SEC Info - White River Energy Corp. - ‘10-Q’ for 9/30/22

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Indicate by checkmark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☐ i No ☒

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). i Yes ☒ No ☐

Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standard provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ i No ☒

As of November 14, 2022, the issuer had i 8,400,000 shares of common stock, $0.0001 par value per share, outstanding.

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT) (UNAUDITED)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this Report as well as the audited consolidated financial statements and notes thereto of Ecoark Holdings, Inc.’s (“Ecoark”) (whose subsidiary, White River Holdings Corp, is the accounting acquirer) included in Ecoark’s Annual Report on Form 10-K for the year ended March 31, 2022 filed July 7, 2022.

This Quarterly Report on Form 10-Q (this “Report”) contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, including statements regarding the planned spin-off by Ecoark of our common stock issuable upon conversion of its preferred stock, our entrance into the oil and gas drilling industry through our acquisition of White River Holdings Corp, the expected results from and trends and developments in our oil drilling and related activities, future plans for and anticipated transactions and relationships with respect to our oil and gas portfolio and operations, our working capital needs, potential financings through the sale of our common stock or other securities, the subsequent use and sufficiency of the proceeds from any capital raising methods we may undertake to fund our operations, our further development and implementation of our business plan and our ability to locate sources of capital necessary to meet our business needs and objectives. All statements other than statements of historical facts contained in this Report, including statements regarding our future financial position, liquidity, business strategy and plans and objectives of management for future operations, are forward-looking statements. The words “believe,” “may,” “estimate,” “continue,” “anticipate,” “intend,” “should,” “plan,” “could,” “target,” “potential,” “is likely,” “will,” “expect” and similar expressions, as they relate to us, are intended to identify forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends that we believe may affect our financial condition, results of operations, business strategy and financial needs.

The results anticipated by any or all of these forward-looking statements might not occur. Important factors, uncertainties and risks that may cause actual results to differ materially from these forward-looking statements include oil and gas price volatility and the continuation of high oil prices, the impact of (i) the Securities and Exchange Commission’s (“SEC”) propose climate change rules on us including enhanced regulatory compliance costs, (ii) future strains of COVID-19, (iii) the Russian invasion of the Ukraine, (iv) inflation and Federal Reserve interest rate increases in response thereto on the economy including any resulting recession, (v) supply chain shortages, (vi) the future prices of, and demand for, oil and gas, our ability to efficiently develop our current oil reserves and economically find or acquire additional recoverable reserves, and (vii) general risks related to drilling operations, together with those described in this Report under Item 1A of Part II – Risk Factors. We may also encounter regulatory delays in causing the registration statement to go effective with the SEC in connection with Ecoark’s planned spin-off of shares of our common stock and the PIPE offering described elsewhere in this Report. We undertake no obligation to publicly update or revise any forward-looking statements, whether as the result of new information, future events or otherwise.

White River Energy Corp (formerly known as Fortium Holdings Corp.) (“WREC” or the “Company”) is a holding company which, beginning in late July 2022, operates in oil and gas drilling through White River Holdings Corp. (“White River”). The Company previously was in the early stages of operations in the online sporting goods space through Norr LLC, and was planning to operate as a retail distributor of cannabis products in California through Elysian Premium Corp. The Norr and Elysian businesses were both sold during September 2022 to allow the Company to focus on its core business in the energy sector, and the divested businesses are therefore not discussed in this section. All operations of the divested entities are reflected as discontinued operations in our condensed consolidated financial statements. For more details on these businesses, see our Annual Report on Form 10-K for the year ended December 31, 2021.

On September 28, 2022, we changed our fiscal year end of White River Energy Corp from December 31 to March 31 to coincide with White River’s fiscal year end. On October 28, 2022, we filed an Amendment to our Current Report on Form 8-K/A disclosing the White River acquisition which filed as exhibits the historical financial statements for White River for the years ended March 31, 2022 and 2021 and the three months ended June 30, 2022 and June 2021.

On July 25, 2022, the Company entered into a Share Exchange Agreement with Ecoark and White River pursuant to which the Company acquired White River from Ecoark and in exchange issued Ecoark 1,200 shares of a new series of Series A Convertible Preferred Stock of the Company (the “Series A”). The transaction was treated as a business combination. Ecoark funded White River with $3 million in cash which was held by White River at the time of the business combination to ensure there was no lapse in White River’s ongoing business operations.

The Series A is non-voting, has a stated value of $30 million, and is convertible into 42,253,521 shares of the Company’s common stock, provided that the Series A will only become convertible if and when a Registration Statement on Form S-1 filed by the Company for the purpose of effecting a spin-off of the Company’s common stock to Ecoark’s stockholders has been filed and declared effective by the SEC, and Ecoark elects to effect said spin-off. The Company has been informed that Ecoark intends to effect the spin-off as soon as practicable following the closing of the business combination and the closing of its PIPE offering. Ecoark’s two senior management members were appointed to be the initial executive management team of the Company following the White River acquisition. Our Executive Chairman, Randy May, is one of five directors, his daughter Alisa Horgan is a new director and he recommended the other three new directors. Our previous sole officer and director, Richard Horgan, is Mr. May’s son-in-law.

Following the business combination, our principal operations consist of generating revenue through oil and gas exploration, production and drilling. Through White River the Company is now engaged in oil and gas exploration, production, and drilling operations on over 30,000 cumulative acres of active mineral leases in Louisiana, and Mississippi. These subsidiaries are each engaged in oil and natural gas development, production, acquisition, and exploration activities principally in the above-referenced states. We may also expand our energy asset portfolio or engage in other energy-related strategic transactions as they arise, provided we have sufficient capital and market and regulatory conditions otherwise enable us and/or are favorable to such transactions. Such transactions may serve a number of business objectives, including by seeking to expand our product and service offerings and/or to increase our geographic footprint.

Immediately following the White River acquisition, the Company designated a new Series B Preferred Stock with the purpose of allowing the Company’s Board of Directors to potentially ward off any potential hostile takeover attempts on the Company at a valuation that is deemed sub-optimal to stockholders by the Company’s Board of Directors. See Note 1 to the condensed consolidated financial statements for additional information.

Through White River and its subsidiaries listed below, we are engaged in oil and gas exploration, production, and drilling operations on over 30,000 cumulative acres of active mineral leases in Louisiana, and Mississippi. White River owns the following subsidiaries in the following sub-categories:

Passive entities holding working interests in successfully completed oil and gas wells:

White River has recently formed an affiliated entity called White River E&P 1 LP (“WR Fund #1”) which will consist of private external general and limited partners consisting of retail accredited and institutional investors who have or will advance proceeds to the fund in exchange for partnership interests therein. WR Fund #1 Manager is the managing General Partner of WR Fund #1. WR Fund #1 is currently offering up to 4,000 units of partnership interest at a price per unit of $50,000 with a minimum investment of 1 unit or $50,000 through a 5-year closed-end fund structure. The fund is expected to close to new investors at the earlier of June 30, 2023 or the sale of all 4,000 units. Mr. May, our Executive Chairman and Mr. Puchir, our Chief Executive Officer are also serving in the roles as Co-Fund Managers of WR Fund #1 Manager. Proceeds of the fund will be intended to be used in drilling White River drilling projects whereby White River will receive a 25% promoted working interest and WR Fund #1 Manager will receive a 10% carried working interest at the successful closure of the fund and 1% annual management fee. White River has made a commitment to acquire the partnership interest of all investor partners in WR Fund #1 at the end of the fund’s 5-year term at the PV20 valuation generated by an independent valuation firm subject to the cash availability of White River.

While the Company anticipates collaborating with WR Fund #1 in pursuing oil and gas ventures that are mutually beneficial to both entities, conflicts of interest may arise. See “Risk Factors” below for more information. The Company has no equity ownership of WR Fund #1 but expect to provide drilling services for a fee and receive management fees.

In 2022, data indicates a sharp rise in inflation in the U.S. and globally. In the U.S., inflation has been triggered by constrained supplies and increasing demand of certain goods and services as recovery from the COVID-19 pandemic continues. The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and natural gas industry, and allied industries rather than by changes in general inflation. Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels, the Biden Administration’s efforts to reduce drilling and hydraulic fracturing and transition away from fossil fuels and/or attitudes of traders concerning supply and demand in the future. Prices for oil and gas related services are also affected by the worldwide prices for crude oil. As a result of increasing prices for oil and natural gas in 2021 and 2022 and general inflation, higher costs for goods and services in the oil and gas industry are being observed.

In response to recent inflationary pressures in the U.S., the Federal Reserve commenced interest rate hikes in calendar year 2022 in an effort to combat inflation. Because of these and other developments, a recession is expected in the coming months by many economic analysts, which may, among other things, reduce demand for the oil we drill as well as increase operating costs to the extent we are unable to procure required resources to continue our operations.

As a result of the overall volatility of oil prices, it is not possible to predict the Company’s future cost of oil it produces or services it uses or provides.

COVID-19 may continue to affect the economy and the industry in which we operate, depending on the vaccine rollouts and the emergence of virus mutations as well as the impact of supply chain disruptions.

COVID-19 did not have a material effect on the Consolidated Statements of Operations or the Consolidated Balance Sheets for the six and three months ended September 30, 2022 or 2021 included in this Report.

Because of the possibility of new variants of the virus and any governmental or economic reactions that may result, there is inherent uncertainty on whether any such developments could disrupt the operation of the Company’s business and have an adverse effect on the Company. Additionally, COVID-19 has been a contributing factor in supply shortages which have been pervasive in many industries. The extent to which the COVID-19 outbreak and other adverse developments may impact the Company’s results will depend on future developments that are highly uncertain and cannot be predicted, including new information that may emerge concerning the severity of the virus and the actions to contain its impact.

In early March 2020, oil prices dropped sharply and continued to decline, with oil futures briefly reaching negative levels as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken by OPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the ongoing COVID-19 pandemic. However, certain restrictions on conducting business that were implemented in response to the COVID-19 pandemic have been lifted as improved treatments and vaccinations for COVID-19 have been rolled-out globally since late 2020. As a result, oil and natural gas market prices have improved in response to the increase in demand and global and United States reductions in drilling. However, in recent periods oil and natural gas prices have experienced increased volatility due to the uncertainty arising from prior variants of the virus and other factors.

