Evolution Petroleum Corp: Form 10-Q for the period ended Mar 31, 2024

Executive Overview

Liquidity and Capital Resources

Results of Operations

Critical Accounting Policies

Commonly Used Terms

“Current quarter” refers to the three months ended March 31, 2024, our third quarter of fiscal year 2024.

“Year-ago quarter” refers to the three months ended March 31, 2023, our third 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 SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; 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; as well as small overriding royalty interests in four onshore central Texas wells.

Our non-operated interests in the SCOOP and STACK plays, an oil and natural gas producing property in the Anadarko basin, consist of approximately 3% average net working interest and approximately 2% average net revenue interests located on approximately 3,700 net acres across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma. The oil and natural gas properties are primarily operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators.

Our non-operated interests in the Chaveroo oilfield consist of a 50% net working interest, with an associated 41% revenue interest, in approximately 1,625 gross acres associated with ten development locations with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price. The field is operated by PEDEVCO Corp. (“PEDEVCO”). See “Chaveroo Oilfield Participation Agreement” below for further information.

Our non-operated interests in the Jonah Field, a natural gas and 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, 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 producing oil and NGLs, 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”), which was acquired by Exxon Mobil Corporation during the current fiscal year. 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.

Recent Developments

SCOOP/STACK Acquisitions

On February 12, 2024, we closed the acquisitions of certain non-operated oil and natural gas assets in the SCOOP and STACK plays in central Oklahoma (the "SCOOP/STACK Acquisitions") from Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. After taking into account preliminary customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $40.5 million, which includes $43.8 million paid at closing less interim purchase price adjustments totaling approximately $3.3 million related to net cash flows earned on the properties from the effective date to the closing date. We expect to receive the remaining net cash flows from the properties between the effective date of November 1, 2023 and the closing date, at the final post-closing settlement process expected to occur during the fourth quarter of fiscal 2024.

The acquired assets consist of an average net working interest of approximately 3% in 247 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties, Oklahoma. The acquisitions also include approximately 3,700 net acres with more than 275 associated potential drilling opportunities.

Senior Secured Credit Facility

On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility. This amendment required that we enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period. We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.

Appointment of Chief Accounting Officer

On December 18, 2023, we announced that the Board of Directors approved the appointment of Kelly M. Beatty as Chief Accounting Officer, effective January 1, 2024. Ms. Beatty has been serving as Principal Accounting Officer since December 2022 and has served as the Company’s Controller since February 2022.

Share Repurchase Program

In November 2023, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 million over that period. We may alter the terms of the plan from time to time to the extent we determine changes are necessary to achieve the intended objectives of our repurchase program. During the three and nine months ended March 31, 2024, 0.1 million shares of the Company’s common stock have been repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs. These shares were subsequently cancelled.

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 leasehold acres associated with two initial development blocks. As of March 31, 2024, we have participated in the drilling and completion of the first development block which consisted of three gross (1.5 net ) wells. Following the completion of the second development block, we will have the right, but not the obligation, to elect to participate in additional development blocks. The Participation Agreement initially includes up to 80 gross drilling locations across twelve development blocks. Refer to Capital Expenditures below for a further discussion of Chaveroo drilling and completion activities since entering into the Participation Agreement.

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 recovered primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses. During the current year, natural gas prices have declined primarily due to a warmer winter, and during the current quarter, oil prices have increased somewhat due to geopolitical factors and increased demand relative to supply.

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.

At times, we do maintain cash balances in excess of the U.S. Federal Deposit Insurance Corporation (“FDIC”); however, we believe our bank counterparty 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 March 31, 2024, we had $3.1 million in cash and cash equivalents and $42.5 million outstanding on our Senior Secured Credit Facility compared to $11.0 million in cash and cash equivalents and no borrowings outstanding on our Senior Secured Credit Facility at June 30, 2023. Our primary sources of liquidity and capital resources during the nine months ended March 31, 2024 were cash provided by operations as well as net borrowings under our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the nine months ended March 31, 2024 were our SCOOP/STACK Acquisitions, cash dividend payments to our common stockholders, and development capital expenditures, primarily at Chaveroo oilfield where we participated in drilling three gross (1.5 net) wells. As of March 31, 2024, working capital was $7.6 million, a decrease of $1.3 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, with $42.5 million drawn as of March 31, 2024. 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%. For the nine months ended March 31, 2024 and 2023, the weighted average interest on our borrowings was 8.13% and 5.25%, respectively. 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 March 31, 2024, we were in compliance with all covenants under the Senior Secured Credit Facility.

