Evolution Petroleum Reports Full Year and Fourth Quarter Fiscal 2023 Results and Declares Quarterly Cash Dividend for the Fiscal 2024 First Quarter

HOUSTON, Sept. 12, 2023 (GLOBE NEWSWIRE) -- Evolution Petroleum Corporation (NYSE American: EPM) ("Evolution" or the "Company") today announced its financial and operating results for its fiscal fourth quarter and full year ended June 30, 2023. Evolution also declared a quarterly cash dividend of $0.12 per common share for the fiscal 2024 first quarter.

Key Highlights

• Increased revenue 18% over the prior year to $128.5 million, increased net income year-over-year ("YoY") by 8% to $35.2 million, and increased earnings per share 8% to $1.04 per diluted share.
• Generated Adjusted EBITDA1 of $60.1 million for fiscal 2023 – an increase of 14% YoY.
• Produced 7,104 net barrels of oil equivalent per day ("BOEPD") in fiscal 2023 (19% increase YoY).
• Paid quarterly dividends totaling $0.48 per common share for the current fiscal year – a 37% increase from fiscal 2022.
• Repurchased $3.9 million of common shares under our previously announced share repurchase plan, resulting in a total of $20 million returned to shareholders in fiscal year 2023 through dividends and repurchases.
• Maintained significant liquidity and balance sheet strength at fiscal year-end:
  • Paid down $21.25 million in borrowings, ending the year with zero debt outstanding;
  • Increased cash and cash equivalents to from $8.3 million to $11.0 million; and,
  • Maintained $50 million available borrowing capacity under the senior secured credit facility, increasing liquidity from $37.0 million to $61.0 million.
    

Kelly Loyd, President and Chief Executive Officer, commented, "Despite a challenging fiscal fourth quarter that was impacted by much lower quarter over quarter price realizations and extended downtime and maintenance across multiple fields, we are pleased to announce our 2023 fiscal full-year results, in which we recorded our highest ever levels of revenue, production and net income. It was a year of transition that saw EPM strengthen its team of highly valued professionals, fully integrate and absorb previous acquisitions, and focus on process, setting the Company and our shareholders up for future success.”

Mr. Loyd concluded, “Our commitment to providing long-term total returns to our shareholders is underscored by our consistent dividend history and share repurchases. We paid our 39th consecutive quarterly dividend in June, totaling $0.48 per common share for the current fiscal year, representing a remarkable 37% increase from the dividends paid in fiscal 2022 and demonstrating the Board’s confidence in sustaining the increased payout. Our strong cash flow generation from low-decline reserves, zero outstanding debt, and significant liquidity highlight our disciplined approach to maximizing total shareholder returns as we continue to evaluate accretive opportunities to prudently grow the business for the long-term benefit of our shareholders."

Cash Dividend on Common Stock

On September 11, 2023, Evolution’s Board of Directors declared a cash dividend of $0.12 per share of common stock, which will be paid on September 29, 2023, to common stockholders of record on September 22, 2023. This will be the 40th consecutive quarterly cash dividend on the Company’s common stock since December 31, 2013. To date, Evolution has returned approximately $102.4 million, or $3.09 per share, back to stockholders in common stock dividends. Maintaining and ultimately growing the common stock dividend remains a key Company priority.

(1) Adjusted EBITDA is Adjusted Earnings Before Interest, Taxes, Depreciation, and Amortization and is a non-GAAP financial measure; see the “Non-GAAP Reconciliation” tables later in this release for more information on the most comparable GAAP measures.

Financial and Operational Results for the Year Ended June 30, 2023

(1) Adjusted Net Income is a non-GAAP financial measure; see the “Non-GAAP Information” section later in this release for more information, including reconciliations to the most comparable GAAP measures.
(2) Adjusted EBITDA is Adjusted Earnings Before Interest, Taxes, Depreciation, and Amortization and is a non-GAAP financial measure; see the “Non-GAAP Information” section later in this release for more information, including reconciliations to the most comparable GAAP measures.