During 2020 and 2021, the posted NYMEX WTI price for crude oil ranged from $(37.63) to $84.65 per Bbl. On September 30, 2022, the NYMEX WTI price for crude oil was $79.49 per Bbl. Commodity prices have historically been volatile and we cannot predict events which may lead to future fluctuations in these prices.

In connection with the management of our businesses, we identify, measure and assess a variety of operating metrics. In the Commodities segment, the principal metrics we use in managing our businesses are set forth below:

“Bbl” – Bbl means barrel of crude oil. Metric used by management to specify the unit of measure (“in barrels”) from which the Company’s midstream customers use to incrementally purchase oil from the Company. Barrels are used as a unit of measure universally across the oil industry so the Company’s adoption of barrels to measure units of oil is a standard practice.

“Mbbl” – Mbbl means a thousand barrels of oil. See comments on “Bbl” metric. “Mbbl” is a standard for measuring larger quantities of barrels of oil in thousands of units.

“Production (Gross)” – Production (Gross) is defined as barrels of oil produced before accounting for working interests from non-mineral owning parties. Metric used by management to specify the total number of barrels of oil produced from a given oil well. Gross production includes both the barrels owned by the oil and gas mineral owners as well as the drilling and investing group who funded and drilled the well which are considered the working interest owners. Gross production is a standard term used universally across the oil industry, so the Company’s adoption of this term is a standard practice.

“Production (Net)” – Production (Net) is defined as the net barrels of oil produced after deducting the ownership portion owned by the mineral owning parties. Unless otherwise specified, management assumes that the mineral ownership portion of a well is 25%, so a 100% working interest would result in a 75% Net Production or Net Revenue interest after accounting for the ownership portion of oil production owned by the mineral owners.

The critical accounting policies listed below are those the Company deems most important to their operations.

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the U.S. requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and reported amounts of revenues and expenses during the reporting period. These estimates include, but are not limited to, management’s estimate of provisions required for uncollectible accounts receivable, fair value of assets held for sale and assets and liabilities acquired, impaired value of equipment and intangible assets, including goodwill, asset retirement obligations, estimates of discount rates in lease, liabilities to accrue, fair value of derivative liabilities associated with warrants, cost incurred in the satisfaction of performance obligations, permanent and temporary differences related to income taxes and determination of the fair value of stock awards.

The estimates of proved, probable and possible oil and gas reserves are used as significant inputs in determining the depletion of oil and gas properties and the impairment of proved and unproved oil and gas properties. There are numerous uncertainties inherent in the estimation of quantities of proven, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized.

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under the full cost method of accounting, all costs associated with acquisition, exploration and development of oil and gas reserves, including directly related overhead costs are capitalized. General and administrative costs related to production and general overhead are expensed as incurred.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit of production method using estimates of proved reserves. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in operations. Unproved properties and development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the loss from operations before income taxes and the adjusted carrying amount of the unproved properties is amortized on the unit-of-production method.

Under the full-cost method of accounting, we are required, at the end of each reporting period, to perform a test to determine the limit on the book value of our oil and gas properties (the “Ceiling” test). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the Ceiling, the excess or impairment is charged to expense. The expense may not be reversed in future periods, even though higher oil and gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10% and assuming continuation of existing economic conditions, of (1) estimated future gross revenues from proved reserves, which is computed using oil and gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month hedging arrangements pursuant to Staff Accounting Bulletin (“SAB”) 103, less (2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus, (b) the cost of properties being amortized; plus, (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties.

Reserve engineering is a subjective process that is dependent upon the quality of available data and interpretation thereof, including evaluations and extrapolations of well flow rates and reservoir pressure. Estimates by different engineers often vary sometimes significantly. In addition, physical factors such as results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using recent prices of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.

Certain of our exploration, development and production activities are conducted jointly with other entities and, accordingly, the consolidated financial statements reflect only our proportionate interest in such activities.

Crude oil, products and merchandise inventories are carried at the lower of cost (last-in-first-out (LIFO)) or net realizable value. Inventory costs include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location.

Asset retirement obligations (“ARO”) primarily represent the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the projected end of their productive lives, in accordance with applicable federal, state and local laws. The Company determined its ARO by calculating the present value of the estimated cash flows related to the obligation. The retirement obligation is recorded as a liability at its estimated present value as of the obligation’s inception, with an offsetting increase to proved properties or to exploration costs in cost of revenues.

The Company accounts for revenue in accordance with ASC Topic 606, Revenue from Contracts with Customers.

The core principle of the revenue standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The following five steps are applied to achieve that core principle:

● Step 4: Allocate the transaction price to the performance obligations in the contract

● Step 5: Recognize revenue when the Company satisfies a performance obligation

In order to identify the performance obligations in a contract with a customer, a company must assess the promised goods or services in the contract and identify each promised good or service that is distinct. A performance obligation meets ASC 606’s definition of a “distinct” good or service (or bundle of goods or services) if both of the following criteria are met: The customer can benefit from the good or service either on its own or together with other resources that are readily available to the customer (i.e., the good or service is capable of being distinct), and the entity’s promise to transfer the good or service to the customer is separately identifiable from other promises in the contract (i.e., the promise to transfer the good or service is distinct within the context of the contract).

If a good or service is not distinct, the good or service is combined with other promised goods or services until a bundle of goods or services is identified that is distinct.

The transaction price is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer. The consideration promised in a contract with a customer may include fixed amounts, variable amounts, or both. When determining the transaction price, an entity must consider the effects of all of the following:

Variable consideration is included in the transaction price only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. The transaction price is allocated to each performance obligation on a relative standalone selling price basis. The transaction price allocated to each performance obligation is recognized when that performance obligation is satisfied, at a point in time or over time as appropriate.

The Company accounts for contract costs in accordance with ASC Topic 340-40, Contracts with Customers. The Company recognizes the cost of sales of a contract as expense when incurred or at the time a performance obligation is satisfied. The Company recognizes an asset from the costs to fulfil a contract only if the costs relate directly to a contract, the costs generate or enhance resources that will be used in satisfying a performance obligation in the future and the costs are expected to be recovered. The incremental costs of obtaining a contract are capitalized unless the costs would have been incurred regardless of whether the contract was obtained.

The Company recognizes revenue for their proportionate share of revenue when: (i) the Company receives notification of the successful sale of a load of crude oil to a buyer; (ii) the buyer will provide a price based on the average monthly price of crude oil in the most recent month; and (iii) cash is received the following month from the crude oil buyer.

The accounting guidance defines fair value, establishes a consistent framework for measuring fair value and expands disclosure for each major asset and liability category measured at fair value on either a recurring or non-recurring basis. Fair value is defined as an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, the accounting guidance establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 2: Inputs, other than the quoted prices in active markets that are observable either directly or indirectly.

Level 3: Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

The carrying values of the Company’s financial instruments such as cash, investments, accounts payable, and accrued expenses approximate their respective fair values because of the short-term nature of those financial instruments.

Management reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to undiscounted future cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets.

The Company does not use derivative instruments to hedge exposures to cash flow, market, or foreign currency risks. Management evaluates all of the Company’s financial instruments, including warrants, to determine if such instruments are derivatives or contain features that qualify as embedded derivatives. The Company generally uses a Black-Scholes model, as applicable, to value the derivative instruments at inception and subsequent valuation dates when needed. The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is re-measured at the end of each reporting period. The Black-Scholes model is used to estimate the fair value of the derivative liabilities.

In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-06, Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40), Accounting for Convertible Instruments and Contract’s in an Entity’s Own Equity. The ASU simplifies accounting for convertible instruments by removing major separation models required under current GAAP. Consequently, more convertible debt instruments will be reported as a single liability instrument with no separate accounting for embedded conversion features. The ASU removes certain settlement conditions that are required for equity contracts to qualify for the derivative scope exception, which will permit more equity contracts to qualify for it. The ASU simplifies the diluted net income per share calculation in certain areas.

The ASU is effective for annual and interim periods beginning after December 31, 2021, and early adoption is permitted for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. The Company does not believe this new guidance will have a material impact on its consolidated financial statements.

In May 2021, the Financial Accounting Standards Board (“FASB”) issued ASU 2021-04 “Earnings Per Share (Topic 260), Debt—Modifications and Extinguishments (Subtopic 470-50), Compensation— Stock Compensation (Topic 718), and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815- 40) Issuer’s Accounting for Certain Modifications or Exchanges of Freestanding Equity-Classified Written Call Options” which clarifies and reduces diversity in an issuer’s accounting for modifications or exchanges of freestanding equity-classified written call options (for example, warrants) that remain equity classified after modification or exchange. An entity should measure the effect of a modification or an exchange of a freestanding equity-classified written call option that remains equity classified after modification or exchange as follows: i) for a modification or an exchange that is a part of or directly related to a modification or an exchange of an existing debt instrument or line-of-credit or revolving-debt arrangements (hereinafter, referred to as a “debt” or “debt instrument”), as the difference between the fair value of the modified or exchanged written call option and the fair value of that written call option immediately before it is modified or exchanged; ii) for all other modifications or exchanges, as the excess, if any, of the fair value of the modified or exchanged written call option over the fair value of that written call option immediately before it is modified or exchanged.

The amendments in this Update are effective for all entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. An entity should apply the amendments prospectively to modifications or exchanges occurring on or after the effective date of the amendments. The Company does not believe this new guidance will have a material impact on its consolidated financial statements.

The Company does not discuss recent pronouncements that are not anticipated to have an impact on or are unrelated to its financial condition, results of operations, cash flows or disclosures.

The following tables set forth our production data for the six months ended September 30, 2022 and 2021:

The following tables set forth our production data for the three months ended September 30, 2022 and 2021:

Results of Operations For Continuing Operations For the Six Months Ended September 30, 2022 and 2021

Revenues for the six months ended September 30, 2022 of $2,208,760 compared to the six months ended September 30, 2021 of $2,303,071, reflected a slight decrease of $94,311. The decrease is primarily related to a decline in the average barrel price of oil period over period, and less production out of some of our wells as we completed some repairs intended to enable greater production.

