Evolution Petroleum Corp: Form 10-Q for the period ended Sep 30, 2023

Executive Overview

Liquidity and Capital Resources

Results of Operations

Critical Accounting Policies

Commonly Used Terms

“Current quarter” refers to the three months ended September 30, 2023, our first quarter of fiscal year 2024.

“Year-ago quarter” refers to the three months ended September 30, 2022, our first quarter of fiscal year 2023.

Executive Overview

General

Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States. In support of that objective, our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisitions and through selective development opportunities, production enhancements, and other exploitation efforts on our oil and natural gas properties.

Our oil and natural gas properties consist of non-operated interests in the following areas: the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; as well as small overriding royalty interests in four onshore central Texas wells.

Our non-operated interests in the Jonah Field, a natural gas and natural gas liquids (“NGL”) producing field in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 950 net acres. The properties are operated by Jonah Energy, an established operator in the geographic region.

Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 43,300 net acres (approximately 92% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management (“Foundation”), an established operator in the geographic region.

Our non-operated interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of small overriding royalty interests). The approximately 21,000 net acres are held by production across nine North Texas counties. The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators.

Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest). The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the majority of the remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming.

Our non-operated interests in the Delhi Field, a CO2-EOR project, consist of approximately 24% average net working interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC (“Denbury”). The Delhi Field is located in northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses approximately 14,000 gross unitized acres, or approximately 3,200 net acres.

Our non-operated interest in the Chaveroo oilfield consist of a 50% net working interest, with an associated 41% revenue interest, in approximately 1,625 gross undeveloped acres associated with nine initial development locations. The field is operated by PEDEVCO Corp. (“PEDEVCO”). See “Chaveroo Oilfield Participation Agreement” below for further information.

Recent Developments

Chaveroo Oilfield Participation Agreement

On September 12, 2023, we entered into a participation agreement (the “Participation Agreement”) with PEDEVCO for the joint development of the Chaveroo oilfield, a conventional oil-bearing San Andres field located in Chaves and Roosevelt Counties, New Mexico (the “Chaveroo Field”).

Pursuant to the Participation Agreement, we have the right, but not the obligation, to elect to participate in drilling locations on approximately 16,000 gross leasehold acres consisting of all leasehold rights from surface to the base of the San Andres formation, where PEDEVCO currently holds leasehold interest. We have agreed to pay PEDEVCO $450 per acre to acquire a 50% working interest share in the leases associated with the locations that we choose to participate in. We have entered into a standard operating agreement with PEDEVCO serving as the operator with respect to the development of the properties. The Participation Agreement includes customary representations and warranties of the parties and other terms and conditions that are standard in such participation agreements.

During the three months ended September 30, 2023, we paid total cash consideration of $0.4 million, which includes less than $0.1 million of capitalized transaction costs, in exchange for a 50% working interest share in 1,625 gross undeveloped leasehold acres associated with two initial development blocks, comprised of nine development wells. Following the completion of the initial nine development wells, we will have the right, but not the obligation, to elect to participate in the next development block.

Risks and uncertainties

The global economy was deeply impacted by the effects of the novel coronavirus (“COVID-19”) pandemic and related efforts to mitigate the spread of the disease. These events led to crude oil prices falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020. Beginning in 2021, the demand for oil and natural gas started to recover primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses.

In addition, the conflict in the Middle East, the military activities of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which have further enhanced volatility in global commodity prices.

Additionally, in March 2023, the closures of Silicon Valley Bank and Signature Bank and their placement into receivership with the Federal Deposit Insurance Corporation (“FDIC”) created broad uncertainty around world-wide financial institutions and liquidity risk. While we do not have exposure to these banks, we do maintain cash balances in excess of FDIC insurance protections at banks we believe to be financially sound. We also utilize insured cash sweep deposits to maximize the amount of our cash that is protected by FDIC insurance. We also rely heavily on our third-party operators who manage their own liquidity with various financial institutions.

