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Item 2. Management’s Discussion and Analysis

2023-05-15 compared with 2022-11-14 · 119 added, 122 removed, 114 unchanged (68% of the section changed)

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

The following discussion is intended to assist in understanding our results of operations for the three and nine months ended September 30, 2022 and 2021 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2021.

The following discussion is intended to assist in understanding our results of operations for the three months ended March 31, 2023 and 2022 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

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

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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 long-term economics.

Our total operating revenues for the first nine months of 2022 and 2021 were $282.3 million and $200.7 million, respectively.

The increase in revenues is primarily attributable to an approximate $21.07 per Boe increase in average realized prices (excluding the effects of hedging arrangements).

During the first nine months of 2022, production averaged 15,352 Boe/d.

For the nine months ended September 30, 2022, we drilled and cased 8 gross (7.5 net) operated wells and completed and put online 5 gross (4.5 net) operated wells.

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

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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.

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

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

Using the crude oil price for October 2022 of $79.79 per barrel, and holding it constant for two months to create a trailing 12-month period of average prices that is more reflective of recent price trends, our ceiling test calculation would not have generated an impairment, holding all other inputs and factors constant.

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

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

Recent Developments

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 $24.4 million in proceeds, net of $0.6 million 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 have no voting rights with respect to the shares of preferred stock.

The preferred stock is entitled to 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 are 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 also has 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 Note 10, Redeemable Convertible Preferred Stock.

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.

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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 is obligated to provide all necessary capital for the construction of the Facility, which is expected to come online on or before twelve months from the effective date of the GTA, with an initial capacity of approximately 30 MMcf per day, and a design capacity to treat up to 10% combined concentrations for H2S and CO2.

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.

The Company has begun testing procedures and initial processing for its previously announced AGI project.

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.

We currently expect the AGI facility will be in service in the first quarter of 2023.

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 our beyond our control, which could impact the timing and extent of these estimates.

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

At September 30, 2022, we had $33.5 million of cash and cash equivalents, $220.0 million of indebtedness outstanding, approximately $1.3 million letters of credit outstanding and $15.0 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.

Capital Expenditures.

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

Included in our remaining 2022 capital expenditures budget is approximately $2.8 million associated with an active drilling rig commitment through the fourth quarter of 2022.

We also have a minimum volume commitment of approximately $1.6 million with a third party for the purchase of chemicals to treat sour gas production through December 31, 2022.

Our 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 (which is further described below) and cash flows from operations.

Our ability to execute our operating strategy is dependent on our ability to maintain adequate liquidity and access additional capital, as needed.

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.

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

As of March 31, 2023, we had $23.2 million of cash and cash equivalents, and no additional borrowing capacity under the Amended Term Loan.

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 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 upcoming obligations, including debt repayments and interest, capital expenditures and operating costs.

In the absence of additional liquidity from other sources with agreeable economic terms, we obtained $24.4 million of additional preferred equity funding from our three largest existing shareholders.

Changes to our current business estimates and forecasts, based primarily on recent reductions in commodity prices and modifications to our planned drilling schedule to achieve better overall well economics, indicate that we will require additional liquidity to continue our operations and meet our debt requirements for the next 12 months from the issuance of these consolidated financial statements.

In response to these events and conditions, we have implemented a plan to

reduce operating and capital costs to improve cash flow, including a reduction in headcount in April 2023 to align with planned drilling activity .

The Company also has obtained a support letter from its three largest current investors to purchase additional preferred equity securities in an amount up to $20 million to enable the Company to meet its obligations as they become due through at least one year beyond the issuance of these financial statements.

Management believes that based upon its operational forecasts, cash and cash equivalents on hand, cost reduction measures, and the commitment from its three largest current investors to purchase up to $20 million in additional preferred equity securities, as needed, it is probable the Company will have sufficient liquidity to fund its operations, meet its debt requirements and maintain compliance with our future debt covenants as described in Note 5, “ Debt, ” for the next 12 months from the issuance of these consolidated financial statements.

