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Item 7. Management’s Discussion and Analysis

2023-03-30 compared with 2022-03-07 · 175 added, 238 removed, 161 unchanged (72% of the section changed)

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These forward- looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.

For more information, see “ Special note regarding forward-looking statements .”

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.

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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, 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 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, 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.

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

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 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.

However, significant or prolonged reductions in capital spending will adversely impact our production and may negatively affect our future cash flows.

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

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, 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.

Recent Developments

Risk and Uncertainties

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

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

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).

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, 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 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.

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.

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 Term Loan Agreement.

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.

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

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

In addition, we encountered certain

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

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

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

In the event we are not successful 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 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.

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 Amended 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.

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We do not enter into derivative contracts for speculative trading purposes.

Recent Developments

Preferred Stock Equity Issuance.

On March 28, 2023, we sold, in a private placement, an aggregate of 25,000 shares of Series A Convertible Preferred Stock (the “preferred stock”) to certain funds managed by Luminus Management, LLC, Oaktree Capital Management, LP, and LSP Investment Advisors, LLC, who represent our largest three existing shareholders.

We received $24,375,000 in proceeds, net of $625,000 in original issue discount.

The issuance of preferred stock was approved by our board of directors upon recommendation by a special committee of disinterested directors that was established to evaluate the proposed terms of the preferred stock.

Holders will have no voting rights with respect to the shares of preferred stock.

The preferred stock will receive annual dividends, paid either in cash at a fixed rate of 14.5% annually or accrued (“PIK accrual”) at a fixed rate of 16.0% annually at the option of the Company.

Currently, the Company’s Amended Term Loan Agreement prohibits the payment of cash dividends.

PIK dividends will be cumulative, compound and accrue quarterly in arrears and will be added to the Liquidation Preference.

Shares of preferred stock will be convertible, subject to conversion ratios and prices stipulated in the agreement, at any time by the holders and by Battalion after meeting certain other agreement requirements.

Battalion will also have the right to redeem the preferred stock in cash at an amount equal to between 100-120% of the Liquidation Preference

($1,000 per share, or $25.0 million, increased for any PIK accruals) determined according to the redemption date.

Additionally, in the event of a change of control, holders have the right to receive, (i) at any time on or prior to 150 days following the closing date, and at the election of the Company, a cash payment equal to the Liquidation Preference or equity consideration equal to the 107.5% of the Liquidation Preference, or (ii) at any time after 150 days following the closing date, a cash payment equal to between 100-120% of the Liquidation Preference determined by the redemption date or conversion into common stock.

Until (i) a termination of or certain amendments to the Amended Term Loan Agreement or (ii) one year past the maturity date of the Amended Term Loan Agreement, an election of the cash payment option by holders in a change of control scenario is not permitted.

For additional information, see Item 9B.

Other Information.

H2S Treating Joint Venture.

In May 2022, we entered into a joint venture agreement with Caracara Services, LLC (“Caracara”) to develop a strategic acid gas treatment and carbon sequestration facility (the “Facility”) in Winkler County, Texas.

The joint venture, operating as Brazos Amine Treater, LLC (“BAT”), has also entered into a Gas Treating Agreement (“GTA”) with us for gas production from our Monument Draw area.

In exchange for contributing to the joint venture a wellbore with an approved permit for the injection of acid gas and surface land , we retained a 5% equity interest in BAT, an unconsolidated subsidiary.

Caracara provided all necessary capital for the construction of the Facility, which is expected to have an initial capacity of approximately 30 MMcf per day, and a design capacity to treat up to 10% combined concentrations for H2S and CO2.

We expect the AGI facility will be mechanically complete in early April 2023 and expect the facility to be in service in the second quarter of 2023.

Under the GTA, we will pay a treating rate that varies based on volumes delivered to the Facility for a term that will last 20 years from the in-service date of the Facility and have a minimum volume commitment of 20 MMcf per day, with certain rollover rights and start-up flexibility, for an initial term of five years from the in service date of the Facility, which can be extended up to seven years under certain conditions.

Once in service, the GTA has a tiered-rate structure which is expected to drive a greater than 50 percent reduction in treating fees.

