Item 7. Management’s Discussion and Analysis
ITEM 7. 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 and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K contain additional information that should be referred to when reviewing this material.
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. 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 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. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.
When commodity prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge are less than our expected production, vary from period to period based on our view of current and future market conditions, remain consistent with the requirements in effect under our Amended Term Loan Agreement and extend, on a rolling basis, for the next four years. These limitations result in our liquidity being susceptible to commodity price declines. 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
Merger with Fury Resources.
On December 14, 2023, we entered into an Agreement and Plan of Merger, as amended (the “Merger Agreement”) with Fury Resources, Inc., a Delaware corporation (“Parent”) and San Jacinto Merger Sub, Inc. (“Merger Sub”), a Delaware corporation and a direct, wholly owned subsidiary of Parent.
The Merger Agreement provides, that upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into us (the “Merger”), with us surviving as a wholly owned subsidiary of Parent. Subject to the terms and conditions set forth in the Merger Agreement, at the effective time of the Merger, each of our issued and outstanding shares of Common Stock, par value $0.0001 per share (“Common Stock”) shall be converted into the right to receive $9.80 in cash, without interest, which represents a total transaction value of approximately $450. million (the “Merger Consideration”), and such shares shall otherwise cease to be outstanding, shall automatically be canceled and retired and cease to exist; and each outstanding share of redeemable convertible preferred
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stock will be contributed to Parent in exchange for new preferred shares of Parent, or sold to Parent for cash, in each case at valuation based on the conversion or redemption value of such preferred stock.
If the Merger is consummated, our shares of Common Stock will no longer trade on the NYSE American and will be deregistered under the Securities Exchange Act of 1934, as amended. As a result, we will become a private company.
On January 24, 2024, Parent and we agreed to cause an amount equal to $10.0 million to be distributed from the escrow account to the Company.
Conditions to Closing
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 $3.2 million as of March 20, 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. During the third quarter of 2023, we obtained an additional support letter from the Investors to purchase additional preferred equity securities in an amount up to $55.0 million over the next 12 months and an aggregate of 35,000 shares of preferred stock were sold on December 15, 2023 under such support letter to the Investors for proceeds of $34.1 million, net of $0.9 million of original issue discount.
At December 31, 2023, $20.0 million remained available for issuance under the support letter from the Investors. 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.
On March 27, 2024, we sold, in a private placement, the remaining 20,000 shares under the support letter to the Investors for proceeds of $19.5 million, net of $0.5 million of original issue discount.
Holders have no voting rights with respect to the shares of preferred stock. The preferred stock receives 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. Paid-in-kind (“PIK”) dividends are cumulative, compound and accrue quarterly in arrears and are added to the Liquidation Preference.
Shares of preferred stock will be convertible, subject to conversion ratios and prices stipulated in the agreement, at any time by the holders and by Battalion after meeting certain other agreement requirements. Battalion will also have 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, increased for any PIK accruals) determined according to the redemption date. Additionally, in the event of a change of control, holders have the right to receive, (i) at any time on or prior to 150 days following the closing date, and at the election of the Company, a cash payment equal to the Liquidation Preference or equity consideration equal to the 107.5% of the Liquidation Preference, or (ii) at any time after 150 days following the closing date, a cash payment equal to between 100-120% of the Liquidation Preference determined by the redemption date or conversion into common stock. Until (i) a termination of or certain amendments to the Amended Term Loan Agreement or (ii) one year past the maturity date of the Amended Term Loan Agreement, an election of the cash payment option by holders in a change of control scenario is not permitted. For additional information, see Item 8. Consolidated Financial Statements and Supplementary Date – Note 11, Redeemable Convertible Preferred Stock.
H2S Treating Joint Venture. In May 2022, we entered into a joint venture agreement with Caracara to develop the Facility in Winkler County, Texas. The joint venture, operating as WAT, also entered into a 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
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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. We initially expected the AGI facility to be mechanically complete in early April 2023 and the facility to be in service in the second quarter of 2023. However, d uring 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 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. During the third quarter of 2023, additional complications were encountered with the workover operation at the Facility causing higher than expected costs. To fund this workover operation, we advanced capital contributions totaling approximately $15.1 million during the year ended December 31, 2023 on behalf of our joint venture partner in WAT. Pursuant to the terms of the agreement governing the joint venture, we believe 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. We advanced additional capital contributions on behalf of our joint venture partner during the first quarter of 2024 of approximately $3.0 million to fund WAT with the necessary capital required to complete the sidetrack of the AGI well.