On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility. This amendment required that we enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period. We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.

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.

On February 7, 2022, we entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required us to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected crude oil and natural gas production over that period.

On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby we must hedge a minimum of 25% to 75% of future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in the subsequent amendments, as discussed above.

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 Secured 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 $7.5 million as of March 31, 2024. 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 42 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 May 6, 2024, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on June 14, 2024 and payable on June 28, 2024.

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.

In December 2022, we entered into a Rule 10b5-1 plan that authorized a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan was effective until June 30, 2023 and had a maximum authorized amount of $5.0 million over that period. During the three and nine months ended March 31, 2023, 0.6 million shares of our common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct transaction costs. These shares were subsequently cancelled.

In November 2023, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 million over that period. We may alter the terms of the plan from time to time to the extent we determine changes are necessary to achieve the intended objectives of our repurchase program. During the three and nine months ended March 31, 2024, 0.1 million shares of the Company’s common stock have been repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs. These shares were subsequently cancelled.

Capital Expenditures

During the nine months ended March 31, 2024, we incurred $9.4 million in capital expenditures, a majority of which was spent at the Chaveroo Field where we participated in the drilling and completion of three gross (1.5 net) wells. First production on the three gross wells at Chaveroo Field occurred at the beginning of February 2024. During the first fiscal quarter of 2024, we also participated in the drilling and completion of two new wells in the Delhi Field. Production of the Delhi wells came online in the first fiscal quarter of 2024 and produced consistently in the second fiscal quarter.

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 $12.0 million, which excludes any potential acquisitions. Our expected capital expenditures for fiscal year 2024 include the two new drilled wells at Delhi Field and three wells at Chaveroo Field, both of which are discussed above. As mentioned in Recent Developments, we closed three separate definitive agreements to purchase oil and natural gas properties in the SCOOP/STACK plays in central Oklahoma for a combined purchase price of $40.5 million after taking into account preliminary post-close adjustments. Our budgeted capital expenditures discussed above also include capital projects associated with properties acquired in the SCOOP/STACK Acquisitions.

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 March 31, 2024 were $77.64 per barrel of oil, $2.44 per MMBtu of natural gas and $29.88 per barrel of NGLs. As of March 31, 2024, 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 March 31, 2024 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 March 31, 2024, while all other factors remained constant, would not have generated an impairment.

Overview of Cash Flow Activities

Cash provided by operating activities for the nine months ended March 31, 2024 decreased $37.0 million compared to the nine months ended March 31, 2023 primarily due to a decrease in revenues. Total revenues decreased $45.7 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 $19.71, or 35.8% from the prior year period. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the nine months ended March 31, 2024 increased $47.9 million compared to the nine months ended March 31, 2023 primarily due to the acquisition of our SCOOP/STACK properties in February 2024 together with an increase in capital expenditures related to the drilling and completion of three new wells in the Chaveroo Field. As of the quarter ended March 31, 2024, we have paid approximately $43.8 million for the SCOOP/STACK Acquisitions and have accrued estimated preliminary purchase price adjustments of $3.3 million related to net cash flows earned on the properties from the effective date to the closing date to arrive a net purchase price of $40.5 million.

Net cash flows provided by financing activities for the nine months ended March 31, 2024 were $29.4 million compared to net cash flows used in financing activities of $37.3 million for the nine months ended March 31, 2023. In the current year period, we borrowed $42.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions which was partially offset by $12.0 million cash dividends paid to our common stockholders together with $0.8 million paid to repurchase shares of common stock under our share repurchase plan. In the prior year period, we had repayments totaling $21.3 million of borrowings outstanding under our Senior Secured Credit Facility, $12.1 million in cash dividends paid to our common stockholders and $3.9 million paid to repurchase shares of common stock under our share repurchase program.

