EXTRACTION OIL & GAS, INC. CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report contains "forward-looking statements." All statements, other than statements of historical facts, included or incorporated by reference herein concerning, among other things, the BCEI Merger and Crestone Peak Merger, any statements regarding the expected timetable for completing the BCEI Merger and Crestone Peak Merger, the results, effects, benefits and synergies of the BCEI Merger and Crestone Peak Merger, future opportunities for the combined company, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "'may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could," and similar terms and phrases. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others: •our ability to execute on our business strategy following emergence from bankruptcy; •the COVID-19 pandemic, including its effects on commodity prices, downstream capacity, employee health and safety, business continuity and regulatory matters; •federal and state regulations and laws; •capital requirements and uncertainty of obtaining additional funding on terms acceptable to us; •risks and restrictions related to our debt agreements; •impact of political and regulatory developments inColorado , particularly with respect to additional permit scrutiny; •our ability to use derivative instruments to manage commodity price risk; •realized oil, natural gas and NGL prices as well as the volatility and widening of differentials; •a decline in oil, natural gas and NGL production, and the impact of general economic conditions on the demand for oil, natural gas and NGL and the availability of capital; •asset impairments from commodity price declines; •the willingness of theOrganization of Petroleum Exporting Countries ("OPEC") to set and maintain production levels; •unsuccessful drilling and completion activities and the possibility of resulting write-downs; •geographical concentration of our operations; •constraints in theDJ Basin ofColorado with respect to gathering, transportation and processing facilities and marketing; •our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil or natural gas in commercially viable quantities; •seasonal weather conditions. •shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel; •adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities; •incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of such acquired properties; •drilling operations associated with the employment of horizontal drilling techniques, and adverse weather and environmental conditions; •limited control over non-operated properties; •title defects to our properties and inability to retain our leases; •our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage; •our ability to retain key members of our senior management and key technical employees; •cost of pending or future litigation; •risks relating to managing our growth, particularly in connection with the BCEI Merger and Crestone Peak Merger and integration of other significant acquisitions; •impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation; •changes in tax laws; •effects of competition; and •the outbreak of communicable diseases such as coronavirus. Reserve engineering is a process of estimating underground accumulations of oil, natural gas, and NGL that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers and management. In addition, the 31 -------------------------------------------------------------------------------- Table of Contents results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGL that are ultimately recovered. In addition to the other information and risk factors set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading "Risk Factors" included in Item 1A of this Quarterly Report, in the Company's Annual Report on Form 10-K for the year endedDecember 31, 2020 ("Annual Report"), and in the Company's other filings with theSecurities and Exchange Commission , which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this Quarterly Report. Except as required by law, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise. Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the condensed consolidated financial statements and related notes included in Item 1 of this Quarterly Report. The following information updates the discussion of the Company's financial condition provided in its Annual Report and analyzes the changes in the results of operations between the three and combined six months endedJune 30, 2021 and the three and six months endedJune 30, 2020 . EXECUTIVE SUMMARY We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in theRocky Mountain region, primarily in the Wattenberg Field of theDenver-Julesburg Basin ofColorado . We have developed an oil, natural gas and NGL asset base of proved reserves, as well as a portfolio of development drilling opportunities on high resource-potential leasehold on contiguous acreage blocks in some of the most productive areas of what we consider to be the core of theDJ Basin . 