Total revenues increased 18% to $128.5 million from $108.9 million in the prior fiscal year. The increase was primarily associated with a 19% increase in our average daily equivalent production, which was 5,953 net BOEPD in fiscal year 2022 and increased to 7,104 net BOEPD in the current fiscal year. In the current fiscal year, we benefited from a full year of production from the acquisitions of the Jonah Field and Williston Basin which occurred in the latter half of fiscal year 2022. Partially offsetting the increase in revenue due to production was a slight decrease in our average realized commodity price (excluding the impact of derivative contracts), which decreased YoY by approximately $0.57 per BOE, or 1%. Realized oil and NGL prices decreased approximately 9% and 30%, respectively, over the prior year. These decreases are partially offset by an increase of approximately 28% in realized natural gas prices from the prior year, despite the substantial decrease in natural gas prices that occurred in the latter part of the third quarter of fiscal 2023. The YoY increase in realized natural gas prices is primarily attributed to the benefit of natural gas price differentials received at the Jonah Field where our realized price for natural gas for fiscal year 2023 was $10.63 per MCF.

Lease operating costs (“LOE”) increased to $59.5 million from $48.7 million in fiscal 2022. On a per BOE basis, LOE was $22.96 in the current fiscal year compared to $22.39 in the prior year. Primarily driving the overall increase was the acquisitions of the Jonah Field and Williston Basin which occurred in the latter half of fiscal year 2022. CO2 costs at Delhi Field decreased due to an 8% decline in CO2 costs per MCF driven by the decline in our average realized oil price partially offset by an increase in purchased CO2 volumes.

Depletion, depreciation, and accretion ("DD&A") expense increased 77% to $14.3 million from $8.1 million in fiscal year 2022 primarily due to an increase in production volumes and an increase in our depletion rate. Depletion expense was $5.07 per BOE versus $3.46 per BOE in the prior fiscal year. The increase in depletion per BOE was due primarily to an increase in the depletable base of our unit of production calculation led by our acquisitions in fiscal year 2022, an increase in our future development costs combined with a decrease in our proved reserve volumes.

General and administrative ("G&A") expenses increased 18% to $7.9 million from $6.7 million in fiscal year 2022. The increase in total expenses is due to approximately $0.6 million in salary and employee benefits from the addition of personnel added since the prior year and $0.3 million in professional fees associated with our search for a CEO. Also contributing to the increase are higher fees for accounting and audit-related services and public reporting expenses due to the increased size of our Company. On a per unit basis, G&A expenses were $3.06 per BOE in the current fiscal year compared to $3.09 per BOE in the prior year.

Stock-based compensation increased $1.5 million to $1.6 million from $0.1 million in fiscal year 2022. The prior year included a reduction of $1.2 million of stock-based compensation related to the forfeiture of unvested shares in connection with severance.

Net income was $35.2 million, or $1.04 per diluted share, compared to net income of $32.6 million, or $0.96 per diluted share, in fiscal year 2022.

Adjusted EBITDA increased to $60.1 million from $52.8 million in the prior fiscal year. On a per BOE basis, Adjusted EBITDA decreased to $23.17 per BOE from $24.29 per BOE for the fiscal year 2022 due to the increased production volumes described above.

Financial and Operational Results for the Quarter Ended June 30, 2023

Total production for the fourth quarter of fiscal 2023 was 6,484 net BOEPD, including 1,736 barrels per day (“BOPD”) of crude oil; 22,462 thousand cubic feet per day (“MCFPD”), or 3,748 BOEPD, of natural gas; and 1,000 BOEPD of natural gas liquids (“NGLs”).