Our current estimates of facility in-service dates and future treating fee reductions are subject to various operational and other risk factors, some of which are beyond our control, which could impact the timing and extent of these estimates.

Capital Resources and Liquidity

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

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

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.

Sufficient levels of available cash are required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves.

As of December 31, 2022, we had $32.7 million of cash and cash equivalents, and no additional borrowing capacity under the Amended Term Loan.

On March 28, 2023, we received approximately $24.4 million in additional cash proceeds upon the issuance of 25,000 shares of preferred stock as described above.

Our Amended Term Loan Agreement contains certain restrictive covenants (namely our Current Ratio covenant) as well as a mandatory repayment schedule ($5 million due March 31, 2023 and $10 million due at the end of each succeeding quarter in 2023 and in the aggregate, $120.0 million due from the fiscal quarter ending March 31, 2023 through the fiscal quarter ending September 30, 2025).

In November 2022, we were required to seek an amendment to our Term Loan to alleviate Current Ratio covenant compliance requirements through the first quarter of 2023 as a result of reduced commodity prices, higher interest rates, and the high capital costs experienced in our 2022 drilling program, which are by nature difficult to predict and subject to factors outside the Company’s control.

In December of 2022 and January of 2023, commodity prices, cost conditions and interest rates continued to deteriorate, which further constrained our liquidity.

As a result, we projected near-term future covenant (Current Ratio) breaches beginning with the first quarter of 2023 coupled with inadequate liquidity resources available to fully fund all of our collective upcoming obligations, including debt repayments and interest, capital expenditures and operating costs.

In the absence of obtaining additional liquidity from other sources prior to March 2023, we obtained $24.4 million of additional preferred equity funding as noted above.

We believe our forecasted cash flows from operations, cash on hand (including $24.4 million from our March 2023 preferred stock issuance) and our hedging program provide us with sufficient liquidity to address our near-term debt

maturities of approximately $45.0 million through the first quarter of 2024, maintain compliance with our debt covenants, address concerns around future covenant compliance, and meet our drilling requirements under our leases.

However, without additional future capital funding, our liquidity may continue to be constrained and will not provide for growth in our drilling program or maintenance or growth in production volumes.

However, significant or prolonged reductions in capital spending will adversely impact our production and may negatively affect our future cash flows.

We continuously monitor changes in market conditions and will continue to adapt our operational plans as necessary to strive to maintain sufficient liquidity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage, as well as meet our debt obligations and restrictive covenants.

The Company has been, and continues to, explore strategic transactions to address these concerns, while also looking at opportunities to significantly reduce expenses in the near term.

In this regard, the Company has considered whether it is advisable to continue to bear the ongoing costs of the listing of its common stock on the NYSE American and of being a reporting Company under the Securities Exchange Act of 1934.

The Company believes that it currently qualifies to suspend these obligations should it elect to do so.

While such a determination has not yet been made, the Company expects that the cost savings, particularly over the longer term, would be significant.

Accordingly, the Company will continue to consider the matter while it simultaneously pursues strategic and financial alternatives that may render it unnecessary.

We will continue to pursue additional liquidity sources which could include entering into other financing arrangements (e.g.

future equity raises), a sale of a portion of our non-core assets, pursuing strategic merger opportunities or joint ventures, further reducing our discretionary capital program, or pursuing other general and administrative or other cost reduction opportunities including aligning our workforce headcount with planned drilling activity.

However, there can be no assurance that, absent additional capital, reducing costs or other material favorable developments, the company will not experience liquidity and covenant compliance issues in the future.

Other Risks and Uncertainties.

Our ability to complete 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 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.

Additionally, in periods of increasing commodity prices, we continue to be at risk to supply chain issues, including, but not limited to, labor shortages, pipe restrictions and potential delays in obtaining frac and/or drilling related equipment that could impact our business.

During these periods, the costs and delivery times of rigs, equipment and supplies may also be substantially greater.

The unavailability or high cost of drilling rigs and/or frac crews, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability.

Lastly, 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 international conflicts, efforts to contain the COVID-19 pandemic 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 Amended Term Loan 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 Amended Term Loan Agreement.

