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Item 2. Management’s Discussion and Analysis

2021-05-14 compared with 2020-11-09 · 143 added, 350 removed, 119 unchanged (81% of the section changed)

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations for the three and nine months ended September 30, 2020 (Successor) and 2019 (Predecessor) and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019 (Successor).

Certain prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting.

References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to October 1, 2019.

References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, October 1, 2019.

The following discussion is intended to assist in understanding our results of operations for the three months ended March 31, 2021 and 2020 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

Statements in this discussion may be forward-looking.

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We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States.

During 2017 (Predecessor), we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota and in the El Halcón area of East Texas.

During 2017, we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota and in the El Halcón area of East Texas.

As a result, our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers attractive long-term economics.

During the first nine months of 2020 (Successor), production averaged 16,712 Boe/d compared to average production of 17,209 Boe/d during the first nine months of 2019 (Predecessor).

Our average daily oil and natural gas production decreased in the first nine months of 2020 (Successor) when compared to the same period in the prior year primarily due to our temporary shut-in of a portion of producing wells across all our operating areas in May and June 2020 as a consequence of low oil prices.

Estimated downtime associated with these temporary shut-ins was approximately 1,800 Boe/d for the first nine months of 2020 (Successor).

The production decline caused by temporary shut-ins in the current year period was partially offset by new wells put online since the prior year.

For the nine months ended September 30, 2020 (Successor), we drilled and cased 4.0 gross (4.0 net) operated wells, completed 5.0 gross (4.3 net) operated wells, and put online 7.0 gross (6.3 net) operated wells.

Our total operating revenues for the first three months of 2021 and 2020 were $55.5 million and $47.4 million, respectively.

The increase in revenues in the most recent period is primarily attributable to an approximate $15.34 per Boe increase in average realized prices in the most recent period.

During the first three months of 2021, production averaged 14,333 Boe/d compared to average production of 18,791 Boe/d during the first three months of 2020.

Our average daily oil and natural gas production decreased in the first three months of 2021 when compared to the same period in the prior year primarily due to production declines in our non-core areas, which were partially offset by increased production from our Monument Draw area, where new production came online as a result of our capital spending program.

Also contributing to decreased total production in the current year period is a temporary shut-in of production in February 2021 as a result of inclement weather.

The estimated production decrease associated with this temporary shut-in was approximately 1,300 Boe/d for the first three months of 2021.

In addition, in December 2020, we divested properties that produced approximately 800 Boe/d during the three months ended March 31, 2020.

For the three months ended March 31, 2021, we drilled and cased 2.0 gross (2.0 net) operated wells, completed 4.0 gross (4.0 net) operated wells, and put online 4.0 gross (4.0 net) operated wells.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production.

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The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors.

Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Oil and natural gas prices are inherently volatile and sustained lower commodity prices could have a material impact upon our full cost ceiling test calculation.

Accordingly, finding, developing and producing oil and natural gas reserves at economical costs are critical to our long-term success.

Oil and natural gas prices are inherently volatile and sustained lower commodity prices could result in impairment charges under our full cost ceiling test calculation.

The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date.

Using the crude oil price for October 2020 of $42.37 per barrel, and holding it constant for two months to create a trailing 12-month period of average prices, that is more reflective of recent price trends, our ceiling amount related to the net book value of our oil and natural gas properties would have been reduced and would have generated an additional impairment of $77.5 million, holding all other inputs and factors constant.

In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full

cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Using the crude oil price for April 2021 of $61.35 per barrel, and holding it constant for two months to create a trailing 12-month period of average prices that is more reflective of recent price trends, our ceiling test calculation would not have generated an impairment, holding all other inputs and factors constant.

In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Recent Developments

Risk and Uncertainties

We are continuously monitoring the current and potential impacts of the novel coronavirus (COVID-19) pandemic on our business, including how it has and may continue to impact our operations, financial results, liquidity, contractors, customers, employees and vendors, and taking appropriate actions in response, including reducing capital expenditures, temporarily shutting-in producing wells, and implementing various measures to ensure the continued operation of our business in a safe and secure manner.

COVID-19 and governmental actions to contain the pandemic have contributed to an economic downturn, reduced demand for oil and natural gas and, together with a price war between the Organization of Petroleum Exporting Countries (OPEC)/Saudi Arabia and Russia, depressed oil and natural gas prices to historically low levels.

Although OPEC and Russia agreed in April to reduce production, downward pressure on prices has continued and could continue for the foreseeable future, particularly given concerns over the impacts of the current economic downturn on demand.

We are unable to predict the effect that these events will have on our business and financial condition due to numerous uncertainties, including the severity and duration of the COVID-19 outbreak and the impacts that governmental or other actions taken to limit the extent and duration of the outbreak, in conjunction with economic conditions, will have on our business, demand for oil and natural gas, and oil and natural gas prices.

We are continuously monitoring the current and potential impacts of the novel coronavirus (COVID-19) pandemic on our business, including how it has and may continue to impact our operations, financial results, liquidity, contractors, customers, employees and vendors, and taking appropriate actions in response, including implementing various measures to ensure the continued operation of our business in a safe and secure manner.

In 2020, COVID-19 and governmental actions to contain the pandemic contributed to an economic downturn, reduced demand for oil and natural gas and, together with a price war involving the Organization of Petroleum Exporting Countries (OPEC)/Saudi Arabia and Russia, depressed oil and natural gas prices to historically low levels.

Although OPEC and Russia subsequently agreed to reduce production, downward pressure on prices continued for several months, particularly given concerns over the impacts of the economic downturn on demand.

We are unable to predict the future affects that these events will have on our business and financial condition due to numerous uncertainties, including the continuing severity and duration of the COVID-19 outbreak and the impacts that governmental or other actions taken to limit the extent and duration of the outbreak, in conjunction with economic conditions, will have on our business, demand for oil and natural gas, and oil and natural gas prices.

The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and critical functions cannot be predicted, nor can the impact on our customers, vendors and contractors.

Any material effect on these parties could adversely impact us.

These and other factors could affect the Company’s operations, earnings and cash flows and could cause our results to not be comparable to those of the same period in previous years.

For example, we realized lower revenue as a result of commodity price declines, which began in March 2020.

In response to low commodity prices, we temporarily shut-in producing wells in May and June 2020, which further contributed to lower revenues in the current year.

Additionally, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing used in the valuation of our reserves.

These and other factors could affect our operations, earnings and cash flows and could cause our results to not be comparable to those of the same period in previous years.

For example, in 2020, we realized lower revenue as a result of commodity price declines, which began in March 2020.

In response to low commodity prices, we temporarily shut-in producing wells in May and June 2020, which further contributed to lower revenues that year.

Additionally, we incurred ceiling test impairments in 2020, which were primarily driven by a decline in the average pricing required to be used in the valuation of our reserves for ceiling test purposes.

The results presented in this Form 10-Q are not necessarily indicative of future operating results.

For further information regarding the actual and potential impacts of COVID-19 on us, see “Risk Factors” in Item 1A of this Quarterly Report on Form 10-Q.

Acid Gas Injection Well Permits

During the nine months ended September 30, 2020 (Successor), we received permits from the Texas Railroad Commission and the Texas Commission on Environmental Quality to construct and operate an acid gas injection well (AGI) by converting an existing producing gas well.

AGI can provide a more cost effective alternative to sour gas treating.

