What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2022-03-07 compared with 2021-03-08 · 218 added, 313 removed, 181 unchanged (75% of the section changed)

2 unchanged sentences

Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K contain additional information that should be referred to when reviewing this material.

Certain prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh- start accounting upon our emergence from chapter 11 bankruptcy on October 8, 2019.

References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to October 1, 2019, the convenience date applied for fresh-start accounting.

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.

Refer to Item 8.

Consolidated Financial Statements and Supplementary Data – Note 2, “ Reorganization ” and Note 3, “ Fresh-start Accounting ,” for further details.

Statements in this discussion may be forward-looking.

1 unchanged sentence

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 economics.

At December 31, 2020 (Successor), our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc.

At December 31, 2021, our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc.

(Netherland, Sewell), using Securities and Exchange Commission (SEC) prices for crude oil and natural gas, which are based on preceding 12-month first day of the month average prices of West Texas Intermediate (WTI) crude oil spot price of $66.55 per Bbl and Henry Hub natural gas spot price of $3.60 per MMBtu, were approximately 95.9 MMBoe, consisting of 58.7 MMBbls of oil, 16.3 MMBbls of natural gas liquids, and 125.0 Bcf of natural gas.

Approximately 57% of our proved reserves were classified as proved developed as of December 31, 2020 (Successor).

Approximately 44% of our proved reserves were classified as proved developed as of December 31, 2021.

We maintain operational control of 99.9% of our proved reserves.

Substantially all of our proved reserves and production at December 31, 2020 (Successor) are associated with our Delaware Basin properties.

Our total operating revenues for the year ended December 31, 2020 (Successor) were approximately $148.3 million.

Our total operating revenues for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) were approximately $65.6 million and $159.1 million, respectively, or $224.7 million combined.

Full year 2020 (Successor) production averaged 16,858 Boe/d.

During the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), production averaged 20,293 Boe/d and 17,209 Boe/d, respectively, or 17,986 Boe/d combined.

The decrease in total operating revenues and average daily production year over year was driven by our temporary shut-in of a portion of producing wells across all our operating areas in May and June 2020 (Successor) as a consequence of low oil prices as well as average realized prices that were lower by approximately $10.25 per Boe.

The estimated production decrease associated with these temporary shut-ins was approximately 1,300 Boe/d for 2020 (Successor).

In December 2020 (Successor), we divested properties that produced approximately 600 Boe/d during the nine months ended September 30, 2020 (Successor).

Substantially all of our proved reserves and production at December 31, 2021 are associated with our Delaware Basin properties.

Our total operating revenues for the year ended December 31, 2021 were approximately $285.2 million, compared to total operating revenues for the year ended December 31, 2020 of approximately $148.3 million.

The increase in revenues is primarily attributable to an approximate $24.14 per Boe increase in average realized prices (excluding the effects of hedging arrangements).

Full year 2021 production averaged 16,241 Boe/d compared to average daily production of 16,858 Boe/d for 2020.

Average daily oil and natural gas production was impacted by the temporary shut-in of production amounting to approximately 300 Boe/d and 1,300 Boe/d for the year ended December 31, 2021 and 2020, respectively.

In February 2021, we temporarily shut-in production due to inclement weather.

In May and June 2020, we temporarily shut-in production in response to historically low commodity prices.

Current year production was also impacted by third-party processing curtailments and downtime resulting from facility upgrades and repairs.

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.

Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production.

take-away capacity constraints, inventory storage levels, basis differentials and other factors.

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.

In 2020 (Successor), we spent approximately $101.8 million on oil and gas capital expenditures.

In early 2020, we ran one operated rig in the Delaware Basin, and in March 2020, as a result of changes in market conditions and commodity prices, we began to scale back our capital operations and spending and eventually released the rig.

In 2021, we spent approximately $52.6 million on oil and gas capital expenditures.

In early 2021 and at the end of 2021, we ran one operated rig in the Delaware Basin.

We drilled and cased 2.0 gross (2.0 net) operated wells, completed 6.0 gross (6.0 net) operated wells, and put online 6.0 gross (6.0 net) operated wells during the year.

We expect to spend approximately $130.0 million to $150.0 million on capital expenditures during 2022.

Overall, we currently plan to drill two gross operated wells during the year, complete six gross operated wells, and bring six gross operated wells on production.

Our 2021 capital budget currently contemplates running one operated rig in the Delaware Basin at the beginning of the year.

We continuously monitor changes in market conditions and adapt our operational plans as necessary in order to maintain financial flexibility, preserve core acreage and meet contractual obligations, and therefore our capital budget is subject to change.

We expect to fund our budgeted 2021 capital expenditures with cash and cash equivalents on hand, cash flows from operations and, if necessary, borrowings under our Senior Credit Agreement.

Overall, we currently plan to drill 12 gross operated wells during the year, complete 9 to 13 gross operated wells, and bring 8 to 12 gross operated wells on production.

Our 2022 capital budget currently contemplates running one operated rig in the Delaware Basin during the year.

We continuously monitor changes in market conditions and adapt our operational plans

as necessary in order to maintain financial flexibility, preserve core acreage and meet contractual obligations, and therefore our capital budget is subject to change.

We expect to fund our budgeted 2022 capital expenditures with cash and cash equivalents on hand from the funding of the Term Loan Agreement and cash flows from operations.

In the event our cash flows are materially less than anticipated or our costs are materially greater than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may be required to curtail drilling, development, land acquisitions and other activities to reduce our capital spending.

2 unchanged sentences

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 first-day-of-the-month average for the 12-months ended March 31, 2021 of the WTI crude oil spot price of $39.95 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended March 31, 2021 of the Henry Hub natural gas price of $2.16 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation would not have generated an additional impairment at December 31, 2020 (Successor), holding all other inputs and factors constant.

Using the first-day-of-the-month average for the 12-months ended March 31, 2022 of the WTI crude oil spot price of $75.28 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended March 31, 2022 of the Henry Hub natural gas price of $4.09 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation would not have generated an additional impairment at December 31, 2021, 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.