32 -------------------------------------------------------------------------------- Table of Contents Financial Results Our results of operations as reported in our condensed consolidated financial statements for the periodsJanuary 21, 2021 throughJune 30, 2021 ("Successor"),January 1, 2021 throughJanuary 20, 2021 ("Predecessor"), three months endedJune 30, 2021 ("Successor"), and the three and six months endedJune 30, 2020 ("Predecessor") are in accordance with accounting principles generally accepted inthe United States of America ("GAAP"). Although GAAP requires that we report on our results for the Successor and Predecessor periods separately, management views our operating results for the combined six months endedJune 30, 2021 by combining the results of the Predecessor and Successor periods because management believes such presentation provides the most meaningful comparison of our results to prior periods. We are not able to compare the 20 days fromJanuary 1, 2021 throughJanuary 20, 2021 operating results to any of the previous periods reported in the condensed consolidated financial statements and do not believe reviewing this period in isolation would be useful in identifying any trends in or reaching any conclusions regarding our overall operating performance. We believe the key performance indicators such as operating revenues and expenses for the Successor period combined with the Predecessor period provide more meaningful comparisons to other periods and are useful in understanding operational trends. Additionally, there were no changes in policies between the periods and any material impacts as a result of fresh start reporting were included within the discussion of these changes. These combined results do not comply with GAAP and have not been prepared as pro forma results under applicable regulations, but are presented because we believe they provide the most meaningful comparison of our results to prior periods. For the three and combined six months endedJune 30, 2021 , crude oil, natural gas and NGL sales, coupled with the impact of settled derivatives, increased to$204.4 million and$486.2 million , respectively, as compared to$94.5 million and$299.0 million , respectively, in the same prior year period due to an increase of$17.95 and$18.64 , respectively, in realized price per BOE, including settled derivatives, partially offset by a decrease in sales volumes of approximately 1,347 MBoe and 3,480 MBoe, respectively. For the three and combined six months endedJune 30, 2021 , we had net income of$24.5 million and$984.1 million , respectively, as compared to a net loss of$291.9 million and$282.9 million , respectively, for the three and six months endedJune 30, 2020 . The change to net income for the three months endedJune 30, 2021 from a net loss for the three months endedJune 30, 2020 was primarily driven by an increase in sales revenues of$160.5 million , a decrease in operating expenses of$122.2 million , a decrease in reorganization items, net of$26.9 million and a decrease of$18.1 million in interest expense, partially offset by an increase in income tax expenses of$4.8 million . The change to net income for the combined six months endedJune 30, 2021 from a net loss for the six months endedJune 30, 2020 was primarily driven by an increase in sales revenues of$287.8 million , a decrease in operating expenses of$307.4 million , an increase in reorganization items, net of$900.8 million , a decrease in the loss on deconsolidation of Elevation of$73.1 million and a decrease of$34.9 million in interest expense, partially offset by a decrease in commodity derivative gains of$310.6 million and an increase in income tax expenses of$25.9 million . Adjusted EBITDAX was$150.1 million and$357.3 million , respectively, for the three and combined six months endedJune 30, 2021 as compared to$114.0 million and$237.9 million , respectively, for the three and six months endedJune 30, 2020 , reflecting a 32% increase and 50% increase, respectively. Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please refer to "-Adjusted EBITDAX."
Operational Results
During the three and combined six months endedJune 30, 2021 , we focused on improving free cash flow and implemented operational efficiencies to reduce drilling and completion costs. During the three months endedJune 30, 2021 , we incurred approximately$47.3 million in drilling 9 gross (6.4 net) wells with an average lateral length of 2.1 miles and completing 24 gross (14.9 net) wells with an average lateral length of 2.2 miles. In addition, we incurred approximately$3.4 million of leasehold and surface acreage additions. We turned 22 gross (16.3 net) wells to sales during the three months endedJune 30, 2021 . 33 -------------------------------------------------------------------------------- Table of Contents During the combined six months endedJune 30, 2021 , we incurred approximately$78.8 million in drilling 20 gross (12.5 net) wells with an average lateral length of 2.2 miles and completing 39 gross (26.7 net) wells with an average lateral length of 2.2 miles, all of which were horizontal wells in theDJ Basin . In addition, we incurred approximately$4.6 million of leasehold and surface acreage additions. We turned 22 gross (16.3 net) wells to sales during the combined six months endedJune 30, 2021 .
