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Item 2. Management’s Discussion and Analysis

2023-11-15 compared with 2023-08-21 · 132 added, 125 removed, 125 unchanged (67% 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 six months ended June 30, 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.

MANAGEMENT’S DISCUSSION A ND 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, 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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Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production.

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, attempts by foreign oil and gas producers to control the global supply, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors.

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

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

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 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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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.

On March 28, 2023 and September 6, 2023, we sold, in private placements, an aggregate of 25,000 shares and 38,000 shares, respectively, 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 stockholders (the “Investors”).

We received $24.4 million in proceeds, net of $0.6 million in original issue discount, and $37.1 million in proceeds, net of $0.9 million of original issue discount, respectively.

The issuances of preferred stock were 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 of the preferred stock 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 at a fixed rate of 16.0% annually (“PIK accrual”) at the option of the Company.

Currently, our Amended Term Loan Agreement

prohibits the payment of cash dividends.

Paid in kind (“PIK”) dividends are cumulative, compound and accrue quarterly in arrears and are added to the Liquidation Preference (defined below) of the preferred stock.

Shares of preferred stock are convertible, subject to conversion ratios and prices stipulated in the certificate of designation of the preferred stock, at any time by the holders of the preferred stock 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 $63.0 million, increased for any PIK accruals) determined according to the redemption date.

Additionally, in the event of a change of control, holders of the preferred stock 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”.

For additional information, see Note 10, “ Redeemable Convertible Preferred Stock” to the unaudited condensed consolidated financial statements.

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.

The joint venture, operating as Wink Amine Treater, LLC (“WAT”) (previously Brazos Amine Treater, LLC (“BAT”), has also entered into a Gas Treating Agreement (“GTA”) with us for natural 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 WAT, an unconsolidated subsidiary.

Caracara provided the initial 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.

During commissioning and initial operations, it was determined that additional pressure was required to initiate gas injection.

To correct this issue, a positive displacement pump was ordered and is currently onsite and being installed.

To correct this issue, a positive displacement pump was ordered and has been installed.

The Facility’s injection well also experienced pressure communication between the tubing and annular space after an injection procedure.

The Company has commenced workover operations to remediate this issue and is exploring alternatives in the event such efforts prove inadequate.

The Company’s current forecast assumes the Acid Gas Injection (“AGI”) facility will be processing 20,000 mcf gas per day in October 2023.

We commenced workover operations to remediate this issue and are exploring alternatives in the event such efforts prove inadequate.

During the third quarter of 2023, additional complications were encountered with the workover operation causing higher than expected costs.

To fund this workover operation, we advanced a capital contribution of $8.05 million on behalf of our joint venture partner in WAT.

Pursuant to the terms of the agreement governing the joint venture, we have multiple remedies to recover such advance, including (1) declaring such payment a loan, which pursuant to the agreement would have an interest rate of the lessor of 15% or the maximum rate permitted by law, (2) recoupment from distributions from the joint venture and (3) reallocation of equity of the joint venture based on the relative level of total capital contributions by the parties after taking into account the advance.

We estimate that we will advance additional capital contributions on behalf of our joint venture partner during the fourth quarter of 2023 of approximately $5.5 million to fund the necessary capital to WAT required to sidetrack the Acid Gas Injection (“AGI”) well.

Our current forecast assumes the AGI facility will be processing 20,000 mcf gas per day in the first quarter of 2024.

It is possible that the existing remedial well work could extend past this estimate.

Any delays in commissioning past October 2023 will result in higher processing fees than currently forecast until such time the facility comes online.

Any delays in commissioning past the first quarter of 2024 will result in higher processing fees than currently forecast until such time the facility comes online.

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.

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

As of June 30, 2023, we had $18.5 million of cash and cash equivalents, no additional borrowing capacity under the Amended Term Loan and $20 million of debt repayments due during the remainder of 2023 and a total of $105 million due through September 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.

As of September 30, 2023, we had $42.7 million of cash and cash equivalents, no additional borrowing capacity under the Amended Term Loan Agreement (as defined in Note 5, “ Debt ” to the unaudited condensed consolidated financial statements) and a total of $95.0 million in debt repayments due through September 2025, including $10.0 million due during the remainder of 2023.

In November 2022, we were required to seek an amendment to our Term Loan Agreement (as defined in Note 5, “Debt” to the unaudited condensed consolidated financial statements) 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 our control.