1 unchanged sentence

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 subsequently agreed 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 ongoing effects 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.

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.

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

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 current economic downturn on demand.

As a consequence, beginning March 2020, we realized lower revenue as a result of commodity price declines, resulting in us temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year.

Additionally in 2020, we incurred ceiling test impairments, 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.

During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand for oil and natural gas and increases in oil and natural gas prices.

Further, at present, OPEC and Russia have been coordinating production increases to maintain supply and demand balance, stabilize prices and avoid market disruptions.

However, there remains the potential for such cooperation to fail and for demand for oil and natural gas to be adversely impacted by the economic effects of the ongoing COVID-19 pandemic, including as a consequence of the circulation of more infectious “variants” of the disease, vaccine hesitancy, waning vaccine effectiveness or other factors.

As a consequence, we are unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by the same sorts of factors that negatively impacted prices during 2020.

Furthermore, the health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and critical functions remain concerns and 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 our operations, earnings and cash flows and could cause our results to not be comparable to those of the same period in previous years.

The results presented in this Form

10-K 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 Annual Report on Form 10-K.

Northern West Quito Assets Divestiture

On December 18, 2020 (Successor), we sold certain oil and gas properties and related assets located in Ward County, Texas (the North West Quito Assets) to Point Energy Partners Operating, LLC for a total sales price of $26.3 million in cash, subject to customary post-closing adjustments as provided in the Purchase and Sale Agreement.

The effective date of the transaction was October 1, 2020 (Successor).

Proceeds from the sale were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded.

We used the net proceeds from the sale to repay amounts outstanding under our Senior Credit Agreement and for general corporate purposes.

Estimated proved reserves associated with the North West Quito Assets were approximately 2 MMBoe, or approximately 3% of our year-end 2019 proved reserves.

The North West Quito Assets generated net production of approximately 600 Boe/d, or approximately 4% of our average daily production for the nine months ended September 30, 2020 (Successor).

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, set the borrowing base to $190.0 million as of November 1, 2020, which eliminated the final monthly reduction of $5.0 million required under the Second Amendment (discussed below).

The Third Amendment also reduced the amount available for 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 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 for 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.

Term Loan Credit Facility

On November 24, 2021, we and our wholly owned subsidiary, Halcón Holdings, LLC (Borrower), entered into an Amended and Restated Senior Secured Credit Agreement (Term Loan Agreement) with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders.

The Term Loan Agreement amends and restates in its entirety our Senior Credit Agreement as discussed below.

Pursuant to the Term Loan Agreement, the lenders have agreed to loan us (i) $200.0 million, which funded on November 24, 2021 and was partially used to refinance all amounts owed under the Senior Credit Agreement;

(ii) up to $20.0 million, available to be drawn up to 18 months from November 24, 2021, subject to the satisfaction of certain conditions;

and (iii) up to $15.0 million, which amount will be available to be drawn from the date certain wells included in the approved plan of development are deemed producing, subject to the satisfaction of certain conditions.

An additional $5.0 million is available for the issuance of letters of credit.

The maturity date of the Term Loan Agreement is November 24, 2025.

Until such maturity date, borrowings under the Term Loan Agreement shall bear interest at a rate per annum equal to LIBOR (or another applicable reference rate, as determined pursuant to the provisions of the Term Loan Agreement) plus an applicable margin of 7.00%.

Consolidated Financial Statements and Supplementary Data —Note 6, “Debt” for additional information on the Term Loan Agreement.

Senior Revolving Credit Facility

On November 24, 2021, our Senior Secured Revolving Credit Agreement (Senior Credit Agreement) was amended and restated in its entirety by the Term Loan Agreement.

Borrowings outstanding under the Senior Credit Agreement were repaid with proceeds from the Term Loan Agreement resulting in a charge of $0.1 million presented in “Gain (loss) on extinguishment of debt” in the consolidated statements of operations for the year ended December 31, 2021.

On September 24, 2021, we entered into the Fifth Amendment to Senior Secured Revolving Credit Agreement (the Fifth Amendment) which, among other things, modified the limits on swap agreements so as not to exceed, (i) from the period of the Fifth Amendment effective date through December 31, 2021, the percentage of the reasonably anticipated hydrocarbon production from proved developed producing reserves during such period hedged pursuant to secured swap agreements in place as of the Fifth Amendment effective date;

(ii) for the fiscal year ending December 31, 2022, the greater of (a) the proved developed producing reserves during such fiscal year hedged pursuant to secured swap agreements in place as of the Fifth Amendment effective date and (b) 85% of the proved developed producing reserves during such fiscal year;

and (iii) for the fiscal years ending December 31, 2023, December 31, 2024 and December 31, 2025, swap agreements not to exceed 85%, 70% and 60% of the proved developed producing reserves, respectively, during each fiscal year.

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

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.

Effective August 13, 2021, the principal amount of our promissory note (the PPP Loan) under the Paycheck Protection Program of the Coronavirus Aid, Relief and Economic Security Act (the CARES Act) was reduced from $2.2 million to $0.2 million 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 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.

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 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.

Acid Gas Injection Well Permits

During the year ended December 31, 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.

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.”

We applied for forgiveness of the amount due

on the PPP Loan based on the use of the loan proceeds on eligible expenses in accordance with the terms of the CARES Act.

We recorded a gain on the extinguishment of the forgiven portion of the PPP Loan and related accrued interest of $2.1 million.

The gain is presented in “Gain (loss) on extinguishment of debt” in the consolidated statements of operations for the year ended December 31, 2021.

Employee Retention Credit

The CARES Act included, among other things, provisions relating to refundable payroll tax credits (the Employee Retention Credit or ERC).

As provided for in the CARES Act and subsequent legislation which modified and extended the provisions included therein, the ERC allows for a refundable tax credit against certain employment taxes equal to 50% of the first $10,000 in qualified wages paid to each employee after March 12, 2020 and through December 31, 2020 and 70% of the first $10,000 in qualified wages paid to each employee, per calendar quarter, after December 31, 2020 through September 30, 2021.