The Federal Reserve has taken actions to raise interest rates in an attempt to tame inflation and slow the economy, which has contributed to volatility in markets.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist; predict the broader impact of liquidity concerns around financial institutions; the impact to long-term cost of capital or economic growth as a result of the Federal Reserve’s policies; or the impact on the commodity prices that we realize.

Currently, our oil and natural gas properties are operated by third-party operators and involve other third-party working interest owners. As a result, we have limited ability to influence the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review capital expenditures and present alternative plans as necessary.

Liquidity and Capital Resources

As of September 30, 2023 and June 30, 2023, we had no borrowings outstanding on our Senior Secured Credit Facility. As of September 30, 2023, we had $9.4 million in cash and cash equivalents compared to $11.0 million in cash and cash equivalents at June 30, 2023. Our primary sources of liquidity and capital resources during the three months ended September 30, 2023 were cash provided by operations and the unused portion of our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the three months ended September 30, 2023 were cash dividend payments to our common stockholders, capital expenditures on our existing oil and natural gas properties, and initial cash consideration paid for unevaluated oil and natural gas properties under our Participation Agreement with PEDEVCO. As of September 30, 2023, working capital was $9.0 million, an increase of $0.1 million from working capital of $8.9 million as of June 30, 2023.

The Senior Secured Credit Facility has a maximum capacity of $50.0 million subject to a borrowing base determined by the lender based on the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $50.0 million. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026.

Borrowings bear interest, at our option, at either the SOFR plus 2.80% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. During the three months ended September 30, 2023, we did not have any borrowings outstanding under our Senior Secured Credit Facility. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. It also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of September 30, 2023, we were in compliance with all covenants under the Senior Secured Credit Facility.

On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among other things, extended the maturity of our Senior Secured Credit Facility to April 9, 2026, converted our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modified the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value. The required amount of hedged oil and natural gas production is related to the amount of borrowings outstanding. At each redetermination, our Margined Collateral Value takes into account the estimated value of our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.

We have historically funded operations through cash from operations and working capital and utilized our credit facility for property acquisitions. Our primary source of cash from operations is the sale of produced crude oil, natural gas, and NGLs. A portion of these cash flows is used to fund capital expenditures and pay cash dividends to shareholders. We expect to fund near-future capital expenditures with cash flows from operating activities and existing working capital, and as needed from borrowings under our Senior Credit Facility.

We are pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, we have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility, totaling $50.0 million as of September 30, 2023. We also have an effective shelf registration statement with the SEC under which we may issue up to $500.0 million of new debt or equity securities.

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 40 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase dividends over time, as appropriate. On November 6, 2023, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on December 15, 2023 and payable on December 29, 2023.

On September 8, 2022, our Board of Directors approved a share repurchase program, under which we are authorized to repurchase up to $25.0 million of our common stock in the open market through December 31, 2024. We intend to fund any repurchases from working capital and cash provided by operating activities. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program is a complimentary option to the existing dividend policy and investment opportunities, and is a tax efficient means to further improve shareholder return.

Capital Expenditures

During the three months ended September 30, 2023, we incurred $1.5 million on development capital expenditures. During the current quarter, we participated in the drilling and completion of two new down dip wells in the Delhi Field. Production of the first well began August 2023 while the second well came online in September 2023. We and the operator have been pleased with the early results of these two wells.

Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2024, we expect budgeted capital expenditures to be in the range of $10.0 million to $14.0 million, which excludes any potential acquisitions. Our expected capital expenditures for fiscal year 2024 include the two new drilled wells at Delhi Field, discussed above, and Foundation, the operator of our Williston Basin properties, drilling two sidetrack locations targeting the Birdbear formation. It also includes the drilling and completion of three horizontal wells at Chaveroo Field associated with the first development block. Our operator, PEDEVCO, spud the initial well in October 2023 and we expect the wells to come online in the third quarter of fiscal year 2024. We also expect to start incurring capital expenditures, in the fourth quarter at Chaveroo Field, for the second development block consisting of six horizontal wells.

Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and current working capital, and as needed from borrowings under our Senior Secured Credit Facility.

Full Cost Pool Ceiling Test

Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of September 30, 2023 were $78.53 per barrel of oil, $3.43 per MMBtu of natural gas and $31.76 per barrel of NGLs. As of September 30, 2023, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling. If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of September 30, 2023 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Additionally, a 10% reduction in respective commodity prices at September 30, 2023, while all other factors remained constant, would not have generated an impairment.

Overview of Cash Flow Activities

Cash provided by operating activities for the three months ended September 30, 2023 decreased $13.0 million compared to the three months ended September 30, 2022 primarily due to a decrease in revenues. Total revenues decreased $19.2 million as compared to the prior year period primarily due to lower commodity prices coupled with lower sales volumes. Our average realized price per barrel of oil equivalent (“BOE”) decreased $22.25, or 39.1% from the prior year period. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the three months ended September 30, 2023 decreased slightly as compared to the three months ended September 30, 2022. Capital expenditures for oil and natural gas properties where approximately $1.8 million for each of the three months ended September 30, 2023 and 2022.

Net cash flows used in financing activities for the three months ended September 30, 2023 decreased $8.9 million from the three months ended September 30, 2022. In the prior year quarter, we had repayments totaling $9.0 million of borrowings outstanding under our Senior Secured Credit Facility. For each of the three months ended September 30, 2023 and 2022, cash dividends paid to our common stockholders were $4.0 million.

Results of Operations

Three Months Ended September 30, 2023 and 2022

We reported net income of $1.5 million and $10.7 million for the three months ended September 30, 2023 and 2022, respectively. The following table summarizes the comparison of financial information for the periods presented:

(in thousands, except per unit and per BOE amounts)

(1) Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

(2) Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting.

Revenues

Crude oil, natural gas and NGL revenues were $20.6 million and $39.8 million for the three months ended September 30, 2023 and 2022, respectively. The decrease in revenue is primarily due to the decrease in our average realized price per BOE coupled with a decrease in our sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the three months ended September 30, 2023 decreased approximately $22.25 per BOE, or 39.1%, over the prior year period. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, inventory storage levels, basis differentials and other factors. Realized natural gas prices decreased 65.6% from the prior year period, driving the largest decrease in revenues. Average daily equivalent production decreased 15.0% from 7,598 BOEPD in the prior year period to 6,457 BOEPD in the current period. We began experiencing production declines and downtime in April 2023 at Barnett Shale and May 2023 at Delhi Field. At Barnett Shale, production declines were related to compression issues due to excessive heat, downtime in the gathering and processing system, pipeline rerouting and optimization, and our operator’s decision to temporarily shut-in certain low margin wells. Starting in May 2023, Delhi Field incurred downtime as a result of the installation of the heat exchanger project, turbine issues at the NGL plant and shut-in of wells throughout the summer due to high ambient temperatures. As of September 30, 2023, these issues have been moderated or resolved.

Lease Operating Costs

Ad valorem and production taxes were $1.3 million and $3.3 million for the three months ended September 30, 2023 and 2022, respectively. On a per unit basis, ad valorem and production taxes were $2.15 per BOE and $4.67 per BOE for the three months ended September 30, 2023 and 2022, respectively. The decrease in ad valorem and production taxes is primarily due to decreases in oil and natural gas prices as well as decreased production volumes described above as production taxes are based on sales at the wellhead.

The following table summarizes CO2 costs per Mcf and CO2 volumes for the three months ended September 30, 2023 and 2022. CO2 purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO2 is priced at 1% of the realized oil price in the field per MCF, plus sales taxes and transportation costs as per contract terms.

The $0.6 million decrease in CO2 costs for the three months ended September 30, 2023 was primarily due to a 19.6% decrease in purchased CO2 volumes combined with a 10.8% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price. CO2 volumes injected were reduced compared to prior year period due to downtime associated with maintenance on the CO2 pipeline and higher ambient temperatures in the Delhi Field during the current quarter. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO2 pipeline which is owned and operated by Denbury. On a per unit basis, CO2 costs were $2.66 per BOE and $3.15 per BOE for the three months ended September 30, 2023 and 2022, respectively.