The following table shows costs and expenses for the six months ended September 30, 2022 and 2021:

Costs and expenses in the six months ended September 30, 2022 increased by $9,953,886 when compared to the six months ended September 30, 2021, primarily from the increase of $3,627,980 in oilfield costs as we repaired some wells in an effort to increase production. In addition, we increased labor in the fields contributing to the $1,109,066 increase in salaries and salaries related costs. Our general and administrative costs were consistent period over period, and in the periods ended 2022 and 2021 we recognized impairment, thus the depreciation, amortization, depletion, accretion and impairment costs increased $4,968,134 in the 2022 period from the same period in 2021.

The following table shows other income (expense) for the six months ended September 30, 2022 and 2021:

Total other income decreased $1,242,014 in 2022 from the same period in 2021. The 2021 change in the derivative liability and the interest expense was the result of a cost allocation from Ecoark to White River in accordance with SAB Topic 1.B.1. In both 2022 and 2021 we recognized gains on sales of oil and gas reserves.

Net loss from continuing operations for 2022 was $(13,135,416) as compared to net loss from continuing operations of $(1,614,703) for 2021. The increase in net loss was primarily due to non-cash charges of almost $5 million, and the oilfield repair work completed in 2022. While the work performed is intended and expected to increase production on the applicable wells, no assurances can be given that the increased production will offset the expenses incurred in the short-term or at all, including due to fluctuations in oil prices over time and other factors beyond our control. See “Risk Factors” for more information.

Results of Operations For Continuing Operations For the Three Months Ended September 30, 2022 and 2021

Revenues for the three months ended September 30, 2022 of $594,485 compared to the three months ended September 30, 2021 of $728,667, reflected a decrease of $134,182. The decrease is primarily related to a decrease in the average barrel price of oil period over period, and less production out of some of our wells as we completed some repairs intended to enable greater production.

The following table shows costs and expenses for the three months ended September 30, 2022 and 2021:

Costs and expenses in 2022 increased $8,669,883, primarily from the increase of $2,456,511 in oilfield costs as we repaired some wells to increase production. In addition, we increased labor in the fields contributing to the $945,634 increase in salaries and salaries related costs. Our general and administrative costs were very consistent period over period showing a decrease in these expenses of $340,005 in 2022 compared to 2021, and in 2022 we reflected greater depletion and impairment which lead to an increase in these expenses of $5,566,105 period over period.

The following table shows other income (expense) for the three months ended September 30, 2022 and 2021:

Total other income increased $518,164 in 2022 form the same period in 2021. The 2021 change in the derivative liability and the interest expense was the result of a cost allocation from Ecoark to White River in accordance with SAB Topic 1.B.1. In both 2022 and 2021 we recognized gains on sales of oil and gas reserves.

Net loss from continuing operations for 2022 was $(11,148,872) as compared to net loss from continuing operations of $(2,632,469) for 2021. The increase was primarily due to the oilfield repair work completed in 2022 and the impairment on the reverse merger.

Liquidity is the ability of a company to generate funds to support its current and future operations, satisfy its obligations, and otherwise operate on an ongoing basis. Significant factors in the management of liquidity are revenue generated from operations, levels of accounts receivable and accounts payable and capital expenditures.

Net cash (used in) provided by operating activities for continuing operations was $(2,689,794) for the six months ended September 30, 2022, as compared to $327,795 for the same period in 2021. Cash used in operating activities for the six months ended September 30, 2022 was primarily caused by the $13,135,416 net loss from continuing operations including offset by the changes in current assets and liabilities and the stock-based compensation of $657,935 and impairment of $5,917,843. In the 2021 period, the changes in operating activities related to the net loss from continuing operations of $1,614,703 offset by the changes in accounts payable and the amounts that were due to Ecoark.

Net cash used in investing activities was $89,353 for the six months ended September 30, 2022, compared to $301,000 for the six months ended September 30, 2021. Net cash used in investing activities in the six months ended September 30, 2022 were comprised of proceeds received from the sale of equipment, net of purchases, and advances of $200,000 in notes receivable. In the 2021 period, the cash used in investing activities related to purchases of oil and gas properties, offset slightly by sales of fixed assets.

Net cash provided by (used in) financing activities for the six months ended September 30, 2022 was $3,107,454 which comprised of $3,000,000 in cash transferred to White River from Ecoark which was a condition of such acquisition, $145,266 in proceeds from long-term debt, offset by repayments of long-term debt and a decrease in a cash overdraft. In 2021, we used $26,387 in cash flows from financing activities related to the decrease in a cash overdraft. Subsequent to September 30, 2022, we closed on a private investment in public equity (“PIPE”) for approximately $4,000,000 with accredited investors. Investors in the PIPE received units of Series C preferred stock and 200% warrant coverage on their investments. See Subsequent Events in the condensed consolidated financial statements for additional information.

As of November 10, 2022, the Company has approximately $2,750,000 in cash and cash equivalents. The Company believes this cash is sufficient to meet our cash needs for the 12 months following the filing of this Report.

The Company has continuous drilling requirements to drill or re-complete a well on its 9,615 Peabody Blackhawk lease every 270 days to keep the lease active. The Company drilled and completed a well in February 2022 on this oil and gas mineral lease and extended the lease to at least November 2022. Depending on the formation drilled, the costs could be as high as approximately $2,000,000. In this event, we would likely seek significant partners to share the cost. We have already orally agreed to afford the Ault Energy, LLC a 25% participation right in future wells we drill. Ault Energy, LLC is a subsidiary of BitNile Holdings, Inc. which invested $12 million in Ecoark in June 2022.

The Company has undertaken the following financing transactions to raise capital needed to continue its operations and execute its business plan.

On October 13, 2022, White River Operating LLC, an indirect subsidiary of the Company, issued a $1,500,000 secured promissory note, which was used for the two workover rigs purchased (total value of $1,800,000, where the Company paid a total of $300,000). The note bears interest at the lesser of (i) the prime rate published in the “Bonds, Rates and Yields” section of The Wall Street Journal plus 7.50%; and (ii) the maximum rate permitted by applicable law, and payments consist of interest and principal in the amount of $25,000 per month through October 13, 2025 when the remaining balance of principal and interest is due. Randy May and Jay Puchir executed and delivered guarantees in favor of the lender to secure this note.

From October 19, 2022 through November 8, 2022, the Company entered into a Securities Purchase Agreement (“SPA”) with accredited investors (the “Purchasers”) whereby the Purchasers agreed to purchase a total of 182.6419972 Units from the Company, with each Unit consisting of one share of a newly-designated Series C Convertible Preferred Stock (the “Series C”) and five-year Warrants to purchase up to 200% of the shares of Common Stock issuable upon conversion of the Series C (the “Warrants”), at a purchase price of $25,000 per Unit for a total purchase price of $4,566,050, of which the Company has received $4,531,050 as of November 8, 2022 (the “PIPE Offering”). The net proceeds from the PIPE Offering, after offering expenses and related costs, will be used for working capital and general corporate purposes including oil and gas drilling on the Company’s working interests in Louisiana and Mississippi. The terms of the securities sold in the PIPE Offering are outlined under “Note 18 – Subsequent Events.”

In conjunction with the approximately $4.5 million received as of November 8, 2022 in the PIPE Offering described above, White River plans to initiate a long-term business strategy to focus on sourcing capital for its current and future drilling projects through WR Fund #1 in a non-dilutive manner to stockholders as opposed to equity financing through common or preferred stock issuances from WREC.

As consideration for managing WR Fund #1, WR Fund #1 Manager will receive a 1% annual management fee and a promoted working interest and carried working interest on successfully completed drilling projects. See above under “White River Energy Corp Subsidiaries.”

We are required to maintain “disclosure controls and procedures” as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on his evaluation as of the end of the period covered by this Quarterly Report on Form 10-Q, Mr. Jay Puchir, who is presently serving as our Chief Executive Officer and Principal Financial Officer has concluded that our disclosure controls and procedures were not effective to ensure that the information relating to our company, required to be disclosed in our SEC reports (i) is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and (ii) is accumulated and communicated to our management, including our Chief Executive Officer, to allow timely decisions regarding required disclosure as a result of material weaknesses in our internal control over financial reporting.

There have been no changes in our internal control over financial reporting during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

From time-to-time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. As of the date of this Report, we are not aware of any other pending or threatened lawsuits that could reasonably be expected to have a material effect on the results of our operations and there are no proceedings in which any of our directors, officers or affiliates, or any registered or beneficial shareholder, is an adverse party or has a material interest adverse to our interest.

We cannot predict our future results because we have a limited operating history, both as a standalone oil and gas company and in general.

In July 2022, we acquired our oil and gas business, which presently comprises all of our operations and revenue. In September 2022, we sold our legacy businesses, which consisted of a small online sporting goods and apparel sales business and a development stage cannabis business. Further, White River’s oil and gas operations are also relatively new, and until we acquired the business from Ecoark Holdings, Inc. (“Ecoark”), had operated as a portion of a larger public holding company with greater diversification and access to capital. Given our limited operating history both as a standalone company, in our newly acquired oil and gas business, and in general, it may be difficult to evaluate our future performance or prospects. You should consider the uncertainties that we may encounter as a company that should still be considered an early-stage oil and gas company. These uncertainties include:

If we are not able to address successfully some or all of these uncertainties, we may not be able to expand our business, compete effectively or achieve profitability.

We had incurred net losses on an annual basis since our inception and may continue to experience losses and negative cash flow in the future.

As of November 10, 2022, we had cash (not including restricted cash) of approximately $2,750,000. We have not been profitable on an annual basis since inception and had previously incurred significant operating losses and negative cash flow from operations. We recorded a net loss of approximately $6,922,753 and $9,756,222 for the fiscal years ended March 31, 2022 (FY 2022) and 2021 (FY 2021). We will likely continue to incur losses and experience negative cash flows from operations for the foreseeable future. If we cannot achieve positive cash flow from operations or net income, it may make it more difficult to raise capital based on our common stock on acceptable terms.

Because we may require additional capital to fund our business objectives and support our growth, our inability to generate and obtain such capital could harm our business, operating results, financial condition and prospects.