We are currently evaluating options for development of an AGI facility, including, but not limited to, divestiture of the assets with an associated third party treating arrangement for our sour gas production.

Successor Senior Revolving Credit Facility

On October 29, 2020 (Successor), we entered into the Third Amendment to Senior Secured Revolving Credit Agreement and Limited Waiver (the Third Amendment).

The Third Amendment, among other things, sets the borrowing base to $190 million as of November 1, 2020, which eliminated the final monthly reduction of $5.0 million required under the Second Amendment (defined below).

The Third Amendment also reduces the amount available for the issuance of letters of credit to $25.0 million and amends certain covenants including, but not limited to, covenants relating to increasing the minimum mortgaged total value of proved borrowing base properties from 85% to 90%.

Additionally, the Third Amendment provides for new covenants that, among other things, require us to enter into required swap agreements representing not less than 65% of our reasonably anticipated projected production from the proved reserves classified as developed producing reserves for a period from the Third Amendment effective date through at least December 31, 2022 and prohibit no more than $3 million of our uncontested accounts payable or accrued expenses, liabilities or other obligations from remaining outstanding for longer than 90 days.

Pursuant to the Third Amendment, the administrative agent and the lenders consented to a waiver of the Current Ratio (as defined in the

Senior Credit Agreement) for the fiscal quarter ended September 30, 2020 and also suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

On July 31, 2020 (Successor), we entered into the Limited Waiver to Senior Secured Revolving Credit Agreement (the Waiver) in which, the lenders consented to waive maintenance of a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 as of the fiscal quarter ended June 30, 2020.

Our failure to comply with the Current Ratio for the three months ended June 30, 2020 (Successor) was primarily the result of our decision to shut in certain production due to low oil prices coupled with capital spending required to maintain certain of our oil and gas leasehold interests.

On April 30, 2020 (Successor), we entered into the Second Amendment to the Senior Credit Agreement (Second Amendment) which among other things, (i) reduced the borrowing base to $200.0 million effective from April 30, 2020, which was then reduced by $5.0 million monthly starting September 1, 2020 until November 1, 2020, so that the borrowing base was scheduled to be $185.0 million on November 1, 2020, provided the borrowing base redetermination scheduled for November 1, 2020 occurred pursuant to the terms of the Senior Credit Agreement, (ii) increased interest margins to 1.50% to 2.50% for ABR-based loans and 2.50% to 3.50% for Eurodollar-based loans, (iii) provided that should our Consolidated Cash Balance (as defined pursuant to the Second Amendment) exceed $10.0 million, such amounts shall be used to prepay any borrowings under the Senior Credit Agreement and thereafter, to the extent of any uncollateralized letters of credit exposure, shall be cash collateralized in accordance with the Senior Credit Agreement and (iv) allowed for a replacement benchmark rate to the London Interbank Offered Rate (which may include SOFR, Compounded SOFR or Term SOFR).

The Second Amendment also added provisions related to a loan incurred by us under the Paycheck Protection Program of the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act).

We used, and the Second Amendment required us to use, the loan proceeds for CARES Forgivable Uses under the CARES Act.

Additionally, the Second Amendment waived, for the fiscal quarter ended June 30, 2020, that we comply with the requirement under the Senior Credit Agreement that we unwind certain swap agreements for which settlement payments were calculated in such fiscal quarter to exceed 100% of actual production.

Paycheck Protection Program Loan

On April 16, 2020 (Successor), we entered into a promissory note (the PPP Loan) for a principal amount of approximately $2.2 million from Bank of Montreal under the Paycheck Protection Program of the CARES Act, which is administered by the U.S.

Small Business Administration.

Pursuant to the terms of the CARES Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent or utility costs.

The PPP Loan bears interest at a rate of 1.0% per annum.

We are required to pay principal and interest installments of $0.1 million monthly beginning November 16, 2020.

The maturity date of the PPP Loan is April 16, 2022.

We may elect, at our option, to prepay 20% or less of the borrowings outstanding under the PPP Loan without premium or penalty, and without notice.

Prepayments of more than 20% of the outstanding borrowings require written advanced notice and payment of accrued interest.

The PPP Loan contains certain events of default including non-payment, breach of representations and warranties, cross-defaults to other loans with the lender or to material indebtedness, voluntary or involuntary bankruptcy, judgments and change in control.

Under the terms of the CARES Act, we can apply for and be granted forgiveness for all or a portion of the PPP Loan.

Such forgiveness will be determined, subject to limitations, based on the use of loan proceeds in accordance with the terms of the CARES Act during the eight week period after loan origination and the maintenance or achievement of certain employee levels.

We believe we are eligible for, and are currently pursuing, forgiveness of the PPP Loan in accordance with the requirements and limitations under the CARES Act;

however, no assurance can be provided that forgiveness of any portion of the PPP Loan will be obtained.

Listing of our Common Stock on NYSE American

Our Predecessor common stock was previously listed on the New York Stock Exchange (NYSE) under the symbol “HK.” As a result of our failure to satisfy the continued listing requirements of the NYSE, on July 22, 2019, our

Predecessor common stock was delisted from the NYSE.

Effective February 20, 2020, we commenced trading on the NYSE American exchange under the symbol “BATL.”

For further information regarding the actual and potential impacts of COVID-19 on us, see “Risk Factors” in Item 1A of our 2020 Annual Report on Form 10-K.

Senior Revolving Credit Facility

On May 10, 2021, we entered into the Fourth Amendment to Senior Secured Revolving Credit Agreement (the Fourth Amendment) which reduces the borrowing base to $185.0 million effective June 1, 2021 and further reduces the borrowing base to $175.0 million effective September 1, 2021.

The Fourth Amendment also, among other things, (i) increased interest margins to 2.00% to 3.00% for ABR-based loans and 3.00% to 4.00% for Eurodollar-based loans, (ii) amended the covenant relating to the minimum mortgaged total value of proved borrowing base properties to increase the value from 90% to 95%, (iii) provides for direct reductions in the borrowing base in the event of asset dispositions in excess of $1.0 million per fiscal year or swap terminations and (iv) revised certain covenants and covenant-related baskets including, but not limited to, adding covenants prohibiting the designation of unrestricted subsidiaries and requiring prior consent from the lenders regarding asset dispositions or swap terminations in excess of the greater of $7.5 million or 3.5% of the then effective borrowing base.

Capital Resources and Liquidity

In March 2020 (Successor), the World Health Organization declared the outbreak of COVID-19 a pandemic.

T he COVID - 19 outbreak and associated government restrictions significantly impacted economic activity and markets and dramatically reduced current and anticipated demand for oil and natural gas at the same time that supply was maintained at high levels due to a price and market share war involving the OPEC/Saudi Arabia and Russia, all of which adversely impacted the prices we received for our production during the nine months ended September 30, 2020 (Successor).

We realized lower revenue as a result of these commodity price declines, which began in March 2020 (Successor).

In response to low commodity prices, we temporarily shut-in producing wells in May and June 2020 (Successor), which further contributed to lower revenues in the current year.

Additionally, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing used in the valuation of our reserves.

In March 2020, the World Health Organization declared the outbreak of COVID-19 a pandemic.

In 2020, the COVID - 19 outbreak and associated government restrictions significantly impacted economic activity and markets and dramatically reduced demand for oil and natural gas at the same time that supply was maintained at high levels due to a price and market share war involving the OPEC/Saudi Arabia and Russia, all of which adversely impacted the prices we received for our production.