Capital Expenditures .

During 2022, we spent approximately $126.6 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs.

In 2022, we ran one operated rig in the Delaware Basin.

We drilled, completed, and brought online 9 gross (8.5 net) operated wells during the year.

We had one drilled well awaiting completion as of December 31, 2022.

Debt Obligations .

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

The Term Loan Agreement amended and restated in its entirety our previous revolving credit agreement entered into in 2019.

On November 14, 2022, the Company paid approximately $2.4 million and entered into a further Amended Credit Agreement (the “Amended Term Loan Agreement”) with its lenders which modified certain provisions of its original Term Loan Agreement including, but not limited to, the following:

● Current Ratio .

Our Current Ratio financial covenant decreased to 0.90 to 1.00 as of September 30, 2022, to 0.70 to 1.00 for the quarter ended December 31, 2022, and to 0.75 to 1.00 for the quarter ended March 31, 2023, returning to 1.00 to 1.00 for the quarter ended June 30, 2023 and for each fiscal quarter thereafter as further described below.

● Interest Rate.

We converted our benchmark interest rate from LIBOR to a Secured Overnight Financing Rate (SOFR) plus 0.15% and increased the applicable margin on borrowings by 0.50%, such that borrowings under the Amended Term Loan Agreement will now bear interest at a rate per annum equal to the SOFR benchmark rate plus 7.65%.

● Prepayment Premium.

We reset the prepayment periods (for outstanding borrowings) beginning on the amendment date with the following prepayment premiums, subject to the conditions described in the table and further discussion below:

Period (after amendment date)

Months 0 - 12

Make-whole amount equal to 12 months of interest plus 2.00%

Months 13 - 24

In the following scenarios, our prepayment premiums would differ from those noted in the table above:

(i) if within 6 months after the November 14, 2022 amendment date the Company raises a minimum of $20 million of new capital in the form of equity, equity-linked, preferred equity, or unsecured debt, in all cases bearing no cash dividend or cash interest, to bolster liquidity or repay debt, our prepayment premiums will reset to those in the original Term Loan Agreement or (ii) should a change of control result in prepayment within the second anniversary of the amendment date, a 2% payment premium will apply.

As of December 31, 2022, we had $235.0 million of indebtedness outstanding and approximately $1.4 million of letters of credit outstanding under the Amended Term Loan Agreement.

An additional $3.6 million is available for the issuance of letters of credit.

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

We may be required to make mandatory prepayments of the loans under the Amended Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, and with cash on hand in excess of certain maximum levels beginning in 2023.

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

Until December 31, 2024, the forecasted approved plan of development (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 Amended 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 Amended Term Loan Agreement there are certain restrictions on the transfer of assets, including cash, to Battalion from the guarantor subsidiaries.

The Amended Term Loan Agreement contains certain financial covenants (as defined), including maintenance of the following rations:

● an Asset Coverage Ratio of not less than 1.80 to 1.00 as of December 31, 2022 and each fiscal quarter thereafter;

● Total Net Leverage Ratio of not greater than 3.00 to 1.00 as of December 31, 2022, 2.75 to 1.00 as of March 31, 2023, and 2.50 to 1.00 as of each fiscal quarter thereafter;

● a Current Ratio of not less than 1.00 to 1.00, each determined as of the last day of any fiscal quarter period, other than as amended in November 2022 to 0.70 to 1.00 as of December 31, 2022, and to 0.75 to 1.00 as of March 31, 2023.

As of December 31, 2022, the Company was in compliance with the financial covenants under the Amended Term Loan Agreement.

The Amended 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 Amended 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.

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

While we have largely been successful in obtaining modifications of our covenants as needed, as evidenced most recently by the amendment of our Term Loan Agreement in November 2022 which reduced the Current Ratio covenant as of September 30, 2022 and each successive quarter through the quarter ended March 31, 2023, there can be no assurance that we will be successful in the future.

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

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

For further information regarding these risks and uncertainties on us, see “Risk Factors” in Item 1A of this Annual Report on Form 10-K.

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

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Operating Activities.

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.

