure of E&P Cash G&A for the periods presented (in thousands): Successor Predecessor Successor Predecessor Three Months Nine Months Ended Ended September Three Months Ended September Nine Months Ended 30, 2021 September 30, 2020 30, 2021 September 30, 2020 General and administrative expenses$ 19,514 $ 49,251$ 60,461 $ 117,868 Equity-based compensation expenses (4,287) (4,502) (11,187) (15,861) G&A expenses attributable to midstream segment (3,670) (5,317) (12,709) (17,128) Other non-cash adjustments (1,025) 983 (675) 560 E&P Cash G&A$ 10,532 $ 40,415$ 35,890 $ 85,439 Cash Interest and E&P Cash Interest We define Cash Interest as interest expense plus capitalized interest less amortization and write-offs of deferred financing costs and debt discounts included in interest expense, and E&P Cash Interest is defined as total Cash Interest less Cash Interest attributable to OMP. Cash Interest and E&P Cash Interest are not measures of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest and E&P Cash Interest provide useful additional information to investors and analysts for assessing the interest charges incurred on our debt to finance our E&P activities, excluding non-cash amortization, and our ability to maintain compliance with our debt covenants. 47 -------------------------------------------------------------------------------- Table of Contents The following table presents a reconciliation of the GAAP financial measure of interest expense to the non-GAAP financial measures of Cash Interest and E&P Cash Interest for the periods presented (in thousands): Successor Predecessor Successor Predecessor Three Months Nine Months Ended Ended Nine Months Ended September Three Months Ended September September 30, 30, 2021 September 30, 2020 30, 2021 2020(1) Interest expense$ 18,153 $ 37,389$ 49,421 $ 177,534 Capitalized interest 578 1,572 1,539 5,635 Amortization of deferred financing costs(2) (1,216) (1,443) (14,677) (7,590) Amortization of debt discount - (2,782) - (8,317) Cash Interest 17,515 34,736 36,283 167,262 Cash Interest attributable to OMP (10,606) (2,481) (24,091) (37,694) E&P Cash Interest$ 6,909 $ 32,255$ 12,192 $ 129,568 ___________________ (1)For the nine months endedSeptember 30, 2020 , interest expense, Cash Interest and E&P Cash Interest include a specified default interest charge of$30.3 million related to the Predecessor Credit Facility. For the nine months endedSeptember 30, 2020 , interest expense, Cash Interest and Cash Interest attributable to OMP include a specified default interest charge of$28.0 million related to the OMP Credit Facility. These specified default interest charges were waived upon our emergence from bankruptcy onNovember 19, 2020 . (2)The nine months endedSeptember 30, 2021 includes$7.8 million of fees associated with a bridge loan facility which were expensed as incurred. See "Item 1. - Financial Statements (Unaudited)-Note 11-Long-Term Debt" for more information. Adjusted EBITDA and Adjusted EBITDA attributable to Oasis We define Adjusted EBITDA as earnings (loss) before interest expense, income taxes, DD&A, exploration expenses and other similar non-cash or non-recurring charges. We define Adjusted EBITDA attributable to Oasis as Adjusted EBITDA less Adjusted EBITDA attributable to OMP, plus distributions from OMP for our ownership of OMP limited partner units and, prior to the Midstream Simplification, Adjusted EBITDA attributable to our retained interests in Bobcat DevCo and Beartooth DevCo (the "DevCo Interests") and distributions from OMP GP related to OMP's incentive distribution rights. Adjusted EBITDA and Adjusted EBITDA attributable to Oasis are not measures of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Adjusted EBITDA and Adjusted EBITDA to Oasis provides useful additional information to investors and analysts for assessing our results of operations, financial performance, ability to generate cash from our business operations without regard to our financing methods or capital structure and, with respect to Adjusted EBITDA attributable to Oasis, our ability to maintain compliance with our debt covenants under the Oasis Credit Facility. 48 -------------------------------------------------------------------------------- Table of Contents The following table presents reconciliations of the GAAP financial measures of net loss including non-controlling interests and net cash provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA attributable to Oasis for the periods presented (in thousands): Successor Predecessor Successor Predecessor Three Months Nine Months Nine Months Ended Ended September Three Months Ended Ended September September 30, 30, 2021 September 30, 2020 30, 2021 2020 Net income (loss) including non-controlling$ 83,332 $ (47,097)$ 129,376 $ (4,470,721)
interests