Thus, in 2020, we realized lower revenue as a result of these commodity price declines, which began in March 2020.

In response to low commodity prices, we temporarily shut-in producing wells in May and June 2020, which further contributed to lower revenues that year.

Additionally, we incurred ceiling test impairments during 2020, which were primarily driven by a decline in the average pricing required to be used in the valuation of our reserves for ceiling test purposes.

Continued actual or anticipated declines in domestic or foreign economic activity or growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the U.S.

or global financial system and markets and a severe economic contraction either regionally or worldwide, resulting from current efforts to contain the COVID-19 coronavirus or other factors, could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide oil demand, negatively impacting the price received for oil and natural gas production, adversely impacting our ability to comply with covenants in our Senior Credit Agreement or causing our lenders to reduce the borrowing base under our Senior Credit Agreement.

or global financial system and markets and an economic contraction either regionally or worldwide, resulting from current efforts to contain the COVID-19 coronavirus or other factors, could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide oil demand, negatively impacting the price received for oil and natural gas production, adversely impacting our ability to comply with covenants in our Senior Credit Agreement or causing our lenders to further reduce the borrowing base under our Senior Credit Agreement.

Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations.

All of the foregoing may adversely affect our business, financial condition, results of operations, cash flows and, potentially, compliance with the covenants contained in, and borrowing capacity under, our Senior Credit Agreement.

Our 2020 drilling and completion budget, originally approved by our board in December 2019, contemplated running one operated rig in the Delaware Basin during the year.

That budget contemplated spending approximately $123 million to $138 million in capital expenditures, including drilling, completions, support infrastructure and other capital costs, to drill seven to ten gross operated wells and to put online 12 to 14 gross operated wells during the year.

We continuously monitor changes in market conditions and adapt our operational plans as necessary in order to maintain financial flexibility, preserve acreage, and meet our contractual obligations.

Accordingly, in March 2020, as a result of changes in market conditions and commodity prices, we scaled back our capital operations and spending.

The rate of our expenditures has declined as we have progressed through the year and we expect our anticipated full year 2020 capital expenditures will be approximately $80 million to $84 million, subject to our continuing evaluation of market conditions and the risks and uncertainties affecting our business detailed elsewhere in this report.

Our near-term capital spending requirements are expected to be funded with cash and cash equivalents on hand, cash flows from operations, and borrowings under our Senior Credit Agreement, which has a current borrowing base of $190.0 million.

Amounts borrowed under the Senior Credit Agreement will mature on October 8, 2024.

At September 30, 2020 (Successor), under the then-effective borrowing base of $195.0 million, we had $178.0 million of indebtedness outstanding and approximately $4.7 million letters of credit outstanding under the Senior Credit Agreement, resulting in $12.3 million of borrowing capacity.

Under the Third Amendment, our borrowing base was recently affirmed at $190.0 million;

however, we currently expect availability under our Senior Credit Agreement to be limited through at least the second quarter of 2021.

The next redetermination is scheduled for the spring of 2021.

If our borrowing base is reduced upon a redetermination, our resulting liquidity could be insufficient to fund our business and operations and the reduction could result in a borrowing base deficiency, which would require us to repay any amount outstanding in excess of the borrowing base.

As part of our ongoing efforts to manage our business and liquidity, we are in regular contact with our lenders regarding these and other matters relating to the Senior Credit Agreement and, in parallel, are exploring alternative means to maintain our access to sufficient capital to fund our business, including refinancings, asset sales, and additional means to reduce our capital requirements.

While we believe that alternatives to maintain compliance or to

replace our Senior Credit Agreement are available to us should they become necessary, there can be no assurance in this regard.

The Senior Credit Agreement contains certain financial covenants, including maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00:1.00.

We have recently, and in the past, obtained amendments to the covenants under our revolving credit agreements in circumstances where we anticipated that it might be challenging for us to comply with the financial covenants for a particular period of time.

We expect to spend approximately $40.0 million to $50.0 million on drilling, completion, support infrastructure and other capital costs during 2021.

These near-term capital spending requirements are expected to be funded with cash and cash equivalents on hand, cash flows from operations and, if needed, borrowings under our Senior Credit Agreement, which has a current borrowing base of $190.0 million, which is scheduled to be reduced to $185.0 million on June 1, 2021 and to $175.0 million on September 1, 2021 pursuant to the Fourth Amendment to our Senior Credit Agreement, as discussed in greater detail above.

Amounts borrowed under our Senior Credit Agreement will mature on October 8, 2024.

At March 31, 2021, we had $155.0 million of indebtedness outstanding and approximately $2.5 million letters of credit outstanding under our Senior Credit Agreement, resulting in $32.5 million of borrowing capacity under the current $190.0 million borrowing base.

The next redetermination is scheduled for the fall of 2021.

If our borrowing base is further reduced upon a redetermination, our resulting liquidity could be insufficient to fund our business, operations and planned capital expenditures and the reduction could result in a borrowing base deficiency, which would require us to repay any amount outstanding in excess of the borrowing base.

As part of our ongoing efforts to manage our business and liquidity, we are in regular contact with our lenders regarding matters relating to the Senior Credit Agreement, and we closely monitor our compliance with the various covenants under our Senior Credit Agreement, which include certain financial covenants, such as maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00:1.00.

As of March 31, 2021, afte r giving effect to the Third Amendment to Senior Secured Revolving Credit Agreement and Limited Waiver (the Third Amendment), we were in compliance with the financial covenants under the Senior Credit Agreement.

We have periodically, including as recently as October 2020, obtained waivers or amendments to the financial covenants under our revolving credit agreements in circumstances where we anticipated that it might be challenging for us to comply with them for a particular period of time.

Changes in the level and timing of our production, drilling and completion costs, the cost and availability of transportation for our production and other factors varying from our expectations can affect our ability to comply with the covenants under our Senior Credit Agreement.

As a consequence, we endeavor to anticipate potential covenant compliance issues and work with the lenders under our Senior Credit Agreement to address any such issues ahead of time.

The current depression in oil and natural gas prices and our decision to temporarily shut-in a portion of our production in response to those market conditions adversely impacted our cash flows, which, combined with cash requirements associated with capital-intensive oil and gas development projects undertaken in late 2019 and early 2020, led to challenges in compliance with the Current Ratio under the Senior Credit Agreement for the fiscal quarter ended June 30, 2020.

Thus, o n July 31, 2020 (Successor), we entered into the Waiver, in which the lenders consented to waive maintenance of the Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 for the fiscal quarter ended June 30, 2020.

For instance, depressed oil and natural gas prices during 2020 and our decision to temporarily shut-in a portion of our production in response to market conditions adversely impacted our cash flows, which, combined with cash requirements associated with capital-intensive oil and gas development projects undertaken in late 2019 and early 2020, led to challenges in our compliance with the Current Ratio under the Senior Credit Agreement for the fiscal quarter ended June 30, 2020.

Thus, o n July 31, 2020, we secured a waiver in which the lenders consented to waive maintenance of the Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 for the fiscal quarter ended June 30, 2020.

In conjunction with the fall 2020 borrowing base redetermination process, and due to a decline in the value associated with our derivative contracts, we pursued additional relief from our lenders in regards to the Current Ratio.