Net cash flows provided by operating activities for the years ended December 31, 2022 and 2021 were $78.8 million and $68.6 million, respectively.

Items impacting operating cash flows were (i) higher total operating revenues resulting from an approximate $15.50 per Boe increase in average realized prices (excluding the impact of hedging arrangements) for the year ended December 31, 2022 compared to the year ended December 31, 2021 partially offset by realized losses from derivative contracts, (ii) increased operating and interest costs in 2022, and (iii) changes in working capital.

Investing Activities.

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.

Net cash flows used in investing activities for the years ended December 31, 2022 and 2021 were approximately $126.1 million and $51.9 million, respectively.

During the year ended December 31, 2022, we spent $125.5 million on oil and natural gas capital expenditures, of which $108.3 million related to drilling and completion costs and $13.7 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, 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 $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.

Financing Activities.

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.

Net cash flows provided by financing activities for the years ended December 31, 2022 and 2021 were approximately $31.8 million and $27.4 million, respectively.

During the year ended December 31, 2022, we borrowed the remaining $35.0 million available under the Amended Term Loan Agreement and paid approximately $2.9 million in deferred financing costs, including $2.4 million upon entering into the Amended Term Loan Agreement with its lenders in November 2022.

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.

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, 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 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.

Critical Accounting Policies and Estimates

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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;

8 unchanged sentences

Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation.

If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income.

If the estimates of proved reserves were to be reduced, the rate at

which we record depletion expense would increase, reducing net income.

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.

7 unchanged sentences

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

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, 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.

If average oil and natural gas prices decline, it is possible that write-downs of our oil and natural gas properties could occur in the future.

Using the first-day-of-the-month average for the 12-months ended December 31, 2022 of the WTI crude oil spot price of $94.14 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 December 31, 2022 of the Henry Hub natural gas price of $6.36 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 impairment at December 31, 2022, holding all other inputs and factors constant.

Additionally, a 10% reduction in respective commodity prices at December 31, 2022, while all other factors remained constant, would not have generated an impairment.

Future Development Costs

18 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 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).

ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements.

Based upon the evaluation of available evidence, a valuation allowance of $425.0 million has been applied against our deferred tax asset balance as of December 31, 2022.

ASC 740, Income Taxes (ASC 740) creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes.

6 unchanged sentences

The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

Comparison of Results of Operations

Results of Operations

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

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

We reported net income (loss) of $17.7 million and ($28.3) million for the year ended December 31, 2022 and 2021, respectively.

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

In thousands (except per unit and per Boe amounts)

Net income (loss)

Operating revenues:

Natural gas liquids

Total operating revenues

Operating expenses:

3 unchanged sentences

Gathering and other

Restructuring

General and administrative:

5 unchanged sentences

Accretion expense

Full cost ceiling impairment

Other income (expenses):

2 unchanged sentences

Gain (loss) on extinguishment of debt

Net income (loss)

Crude oil – MBbls

20 unchanged sentences

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

Oil, natural gas and natural gas liquids revenues were $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).

Operating Revenues .

Oil, natural gas and natural gas liquids revenues were $357.4 million and $284.2 million for the years ended December 31, 2022 and 2021, respectively.

The increase in revenue is primarily attributable to an approximately $91.8 million increase in average realized prices partially offset by approximately $18.6 million attributable to slightly lower production volumes in 2022 compared to 2021.

Average realized prices (excluding the effects of hedging arrangements) increased approximately $15.50 per Boe for the year ended December 31, 2022 when compared with the same period in 2021.

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, quality of production, basis differentials and other factors.

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.

Production for the years ended December 31, 2022 and 2021 averaged 15,438 Boe/d and 16,241 Boe/d, respectively.

While production is lower in 2022 compared with 2021 in total due largely to the timing of capital expenditures spent to bring new wells online and natural production declines on our existing producing wells, our production has increased from 14,767 Boe/d in the first quarter of 2022 to 15,696 Boe/d and 15,438 Boe/d for the quarter and year ended December 31, 2022, respectively.

We have put online 9 gross (8.5 net) operated wells in 2022.