Other lease operating costs decreased $4.6 million, or 33.9%, compared to the prior year period primarily due to lower production combined with the lower commodity price environment. On a per unit basis, other lease operating costs decreased to $15.20 per BOE for the three months ended September 30, 2023 from $19.53 per BOE in the year-ago quarter. The largest decrease in operating costs is at our Barnett Shale properties and the Delhi Field. At the Barnett Shale, significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are incurring lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges. At Delhi Field, we have seen lower electricity charges due to lower commodity prices.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $0.6 million or 17.7% from $3.3 million to $3.9 million for the three months ended September 30, 2023 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $6.58 per BOE and $4.75 per BOE for the three months ended September 30, 2023 and 2022, respectively. The deletion rate of our unit of production calculation increased due to decreases in proved reserve volumes as well as increase in our depletable base due to capital expenditures since September 30, 2022.

General and Administrative Expenses

General and administrative expenses for the three months ended September 30, 2023 decreased $0.1 million, or 5.9%, to $2.1 million compared to $2.3 million for the prior year period. The decrease primarily relates to lower consulting fees totaling approximately $0.3 million related to our search for a CEO and outsourced services in the prior year period. The decrease in consulting fees is partially offset by an increase of approximately $0.1 million for salary and employee benefits due to additional personnel added since the prior year period. On a per unit basis, general and administrative expenses were $3.59 per BOE and $3.24 per BOE for the three months ended September 30, 2023 and 2022, respectively. The slight increase on a per unit basis is the result of the decrease in production for the current year period.

Stock-based Compensation Expense

Stock-based compensation expense for the three months ended September 30, 2023 increased $0.3 million to $0.5 million compared to $0.2 million for the prior year period. The increase is primarily due to the addition of new personnel, including our CEO and COO added since the prior year period and the associated new awards granted during the current year period.

Net Gain (Loss) on Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As of September 30, 2023, we did not have any open crude oil or natural gas derivative contracts. In the prior year period, because of our acquisitions during fiscal year 2022 and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms set in the Senior Secured Credit Facility to hedge a portion of our production. The increase in commodity prices since entering into those hedges resulted in realized losses on derivative contracts for the prior year period.

(in thousands, except per unit and per BOE amounts)

29

Interest Expense

Interest expense decreased $0.2 million for the three months ended September 30, 2023 compared to the prior year period primarily due to repayments of borrowings outstanding on our Senior Secured Credit Facility during the prior fiscal year.

Income Tax (Expense) Benefit

For the three months ended September 30, 2023, we recognized income tax expense of $0.5 million on net income before income taxes of $1.9 million compared to income tax expense of $3.1 million on net income before income taxes of $13.8 million for the three months ended September 30, 2022. The effective tax rates were 23.9% and 22.2% for three months ended September 30, 2023 and 2022, respectively.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements. The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our unaudited condensed consolidated financial statements. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended June 30, 2023.

Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil, natural gas, and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we monitor commodity prices to identify the potential need for the use of derivative financial instruments to provide partial protection against declines in oil and natural gas prices. We do not enter into derivative contracts for speculative trading purposes.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. For the derivative contracts settled during fiscal 2023 and 2022, we did not post collateral. We account for our derivative activities under the provisions of ASC 815, *Derivatives and Hedging, (“*ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 6, “Derivatives” to our unaudited condensed consolidated financial statements for more details.

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%. SOFR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. Under our current practices, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s (“SEC”) rules and forms. This information is accumulated and communicated to our management, including our Principal Executive Officer and Principal Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

As required by SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15(d)-15(e)) as of the end of the quarter covered by this report. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. Based on the foregoing, our Principal Executive Officer and Principal Financial Officer concluded that as of September 30, 2023 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms.

Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, during the quarter ended September 30, 2023, we have determined that there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.