Pursuant to the Third Amendment, on October 29, 2020, the lenders waived maintenance of the Current Ratio for the fiscal quarters ending September 30, 2020 and suspends testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

As of September 30, 2020 (Successor), afte r giving effect to the Third Amendment, we were in compliance with the financial covenants under the Senior Credit Agreement.

In prior years, we have also obtained waivers and amendments for optional covenant violations.

For instance, our strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in West Texas resulted in us divesting our producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin.

On October 29, 2020, in the Third Amendment, the lenders waived maintenance with the Current Ratio for the fiscal quarter ending September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

Similarly, in prior years, we have also obtained waivers and amendments for other financial covenant violations.

For instance, our strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in

West Texas resulted in us divesting our producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin.

Our drilling activities once we acquired these assets required significant capital expenditure outlays to replenish production and related EBITDA from the divested producing properties.

These and other factors adversely impacted our ability to comply with our debt covenants under the predecessor credit agreement by reducing our production, reserves and EBITDA on a current and a pro forma historical basis, while making us more susceptible to fluctuations in performance and compliance more challenging.

In addition, we encountered certain operational difficulties that impacted our ability to comply, including, elevated levels of hydrogen sulfide in the natural gas produced from our Monument Draw wells and limited and expensive treatment and transportation options.

In addition, we encountered certain operational difficulties that impacted our ability to comply at the time, including elevated levels of hydrogen sulfide in the natural gas produced from our Monument Draw wells and limited and expensive treatment and transportation options.

Severance payments to executives in 2019 also impacted our ability to comply with our financial covenants.

While we have largely been successful in obtaining modifications of our covenants as needed, there can be no assurance that we will be successful in the future.

In the event we are not successful, there is no assurance that we will be successful in implementing alternatives that allow us to maintain compliance with our covenants or that we will be successful in obtaining alternative financing that provides us with the liquidity that we need to operate our business.

Even if successful, alternative sources of financing could prove more expensive than borrowing under our Senior Credit Agreement.

When commodity prices decline significantly, as they have recently, our ability to finance our capital budget and operations may be adversely impacted.

We use derivative instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices, however, the total volumes we typically hedge are less than our expected production, vary from period to period based on our view of current and future market conditions and generally extend up to only approximately 30 months.

These limitations result in our liquidity being susceptible to commodity price declines.

Additionally, while intended to reduce the effects of volatile commodity prices, derivative transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge.

In short, historically, our lenders have provided us with the covenant relief we have sought to the extent it was necessary to manage through near-term business and operational challenges as we pursued our longer-term business objectives;

however, there is no assurance that they will be amenable to providing any such relief in the future, should it become necessary.

Further, there is some evidence that credit is becoming more challenging for oil and gas companies generally, and for us in particular, to secure.

As noted previously, late last year, Bank of Montreal, the primary lender under our Senior Credit Agreement, announced that it was exiting its U.S.

energy investment banking business, a service line that is generally complementary to commercial banking service offerings.

Bank of Montreal’s election to exit that line of business may be an indication of sentiment overall with regards to the business and investment banking environment affecting the U.S.

oil and gas industry in the near term.

More specifically as it regards us, in our recent redetermination, the lenders under our Senior Credit Agreement have reduced our borrowing base to $185.0 million effective on June 1, 2021 and $175.0 million effective on September 1, 2021, and we agreed to some other modifications of the terms and covenants contained in our Senior Credit Agreement at the request of our lenders in the Fourth Amendment, as discussed in greater detail above.

While we anticipate that we will be able to operate our business and maintain adequate liquidity within the limitations imposed by our Senior Credit Agreement, as amended, the loss of additional liquidity may prevent us from accelerating our drilling plans in an effort to manage our liquidity more closely.

Additionally, reduced access to bank borrowings limits our flexibility in responding to unforeseen adverse events as well as our ability to pursue opportunities that might prove beneficial in the future.

As noted elsewhere herein and our other filings with the Securities and Exchange Commission, many factors, including many that are beyond our control, affect our business and operations and may adversely impact our cash flows, liquidity and our ability to comply with the covenants under our Senior Credit Agreement.

Consequently, there is no assurance that our expectations with regard to our capital needs or compliance with the covenants in the Senior Credit Agreement will prove accurate.

In the event we are unable to maintain compliance, the lenders under our Senior Credit Agreement may be unwilling to provide us with the covenant relief we need.

In the event we are not successful in obtaining covenant modifications, if needed, there is no assurance that we will be successful in securing alternative means of financing our business upon favorable terms or at all.

If we are able to secure alternative financing, it may be more costly, provide less liquidity, or impose more restrictive covenants than our Senior Credit Agreement.

When commodity prices decline significantly, as they did in 2020, our ability to finance our capital budget and operations may be adversely impacted.

We employ derivative instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices, however, the total volumes we typically hedge are less than our expected production, vary from period to period based on our view of current and future market conditions and generally extend up to only approximately 30 months.

These limitations result in our liquidity being susceptible to commodity price declines in the near term and, in particular, if such prices decline for a sustained period of time.

Our Senior Credit Agreement contains minimum hedging requirements.

Pursuant to the Third Amendment, we are required to hedge at least 65% of anticipated production from proved developed producing reserves

through December 31, 2022.

Pursuant to the Third Amendment, we are required to hedge at least 65% of anticipated production from proved developed producing reserves through December 31, 2022.

Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change.

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Our future capital resources and liquidity depend on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves.

Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry.

Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas

We strive to maintain financial flexibility while pursuing our drilling plans and may access capital markets, pursue joint ventures, sell assets and engage in other transactions as necessary to, among other things, maintain borrowing capacity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage.

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Even if we are otherwise successful in growing our proved reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.

During the nine months ended September 30, 2020 (Successor), operating cash flows supplemented with borrowings under our revolving credit agreement were used to fund our drilling and completion programs.

During the three months ended March 31, 2021, operating cash flows and proceeds from divested properties funded our capital expenditures program and net repayments of borrowings under our Senior Credit Agreement.

See “ Results of Operations ” for a review of the impact of prices and volumes on operating revenues.

Net increase (decrease) in cash, cash equivalents and restricted cash is summarized as follows (in thousands):

September 30, 2020

September 30, 2019

Net increase (decrease) in cash and cash equivalents is summarized as follows (in thousands):

Three Months Ended

Cash flows provided by (used in) operating activities

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Cash flows provided by (used in) financing activities

Net increase (decrease) in cash, cash equivalents and restricted cash

Net increase (decrease) in cash and cash equivalents

Operating Activities.

Net cash flows provided by operating activities for the nine months ended September 30, 2020 (Successor) and net cash flows used in operating activities for the nine months ended September 30, 2019 (Predecessor) were $47.9 million and $33.2 million, respectively.

Operating cash flows for the nine months ended September 30, 2020 (Successor) increased from the comparable prior year period due to decreases in our operating expenses associated with our focus on efficiencies and cost savings and a decrease in interest expense associated with lower outstanding debt due to our chapter 11 bankruptcy.

In addition, realized gains from derivative contracts were higher in the nine months ended September 30, 2020, which included the early termination of certain derivative contracts.

During the nine months ended September 30, 2020 (Successor), we terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $22.9 million during the period.

These increases to operating cash flows in 2020 were partially offset by decreased oil and natural gas revenues as a result of lower realized commodity prices and lower production volumes than the comparable prior year period.

