What changed in BATTALION OIL CORP's 10-K — 2022 vs 2023

(“Parent”) and San Jacinto Merger Sub, Inc (“Merger Sub”), a direct wholly-owned subsidiary of Parent, pursuant to which Parent will acquire all of the outstanding shares of common stock of the Company for $9.80 per share in cash, which represents a total transaction value of approximately $450.0 million (the “Merger”).

The preferred stock (as defined below) of the Company held by the Investors (as defined below) will be contributed to Parent in exchange for new preferred shares of Parent, or sold to Parent for cash, in each case at a 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.

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. For a further discussion of the redemption and conversion provisions associated with the preferred stock, refer to Item 7.

Management’s Discussion and Analysis, “Capital Resources and Liquidity”. ● H 2 S 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 9 Table of Contents 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 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 such workover operations on the well and injection tests were completed.

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 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 Acid Gas Injection (“AGI”) well. Workover operations on the well and injection tests have now been successfully completed.

WAT is now ramping up operations and our current forecast assumes the AGI facility will be processing 20,000 Mcf of natural gas per day by the second quarter of 2024. For further details on the joint venture arrangement, see Item 7. Management’s Discussion and Analysis on Financial Condition - “Recent Developments ”.

Risk Management We have designed a risk management policy for the use of derivative instruments to provide initial protection against certain risks relating to our ongoing business operations, such as commodity price declines and price differentials between the NYMEX commodity price and the index price at the location where our production is sold.

Derivative contracts are utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production.

Our requirement, under our Amended Term Loan Agreement, is to hedge approximately 50% to 85% of our anticipated oil and natural gas production, in varying percentages by year, and on a rolling basis for the next four years.

However, our decision on the price at which we choose to hedge our production is based in part on our view of current and future market conditions. Our hedge policies and objectives change as our operational profile changes but remain consistent with the requirements in effect under our Amended Term Loan Agreement.

Our future performance is subject to commodity price risks and our future cash flows from operations may be volatile. We do not enter into derivative contracts for speculative trading purposes. While there are many different types of derivatives available, we typically use fixed-price swaps, costless collars, basis swaps and WTI NYMEX roll agreements to attempt to manage price risk.

The fixed-price swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the fixed-price swap agreement.

Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period.

All costless collar agreements provide for payments to counterparties if the settlement price under the agreement exceeds the ceiling and payments from the counterparties if the settlement price under the agreement is below the floor. Basis swaps effectively lock in a price differential between regional prices (i.e.

Midland) where the product is sold and the relevant pricing index under which the oil production is hedged (i.e. Cushing).

WTI NYMEX roll agreements account for pricing adjustments to the trade month versus the delivery month for contract pricing. 10 Table of Contents It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers.

As of December 31, 2023, we did not post collateral under any of our derivative contracts as they are secured under our Amended Term Loan Agreement. We will continue to evaluate the benefit of employing derivatives in the future. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Item 8.

Consolidated Financial Statements and Supplementary Data— Note 7 , “Derivative and Hedging Activities,” for additional information. Oil and Natural Gas Reserves The proved reserves estimates reported herein for the years ended December 31, 2023 and 2022, have been independently evaluated by NSAI, our independent reserve engineering firm.

Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in their reserves reports incorporated herein each have over 20 years of industry experience.

Each meet or exceed the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Our board of directors has established a reserves committee composed of independent directors with experience in energy company reserve evaluations. Our independent engineering firm reports jointly to the reserves committee and to our Director of Corporate Development and Reserves.

The reserves committee is charged with ensuring the integrity of the process of selection and engagement of the independent engineering firm and in making a recommendation to our board of directors as to whether to approve the report prepared by our independent engineering firm.

Our Vice President of Strategy and Planning is primarily responsible for overseeing the preparation of the annual reserve report by NSAI.

He has approximately 14 years of oil and natural gas operations experience and has earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University, a Master of Business Administration degree from Rice University and is an active member of the Society of Petroleum Engineers. The reserves information in this Annual Report on Form 10-K represents only estimates.

Reserve evaluation is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based.

Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced. Proved reserve estimates are based on the unweighted arithmetic average prices on the first day of each month for the 12-month period ended December 31, 2023.

Average prices for the 12-month period were as follows: WTI crude oil spot price of $78.21 per Bbl, adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub natural gas spot price of $2.64 per MMBtu, adjusted by lease or field for energy content, transportation fees, and market differentials.

All prices and costs associated with operating wells were held constant in accordance with SEC guidelines. 11 Table of Contents The following table presents certain proved reserve information as of December 31, 2023 (dollars in thousands): ​ ​ ​ Proved Reserves (MBoe) (1) ​ Developed ​ 40,129 Undeveloped ​ 27,978 Total ​ 68,107 PV-10 (2) $ 613,238 Discounted Future Income Taxes ​ (14,757) Standardized measure of discounted future net cash flows $ 598,481 (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) PV-10 represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. PV-10 of our total year-end proved reserves is considered a non-U.S.

GAAP financial measure as defined by the SEC. We believe that the presentation of the PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure.

We further believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. Refer to the reconciliation of our PV-10 to the standardized measure of discounted future net cash flows in the table above.

The following table presents estimated proved reserves at December 31, 2023: ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved ​ Proved ​ Total ​ Developed Undeveloped Proved Oil (MBbls) ​ 18,626 ​ 15,996 ​ 34,622 Natural Gas Liquids (MBbls) ​ 9,661 ​ 5,199 ​ 14,860 Natural Gas (MMcf) ​ 71,051 ​ 40,698 ​ 111,749 Equivalent (MBoe) (1) ​ 40,129 ​ 27,978 ​ 68,107 (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. At December 31, 2023, total estimated proved reserves were approximately 68.1 MMBoe, a 23.9 MMBoe net decrease from the previous year’s estimate of 92.0 MMBoe.

Proved developed reserves of 40.1 MMBoe decreased approximately 6.2 MMBoe from December 31, 2022 primarily as a result of negative revisions of 3.6 MMBoe and production of 5.0 MMBoe offset by proved undeveloped (“PUD”) reserve development of 2.4 MMBoe.

PUD reserves of 27.9 MMBoe decreased approximately 17.7 MMBoe from December 31, 2022 as a result of the transfer of 2.4 MMBoe to proved developed producing reserves and downward revisions of 15.3 MMBoe due primarily to the removal of 13.0 MMBoe of PUDS due to decreased activity associated with managing cash flow, servicing debt and financial covenants, and ongoing work to recapitalize the business coupled with a downward revision of 2.3 MMBoe due to decreased SEC prices.

All of our PUD reserves are planned to be developed within five years from the date they were initially recorded. During 2023, approximately $33.0 million in capital expenditures went toward the development of PUD reserves, which includes drilling, completion and other facility costs associated with developing PUD wells.

Reliable technologies were used to determine areas where PUD locations are more than one offset location away from a producing well. These technologies include seismic data, wire line openhole log data, core data, log cross-sections, performance data and statistical analysis.

In such areas, this data demonstrated consistent, continuous reservoir characteristics in addition to significant quantities of economic estimated ultimate recoveries from individual producing wells. We relied only on production flow tests and historical production data, along with the reliable geologic data mentioned above to estimate proved reserves.

No other alternative methods or technologies were used to estimate 12 Table of Contents proved reserves. Out of total PUD reserves of 27.9 MMBoe at December 31, 2023, 12.7 MMBoe were associated with 16 gross PUD locations that were more than one offset location from a producing well.

The estimates of quantities of proved reserves contained in this report were made in accordance with the definitions contained in SEC Release No. 33-8995, Modernization of Oil and Gas Reporting .

For additional information on our estimates of oil and natural gas reserves, the preparation of such estimates by NSAI and other information about our oil and natural gas reserves including a table detailing the changes by year of our proved reserves, see Item 8.

Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information (Unaudited).” We account for our oil and natural gas producing activities using the full cost method of accounting in accordance with SEC regulations which is further described in Item 8.

Consolidated Financial Statements and Supplementary Data —Note 4, “Oil and Natural Gas Properties.” Wells and Acreage Our principal properties consist of leasehold interests in developed and undeveloped oil and natural gas properties and the reserves associated with these properties.

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2023 and 2022.

Shut-in wells currently not capable of production are excluded from the well information below. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ ​ 2023 ​ 2022 ​ Gross Net Gross Net Oil ​ 109 ​ 86.2 ​ 111 ​ 91.2 Natural Gas ​ — ​ — ​ 9 ​ 6.9 Total ​ 109 ​ 86.2 ​ 120 ​ 98.1 ​ The table below sets forth the results of our drilling activities for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ ​ 2023 ​ 2022 ​ ​ Gross Net Gross Net Development Wells: ​ ​ ​ ​ ​ ​ ​ ​ ​ Productive (1) ​ 3 ​ 3.0 ​ 9 ​ 8.5 ​ Dry ​ — ​ — ​ — ​ — ​ Total Development ​ 3 ​ 3.0 ​ 9 ​ 8.5 ​ Total Wells: ​ ​ ​ ​ ​ ​ ​ ​ ​ Productive (1) ​ 3 ​ 3.0 ​ 9 ​ 8.5 ​ Dry ​ — ​ — ​ — ​ — ​ Total ​ 3 ​ 3.0 ​ 9 ​ 8.5 ​ (1) Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly extension or exploratory wells where there is no production history.

We had no exploratory or extension wells drilled for the years ended December 31, 2023 and 2022. We own interests in developed and undeveloped oil and natural gas acreage in the locations set forth in the table below. These ownership interests generally take the form of working interests in oil and natural gas leases that have varying provisions.

The following table presents a summary of our acreage interests as of December 31, 2023: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed Acreage ​ Undeveloped Acreage ​ Total Acreage State Gross Net Gross Net Gross Net Texas ​ 33,113 ​ 30,871 ​ 9,927 ​ 8,996 ​ 43,040 ​ 39,867 13 Table of Contents ​ Generally, our oil and natural gas leases remain in force as long as production in paying quantities is maintained.

Leases on our undeveloped oil and natural gas acreage are either categorized as “held by production” or perpetuated by continuous development clauses contained in our leases or tolling agreements.

Of our 8,996 net undeveloped acres at December 31, 2023, approximately 5,300 acres are subject to continuous development clauses and 3,692 acres are “held by production.” We continually review our acreage subject to these clauses or agreements when determining our drilling program. ​ Production Volumes, Sales Prices, and Average Costs The following table summarizes our oil, natural gas and NGLs production volumes, average sales price per unit and average costs per unit: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ 2023 2022 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 (excluding impact of settled derivatives) : ​ ​ ​ ​ ​ ​ ​ 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 ​ Barrel of oil equivalent price - Boe (1) ​ ​ 43.43 ​ ​ 63.43 ​ ​ ​ ​ ​ ​ ​ ​ ​ Average price per unit ( including impact of settled derivatives) (2) : ​ ​ ​ ​ ​ ​ ​ Crude oil price - Bbl ​ $ 68.28 ​ $ 53.54 ​ Natural gas price - Mcf ​ ​ 2.36 ​ ​ 3.40 ​ Natural gas liquids price - Bbl ​ ​ 20.48 ​ ​ 35.02 ​ Barrel of oil equivalent price - Boe (1) ​ ​ 41.59 ​ ​ 40.31 ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​ Total average cost ​ ​ 25.35 ​ ​ 24.39 ​ (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) Cash paid on, or cash received from, settled derivative contracts are reflected as “Net gain (loss) on derivative contracts” in the consolidated statements of operations, consistent with our decision not to elect hedge accounting.

Realized prices differ from the applicable spot prices due to lease or field quality, energy content, transportation fees and market differentials. 14 Table of Contents Competitive Conditions in the Business The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources.

Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis.

The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, obtaining sufficient availability of drilling and completion equipment and services, obtaining purchasers, transporters and take-away capacity for the oil and natural gas we produce and hiring and retaining key employees.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States and the states in which our properties are located.

It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.

Other Business Matters Markets and Major Customers The purchasers of our oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, we have not experienced any significant losses from uncollectible accounts.