We will, however, continue to pursue alternative 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, seeking capital partners for our drilling program, pursuing strategic merger opportunities or joint ventures, or pursuing additional general and administrative or other cost reduction opportunities.

The Company’s estimates and forecasts are based upon assumptions that may prove to be incorrect due to many factors that are currently unknown, such as prevailing economic conditions, many of which are beyond our control.

In the event the assumptions underlying our estimates and forecasts prove to be incorrect, our operating plans, capital requirements, and covenant compliance may be adversely impacted.

We continuously monitor changes in market conditions and will continue to adapt our operational and capital plans as necessary to strive to maintain sufficient liquidity, meet our drilling requirements, and selectively develop or expand our acreage position, while meeting our debt obligations and maintaining compliance with our 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.

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.

Additionally, particularly 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.

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 Amended Term Loan Agreement.

Debt Obligations.

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 previous revolving credit agreement entered into in 2019.

As of September 30, 2022, the Company had borrowed $220.0 million under the Term Loan Agreement, a portion of which was used to refinance all amounts owed under the Senior Credit Agreement, and had approximately $1.3 million letters of credit outstanding.

Under the Term Loan Agreement, the lenders have also agreed to loan the Company up to an additional $15.0 million, which 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.

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, its Current Ratio financial covenant, interest rate benchmark, and prepayment premiums, all as further described below.

As of March 31, 2023, we had $230.0 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 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%.

● Current Ratio .

Our Current Ratio financial covenant decreased to 0.9 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 each quarter thereafter as further described below.

● Interest Rate.

Effective on the amendment date, we (i) converted the benchmark interest rate to the Secured Overnight Financing Rate (SOFR) and (ii) increased the applicable margin on borrowings by 0.50%, such that borrowings under the Term Loan Agreement will now bear interest at a rate per annum equal to the SOFR plus an applicable margin of 7.50%.

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

Period (after amendment date)

The maturity date of the Amended Term Loan Agreement is November 24, 2025.We have a variable interest rate on our borrowings based on the 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 bear interest at a rate per annum equal to the SOFR benchmark rate plus 7.65%.

The weighted average interest rate on our borrowings for the quarter ended March 31, 2023 was approximately 12.2%.

Our Amended Term Loan Agreement contains a mandatory repayment schedule ($10 million due at the end of each of the second, third, and fourth quarter in 2023 and first quarter of 2024, $12.5 million at the end of the quarter ended June 30, 2024, and in the aggregate, $115.0 million due from the fiscal quarter ending June 30, 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 all 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 Company may elect, at its option, to prepay any borrowing outstanding under the Amended Term Loan Agreement subject to the following prepayment premiums:

Period (after applicable borrowing date (1) )

Months 0 - 12

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Months 13 - 24

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 call cases bearing no cash dividend or cash interest, to bolster liquidity or repay debt, our prepayment premiums will reset to those in the original credit agreement (as further described in our 2021 Annual Report on Form 10-K).

Additionally, if a change of control results in prepayment within the second anniversary of the amendment date, a 2% payment premium will apply.

(1) Applicable borrowing dates are November 2021 for the original $200 million borrowed and April and November 2022 for the $20 million and $15 million in delayed draw borrowings, respectively.

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, or with cash on hand in excess of certain maximum levels beginning in 2023.

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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.

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 also contains certain financial covenants (as defined), including the maintenance of the following ratios:

● Asset Coverage Ratio of not less than 1.70 to 1.00 as of September 30, 2022, and 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 September 30, 2022 and 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, and

● 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 0.9 to 1 as of September 30, 2022, to 0.70 to 1 for the quarter ended December 31, 2022, and to 0.75 to 1 for the quarter ended March 31, 2023.

As of September 30, 2022, (i) the Company was in compliance with the Asset Coverage Ratio and Total Net Leverage Ratio covenants under the Term Loan Agreement and (ii) our Current Ratio was 0.96 to 1, which was less than

the 1.00 to 1.00 Current Ratio required under the original terms of the Term Loan Agreement.

As a result of the amendment to our Term Loan Agreement in November 2022, we were in compliance with the amended Current Ratio covenant of 0.9 to 1 for the quarter ended September 30, 2022.