Results of Operations

Three Months Ended March 31, 2024 and 2023

We reported net income of $0.3 million and $14.0 million for the three months ended March 31, 2024 and 2023, 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 $23.0 million and $36.9 million for the three months ended March 31, 2024 and 2023, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE partially offset by an increase in our crude oil sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the three months ended March 31, 2024 decreased approximately $22.69 per BOE, or 39.3%, compared to 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 71.7% from the prior year period, which was the largest portion of the driver of the decrease in revenues. This was partially attributed to the prior year period benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $20.31 per MCF in the prior year period compared to $3.94 per MCF in the current year quarter. Average daily equivalent production increased 1.7% from 7,089 BOEPD in the prior year period to 7,209 BOEPD in the current period primarily due to the acquisitions of non-operated working interests in the SCOOP/STACK in the latter part of February 2024 and first production at our wells in the Chaveroo Field in early February 2024, which collectively increased current quarter production by approximately 1,020 BOEPD. These increases were partially offset by a decrease in production at our Barnett Shale properties. We began experiencing production declines and downtime in April 2023 at Barnett Shale. Production declines were primarily 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. As of March 31, 2024, the midstream issues have been moderated, but due to low natural gas prices the shut-in wells remain offline which has continued to negatively impact production volumes.

Lease Operating Costs

Ad valorem and production taxes were $1.5 million and $1.6 million for the three months ended March 31, 2024 and 2023, respectively. On a per unit basis, ad valorem and production taxes were $2.22 per BOE and $2.57 per BOE for the three months ended March 31, 2024 and 2023, respectively. The decrease in ad valorem and production taxes is primarily due to decreases in realized natural gas and NGLs revenues 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 March 31, 2024 and 2023. 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 $0.8 million decrease in CO2 costs for the three months ended March 31, 2024 was primarily due to a 43.2% decrease in purchased CO2 volumes, which was primarily due to the suspension of CO2 purchases at the end of February 2024 due to maintenance on the CO2 pipeline. 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 $1.58 per BOE and $2.85 per BOE for the three months ended March 31, 2024 and 2023, respectively.

Other lease operating costs were primarily flat, compared to the prior year period. On a per unit basis, other lease operating costs decreased slightly to $15.44 per BOE for the three months ended March 31, 2024 from $15.84 per BOE in the year-ago quarter. The largest decrease in operating costs was at our Barnett Shale properties offset by an additional LOE incurred as a result of our SCOOP/STACK Acquisitions. 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 experiencing lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $2.4 million or 78.6% from $3.1 million to $5.5 million for the three months ended March 31, 2024 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $8.43 per BOE and $4.86 per BOE for the three months ended March 31, 2024 and 2023, respectively. The depletion rate of our unit of production calculation increased due to decreases in proved reserve volumes as well as increases in our depletable base due to our SCOOP/STACK Acquisitions and capital expenditures since March 31, 2023. Our proved reserves volumes have decreased since the prior year period primarily due to oil and natural gas volumes produced combined with a reduction in the SEC prices used in calculating proved reserves since the prior year period.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2024 increased minimally over the prior year period. General and administrative expenses were $1.9 million for the three months ended March 31, 2024 compared to $1.8 million for the prior year period. The increase primarily relates to an increase in salary and employee benefits due to additional personnel added as additional assets were acquired. On a per unit basis, general and administrative expenses were $2.85 per BOE and $2.84 per BOE for the three months ended March 31, 2024 and 2023, respectively.

Stock-based Compensation Expense

Stock-based compensation expense for the three months ended March 31, 2024 remained flat at $0.5 million for each 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 a result of our SCOOP/STACK Acquisitions in the current quarter and 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 the hedges and the continued increase in forward commodity prices resulted in a realized loss on hedges for the current quarter and an unrealized loss on the mark-to-market of our hedges, respectively. As of March 31, 2024, we had $0.3 million derivative asset all of which was classified as current, and a $1.4 million derivative liability, all of which was classified as current.

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

Interest Expense

Interest expense increased $0.5 million for the three months ended March 31, 2024 compared to the prior year period primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions during the current period.

Income Tax (Expense) Benefit

For the three months ended March 31, 2024, we recognized income tax expense of $0.2 million on net income before income taxes of $0.4 million compared to income tax expense of $3.9 million on net income before income taxes of $17.9 million for the three months ended March 31, 2023. The effective tax rates were 35.2% and 22.0% for three months ended March 31, 2024 and 2023, respectively. The effective tax rate increased compared to the prior year period as projected state income taxes have become a larger component of our overall income tax expense during the period.