All well work is currently complete, and our current forecast assumes the AGI facility will be processing 20,000 Mcf of natural gas per day in the second quarter of 2024. It is possible that the existing remedial facility work by WAT could extend past this estimate. Any delays in commissioning past the first quarter of 2024 will result in higher processing fees than currently forecasted 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.
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 December 31, 2023, we had $57.5 million of cash and cash equivalents, no additional borrowing capacity under our Amended Term Loan Agreement (in Item 8. Consolidated Financial Statements and Supplementary Date – Note 6, Debt ) and a total of $50.0 million in debt repayments due under our Amended Term Loan Agreement through December 2024. At December 31, 2023, $20.0 million remained available for issuance under the support letter from the Investors.
Our Amended Term Loan Agreement contains certain restrictive covenants (namely our Current Ratio covenant) as well as a mandatory repayment schedule. We are required to make scheduled payments in the aggregate amount of $85.0 million from the fiscal quarter ending March 31, 2024 through the fiscal quarter ending September 30, 2025 with $10.0 million due at the end of the first quarter of 2024, $12.5 million due at the end of each of the second and third quarters of 2024, $15.0 million due at the end 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 $115.0 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 Item 8. Consolidated Financial Statements and Supplementary Date – Note 6, Debt) to alleviate Current Ratio covenant
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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 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 $95.6 million preferred equity funding from our three largest existing stockholders during 2023.
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 $95.6 million during 2023. On March 27, 2024, we completed the sale of the additional $19.5 million of available preferred equity securities under the support letter from the Investors received in November 2023. Management believes that based upon its operational forecasts, cash and cash equivalents on hand, including the $10.0 million Initial Deposit Amount under the Merger Agreement, the March 2024 sale of $19.5 million in additional preferred equity and continued cost reduction measures, 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 Item 8. Consolidated Financial Statements and Supplementary Date – Note 6, Debt for the next 12 months from the issuance of these consolidated financial statements. We will, however, continue to pursue alternative liquidity sources which could include entering into other financing arrangements (e.g. future equity raises), a sale of a portion of our non-core assets, seeking capital partners for our drilling program, pursuing strategic merger opportunities or joint ventures, 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.
In the event our cash flows are materially less than anticipated or our costs are materially greater than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may be required to curtail drilling, development, land acquisitions and other activities to reduce our capital spending. However, significant or prolonged reductions in capital spending will adversely impact our production and may negatively affect our future cash flows.
We continuously monitor changes in market conditions and will continue to adapt our operational plans as necessary to strive to maintain sufficient liquidity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage, as well as meet our debt obligations and restrictive covenants. We have been, and 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 have considered 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. Accordingly, we will continue to consider the matter while we simultaneously pursue strategic and financial alternatives that may render it unnecessary. We will continue to pursue additional 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, for example deep rights, pursuing strategic merger opportunities or joint ventures, further reducing our discretionary capital program, or pursuing other general and administrative or other cost reduction opportunities including aligning our workforce headcount with planned drilling activity. However, there can be no assurance that, absent additional capital, reducing costs or other material favorable developments, the company will not experience liquidity and covenant compliance issues in the future.
Other Risks and Uncertainties. Our ability to complete transactions and maintain or increase our liquidity is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our indebtedness, as well as various economic and market conditions that have historically
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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, in periods of increasing commodity prices, we continue to be at risk to supply chain issues, including, but not limited to, labor shortages, pipe restrictions and potential delays in obtaining frac and/or drilling related equipment that could impact our business. During these periods, the costs and delivery times of rigs, equipment and supplies may also be substantially greater. The unavailability or high cost of drilling rigs and/or frac crews, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability.
Lastly, actual or anticipated declines in domestic or foreign economic activity or growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the U.S. or global financial system and markets and a severe economic contraction either regionally or worldwide, resulting from international conflicts, efforts to contain pandemics 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.
Capital Expenditures . During 2023, we spent approximately $46.6 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs. During 2023, we ran one operated rig in the Delaware Basin. We drilled and completed 2 gross (2 net) operated wells and put online 3 gross (3 net) operated wells during the year.
Debt Obligations . On November 24, 2021, we and our wholly owned subsidiary, Halcón Holdings, LLC (‘ Borrower’ ), entered into a Term Loan Agreement with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders. The Term Loan Agreement amended and restated in its entirety our previous revolving credit agreement entered into in 2019.