● Asset Coverage Ratio of not less than 1.80 to 1.00 as of March 31, 2023 and each fiscal quarter thereafter

● Total Net Leverage Ratio of not greater than 2.75 to 1.00 as of March 31, 2023, and 2.50 to 1.00 as of each

fiscal quarter thereafter, and

● Current Ratio of not less than 1.00 to 1.00, determined as of the last day of any fiscal quarter period, of 0.75 to 1.00 as of March 31, 2023, returning to 1.00 to 1.00 for the quarter ended June 30, 2023 and for each fiscal quarter thereafter.

As of March 31, 2023, the Company was in compliance with the financial covenants under the 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.

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In the event we are not successful in obtaining future modifications or amendments to our covenants, 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.

Other Risks and Uncertainties.

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.

In periods of increasing commodity prices, the Company also continues 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.

We are also 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.

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, in 2022, the effects of Russian sanctions amidst the conflict with Ukraine have pushed oil and gas prices higher.

However, there remains the potential for demand for oil and natural gas to be adversely impacted by the economic effects of rising interest rates and tightening monetary policies, as well as 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, the Company is unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by these or other factors.

For further information regarding risk factors which could impact the Company, see “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.

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 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.

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

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

Nine Months Ended

September 30,

Three Months Ended

Cash flows provided by (used in) operating activities

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Operating Activities .

Net cash flows provided by operating activities for the nine months ended September 30, 2022 and 2021 were $53.8 million and $47.1 million, respectively.

Items impacting operating cash flows were (i) higher total operating revenues resulting from an approximate $21.07 per Boe increase in average realized prices (excluding the impact of hedging arrangements) for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 partially offset by realized losses from derivative contracts, (ii) increased operating and interest costs in 2022, and (iii) changes in working capital.

Net cash flows used in operating activities and net cash flows provided by operating activities for the three months ended March 31, 2023 and 2022, respectively were $0.7 million and $12.0 million.

Items impacting operating cash flows were (i) lower total operating revenues resulting from an approximate $17.18 per Boe decrease in average realized prices (excluding the impact of hedging arrangements) for the three months ended March 31, 2023 compared to the three months ended March 31, 2022, partially offset by increased production in 2023 and the impact of settled derivative contracts period over period, (ii) increased operating and interest costs in 2023 and (iii) changes in working capital.

Investing Activities.

Net cash flows used in investing activities for the nine months ended September 30, 2022 and 2021 were approximately $87.8 million and $46.2 million, respectively.

During the nine months ended September 30, 2022, we spent $87.0 million on oil and natural gas capital expenditures, of which $77.5 million related to drilling and completion costs and $6.8 million related to the development of our treating equipment and gathering support infrastructure.

During the nine months ended September 30, 2021, we spent $47.2 million on oil and natural gas capital expenditures, of which $39.4 million related to drilling and completion costs and $5.7 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.

Net cash flows used in investing activities for the three months ended March 31, 2023 and 2022 were approximately $27.7 million and $15.8 million, respectively.

During the three months ended March 31, 2023, we spent $28.6 million on oil and natural gas capital expenditures, of which $25.7 million related to drilling and completion costs and $2.4 million related to the development of our treating equipment and gathering support infrastructure.

During the first quarter of 2023, our cash capital expenditures included amounts related to the drilling and completion activities that occurred in the fourth quarter of 2022.

In the first quarter of 2023, we ran one operated rig in the Delaware Basin and completed and put online one operated well.

We also received $1.2 million in proceeds from the sale of oil and natural gas assets that were deemed to be unnecessary for future operations.

During the three months ended March 31, 2022, we spent $15.7 million on oil and natural gas capital expenditures, of which $12.9 million related to drilling and completion costs and $1.7 million related to the development of our treating equipment and gathering support infrastructure.

Cash capital expenditures in the first quarter of 2022 reflect last bringing new producing wells online in June 2021.

During the three months ended March 31, 2022, we drilled and cased 3.0 gross (3.0 net) operated wells, completed zero gross and net operated wells, and put online zero gross and net operated wells.

