Item 2. Management’s Discussion and Analysis
ITEM 2. 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.
Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. For more information, see “ Special note regarding forward-looking statements .”
Overview
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. 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, 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 a limited period of time (generally, four years). These limitations result in our liquidity being susceptible to commodity price declines. Additionally, while intended to reduce the effects of volatile commodity prices, derivative transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.
Recent Developments
Preferred Stock Equity Issuance. 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
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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” 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 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 has been installed. The Facility’s injection well also experienced pressure communication between the tubing and annular space after an injection procedure. 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 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. 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.
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Capital Resources and Liquidity
Overview. Our ability to execute our operating strategy is dependent on our ability to maintain adequate liquidity and access additional capital, as needed. Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Sufficient levels of available cash are required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves. As of 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 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. 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 and the issuance of preferred stock totaling $63.0 million during 2023 . 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, 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. 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.
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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. Our ability to complete transactions and maintain or increase our liquidity is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our indebtedness, as well as various economic and market conditions that have historically affected the oil and natural gas industry. Even if we are otherwise successful in growing our proved reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.
Additionally, particularly in periods of increasing commodity prices, we continue to be at risk to supply chain issues, including, but not limited to, labor shortages, pipe restrictions and potential delays in obtaining frac and/or drilling related equipment that could impact our business. During these periods, the costs and delivery times of rigs, equipment and supplies may also be substantially greater. The unavailability or high cost of drilling rigs and/or frac crews, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability.
Lastly, actual or anticipated declines in domestic or foreign economic activity or growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the 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. All of the foregoing may adversely affect our business, financial condition, results of operations, cash flows and, potentially, compliance with the covenants contained in our Amended Term Loan Agreement.
Debt Obligations. On November 24, 2021, we and our wholly owned subsidiary, Halcón Holdings, LLC (Borrower) entered into the Term Loan Agreement with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders.
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. 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. 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,
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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.
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) )
Premium
Months 0-12
Make-whole amount equal to 12 months of interest plus 2.00%
Months 13-24
2.00%
Months 25-36
1.00%
Months 37-48
0.00%
(1) Applicable borrowing dates are November 2021 for the original $200.0 million borrowed and April and November 2022 for the $20.0 million and $15.0 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. 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 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. The Amended Term Loan Agreement contains a proved developed producing production test and an APOD economic test which we must maintain compliance with otherwise, subject to any available remedies or waivers, we are required to immediately cease making expenditures in respect of the approved plan of development other than any expenditures deemed necessary by us in respect of no more than six additional approved plan of development wells.
The Amended Term Loan Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.
Changes in the level and timing of our production, drilling and completion costs, the cost and availability of transportation for our production and other factors varying from our expectations can affect our ability to comply with the covenants under our Amended Term Loan Agreement. 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 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
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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.
Cash Flow
Net increase (decrease) in cash and cash equivalents is summarized as follows (in thousands):
Nine Months Ended
September 30,
2023
2022
Cash flows provided by operating activities
$
11,065
$
53,814
Cash flows used in investing activities
(37,106)
(87,780)
Cash flows provided by financing activities
35,905
19,166
Net increase (decrease) in cash, cash equivalents and restricted cash
$
9,864
$
(14,800)
Operating Activities . 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 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 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 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.
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Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
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Results of Operations
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
Nine Months Ended
September 30,
September 30,
In thousands (except per unit and per Boe amounts)
2023
2022
2023
2022
Net (loss) income
$
(53,799)
$
105,888
$
(35,736)
$
26,191
Operating revenues:
Oil
43,689
70,406
144,072
206,874
Natural gas
3,668
15,656
8,628
39,296
Natural gas liquids
6,078
12,644
18,893
35,234
Other
671
443
1,927
858
Operating expenses:
Production:
Lease operating
11,152
12,265
34,208
35,698
Workover and other
700
2,559
4,669
4,807
Taxes other than income
3,307
5,613
9,677
15,936
Gathering and other
15,512
16,663
48,857
47,787
General and administrative:
General and administrative
3,878
3,815
14,803
12,531
Stock-based compensation
(686)
683
(1,231)
1,540
Depletion, depreciation and accretion:
Depletion – Full cost
13,070
13,391
43,238
35,872
Depreciation – Other
167
110
488
230
Accretion expense
189
114
561
334
Other income (expenses):
Net (loss) gain on derivative contracts
(53,687)
67,634
(29,741)
(88,134)
Interest expense and other
(6,929)
(5,682)
(24,245)
(13,202)
Production:
Oil – MBbls
539
753
1,905
2,097
Natural Gas - MMcf
2,054
2,352
6,616
7,022
Natural gas liquids – MBbls
288
348
917
924
Total MBoe (1)
1,170
1,493
3,925
4,191
Average daily production – Boe (1)
12,717
16,228
14,377
15,352
Average price per unit (2) :
Oil price - Bbl
$
81.06
$
93.50
$
75.63
$
98.65
Natural gas price - Mcf
1.79
6.66
1.30
5.60
Natural gas liquids price - Bbl
21.10
36.33
20.60
38.13
Total per Boe (1)
45.67
66.11
43.72
67.14
Average cost per Boe:
Production:
Lease operating
$
9.53
$
8.22
$
8.72
$
8.52
Workover and other
0.60
1.71
1.19
1.15
Taxes other than income
2.83
3.76
2.47
3.80
Gathering and other
13.26
11.16
12.45
11.40
General and administrative:
General and administrative
3.31
2.56
3.77
2.99
Stock-based compensation
(0.59)
0.46
(0.31)
0.37
Depletion
11.17
8.97
11.02
8.56
(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.
(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.
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Operating Revenues. 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 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 $11.2 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 $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 $3.3 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 $2.83 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 $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 $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 ,
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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 $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 $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 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 $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 12.89% 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.
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Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.