During the year ended December 31, 2021, we determined that the qualifications for the Employee Retention Credit were met and filed the corresponding applications for the applicable 2020 and 2021 periods.

We recognized an approximate $0.7 million Employee Retention Credit during the year ended December 31, 2021, with approximately $0.5 million recorded to “General and administrative” and approximately $0.2 million recorded to “Lease operating” in the consolidated statements of operations.

Capital Resources and Liquidity

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

The 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 year ended December 31, 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.

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.

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 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.

As a consequence, beginning in March 2020, we realized lower revenue as a result of these commodity price declines, resulting in us temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year.

Further, at present, OPEC and Russia have been coordinating production increases to maintain supply and demand balance, stabilize prices and avoid market disruptions.

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 or adversely impacting our ability to comply with covenants in our Term Loan 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.

All of the foregoing may adversely affect our business, financial condition, results of operations, cash flows and, potentially, compliance with the covenants contained in our Term Loan Agreement.

We expect to spend approximately $130.0 million to $150.0 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs, during 2022.

These 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 our Senior Credit Agreement will mature on October 8, 2024.

At December 31, 2020 (Successor), we had $158.0 million of indebtedness outstanding and approximately $4.7 million letters of credit outstanding under our Senior Credit Agreement, resulting in $27.3 million of borrowing capacity under the current borrowing base.

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 matters relating to the Senior Credit Agreement and we explore 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.

Bank of Montreal, who recently announced its plans to exit the United States oil and gas investment banking business, currently holds substantially all of the commitments under our Senior Credit Agreement.

Bank of Montreal’s decision to exit its US investment banking business could lead to similar decisions with regard to its participation in oil and gas lending in the United States, resulting in the sale of our Senior Credit Agreement to another financial institution, hedge fund, or other third party and could also lead us to seek alternative forms of financing, the terms of which may be more costly, provide less liquidity, or impose more restrictive covenants.

While we believe that alternatives to maintain liquidity under, 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.

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.

Depressions in oil and natural gas prices during 2020 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.

In conjunction with the fall 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 suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

As of December 31, 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.

Additionally, from time to time, we enter into commitments that may require us to incur material expenditures in the future.

Included in our 2022 capital expenditures budget is $2.6 million associated with an active drilling rig commitment.

We have a minimum volume commitment with

a third party for the treating of sour gas production through June 30, 2022.

The future payments associated with the minimum volume commitment are approximately $4.8 million.

These capital spending requirements and commitments are expected to be funded with cash and cash equivalents on hand from the funding of our Term Loan Agreement and cash flows from operations.

Amounts borrowed under our Term Loan Agreement bear interest at LIBOR plus an applicable margin of 7.00% and will mature on November 24, 2025.

At December 31, 2021, we had $46.9 million of cash and cash equivalents, $200.0 million of indebtedness outstanding, approximately $0.3 million letters of credit outstanding and $35.0 million in delayed draw term loans available to be drawn under our Term Loan Agreement, subject to the satisfaction of certain conditions defined in the agreement.

We are required to make scheduled amortization payments in the aggregate amount of $120.0 million from the fiscal quarter ending March 31, 2023 through the fiscal quarter ending September 30, 2025.

In addition, we may be required to make mandatory prepayments of the loans under the Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, and with excess cash on hand in excess of certain maximum levels.

For each fiscal quarter after January 1, 2023, we shall make mandatory prepayments when the Consolidated Cash Balance, as defined in the Term Loan Agreement, exceeds $20.0 million.

Until December 31, 2024, the forecasted APOD capital expenditures for the succeeding fiscal quarter are excluded for purposes of determining the Consolidated Cash Balance.

The Term Loan Agreement contains certain financial covenants, including maintenance of (i) an Asset Coverage Ratio (as defined in the Term Loan Agreement) of not less than (A) 1.50 to 1.00 as of December 31, 2021 and March 31, 2022, (B) 1.60 to 1.00 as of June 30, 2022, (C) 1.70 to 1.00 as of September 30, 2022, and (D) 1.80 to 1.00 as of December 31, 2022 and each fiscal quarter thereafter, (ii) a Total Net Leverage Ratio (as defined in the Term Loan Agreement) of not greater than (A) 3.25 to 1.00 as of December 31, 2021 through and including June 30, 2022, (B) 3.00 to 1.00 as of September 30, 2022 and December 31, 2022, (C) 2.75 to 1.00 as of March 31, 2023, and (D) 2.50 to 1.00 as of each fiscal quarter thereafter, and (iii) a Current Ratio (as defined in the Term Loan Agreement) of not less than 1.00:1.00, each determined as of the last day of any fiscal quarter period.

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

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 the financial covenants for a particular period of time.

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, on 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 under the Senior Credit Agreement, 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.

On October 29, 2020, in the Third Amendment to the Senior Credit Agreement, 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 ended December 31, 2021.

The Senior Credit Agreement was amended and restated by the Term Loan Agreement in November 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.

1 unchanged sentence

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, 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.

As discussed above, the primary lender under the Senior Credit Agreement has scaled back certain of its activities in the United States, and it is unknown to what extent, if any, its oil and gas lending activities in the United States may be impacted by that decision or whether that, or other factors, may impact our ability to obtain covenant modifications in the future, if necessary.

In the event we are not successful in obtaining covenant modifications, if needed, 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.

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

Even if successful, alternative sources of financing could prove more expensive than borrowings under our Term Loan Agreement.

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

While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge are less than our expected production, vary from period to period based on our view of current and future market conditions, remain consistent with the requirements in effect under our Term Loan Agreement and extend, on a rolling basis, for the next four years.

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.

Our Senior Credit Agreement contains minimum hedging requirements.

Pursuant to the Third Amendment, we are required to utilize fixed price swaps 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.

2 unchanged sentences

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.

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.

Our ability to complete such transactions and maintain or increase our borrowing base is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our indebtedness, as well as various economic and market conditions that have historically affected the oil and natural gas industry.

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 sufficient liquidity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage.