Operating cash flows for the nine months ended September 30, 2019 (Predecessor) decreased from the comparable prior year period due to increases in our operating expenses, primarily severances paid to executives, reorganization costs, and third party water hauling and disposal costs.

Net cash flows provided by operating activities for the three months ended March 31, 2021 and 2020 were $13.4 million and $12.3 million, respectively.

Operating cash flows for the three months ended March 31, 2021 increased slightly between the first three months of 2021 and 2020.

Our average realized price increase of approximately $15.34 per Boe contributed to higher total operating revenues in 2021 which were partially offset by payments on derivative settlements in 2021.

Operating cash flows for the three months ended March 31, 2020 increased from the comparable prior year due to decreases in our operating expenses associated with our focus on efficiencies and cost savings and a decrease in interest expense associated with lower outstanding debt due to our chapter 11 bankruptcy.

These decreases in expenditures were partially offset by decreased oil and natural gas revenues as a result of lower realized commodity prices.

Investing Activities.

Net cash flows used in investing activities for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor) were approximately $92.5 million and $254.4 million, respectively.

During the nine months ended September 30, 2020 (Successor), we spent $96.5 million on oil and natural gas capital expenditures, of which $62.9 million related to drilling and completion costs and $32.1 million related to the development of our treating equipment and gathering support infrastructure.

Net cash flows used in investing activities for the three months ended March 31, 2021 and 2020 were approximately $12.7 million and $47.6 million, respectively.

During the three months ended March 31, 2021, we spent $13.8 million on oil and natural gas capital expenditures, of which $10.8 million related to drilling and completion costs and $2.2 million related to the development of our treating equipment and gathering support infrastructure.

We received $1.1 million in proceeds from the sale of oil and natural gas properties.

During the three months ended March 31, 2020, we spent $48.2 million on oil and natural gas capital expenditures, of which $26.0 million related to drilling and completion costs and $21.8 million related to the development of our treating equipment and our gathering support infrastructure.

In addition, we received $0.5 million in insurance proceeds associated with a casualty loss on our support infrastructure.

During the nine months ended September 30, 2019 (Predecessor), we spent $167.2 million on oil and natural gas capital expenditures, of which $158.6 million related to drilling and completion costs.

We also spent approximately $85.6 million on capital expenditures related to the development of our natural gas treating equipment and our gathering support infrastructure.

Financing Activities.

Net cash flows provided by financing activities for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor) were $36.2 million and $257.8 million, respectively.

During the nine months ended September 30, 2020 (Successor), net borrowings of $34.0 million under our Senior Credit Agreement were used to fund our drilling and completions program and the development of our treating equipment and gathering support facilities.

We also borrowed $2.2 million under the PPP Loan to fund payroll costs, rent and utilities.

During the nine months ended September 30, 2019 (Predecessor), net borrowings of $35.0 million under our debtor-in-possession junior secured term credit facility (DIP Facility) and $223.2 million under our Predecessor Credit Agreement were used to fund our drilling and completions program, as well as the development of our treating infrastructure and our gathering support infrastructure.

Net cash flows used in financing activities for the three months ended March 31, 2021 was $3.3 million.

Net cash flow provided by financing activities for the three months ended March 31, 2020 was $26.0 million.

During the three months ended March 31, 2021, we used cash flows from operations to make net repayments of $3.0 million on our Senior Credit Agreement.

During the three months ended March 31, 2020, net borrowings of $26.0 million under our Senior Credit Agreement were used to fund our drilling and completions program and the development of our treating equipment and gathering support facilities.

Senior Revolving Credit Facility

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The maturity date of the Senior Credit Agreement is October 8, 2024.

Redeterminations will occur semi-annually on May 1 and November 1, with the lenders and us each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations.

Redeterminations of the borrowing base occur semi-annually on May 1 and November 1, with the lenders and us each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations.

The borrowing base takes into account the estimated value of our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.

1 unchanged sentence

These margins fluctuate based on our utilization of the facility.

We may elect, at our option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty, except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement.

We may be required to make mandatory prepayments of the outstanding borrowings under the Senior Credit Agreement in connection with certain borrowing base deficiencies, including deficiencies which may arise in connection with a borrowing base redetermination, an asset disposition or swap terminations attributable in the aggregate to more than ten percent (10%) of the then-effective borrowing base.

We may elect, at our option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty, except with respect to any break funding payments that may be payable pursuant to the terms of the Senior Credit Agreement.

Amounts outstanding under the Senior Credit Agreement are guaranteed by our direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of us and our subsidiaries.

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The Senior Credit Agreement also contains certain financial covenants, including maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00:1.00.

On October 29, 2020 (Successor),we entered into the Third Amendment.

On October 29, 2020, we entered into the Third Amendment.

The Third Amendment, among other things, set the borrowing base to $190.0 million as of November 1, 2020.

The Third Amendment also reduced the amount available for the issuance of letters of credit to $25.0 million and amended certain covenants including, but not limited to, covenants relating to increasing the minimum mortgaged total value of proved borrowing base properties from 85% to 90%.

Additionally, the Third Amendment provided for new covenants that, among other things, require us to enter into swap agreements representing not less than 65% of our reasonably anticipated projected production from proved reserves classified as developed producing reserves for a period from the Third Amendment effective date through at least December 31, 2022 and prohibit no more than $3.0 million of our uncontested accounts payable or accrued expenses, liabilities or other obligations from remaining outstanding for longer than 90 days.

Pursuant to the Third Amendment, the administrative agent and the lenders consented to a waiver of the Current Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ended September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

On July 31, 2020 (Successor), we entered into the Waiver which waived maintenance of the Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 for the fiscal quarter ended June 30, 2020.

The Second Amendment also added provisions related to a loan incurred by us under the Paycheck Protection Program of the CARES Act.

We used, and the Second Amendment required us to use, the loan proceeds for CARES Forgivable Uses under the CARES Act.

On November 21, 2019 (Successor), we entered into the First Amendment to the Senior Credit Agreement which, among other things, (i) reduced the borrowing base to $240.0 million and (ii) limited the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) as of the last day of each fiscal quarter, commencing with the fiscal quarter ending March 31, 2020, of not greater than 3.50 to 1.00.

As of September 30, 2020 (Successor), after giving effect to the Third Amendment, we were in compliance with the financial covenants under the Senior Credit Agreement.

On May 10, 2021, we entered into the Fourth Amendment which reduces the borrowing base to $185.0 million effective June 1, 2021 and further reduces the borrowing base to $175.0 million effective September 1, 2021.

As of March 31, 2021, after giving effect to the Third Amendment, we were in compliance with the financial covenants under the Senior Credit Agreement.

Paycheck Protection Program Loan

On April 16, 2020 (Successor), we entered into the PPP Loan for a principal amount of approximately $2.2 million from Bank of Montreal under the Paycheck Protection Program of the CARES Act, which is administered by the U.S.

Small Business Administration.

On April 16, 2020, we entered into a promissory note (the PPP Loan) for a principal amount of approximately $2.2 million from Bank of Montreal under the Paycheck Protection Program of the CARES Act, which is administered by the U.S.

Small Business Administration (SBA).

Pursuant to the terms of the CARES Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent or utility costs.

The PPP Loan bears interest at a rate of 1.0% per annum.