In the first quarter 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 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 covenant requirements for the next 12 months from the issuance of these condensed consolidated financial statements.

In response to these events and conditions, we have continued to execute on 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 up to $38 million of additional preferred equity securities.

The Company has provided notice to the investors of its intent to draw the $38 million in the third quarter of 2023 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 additional $38 million in additional preferred equity expected to close in the third quarter of 2023, 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 condensed consolidated financial statements.

As a result, we projected near-term future covenant breaches (specifically the Current Ratio) 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 in March 2023 and $37.1 million in September 2023 of additional preferred equity funding from our three largest existing stockholders.

Changes to our current business estimates and forecasts, based primarily on recent declines 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 covenant requirements for the next 12 months from the issuance of these unaudited condensed consolidated financial statements.

We have also obtained a support letter from the Investors to purchase up to an additional $55.0 million of preferred equity securities.

When and as needed, we will provide notice to the Investors of our intent to draw the funds necessary to enable us to meet our obligations as they become due.

Management believes that based upon its operational forecasts, cash and cash equivalents on hand, cost reduction measures, and the commitment by the Investors to purchase $55.0 million in additional preferred equity, it is probable that we will have sufficient liquidity to fund our operations, meet our 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 unaudited condensed 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.

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, the sale of the Company, or pursuing additional general and administrative or other cost reduction opportunities.

Our 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 continues to consider 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.

We continue to explore strategic transactions to address these concerns, while also looking at opportunities to significantly reduce expenses in the near term.

In this regard, we continue to consider whether it is advisable to continue to bear the ongoing costs of the listing of our common stock on the NYSE American and of being a reporting company under the Securities Exchange Act of 1934.

We believe that we currently qualify to suspend these obligations should we elect to do so.

While such a determination has not yet been made, we expect that the cost savings, particularly over the longer term, would be significant;

however, as we have noted in the past (see “ Risk Factors ” in our most recent annual report on Form 10-K), we believe doing so would adversely impact liquidity and the trading price of our common stock.

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

However, there can be no assurance that such efforts will succeed, that we will not find it necessary to delist or cease being a reporting company or that absent additional capital, reducing costs or other material favorable developments, we will not experience liquidity and covenant compliance issues in the future.

Other Risks and Uncertainties.

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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.

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 United States 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.

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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.

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 June 30, 2023, we had $220.3 million of indebtedness outstanding and approximately $1.4 million of letters of credit outstanding under the Amended Term Loan Agreement.

We currently have $5.0 million available for the issuance of letters of credit.

On November 14, 2022, we paid approximately $2.4 million and entered into a further Amended Credit Agreement (the “Amended Term Loan Agreement”) with our lenders which modified certain provisions of its original Term Loan Agreement including, but not limited to, our Current Ratio financial covenant, interest rate benchmark, and prepayment premiums, all as further described below.

As of September 30, 2023, we had $210.2 million of indebtedness outstanding and no letters of credit outstanding under the Amended Term Loan Agreement.

We currently, as of November 14, 2023, have $4.7 million available for the issuance of letters of credit.

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 June 30, 2023 was approximately 12.6%.

Our Amended Term Loan Agreement contains a mandatory repayment schedule ($10 million due at the end of each of the third and fourth quarter in 2023 and first quarter of 2024, $12.5 million at the end of the quarter ended September 30, 2024, and in the aggregate, $105.0 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.

Borrowings under the Amended Term Loan Agreement bear a variable interest rate based on the Secured Overnight Financing Rate (“SOFR”) plus 0.15% plus a fixed applicable margin of 7.5%.

The weighted average interest rate on our borrowings for the quarter ended September 30, 2023 was approximately 12.89%.

Our Amended Term Loan Agreement contains a mandatory repayment schedule with $10.0 million due at the end of the fourth quarter in 2023 and first quarter of 2024, $12.5 million due at the end of each of the second and third quarters in 2024 and in the aggregate, $50.0 million due from the third quarter ending September 30, 2024 through the fiscal quarter ending September 30, 2025 as well as a $115.0 million payment due upon maturity.

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:

We may elect, at our option, to prepay any borrowing outstanding under the Amended Term Loan Agreement subject to the following prepayment premiums:

Period (after applicable borrowing date (1) )

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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.

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

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

For each fiscal quarter after January 1, 2023, we are required to make mandatory prepayments when our 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.