• Oil decreased 6% from 1,856 BOPD in the prior quarter, primarily due to downtime at Delhi Field properties where production was shut in for approximately one week to upgrade the facilities and install a heat exchanger to increase plant efficiencies during extreme summer and winter temperatures.
• Natural gas production decreased 8% from 24,489 MCFPD, or 4,077 BOEPD, in the prior quarter primarily due to downtime in the Barnett Shale properties associated with extreme summer weather conditions along with gathering line maintenance and compressor issues.
• NGL production decreased 13% from 1,156 BOEPD in the prior quarter, primarily attributed to downtime at our Delhi Field properties to install the heat exchanger and also perform NGL plant maintenance. At our Barnett Shale properties our NGL volumes were affected by the same factors that impacted our natural gas production.
  

Evolution reported $18.2 million of total revenue for the current quarter, a 51% decrease from the prior quarter. Oil revenue decreased 7% to $11.0 million from the previous quarter, primarily due to a 5% decrease in sales volumes coupled with 2% decrease in realized commodity pricing. Natural gas revenue decreased 77% from the prior quarter to $5.0 million due to a 75% decrease in realized commodity pricing combined with a 7% decrease in sales volumes. NGL revenue decreased 36% to $2.2 million, primarily due to a 27% decrease in realized pricing together with a 13% decrease in sales volumes. The average realized price per BOE decreased 47% to $30.80 compared to $57.79 in the prior quarter.

LOE decreased by 13% to $11.8 million from $13.6 million in the prior quarter. Contributing factors which led to the decrease include a reduction in production taxes due to lower realized natural gas prices, reduced CO2 costs at Delhi Field associated with lower purchased CO2 volumes and the decline in crude oil prices from the prior quarter, and lower workover activity in the Williston Basin.

DD&A expense was $3.8 million compared to $3.4 million in the prior quarter. On a per BOE basis, the Company’s depletion rate of $6.01 increased from the prior quarter due to increases in our depletable base primarily related to increases in future development costs coupled with the reduction in proved reserves.

The Company's G&A expenses, including stock-based compensation, remained flat at $2.3 million for both the current quarter and prior quarter.

Net income for the current quarter was $0.2 million, or $0.00 per diluted share, compared to $14.0 million, or $0.41 per diluted share, in the prior quarter.

Adjusted EBITDA was $4.7 million for the current quarter compared to $22.0 million in the prior quarter. On a per BOE basis, Adjusted EBITDA was $7.92 for the current quarter versus $34.42 for the preceding quarter.

Fiscal Year-End 2023 Reserves

(1) Probable and Possible Developed Reserves are associated with Delhi Field only.
(2) Probable and Possible Undeveloped Reserves are associated with Williston Basin only.

Proved Reserves

For the Company’s fiscal year ended June 30, 2023, SEC proved reserves were 31.2 MMBOE, down 14% from the prior fiscal year. The net decrease in total proved reserves was primarily due to production of 2.6 MBOE and net negative revisions of 2.6 MMBOE partially offset by additions and extensions of 0.1 MMBOE associated with the addition of two new proved undeveloped (“PUD”) wells at Delhi Field. Net negative revisions of 2.6 MMBOE are primarily due to declines in SEC trailing 12-month pricing that impacted late-in-life economic limits of production, adjustment to projections at Delhi Field and increased production costs at Barnett Shale, partially offset by restored production at Hamilton Dome Field and improved economics from our differentials at Jonah Field.

As of June 30, 2023, our PUD reserves included 3.7 MMBOE of reserves and approximately $71.7 million of future development costs primarily associated with the Williston Basin properties.

The SEC pricing (twelve-month first day of the month average prices) used in the report for the fiscal year ended June 30, 2023, was $83.23 per barrel of oil, $33.71 per barrel of NGLs and $4.78 per MMBtu of natural gas a decrease from prior year SEC pricing of $85.82 per barrel of oil, $44.24 per barrel of NGLs and $5.19 per MMBtu of natural gas.

Our proved reserves consist of 32% oil, 49% natural gas, and 19% NGLs; 88% are classified as proved developed producing and 12% are proved undeveloped. Proved undeveloped reserves are primarily attributable to the Williston Basin assets.