Nine Months Ended March 31, 2024 and 2023

We reported net income of $2.8 million and $35.1 million for the nine months ended March 31, 2024 and 2023, 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 $64.7 million and $110.3 million for the nine months ended March 31, 2024 and 2023, respectively. The decrease in revenues 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 nine months ended March 31, 2024 decreased approximately $19.71 per BOE, or 35.8%, 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 64.5% from the prior year period, which was the largest portion of the driver of the decrease in revenues. This was partially attributed to the prior year period benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $12.99 per MCF in the prior year period compared to $4.16 in the current year period. Average daily equivalent production decreased 9.1% from 7,314 BOEPD in the prior year period to 6,651 BOEPD in the current period as a result of natural production declines in our properties combined with operational issues and downtime at our Barnett Shale property. We began experiencing production declines and downtime in April 2023 at Barnett. Production declines were primarily 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. As of March 31, 2024, the midstream issues have been moderated, but due to low natural gas prices the shut-in wells remain offline which has continued to negatively impact production volumes. The overall decrease in production was partially offset by the acquisitions of non-operated working interests in the SCOOP/STACK in February 2024 and first production at our wells in the Chaveroo Field in early February 2024, which collectively increased production for the nine months ended March 31, 2024 by approximately 340 BOEPD.

Lease Operating Costs

Ad valorem and production taxes were $4.0 million and $7.0 million for the nine months ended March 31, 2024 and 2023, respectively. On a per unit basis, ad valorem and production taxes were $2.19 per BOE and $3.49 per BOE for the nine months ended March 31, 2024 and 2023, 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 nine months ended March 31, 2024 and 2023. 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 $1.8 million decrease in CO2 costs for the nine months ended March 31, 2024 was primarily due to a 26.2% decrease in purchased CO2 volumes combined with a 4.0% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price and the suspension of CO2 purchases at the end of February 2024 due to maintenance on the CO2 pipeline. CO2 volumes injected were also reduced compared to prior year period due to a reduction in CO2 purchase nominations and higher ambient temperatures in the Delhi Field during the fiscal year. In the prior year period, CO2 purchase nominations were higher to compensate for reduced reservoir pressure. 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 $2.32 per BOE and $3.01 per BOE for the nine months ended March 31, 2024 and 2023, respectively.

Other lease operating costs decreased $6.1 million, or 17.5%, 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 $15.65 per BOE for the nine months ended March 31, 2024 from $17.31 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 $4.1 million or 42.5% from $9.6 million to $13.7 million for the nine months ended March 31, 2024 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $7.48 per BOE and $4.79 per BOE for the nine months ended March 31, 2024 and 2023, respectively. The depletion 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 our SCOOP/STACK Acquisitions and capital expenditures since the prior year period. Our proved reserves volumes have decreased since the prior year period primarily due to oil and natural gas volumes produced, combined with a reduction in the SEC prices used for calculating proved reserves since the prior year period.

General and Administrative Expenses

General and administrative expenses for the nine months ended March 31, 2024 decreased $0.2 million, or 3.7%, to $5.9 million compared to $6.2 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 in the prior year period. On a per unit basis, general and administrative expenses were $3.25 per BOE and $3.08 per BOE for the nine months ended March 31, 2024 and 2023, respectively. The slight increase on a per unit basis is primarily the result of the decrease in production for the current year period.

Stock-based Compensation Expense

Stock-based compensation expense for the nine months ended March 31, 2024 increased $0.4 million to $1.6 million compared to $1.2 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 a result of our SCOOP/STACK Acquisitions in the current quarter and 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 the hedges and the continued increase in forward commodity prices resulted in a realized loss on hedges for the current quarter and an unrealized loss on the mark-to-market of our hedges, respectively. As of March 31, 2024, we had $0.3 million derivative asset all of which was classified as current, and a $1.4 million derivative liability, all of which was classified as current.

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

Interest Expense

Interest expense increased $0.2 million for the nine months ended March 31, 2024 compared to the prior year period primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions during the current year.

Income Tax (Expense) Benefit

For the nine months ended March 31, 2024, we recognized income tax expense of $1.2 million on net income before income taxes of $4.0 million compared to income tax expense of $9.9 million on net income before income taxes of $45.0 million for the nine months ended March 31, 2023. The effective tax rates were 29.2% and 22.1% for three months ended March 31, 2024 and 2023, respectively. The effective tax rate increased compared to the prior year period as projected state income taxes have become a larger component of our overall income tax expense during the period.

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. In accordance with our Senior Secured Credit Facility, we may be required to enter into hedges if we meet certain utilization levels of the borrowing base under the credit facility. We intend to remain in compliance with these covenants and will enter into derivative contracts from time to time to meet the requirements. Additionally, depending on market conditions, financial and other considerations we may enter into additional hedges to meet our objectives of increasing value to shareholders.

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 2024 and 2023, 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 7, “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 March 31, 2024 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 March 31, 2024, 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.