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 1.80 to 1.00 as of June 30, 2023 and each fiscal quarter thereafter

● Total Net Leverage Ratio of not greater than 2.50 to 1.00 as of June 30, 2023, and 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, as of June 30, 2023 and for each fiscal quarter thereafter.

As of June 30, 2023, the Company was in compliance with the financial covenants under the Term Loan Agreement.

● Asset Coverage Ratio of not less than 1.80 to 1.00 as of September 30, 2023 and each fiscal quarter thereafter

● Total Net Leverage Ratio of not greater than 2.50 to 1.00 as of September 30, 2023, and 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, as of September 30, 2023 and for each fiscal quarter thereafter.

As of September 30, 2023, we were 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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As a consequence, we endeavor to anticipate potential covenant compliance issues and work with our lenders under our Amended Term Loan Agreement to address any such issues ahead of time.

While we have been 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 June 30, 2023, there can be no assurance that we will be successful in the future.

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.

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 September 30, 2023, there can be no assurance that we will be successful in the future.

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 Amended Term Loan Agreement.

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

Six Months Ended

Cash flows provided by (used in) operating activities

Cash flows provided by (used in) investing activities

Cash flows provided by (used in) financing activities

Nine Months Ended

September 30,

Cash flows provided by operating activities

Cash flows used in investing activities

Cash flows provided by financing activities

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

Operating Activities .

Net cash flows provided by operating activities for the six months ended June 30, 2023 and 2022, respectively were $8.6 million and $28.3 million.

Items impacting operating cash flows were (i) lower total operating revenues resulting from an approximate $24.83 per Boe decrease in average realized prices (excluding the impact of hedging arrangements) for the six months ended June 30, 2023 compared to the six months ended June 30, 2022, partially offset by increased production in the first half of 2023 as well as the impact of settled derivative contracts period over period, (ii) increased operating and interest costs in 2023 and (iii) changes in working capital.

Net cash flows provided by operating activities for the nine months ended September 30, 2023 and 2022, respectively were $11.1 million and $53.8 million.

Items impacting operating cash flows were (i) lower total operating revenues resulting from an approximate $23.42 per Boe decrease in average realized prices (excluding the impact of hedging arrangements) and lower production volumes for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, partially offset by the impact of settled derivative contracts period over period, (ii) increased operating costs per Boe and increased interest costs in 2023 and (iii) changes in working capital.

Investing Activities.

Net cash flows used in investing activities for the six months ended June 30, 2023 and 2022 were approximately $31.7 million and $52.0 million, respectively, primarily for drilling and completion activities.

During the six months ended June 30, 2023, we spent $32.6 million on oil and natural gas capital expenditures, of which $28.1 million related to drilling and completion costs and $3.8 million related to the development of our treating equipment and gathering support infrastructure.

During the first half 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 six months of 2023, we ran one operated rig in the Delaware Basin and completed and put online one operated well.

Net cash flows used in investing activities for the nine months ended September 30, 2023 and 2022 were approximately $37.1 million and $87.8 million, respectively, primarily for drilling and completion activities.

During the nine months ended September 30, 2023, we spent $36.7 million on oil and natural gas capital expenditures, of which $31.6 million related to drilling and completion costs and $4.1 million related to the development of our treating equipment and gathering support infrastructure.

During the nine months ended September 30, 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 nine months 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 six months ended June 30, 2022, we spent $51.4 million on oil and natural gas capital expenditures, of which $45.7 million related to drilling and completion costs and $3.8 million related to the development of our treating equipment and gathering support infrastructure.

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.

Financing Activities.

Net cash flows provided by financing activities for the six months ended June 30, 2023 and 2022 were $8.9 million and $19.1 million, respectively.

During the six months ended June 30, 2023, we received $24.4 million from our Series A preferred stock equity issuance and repaid $15.0 million under our Amended Term Loan Agreement.

During the six months ended June 30, 2022, we borrowed $20.0 million under the first delayed draw of the Tern Loan Agreement.

Net cash flows provided by financing activities for the nine months ended September 30, 2023 and 2022 were $35.9 million and $19.2 million, respectively.

During the nine months ended September 30, 2023, we received $61.4 million from our Series A preferred stock equity issuance and repaid $25.1 million under our Amended Term Loan Agreement.