Since March 27, 2020, White River Holdings Corp, our new subsidiary, increased its operating expenses in supporting its business of oil and gas exploration and drilling and consummating acquisitions of oil and gas properties. Following our acquisition from Ecoark, we intend to continue to make substantial investments to fund our business and support our growth. Although we recently raised approximately $4,500,000 in a private placement, we may desire to increase our drilling activity or acquire additional oil and gas properties. In addition, a subsidiary is seeking to raise capital for an oil and gas drilling fund in which we will be the managing general partner.

If we are unable to obtain adequate financing, our ability to continue to support our business growth and to respond to business challenges could be significantly impaired, and our business may be adversely impacted. In addition, our inability to generate or obtain the financial resources needed may require us to delay, scale back, or eliminate some or all of our operations and business objectives and sell some of our assets.

Further, if we (as contrasted to the drilling fund discussed in this Report) raise additional funds through future issuances of equity or convertible debt securities, our existing stockholders could suffer significant dilution, and any new equity or debt securities we issue could have rights, preferences and privileges superior to those of holders of our common stock.

From time-to-time, we may need to access capital markets to obtain long-term and short-term financing. However, our ability to access capital markets could be limited or adversely affected by, among other things, oil and gas prices, interest rates, our asset base, our track record in the industry, and the health or market perceptions of the drilling and overall oil and gas industry and the global economy. In addition, many of the factors that affect our ability to access capital markets, including the liquidity of the overall capital markets and the state of the economy and/or the oil and gas industry, among others, are outside of our control. There have also been efforts in recent years aimed at the investment community, including leading investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities as well as pressuring lenders and other financial services companies to limit or curtail activities with companies engaged in the extraction of fossil fuel reserves, which, if successful, could limit our ability to access capital markets. No assurance can be given that we will be able to access capital markets on terms acceptable to us when required to do so, which could adversely affect our business, financial condition and results of operations.

Since the Company’s Executive Chairman and Chief Executive Officer are involved in other oil and gas ventures, and received certain interests and rights in our oil and gas drilling and production efforts pursuant to their employment agreements, conflicts of interest may arise.

Each of Randy May, the Company’s Executive Chairman, and Jay Puchir, the Company’s Chief Executive Officer, are involved in a new oil and gas venture in which they are the managers of a Company subsidiary, which is the managing general partner of a fund formed to invest in various oil and gas exploration and production ventures (the “Fund”). The Company will act as the driller for the Fund and expects to receive management fees. While the Company’s management believes working with the Fund will benefit the Company, the Company and the Fund may compete with each other in drilling opportunities which creates a conflict of interest. To the extent that we have capital available to invest in drilling for our own account and the Fund participates either with us, or separately, to the extent that a well is successful, this conflict can adversely affect us. At the same time, we benefit if the well is not successful.

Additionally, pursuant to their respective employment agreements, each of Messrs. May and Puchir were granted a 5% overriding royalty interest from the Company and its subsidiaries in any and all successfully drilled and completed oil and/or gas wells, as well a participation right of 15% and 10%, respectively, in the funding and ownership interest in any drilling or participation by the Company or any subsidiary in the drilling by a third party of an oil and gas well, which does not include the Fund but will include any other investment funds the Company sponsors. The initial terms of their employment agreements are five years, subject in each case to possible renewal. While these arrangements are intended to directly align these officers’ incentives with the Company’s oil and gas exploration, drilling and production efforts by compensating them for the success of such ventures, they also directly divert any revenue generated by these ventures to these officers and away from the Company, which may be adverse to the Company and its shareholders. For example, a well that could have been profitable, or our operations as a whole, may not be profitable where they otherwise would have been as a result of the rights we have provided to these individuals. Mr. May also has personal oil and gas investments which may also compete with the Company. These conflicts of interest may adversely affect our operations and financial condition, divert management’s time and attention away from running our primary business and result in our management to providing business opportunities to the Fund instead of the Company, any of which could materially adversely affect us.

Any of these or other endeavors that those involved in our operations chooses to pursue could materially harm our operations and ability to execute our business plan.

Because we have agreed with the Fund that we will redeem all of its partners in five years, we may not have the capital to meet this obligation.

In order to attract investors to the Fund, we agreed to redeem all of its partners (other than our subsidiary which is the managing general partner) five years after it terminates its offering which will be not later than but possibly earlier than June 30, 2023. The Fund is seeking to raise up to $200 million, and as of the date of this Report has raised $3,000,000. The redemption will be based upon a 20% discount to an industry formula. We cannot predict what our financial condition or oil and drilling business will be on the redemption date. We may have to engage in financing activities which will be very unfavorable to us including indebtedness with high interest and other unfavorable terms. If we fail to meet our redemption obligation, we may cease operations.

We have significant ongoing capital requirements that could affect our operations if we are unable to generate sufficient cash from operations or obtain financing on favorable terms.

The Company’s drilling plan entails extracting oil reserves across its over 30,000 acres of shallow and deep drilling rights. The Company recently bought a deep drilling rig to further vertically integrate its operations. However, with historically high oil prices, ancillary services related to drilling and producing oil wells have risen significantly. While the Company is largely vertically integrated, it still relies on third parties for certain functions, including obtaining and deploying concrete and wire lining to evaluate the potential for production of a drill site and commencing oil producing operations.

We expect to pay for projected capital expenditures related to exploring and drilling additional oil wells with cash flows from operations or the proceeds from equity sales, including the Company’s recent financings. If we were unable to generate sufficient cash from operations, we would need to seek alternative sources of capital, including financing, to meet our capital requirements. To the extent that our working capital is insufficient, we may have to scale back operations including our drilling activity.

Since analyzing a well’s potential is very risky, our management may make errors in assessing the potential of wells which could lead to limited revenue.

In our efforts to acquire, explore, and drill interests in oil and gas wells, management will assess reports about the recoverable reserves, future oil and gas prices, operating costs, potential liabilities, and other factors relating to the wells. These assessments are necessarily inexact, and their accuracy is inherently questionable and uncertain. The review of a subject property in connection with its acquisition assessment may not reveal all existing or potential problems or permit it to become sufficiently familiar with the property to fully assess its deficiencies and capabilities. Management and other personnel involved in the process may not inspect every well, and may not be able to observe structural and environmental problems even if it does inspect a well. If problems are identified, various affiliates, vendors, contractors, or third parties may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on the Company’s financial condition, and future results of operations.

Unless we develop new reserves, reserves we acquire and subsequent production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proven reserves, our proven reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently and economically finding or acquiring recoverable reserves. We may not be able to develop, find or acquire sufficient reserves to replace our current and future production. Further, our projections about a well’s production prospects could prove to be incorrect. For example, in late 2022 a number of U.S.-based oil and gas companies have produced less oil than expected, and adjusted there production estimates downward as a result. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected. If our estimates provide to be incorrect now or in the future, for some or all of the wells we are exploring and producing from, it could materially adversely affect our operating results.

Since our exploration and production operations are subject to stringent environmental, oil and gas-related and occupational safety and health laws and regulations, noncompliance with such laws and regulations could expose us to material costs and liabilities.

Our exploration and production operations are subject to stringent federal, state and local laws and regulations governing, among other things, the drilling activities, production rates, the size and shape of drilling and spacing units or proration units, the transportation and sale of crude oil, gas, and the discharging of materials into the environment and environmental protection. These laws and regulations may limit the amount of oil and gas we can produce or limit the number of wells or the locations where we can drill.

Further, we are required to obtain and maintain numerous environmental and oil and gas-related permits, approvals and certificates from various federal, state and local governmental agencies in connection with our exploration and production operations, and may incur substantial costs in doing so. If we acquire gas wells we may in the future be charged royalties on gas emissions or required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. Additionally, our operations are subject to a number of federal and state laws and regulations, including the federal occupational safety and health and comparable state statutes, aimed at protecting the health and safety of employees.

Another significant risk inherent in drilling plans is the need to obtain drilling permits from local, state, federal and other governmental authorities, as appropriate. Delays in obtaining regulatory approvals and drilling permits, including delays which jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have materially adverse effects on our ability to capitalize on proposed projects. As long as the Biden Administration or a successor Democratic Administration holds the Office of President, we expect the permitting process on federal lands will be marked by delays and refusals.

Although we will use third party contractors to handle delivery of crude oil and by-products, we may be subject to environmental liabilities for the acts of the contractors arising from the hauling and handling of hazardous materials, air emissions from our vehicles and facilities, and engine idling and discharge. Our operations involve the risks of environmental damage and hazardous waste disposal, among others. If we are involved in an accident involving hazardous substances, if there are releases of hazardous substances we transport, if soil or groundwater contamination is found at our facilities or results from our operations, or if we are found to be in violation of applicable environmental laws or regulations, we could owe clean-up costs and incur related liabilities, including substantial fines or penalties or civil and criminal liability, any of which could have a materially adverse effect on our business and operating results.

Failure to comply with these laws and regulations may subject us to sanctions, including administrative, civil or criminal penalties, remedial clean-ups or corrective actions, delays in permitting or performance of projects, natural resource damages and other liabilities. In addition, these laws and regulations may be amended and additional laws and regulations may be adopted in the future with more stringent legal requirements.

Our operations may generate waste that may be subject to the Federal Resource Conservation and Recovery Act (“RCRA’) and comparable state statutes. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous waste. Furthermore, certain wasted generated by natural gas and oil operations that are currently exempt from treatment as hazardous waste may in the future be designated as hazardous waste and therefore become subject to more rigorous and costly operating and disposal requirements.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on specified classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. These classes of persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Our operations also may become subject to the Clean Air Act (“CAA”) and comparable state and local requirements. In 1990, Congress adopted amendments to the CAA containing provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions. The EPA and states have developed and continue to develop regulations to implement these requirements. We are also subject to a variety of federal, state, local and international permitting and registration requirements relating to protection of the environment. While the Company believes it is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on its operations, but it cannot be certain.

Legislation, regulations or government actions related to climate change, greenhouse gas emissions and sustainability initiatives and other “ESG” laws, regulations and government action, could result in increased compliance and operating costs and reduced demand for fossil fuels, and concern in financial and investment markets over greenhouse gasses and fossil fuel production could adversely affect demand for our products, limit our access to capital and materially and adversely affect our future operating results.