Financing Activities.

Net cash flows provided by (used in) financing activities for the nine months ended September 30, 2022 and 2021 were $19.2 million and $(3.3) million, respectively.

During the nine months ended September 30, 2022, we borrowed the $20 million available under the first delayed draw of the Term Loan Agreement.

During the nine months ended September 30, 2021, net borrowings of $3.0 million under our Senior Credit Agreement were funded with cash flows from operations.

Net cash flows provided by (used in) financing activities for the three months ended March 31, 2023 and 2022 were $18.9 million and $(0.9) million, respectively.

During the three months ended March 31, 2023, we received $24.4 million from our Series A preferred stock equity issuance and repaid $5.0 million under our Amended Term Loan Agreement.

Critical Accounting Policies and Estimates

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Results of Operations

We reported a net income of $105.9 million and $13.1 million for the three months ended September 30, 2022 and 2021, and a net income (loss) of $26.2 million and $(54.3) million for the nine months ended September 30, 2022 and 2021, respectively.

We reported a net income of $22.8 million and a net loss of $92.7 million for the three months ended March 31, 2023 and 2022, respectively.

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

Three Months Ended

Nine Months Ended

September 30,

In thousands (except per unit and per Boe amounts)

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Interest expense and other

Gain (loss) on extinguishment of debt

Natural Gas - MMcf

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Operating Revenues.

Oil, natural gas and natural gas liquids revenues were $98.7 million and $80.5 million for the three months ended September 30, 2022 and 2021 and $281.4 million and $199.9 million for the nine months ended September 30 2022 and 2021, respectively.

The increase in revenues is primarily attributable to an increase in our average realized prices partially offset by slightly lower production volumes in 2022 compared to 2021.

Average realized prices (excluding the effects of hedging arrangements) increased approximately $16.75 per Boe and $21.07 per Boe increase, respectively, for the quarter and nine months ended September 30, 2022 when compared with the same periods in 2021.

Oil, natural gas and natural gas liquids revenues were $64.3 million and $81.4 million for the three months ended March 31, 2023 and 2022, respectively.

The decrease in revenues is primarily attributable to a decrease in our average realized prices partially offset by higher production volumes in 2023 compared to 2022.

Average realized prices (excluding the effects of hedging arrangements) decreased approximately $17.18 per Boe for the three months ended March 31, 2023 when compared with the same periods in 2022.

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.

Production for the three months ended September 30, 2022 and 2021, averaged 16,228 Boe/d and 17,728 Boe/d and 15,352 Boe/d and 15,890 Boe/d for the nine months ended September 30, 2022 and 2021, respectively.

While production is lower in 2022 compared with 2021 due largely to the timing of capital expenditures 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 16,228 Boe/d in the third quarter of 2022 and we have put online 5 gross (4.5 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 400 Boe/d in the first nine months of 2021.

Production averaged 16,200 Boe/d and 14,767 Boe/d for the three months ended March 31, 2023 and 2022, respectively.

Production was higher in the first quarter of 2023 compared with the same period in 2022 due largely to putting additional operated wells online in 2022 partially offset by natural production declines on our existing producing wells.

Lease Operating Expenses.

Lease operating expenses were $12.3 million and $12.0 million for the three months ended September 30, 2022 and 2021 and $35.7 million and $31.6 million for the nine months ended September 30, 2022 and 2021, respectively.

On a per unit basis, lease operating expenses were $8.22 per Boe and $7.34 per Boe for the three months ended September 30, 2022 and 2021 and $8.52 per Boe and $7.29 per Boe for the nine months ended September 30, 2022 and 2021, respectively.

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

Lease operating expenses were $11.7 million and $11.5 million for the three months ended March 31, 2023 and 2022, respectively.

On a per unit basis, lease operating expenses were $8.02 per Boe and $8.67 per Boe for the three months ended March 31, 2023 and 2022, respectively.

The increase in lease operating expenses in 2023 results primarily from an inflationary market increase in maintenance, power, and chemical costs, while the per unit cost decreased due to the increase in average production as fixed costs represent a large portion of our lease operating expenses.

