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Item 2. Management’s Discussion and Analysis

2024-11-12 compared with 2024-08-14 · 94 added, 82 removed, 204 unchanged (46% of the section changed)

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 six months ended June 30, 2024 and 2023 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, 2023.

The following discussion is intended to assist in understanding our results of operations for the nine months ended September 30, 2024 and 2023 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, 2023.

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

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With respect to the remaining $150.0 million of equity financing commitments, under the terms of the applicable Equity Financing Subscription Agreements, the obligation of the relevant financing sources to fund their portion of the equity financing is conditioned upon the satisfaction of certain conditions, including Parent entering into Equity Financing Subscription Agreements evidencing an aggregate amount of equity financing equal to $200.0 million and the other parties to such Equity Financing Subscription Agreements providing the related equity funding in escrow concurrently with or prior to the closing of the transactions contemplated by the Merger Agreement.

On September 19, 2024, pursuant to an amendment to the Merger Agreement, the amount of merger consideration payable to the holders of the Company’s Common Stock in connection with the transactions contemplated by the Merger Agreement would be reduced from $9.80 per share of Common Stock to $7.00 per share of Common Stock.

This amendment further amended the Merger Agreement such that the existing holders of the Company’s Series A through Series A-4 preferred stock, par value $0.0001 per share (collectively, the “Preferred Stock”), who are the holders of all of the issued and outstanding Preferred Stock of the Company, will roll over 100% of the Preferred Stock held by them into new preferred equity of Parent following the Merger (such proposed rollover, the “Rollover Transaction”).

In addition, this amendment further amended the Merger Agreement to (a) delete the Company’s right to terminate the Merger Agreement at any time prior to delivering the Evidence of Funding by Parent (as defined in the Merger Agreement), (b) add a right for the Company to terminate the Merger Agreement by written notice to Parent if the Closing (as defined in the Merger Agreement) has not occurred on or before 11:59 p.m.

Central Time on November 29, 2024 so long as the Company’s breach of the Merger Agreement is not the primary cause of the Closing not to have occurred, (c) add a customary non-solicitation covenant, in substantially the same form as was present in the Merger Agreement before such covenant was amended, prohibiting us from soliciting, providing non-public information in response to, or engaging in discussions or negotiations with respect to, proposals relating to alternative business combination transactions, except as permitted under the Merger Agreement, and (d) consistent with the changes to the amount of the Amended Merger Consideration (as defined in the Merger Agreement) and the structure of the Rollover Transaction contemplated, reduce the amount of aggregate equity financing sufficient to consummate the transactions contemplated by the Merger Agreement (as amended) reflected in the definition of “Evidence of Funding” in the Merger Agreement from $200,000,000 to $160,000,000 (“Sufficient Equity Financing”).

Furthermore, as of September 19, 2024, Parent had delivered to us sufficient binding equity financing commitments that, in the aggregate, reflect the Sufficient Equity Financing and constitute Qualifying Additional Financing Documents (as defined in the Merger Agreement) for purposes of the Merger Agreement, and the amendment reflected an acknowledgement by Parent and the Company that such delivery had taken place.

We will hold a special meeting of the Company stockholders on November 19, 2024 (the “special meeting”) in connection with the Merger.

Company stockholders will be asked to vote to adopt the Merger Agreement and approve related matters, as described in the notice of special meeting of stockholders and proxy statement.

Adoption of the

Merger Agreement requires the affirmative vote at the special meeting or by proxy of holders of a majority of the outstanding shares of the Company common stock as of the record date.

The obligations of us, Parent and Merger Sub to consummate the Merger are subject to the satisfaction or waiver of certain customary closing conditions, including, among other things:

(a) the absence of any law or order of any Governmental Authority having jurisdiction over a party to the Merger Agreement prohibiting or making illegal the consummation of the Merger, and (b) the adoption of the Merger Agreement by a majority vote of the issued and outstanding shares of Company Common Stock.

We have incurred approximately $3.6 million as of August 8, 2024, and will continue to incur significant costs and expenses, including fees for professional services and other transaction costs, in connection with the Merger.

We have incurred approximately $4.6 million as of November 8, 2024, and will continue to incur significant costs and expenses, including fees for professional services and other transaction costs, in connection with the Merger.

Preferred Stock Equity Issuance.

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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 our option.