As described above, our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. The trend in recent years has been increased scrutiny and regulatory oversight of the oil and gas industry, including among other things increasingly the proposal of new laws and regulations aimed at reducing or restricting oil and gas production and use. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. In addition, failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and fines. Some of the recent government undertakings which may apply to the oil and gas industry are outlined in the paragraphs that follow.

Since he took office in January 2021, President Biden has signed a series of executive orders seeking to adopt new regulations to address climate change and to suspend, revise, or rescind certain prior agency actions which were part of the Trump Administration’s de-regulatory push, including oil drilling. The Biden Administration is expected to continue to aggressively seek to regulate the energy industry and has stated its goal to eliminate fossil fuels. The new executive orders include, among other things, orders requiring a review of current federal lands leasing and permitting practices, as well as a temporary halt of new leasing of federal lands and offshore waters available for oil and gas exploration, directing federal agencies to eliminate subsidies for fossil fuels, and to develop a plan to improve climate-related disclosures. Federal agencies including the Environmental Protection Agency (“EPA”) and the Securities and Exchange Commission (the “SEC”) have followed suit in pushing ahead with new regulations which will adversely affect our future business, as more particularly described below.

In January 2021, President Biden also issued an executive order calling for methane emissions regulations to be reviewed and for the EPA to establish new standards by September 2021. This resulted in the EPA finalizing what it refers to as “the most ambitious federal greenhouse gas emissions standards for passenger cars and light trucks ever” in December 2021. The EPA has also adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (the “PSD”), construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their greenhouse gas emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. The EPA also has adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore natural gas and oil production sources in the United States on an annual basis, which include certain of our operations.

In November 2021, the EPA released new proposed methane rules which would impose regulations on methane release at existing wells nationwide. These new rules, among other things, would implement a comprehensive monitoring program to require companies to find and fix leaks. Additionally, the new rules would require well operators to place gas that is produced in a pipeline to be sold when possible to prevent wasting the gas, which could force us or well operators on which we rely to sell the gas at lower prices and thereby reduce our revenues. As with most regulations, smaller participants like us will face more burdens due to the compliance and other costs and the limited revenue to absorb such costs. The EPA is expected to issue a supplemental proposal in 2022 in the hopes of identifying additional regulatory means of reducing methane and other emissions, and has indicated an intention to adopt final rules before the end of calendar year 2022.

While a recent U.S. Supreme Court case imposed limitations on the EPA’s authority under the Clean Air Act, including by holding that the EPA’s attempted energy generation shifting entailed an overly broad interpretation of the statute’s delegation of authority, if the EPA adopts the above or other regulations and such regulations are held to be valid, the resulting new regulatory framework could impose additional restrictions and costs on our operations which could materially adversely affect our business. The regulations at issue in the recent case pertained to an attempt to shift a portion of U.S. energy production from coal to natural gas by an enumerated percentage by 2030. In February 2022, a federal judge blocked a Biden Administration executive order which used the “social cost of carbon.” The Interior Department responded by suspending permits for oil and gas drilling.

Although Congress from time-to-time has considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of states, including states in which we operate, have enacted or passed measures to track and reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and regional greenhouse gas cap-and-trade programs. Most of these cap-and-trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. These reductions may cause the cost of allowances to escalate significantly over time.

Additionally, the United States re-joined, effective February 19, 2021, the non-binding international treaty to reduce global greenhouse gas emissions (the “Paris Agreement”), adopted by over 190 countries in December 2015. The Paris Agreement entered into force in November 2016 after more than 70 nations, including the United States, ratified or otherwise indicated their intent to be bound by the agreement. The United States had previously withdrawn from the Paris Agreement effective November 4, 2020. Following the United States re-joining the Paris Agreement, President Biden announced in April 2021 the United States’ pledge to achieve an approximately 50% reduction from 2005 levels in “economy-wide” net greenhouse gas emissions by 2030. To the extent that the United States implements this agreement or imposes other climate change regulations on the oil and natural gas industry, or that investors insist on compliance regardless of legal requirements, it could have an adverse effect on our business, operating results and future growth.

The adoption and implementation of these and other similar regulations could require us to incur material costs to monitor and report on greenhouse gas emissions or install new equipment to reduce emissions of greenhouse gases associated with our operations. In addition, these regulatory initiatives could drive down demand for our products and services in the oil and gas industry by stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels that serve as a major source of greenhouse gas emissions, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. This could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.

Because of the trend to use alternative energy technologies rather than oil and gas, it could have a material adverse effect on our results of operations.

Since our business depends on the level of activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energy technologies that increase the use of alternative forms of energy and reduce the demand for oil and natural gas could have a material adverse effect on our business, financial condition and results of operations. As the United States and certain other countries transition to electric vehicles and as certain states in the United States are banning any usage of gas as a fuel, the oil and gas business is adversely affected. We will be further subject to state regulatory efforts such as California’s announced goal of eliminating the sale of vehicles which use gas by 2035. Automobile manufacturers are beginning to announce that they will only manufacture electric vehicles in the future. President Biden has also stated that the 2022 retail price rise in the price of gasoline was part of a plan to transition to electric vehicles.

As an example, in August 2022, the California Air Resources Board passed a rule banning the sale of gas vehicles by 2035, requiring 35% of new passenger vehicles sold by 2026 to be electric or otherwise not using gas with the number rising to 68% by 2030. It has been reported that more than a dozen states typically follow California which is the largest market for the sale of passenger vehicles. The State of Washington has enacted a Rule similar to California. California also enacted a law effective July 1, 2022 banning the sale of gas powered lawn mowers and leaf blowers starting in 2024. Further in late September 2022 the California Air Resources Board banned natural gas heaters and furnaces by 2030. As this and the other trends outlined above are implemented, the Company could incur material and adverse effects on its results of operations.

Because we expect the SEC will adopt most, if not all of its proposed climate change rules, as a small producer, the compliance costs may adversely affect our future results of operating and financial condition, which effects may be material.

On March 21, 2022, the SEC released proposed rule changes that would require new climate-related disclosure in SEC filings, including certain climate-related metrics and greenhouse gas emissions, information about climate-related targets and goals, transition plans, if any, and extensive attestation requirements. In addition to requiring filers to quantify and disclose direct emissions data, the new rules would also require disclosure of climate impact arising from the operations and uses by the filer’s business partners and contractors and end-users of the filer’s products and/or services. If adopted as proposed, the rule changes would apply to the Company and result in us incurring material additional compliance and reporting costs, including monitoring, collecting, analyzing and reporting the new metrics and implementing systems and procuring additional internal and external personnel with the requisite skills and expertise to serve those functions. Such costs are likely to adversely affect our future results of operations and financial condition, which may be material. We expect the rule will be adopted in late 2022 or early 2023 and be effective beginning at some point after that date. We cannot predict the outcome of litigation which we expect will challenge any new climate change rules.

If Congress enacts the proposed price gouging bill, it could have a material adverse effect on our oil and gas operations and the fund.

Senator Elizabeth Warren and others have introduced legislation aimed at rising gasoline and other prices and would empower the Federal Trade Commission (“FTC”) to investigate and penalize companies with “unconscionably excessive price increases.” The proposed legislation does not define what this phrase means so it will permit the FTC to define it. While we cannot predict whether the legislation will pass, the Congress has Democratic majorities (with the vice president breaking a tie in the Senate) and a Democratic President so there is a likelihood that it may pass. If it does, the FTC will enact Rules although it is possible it may enact an emergency Rule like other regulatory agencies have recently done. Any such legislation will likely affect gasoline prices especially in an election year. We believe price controls will have a material adverse effect on the Company.

Because competition in the oil and natural gas industry is intense, we may be unable to effectively compete with larger companies with greater financial, technical and managerial resources.

We are a relatively small participant in the United States onshore oil and gas exploration and drilling industry and we face significant competition from major energy companies with substantial financial, technical, management, and other resources as well as large and other privately-held businesses which have competitive advantages. While we are mostly vertically integrated, our cost of operations is dependent in part on certain third-party services, and competition for these services can be significant, especially in times when commodity prices are high. Similarly, if and as we grow we will compete for trained, qualified personnel, and in times of lower prices for oil, we and other companies with similar production profiles may not be able to attract and retain this talent. Conversely, some of our competitors have a broader portfolio properties, assets and rights that in many cases enable them to both explore and drill wider geographic areas with a greater likelihood of success and/or complete the exploration, drilling, distribution and sale processes at lower costs while also offering related services to third parties.

Our ability to acquire and develop reserves in the future, and maintain and grow our customer base will depend on our ability to evaluate and select suitable properties and assets and to consummate transactions in a highly competitive environment for acquiring such properties and assets, marketing oil and gas, securing and compensating trained personnel and meeting demand for our products and services. Also, there is substantial competition for capital available for investment in the oil and gas industry. Our competitors may be able to pay more for personnel, property and services and to attract capital at lower rates. Because of our small size, we may be more affected than larger competitors. Further, the current inflation the United States is facing will affect us more that many well capitalized competitors.

The potential lack of availability of, or cost of, drilling rigs, equipment, supplies, personnel and crude oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

We currently own three deep drilling rigs which can reach vertical depths of up to 20,000 feet, and three workover rigs. However, we do not currently own a drilling rig capable of drilling deep lateral wells in formations on our oil and gas mineral lease properties such as the Tuscaloosa Marine Shale (“TMS”). When the prices of crude oil increase, or the demand for equipment and services is greater than the supply in certain areas, we could encounter an increase in the cost of securing a deep drilling rig capable of performing lateral drilling projects in the TMS. In addition, larger producers may be more likely to secure access to such equipment by offering more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be delayed and the cost of producing those reserves could increase significantly. In addition to increasing our costs, we may face the possibility of poorly rendered services or faulty or damaged equipment coupled with potential damage to downhole reservoirs and personnel injuries. Such issues can increase the actual cost of services, extend the time to secure such services and add costs for damages due to accidents sustained from the overuse of equipment and inexperienced personnel. All of these factors may adversely affect our results of operations and financial condition.

Drilling for and producing crude oil involves significant risks and uncertainties that could adversely affect our business, financial condition or results of operations.