During the nine months ended September 30, 2022, we borrowed $20.1 million under the first delayed draw of the Tern Loan Agreement.

Critical Accounting Policies and Estimates

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Results of Operations

We reported a net loss of $4.7 million and net income of $18.1 million the three and six months ended June 30, 2023 and net income of $13.0 million and a net loss of $79.7 million for the June 30, 2022, respectively.

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

We reported net losses of $53.8 million and $35.7 million for the three and nine months ended September 30, 2023, respectively, and net income of $105.9 million and $26.2 million for the three and nine months ended September 30, 2022, respectively.

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

Three Months Ended

Six Months Ended

Nine Months Ended

September 30,

In thousands (except per unit and per Boe amounts)

Net income (loss)

Net (loss) income

Operating revenues:

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Other income (expenses):

Net gain (loss) on derivative contracts

Net (loss) gain on derivative contracts

Interest expense and other

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Stock-based compensation

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

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

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

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Operating Revenues.

Oil, natural gas and natural gas liquids revenues were $53.9 million and $118.2 million for the three and six months ended June 30, 2023, respectively.

Oil, natural gas and natural gas liquids revenues were $101.3 million and $182.7 million for the three and six months ended June 30, 2022, respectively.

The decrease in revenues is primarily attributable to a decrease in our average realized prices partially offset by higher production volumes for the six months ended in June 30, 2023 compared to the same period in 2022.

Average realized prices (excluding the effects of hedging arrangements) decreased approximately $32.44 and $24.83, respectively, for the three and six months ended June 30, 2023 when compared with the same periods in 2022.

Oil, natural gas and NGLs revenues were $53.4 million and $171.6 million for the three and nine months ended September 30, 2023, respectively.

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

The decrease in revenues is primarily attributable to a decrease in our average realized prices and lower production volumes for the nine months ended in September 30, 2023 compared to the same period in 2022.

Average realized prices (excluding the effects of hedging arrangements) decreased approximately $20.44 per Boe and $23.42 per Boe, respectively, for the three and nine months ended September 30, 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 averaged 14,253 Boe/d and 15,221 Boe/d for the three and six months ended June 30, 2023, respectively.

Production averaged 15,044 Boe/d and 14,906 Boe/d for the three and six months ended June 30, 2022, respectively.

Production was lower for the three months ended June 30, 2023 compared with the same period in 2022 primarily due to natural production declines on producing wells, which more than offset the additional production from the one operated well we brought online in the first half of 2023.

Production was higher for the six months ended June 30, 2023 compared to the prior year largely due to putting additional operated wells online in the second half of 2022, partially offset by natural production declines on producing wells.

Production averaged 12,717 Boe/d and 14,377 Boe/d for the three and nine months ended September 30, 2023 , respectively.

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

Production was lower for the three and nine months ended September 30, 2023 compared with the same periods in 2022 primarily from midstream disruptions and plant curtailments causing sales per day to be lower on an equivalent basis and natural production declines on producing wells, partially offset by additional operated wells being put online in the third quarter of 2022.

Lease Operating Expenses.

Lease operating expenses were $11.4 million and $23.1 million for the three and six months ended June 30, 2023, respectively.

Lease operating expenses were $11.9 million and $23.4 million for the three and six months ended June 30, 2022, respectively.

On a per unit basis, lease operating expenses were $8.76 per Boe and $8.37 per Boe for the three and six months ended June 30, 2023, respectively.

On a per unit basis, lease operating expenses were $8.70 per Boe and $8.69 per Boe for the three and six months ended June 30, 2022, respectively.

The increase in lease operating expenses per Boe for the three months ended June 30, 2023 compared to the prior year resulted primarily from high flare volumes due to midstream disruptions causing sales Boe per day to be lower, while the per unit cost decrease for the six months ended June 30, 2023 compared to the prior year was primarily due to renegotiated contracts for chemicals and labor resulting in lower daily burn rates .

Lease operating expenses were $11.2 million and $34.2 million for the three and nine months ended September 30, 2023, respectively.

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

On a per unit basis, lease operating expenses were $9.53 per Boe and $8.72 per Boe for the three and nine months ended September 30, 2023, respectively.

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

The increase in lease operating expenses per Boe for the three months and nine months ended September 30, 2023 compared to the prior year resulted primarily midstream disruptions and plant curtailments causing sales per day to be lower on an equivalent basis .

Workover and Other Expenses.