Recent Developments
Emergence from Chapter 11 Bankruptcy
As previously disclosed, onJune 14, 2020 (the "Petition Date"), Extraction and its wholly owned subsidiaries (collectively, the "Debtors"), filed voluntary petitions for relief under chapter 11 ("Chapter 11") of title 11 of the United States Code (the "Bankruptcy Code") in theUnited States Bankruptcy Court for the District of Delaware (the "Bankruptcy Court "). The Debtors' Chapter 11 cases (the "Chapter 11 Cases") were jointly administered under the caption In reExtraction Oil & Gas ., et al. Case No. 20-11548 (CSS). OnJuly 30, 2020 , the Debtors filed a proposed Plan of Reorganization (as amended, modified, or supplemented from time to time, the "Plan") and related Disclosure Statement (as amended or modified, the "Disclosure Statement") describing the Plan and the solicitation of votes to approve the same from certain of the Debtors' creditors with respect to the Chapter 11 Cases. Subsequently onOctober 22, 2020 andNovember 5, 2020 , the Debtors filed first and second amendments, respectively, to the Disclosure Statement. The hearing to consider approval of the Disclosure Statement was held onNovember 6, 2020 . OnNovember 6, 2020 , theBankruptcy Court approved the adequacy of the Disclosure Statement and the Debtors commenced a solicitation process to obtain votes on the Plan. The Plan was confirmed by order of theBankruptcy Court onDecember 23, 2020 (the "Confirmation Order"). OnJanuary 20, 2021 (the "Emergence Date"), the Plan became effective in accordance with its terms and the Company emerged from the Chapter 11 Cases.
NASDAQ Delisting and Relisting
Our common stock was traded on the NASDAQ Global Select Market (the "NASDAQ") under the symbol "XOG" prior toJune 25, 2020 . OnJune 16, 2020 , we received a letter from NASDAQ notifying us that in accordance with NASDAQ rules, our securities would be delisted at the opening of business onJune 25, 2020 . OnJune 25, 2020 , our common stock began trading on the Pink Open Market under the symbol "XOGAQ". In connection with our emergence from the Chapter 11 Cases, our common stock was relisted on the NASDAQ onJanuary 21, 2021 and began trading under the symbol "XOG."
Bonanza Creek Energy, Inc. Merger and Crestone Peak Merger
As previously disclosed, onMay 9, 2021 , Bonanza Creek Energy, Inc. ("Bonanza Creek") and Extraction signed a merger agreement (the "BCEI Merger Agreement") for an all-stock merger of equals (the "BCEI Merger"). OnJune 6, 2021 , Extraction entered into a merger agreement, by and among Bonanza Creek, Raptor Condor Merger Sub 1, Inc., aDelaware corporation and a wholly owned subsidiary of BCEI, Raptor Condor Merger Sub 2, LLC, aDelaware limited liability company and a wholly owned subsidiary of BCEI,Crestone Peak Resources LP , aDelaware limited partnership,CPPIB Crestone Peak Resources America Inc. , aDelaware corporation ("Crestone Peak"),Crestone Peak Resources Management LP , aDelaware limited partnership (the "Crestone Peak Merger Agreement"). The Crestone Peak Merger Agreement, among other things, provides for Bonanza Creek's acquisition of Crestone Peak (the "Crestone Peak Merger"). The closing of the Crestone Peak Merger is expressly conditioned on the closing of the BCEI Merger. Upon completion of the BCEI Merger and Crestone Peak Merger, the combined company will be namedCivitas Resources, Inc. ("Civitas"). Following the BCEI Merger and Crestone Peak Merger, Bonanza Creek President and Chief Executive Officer,Eric Greager , will serve as President and CEO of Civitas. Other senior leadership positions will be filled by current executives of Bonanza Creek and Extraction. As designated in the BCEI Merger agreement, of the six named officers, three will be from Bonanza Creek and three from Extraction. Extraction Chairman of the Board of Directors ("Board"),Ben Dell , will serve as Chairman of Civitas, and Bonanza Creek and Extraction will each nominate four directors, and CPP Investments will nominate one director to Civitas' diverse, nine-member Board. We anticipate the BCEI Merger will be completed during the latter half of 2021. 34 -------------------------------------------------------------------------------- Table of Contents Divestiture InApril 2021 , we completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately$15.2 million , subject to customary purchase price adjustments. No gain or loss was recognized. In conjunction with theApril 2021 divestiture,we recorded a receivable of approximately$2.7 million in the condensed consolidated balance sheet as ofJune 30, 2021 for post-closing adjustments.