We are required to pay principal and interest installments of $0.1 million monthly beginning November 16, 2020.

The maturity date of the PPP Loan is April 16, 2022.

The PPP Loan bears interest at a rate of 1.0% per annum and, if not forgiven, has a maturity date of April 16, 2022.

As long as we make a timely application of forgiveness to the SBA, we are not required to make any payments under the PPP Loan until the forgiveness amount is communicated to us by the SBA.

We may elect, at our option, to prepay 20% or less of the borrowings outstanding under the PPP Loan without premium or penalty, and without notice.

Prepayments of more than 20% of the outstanding borrowings require written advanced notice and payment of accrued interest.

The PPP Loan contains certain events of default including non-

payment, breach of representations and warranties, cross-defaults to other loans with the lender or to material indebtedness, voluntary or involuntary bankruptcy, judgments and change in control.

Under the terms of the CARES Act, we can apply for and be granted forgiveness for all or a portion of the PPP Loan.

We believe we are eligible for, and are currently pursuing, forgiveness of the PPP Loan in accordance with the requirements and limitations under the CARES Act;

Such forgiveness will be determined, subject to limitations, based on the use of loan proceeds in accordance with the terms of the CARES Act during the covered period after loan origination and the maintenance or achievement of certain employee levels.

We believe we are eligible for, and intend to pursue, forgiveness of the PPP Loan in accordance with the requirements and limitations under the CARES Act;

however, no assurance can be provided that forgiveness of any portion of the PPP Loan will be obtained.

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Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses.

There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019 (Successor).

There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

Results of Operations

Three Months Ended September 30, 2020 (Successor) and 2019 (Predecessor)

We reported a net loss of $153.1 million and $63.3 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

The table included below sets forth financial information for the periods presented.

In thousands (except per unit and per Boe amounts)

September 30, 2020

September 30, 2019

Net income (loss)

Operating revenues:

Natural gas liquids

Operating expenses:

Lease operating

Workover and other

Taxes other than income

Gathering and other

Restructuring

General and administrative:

General and administrative

Stock-based compensation

Depletion, depreciation and accretion:

Depletion – Full cost

Depreciation – Other

Accretion expense

Full cost ceiling impairment

(Gain) loss on sale of Water Assets

Other income (expenses):

Net gain (loss) on derivative contracts

Interest expense and other

Reorganization items, net

Natural Gas - MMcf

Natural gas liquids – MBbls

Total MBoe (1)

Average daily production – Boe/d (1)

Average price per unit (2) :

Oil price - Bbl

Natural gas price - Mcf

Natural gas liquids price - Bbl

Total per Boe (1)

Average cost per Boe:

Lease operating

Workover and other

Taxes other than income

Gathering and other

Restructuring

General and administrative:

General and administrative

Stock-based compensation

(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil.

This ratio is based on energy equivalency, not price equivalency.

The price for a barrel of oil equivalent for natural gas is substantially lower than the price for a barrel of oil.

(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

Oil, natural gas and natural gas liquids revenues were $39.4 million and $50.6 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

For the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), production averaged 17,076 Boe/d and 16,489 Boe/d, respectively.

Average realized prices (excluding the effects of hedging arrangements) were $25.11 per Boe and $33.33 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Lease operating expenses were $10.1 million and $12.0 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

On a per unit basis, lease operating expenses were $6.42 per Boe and $7.88 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

The decrease in lease operating expenses in 2020 results from our focus on optimization of production operations and decreased salt water disposal costs due to lower production volumes and less produced water.

Workover and other expenses were $0.9 million and $1.6 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

On a per unit basis, workover and other expenses were $0.58 per Boe and $1.03 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

The decreased costs in 2020 relate to recent strides in improving well and completion designs and fewer workovers performed.

Taxes other than income were $2.7 million and $3.0 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Most production taxes are based on realized prices at the wellhead.

As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease.

On a per unit basis, taxes other than income were $1.73 per Boe and $1.99 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Gathering and other expenses were $13.5 million and $10.1 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production, operating expenses of our gathering support infrastructure, gas treating fees, rig stacking charges and other.

Approximately $3.8 million and $2.5 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production.

Approximately $9.7 million and $7.3 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively, relate to operating expenses on our treating equipment and gathering support facilities.

Our overall production volumes were slightly higher in the current year period primarily from an increase in our produced natural gas in Monument Draw.

These natural gas volumes are processed through our hydrogen sulfide treating plant in the area, which led to higher operating expenses, such as chemical costs, associated with our treating equipment during the current year period.

Restructuring expense was approximately $3.2 million for the three months ended 2019 (Predecessor).

During the three months ended September 30, 2019 (Predecessor), senior executives resigned from their positions.

These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits.

Additionally, during the 2019 period, we made the decision to consolidate into one corporate office located in Houston, Texas.

The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions.

General and administrative expense was $3.5 million and $21.7 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

The decrease in general and administrative expense primarily results from a reduction in our payroll and employee-related benefits.

Payroll and employee-related benefits decreased due to a reduction in our workforce since the prior year period.

The decrease in general and administrative costs also results from other administrative cost reductions as part of our continued focus on efficiencies and cost savings.

On a per unit basis, general and administrative expenses were $2.22 per Boe and $14.31 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Stock-based compensation expense was $0.6 million and a credit of $2.3 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Stock-based compensation expense decreased in the current period due to a reduction in our workforce.

During the three months ended September 30, 2019 (Predecessor), senior executives resigned from their positions.

In accordance with the terms of these senior executives’ employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination.

For the three months ended September 30, 2019 (Predecessor), we recognized an incremental reduction to stock-based compensation expense of $1.1 million associated with these modifications.

Stock-based compensation expense also decreased in the prior year period due to a reduction in our workforce.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period.

Depletion expense was $15.3 million and $18.0 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

On a per unit basis, depletion expense was $9.76 per Boe and $11.89 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

The lower depletion rate in the Successor period is attributable to the change in our depletable base as a result of the adoption of fresh-start accounting and the full cost ceiling test impairment incurred in the three months ended June 30, 2020.

Under the full cost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling”, based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves.

Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense.

At September 30, 2020 (Successor), we recorded a full cost ceiling impairment of $128.3 million.

The ceiling test impairment was primarily driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, from $47.37 per barrel at June 30, 2020 (Successor) to $43.63 per barrel at September 30, 2020 (Successor).

The ceiling test impairment also reflects the transfer of $23.6 million of unevaluated property costs to the full cost pool due to our intent to focus available capital on Monument Draw.

At September 30, 2019 (Predecessor), we recorded a full cost ceiling impairment of $45.6 million.

The ceiling test impairment at September 30, 2019 (Predecessor) was driven by decreases in first-day-of-the-month average price for crude oil used in the ceiling test calculation since June 30, 2019 (Predecessor), when the first-day-of-the-month average price for crude oil was $61.45 per barrel.

Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

On December 20, 2018 (Predecessor), we sold our water infrastructure assets located in the Delaware Basin for a total adjusted purchase price of $210.9 million.

We recognized a cumulative $115.4 million gain on the sale which includes the $0.2 million increase in the three months ended September 30, 2019 (Predecessor) due to customary post-closing adjustments.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production.

Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statements of operations.

At September 30, 2020 (Successor), we had a $28.7 million derivative asset, $19.0 million of which was classified as current, and we had a $12.3 million derivative liability, $9.1 million of which was classified as current.

