BATTALION OIL CORPORATION 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
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
Preferred Stock Equity Issuance. On
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
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(
H2S Treating Joint Venture. In
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 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
Our Amended Term Loan Agreement contains certain restrictive covenants (namely
our Current Ratio covenant) as well as a mandatory repayment schedule (
In December of 2022 and January of 2023, commodity prices, cost conditions and
interest rates continued to deteriorate, which further constrained our
liquidity. As a result, we projected near-term future covenant (Current Ratio)
breaches beginning with the first quarter of 2023 coupled with inadequate
liquidity resources available to fully fund all of our collective upcoming
obligations, including debt repayments and interest, capital expenditures and
operating costs. In the absence of obtaining additional liquidity from other
sources prior to
We believe our forecasted cash flows from operations, cash on hand (including
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maturities of approximately
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. The Company has been, and continues to, explore strategic transactions to address these concerns, while also looking at opportunities to significantly reduce expenses in the near term. In this regard, the Company has considered whether it is advisable to continue to bear the ongoing costs of the listing of its common stock on the NYSE American and of being a reporting Company under the Securities Exchange Act of 1934. The Company believes that it currently qualifies to suspend these obligations should it elect to do so. While such a determination has not yet been made, the Company expects that the cost savings, particularly over the longer term, would be significant. Accordingly, the Company will continue to consider the matter while it simultaneously pursues 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, 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 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
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Capital Expenditures. During 2022, we spent approximately
Debt Obligations. On
On
Current Ratio. Our Current Ratio financial covenant decreased to 0.90 to 1.00
as of
? 2022, and to 0.75 to 1.00 for the quarter ended
1.00 to 1.00 for the quarter ended
thereafter as further described below.
Interest Rate. We converted our benchmark interest rate from LIBOR to a Secured
Overnight Financing Rate (SOFR) plus 0.15% and increased the applicable margin
? on borrowings by 0.50%, such that borrowings under the Amended Term Loan
Agreement will now bear interest at a rate per annum equal to the SOFR
benchmark rate plus 7.65%.
Prepayment Premium. We reset the prepayment periods (for outstanding
? borrowings) beginning on the amendment date with the following prepayment
premiums, subject to the conditions described in the table and further
discussion below: Period (after amendment date) Premium Months 0 - 12 Make-whole amount equal to 12 months of interest plus 2.00% Months 13 - 24 2.00% Thereafter 0.00%
In the following scenarios, our prepayment premiums would differ from those
noted in the table above: (i) if within 6 months after the
As of
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
We are required to make scheduled amortization payments in the aggregate amount
of
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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.
The Amended Term Loan Agreement contains certain financial covenants (as defined), including maintenance of the following rations:
? an Asset Coverage Ratio of not less than 1.80 to 1.00 as of
and each fiscal quarter thereafter;
Total Net Leverage Ratio of not greater than 3.00 to 1.00 as of
? 2022, 2.75 to 1.00 as of
quarter thereafter; and
a Current Ratio of not less than 1.00 to 1.00, each determined as of the last
? day of any fiscal quarter period, other than as amended in
to 0.70 to 1.00 as of
2023.
As of
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.
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
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.
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Cash Flow. Net increase (decrease) in cash, cash equivalents and restricted cash is summarized as follows (in thousands):
Years Ended December 31,
2022 2021
Cash flows provided by (used in) operating $ $
activities 78,801 68,572
Cash flows provided by (used in) investing
activities (126,130) (51,913)
Cash flows provided by (used in) financing
activities 31,786 27,405
Net increase (decrease) in cash, cash $ $
equivalents and restricted cash (15,543) 44,064
Operating Activities. Net cash flows provided by operating activities for the
years ended
Investing Activities. Net cash flows used in investing activities for the years
ended
During the year ended
During the year ended
Financing Activities. Net cash flows provided by financing activities for the
years ended
During the year ended
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
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Oil and Natural Gas Activities
Accounting for oil and natural gas activities is subject to unique rules. Two generally accepted methods of accounting for oil and natural gas activities are available - successful efforts and full cost. The most significant differences between these two methods are the treatment of unsuccessful exploration costs and the manner in which the carrying value of oil and natural gas properties are amortized and evaluated for impairment. The successful efforts method requires unsuccessful exploration costs to be expensed as they are incurred upon a determination that the well is uneconomical while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and natural gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and natural gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using the unweighted arithmetic average of the first day of the month for each of the 12-month prices for oil and natural gas within the period, holding prices and costs constant and applying a 10% discount rate.
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
Our estimated proved reserves for the years ended
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
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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
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
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
Accounting for Derivative Instruments and Hedging Activities
We account for our derivative activities under the provisions of ASC 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 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.
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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
ASC 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
We reported net income (loss) of
Years Ended
December 31,
In thousands (except per unit and per Boe amounts) 2022 2021
Operating revenues:
Oil $ 267,690 $ 213,512
Natural gas 46,210 35,248
Natural gas liquids 43,501 35,394
Other 1,663 1,051
Total operating revenues 359,064 285,205
Operating expenses:
Production:
Lease operating 48,095 43,977
Workover and other 6,683 3,224
Taxes other than income 18,483 12,312
Gathering and other 64,117 60,396
General and administrative:
General and administrative 15,425 14,504
Stock-based compensation 2,210 2,010
Depletion, depreciation and accretion:
Depletion - Full cost 51,020 44,613
Depreciation - Other 367 318
Accretion expense 528 477
Other income (expenses):
Net gain (loss) on derivative contracts (110,006) (125,619)
Interest expense and other (23,591) (8,018)
Gain (loss) on extinguishment of debt - 1,946
Net income (loss) $ 18,539 $ (28,317)
Production:
Crude oil - MBbls 2,837 3,196
Natural gas - MMcf 9,337 9,447
Natural gas liquids - MBbls 1,242 1,157
Total MBoe(1) 5,635 5,928
Average daily production - Boe(1) 15,438 16,241
Average price per unit (2):
Crude oil price - Bbl $ 94.36 $ 66.81
Natural gas price - Mcf 4.95 3.73
Natural gas liquids price - Bbl 35.02 30.59
Total per Boe(1) 63.43 47.93
Average cost per Boe:
Production:
Lease operating $ 8.54 $ 7.42
Workover and other 1.19 0.54
Taxes other than income 3.28 2.08
Gathering and other 11.38 10.19
Restructuring - -
General and administrative:
General and administrative 2.74 2.45
Stock-based compensation 0.39 0.34
Depletion 9.05 7.53
(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
Production for the years ended
Lease Operating Expenses. Lease operating expenses were
Workover and Other Expenses. Workover and other expenses were
Taxes Other than Income. Taxes other than income were
Gathering and Other Expenses. Gathering and other expenses were
General and Administrative Expense. General and administrative expense was
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
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compared to 2021 is primarily due to increased future development costs associated with proved reserve additions relative to the change in proved reserves when comparing 2022 to 2021.
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 loss of
Interest Expense and Other. Interest expense and other was
Gain (Loss) on Extinguishment of Debt. During the year ended
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."
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