Currently, our Amended Term Loan Agreement prohibits the payment of

cash dividends.

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.

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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.

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 AGI 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 H 2 S and CO2.

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

To fund this workover operation, we advanced capital contributions totaling approximately $18.5 million to date as of June 30, 2024 on behalf of our joint venture partner in WAT.

To fund this workover operation, we advanced capital contributions totaling approximately $18.5 million to date as of September 30, 2024 on behalf of our joint venture partner in WAT.

Pursuant to the terms of the agreement governing the joint venture, we believe that 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 lesser 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, none of which would occur until the expiration of the current tolling agreement between the parties.

The Acid Gas Injection (“AGI”) well and facility have been operational since March 9, 2024 and continued to process gas in the second quarter of 2024.

Additional projects have been completed causing interruption in the daily rates, however, the facility has processed over 2.1 Bcf effectively since operational through the second quarter of 2024.

The delays during the second quarter of 2024 have resulted in higher than expected gathering and treating costs.

It is possible that the existing remedial facility work by WAT could extend past the second quarter of 2024 and any delays in commissioning or shut downs of the plant past the second quarter of 2024 will result in higher processing fees than currently forecast until such time the facility becomes fully operational.

The AGI Facility has been processing gas since March 9, 2024 and continued to process gas in the third quarter of 2024.

Additional projects have been completed causing interruption in the daily rates;

however, the facility has processed over 3.7 Bcf through the third quarter of 2024.

The delays during the second and third quarters of 2024 have resulted in higher than expected gathering and treating costs.

It is possible that the existing remedial facility work by WAT could extend past the third quarter of 2024, and any delays in fully commissioning the facility or shut downs of the plant past the third quarter of 2024 will result in higher processing fees than currently forecast until such time the facility becomes fully operational.

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

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

Our current estimates of facility in-service

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

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

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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.

We generated a net loss of $45.5 million for the six months ended June 30, 2024 and had a negative working capital of $69.1 million as of June 30, 2024.

As of June 30, 2024, we had $54.4 million of cash and cash equivalents, no additional borrowing capacity under the Amended Term Loan Agreement (as defined in Note 4, “ Debt ” to the unaudited condensed consolidated financial statements) and a total of $52.5 million in debt repayments due through June 2025, including $27.5 million due during the remainder of 2024.

Our Amended Term Loan Agreement contains certain restrictive covenants as well as a mandatory repayment schedule.

We are required to make scheduled payments in the aggregate amount of $62.5 million from the fiscal quarter ending September 30, 2024 through the fiscal quarter ending September 30, 2025 with $12.5 million due at the end of the third quarter of 2024, $15.0 million due at the end of each of the fourth quarter of 2024 and the first quarter of 2025, and $10.0 million due at the end of each of the second and third quarters of 2025.

We generated a net loss of $33.2 million for the nine months ended September 30, 2024 and had negative working capital of $64.5 million as of September 30, 2024.

As of September 30, 2024, we had $29.8 million of cash and cash equivalents, no additional borrowing capacity under the Amended Term Loan Agreement (as defined in Note 4, “ Debt ” to the unaudited condensed consolidated financial statements) and a total of $50.0 million in debt repayments due through September 2025, including $15.0 million due at the end of each of the fourth quarter of 2024 and the first quarter of 2025 and $10.0 million due at the end of each of the second and third quarters of 2025.

We will be required to make a final payment of $97.7 million at maturity on November 24, 2025.

In November 2022, we were required to seek an amendment to our Term Loan Agreement (as defined in Note 4, “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.

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 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.

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Such prepayment cured the noncompliance of the Total Net Leverage Ratio as of March 31, 2024.

We continue to execute on a plan to reduce operating and capital costs to improve cash flow, including the issuance of preferred stock totaling $134.6 million as of June 30, 2024 .

We continue to execute on a plan to reduce operating and capital costs to improve cash flow, including the issuance of preferred stock totaling $134.6 million as of September 30, 2024 .

Changes to our current business estimates and forecasts, based primarily on recent 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, satisfy our debt payment requirements 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.

We have also obtained a support letter from our three largest current investors to purchase up to $30 million of additional preferred equity securities over the next 12 months.

We also obtained support letters from our three largest current investors to purchase up to $30.0 million of additional preferred equity securities.

We believe that, based upon our operational forecasts, cash and cash equivalents on hand, cost reduction measures, and the commitment of the investors to purchase up to $30.0 million in additional preferred equity if needed, 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 4, “ Debt, ” for the next 12 months from the issuance of these condensed consolidated financial statements.

We will, however, continue to consider alternative liquidity sources which could include entering into other financing arrangements (e.g.

the refinancing of our Amended Term Loan), 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.

the refinancing of our Amended Term Loan), 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.

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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.

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, 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.

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The Third Amendment, amended the Amended Term Loan Agreement to, among other things, (a) amend the approved plan of development (“APOD”) for certain properties, (b) remove the Proved Developed Producing (“PDP”) Production Test and APOD Economic Test (each defined in the Term Loan Agreement), (c) require the Borrower to receive cash proceeds from equity issuances and/or cash contributions in an aggregate amount of not less than $38.0 million during the period from Amendment Effective Date through March 31, 2024 (the “Specified Additional Equity Capital”), which such Specified Additional Equity Capital shall be excluded from the calculation of Consolidated Cash Balance (as defined in the Term Loan Agreement) through December 31, 2024, and (d) make amendments to certain other affirmative covenants in connection with the foregoing.

As of June 30, 2024, we had $160.2 million of indebtedness outstanding and $0.3 million of letters of credit outstanding under the Amended Term Loan Agreement.

We currently, as of August 8, 2024, have $160.2 million in borrowings outstanding and $4.7 million available for the issuance of letters of credit.

On August 23, 2024, we entered into the Fourth Amendment to the Amended Term Loan Agreement (the “Fourth Amendment”) with our lenders.

The Fourth Amendment amended the Amended Term Loan Agreement to allow for a Current Ratio (as defined in the Amended Term Loan Agreement) of not less than 0.90 to 1.00 for the fiscal quarter ending September 30, 2024.

As of September 30, 2024, we had $147.7 million of indebtedness outstanding and $0.3 million of letters of credit outstanding under the Amended Term Loan Agreement.

We currently, as of November 8, 2024, have $147.7 million in borrowings outstanding and $5.0 million available for the issuance of letters of credit.

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

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 June 30, 2024 was approximately 12.95%.

Our Amended Term Loan Agreement contains a mandatory repayment schedule with $12.5 million due at the end of the third quarter in 2024 and in the aggregate, $50.0 million due from the fourth quarter ending December 31, 2024 through the fiscal quarter ending September 30, 2025 as well as a $97.7 million payment due upon maturity.

The weighted average interest rate on our borrowings for the quarter ended September 30, 2024 was approximately 12.98%.

Our Amended Term Loan Agreement contains a mandatory repayment schedule with $15.0 million due at the end of the fourth quarter in 2024 and in the aggregate, $35.0 million due from the first quarter ending March 31, 2025 through the fiscal quarter ending September 30, 2025 as well as a $97.7 million payment due upon maturity on November 24, 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.

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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.

As of June 30, 2024, the Consolidated Cash Balance, as defined in the Amended Term Loan Agreement and excluding the Specified Additional Equity Capital, did not exceed $20.0 million;

As of September 30, 2024, the Consolidated Cash Balance, as defined in the Amended Term Loan Agreement and excluding the Specified Additional Equity Capital, did not exceed $20.0 million;

therefore, no mandatory prepayment was necessary.

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, 2024 and each fiscal quarter thereafter

● Total Net Leverage Ratio of not greater than 2.50 to 1.00 as of June 30, 2024, 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, 2024 and for each fiscal quarter thereafter.

● Asset Coverage Ratio of not less than 1.80 to 1.00 as of September 30, 2024 and each fiscal quarter thereafter

● Total Net Leverage Ratio of not greater than 2.50 to 1.00 as of September 30, 2024, and each fiscal quarter thereafter, and

● Current Ratio of not less than 0.90 to 1.00 for the fiscal quarter ending September 30, 2024 and not less than 1.00 to 1.00, determined as of the last day of any fiscal quarter period, as of December 31, 2024 and for each fiscal quarter thereafter.

At March 31, 2024, subject to the cure provision discussed below, we were not in compliance with the Total Net Leverage Ratio covenant but were in compliance with the remaining financial covenants under the Amended Term Loan Agreement.

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Upon giving effect to such prepayment for the calculation of the Total Net Leverage Ratio at March 31, 2024, we were in compliance with such financial covenant.

As of June 30, 2024, we were in compliance with the financial covenants under the Amended Term Loan Agreement.

As of September 30, 2024, we were in compliance with the financial covenants under the Amended Term Loan Agreement.

The Amended Term Loan Agreement 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 to address any such issues ahead of time.

While we have largely been successful in obtaining modifications of our covenants as needed, as evidenced most recently by the Third Amendment in March 2024 and the amendment of our Term Loan Agreement in November 2022 which reduced the Current Ratio covenant as of September 30, 2022 through March 31, 2023, there can be no assurance that we will be successful in the future.

While we have largely been successful in obtaining modifications of our covenants as needed, as evidenced most recently by the Fourth Amendment in August 2024 and the Third Amendment in March 2024, there can be no assurance that we will be successful in the future.

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

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

Six Months Ended

Nine Months Ended

September 30,

Cash flows provided by (used in) operating activities

Cash flows used in investing activities

Cash flows provided by financing activities

Cash flows (used in) provided by financing activities

Net decrease in cash, cash equivalents and restricted cash

Operating Activities .

Net cash flows provided by operating activities for the six months ended June 30, 2024 were $33.7 million compared to net cash flows used in operating activities of $8.7 million for the six months ended June 30, 2023.

Items impacting operating cash flows were (i) lower total operating revenues resulting from an approximate $0.96 per Boe decrease in average realized prices (excluding the impact of hedging arrangements) and lower production volumes for the six months ended June 30, 2024 compared to the six months ended June 30, 2023, 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.

Net cash flows provided by operating activities for the nine months ended September 30, 2024 were $28.7 million compared to net cash flows provided by operating activities of $11.1 million for the nine months ended September 30, 2023.

Items impacting the increase in operating cash flows were primarily driven by changes in working capital offset by lower total operating revenues resulting from an approximate $2.22 per Boe decrease in average realized prices (excluding the impact of hedging arrangements), lower production volumes for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, and the impact of settled derivative contracts period over period .

Investing Activities.

Net cash flows used in investing activities for the six months ended June 30, 2024 and 2023 were approximately $45.7 million and $31.7 million, respectively, primarily for drilling and completion activities.

During the six months ended June 30, 2024, we spent $44.8 million on oil and natural gas capital expenditures, of which $42.2 million related to drilling and completion costs and $2.0 million related to the development of our treating equipment and gathering support infrastructure.

Net cash flows used in investing activities for the nine months ended September 30, 2024 and 2023 were approximately $52.6 million and $37.1 million, respectively, primarily for drilling and completion activities.

During the nine months ended September 30, 2024, we spent $51.8 million on oil and natural gas capital expenditures, of which $46.8 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 first half of 2024, our cash capital expenditures included amounts related to the drilling and completion activities that occurred in the fourth quarter of 2023.

In the first six months of 2024, we ran one (1) operated rig in the Delaware Basin, drilled and cased four (4) gross (3.73 net), and completed and put online two (2) gross (1.925 net) operated wells.

In the first nine months of 2024, we ran one 1 operated rig in the Delaware Basin, drilled and cased four 4 gross

(3.73 net), and completed and put online two 2 gross (1.925 net) operated wells.

We also received $7.0 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, 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.

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

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.

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

Financing Activities.

Net cash flows provided by financing activities for the six months ended June 30, 2024 and 2023 were $8.9 million.

During the six months ended June 30, 2024, we received $38.8 million from our preferred stock equity issuances and repaid $39.9 million under our Amended Term Loan Agreement.

Our net cash flows provided by financing activities during the six months ended June 30, 2024 also reflect the receipt of the $10.0 million distributed from the Merger escrow account to the Company.

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

Net cash flows used in financing activities for the nine months ended September 30, 2024 were $3.8 million and net cash flows provided by financing activities for the nine months ended September 30, 2023 were $35.9 million.

During the nine months ended September 30, 2024, we repaid $52.3 million under our Amended Term Loan Agreement and received $38.8 million from our preferred stock equity issuances.

Our net cash flows provided by financing activities during the nine months ended September 30, 2024 also reflect the receipt of the $10.0 million distributed from the Merger escrow account to the Company.

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

Critical Accounting Policies and Estimates

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Three Months Ended

Six Months Ended

Nine Months Ended

September 30,

In thousands (except per unit and per Boe amounts)

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Operating Revenues.

Oil, natural gas and NGLs revenues were $ 49.1 million and $53.9 million for the three months ended June 30, 2024 and 2023.

The decrease in revenues is primarily attributable to our lower production volumes in 2024 compared to 2023 partially offset by an increase in average realized prices.

Average realized prices (excluding the effects of hedging arrangements) increased approximately $0.40 per Boe for three months ended June 30, 2024 when compared with the same period in 2023.

Oil, natural gas and NGLs revenues were $98.6 million and $118.2 million for the six months ended June 30, 2024 and 2023, respectively.

Oil, natural gas and NGLs revenues were $45.1 million and $53.4 million for the three months ended September 30, 2024 and 2023.

The decrease in revenues is primarily attributable a decrease in average realized prices combined with our lower production volumes in 2024 compared to 2023.

Average realized prices (excluding the effects of hedging arrangements) decreased approximately $5.07 per Boe for three months ended September 30, 2024 when compared with the same period in 2023.

Oil, natural gas and NGLs revenues were $143.7 million and $171.6 million for the nine months ended September 30, 2024 and 2023, respectively.

The decrease in revenues is primarily attributable to a decrease in our average realized prices and lower production volumes in 2024 compared to 2023.

Average realized prices (excluding the effects of hedging arrangements) decreased approximately $0.96 per Boe for the six months ended June 30, 2024 when compared with the same period in 2023.

Average realized prices (excluding the effects of hedging arrangements) decreased approximately $2.22 per Boe for the nine months ended September 30, 2024 when compared with the same period in 2023.

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 12,857 Boe/d and 14,253 Boe/d for the three months ended June 30, 2024 and 2023, respectively, and 12,923 Boe/d and 15,221 for the six months ended June 30, 2024 and 2023, respectively.

Production was lower in the second quarter and year to date period 2024 compared with the same period in 2023 due largely to the timing of capital expenditures spent to bring new wells online and natural production declines on our existing producing wells.

Over the twelve months preceding June 30, 2024, we put online 4 gross (3.93 net) operated wells while in the twelve months preceding June 30, 2023, we put online 7 gross (6.5 net) operated wells.

Production averaged 12,076 Boe/d and 12,717 Boe/d for the three months ended September 30, 2024 and 2023, respectively, and 12,639 Boe/d and 14,377 Boe/d for the nine months ended September 30, 2024 and 2023, respectively.

Production was lower in the third quarter and year to date period 2024 compared with the same period in 2023 due largely to the timing of capital expenditures spent to bring new wells online and natural production declines on our existing producing wells.

Also impacting 2024 production volumes was curtailment in Monument Draw due to downstream throughput limitations causing increased downtime and shut-in production.

Lease Operating Expenses.

Lease operating expenses were $11.0 million and $11.4 million for the three months ended June 30, 2024 and 2023, respectively, and $22.6 million and $23.1 million for the six months ended June 30, 2024 and 2023, respectively.

On a per unit basis, lease operating expenses were $9.41 per Boe and $8.76 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $9.61 per Boe and $8.37 per Boe for the six months ended June 30, 2024 and 2023, respectively.

The increase in lease operating expenses on a per unit basis in the second quarter and first six months of 2024 is primarily a result of an inflationary market increase in maintenance, power, and chemical costs combined with lower production .

Lease operating expenses were $11.6 million and $11.2 million for the three months ended September 30, 2024 and 2023, respectively, and $34.2 million for each of the nine months ended September 30, 2024 and 2023.

On a per unit basis, lease operating expenses were $10.44 per Boe and $9.53 per Boe for the three months ended September 30, 2024 and 2023, respectively, and $9.87 per Boe and $8.72 per Boe for the nine months ended September 30, 2024 and 2023, respectively.

The increase in lease operating expenses on a per unit basis in the third quarter and first nine months of 2024 is primarily a result of an inflationary market increase in maintenance, power, and chemical costs combined with lower production .

Workover and Other Expenses.

Workover and other expenses were $1.0 million and $2.6 million for the three months ended June 30, 2024 and 2023, respectively and $1.8 million and $4.0 million for the six months ended June 30, 2024 and 2023, respectively.

On a per unit basis, workover and other expenses were $0.81 per Boe and $2.03 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $0.78 per Boe and $1.44 per Boe for the six months ended June 30, 2024 and 2023, respectively.

The decreased workover and other expenses in 2024 relate to more significant workover projects undertaken in the prior year.

Workover and other expenses were $1.2 million and $0.7 million for the three months ended September 30, 2024 and 2023, respectively and $3.1 million and $4.7 million for the nine months ended September 30, 2024 and 2023, respectively.

On a per unit basis, workover and other expenses were $1.12 per Boe and $0.60 per Boe for the three months ended September 30, 2024 and 2023, respectively, and $0.89 per Boe and $1.19 per Boe for the nine months ended September 30, 2024 and 2023, respectively.

The year to date September 30, 2024 decrease in workover and other expenses compared to the same period in 2023 relate to more significant workover projects undertaken in the prior year.

Taxes Other than Income.

Taxes other than income were $3.3 million and $3.2 million for the three months ended June 30, 2024 and 2023, respectively, and $6.3 million and $6.4 million for the six months ended June 30, 2024 and 2023, respectively.

Taxes other than income were $2.5 million and $3.3 million for the three months ended September 30, 2024 and 2023, respectively, and $8.9 million and $9.7 million for the nine months ended September 30, 2024 and 2023, 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 $2.86 per Boe and $2.45 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $2.70 per Boe and $2.31 per Boe for the six months ended June 30, 2024 and 2023, respectively.

On a per unit basis, taxes other than income were $2.28 per Boe and $2.83 per Boe for the three months ended September 30, 2024 and 2023, respectively, and $2.56 per Boe and $2.47 per Boe for the nine months ended September 30, 2024 and 2023, respectively.

Gathering and Other Expenses.

Gathering and other expenses were $12.1 million and $16.8 million for the three months ended June 30, 2024 and 2023, respectively, and $29.4 million and $33.3 million for the six months ended June 30, 2024 and 2023, respectively.

Gathering and other expenses were $12.4 million and $15.5 million for the three months ended September 30, 2024 and 2023, respectively, and $41.9 million and $48.9 million for the nine months ended September 30, 2024 and 2023, 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 H 2 S 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 $10.36 per Boe and $12.97 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $12.51 per Boe and $12.10 per Boe for the six months ended June 30, 2024 and 2023, respectively.

The decrease in gathering and other expenses per Boe for the three months

ended June 30, 2024 is primarily related to the increase in volumes treated at the AGI facility compared to the same period in 2023.

The increase in gathering and other expenses per Boe for the six months ended June 30, 2024 is primarily related to an increased percentage of total production requiring H 2 S treatment, as well as inflationary impacts on costs associated with our own hydrogen sulfide treating plant, partially offset by increased volumes treated at the AGI facility, compared to the same period in 2023.

On a per unit basis, gathering and other expenses were $11.20 per Boe and $13.26 per Boe for the three months ended September 30, 2024 and 2023, respectively, and $12.09 per Boe and $12.45 per Boe for the nine months ended September 30, 2024 and 2023, respectively.

The decrease in

gathering and other expenses per Boe for the three and nine months ended September 30, 2024 is primarily related to the commencement of volumes being treated by the AGI facility during 2024.

General and Administrative Expense.

General and administrative expense was $3.3 million and $6.0 million for the three months ended June 30, 2024 and 2023, respectively, and $7.3 million and $11.0 million for the six months ended June 30, 2024 and 2023, respectively.

On a per unit basis, general and administrative expenses were $2.82 per Boe and $4.64 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $3.09 per Boe and $3.97 per Boe for the six months ended June 30, 2024 and 2023, respectively.

The decreases in general and administrative expense for the three and six months ended June 30, 2024 compared with the prior year periods is primarily associated with a decrease in payroll and benefits in connection with the headcount reduction in 2023 partially offset by an increase in legal fees associated with the merger.

General and administrative expense was $3.8 million and $3.9 million for the three months ended September 30, 2024 and 2023, respectively, and $11.1 million and $14.8 million for the nine months ended September 30, 2024 and 2023, respectively.

On a per unit basis, general and administrative expenses were $3.46 per Boe and $3.31 per Boe for the three months ended September 30, 2024 and 2023, respectively, and $3.21 per Boe and $3.77 per Boe for the nine months ended September 30, 2024 and 2023, respectively.

The decreases in general and administrative expense for the three and nine months ended September 30, 2024 compared with the prior year periods is primarily associated with a decrease in payroll and benefits in connection with the headcount reduction in 2023 partially offset by an increase in legal fees associated with the merger.

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 $12.8 million and $14.4 million for the three months ended June 30, 2024 and 2023, respectively, and $25.4 million and $30.2 million for the six months ended June 30, 2024 and 2023, respectively.

On a per unit basis, depletion expense was $10.95 per Boe and $11.07 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $10.82 per Boe and $10.95 per Boe for the six months ended June 30, 2024 and 2023, respectively.

The decreases in our depletion rate per Boe is primarily due to a period over period decrease in future development costs associated with proved reserves relative to the associated period over period decrease in proved reserves.

Net (loss) gain on derivative contracts.

Depletion expense was $12.1 million and $13.1 million for the three months ended September 30, 2024 and 2023, respectively, and $37.6 million and $43.2 million for the nine months ended September 30, 2024 and 2023, respectively.

On a per unit basis, depletion expense was $10.91 per Boe and $11.17 per Boe for the three months ended September 30, 2024 and 2023, respectively, and $10.85 per Boe and $11.02 per Boe for the nine months ended September 30, 2024 and 2023, respectively.

The decreases in our depletion rates per Boe are primarily due to a period over period decrease in future development costs associated with proved reserves relative to the associated period over period decrease 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 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 months ended June 30, 2024, we recorded a net derivative gain of $1.2 million ($4.4 million net gain on unsettled contracts and $3.2 million net realized loss on settled contracts).

For the three months ended June 30, 2023, we recorded a net derivative gain of $4.5 million ( $2.4 million net gain on unsettled contracts and $2.1 million net realized gain on settled contracts ).

For the six months ended June 30, 2024, we recorded a net derivative loss of $22.9 million ($15.3 million net loss on unsettled contracts and $7.6 million net realized loss on settled contracts).

For the six months ended June 30, 2023, we recorded a net derivative gain of $23.9 million ($23.3 million net gain on unsettled contracts and $0.6 million net realized gain on settled contracts).

At June 30, 2024, we had a $10.5 million derivative asset ($5.9 million current) and a $45.2 million derivative liability ($25.6 million current).

For the three months ended September 30, 2024, we recorded a net derivative gain of $26.9 million ($28.1 million net gain on unsettled contracts and $1.2 million net realized loss on settled contracts).

For the three months ended September 30, 2023, we recorded a net derivative loss of $53.7 million ( $46.8 million net loss on unsettled contracts and $6.9 million net realized loss on settled contracts ).

For the nine months ended September 30, 2024, we recorded a net derivative gain of $3.9 million ($12.7 million net gain on unsettled contracts and $8.8 million net realized loss on settled contracts).

For the nine months ended September 30, 2023, we recorded a net derivative loss of $29.7 million ($23.5 million net loss on unsettled contracts and $6.3 million net realized loss on settled contracts).

At September 30, 2024, we had a $12.9 million derivative asset ($5.7 million current) and a $19.5 million derivative liability ($9.8 million current).

Interest Expense and Other.

Interest expense and other was $6.5 million and $9.5 million for the three months ended June 30, 2024 and 2023, respectively, and $13.5 million and $17.3 million for the six months ended June 30, 2024 and 2023, respectively.

Interest expense and other was $6.3 million and $6.9 million for the three months ended September 30, 2024 and 2023, respectively, and $19.8 million and $24.2 million for the nine months ended September 30, 2024 and 2023, respectively.

Interest expense and other primarily decreased in the current year periods compared to the same periods in the prior year due to a lower average debt balance resulting from repayment of borrowings associated with our Amended Term Loan Agreement.

Our weighted average interest rate was approximately 12.95% for the quarter ended June 30, 2024 and 12.97% for the six months ended June 30, 2024 .

For the third quarter of 2024, our interest rate will be approximately 12.98% on outstanding borrowings .

Our weighted average interest rate was approximately 12.98% for the quarter ended September 30, 2024 and 12.97% for the nine months ended September 30, 2024 .

For the fourth quarter of 2024, our interest rate will be approximately 12.25% 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