Workover and other expenses were $2.6 million and $4.0 million for the three and six months ended June 30, 2023, respectively.

Workover and other expenses were $1.4 million and $2.2 million for the three and six months ended June 30, 2022, respectively.

On a per unit basis, workover and other expenses were $2.03 per Boe and $1.44 per Boe for the three and six months ended June 30, 2023, respectively.

On a per unit basis, workover and other expenses were $1.01 per Boe and $0.83 per Boe for the three and six months ended June 30, 2022, respectively.

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

Workover and other expenses were $0.7 million and $4.7 million for the three and nine months ended September 30, 2023, respectively.

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

On a per unit basis, workover and other expenses were $0.60 per Boe and $1.19 per Boe for the three and nine months ended September 30, 2023, respectively.

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

The decreased workover and other expenses for the three months ended September 30, 2023 relate to more significant workover projects undertaken in the prior year.

Taxes Other than Income.

Taxes other than income were $3.2 million and $6.4 million for the three and six months ended June 30, 2023, respectively.

Taxes other than income were $5.4 million and $10.3 million for the three and six months ended June 30, 2022, respectively.

Taxes other than income were $3.3 million and $9.7 million for the three and nine months ended September 30, 2023, respectively.

Taxes other than income were $5.6 million and $15.9 million for the three and nine months ended September 30, 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 $2.45 per Boe and $2.31 per Boe for the three and six months ended June 30, 2023, respectively.

On a per unit basis, taxes other than income were $3.92 per Boe and $3.83 per Boe for the three and six months ended June 30, 2022, respectively.

The decrease in taxes other income was largely driven by the reduced commodity pricing experienced in 2023 in addition to lower volumes for the three months ended June 30, 2023, compared to the prior year period.

On a per unit basis, taxes other than income were $2.83 per Boe and $2.47 per Boe for the three and nine months ended September 30, 2023, respectively.

On a per unit basis, taxes other than income were $3.76 per Boe and $3.80 per Boe for the three and nine months ended September 30, 2022, respectively.

The decrease in taxes other than income was largely driven by the reduced commodity pricing experienced in 2023 in addition to lower volumes for the three and nine months ended September 30, 2023, compared to the prior year period.

Gathering and Other Expenses.

Gathering and other expenses were $16.8 million and $33.3 million for the three and six months ended June 30, 2023, respectively.

Gathering and other expenses were $15.9 million and $31.1 million for the three and six months ended June 30, 2022, respectively.

Gathering and other expenses were $15.5 million and $48.9 million for the three and nine months ended September 30, 2023, respectively.

Gathering and other expenses were $16.7 million and $47.8 million for the three and nine months ended September 30, 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.

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.

On a per unit basis, gathering and other expenses were

$12.97 per Boe and $12.10 per Boe for the three and six months ended June 30, 2023, respectively, and $11.59 per Boe and $11.54 per Boe for the three and six months ended June 30, 2022 , respectively.

The increases in gathering and other expenses are primarily related to increased production of higher acid natural gas in our Monument Draw area in 2023 requiring H2S treatment, compared to 2022, as well as inflationary impacts on costs associated with our own hydrogen sulfide treating plant.

On a per unit basis, gathering and other expenses were $13.26 per Boe and $12.45 per Boe for the three and nine months ended September 30, 2023, respectively, and $11.16 per Boe and $11.40 per Boe for the three and nine months ended September 30, 2022 ,

respectively.

The increases in gathering and other expenses per Boe are primarily related to midstream disruptions and plant curtailments as well as an increased percentage of total production requiring H2S treatment, compared to 2022, as well as inflationary impacts on costs associated with our own hydrogen sulfide treating plant.

General and Administrative Expense.

General and administrative expense was $6.0 million and $10.9 million for the three and six months ended June 30, 2023, respectively.

General and administrative expense was $4.1 million and $8.7 million for the three and six months ended June 30, 2022, respectively.

On a per unit basis, however, general and administrative expenses were $4.64 per Boe and $3.97 per Boe for the three and six months ended June 30, 2023, respectively, and were $3.01 per Boe and $3.23 per Boe for the three and six months ended June 30, 2022, respectively.

The increase in general and administrative expense for the three and six months ended June 30, 2023 compared with prior year periods is primarily associated with an increase in professional fees, partially offset by a decrease in payroll and benefits in connection with the headcount reduction.