On November 14, 2022, we paid approximately $2.4 million and entered into the Amended Term Loan Agreement with our lenders which modified certain provisions of our original Term Loan Agreement and includes the maintenance of the following ratios (as defined in the Amended Term Loan Agreement):
● Asset Coverage Ratio of not less than 1.80 to 1.00 as of December 31, 2023 and the last day of each fiscal quarter thereafter,
● Total Net Leverage Ratio of not greater than 2.50 to 1.00 as of December 31, 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 December 31, 2023 and each fiscal quarter thereafter.
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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, and 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 the 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. As of December 31, 2023, the Consolidated Cash Balance, as defined in the Amended Term Loan Agreement, did not exceed $20.0 million when considering forecasted APOD capital expenditures and cash held in unrestricted subsidiaries; therefore, no mandatory prepayment was necessary.
Our prepayment premiums would differ from those noted in the table above should a change of control result in prepayment within the second anniversary of the amendment date, as a 2% payment premium will apply.
As of December 31, 2023, we had $200.0 million of indebtedness outstanding and approximately $0.3 million of letters of credit outstanding under the Amended Term Loan Agreement. We currently, as of March 25, 2024, have $4.7 million available for the issuance of letters of credit. The maturity date of the Amended Term Loan Agreement is November 24, 2025.
We are required to make scheduled amortization payments in the aggregate amount of $85.0 million from the fiscal quarter ending March 31, 2024 through the fiscal quarter ending September 30, 2025 with $10.0 million due at the end of the first quarter of 2024, $12.5 million due at the end of each of the second and third quarters of 2024, $15.0 million due at the end 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 $115.0 million at 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 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.
As of December 31, 2023, the Company was in compliance with the financial covenants under the Amended 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 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.
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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 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 through March 31, 2023, 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. Even if successful, alternative sources of financing could prove more expensive than borrowings under our Amended Term Loan Agreement.
The results presented in this Form 10-K are not necessarily indicative of future operating results. For further information regarding these risks and uncertainties on us, see “Risk Factors” in Item 1A of this Annual Report on Form 10-K.
Cash Flow . Net increase (decrease) in cash, cash equivalents and restricted cash is summarized as follows for the periods presented (in thousands):
Years Ended December 31,
2023
2022
Cash flows provided by operating activities
$
17,589
$
78,801
Cash flows used in investing activities
(51,845)
(126,130)
Cash flows provided by financing activities
59,059
31,786
Net increase (decrease) in cash, cash equivalents and restricted cash
$
24,803
$
(15,543)
Operating Activities. Net cash flows provided by operating activities for the years ended December 31, 2023 and 2022 were $17.6 million and $78.8 million, respectively. Items impacting the reduction in operating cash flows were (i) lower total operating revenues resulting from an approximate $20.00 per Boe decrease in average realized prices (excluding the impact of hedging arrangements) for the year ended December 31, 2023 compared to the year ended December 31, 2022, (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 years ended December 31, 2023 and 2022 were approximately $51.8 million and $126.1 million, respectively.
During the year ended December 31, 2023, we spent $46.3 million on oil and natural gas capital expenditures, of which $40.4 million related to drilling and completion costs and $4.7 million related to the development of our treating equipment and gathering support infrastructure.
During the year ended December 31, 2022, we spent $125.5 million on oil and natural gas capital expenditures, of which $108.3 million related to drilling and completion costs and $13.7 million related to the development of our treating equipment and gathering support infrastructure.
Financing Activities. Net cash flows provided by financing activities for the years ended December 31, 2023 and 2022 were approximately $59.1 million and $31.8 million, respectively. During the year ended December 31, 2023, we received $95.6 million in proceeds from the sales and issuance of preferred stock and we made $35.0 million of repayments under our Amended Term Loan Agreement.
During the year ended December 31, 2022, we borrowed the remaining $35.0 million available under the Amended Term Loan Agreement and paid approximately $2.9 million in deferred financing costs, including $2.4 million upon entering into the Amended Term Loan Agreement with its lenders in November 2022.
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Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Item 8. Consolidated Financial Statements and Supplementary Data —Note 1, “ Summary of Significant Events and Accounting Policies,” for a discussion of additional accounting policies and estimates made by management.