Our ability to complete such transactions and maintain or increase our liquidity is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our indebtedness, as well as various economic and market conditions that have historically affected the oil and natural gas industry.

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.

In 2020 (Successor), cash generated by operating activities, borrowings under our Senior Credit Agreement and proceeds from the North West Quito Assets divestiture were used to fund our drilling and completion program.

In 2021, operating cash flows and net borrowings under our credit agreements funded our capital expenditures program.

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):

October 2, 2019

January 1, 2019

December 31, 2020

December 31, 2019

October 1, 2019

December 31, 2018

Years Ended December 31,

Cash flows provided by (used in) operating activities

3 unchanged sentences

Operating Activities.

Net cash flows provided by operating activities for the year ended December 31, 2020 (Successor) was $50.2 million.

Net cash flows provided by operating activities for the period of October 2, 2019 through December 31, 2019 (Successor) were $13.7 million and net cash flows used in operating activities for the period of January 1, 2019 through October 1, 2019 (Predecessor) were $39.7 million.

Net cash flows provided by operating activities was $67.2 million for the year ended December 31, 2018 (Predecessor).

Operating cash flows for the year ended December 31, 2020 (Successor) increased from the 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.

In addition, realized gains from derivative contracts were higher in the year ended December 31, 2020 (Successor), which included the early termination of certain derivative contracts.

During the year ended December 31, 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.

Net cash flows provided by operating activities for the year ended December 31, 2021 and 2020 were $68.6 million and $50.2 million, respectively.

Operating cash flows for the year ended December 31, 2021 increased from the prior year due an approximate $24.14 per Boe average realized price increase which contributed to higher total operating revenues in 2021 partially offset by realized losses from derivative contracts incurred in 2021 as a result of increased commodity prices.

Operating cash flows for the year ended December 31, 2020 increased from the 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.

In addition, realized gains from derivative contracts were higher in the year ended December 31, 2020, which included the early termination of certain derivative contracts.

During the year ended December 31, 2020, 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.

For the period of October 2, 2019 through December 31, 2019 (Successor), operating cash flows increased due to higher oil and natural gas revenues resulting from increased average daily production, as well as decreases in our operating expenses.

For the period of January 1, 2019 through October 1, 2019 (Predecessor), operating cash flows decreased from the prior year due to increases in our operating expenses, primarily from third party water hauling and disposal costs, reorganization costs and severances paid to executives.

Operating cash flows for the year ended December 31, 2018 (Predecessor) decreased from prior year primarily due to our divestitures in 2017, in which we divested non-core producing properties in other areas for primarily undeveloped acreage in the Delaware Basin.

This decrease was partially offset by $35.2 million of proceeds related to hedge monetizations that occurred during the year.

Investing Activities.

Net cash flows used in investing activities for the year ended December 31, 2020 (Successor) were approximately $72.4 million.

Net cash flows used in investing activities for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) were approximately $42.8 million and $254.4 million, respectively.

Net cash flows used in investing activities for the year ended December 31, 2018 (Predecessor) were approximately $706.5 million.

During the year ended December 31, 2020 (Successor) we spent $101.8 million on oil and natural gas capital expenditures, of which $65.1 million related to drilling and completion costs and $33.9 million related to the development of our treating equipment and gathering support infrastructure.

We received $29.0 million in proceeds from

the sale of oil and natural gas properties, primarily from the North West Quito Assets in December 2020.

Net cash flows used in investing activities for the year ended December 31, 2021 and 2020 were approximately $51.9 million and $72.4 million, respectively.

During the year ended December 31, 2021, we spent $52.6 million on oil and natural gas capital expenditures, of which $42.9 million related to drilling and completion costs and $6.8 million related to the development of our treating equipment and gathering support infrastructure.

We received $0.9 million in proceeds from the sale of oil and natural gas properties.

During the year ended December 31, 2020, we spent $101.8 million on oil and natural gas capital expenditures, of which $65.1 million related to drilling and completion costs and $33.9 million related to the development of our treating equipment and gathering support infrastructure.

We received $29.0 million in proceeds from the sale of oil and natural gas properties, primarily from the sale of the northern assets in our West Quito area in December 2020.

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

During the period of October 2, 2019 through December 31, 2019 (Successor), we spent $43.2 million on oil and natural gas capital expenditures, of which $29.2 million related to drilling and completion costs and $13.2 million related to the development of our treating equipment and our gathering support infrastructure.

During the period of January 1, 2019 through October 1, 2019 (Predecessor), we spent $167.2 million on oil and natural gas expenditures, of which $158.6 million related to drilling and completion costs.

During the period of January 1, 2019 through October 1, 2019 (Predecessor), we spent approximately $85.6 million on capital expenditures to develop our treating equipment and our gathering support infrastructure.

In 2018 (Predecessor), we incurred cash expenditures of $333.9 million on acquisition activities, the majority of which related to the acquisitions of acreage and related assets in the Delaware Basin located in Ward County, Texas (the West Quito Draw Properties) and in the northern tract of the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets).

Additionally, we spent $475.7 million on oil and natural gas capital expenditures, of which $444.4 million related to drilling and completion costs.

We also spent approximately $117.0 million on capital expenditures primarily to develop our water recycling facilities and gas gathering and treating infrastructure.

These cash outflows were offset by proceeds from the sale of our water infrastructure assets located in the Delaware Basin (the Water Assets) of $213.8 million.

Financing Activities.

Net cash flows provided by financing activities for the year ended December 31, 2020 (Successor) were approximately $16.2 million.

Net cash flows provided by financing activities for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) were $10.0 million and $276.7 million, respectively.

Net cash flows provided by financing activities for the year ended December 31, 2018 (Predecessor) were approximately $262.1 million.

During the year ended December 31, 2020 (Successor), net borrowings of $14.0 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.

Net cash flows provided by financing activities for the year ended December 31, 2021 and 2020 were approximately $27.4 million and $16.2 million, respectively.

During the year ended December 31, 2021, we borrowed $200.0 million under the Term Loan Agreement and paid in cash $14.2 million in debt issuance costs associated with the loan.