Probable and Possible Reserves

The Company's fiscal year ended June 30, 2023, probable and possible reserves were 24.4 MMBOE, up 16% from 21.1 MMBOE from the prior fiscal year ended June 30, 2022. This increase was due to the inclusion of Test Site 5 development at Delhi as well as the potential for increased recoveries in the 2 new Delhi Field PUDs. The Williston Basin probable reserves meet all of the criteria for being determined proved undeveloped reserves, except that they are associated with drilling locations that are not presently scheduled to be developed within the next five years and, therefore, do not meet SEC requirements for proved undeveloped reserves. The Williston Basin possible reserves represent incremental drilling locations within our acreage that the Company expects to continue to evaluate for potential future drilling.

Developed probable and possible categories at Delhi Field represent greater potential recoveries from the CO2 flood than those included in the proved reserves. Consequently, while both the probable and possible reserves are 100% developed and require de minimus capital expenditures, they remain less certain of attainment and have more risk of recovery than proved reserves and should not be aggregated with other categories. These categories of reserves reflect the incremental reserves associated with different engineering assumptions with respect to the percentage of original oil in place that can be recovered through CO2 enhanced oil recovery. The undeveloped probable and possible categories at Delhi Field consist of Test Site 5 development which is technically proven, however currently not scheduled.

Operations Update

At Delhi Field, the heat exchanger project was successfully installed and operational during the fiscal fourth quarter. This project is expected to reduce expenses and improve operational efficiency. During this quarter we approved authorization for expenditure elections to drill two vertical wells in the Delhi Field. These wells were recently drilled and completed during the first quarter of fiscal 2024 and are awaiting results.

In the Williston, the Birdbear sidetrack project was pushed back due to a delay in the NDIC’s approval of operations. The Bakken vertical recompletion and fracture stimulation completed in third quarter fiscal 2023 is online and producing approximately 20 gross BOPD.

At Hamilton Dome, facility consolidation to improve operating efficiency and reduce emissions is ongoing. We expect the project to be finished in fiscal year 2024.

Balance Sheet, Liquidity, and Capital Spending

On June 30, 2023, cash and cash equivalents totaled $11.0 million, and working capital was $8.9 million. Evolution did not have any debt outstanding under its $50 million revolving credit facility after retiring all of the debt incurred in the Williston Basin and Jonah Field acquisitions. As a result, total liquidity on June 30, 2023, was $61.0 million, including cash and cash equivalents. This represents an increase in liquidity of 65% since June 30, 2022.

During fiscal 2023, the Company fully funded operations, development capital expenditures, cash dividends, and share repurchases through cash generated from operations and working capital. For the year ended June 30, 2023, Evolution paid $16.1 million in common stock dividends, repurchased $3.9 million of common shares under its previously announced share repurchase plan, and incurred $6.2 million in development capital expenditures.

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 $4.0 million to $5.0 million, which excludes any potential acquisitions. Our expected capital expenditures for the next 12 months include two new drill wells at Delhi Field and also include Foundation, the operator of our Williston Basin properties, drilling two sidetrack locations targeting the Birdbear formation. Evolution believes its near-term capital spending requirements will be met from cash flows from operations and current working capital.

Conference Call

As previously announced, Evolution Petroleum will host a conference call on Wednesday, September 13, 2023, at 1:00 p.m. Central Time to review its fiscal year-end 2023 financial and operating results. To join by phone, please dial (844) 481-2813 (Toll-free) or (412) 317-0677 (International) and ask to join the Evolution Petroleum Corporation call. To join online, click the following link https://event.choruscall.com/mediaframe/webcast.html?webcastid=xsIVjdfv. A webcast replay will be available through September 13, 2024, via the webcast link above and on Evolution's website at www.ir.evolutionpetroleum.com.

About Evolution Petroleum

Evolution Petroleum Corporation is an independent energy company focused on maximizing total shareholder returns through the ownership of and investment in onshore oil and natural gas properties in the U.S. The Company aims to build and maintain a diversified portfolio of long-life oil and natural gas properties through acquisitions, selective development opportunities, production enhancements, and other exploitation efforts. Properties include 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; as well as small overriding royalty interests in four onshore Texas wells. Visit www.evolutionpetroleum.com for more information.