We recorded a net derivative loss of $15.8 million ($21.1 million net unrealized loss and $5.3 million net realized gain on settled and early terminated contracts) for the three months ended September 30, 2020 (Successor).

During this period, we terminated certain derivative contracts in advance of their natural expiration dates and received proceeds of approximately $6.6 million, which were included in the $5.3 million net realized gains for the period.

For the three months ended September 30, 2019 (Predecessor), we recorded a net derivative gain of $13.5 million ($11.6 million net unrealized gain and $1.9 million net realized gain on settled and early terminated contracts).

Interest expense and other was $1.7 million and $10.5 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Interest expense for the Successor period represents interest associated with borrowings under the Senior Credit Agreement and the PPP Loan.

Interest expense in the Predecessor period

represents interest associated with the Predecessor Credit Agreement and DIP Facility.

In addition to interest expense, during the three months ended September 30, 2019 (Predecessor), we paid fees associated with consents and amendments to our Predecessor Credit Agreement.

We recorded a net loss on reorganization items of $1.8 million for the three months ended September 30, 2019 (Predecessor) which includes the following:

September 30, 2019

Accrued interest

Write-off debt discount/premium and debt issuance costs

Reorganization professional fees and other

Gain (loss) on reorganization items

Nine Months Ended September 30, 2020 (Successor) and 2019 (Predecessor)

We reported a net loss of $166.0 million and $1.0 billion for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Three Months Ended March 31, 2021 and 2020

We reported a net loss of $33.4 million and net income of $114.5 million for the three months ended March 31, 2021 and 2020, respectively.

The table included below sets forth financial information for the periods presented.

Three Months Ended

In thousands (except per unit and per Boe amounts)

September 30, 2020

September 30, 2019

Net income (loss)

14 unchanged sentences

Accretion expense

Full cost ceiling impairment

(Gain) loss on sale of Water Assets

Other income (expenses):

1 unchanged sentence

Interest expense and other

Reorganization items, net

Income tax benefit (provision)

Natural Gas - MMcf

20 unchanged sentences

(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

Oil, natural gas and natural gas liquids revenues were $104.5 million and $158.4 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

For the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), production averaged 16,712 Boe/d and 17,209 Boe/d, respectively.

Our average daily oil, natural gas and natural gas liquids production decreased in the nine months ended September 30, 2020 (Successor) when compared to the same period in the prior year primarily due to our temporary shut-in of a portion of producing wells across all our operating areas during the months of May and June 2020.

Estimated downtime associated with these temporary shut-ins was approximately 1,800 Boe/d for the nine months ended September 30, 2020 (Successor).

The production decline caused by temporary shut-ins in the current year period was partially offset by new wells put online since the prior year period.

Average realized prices (excluding the effects of hedging arrangements) were $22.82 per Boe and $33.71 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Oil, natural gas and natural gas liquids revenues were $55.3 million and $47.0 million for the three months ended March 31, 2021 and 2020, respectively.

For the three months ended March 31 2021 and 2020, production averaged 14,333 Boe/d and 18,791 Boe/d, respectively.

Our average daily oil, natural gas and natural gas liquids production decreased in the first three months ended March 31, 2021 when compared to the same period in the prior year primarily due to production declines in our non-core areas, which were partially offset by increased production from our Monument Draw area, where new production came online as a result of our capital spending program.

Also contributing to decreased total production in the current year period is a temporary shut-in of production in February 2021 as a result of inclement weather.

The estimated production decrease associated with this temporary shut-in was approximately 1,300 Boe/d for the first three months of 2021.

In addition, in December 2020, we divested properties that produced approximately 800 Boe/d during the three months ended March 31, 2020.

Average realized prices (excluding the effects of hedging arrangements) were $42.84 per Boe and $27.50 per Boe for the three months ended March 31, 2021 and 2020, respectively.

Lease operating expenses were $32.9 million and $39.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

On a per unit basis, lease operating expenses were $7.18 per Boe and $8.43 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Workover and other expenses were $2.8 million and $5.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

On a per unit basis, workover and other expenses were $0.60 per Boe and $1.19 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

The decreased costs in 2020 relate to recent strides in improving well and completion designs and fewer workovers performed.

Taxes other than income were $7.1 million and $9.2 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Lease operating expenses were $9.5 million and $12.5 million for the three months ended March 31, 2021 and 2020, respectively.

The decrease in lease operating expenses in 2021 results from decreased salt water disposal costs due to lower production volumes and less produced water.

On a per unit basis, lease operating expenses were $7.34 per Boe and $7.30 per Boe for the three months ended March 31, 2021 and 2020, respectively.

Workover and other expenses were $0.6 million and $1.3 million for the three months ended March 31, 2021 and 2020, respectively.

On a per unit basis, workover and other expenses were $0.43 per Boe and $0.77 per Boe for the three months ended March 31, 2021 and 2020, respectively.

The decreased workover and other expenses in 2021 relate to preventive operational measures previously undertaken to mitigate potential future failures in producing wells, continued improvements in well and completion designs, and cost reductions for materials and services.

Taxes other than income were $3.2 million and $2.9 million for the three months ended March 31, 2021 and 2020, respectively.

Most production taxes are based on realized prices at the wellhead.

As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease.

On a per unit basis, taxes other than income were $1.56 per Boe and $1.96 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Gathering and other expenses were $39.3 million and $36.1 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Approximately $9.0 million and $9.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production.

Oil and natural gas production volumes were lower in the current period due to the temporary shut-in of a portion of producing wells during the months of May and June 2020.

Approximately $26.9 million and $24.8 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively, relate to operating expenses on our treating equipment and gathering support facilities.

In April 2019 (Predecessor), we installed a hydrogen sulfide treating plant that more efficiently removes hydrogen sulfide from our produced natural gas and reduces our reliance on expensive wellhead-level treating.

Until the treating plant was operational, we incurred $10.9 million of wellhead-level costs to remove hydrogen sulfide from natural gas produced from our Monument Draw properties during the nine months ended September 30, 2019 (Predecessor).

Our produced natural gas from the Monument Draw area increased in the current year period, despite a decrease in our overall production volumes.

Also included are $3.4 million and $0.8 million of rig stacking charges for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor).

Restructuring expense was approximately $2.6 million and $15.1 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

During the nine months ended September 30, 2020 (Successor), we incurred restructuring charges related to the consolidation into one corporate office and had reductions in our

workforce due to efforts to improve efficiencies and go forward costs.

In May 2020 (Successor), in furtherance of the consolidation into one corporate office, we exercised a one-time early termination option under the lease agreement for our office space in Denver, Colorado.

During the nine months ended September 30, 2019 (Predecessor), several senior executives resigned from their positions.

These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits.

Additionally, during the 2019 period, we made the decision to consolidate into one corporate office located in Houston, Texas.

The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions.

General and administrative expense was $11.4 million and $44.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

The decrease in general and administrative expense primarily results from a reduction in our payroll and employee-related benefits.

Payroll and employee-related benefits decreased due to a reduction in our workforce since the prior year period.

The decrease in general and administrative costs also results from other administrative cost reductions as part of our continued focus on efficiencies and cost savings.

On a per unit basis, general and administrative expenses were $2.50 per Boe and $9.49 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Stock-based compensation expense was $1.8 million and a credit of $8.0 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

During the nine months ended September 30, 2019 (Predecessor), several senior executives resigned from their positions.