A portion of the funds received from the Term Loan Agreement were used to refinance all amounts owed under the Senior Credit Agreement.

During the year ended December 31, 2020, net borrowings of $14.0 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 period of October 2, 2019 through December 31, 2019 (Successor), net borrowings of $14.0 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.

During the period of January 1, 2019 through October 1, 2019 (Predecessor), we received proceeds of $150.2 million from a rights offering to our unsecured senior noteholders and $5.8 million from a rights offering to our previous common stockholders, both related to our chapter 11 bankruptcy.

In addition, we borrowed $130.0 million under our Senior Credit Agreement.

The proceeds from our offerings and borrowings under our Senior Credit Agreement were used to refinance our DIP facility and the Predecessor credit agreement.

Borrowings under our DIP facility and under our Predecessor credit agreement were used to fund our drilling and completions program, as well as the development of our treating equipment and our gathering infrastructure.

In 2018 (Predecessor), we issued an additional $200.0 million aggregate principal amount of our 6.75% senior notes due 2025.

Proceeds from the private placement were approximately $202.4 million after initial purchasers’ premiums and deducting commissions and offering expenses.

Additionally, we sold 9.2 million shares of common stock in a public offering at a price of $6.90 per share.

The net proceeds from the offering were approximately $60.4 million after deducting underwriters’ discounts and offering expenses.

Senior Revolving Credit Facility

On October 8, 2019, we entered into the Senior Credit Agreement with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders.

The Senior Credit Agreement, as amended, provides for a $750.0 million senior secured reserve-based revolving credit facility with a current borrowing base of $190.0 million.

A portion of the Senior Credit Agreement, in the amount of $25.0 million, is available for the issuance of letters of credit.

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.

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.

Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.50% to 2.50% for ABR-based loans or at specified margins over LIBOR of 2.50% to 3.50% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Senior Credit Agreement.

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.

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.

The Senior Credit Agreement contains certain events of default, including non-payment;

breaches of representation and warranties;

non-compliance with covenants;

cross-defaults to material indebtedness;

voluntary or involuntary bankruptcy;

judgments and change in control.

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 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.

On April 30, 2020 (Successor), we entered into the Second Amendment which, among other things, (i) reduced the borrowing base to $200.0 million effective from April 30, 2020, which was then to be 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 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.

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, to not greater than 3.50 to 1.00.

As of December 31, 2020 (Successor), after giving effect to the Third Amendment, we were in compliance with the financial covenants under the Senior Credit Agreement.

Term Loan Credit Facility

On November 24, 2021, we and our wholly owned subsidiary, Halcón Holdings, LLC (Borrower) entered into the Term Loan Agreement with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders.

The Term Loan Agreement amends and restates in its entirety our Senior Credit Agreement as discussed below.

(ii) up to $20.0 million, available to be drawn up to 18 months from November 24, 2021, subject to the satisfaction of certain conditions;

and (iii) up to $15.0 million, which amount will be available to be drawn from the date certain wells included in the approved plan of development (APOD) are deemed producing APOD wells until up to 18 months after November 24, 2021, subject to the satisfaction of certain conditions.

An additional $5.0 million is available for the issuance of letters of credit.

The maturity date of the Term Loan Agreement is November 24, 2025.

We may be required to make mandatory prepayments of the loans under the Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, and with excess cash on hand in excess of certain maximum levels.

For each fiscal quarter after January 1, 2023, we shall make mandatory prepayments when the Consolidated Cash Balance, as defined in the Term Loan Agreement, exceeds $20.0 million.

Until December 31, 2024, the forecasted APOD capital expenditures for the succeeding fiscal quarter are excluded for purposes of determining the Consolidated Cash Balance.

We are required to make scheduled amortization payments in the aggregate amount of $120.0 million from the fiscal quarter ending March 31, 2023 through the fiscal quarter ending September 30, 2025.

Amounts outstanding under the Term Loan Agreement are guaranteed by certain of the Borrower’s direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Borrower and such direct and indirect subsidiaries, and of the equity interests of the Borrower held by us.

As part of the Term Loan Agreement there are certain restrictions on the transfer of assets, including cash, to Battalion from the guarantor subsidiaries.

The Term Loan Agreement also contains certain financial covenants, including the maintenance of (i) an Asset Coverage Ratio (as defined in the Term Loan Agreement) of not less than (A) 1.50 to 1.00 as of December 31, 2021 and March 31, 2022, (B) 1.60 to 1.00 as of June 30, 2022, (C) 1.70 to 1.00 as of September 30, 2022, and (D) 1.80 to 1.00 as of December 31, 2022 and each fiscal quarter thereafter, (ii) a Total Net Leverage Ratio (as defined in the Term Loan Agreement) of not greater than (A) 3.25 to 1.00 as of December 31, 2021 through and including June 30, 2022, (B) 3.00 to 1.00 as of September 30, 2022 and December 31, 2022, (C) 2.75 to 1.00 as of March 31, 2023, and (D) 2.50 to 1.00 as of each fiscal quarter thereafter, and (iii) a Current Ratio (as defined in the Term Loan Agreement) of not less than 1.00 to 1.00, each determined as of the last day of any fiscal quarter period.

As of December 31, 2021, we were in compliance with the financial covenants under the Term Loan Agreement.

The Term Loan Agreement also contains an APOD for our Monument Draw acreage through the drilling and completion of certain wells.

The Term Loan Agreement contains a proved developed producing production test and an APOD economic test which we must maintain compliance with otherwise, subject to any available remedies or waivers, we are required to immediately cease making expenditures in respect of the approved plan of development other than any expenditures deemed necessary by us in respect of no more than six additional approved plan of development wells.

The Term Loan Agreement also contains certain events of default, including non-payment;

breaches of representations and warranties;

non-compliance with covenants or other agreements;

cross-default to material indebtedness;

change of control;

and voluntary and involuntary bankruptcy.

Consolidated Financial Statements and Supplementary Data– Note 6, “Debt” for additional information on the Term Loan 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 SBA.