Oil and Natural Gas Activities
Full Cost Method
We use the full cost method of accounting for our oil and natural gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized into a cost center (the amortization base or full cost pool). Such amounts include the cost of drilling and equipping productive wells, treating equipment and gathering support facilities costs, dry hole costs, lease acquisition costs and delay rentals. All general and administrative costs unrelated to drilling activities are expensed as incurred. The capitalized costs of our evaluated oil and natural gas properties, plus an estimate of our future development and abandonment costs, are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations could have been significantly different had we used the successful efforts method of accounting for our oil and natural gas activities.
Proved Oil and Natural Gas Reserves
Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.
Our estimated proved reserves for the years ended December 31, 2023 and 2022 were prepared by NSAI, an independent oil and natural gas reservoir engineering consulting firm. For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8. Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information (Unaudited). ”
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Depletion Expense
Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2023, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.50 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.56 per Boe.
Full Cost Ceiling Test Limitation
Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and could result in lower amortization expense in future periods. The present value of our estimated proved reserves (discounted at 10%) is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average oil and natural gas prices decline, it is possible that write-downs of our oil and natural gas properties could occur in the future. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
Using the first-day-of-the-month average for the 12-months ended December 31, 2023 of the WTI crude oil spot price of $78.21 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended December 31, 2023 of the Henry Hub natural gas price of $2.64 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation would not have generated an impairment at December 31, 2023, holding all other inputs and factors constant. Additionally, a 10% reduction in respective commodity prices at December 31, 2023, while all other factors remained constant, would not have generated an impairment.
Future Development Costs
Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic location, type of production facility, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. At December 31, 2023, a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.31 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.31 per Boe.
Accounting for Derivative Instruments and Hedging Activities
We account for our derivative activities under the provisions of the Financial Accounting Standards Board’s (the “FASB”) Accounting Standards Codification (“ASC” Topic 815, Derivatives and Hedging (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, in accordance with our policy, we may hedge a portion of our
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forecasted oil and natural gas production. We elected to not designate any of our positions for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.
Income Taxes
Our provision for taxes includes both state and federal taxes. We account for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We classify all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets.
In assessing the need for a valuation allowance on our deferred tax assets, we consider possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required. Based upon the evaluation of available evidence, a valuation allowance of $425.0 million has been applied against our deferred tax asset balance as of December 31, 2023.
ASC Topic 740, Income Taxes (“ASC 740”) creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows. The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.
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Results of Operations
Year Ended December 31, 2023 Compared to Year Ended December 31, 2022
The table below set forth financial information for the periods presented.
Years Ended
December 31,
In thousands (except per unit and per Boe amounts)
2023
2022
Operating revenues:
Oil
$
183,634
$
267,690
Natural gas
11,057
46,210
Natural gas liquids
23,814
43,501
Other
2,257
1,663
Total operating revenues
220,762
359,064
Operating expenses:
Production:
Lease operating
44,864
48,095
Workover and other
7,149
6,683
Taxes other than income
11,943
18,483
Gathering and other
63,575
64,117
General and administrative:
General and administrative
20,095
15,425
Stock-based compensation
(1,070)
2,210
Depletion, depreciation and accretion:
Depletion – Full cost
55,179
51,020
Depreciation – Other
652
367
Accretion expense
793
528
Other income (expenses):
Net gain (loss) on derivative contracts
12,689
(110,006)
Interest expense and other
(33,319)
(23,591)
Net (loss) income
$
(3,048)
$
18,539
Production:
Crude oil – MBbls
2,415
2,837
Natural gas – MMcf
8,718
9,337
Natural gas liquids – MBbls
1,163
1,242
Total MBoe (1)
5,031
5,635
Average daily production – Boe (1)
13,784
15,438
Average price per unit (2) :
Crude oil price - Bbl
$
76.04
$
94.36
Natural gas price - Mcf
1.27
4.95
Natural gas liquids price - Bbl
20.48
35.02
Total per Boe (1)
43.43
63.43
Average cost per Boe:
Production:
Lease operating
$
8.92
$
8.54
Workover and other
1.42
1.19
Taxes other than income
2.37
3.28
Gathering and other
12.64
11.38
Restructuring
—
—
General and administrative:
General and administrative
3.99
2.74
Stock-based compensation
(0.21)
0.39
Depletion
10.97
9.05
(1) Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or 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 natural gas liquids revenues were $218.5 million and $357.4 million for the years ended December 31, 2023 and 2022, respectively. The decrease of $138.9 million in revenue is primarily attributable to a decrease in average realized prices and lower production volumes in 2023 compared to 2022. The decrease is comprised of $38.3 million due to lower production volumes and $100.6 million due to lower average realized prices. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors.