Our drilling and production activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for crude oil can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be curtailed, delayed or cancelled as a result of other factors, including but not limited to:

Any of these risks can cause substantial losses, including personal injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, clean-up responsibilities, loss of wells, repairs to resume operations; and regulatory fines or penalties. Further, our exposure to operational risks may increase as our drilling activity expands.

We may not be insured or fully insured against certain of the above operational risks, either due to unavailability of such insurance or the high premiums and deductibles. The occurrence of an event that is not covered in full or in part by insurance could have a material adverse impact on our business, financial condition and results of operations.

Because of the speculative nature of drilling oil and gas wells, we cannot guarantee any return on your investment.

Oil and natural gas exploration is an inherently speculative activity. Before the drilling of a well, we cannot predict with absolute certainty the volume of oil and natural gas recoverable from the well; or the time it will take to recover the oil and gas.

In addition, oil and gas wells by their nature are depleting assets with respect to which production could last anywhere from a few months to more than 30 years. As a result, annual production will naturally decline over the life of a well, and so too will returns to investors.

Even if targeted wells are completed and produce oil and gas in commercial quantities, it may not produce enough oil and gas to pay for the costs of drilling and completing the well.

Because the oil and gas drilling business is very cyclical, we may face a downturn which in turn can adversely affect our business.

Between inflation, supply chain shortages and the war in Ukraine, among other factors, the price of oil has spiked in 2022 with peak oil prices over $122 per barrel of oil for WTI crude on June 8, 2022, which was the highest level in over 10 years. However, as the economy is seemingly worsening and the stock market declining, the price of crude oil fell to early January levels with WTI crude at $78.74 on September 24, 2022, although the price has since increased to above $90 in early November 2022. Changes in oil and natural gas prices (and specifically downwards trends or the lack of an increase) will have a significant adverse impact on our cash flow. Lower oil and gas prices may not only impact our revenues, but also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas prices have been volatile, and it is likely that they will continue to be volatile in the future. At some point, the regulatory factors facing fossil fuels and the drilling for oil as well as a recession may make oil drilling financially unattractive. In that event, our results of operations may be materially and adversely affected.

The volatility of oil and natural gas prices could also hamper our ability to produce oil and gas economically. Oil and natural gas prices are volatile, and a decline in prices, especially recent historic declines below zero, would significantly, adversely affect both profitability and overall financial health of the Company. The oil and gas industry has experienced severe downturns characterized by oversupply and/or weak-to-zero demand.

Our future revenues from exploration and production operations, cash flows, and carrying value of our oil and gas properties will depend on oil prices. Commodity prices, including oil, are highly volatile and may fluctuate widely in response to relatively minor changes in supply and demand and market uncertainty. Additional factors which may affect oil prices and which are beyond our control include but are not limited to, the following factors:

Currently, oil prices are higher than they have been in prior years, although there can be no certainty as to if, when and to what extent they may decline in the future. Further, while higher oil prices generally provide benefits to our drilling operations to the extent we have productive wells during the high price periods, they also pose increased costs in drilling additional wells.

Our operating results fluctuate due to the effect of seasonality, adverse weather or other natural occurrences that generally impact the oil and gas industry.

Operating levels of the oil industry have historically been lower in the winter months because of adverse weather conditions. Accordingly, our revenue generally follows a seasonal pattern. Revenue can also be affected by other adverse weather conditions, holidays and the number of business days during a given period because revenue is directly related to the available working days. From time-to-time, we may also suffer short-term impacts from severe weather and similar events, such as tornadoes, hurricanes, blizzards, ice storms, floods, fires, earthquakes, and explosions that could harm our results of operations or make our results of operations more volatile.

Because we may be subject to various claims and lawsuits in the ordinary course of business, increases in the amount or severity of these claims and lawsuits could adversely affect us.

In the ordinary course of our planned business, we may be exposed to various claims and litigation related to commercial disputes, personal injury, property damage, environmental liability and other matters. If we incur increases in litigation or serious claims, there are developments in legislative or regulatory trends, or our employees or contractors incur a catastrophic accident or series of accidents, involving property damage, personal injury, or environmental liability it could have a material adverse effect on our operating results and financial condition.

The extension of our active oil and gas mineral leases are in some cases subject to performing continuous drilling operations.

Our oil and gas mineral leases may contain acreage that is either held by production or not. In order to extend the leased acreage not held by production, the Company must maintain minimum continuous drilling operations in order to extend these leases to future periods. Further, at least one of our leases requires us to drill a new well every 270 days in order to maintain the rights, and our failure to do so would result in us losing the rights unless the owner agrees to a waiver or extension. The Company’s inability to perform operations during any given period could result in the Company’s losing the rights to future operations on that lease.

We may be required to meet future drilling conditions and lack the capital to protect our interest in one or more wells.

In addition to the requirements under our current interests, we may acquire interests in wells that require continuous drilling in order to maintain our interest. In the past, White River Holdings Corp a then subsidiary of Ecoark was unable to meet the drilling condition, which permitted our Executive Chairman to personally acquire a portion of the working interest when he made the required investment. Because we may acquire oil and gas mineral leases that may require future drilling to maintain the leasehold interest, if we do the Company will be required to invest in future drilling in order to extend these leases to future periods or lose the interest in any such leases. If we lack the capital, our affiliates may acquire the leases by investing their own capital.

Our ability to spread the risks of drilling among many wells may be limited.

Our ability to spread risks through diversification will be related to our ability to obtain the necessary capital and other resources needed to evaluate a well’s prospects and deploy drilling equipment, as well as acquire and maintain drilling rights. Limited capital will force us to drill fewer wells, or forego opportunities management deems to be attractive, which decreases our ability to spread the risks of drilling and mitigate the possibility of deploying our limited resources towards a successful drilling venture. In addition, our revenue and ability to achieve or maintain profitability may decrease if management is unable to find enough suitable well locations to be drilled. While we have over 30,000 acres to select drilling locations from, there can be no assurance that we will be successful in drilling in a manner or pace that enables us to generate sufficient revenue at low enough costs to become profitable.

The Company may face issues with title defects, which could result in losses in leases which the fund acquires.

There may be defects in the title to the leases on which the Company’s wells are drilled. In certain instances, the Company may elect not to obtain title opinions or take certain other due diligence related actions that could have otherwise unveiled problems, due to cost, timing or other constraints. Thus, the Company may experience losses from title defects which arose during drilling that would have been disclosed by such due diligence. Also, the Company may waive title requirements for the leases on which the Company’s wells are drilled. Any failure of title of working interest transferred to the Company could materially adversely affect our operating results and business.

We may be required to record significant non-cash impairment charges related to a reduction in the carrying value of our proved oil and gas properties, which could materially and adversely affect our results of operations.

We will perform assessments of our oil and gas properties whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. In order to perform these assessments, management will use various observable and unobservable inputs, including management’s outlooks for (i) proved reserves and risk-adjusted probable and possible reserves, (ii) commodity prices, (iii) production costs, (iv) capital expenditures and (v) production. Significant or extended price declines could result in the need to adjust the carrying value of our proved oil and gas properties by recording non-cash impairment charges. To the extent such assessments indicate a reduction of the estimated useful life or estimated future cash flows, the carrying value of the oil and gas properties may not be recoverable and therefore we may be required to record an impairment charge reducing the carrying value of the proved properties to their fair value. If oil and natural gas prices decline in the future, we may be required to record impairment charges related to the oil and gas properties acquired from Ecoark, which would materially and adversely affect our results of operations in the period incurred.

Similar to many companies, we have experienced a spike in our insurance costs, which could have a material adverse effect on our operating results.

Insurance premiums have recently escalated, and we are facing a similar increase in our insurance costs. Our future insurance and claims expense might exceed historical levels, which could reduce our earnings. We self-insure or maintain a high deductible for a portion of our claims exposure resulting from workers’ compensation, auto liability, general liability, cargo and property damage claims, as well as associated health insurance. Estimating the number and severity of claims, as well as related judgment or settlement amounts is inherently difficult. This, along with legal expenses, incurred but not reported claims and other uncertainties can cause unfavorable differences between actual claim costs and our reserve estimates. We plan to reserve for anticipated losses and expenses and periodically evaluate and adjust our claims reserves to reflect our experience. However, ultimate results may differ from our estimates, which could result in losses over our reserved amounts.

We maintain insurance with licensed insurance carriers above the amounts which we retain. Although we believe our general liability and related insurance limits should be sufficient to cover reasonably expected claims, the amount of one or more claims could exceed our coverage limits. If any claim were to exceed our coverage, we would be required to bear the excess, in addition to our other self-insured/retained amounts. As a result, our insurance and claims expense could increase, or we could raise our self-insured retention or deductible when our policies are renewed or replaced. Our operating results and financial condition could be materially and adversely affected if (i) cost per claim, premiums, or the number of claims significantly exceed our estimates, (ii) there is one or more claims in excess of our coverage limits, (iii) our insurance carriers refuse to pay our insurance claims or (iv) we experience a claim for which coverage is not provided.

The Company’s Board of Directors approved five-year executive employment agreements pursuant to which our officers are entitled to the following compensation and other rights:

Randy May, our Executive Chairman, is receiving an annual base salary of $400,000, and was granted 5,000,000 shares of restricted common stock with half of the shares vesting annually over a five-year period and the remainder vesting based on performance metrics set forth in the agreement. Under his agreement, Mr. May was also granted the following rights related to the Company’s oil and gas operations:

(A) an overriding royalty interest to be held in perpetuity from either the Company or its subsidiaries equal to 5% in any and all successfully drilled and completed oil and/or gas wells (an “ORRI”) during the term of his employment.

(B) a 15% participation right in the funding and ownership interest in any drilling or participation by the Company or any subsidiary in the drilling by the Company or a third party of an oil and gas well other than the Fund (a “Participation Right”).

Jay Puchir, our Chief Executive Officer, is receiving an annual base salary of $350,000 and was granted 5,000,000 shares of restricted common stock with half of the shares vesting annually over a five-year period and the remainder vesting based on performance metrics set forth in the agreement. Under his agreement, Mr. Puchir was also granted the following rights related to the Company’s oil and gas operations:

Alisa Horgan, our Chief Administrative Officer and a member of our Board of Directors and Mr. May’s daughter, is receiving an annual base salary of $180,000, and was granted 2,000,000 shares of restricted common stock with the shares vesting annually over a 10-year period.