On April 16, 2020, 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 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 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 bears interest at a rate of 1.0% per annum and has a maturity date of April 16, 2022.

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

We applied for forgiveness of the amount due on the PPP Loan based on the use of the loan proceeds on eligible expenses in accordance with the terms of the CARES Act.

Effective August 13, 2021, the principal amount of our PPP Loan was reduced to $0.2 million by the SBA and we recorded a gain on the extinguishment of the forgiven portion of the PPP Loan and related accrued interest of $2.1 million.

The gain is presented in “Gain (loss) on extinguishment of debt” in the consolidated statements of operations for the year ended December 31, 2021.

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 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.

Off-Balance Sheet Arrangements

At December 31, 2020 (Successor), we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Estimates

7 unchanged sentences

Consolidated Financial Statements and Supplementary Data —Note 1, “ Summary of Significant Events and Accounting Policies,” for a discussion of additional accounting policies and estimates made by management.

Fresh-start Accounting

Upon our emergence from chapter 11 bankruptcy, on October 8, 2019, we adopted fresh-start accounting in accordance with the provisions set forth in ASC 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances.

Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date.

We elected to adopt fresh-start accounting effective October 1, 2019, to coincide with the timing of our normal fourth quarter reporting period, which resulted in us becoming a new entity for financial reporting purposes.

We evaluated and concluded that events between October 1, 2019 and October 8, 2019 were immaterial and use of an accounting convenience date of October 1, 2019 was appropriate.

As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2019 (Successor) and related fresh-start adjustments are included in the accompanying consolidated statement of operations for the period from January 1, 2019 through October 1, 2019 (Predecessor).

Fresh-start accounting requires an entity to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy.

The new entity is referred to as “Successor” or “Successor Company.” However, we will continue to present financial information for any periods before adoption of fresh-start accounting for the Predecessor Company.

The Predecessor and Successor companies may lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (ASC 205).

ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed.

Therefore, “black-line” financial statements are presented to distinguish between the Predecessor and Successor Companies.

Refer to Item 8.

Consolidated Financial Statements and Supplementary Data—Note 3, “Fresh-Start Accounting,” for further details.

Oil and Natural Gas Activities

17 unchanged sentences

The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir.

The accuracy of a reserve estimate is a function of (i) the quality and quantity of available data;

The accuracy of a reserve estimate is a function of (i) the quality and quantity of

available data;

(ii) the interpretation of that data;

3 unchanged sentences

Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Our estimated proved reserves for the years ended December 31, 2020 (Successor), 2019 (Successor) and 2018 (Predecessor) were prepared by Netherland, Sewell, an independent oil and natural gas reservoir engineering consulting firm.

Our estimated proved reserves for the years ended December 31, 2021, 2020 and 2019 were prepared by Netherland, Sewell, an independent oil and natural gas reservoir engineering consulting firm.

For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8.

4 unchanged sentences

Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves.

At December 31, 2020 (Successor), a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.40 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.44 per Boe.

At December 31, 2021, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.37 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.40 per Boe.

Full Cost Ceiling Test Limitation

6 unchanged sentences

If average oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of our oil and natural gas properties could occur in the future.

If the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ended December 31, 2020 (Successor) had been 10% lower while all other factors remained constant, our ceiling amount related to our net book value of oil and natural gas properties would have been reduced by approximately $93.0 million and would have increased our full cost ceiling impairment by the same amount.

If the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ended December 31, 2021 had been 10% lower while all other factors remained constant, our ceiling amount related to our net book value of oil and natural gas properties would have been reduced by approximately $182.9 million and would not have generated a full cost ceiling impairment.

Future Development Costs

4 unchanged sentences

We review our assumptions and estimates of future development and future abandonment costs on an annual basis.

At December 31, 2020 (Successor), a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.23 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.24 per Boe.

At December 31, 2021, a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.27 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.27 per Boe.

Accounting for Derivative Instruments and Hedging Activities

1 unchanged sentence

ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value.

From time to time, in accordance with our policy, we may hedge a portion of our forecasted oil, natural gas, and natural gas liquids production.

From time to time, in accordance with our policy, we may hedge a portion of our forecasted oil and natural gas production.

We elected to not designate any of our positions for hedge accounting.

7 unchanged sentences

We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required.

Based upon the evaluation of available evidence we recorded an increase of $10.8 million to our valuation allowance as a result of increases to deferred tax assets for deferred deductions and net operating losses offset by the write-off of deferred tax assets for oil and gas properties and other deferred tax assets during 2020 (Successor).

A valuation allowance of $489.5 million has been applied against our deferred tax assets as of December 31, 2020 (Successor).

Based upon the evaluation of available evidence we recorded a decrease of $57.8 million to our valuation allowance as a result of increases to deferred tax assets for deferred deductions and net operating losses offset by the write-off of deferred tax assets for oil and gas properties and other deferred tax assets during 2021.

A valuation allowance of $431.7 million has been applied against our deferred tax assets as of December 31, 2021.

We follow ASC 740, Income Taxes (ASC 740).

5 unchanged sentences

The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position.

In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the

appropriate taxing authority with full knowledge of all relevant information.

In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information.

The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements.

1 unchanged sentence

Comparison of Results of Operations

Year Ended December 31, 2020 (Successor) Compared to Year Ended December 31, 2019 (Successor)

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

We reported a net loss of $28.3 million and $229.7 million for the year ended December 31, 2021 and 2020, respectively.

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

The period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) are distinct reporting periods as a result of our adoption of fresh-start accounting upon our emergence from chapter 11 bankruptcy and are not comparable to prior periods.

Refer to the paragraphs following the table below for a discussion around our results of operations.

October 2, 2019

January 1, 2019

In thousands (except per unit and per Boe amounts)

December 31, 2020

December 31, 2019

October 1, 2019

Net income (loss)

15 unchanged sentences

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)

Gain (loss) on extinguishment of debt

Crude oil – MBbls

17 unchanged sentences

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.

(1) Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or NGLs based on approximate energy equivalency.