Production for the years ended December 31, 2023 and 2022 averaged 13,784 Boe/d and 15,438 Boe/d, respectively. Production is lower in 2023 compared with 2022 in total due largely to the timing of capital expenditures spent to bring new wells online and natural production declines on our existing producing wells. In 2023, we have put online 3 gross (3 net) operated wells while in 2022 we put online 9 gross (8.5 net) operated wells. In addition, 2 of the 3 operated wells we put online in 2023 were put online at the end of December. As such, these wells had minimal impact on 2023 productions. Also impacting 2023 production volumes was curtailment in Monument Draw in the second half of the year due to downstream throughput limitations.
Lease Operating Expenses . Lease operating expenses were $44.9 million and $48.1 million for the years ended December 31, 2023 and 2022, respectively. On a per unit basis, lease operating expenses were $8.92 per Boe and $8.54 per Boe for the years ended December 31, 2023 and 2022, respectively. The decrease in lease operating expenses in 2023 results primarily from lower production in 2023 compared to 2022 while the increase year over year in lease operating expenses on a per unit basis is primarily a result of an inflationary market increase in maintenance, power, and chemical costs.
Workover and Other Expenses . Workover and other expenses were $7.2 million and $6.7 million for the years ended December 31, 2023 and 2022, respectively. On a per unit basis, workover and other expenses were $1.42 per Boe and $1.19 per Boe for the year ended December 31, 2023 and 2022, respectively. The increased workover and other expenses in 2023 relate to more significant workover projects undertaken in the current year as well as inflationary market increases in service and material costs in 2023.
Taxes Other than Income . Taxes other than income were $11.9 million and $18.5 million for the years ended December 31, 2023 and 2022, respectively. Most production taxes are based on production volumes and realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $2.37 per Boe and $3.28 per Boe for the years ended December 31, 2023 and 2022, respectively.
Gathering and Other Expenses. Gathering and other expenses were $63.6 million ($12.64 per Boe) and $64.1 million ($11.38 per Boe) for the years ended December 31, 2023 and 2022, respectively. 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 year ended December 31, 2023, overall natural gas production volumes slightly decreased compared to 2022; however, a higher concentration of sour natural gas in our Monument Draw area requiring H2S treatment in 2023 contributed to higher gathering and other expenses on a per unit basis compared to 2022.
General and Administrative Expense . General and administrative expense was $20.1 million and $15.4 million for the years ended December 31, 2023 and 2022, respectively. The increase in general and administrative expense for 2023 is primarily associated with an increase in professional fees and nonrecurring costs related to the merger partially offset by a decrease in payroll and employee benefits. On a per unit basis, general and administrative expense were $3.99 per Boe and $2.74 per Boe for the years ended December 31, 2023 and 2022, respectively.
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 $55.2 million and $51.0 million for the years ended December 31, 2023 and 2022, respectively. On a per unit basis, depletion expense was $10.97 per Boe and $9.05 per Boe for the years ended December 31, 2023 and 2022, respectively. The increase in our depletion rate for the year ended December 31, 2023
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compared to 2022 is primarily due to decreased proved reserves relative to the change in future development costs associated with those proved reserves when comparing 2023 to 2022 .
Net gain (loss) on derivative contracts . We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes. Accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. We recorded a net derivative gain of $12.7 million ($21.9 million net gain on unsettled contracts and $9.2 million net loss on settled contracts) for the year ended December 31, 2023. We recorded a net derivative loss of $110.0 million ($20.3 million net gain on unsettled contracts and $130.3 million net loss on settled contracts) for the year ended December 31, 2022. At December 31, 2023, we had a $13.9 million derivative asset, $9.0 million of which was classified as current, and we had a $33.3 million derivative liability, $17.2 million of which was classified as current.
Interest Expense and Other. Interest expense and other was $33.3 million and $23.6 million for the years ended December 31, 2023 and 2022, respectively. Interest expense and other increased in the current year due primarily to increased interest rates and amortization/accretion of financing related costs associated with our amendment to the Amended Term Loan Agreement entered into in November 2022. Our weighted average interest rate for the year ended December 31, 2023, was approximately 12.68%. For the first quarter of 2024, we anticipate our interest rate will be 12.99% on outstanding borrowings.
Recently Issued Accounting Pronouncements
We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data —Note 1, “ Summary of Significant Events and Accounting Policies .”