General and administrative expense was $3.9 million and $14.8 million for the three and nine months ended September 30, 2023, respectively.

General and administrative expense was $3.8 million and $12.6 million for the three and nine months ended September 30, 2022, respectively.

On a per unit basis, general and administrative expenses were $3.31 per Boe and $3.77 per Boe for the three and nine months ended September 30, 2023, respectively, and were $2.56 per Boe and $2.99 per Boe for the three and nine months ended September 30, 2022, respectively.

The increase in general and administrative expense for the three and nine months ended September 30, 2023 compared with prior year periods is primarily associated with an increase in professional fees, partially offset by a decrease in payroll and benefits in connection with the headcount reduction in April 2023.

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 $14.4 million and $30.2 million for the three and six months ended June 30, 2023, respectively.

Depletion expense was $12.4 million and $22.5 million for the three and six months ended June 30, 2022, respectively.

On a per unit basis, depletion expense was $11.07 per Boe and $10.95 per Boe for the three and six months ended June 30, 2023, respectively.

On a per unit basis, depletion expense was $9.07 per Boe and $8.33 per Boe for the three and six months ended June 30, 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.

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

Depletion expense was $13.1 million and $43.2 million for the three and nine months ended September 30, 2023, respectively.

Depletion expense was $13.4 million and $35.9 million for the three and nine months ended September 30, 2022, respectively.

On a per unit basis, depletion expense was $11.17 per Boe and $11.02 per Boe for the three and nine months ended September 30, 2023, respectively.

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

The increase in our depletion rate per Boe 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 (loss) gain on derivative contracts.

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

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

For the three and six months ended June 30, 2023, respectively, we recorded net derivative gains of $4.5 million and $23.9 million ($2.4 million net gain on unsettled contracts and $2.1 million net realized gain on settled contracts for the three months ended June 30, 2023, and $23.3 million net gain on unsettled contracts and $0.6 million net realized gain on settled contracts for the six months ended June 30, 2023).

For the three and six months ended June 30, 2022, respectively, we recorded net derivative losses of $31.9 million and $155.8 million ($12.8 million net gain on unsettled contracts and $44.7 million net realized loss on settled contracts three months ended June 30, 2022, and $78.2 million net loss on unsettled contracts and $77.6 million net realized loss on settled contracts for the six months ended June 30, 2022).

At June 30, 2023, we had a $14.9 million derivative asset ($9.6 million current) and a $32.9 million derivative liability ($15.5 million current).

For the three and nine months ended September 30, 2023, respectively, we recorded net derivative losses of $53.7 million and $29.7 million ($46.8 million net loss on unsettled contracts and $6.9 million net realized loss on settled contracts for the three months ended September 30, 2023, and $23.5 million net loss on unsettled contracts and $6.3 million net realized loss on settled contracts for the nine months ended September 30, 2023).

For the three and nine months ended September 30, 2022, respectively, we recorded a net derivative gain of $67.6 million and a net derivative loss of $88.1 million ($102.1 million net gain on unsettled contracts and $34.5 million net realized loss on settled contracts three months ended September 30, 2022, and $23.9 million net gain on unsettled contracts and $112.0 million net realized loss on settled contracts for the nine months ended September 30, 2022).

At September 30, 2023, we had a $6.7 million derivative asset ($4.6 million current) and a $71.5 million derivative liability ($36.4 million current).

Interest Expense and Other.

Interest expense and other was $9.5 million and $17.3 million for the three and six months ended June 30, 2023, respectively.

Interest expense and other was $4.8 million and $7.5 million for the three and six months ended June 30, 2022, respectively.

Interest expense and other was $6.9 million and $24.2 million for the three and nine months ended September 30, 2023, respectively.

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

Interest expense and other primarily increased in the current year periods due to increased interest rates, an increased average debt balance due to the additional borrowings in April and November of 2022, and amortization/accretion of financing related costs since November 2022 associated with our Amended Term Loan Agreement.

Our weighted average interest rate was approximately 12.6% for the quarter ended June 30, 2023 .

For the third quarter of 2023, our interest rate will be approximately 12.9% on outstanding borrowings.

Our weighted average interest rate was approximately 12.89% for the quarter ended September 30, 2023 and 12.56% for the nine months ended September 30, 2023 .

For the fourth quarter of 2023, our interest rate will be approximately 13.04% 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