This is an energy content correlation and does not reflect the value or price relationship between the commodities.

(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 $146.8 million, $65.1 million and $158.4 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

For the year ended December 31, 2020 (Successor), production averaged 16,858 Boe/d.

Our average daily oil, natural gas and natural gas liquids production decreased year over year due primarily to the temporary shut-in of a portion of producing wells across all operating areas during the months of May and June 2020 (Successor).

Estimated production decreases associated with these temporary shut-ins was approximately 1,300 Boe/d for the year ended December 31, 2020 (Successor).

Average realized prices (excluding the effects of hedging arrangements) were $23.79 per Boe, $34.88 per Boe and $33.71 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

Oil, natural gas and natural gas liquids revenues were $284.2 million and $146.8 million for the year ended December 31, 2021 and 2020, respectively.

The increase in revenue is primarily attributable to an approximate $24.14 per Boe increase in our average realized prices (excluding the effects of hedging arrangements).

Lease operating expenses were $42.1 million, $12.8 million and $39.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

On a per unit basis, lease operating expenses were $6.82 per Boe, $6.86 per Boe and $8.43 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 $3.7 million, $1.7 million and $5.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

On a per unit basis, workover and other expenses were $0.60 per Boe, $0.89 per Boe and $1.19 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 $10.1 million, $3.7 million and $9.2 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

For the year ended December 31, 2021 and 2020, production averaged 16,241 Boe/d and 16,858 Boe/d, respectively.

Average daily oil and natural gas production was impacted by the temporary shut-in of production amounting to approximately 300 Boe/d and 1,300 Boe/d in 2021 and 2020, respectively.

In February 2021, we temporarily shut-in production due to inclement weather.

In May and June 2020, we temporarily shut-in production in response to historically low commodity prices.

Current year production was also impacted by third-party processing curtailments and downtime resulting from facility upgrades and repairs.

Lease operating expenses were $44.0 million and $42.1 million for the year ended December 31, 2021 and 2020, respectively.

On a per unit basis, lease operating expenses were $7.42 per Boe and $6.82 per Boe for the year ended December 31, 2021 and 2020, respectively.

The increase in lease operating expenses in 2021 results from a market increase associated with maintenance, power and chemical costs partially offset by decreased salt water disposal costs due to lower production volumes and less produced water.

Workover and other expenses were $3.2 million and $3.7 million for the year ended December 31, 2021 and 2020, respectively.

On a per unit basis, workover and other expenses were $0.54 per Boe and $0.60 per Boe for the year ended December 31, 2021 and 2020, respectively.

The decreased workover and other expenses in 2021 relate to preventative operational measures previously undertaken to mitigate potential future failures in producing wells.

Taxes other than income were $12.3 million and $10.1 million for the year ended December 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 $1.63 per Boe, $2.00 per Boe and $1.96 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

Gathering and other expenses were $56.0 million, $10.8 million and $36.1 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 oil and gas gathering infrastructure, gas treating fees, rig stacking charges and other.

Approximately $13.9 million, $2.7 million and $9.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 2020 due to the temporary shut-in of certain producing wells during the months of May and June 2020 (Successor).

Approximately $38.7 million, $8.1 million and $24.8 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 period of January 1, 2019 through October 1, 2019 (Predecessor).

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

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.

Also included are $3.4 million and $0.8 million of rig termination and stacking charges for the year ended December 31, 2020 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

Restructuring expense was approximately $2.6 million, $1.2 million and $15.1 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

During the year ended December 31, 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 reduce future 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 2019 (for both the Successor and Predecessor periods), 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, in 2019 (Predecessor), when the decision was made to consolidate into one corporate office, we began to incur restructuring charges which included both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions.

General and administrative expense was $15.9 million, $5.1 million and $44.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

The decrease in general and administrative expense primarily results from a reduction in our payroll and employee-related benefits due to a reduction in our workforce since the prior year period and other administrative cost reductions as part of our continued focus on efficiencies and cost savings.

The decrease in general and administrative expenses is also attributed to prepetition costs incurred in 2019 associated with our chapter 11 bankruptcy that year.

On a per unit basis, general and administrative expense were $2.57 per Boe, $2.74 per Boe and $9.49 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

Stock-based compensation expense was $2.6 million and a credit of $8.0 million for the year ended December 31, 2020 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor).

During 2019 (for both the Successor and Predecessor periods), 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 termination.

For the period of January 1, 2019 through October 1, 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 year due to a reduction in our workforce.

On a per unit basis, taxes other than income were $2.08 per Boe and $1.63 per Boe for the year ended December 31, 2021 and 2020, respectively.

Gathering and other expenses were $60.4 million and $56.0 million for the year ended December 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 $22.7 million and $13.9 million for the year ended December 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 $37.7 million and $38.7 million for the year ended December 31, 2021 and 2020, respectively, relate to operating expenses on our treating equipment and gathering support facilities.

The decrease in treating equipment and gathering support facilities expenses in 2021 results from 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, which were partially offset by 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.

Also included are $3.4 million of rig stacking charges for the year ended December 31, 2020.

Restructuring expense was approximately $2.6 million for the year ended December 31, 2020.

During the year ended December 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.

In May 2020, 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.

General and administrative expense was $14.5 million and $15.9 million for the year ended December 31, 2021 and 2020, respectively.

The decrease in general and administrative expense in the current year period is associated with a decrease in professional fees and information technology expenses, as well as the Employee Retention Credit.

This decrease is partially offset by lower 2020 payroll costs, as the 2020 period included a $1.6 million reduction to general and administrative expenses related to our change in estimate of discretionary cash incentives.

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

expenses in the 2020 period.

On a per unit basis, general and administrative expense were $2.45 per Boe and $2.57 per Boe for the year ended December 31, 2021 and 2020, respectively.

Stock-based compensation expense was $2.0 million and $2.6 million for the year ended December 31, 2021 and 2020, respectively.

Stock-based compensation expense decreased in the current year due to restricted stock units vesting during the first quarter of 2021.