Also impacting 2021 production volumes was temporarily shut-in production due to inclement weather which decreased average daily production by approximately 300 Boe/d for the year ended December 31, 2021.

Lease Operating Expenses .

Lease operating expenses were $48.1 million and $44.0 million for the years ended December 31, 2022 and 2021, respectively.

On a per unit basis, lease operating expenses were $8.54 per Boe and $7.42 per Boe for the years ended December 31, 2022 and 2021, respectively.

The increase in lease operating expenses in 2022 results primarily from an inflationary market increase in maintenance, power, and chemical costs.

Workover and Other Expenses .

Workover and other expenses were $6.7 million and $3.2 million for the year ended December 31, 2022 and 2021, respectively.

On a per unit basis, workover and other expenses were $1.19 per Boe and $0.54 per Boe for the year ended December 31, 2022 and 2021, 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.

The increased workover and other expenses in 2022 relate to more significant workover projects undertaken in the current year as well as inflationary market increases in service and material costs in 2022.

Taxes Other than Income .

Taxes other than income were $18.5 million and $12.3 million for the years ended December 31, 2022 and 2021, respectively.

Most production taxes are based on production volumes and 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 $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.

On a per unit basis, taxes other than income were $3.28 per Boe and $2.08 per Boe for the years ended December 31, 2022 and 2021, respectively.

Gathering and Other Expenses.

Gathering and other expenses were $64.1 million ($11.38 per Boe) and $60.4 million ($10.19 per Boe) for the year ended December 31, 2022 and 2021, respectively.

Our gathering and other expenses are primarily driven by the amount and location of natural gas production, the concentration of H2S in our sour gas produced, and the amounts paid to treat our sour gas volumes, either through our own hydrogen sulfide treating plant or through third parties.

For the year ended December 31, 2022, overall natural gas production volumes were relatively flat compared to 2021;

however, increased production of sour natural gas in our Monument Draw area in 2022 requiring H2S treatment contributed to higher gathering and other expenses compared to 2021.

General and Administrative Expense .

General and administrative expense was $16.2 million and $14.5 million for the years ended December 31, 2022 and 2021, respectively.

The increase in general and administrative expense for 2022 is primarily associated with an increase in professional fees partially offset by a decrease in corporate office lease expense.

On a per unit basis, general and administrative expense were $2.88 per Boe and $2.45 per Boe for the years ended December 31, 2022 and 2021, respectively.

Depletion, Depreciation, and Amortization Expense.

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 $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.

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.

Depletion expense was $51.0 million and $44.6 million for the years ended December 31, 2022 and 2021, respectively.

On a per unit basis, depletion expense was $9.05 per Boe and $7.53 per Boe for the years ended December 31, 2022 and 2021, respectively.

The increase in our depletion rate for the year ended December 31, 2022

compared to 2021 is primarily due to increased future development costs associated with proved reserve additions relative to the change in proved reserves when comparing 2022 to 2021 .

Net gain (loss) on derivative contracts .

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.

Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes.

Accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations.

We recorded a net derivative loss of $110.0 million ($20.3 million net gain on unsettled contracts and $130.3 million net loss on settled contracts) for the year ended December 31, 2022.

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

At December 31, 2022, we had a $21.6 million derivative asset, $16.2 million of which was classified as current, and we had a $62.9 million derivative liability, $29.3 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.

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.

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 net realized gains for the year.

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.

Interest Expense and Other.

Interest expense and other was $23.6 million and $8.0 million for the years ended December 31, 2022 and 2021, respectively.

Interest expense and other increased in the current year due primarily to increased interest rates, higher debt balances in 2022, and amortization/accretion of financing related costs associated with our Term Loan Agreement entered into in November 2021 and further amended in November 2022.

Our weighted average interest rate for the year ended December 31, 2022, was approximately 9.1%.

For the first quarter of 2023, we anticipate our interest rate will be 12.23% on outstanding borrowings.

Gain (Loss) on Extinguishment of Debt .

During the year ended December 31, 2021, we recorded a gain on the extinguishment of the forgiven portion of the Paycheck Protection Program (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.

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

During the first quarter of 2022, the $0.2 million principal amount of the PPP loan was repaid in full.

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