Workover and Other Expenses.

Workover and other expenses were $2.6 million and $1.0 million for the three months ended September 30, 2022 and 2021 and $4.8 million and $2.3 million for the nine months ended September 30, 2022 and 2021, respectively.

On a per unit basis, workover and other expenses were $1.71 per Boe and $0.61 per Boe for the three months ended September 30, 2022 and 2021 and $1.15 per Boe and $0.53 per Boe for the nine months ended September 30, 2022 and 2021, respectively.

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

Workover and other expenses were $1.3 million and $0.9 million for the three months ended March 31, 2023 and 2022, respectively.

On a per unit basis, workover and other expenses were $0.92 per Boe and $0.65 per Boe for the three months ended March 31, 2023 and 2022, respectively.

The increased workover and other expenses in 2023 relate to more significant workover projects undertaken in the current period as well as inflationary and market increases in service and material costs in 2023.

Taxes Other than Income.

Taxes other than income were $5.6 million and $3.1 million for the three months ended September 30, 2022 and 2021 and $15.9 million and $9.2 million for the nine months ended September 30, 2022 and 2021, 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 $3.76 per Boe and $1.89 per Boe for the three months ended September 30, 2022 and 2021 and $3.80 per Boe and $2.12 per Boe for the nine months ended September 30, 2022 and 2021, respectively.

Taxes other than income were $3.2 million and $5.0 million for the three months ended March 31, 2023 and 2022, respectively.

Severance taxes are based on realized prices and volumes at the wellhead, while ad valorem taxes are tied to the annual valuation of our properties.

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

On a per unit basis, taxes other than income were $2.19 per Boe and $3.73 per Boe for the three months ended March 31, 2023 and 2022, respectively, largely driven by the reduced commodity pricing experienced in 2023.

Gathering and Other Expenses.

Gathering and other expenses were $16.7 million and $15.9 million for the three months ended September 30, 2022 and 2021 and $47.8 million and $43.4 million for the nine months ended September 30, 2022 and 2021, respectively.

Gathering and other expenses were $16.5 million and $15.3 million for the three months ended March 31, 2023 and 2022, 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 $7.0 million and $6.3 million for the three months ended September 30, 2022 and 2021 and $20.5 million and $15.0 million for the nine months ended September 30, 2022 and 2021, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production.

Gathering and marketing fees increased in 2022 as we marketed higher quantities of sour gas production to third parties in the current year period.

Approximately $9.7 million and $9.6 million for the three months ended September 30, 2022 and 2021 and $27.5 million and $28.5 million for the nine months ended September 30, 2022 and 2021, respectively, relate to operating expenses on our treating equipment and gathering support facilities.

The decrease in treating equipment and gathering support facilities expenses for the year-to-date period results from lower operating expenses associated with our treating equipment .

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 quarter ended March 31 2023, our natural gas production volumes were relatively flat compared to the same period in 2022;

however, increased production of higher acid natural gas in our Monument Draw area in 2023 requiring H2S treatment contributed to higher gathering and other expenses compared to 2022.

General and Administrative Expense.

General and administrative expense was $3.8 million and $4.0 million for the three months ended September 30, 2022 and 2021 and $12.5 million and $11.8 million for the nine months ended

September 30, 2022 and 2021, respectively.

The decrease in general and administrative expense for the quarter ended September 30, 2022 compared with 2021 is primarily associated with a decrease in office rent and payroll and benefits partially offset by an increase in professional fees.

The increase in general and administrative expense for the year-to-date period in 2022 is primarily associated with an increase in professional fees and payroll and benefits partially offset by a decrease in corporate office lease expense.

On a per unit basis, general and administrative expenses were $2.56 per Boe and $2.46 per Boe for the three months ended September 30, 2022 and 2021 and $2.99 per Boe and $2.72 per Boe for the nine months ended September 30, 2022 and 2021, respectively.

General and administrative expense was $4.9 million and $4.6 million for the three months ended March 31, 2023 and 2022, respectively.