Gain on sale of properties (5,405) (1,473) (228,473) (11,652) (Gain) loss on extinguishment of debt - 20 - (83,867) Net (gain) loss on derivative instruments 101,790 5,071 550,342 (243,064) Derivative settlements (81,443) 80,154 (160,018) 224,223 Interest expense, net of capitalized interest(1) 18,153 37,389 49,421 177,534 Depreciation, depletion and amortization 33,623 36,000 112,581 272,885 Impairment - 2,578 5 4,828,575 Rig termination - 1,017 - 1,279 Exploration expenses 263 725 1,936 3,061 Equity-based compensation expenses 4,287 4,834 11,187 16,531 Litigation settlement - 22,750 - 22,750 Reorganization items, net - 49,758 - 49,758 Income tax benefit - (5,144) - (262,495) Other non-cash adjustments 816 104 164 3,114 Adjusted EBITDA 155,416 186,686 466,521 527,911 Adjusted EBITDA attributable to OMP (58,178) (57,106) (170,456) (170,054) Adjusted EBITDA attributable to DevCo Interests - 19,808 - 60,553 Cash distributions from OMP to Oasis(2) 18,954 13,266 52,828 39,774 Adjusted EBITDA attributable to Oasis$ 116,192 $ 162,654$ 348,893 $ 458,184 Net cash provided by operating activities$ 294,383 $ 95,010$ 644,746 $ 154,905 Derivative settlements (81,443) 80,154 (160,018) 224,223 Interest expense, net of capitalized interest(1) 18,153 37,389 49,421 177,534 Rig termination - 1,017 - 1,279 Exploration expenses 263 725 1,936 3,061 Deferred financing costs amortization and other (2,523) (2,286) (18,811) (19,041) Current tax benefit - - - (36) Changes in working capital (74,233) (48,177) (50,917) (39,878) Litigation settlement - 22,750 - 22,750 Other non-cash adjustments 816 104 164 3,114 Adjusted EBITDA 155,416 186,686 466,521 527,911 Adjusted EBITDA attributable to OMP (58,178) (57,106) (170,456) (170,054) Adjusted EBITDA attributable to DevCo interests - 19,808 - 60,553 Cash distributions from OMP to Oasis 18,954 13,266 52,828 39,774 Adjusted EBITDA attributable to Oasis$ 116,192 $ 162,654$ 348,893 $ 458,184
___________________
(1)For the nine months ended
49
--------------------------------------------------------------------------------
Table of Contents
E&P Adjusted EBITDA and E&P Free Cash Flow
We define E&P Free Cash Flow as Adjusted EBITDA from our E&P segment plus
distributions to Oasis for (i) our ownership of OMP limited partner units and,
prior to the Midstream Simplification, (ii) distributions from OMP GP related to
OMP's incentive distribution rights and (iii) the DevCo Interests; less E&P Cash
Interest, capital expenditures for E&P and other, excluding capitalized
interest, and midstream capital expenditures attributable to the DevCo
Interests. E&P Free Cash Flow is not a measure of net income (loss) or cash
flows as determined by GAAP. Management believes that the presentation of E&P
Free Cash Flow provides useful additional information to investors and analysts
for assessing the financial performance of our E&P business as compared to our
peers and our ability to generate cash from our E&P operations and midstream
ownership interests after interest and capital spending. In addition, E&P Free
Cash Flow excludes changes in operating assets and liabilities that relate to
the timing of cash receipts and disbursements, which we may not control, and
changes in operating assets and liabilities may not relate to the period in
which the operating activities occurred.
The following table presents a reconciliation of the GAAP financial measure of
loss before income taxes including non-controlling interests from our E&P
segment to the non-GAAP financial measure of Adjusted EBITDA from our E&P
segment and E&P Free Cash Flow for the periods presented (in thousands):
Successor Predecessor Successor Predecessor
Three Months
Ended Nine Months Nine Months Ended
September Three Months Ended Ended September September 30,
30, 2021 September 30, 2020 30, 2021 2020
Income (loss) before income taxes including $ 44,040 $ (96,556) $ 18,910 $ (4,726,179)
non-controlling interests
Gain on sale of properties (5,399) (1,473) (233,502) (11,652)
(Gain) loss on extinguishment of debt - 20 - (83,867)
Net (gain) loss on derivative instruments 101,790 5,071 550,342 (243,064)
Derivative settlements (81,443) 80,154 (160,018) 224,223
Interest expense, net of capitalized interest(1) 7,156 34,636 23,445 139,338
Depreciation, depletion and amortization 23,974 31,175 83,976 255,505
Impairment - 992 3 4,717,306
Exploration expenses 263 463 1,936 3,061
Rig termination - 1,279 - 1,279
Equity-based compensation 4,144 4,502 10,518 15,909
Litigation settlement - 22,750 - 22,750
Reorganization items, net - 49,758 - 49,758
Other non-cash adjustments 816 104 185 3,114
E&P Adjusted EBITDA 95,341 132,875 295,795 367,481
Distributions to Oasis from OMP and DevCo 18,954 33,070 52,828 100,320Interests(2)
E&P Cash Interest(1) (6,909) (32,255) (12,192) (129,568) E&P and other capital expenditures (42,551) (10,223) (124,575) (202,507) Midstream capital expenditures attributable to - 1,246 - (6,467) DevCo Interests Capitalized interest 578 1,572 1,539 5,635 E&P Free Cash Flow(1)$ 65,413 $ 126,285$ 213,395 $ 134,894 ___________________ (1)For the nine months endedSeptember 30, 2020 , interest expense, E&P Cash Interest and E&P Free Cash Flow include the impact of a specified default interest charge related to the Predecessor Credit Facility of$30.3 million . The specified default interest was waived upon our emergence from bankruptcy onNovember 19, 2020 . (2)There were no distributions to Oasis from DevCo Interests subsequent to the Midstream Simplification. See "Recent Developments - Midstream Simplification" above for more information. 50 -------------------------------------------------------------------------------- Table of Contents Fair Value of Financial Instruments See "Item 1. Financial Statements (Unaudited)-Note 6-Fair Value Measurements" for a discussion of our derivative instruments and their related fair value measurements. See also "Item 3. Quantitative and Qualitative Disclosures about Market Risk" below. Critical Accounting Policies and Estimates There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2020 Annual Report. Item 3. - Quantitative and Qualitative Disclosures about Market Risk We are exposed to a variety of market risks, including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management, including the use of derivative instruments. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk" refers to the risk of loss arising from adverse changes in crude oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading. The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2020 Annual Report, as well as with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. Commodity price exposure risk. We are exposed to market risk as the prices of crude oil, natural gas and NGLs fluctuate as a result of a variety of factors, including changes in supply and demand and the macroeconomic environment, all of which are typically beyond our control. The markets for crude oil, natural gas and NGLs have been volatile, especially over the last several months and years. These prices will likely continue to be volatile in the future. To partially reduce price risk caused by these market fluctuations, we have entered into commodity derivative contracts in the past and expect to enter into derivative instruments in the future. Additionally, we may choose to liquidate existing derivative positions before the contract ends in order to realize the current value of our existing positions, in accordance with terms under our credit agreements. In addition, pursuant to the purchase and sale agreement associated with the Primary Permian Basin Sale, the Company is entitled to receive up to three earn-out payments of$25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds$60 per barrel for such year. If the NYMEX WTI crude oil price for calendar year 2023 or 2024 is less than$45 per barrel, then each calendar year thereafter Percussion's obligation to make any remaining earn-out payments is terminated. We had a net derivative liability position of$408.9 million atSeptember 30, 2021 . A 10% increase in crude oil prices would decrease the fair value of our derivative position by approximately$158.7 million , while a 10% decrease in crude oil prices would increase the fair value by approximately$153.6 million . See "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations-Recent Developments-Market Conditions and COVID-19," for further discussion on the commodity price environment. See "Item 1. Financial Statements (Unaudited)-Note 7-Derivative Instruments" to our unaudited condensed consolidated financial statements for additional information regarding our derivative instruments. Interest rate risk. AtSeptember 30, 2021 , we had$400.0 million ofOasis Senior Notes outstanding at a fixed cash interest rate of 6.375% per annum and$450.0 million of OMP Senior Notes outstanding at a fixed cash interest rate of 8.00% per annum. AtSeptember 30, 2021 , we had no borrowings and$1.3 million of outstanding letters of credit under the Oasis Credit Facility. Borrowings under the Oasis Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is aLondon interbank offered rate ("LIBOR") loan ("Eurodollar Loan") or a domestic bank prime interest rate loan ("ABR Loan"). The unused borrowing base capacity is subject to a commitment fee of 0.500%. AtSeptember 30, 2021 , OMP had$210.0 million of borrowings and$5.5 million of outstanding letters of credit under the OMP Credit Facility, which were subject to varying rates of interest based on (i) OMP's most recently tested consolidated total leverage ratio and (ii) whether the loan is a Eurodollar Loan or an ABR Loan. The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%. AtSeptember 30, 2021 , the outstanding borrowings under the OMP Credit Facility bore interest at LIBOR plus a 2.25% margin. 51 -------------------------------------------------------------------------------- Table of Contents We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Oasis Credit Facility or the OMP Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the three and nine months endedSeptember 30, 2021 , our credit losses on joint interest receivables were immaterial. We are also subject to credit risk due to concentration of our crude oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results. We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty's credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas sales receivables have been immaterial. In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. All of the counterparties on our derivative instruments currently in place are lenders under the Oasis Credit Facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other lenders under the Oasis Credit Facility, which also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. Item 4. - Controls and Procedures Evaluation of disclosure controls and procedures As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer ("CEO"), our principal executive officer, and our Chief Financial Officer ("CFO"), our principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as ofSeptember 30, 2021 . Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in theSEC's rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, our CEO and CFO concluded that the Company's disclosure controls and procedures were effective as ofSeptember 30, 2021 . Changes in internal control over financial reporting There were no changes in our internal control over financial reporting that occurred during the quarter endedSeptember 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 52
--------------------------------------------------------------------------------
Table of Contents
© Edgar Online, source