In accordance with the terms of these senior executives’ employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon terminations.

For the nine months ended September 30, 2019 (Predecessor), we recognized an incremental reduction to stock-based compensation expense of $9.5 million associated with these modifications.

Stock-based compensation expense also decreased in the current period due to a reduction in our workforce.

On a per unit basis, taxes other than income were $2.47 per Boe and $1.70 per Boe for the three months ended March 31, 2021 and 2020, respectively.

Gathering and other expenses were $13.2 million and $10.5 million for the three months ended March 31, 2021 and 2020, respectively.

Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production and operating expenses of our gathering support infrastructure.

Approximately $4.0 million and $2.9 million for the three months ended March 31, 2021 and 2020, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production.

Gathering and marketing fees increased in 2021 as we marketed higher quantities of sour gas production to third parties in the current year period.

Approximately $9.2 million and $7.6 million for the three months ended March 31, 2021 and 2020, respectively, relate to operating expenses on our treating equipment and gathering support facilities.

The increase in treating equipment and gathering support facilities expenses in 2021 results from higher electricity and buy back fuel costs incurred as a result of inclement weather in February 2021 and higher chemical costs to improve the quality of treated oil, which were partially offset by lower operating expenses associated with our treating equipment, as fewer sour gas production volumes were processed through our hydrogen sulfide treating plant in the current year period.

Restructuring expense was approximately $0.4 million for the three months ended March 31, 2020.

During the three months ended March 31, 2020, we incurred restructuring charges related to the consolidation into one corporate office and had reductions in our workforce due to efforts to improve efficiencies and go forward costs.

General and administrative expense was $4.2 million and $3.5 million for the three months ended March 31, 2021 and 2020, respectively.

In late March 2020, due to changes in market conditions and decreased commodity prices, we determined that previously accrued discretionary cash incentives related to 2019 would not be paid, causing a $1.6 million reduction to general and administrative expense for the period.

On a per unit basis, general and administrative expenses were $3.28 per Boe and $2.03 per Boe for the three months ended March 31, 2021 and 2020, respectively.

Stock-based compensation expense was $0.6 million and $0.4 million for the three months ended March 31, 2021 and 2020, respectively.

Stock based compensation expense increased in the current period related to awards granted during the first three months of 2020.

Depletion expense was $46.9 million and $84.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

On a per unit basis, depletion expense was $10.25 per Boe and $18.00 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense.

At September 30, 2020 (Successor), we recorded a full cost ceiling impairment of $128.3 million.

The ceiling test impairment also reflects the transfer of $23.6 million of unevaluated property costs to the full cost pool due to our intent to focus available capital on Monument Draw.

At June 30, 2020 (Successor), we recorded a full cost ceiling impairment of $60.1 million.

The ceiling test impairment was primarily driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, from $55.96 per barrel at March 31, 2020 (Successor) to $47.37 per barrel at June 30, 2020 (Successor).

This average price decline was partially offset by favorable differentials and lower operating expenses.

We recorded a full cost ceiling test impairment charge of $985.2 million for the nine months ended September 30, 2019 (Predecessor).

The ceiling test impairment at September 30, 2019 (Predecessor) was driven by decreases in the first-day-of-the-month average price for crude oil used in the ceiling test calculation since June 30, 2019 (Predecessor), when the first-day-of-month average price for crude oil was $61.45 per barrel.

At June 30, 2019 (Predecessor), we recorded a full cost ceiling impairment of $664.4 million.

The ceiling test impairment at June 30, 2019 (Predecessor) was primarily driven by our continued focus on Monument Draw.

Accordingly, we transferred approximately $481.7 million of unevaluated property costs to the full cost pool as of June 30, 2019 (Predecessor), the majority of which was associated with our Hackberry Draw area.

At March 31, 2019 (Predecessor), we recorded a full cost ceiling impairment of $275.2 million.

The ceiling test impairment at March 31, 2019 (Predecessor) was driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling

test calculation and our intent to expend capital only on our most economic areas.

As such, we identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool during the three months ended March 31, 2019 (Predecessor).

On December 20, 2018 (Predecessor), we sold our water infrastructure assets located in the Delaware Basin for a total adjusted purchase price of $210.9 million.

We recognized a cumulative $115.9 million gain on the sale.

The gain was reduced during the nine months ended September 30, 2019 by approximately $3.6 million as a result of customary post-closing adjustments.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production.

Depletion expense was $10.3 million and $17.6 million for the three months ended March 31, 2021 and 2020, respectively.

On a per unit basis, depletion expense was $8.02 per Boe and $10.29 per Boe for the three months ended March 31, 2021 and 2020, respectively.

The lower depletion rate in the 2021 is attributable to the change in our depletable base as a result of full cost ceiling test impairments incurred in 2020.

We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production.

We recorded a net derivative gain of $67.7 million ($24.0 million net unrealized gain and $43.7 million net realized gain on settled and early terminated contracts) for the nine months ended September 30, 2020 (Successor).

For the nine months ended September 30, 2019 (Predecessor), we recorded a net derivative loss of $34.3 million ($45.8 million net unrealized loss and $11.5 million net realized gain on settled and early terminated contracts).

Interest expense and other was $4.9 million and $37.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Interest expense for the Successor period represents interest associated with borrowings under the Senior Credit Agreement and the PPP loan.

Interest expense in the Predecessor period represents interest associated with the Predecessor Credit Agreement, the DIP Facility and the 6.75% senior notes.

In addition to interest expense, during the nine months ended September 30, 2019 (Predecessor), we paid fees associated with consents and amendments to our Predecessor Credit Agreement.

We recorded a net loss on reorganization items of $1.8 million for the nine months ended September 30, 2019 (Predecessor) which includes the following:

September 30, 2019

Accrued interest

Write-off debt discount/premium and debt issuance costs

Reorganization professional fees and other

Gain (loss) on reorganization items

We recorded an income tax benefit of $95.8 million for the nine months ended September 30, 2019 (Predecessor), resulting from the reduction to the deferred tax liability generated by the impact of the ceiling test impairment on oil and gas properties and the deferred tax asset created by the tax loss from operations.

The 8.4% effective tax rate for the nine months ended September 30, 2019 (Predecessor) differs from the 21% statutory rate because of non-deductible executive compensation and non-deductible realized built in losses, and valuation allowances on deferred tax assets .

At March 31, 2021, we had a $1.5 million derivative asset, $0.7 million of which was classified as current, and we had a $51.4 million derivative liability, $42.4 million of which was classified as current.

We recorded a net derivative loss of $45.7 million ($36.0 million net unrealized loss and $9.7 million net realized loss on settled and early terminated contracts) for the three months ended March 31, 2021.

For the three months ended March 31, 2020, we recorded a net derivative gain of $118.3 million ($112.4 million net unrealized gain and $5.9 million net realized gain on settled and early terminated contracts).

Interest expense and other was $1.4 million and $1.6 million for the three months ended March 31, 2021 and 2020, respectively.

Interest expense decreased during the three months ended March 31, 2021 as compared to the prior year period due to lower interest rates incurred on outstanding borrowings under our Senior Credit Agreement.

Recently Issued Accounting Pronouncements

2 unchanged sentences

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What changed 10-Q

Item 2. Management’s Discussion and Analysis