How We Evaluate Our Operations
We use various financial and operational metrics to assess the performance of our operations, including:
•Sources of revenue; •Sales volumes; •Realized prices on the sale of oil, natural gas and NGL, including the effect of our commodity derivative contracts; •Lease operating expenses; •Capital expenditures; •Adjusted EBITDAX (a non-GAAP measure); •Free cash flow (a non-GAAP measure); and •Combined Predecessor periodJanuary 1, 2021 toJanuary 20, 2021 and Successor periodJanuary 21, 2021 toJune 30, 2021 (a non-GAAP measure) for comparison purposes in MD&A. Sources of Revenues Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives. For the three months endedJune 30, 2021 , our revenues were derived 62% from oil sales, 18% from natural gas sales and 20% from NGL sales. For the three months endedJune 30, 2020 , our revenues were derived 58% from oil sales, 25% from natural gas sales and 17% from NGL sales. For the combined six months endedJune 30, 2021 , our revenues were derived 52% from oil sales, 32% from natural gas sales and 16% from NGL sales. For the six months endedJune 30, 2020 , our revenues were derived 71% from oil sales, 17% from natural gas sales and 12% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. 35 -------------------------------------------------------------------------------- Table of Contents Sales Volumes The following table presents historical sales volumes for the periods indicated: Successor Predecessor For the Three Months For the Three Months Ended June 30, Ended June 30, 2021 2020 Oil (MBbl) 2,349 3,419 Natural gas (MMcf) 15,834 17,543 NGL (MBbl) 1,987 1,979 Total (MBoe) 6,975 8,322 Average net sales (BOE/d) 76,645 91,451 Successor Predecessor Non-GAAP Predecessor For the Period from For the Period from January 21 through June January 1 through Combined Six Months For the Six Months 30, January 20, Ended June 30, Ended June 30, 2021 2021 2021 2020 Oil (MBbl) 4,141 546 4,687 6,923 Natural gas (MMcf) 27,198 3,412 30,610 36,546 NGL (MBbl) 3,254 376 3,630 3,885 Total (MBoe) 11,927 1,492 13,419 16,899 Average net sales (BOE/d) 74,081 74,600 74,137 92,852 As reservoir pressures decline, production from a given well or formation decreases. Growth or maintenance in our future production and reserves will depend on our ability to continue to add or develop proved reserves in excess of our production. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including takeaway capacity in our areas of operation and our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please refer to "Risks Related to the Oil, Natural Gas and NGL Industry and Our Business" in Item 1A of the Company's Annual Report for a further description of the risks that affect us.
Realized Prices on the Sale of Oil, Natural Gas and NGL
Our results of operations depend upon many factors, particularly the price of oil, natural gas and NGL and our ability to market our production effectively. Oil, natural gas and NGL prices are among the most volatile of all commodity prices. For example, during the period fromJanuary 1, 2019 toJune 30, 2021 , NYMEX West Texas Intermediate ("WTI") oil prices ranged from a high of$74.05 per Bbl to a low of negative$37.63 per Bbl. NYMEX Henry Hub gas prices ranged from a high of$3.65 per MMBtu to a low of$1.48 per MMBtu during the same period. Fluctuations in the price of oil and natural gas occurring during 2019, 2020 and 2021 are due to a combination of factors including increasedU.S. supply, global economic concerns stemming from COVID-19, the price war betweenRussia and OPEC+, and the 2021Texas Power crisis. These price fluctuations can have a material impact on our financial results and capital expenditures. Oil pricing is predominantly driven by fluctuations in supply and demand, including as a result of production and storage capacity, financial markets, and geopolitical factors. The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil inthe United States . The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. In theDJ Basin , oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials. 36 -------------------------------------------------------------------------------- Table of Contents Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas inthe United States . Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, wet natural gas with a high Btu content sells at a premium to dry natural gas with a low Btu content because it yields a greater quantity of NGL. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas' proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant, generally in the form of percentage of proceeds. The price we receive for our natural gas produced in theDJ Basin is based on CIG prices, adjusted for certain deductions. Our price for NGL produced in theDJ Basin is based on a combination of prices fromMont Belvieu inTexas and theConway hub inKansas where this production is marketed. The following table provides the high and low prices for NYMEX WTI and NYMEXHenry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil, natural gas and NGLs normally sell at a discount to the NYMEX WTI and NYMEX Henry Hub price, as applicable. 37
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For the Three Months Ended June 30, For the Six Months Ended June 30,
2021 2020 2021 2020
Oil
NYMEX WTI High ($/Bbl) $ 74.05 $ 40.46 $ 74.05 $ 63.27
NYMEX WTI Low ($/Bbl) $ 58.65 $ (37.63) $ 47.62 $ (37.63)
NYMEX WTI Average ($/Bbl) $ 66.10 $ 28.00 $ 62.21 $ 36.82
Average Realized Price ($/Bbl)(1) $ 59.22 $ 10.61 $ 56.92 $ 23.18
Average Realized Price, with
derivative settlements ($/Bbl)(1) $ 50.60 $ 18.11 $ 50.27 $ 31.97
Average Realized Price as a % of
Average NYMEX WTI 89.6 % 37.9 % 91.5 % 63.0 %
Differential ($/Bbl) to Average NYMEX
WTI(2)(3) $ (6.88) $
(16.26)
3.65 $ 2.13 $ 3.65 $ 2.20
NYMEX Henry Hub Low ($/MMBtu) $ 2.46 $ 1.48 $ 2.45 $ 1.48
NYMEX Henry Hub Average ($/MMBtu) $ 2.97 $ 1.75 $ 2.85 $ 1.81
NYMEX Henry Hub Average converted to a
$/Mcf basis(4) $ 3.27 $ 1.93 $ 3.14 $ 1.99
Average Realized Price ($/Mcf)(5) $ 2.49 $ 0.91 $ 5.38 $ 1.05
Average Realized Price, with
derivative settlements ($/Mcf)(5) $ 2.56 $ 1.24 $ 5.42 $ 1.32
Average Realized Price as a % of
Average NYMEX Henry Hub(4)(5) 76.1 % 47.2 % 171.3 % 52.8 %
Differential ($/Mcf) to Average NYMEX
Henry Hub(4)(5) $ (0.78) $ (1.02) $ 2.24 $ (0.94) NGL
Average Realized Price ($/Bbl)(5) $ 22.67$ 5.47 $ 23.33 $ 7.21 Average Realized Price as a % of Average NYMEX WTI(5) 34.3 % 19.5 % 37.5 % 19.6 %
BOE
Average Realized Price per BOE(1) $ 32.06$ 7.59 $ 38.46 $ 13.42 Average Realized Price per BOE with derivative settlements $ 29.30$ 11.35 $ 36.24 $ 17.60
_______________
(1) Includes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the three and six months endedJune 30, 2020 , pursuant to ASC Topic 606-Revenue Recognition ("ASC 606"). (2) Excludes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the three and six months endedJune 30, 2020 , pursuant to ASC 606. (3) During the first quarter of 2021, our renegotiated crude oil midstream contract was effective as ofMarch 1, 2021 , which resulted in a change in the accounting treatment under ASC 606. As a result, the crude oil differential for the combined six months endedJune 30, 2021 is not reflective of our differential going forward. (4) Based on the difference between our average realized price and the NYMEX Henry Hub Average as converted into Mcf using a conversion factor of 1.1 to 1. (5) During the first quarter of 2021, a large portion of our gas and NGL contracts were subject to daily prices versus a monthly average price. As a result, our realized prices for the combined six months endedJune 30, 2021 benefited from several days of severe cold duringFebruary 2021 . 38 -------------------------------------------------------------------------------- Table of Contents Derivative Arrangements To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time, we enter into derivative arrangements for our oil and natural gas production. By removing a significant portion of price volatility associated with our oil and natural gas production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil and natural gas prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will realize gains to the extent our derivatives contract prices are higher than market prices. In certain circumstances, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts. We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We have relied on a variety of hedging strategies and instruments to hedge our future price risk. We have utilized swaps, put options and call options, which in some instances require the payment of a premium, to reduce the effect of price changes on a portion of our future oil and natural gas production. We expect to continue to use a variety of hedging strategies and instruments for the foreseeable future. The RBL Credit Agreement requires us to maintain commodity hedges covering a minimum of 65% of our anticipated oil and gas production from PDP reserves for the succeeding twelve months and 50% of our anticipated oil and gas production from PDP reserves for the next succeeding twelve months. The hedge prices will depend on the commodity price environment at the time at which those hedge transactions are entered. In the current commodity price environment, our ability to enter into derivative arrangements at favorable prices may be limited.
For a description of our derivative instruments that we utilize and a summary of
our commodity derivative contracts as of
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Table of Contents The following table summarizes our historical derivative positions and the settlement amounts for each of the periods indicated:
Successor Predecessor Predecessor
For the Period from For the Period from
January 21 through January 1 through For the Six Months
June 30, January 20, Ended June 30,
2021 2021 2020
NYMEX WTI Crude Swaps:
Notional volume (Bbl) 2,788,200 - 525,000
Weighted average fixed price ($/Bbl) $ 50.34 $ - $ 60.05
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl) - - 4,950,000
Weighted average purchased put price $ - $ - $ 54.48
($/Bbl)
NYMEX WTI Crude Purchased Calls: Notional volume (Bbl) - - 1,100,000 Weighted average purchased call price $ - $ - $ 68.04 ($/Bbl) NYMEX WTI Crude Sold Calls: Notional volume (Bbl) - - 5,650,000 Weighted average sold call price ($/Bbl) $ - $ - $ 63.37 NYMEX WTI Crude Sold Puts: Notional volume (Bbl) - - 5,300,000 Weighted average sold put price ($/Bbl) $ - $ - $ 44.39 NYMEX HH Natural Gas Swaps: Notional volume (MMBtu) 12,437,315 - 17,400,000 Weighted average fixed price ($/MMBtu) $ 2.94 $ - $ 2.75 NYMEX HH Natural Gas Purchased Puts: Notional volume (MMBtu) - - 600,000 Weighted average purchased put price $ - $ - $ 2.90
($/MMBtu)
NYMEX HH Natural Gas Sold Calls: Notional volume (MMBtu) - - 600,000 Weighted average sold call price ($/MMBtu) $ - $ - $ 3.48 CIG Basis Gas Swaps: Notional volume (MMBtu) - - 22,800,000 Weighted average fixed basis price $ - $ - $ (0.61)
($/MMBtu)
Total Amounts Received/(Paid) from $ (29,871) $ - $ 166,725 Settlement (in thousands) Cash provided by (used in) changes in Accounts Receivable and Accounts Payable 8,703 542 (5,213) related to Commodity Derivatives Derivative unwinds reducing the Prior - - (96,065) Credit Facility balance Settlements on Commodity Derivatives per Condensed Consolidated Statements of Cash $ (21,168) $ 542 $ 65,447 Flows Lease Operating Expenses All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constitutes part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, water injection and disposal costs, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.
Capital Expenditures
For the combined six months endedJune 30, 2021 , we incurred approximately$78.8 million in drilling and completion capital expenditures. For the combined six months endedJune 30, 2021 , we drilled 20 gross (12.5 net) wells with an average lateral length of approximately 2.2 miles and completed 39 gross (26.7 net) wells with an average lateral 40 -------------------------------------------------------------------------------- Table of Contents length of approximately 2.2 miles. We turned to sales 22 gross (16.3 net) wells with an average lateral length of approximately 2.2 miles during the combined six months endedJune 30, 2021 . In addition, we incurred approximately$4.6 million of leasehold and surface acreage additions during the combined six months endedJune 30, 2021 . OnJuly 8, 2021 , the board of directors approved an increase in our 2021 capital expenditures budget. The 2021 total revised capital budget was approved to be$159 million , which includes$146 million for drilling and completion activity and$13 million for plugging and abandoning and other activity. Previously, our 2021 capital budget was$142 million , which included$130 million for drilling and completions activity and$12 million for plugging and abandoning and other activity. 41 -------------------------------------------------------------------------------- Table of Contents Adjusted EBITDAX Adjusted EBITDAX is not a measure of net income (loss) as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) adjusted for certain cash and non-cash items shown in the table below, which presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated (in thousands). Successor Predecessor For the Three For the Three Months Ended Months Ended JuneJune 30 , 30, 2021 2020
Reconciliation of Net Income (Loss) to Adjusted EBITDAX: Net income (loss)
$ 24,544 $ (291,934) Add back: Depletion, depreciation, amortization and accretion 50,090 82,620 Impairment of long-lived assets 170 960 Other operating expenses 5,380 13,209 Exploration and abandonment expenses 3,586 62,661 Loss on commodity derivatives 75,839 69,301 Settlements on commodity derivative instruments (19,237) 127,429 Stock-based compensation expense 2,771 2,560 Amortization of debt issuance costs 457 1,948 Interest expense 1,713 18,366 Income tax expense 4,775 - Reorganization items, net - 26,919 Adjusted EBITDAX$ 150,088 $ 114,039 42
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Successor Predecessor Non-GAAP Predecessor
For the Period
For the Period from January 1 Combined Six
from January 21 through January Months Ended For the Six Months
through June 30, 20, June 30, Ended June 30,
2021 2021 2021 2020
Reconciliation of Net Income (Loss) to
Adjusted EBITDAX:
Net income (loss) $ 113,098 $
870,970
88,665 16,133 104,798 158,670
and accretion
Impairment of long-lived assets 170 - 170 1,736
Other operating expenses 9,262 1,107 10,369 65,784
Exploration and abandonment expenses 4,345 316 4,661 175,141
(Gain) loss on commodity derivatives 104,325 12,586 116,911 (193,714)
Settlements on commodity derivative (29,871) - (29,871) 166,725
instruments
Stock-based compensation expense 4,945 302 5,247 2,560 Amortization of debt issuance costs 909 113 1,022 3,190 Interest expense 4,294 1,421 5,715 38,482 Income tax expense 28,100 - 28,100 2,200 Loss on deconsolidation of Elevation - - - 73,139Midstream, LLC Reorganization items, net - (873,908) (873,908) 26,919 Adjusted EBITDAX$ 328,242 $ 29,040 $ 357,282 $ 237,935 Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed in the table above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance. Additionally, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:
(i) is widely used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items excluded from the calculation of such term, among other factors;
(ii) helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and
(iii) is used by our management team for various purposes, including as a measure of operating performance, in presentations to our Board, as a basis for strategic planning and forecasting.
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Free Cash Flow
Our Free Cash Flow is not a measure of and should not be considered an alternative to, or more meaningful than, net income (loss) as determined by GAAP. We define Free Cash Flow as Discretionary Cash Flow (non-GAAP) less Adjusted Cash Flow used in Investing (non-GAAP) adjusted for Other Non-Recurring Adjustments (non-GAAP). Discretionary Cash Flow is defined as net cash provided by operating activities (GAAP) before changes in working capital accounts (current assets and liabilities). Adjusted Cash Flow used in Investing is defined as cash flow used in investing activities (GAAP) adjusted for changes in accounts payable and accrued liabilities related to capital expenditures. Free Cash Flow is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Free Cash Flow can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe Free Cash Flow provides additional information that may be useful in an analysis of our ability to generate cash to fund exploration and development activities and to return capital to stockholders. The following tables present a reconciliation of Discretionary Cash Flow and Free Cash Flow to the GAAP financial measure of net cash provided by operating activities for each of the periods indicated.
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