Her Husband, Richard Horgan, Senior Vice President of M&A and our former Chief Executive Officer, is receiving an annual base salary of $200,000, and was granted 2,000,000 shares of restricted common stock with the shares vesting annually over a 10-year period.

Each of the above employment agreements are also subject to the following severance provisions:

In the event of termination by the Company without “cause” or resignation by the officer for “good reason,” each officer is entitled to receive 2.99 years’ base salary, immediate vesting of unvested equity awards and continued benefits for six months.

In case of termination or adverse change in title upon a change of control, each officer is entitled to receive 2.99 years’ base salary, immediate vesting of unvested equity awards, continued benefits for 18 months and 100% of the existing target bonus, if any, for that fiscal year when the change of control occurs.

Generally, “change of control” is defined in the employment agreements to include a transfer of 50% of the voting securities or interests of the Company or a key subsidiary (as defined in the Internal Revenue Code and Treasury Regulations thereunder), including through a merger or asset purchase, a change in the majority of the Board of Directors in a two-year period, or a liquidation or dissolution by the Company. The definition of change of control is subject to certain exceptions and limitations as more particularly set forth in the employment agreements.

Generally, “good reason” is defined as a material diminution in the officer’s authority, duties or responsibilities due to no fault of his or her own (unless he or she has agreed to such diminution); any other action or inaction that constitutes a material breach by the Company under the employment agreement; or a relocation of the principal place of employment to a location outside the location specified in the employment agreements.

Generally, “cause” is defined as a felony conviction or plea related to the business of the Company; gross negligence or intentional misconduct in carrying our his or her duties resulting in material harm to the Company; misappropriation of Company funds or otherwise defrauding the Company; breach of fiduciary duty to the Company; material breach of any agreement with the Company without timely cure; breach of certain restrictive covenants set forth in the employment agreement; a federal injunction enjoining the officer from violating federal securities laws; a cease and desist order or other order issued by the SEC; refusal to carry out a resolution adopted by the Company’s Board of Directors after a reasonable opportunity to dispute such resolution; or alcohol or drug abuse in a manner that interferes with the successful performance of his or her duties.

Further, upon the officer’s death or disability, as defined, during the officer’s term of employment, the officer’s estate or the officer, as applicable, becomes entitled to, among other things, a $500,000 lump-sum payment and full vesting of all outstanding equity grants made to the officer.

In the event an officer’s employment is terminated at the end of the term upon the notice of non-renewal and the officer remains employed until the end of the term, the officer will be entitled to receive six months’ base salary and continued benefits for six months.

Under the terms of the employment agreements, the officers are subject to non-competition and non-solicitation covenants during the term of their employment and during one year following termination of employment with the Company. The employment agreements also contain customary confidentiality and non-disparagement covenants.

In addition, the Company agreed to the following compensation for each non-employee director:

(A) an annual grant of $100,000 in restricted stock which will vest on the final business day of each quarter equal to one-fourth of the total stipend, or $25,000 per quarter, with the number of shares to be determined based on the volume weighted average price of the Company’s common stock as of each quarterly vesting (the “Restricted Stock Grant”).

(B) an annual cash fee of $50,000 which will vest on the final business day of each quarter equal to one-fourth of the total fee, or $12,500 per quarter (the “Cash Fees”).

The director compensation set forth above is subject to upward adjustment upon the successful uplisting of the Company to a national securities exchange, whereupon the Restricted Stock Grant will be increased to $200,000 per year and the Cash Fees will be increased to $100,000 per year.

In addition, the Company agreed to enter into indemnification agreements with each of its officers and directors.

*This exhibit is being furnished rather than filed and shall not be deemed incorporated by reference into any filing, in accordance with Item 601 of Regulation S-K.

+ Certain schedules, appendices and exhibits to this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished supplementally to the Securities and Exchange Commission staff upon request.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Large accelerated filer	☐	Accelerated filer	☐
i Non-accelerated filer	☒	Smaller reporting company	i ☒
Emerging growth company	i ☐

	SEPTEMBER 30,			MARCH 31,
	2022			2022
		(unaudited)
ASSETS

CURRENT ASSETS:

Cash (including $ i 201,050 and $ i 251,050 in restricted cash)	$	i 579,357		$	i 251,050
Accounts receivable		i 410,085			i 634,483
Secured promissory note receivable		i 200,000			-
Inventories - Crude Oil		i 91,925			i 107,026
Prepaid expenses and other current assets		i 240,860			i 318,771

Total current assets		i 1,522,227			i 1,311,330

NON-CURRENT ASSETS:
Property and equipment, net		i 1,431,285			i 596,464
Right of use asset - operating lease		i 172,141			i 243,494
Oil and gas properties, full cost-method		i 5,426,976			i 6,626,793
Capitalized drilling costs, net of depletion		i 322,806			i 604,574
Other assets		i 13,465			i 14,760
Goodwill		-			i 2,100,374

Total non-current assets		i 7,366,673			i 10,186,459

TOTAL ASSETS	$	i 8,888,900		$	i 11,497,789

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)

LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	i 344,307		$	i 799,100
Accrued liabilities		i 289,730			i 119,600
Due to Ecoark Holdings		-			i 25,068,890
Cash overdraft		-			i 27,918
Current portion of long-term debt		i 42,668			-
Current portion of lease liability - operating lease		i 157,260			i 155,263

Total current liabilities		i 833,965			i 26,170,771

NON-CURRENT LIABILITIES
Lease liability - operating lease, net of current portion		i 31,236			i 110,235
Long-term debt, net of current portion		i 92,704			-
Asset retirement obligations		i 668,151			i 1,303,751

Total non-current liabilities		i 792,091			i 1,413,986

Total Liabilities		i 1,626,056			i 27,584,757

COMMITMENTS AND CONTINGENCIES		-			-

STOCKHOLDERS’ EQUITY (DEFICIT)
Preferred stock, $ i i 0.0001 / par value, i i 5,000,000 / shares authorized and i i 1,200 / and i i 0 / shares issued and outstanding		i 1			-
Common stock, $ i i 0.0001 / par value, i i 500,000,000 / shares authorized and i i i i 8,400,000 / / / shares issued and outstanding		i 840			i 840
Additional paid in capital		i 37,076,394			i 591,167
Accumulated deficit		( i 29,814,391	)		( i 16,678,975	)

Total stockholders’ equity (deficit)		i 7,262,844			( i 16,086,968	)

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	$	i 8,888,900		$	i 11,497,789

	2022			2021
	SEPTEMBER 30,
	2022			2021
	(unaudited)			(unaudited)
CASH FLOW FROM OPERATING ACTIVITIES FROM OPERATIONS
Net loss	$	( i 13,135,416	)	$	( i 1,614,703	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities
Home office allocation		-			i 700,997
Depreciation, amortization, depletion, accretion and impairment		i 6,202,606			i 1,234,262
Share-based compensation		i 657,935			-
Loss on disposal of Norr and Elysian		i 144,654			-
Gain on disposal of oil and gas property, ARO and fixed assets		( i 391,533	)		( i 29,078	)
Changes in assets and liabilities
Accounts receivable		i 224,398			i 414,860
Inventory		i 15,101			i 21,167
Prepaid expenses and other current assets		i 79,206			( i 78,838	)
Amortization of right of use asset - operating leases		i 71,353			i 59,669
Due to Ecoark Holdings		i 3,884,620			i 2,779,952
Operating lease expense		( i 77,002	)		( i 63,765	)
Accrued payable and accrued liabilities		( i 284,663	)		( i 3,096,728	)
Total adjustments		i 10,526,675			i 1,942,498
Net cash (used in) provided by operating activities of continuing operations		( i 2,608,741	)		i 327,795
Net cash used in discontinued operations		( i 81,053	)		-
Net cash (used in) provided by operating activities		( i 2,689,794	)		i 327,795

CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of oil and gas properties, net of asset retirement obligations		-			( i 303,500	)
Advances on note receivable		( i 200,000	)		-
Proceeds from the sale of fixed assets		-			i 2,500
Proceeds from the sale of oil and gas properties		i 999,999			-
Purchase of fixed assets		( i 889,352	)		-
Net cash (used in) investing activities		( i 89,353	)		( i 301,000	)

CASH FLOWS FROM FINANCING ACTIVITIES
(Decrease) in cash overdraft		( i 27,918	)		( i 26,387	)
Proceeds from long-term debt		i 145,266			-
Repayment of long-term debt		( i 9,894	)		-
Proceeds from Ecoark Holdings in acquisition of White River		i 3,000,000			-
Net cash provided by (used in) financing activities		i 3,107,454			( i 26,387	)

NET INCREASE IN CASH AND RESTRICTED CASH		i 328,307			i 408

CASH AND RESTRICTED CASH - BEGINNING OF PERIOD		i 251,050			i 250,413

CASH AND RESTRICTED CASH - END OF PERIOD	$	i 579,357		$	i 250,821

SUPPLEMENTAL DISCLOSURES
Cash paid for interest expense	$	i 6,168		$	-
Cash paid for income taxes	$	-		$	-

SUMMARY OF NON-CASH ACTIVITIES:
Contribution by Ecoark Holdings	$	i 28,953,510		$	-
Net assets acquired from Enviro Technologies US Inc.	$	i 46,157		$	-

Purchase Price Allocation of White River Energy Corp

Current assets – inventory and deposits	$	i 113,472
Accounts payable and accrued expenses		( i 67,315	)
Goodwill		i 5,917,843

Purchase price	$	i 5,964,000

	1			2			3 ⁽¹⁾			4 ⁽²⁾			5
	Historical White River			White River			Other			Other
	Energy			Holdings			Transaction			Transaction
	Corp			Corp.			Adjustments			Adjustments			Pro Forma
								(1)			(2)
ASSETS

CURRENT ASSETS
Cash	$	i 140,241		$	i 251,050		$	-		$	( i 140,241	)	$	i 251,050
Accounts receivable		-			i 634,483			-			-			i 634,483
Prepaid expenses and other current assets		i 71,756			i 318,771			-			( i 71,756	)		i 318,771
Inventory		-			i 107,026			-			-			i 107,026
Current assets held for sale		-			-			-			-			-
Total current assets		i 211,997			i 1,311,330			-			( i 211,997	)		i 1,311,330

