EVOLUTION PETROLEUM CORP

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:

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 CO 2 costs per Mcf and CO 2 volumes for the nine months ended March 31, 2024 and 2023. CO 2 purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO 2 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 CO 2 costs for the nine months ended March 31, 2024 was primarily due to a 26.2% decrease in purchased CO 2 volumes combined with a 4.0% decrease in CO 2 costs per MCF, which was driven by a decrease in our average realized oil price and the suspension of CO 2 purchases at the end of February 2024 due to maintenance on the CO 2 pipeline. CO 2 volumes injected were also reduced compared to prior year period due to a reduction in CO 2 purchase nominations and higher ambient temperatures in the Delhi Field during the fiscal year. In the prior year period, CO 2 purchase nominations were higher to compensate for reduced reservoir pressure. CO 2 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 CO 2 pipeline which is owned and operated by Denbury. On a per unit basis, CO 2 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.

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.