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 $60.5 million, $19.5 million and $84.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

On a per unit basis, depletion expense was $9.81 per Boe, $10.43 per Boe and $18.00 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 impairments incurred in 2020.

Depletion expense was $44.6 million and $60.5 million for the year ended December 31, 2021 and 2020, respectively.

On a per unit basis, depletion expense was $7.53 per Boe and $9.81 per Boe for the year ended December 31, 2021 and 2020, respectively.

The depletable base of our unit of production calculation was reduced by the full cost ceiling test impairments incurred in 2020 and increased by future development costs associated with PUD reserve additions.

We also experienced an increase in proved reserve volumes, primarily from PUD reserve additions, which resulted in a decrease to our depletion rate in 2021 as compared to 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.

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.

During 2020, the net book value of our oil and gas properties at June 30, September 30 and December 31 (Successor) exceeded the ceiling amount and we recorded full cost ceiling test impairments before income taxes of $60.1 million, $128.3 million and $26.7 million, respectively, for the periods.

The ceiling test impairments during 2020 (Successor) were primarily driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculation.

Additionally, during the three months ended September 30, 2020 (Successor), 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 also contributed to the impairment recorded for the period.

During the three months ended December 31, 2020 (Successor), proved undeveloped reserves additions as a result of changes to our five year development plan partially offset the impact on the impairment of the average price decline for the period.

During 2019, the net book value of our oil and gas properties at March 31, June 30 and September 30 (Predecessor) exceeded the ceiling amount and we recorded full cost ceiling test impairments before income taxes of $275.2 million, $664.4 million, and $45.6 million, respectively, for the periods.

The ceiling test impairments during 2019 (Predecessor) were driven by transfers of unevaluated property to the full cost pool that occurred during the year and decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculation.

For the three months ended June 30, 2019 (Predecessor), we transferred approximately $481.7 million of unevaluated property costs to the full cost pool, the majority of which were associated with our Hackberry Draw area.

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

These transfers of unevaluated property to the full cost pool in 2019 (Predecessor) were the result of our intent to focus available capital on our Monument Draw area.

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 $115.9 million gain on the sale which includes the $0.5 million addition and $3.6 million reduction in the period of October 2, 2019 through December 31, 2019 (Successor) and January 1, 2019 through October 1, 2019 (Predecessor), respectively, due to customary 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.

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.

During 2020, the net book value of our oil and gas properties at June 30, September 30 and December 31 exceeded the ceiling amount and we recorded full cost ceiling test impairments before income taxes of $60.1 million, $128.3 million and $26.7 million, respectively, for the periods.

The ceiling test impairments during 2020 were primarily driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculation.

Additionally, during the three months ended September 30, 2020, 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 also contributed to the impairment recorded for the period.

During the three months ended December 31, 2020, proved undeveloped reserves additions as a result of changes to our five year development plan partially offset the impact of the average price decline on the impairment for the period.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas 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 consolidated statements of operations.

At December 31, 2020 (Successor), we had a $12.6 million derivative asset, $8.6 million of which was classified as current, and we had a $26.4 million derivative liability, $22.1 million of which was classified as current.

We recorded a net derivative gain of $38.8 million ($6.1 million net unrealized loss and $44.9 million net realized gain on settled and early terminated contracts) for the year ended December 31, 2020 (Successor).

During 2020, we terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $22.9 million, which were included in the $44.9 million realized gains for the year.

We recorded a net derivative loss of $16.7 million ($18.7 million net unrealized loss and $2.0 million net realized gain on settled and early terminated contracts) and 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) for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

Interest expense and other was $6.6 million, $1.3 million and $37.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

Interest expense for the Successor periods 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 for the respective periods in which borrowings were outstanding under each type of credit facility or senior notes.

In addition to interest expense, in the period from January 1, 2019 through October 1, 2019 (Predecessor), we paid fees associated with consents and amendments to our Predecessor credit agreement.

Reorganization items represent (i) expenses or income incurred subsequent to August 7, 2019 (when we filed voluntary petitions for relief under chapter 11) as a direct result of the reorganization Plan, (ii) gains or losses from liabilities settled, and (iii) fresh-start accounting adjustments.

The following table summarizes the net reorganization items (in thousands):

October 2, 2019

January 1, 2019

December 31, 2019

October 1, 2019

Gain on settlement of liabilities subject to compromise

Fresh start adjustments

Gain on adjustment of prepetition liabilities subject to compromise to the allowed claims amount

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 using the discrete effective rate method for the period of January 1, 2019 through October 1, 2019 (Predecessor), resulting from the reduction to the deferred tax liability generated by the impact of the full cost ceiling impairment on oil and natural gas properties and the deferred tax asset created by the tax loss from operations.

The 7.7% effective tax rate for the period from January 1, 2019 through October 1, 2019 (Predecessor) differs from the 21% statutory rate because of non-deductible executive compensation, non-deductible realized built in losses, and valuation allowances on deferred tax assets.

At December 31, 2021, we had a $3.9 million derivative asset, $1.4 million of which was classified as current, and we had a $65.5 million derivative liability, $58.3 million of which was classified as current.

We recorded a net derivative loss of $125.6 million ($47.7 million net unrealized loss and $77.9 million net realized loss on settled contracts) for the year ended December 31, 2021.

Interest expense and other was $8.0 million and $6.6 million for the year ended December 31, 2021 and 2020, respectively.

Interest expense and other increased in the current period due to interest and the amortization of debt issuance costs associated with our Term Loan Agreement.

During the year ended December 31, 2021, we recorded a gain on the extinguishment of the forgiven portion of the PPP Loan and related accrued interest of $2.1 million.

We applied for forgiveness of the amount due on the PPP Loan based on the use of the loan proceeds on eligible expenses in accordance with the terms of the CARES Act.

Effective August 13, 2021, the principal amount of our PPP Loan was reduced from $2.2 million to $0.2 million by the SBA.

This gain was partially offset by a $0.1 million extinguishment loss resulting from the refinancing of our Senior Credit Agreement.

Recently Issued Accounting Pronouncements

2 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis