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Item 2. Management’s Discussion and Analysis

2023-08-21 compared with 2023-05-15 · 90 added, 73 removed, 160 unchanged (50% 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 months ended March 31, 2023 and 2022 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

The 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.

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

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We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States.

During 2017, we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota and in the El Halcón area of East Texas.

As a result, our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers attractive long-term economics.

Our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers attractive long-term economics.

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

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

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

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.

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

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

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

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.

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.

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.

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

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.

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

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

In the 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 requirements for the next 12 months from the issuance of these consolidated financial statements.

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

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

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

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

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.

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

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

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

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.

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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.

Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations.

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

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

As of March 31, 2023, we had $230.0 million of indebtedness outstanding and approximately $1.4 million of letters of credit outstanding under the Amended Term Loan Agreement.

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

The maturity date of the Amended Term Loan Agreement is November 24, 2025.We have a variable interest rate on our borrowings based on the Secured Overnight Financing Rate (SOFR) plus 0.15% and increased the applicable margin on borrowings by 0.50%, such that borrowings under the Amended Term Loan Agreement bear interest at a rate per annum equal to the SOFR benchmark rate plus 7.65%.

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

Our Amended Term Loan Agreement contains a mandatory repayment schedule ($10 million due at the end of each of the second, third, and fourth quarter in 2023 and first quarter of 2024, $12.5 million at the end of the quarter ended June 30, 2024, and in the aggregate, $115.0 million due from the fiscal quarter ending June 30, 2023 through the fiscal quarter ending September 30, 2025).

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.

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.

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Period (after applicable borrowing date (1) )

Months 0 - 12

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

Months 13 - 24

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

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

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.

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.

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 March 31, 2023 and each fiscal quarter thereafter

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

fiscal quarter thereafter, and

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

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

● 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.

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 March 31, 2023, there can be no assurance that we will be successful in the future.

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.

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

Three Months Ended

Six Months Ended

Cash flows provided by (used in) operating activities

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Operating Activities .

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

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

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.

Investing Activities.

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

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

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

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

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.

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

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

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

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

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.

Financing Activities.

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

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

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.

Critical Accounting Policies and Estimates

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Results of Operations

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

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.

Three Months Ended

Six Months Ended

In thousands (except per unit and per Boe amounts)

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Operating Revenues.

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

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

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

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.

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

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

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.

Lease Operating Expenses.

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

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

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

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 .

Workover and Other Expenses.

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

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

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

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.

Taxes Other than Income.

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

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.

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

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

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

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.

Gathering and Other Expenses.

Gathering and other expenses were $16.5 million and $15.3 million for the three months ended March 31, 2023 and 2022, respectively.

Gathering and other expenses 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 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.

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

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

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.

General and Administrative Expense.

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

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

On a per unit basis;

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

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.

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

2023 and 2022, respectively.

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

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.

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

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

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

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

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).

Interest Expense and Other.

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

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

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

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

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 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.

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