The increase in general and administrative expense for the quarter ended March 31, 2023 compared with 2022 is primarily associated with an increase in professional fees partially offset by a decrease in payroll and benefits.

On a per unit basis;

however, general and administrative expenses were $3.37 per Boe and $3.46 per Boe for the three months ended March 31, 2023 and 2022, respectively, due to the increase in production volumes.

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 $13.4 million and $10.7 million for the three months ended September 30, 2022 and 2021 and $35.9 million and $32.1 million for the nine months ended September 30, 2022 and 2021, respectively.

On a per unit basis, depletion expense was $8.97 per Boe and $6.57 per Boe for the three months ended September 30, 2022 and 2021 and $8.56 per Boe and $7.39 per Boe for the nine months ended September 30, 2022 and 2021, respectively.

The increase in our depletion rate for the quarter and nine month periods ended September 30, 2022 compared to the same period in 2021 is primarily due to increased future development costs in 2022 compared to 2021 associated with PUD reserve additions during the period s.

Depletion expense was $15.8 million and $10.1 million for the three months ended March 31,

2023 and 2022, respectively.

On a per unit basis, depletion expense was $10.84 per Boe and $7.57 per Boe for the three months ended March 31, 2023 and 2022, respectively.

The increase in our depletion rate is primarily due to increased future development costs (tied to market and inflationary increases) associated with proved reserve additions relative to the change in proved reserves.

Net gain (loss) on derivative contracts.

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

At September 30, 2022, we had a $27.0 million derivative asset ($18.2 million current) and a $64.7 million derivative liability ($41.1 million current).

For the three months ended September 30, 2022, we recorded a net derivative gain of $67.6 million ($102.1 million net unrealized gain and $34.5 million net realized loss on settled contracts).

For the nine months ended September 30, 2022, we recorded a net derivative loss of $88.1 million ($23.9 million net unrealized gain and $112.0 million net realized loss on settled contract).

For the three months ended September 30, 2021, we recorded a net derivative loss of $20.6 million ($1.8 million net unrealized gain and $22.4 million net realized loss on settled and early terminated contracts).

For the nine months ended September 30, 2021, we recorded a net derivative loss of $119.4 million ($69.1 million net unrealized loss and $50.3 million net realized loss on settled and early terminated contracts).

For the three months ended March 31, 2023, we recorded a net derivative gain of $19.5 million ($21.0 million net gain on unsettled contracts and $1.5 million net realized loss on settled contracts).

For the three months ended March 31, 2022, we recorded a net derivative loss of $123.9 million ($91.1 million net loss on unsettled contracts and $32.8 million net realized loss on settled contracts).

At March 31, 2023, we had a $20.5 million derivative asset ($15.1 million current) and a $40.8 million derivative liability ($18.0 million current).

Interest Expense and Other.

Interest expense and other was $5.7 million and $1.9 million for the three months ended September 30, 2022 and 2021 and $13.2 and $5.0 for the nine months ended September 30, 2022 and 2021, respectively.

Interest expense and other primarily increased in the current period due to higher debt balances in 2022, increased interest rates, and amortization of debt issuance costs associated with our Term Loan Agreement entered into in 2022.

This was partially offset by a $0.4 million and $3.0 million change, respectively in the fair value of the Change of Control Call Option (as further discussed in Note 5, “Debt” ) for the quarter and nine months ended September 30, 2022.

Gain (loss) on extinguishment of debt.

During the quarter and nine months ended September 30, 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.

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

Interest expense and other was $7.8 million and $2.7 million for the three months ended March 31, 2023 and 2022, respectively.

Interest expense and other primarily increased in the current period due to $35.0 million of additional borrowings in April and November of 2022, increased interest rates, and amortization/accretion of financing related costs since November 2022 associated with our Amended Term Loan Agreement.

Our weighted average interest rate was approximately 12.2% for the quarter ended March 31, 2023.

For the second quarter of 2023, our interest rate will be approximately 12.5% on outstanding borrowings.

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-Q

Item 2. Management’s Discussion and Analysis