NON-CURRENT ASSETS

Property and equipment, net		i 1,466			i 596,464			-			( i 1,466	)		i 596,464
Capitalized drilling costs		-			i 604,574			-			-			i 604,574
Oil and gas reserves		-			i 6,626,793			-			-			i 6,626,793
Right of use asset - operating leases		-			i 243,494			-			-			i 243,494
Other assets		-			i 14,760			-			-			i 14,760
Goodwill		-			i 2,100,374			-			-			i 2,100,374
Total non-current assets		i 1,466			i 10,186,459			-			( i 1,466	)		i 10,186,459

TOTAL ASSETS	$	i 213,463		$	i 11,497,789		$	-		$	( i 213,463	)	$	i 11,497,789

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable and accrued expenses	$	i 23,500		$	i 918,700		$	-		$	( i 23,500	)	$	i 918,700
Current portion of lease liability - operating leases		-			i 155,263			-			-			i 155,263
Cash overdraft		-			i 27,918			-			-			i 27,918
Due to Ecoark Holdings.		-			i 25,068,890			-			-			i 25,068,890
Total current liabilities		i 23,500			i 26,170,771			-			( i 23,500	)		i 26,170,771

NON-CURRENT LIABILITIES
Asset retirement obligation		-			i 1,303,751			-			-			i 1,303,751
Lease liability - operating leases, net of current portion		-			i 110,235			-			-			i 110,235
Total non-current liabilities		-			i 1,413,986			-			-			i 1,413,986

Total liabilities		i 23,500			i 27,584,757			-			( i 23,500	)		i 27,584,757

STOCKHOLDERS’ EQUITY (DEFICIT)

Preferred stock, $ i 0.0001 par value		-			-			-			-			-
Common stock, $ i 0.0001 par value		i 840			i 60			( i 60	)		-			i 840
Additional paid-in capital		i 4,316,779			i 591,947			( i 4,127,596	)		( i 189,963	)		i 591,167
Accumulated deficit		( i 4,126,539	)		( i 16,678,975	)		i 4,126,539			-			( i 16,678,975	)
Total stockholders’ equity (deficit) before non-controlling interest		i 191,080			( i 16,086,968	)		( i 1,117	)		( i 189,963	)		( i 16,086,968	)
Non-controlling interest		( i 1,117	)		-			i 1,117			-			-
Total stockholders’ equity (deficit)		i 189,963			( i 16,086,968	)		-			( i 189,963	)		( i 16,086,968	)

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	i 213,463		$	i 11,497,789		$	-		$	( i 213,463	)	$	i 11,497,789

White River Energy Corp. – ‘10-Q’ for 9/30/22

On: Monday, 11/14/22, at 4:03pm ET · For: 9/30/22 · Accession #: 1493152-22-31984 · File #: 333-192060

Previous ‘10-Q’: ‘10-Q’ on 8/12/22 for 6/30/22 · Next: ‘10-Q’ on 2/14/23 for 12/31/22 · Latest: ‘10-Q’ on 3/15/24 for 12/31/23 · 22 References:

Quarterly Report — Form 10-Q

Filing Table of Contents

‘10-Q’ — Quarterly Report

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Dates Referenced Herein and Documents Incorporated by Reference

14 Subsequent Filings that Reference this Filing

8 Previous Filings that this Filing References

	(a)	The assets and liabilities of the legal subsidiary recognized and measured at their precombination carrying amounts;
	(b)	The assets and liabilities of the legal parent recognized and measured in accordance with the guidance in this topic applicable to business combinations (ASC 805);
	(c)	The retained earnings and other equity balances of the legal subsidiary before the business combination;
	(d)	The amount recognized as issued equity interests in the consolidated financial statements determined by adding the issued equity interest of the legal subsidiary outstanding immediately before the business combination to the fair value of the legal parent determined in accordance with the guidance in ASC 805 applicable to business combinations. However, the equity structure reflects the equity structure of the legal parent, including the equity interests the legal parent issued to effect the combination. Accordingly, the equity structure of the legal subsidiary is restated using the exchange ratio established in the acquisition agreement to reflect the number of shares of the legal parent issued in the reverse acquisition.

	September 30, 2022			March 31, 2022
	(unaudited)
Land	$	i 140,000		$	i 140,000
Buildings		i 236,000			i 236,000
Machinery and equipment		i 1,167,468			i 278,116
Total property and equipment		i 1,543,468			i 654,116
Accumulated depreciation and impairment		( i 112,183	)		( i 57,652	)
Property and equipment, net	$	i 1,431,285		$	i 596,464

	September 30, 2022			March 31, 2022
		(unaudited)
Truck loan – Amur Capital ^(a)	$	i 80,634		$	-
Truck loan – Mitsubishi ^(b)		i 54,738			-
Total long-term debt		i 135,372			-
Less: current portion		( i 42,668	)		-
Long-term debt, net of current portion	$	i 92,704		$	-

(a)	On May 13, 2022, entered into long-term secured note payable for $ i 87,964 for two service trucks maturing i May 13, 2026. The note is secured by the collateral purchased and accrued interest annually at i 11.99% with principal and interest payments due i monthly. There is i no accrued interest as of September 30, 2022.

(b)	On June 21, 2022, entered into long-term secured note payable for $ i 61,973 for a service truck maturing i December 21, 2024. The note is secured by the collateral purchased and accrued interest annually at i 11.99% with principal and interest payments due i monthly. There is i no accrued interest as of September 30, 2022.

Total	$	135,372
2023	$	i 42,668
2024		i 48,074
2025		i 29,047
2026		i 15,583
Total	$	i 135,372

	Date of Grant
Expected term (years)		i 10
Expected volatility		i 283	%
Risk-free interest rate		i 2.55	%
Dividend yield		i 0	%

	Six Months Ended September 30, 2022			Year Ended March 31, 2022
Expected term		-			-
Expected volatility		-	%		-	%
Expected dividend yield		-			-
Risk-free interest rate		-	%		i 0.10	%

Maturity of lease liability for the operating leases for the period ended September 30,
2023	$	i 158,430
2024	$	i 31,532
Imputed interest	$	( i 1,466	)
Total lease liability	$	i 188,496

Disclosed as:
Current portion	$	i 157,260
Non-current portion	$	i 31,236

Amortization of the right of use asset for the period ended September 30,
2023	$	i 143,318
2024	$	i 28,823

Total	$	i 172,141

	Six months ended September 30, 2022		Six months ended September 30, 2021
		(unaudited)		(unaudited)
Operating lease expense	$	i 72,244	$	i 70,084

	2022			2021
Revenue	$	i 319		$	-
Operating expenses		i 137,877			-
Other (income) loss		-			-
Net loss from discontinued operations	$	( i 137,558	)	$	-

	2022			2021
Proceeds from sale	$	i 3		$	-
Cash		( i 3,205	)		-
Inventory		( i 40,901	)		-
Loss on disposal of discontinued operations	$	( i 44,103	)	$	-

	Six Months Ended September 30,
	2022				2021
	Bbls				Bbls
	Gross		Net		Gross		Net
Production Data:
By State/County
Mississippi
Holmes		8		1		139		104
Amite		3,316		-		6,183		4,927
Wilkinson		5,599		6		7,490		5,805
Pike		288		-		759		585
		9,211		7		14,571		11,421

Louisiana
Catahoula		1,613		-		3,244		2,210
Concordia		4,564		957		3,419		1,660
Tensas		892		646		1,687		1,265
Lasalle		-		-		609		330
Avoyelles		10,367		5,190		30,707		20,878
		17,436		6,793		39,666		26,343

Total		26,647		6,800		54,237		37,764

	Three Months Ended September 30,
	2022				2021
	Bbls				Bbls
	Gross		Net		Gross		Net
Production Data:
By State/County
Mississippi
Holmes		4		-		131		98
Amite		3,305		-		2,671		2,132
Wilkinson		2,549		-		3,871		2,997
Pike		36		-		464		364
		5,894		-		7,137		5,591

Louisiana
Catahoula		1,613		-		1,410		1,311
Concordia		2,764		497		2,360		1,041
Tensas		496		352		660		495
Lasalle		-		-		136		74
Avoyelles		3,923		2,044		10,863		7,407
		8,796		2,893		15,429		10,328

Total		14,690		2,893		22,566		15,919

	Six Months Ended September 30,
	2022			2021
Change in fair value of derivative liabilities	$	-		$	2,157,838
Gain (loss) on disposal of fixed assets/oil and gas		1,363,142			721,365
Interest expense, net of interest income		(4,123	)		(278,170	)
Other income	$	1,359,019		$	2,601,033

	Three Months Ended September 30,
	2022		2021
Costs and Expenses

Cost of revenues (excludes items below)	$	381,216	$	432,546
Salaries and salaries related costs		1,875,461		963,705
Professional and consulting fees		272,611		141,220
Oilfield cists, supplies and repairs		2,629,376		172,865
Selling, general and administrative costs		1,321,327		1,665,877
Depreciation, amortization, depletion, accretion and impairment		6,033,712		467,607
	$	12,513,703	$	3,843,820

	Three Months Ended September 30,
	2022			2021
Change in fair value of derivative liabilities	$	-		$	620,473
Gain (loss) on disposal of fixed assets/oil and gas		1,002,766			122,505
Interest expense, net of interest income		(1,918	)		(260,294	)
Other income	$	1,000,848		$	482,684

	●	the effect of the Biden Administrations’ attempts to eliminate fossil fuels;

	●	the impact from the SEC’s climate change rules;

	●	the price of oil;

	●	our ability to protect our oil and gas assets, including complying with mineral leases;

	●	our ability to locate and procure employees, contractors and third party service providers to assist us in our operations;

	●	our ability to adapt to changing market conditions and manage our planned growth effectively; and

	●	our evolving business model.

	●	unusual or unexpected geological formations and miscalculations;
	●	fires;
	●	explosions and blowouts;
	●	pipe or cement failures;
	●	environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of toxic gases, brine, well stimulation and completion fluids, or other pollutants into the surface and subsurface environment;