Cautionary Statement

All forward-looking statements contained in this press release regarding the Company's current expectations, potential results, and future plans and objectives involve a wide range of risks and uncertainties. Statements herein using words such as "believe," "expect," "plans," "outlook," "should," "will," and words of similar meaning are forward-looking statements. Although the Company’s expectations are based on business, engineering, geological, financial, and operating assumptions that it believes to be reasonable, many factors could cause actual results to differ materially from its expectations and can give no assurance that its goals will be achieved. These factors and others are detailed under the heading "Risk Factors" and elsewhere in our periodic documents filed with the Securities and Exchange Commission. The Company undertakes no obligation to update any forward-looking statement.

Our reserves as of June 30, 2023 were estimated by Netherland Sewell & Associates, Inc. and DeGolyer & MacNaughton, global independent reservoir engineering firms. All reserve estimates are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. The SEC's current rules allow oil and natural gas companies to disclose not only proved reserves, but also probable and possible reserves that meet the SEC's definitions of such terms. Estimates of probable and possible reserves by their nature are much more speculative than estimates of proved reserves. These non-proved reserve categories are subject to greater uncertainties and the likelihood of recovering those reserves is subject to substantially greater risk. When estimating the amount of oil and natural gas liquids recoverable from a particular reservoir, probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered, generally described as having a 50% probability of recovery. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. These three reserve categories have not been adjusted to different levels of recovery risk among these categories and are, therefore, not comparable or meaningfully combined.

Investor Relations
(713) 935-0122
info@evolutionpetroleum.com

Evolution Petroleum Corporation
Condensed Consolidated Statements of Cash Flows (Unaudited)
(In thousands)

Evolution Petroleum Corporation
Non-GAAP Reconciliation – Adjusted EBITDA (Unaudited)
(In thousands)

Adjusted EBITDA and Net income (loss) and earnings per share excluding selected items are non-GAAP financial measures that are used as supplemental financial measures by our management and by external users of our financial statements, such as investors, commercial banks, and others, to assess our operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure, or historical costs basis. We use these measures to assess our ability to incur and service debt and fund capital expenditures. Our Adjusted EBITDA and Net income (loss) and earnings per share, excluding selected items, should not be considered alternatives to net income (loss), operating income (loss), cash flows provided by (used in) operating activities, or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. Our Adjusted EBITDA and Net income (loss) and earnings per share excluding selected items may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA and Net income (loss) and earnings per share excluding selected items in the same manner.

We define Adjusted EBITDA as net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion, and accretion (DD&A), stock-based compensation, ceiling test impairment, and other impairments, unrealized loss (gain) on change in fair value of derivatives, and other non-recurring or non-cash expense (income) items.

(1) For the three months ended June 30, 2022 and March 31, 2023, represents the tax impact using estimated tax rates of 23.4% and 20.7%, respectively. For the years ended June 30, 2023 and 2022, represents the tax impact using an estimated tax rate of 22.2% and 23.4%, respectively.
(2) Net income (loss) and earnings per share excluding selected items are non-GAAP financial measures presented as supplemental financial measures to enable a user of the financial information to understand the impact of these items on reported results. These financial measures should not be considered an alternative to net income (loss), operating income (loss), cash flows provided by (used in) operating activities, or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. Our Adjusted Net Income (Loss) and earnings per share may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted Net Income (Loss) and earnings per share in the same manner.
(3) The impact of selected items for the three months ended June 30, 2023, June 30, 2022, and March 31, 2023 was calculated based upon weighted average diluted shares of 32.9 million, 33.5 million and 33.2 million, respectively, due to the net income (loss), excluding selected items. The impact of selected items for the years ended June 30, 2023 and 2022 were calculated based upon weighted average diluted shares of 33.2 million and 33.3 million, respectively, due to the net income (loss), excluding selected items.

(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.

(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.