Evolution Petroleum reported flat production and flat realized prices in fiscal 2026, but swung to a $2.4 million net loss as bank-mandated oil hedges cost $6.07 per barrel during a March price spike and interest expense rose on acquisition debt.
Flat production, flat prices — and a hedge the bank required turned a small profit into a loss
Evolution Petroleum's fiscal year 2026 (the twelve months ended June 30, 2026) produced almost exactly the same barrels at almost exactly the same prices as fiscal 2025. Revenue rose 0.6% to $86.3 million, and average daily production was essentially unchanged at 7,077 barrels of oil equivalent per day ("BOE" — a unit that converts natural gas and natural gas liquids into an oil-equivalent barrel using energy content, six thousand cubic feet of gas to one barrel).
What changed was everything below the operating line. The company swung from $1.5 million of net income to a $2.4 million net loss, and both halves of that $3.9 million swing came from financing decisions rather than from the wells: a $3.3 million negative swing on commodity hedges and $0.9 million more interest expense, both traceable to the same event — borrowing on the credit facility in August 2025 to buy mineral interests in Oklahoma's SCOOP/STACK plays.
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$1.5M
−264.9%
Diluted EPS
$(0.08)
$0.03
n/m
Average daily production
7,077 BOEPD
7,074 BOEPD
+0.0%
Realized price per BOE (before hedges)
$33.43
$33.25
+0.5%
Realized oil price per barrel (after hedge settlements)
$60.54
$67.55
−10.4%
Dividends declared per share
$0.48
$0.48
0.0%
Cash from operations
$23.5M
$33.1M
−28.8%
Operating margin above is income from operations divided by revenue — the share of each revenue dollar left after field costs, depletion and corporate overhead, before interest, hedges and tax.
The hedge was not a choice
Evolution is a non-operated producer: it owns working interests and mineral/royalty interests in fields run by other companies (Continental, Ovintiv, EOG, Merit, Denbury/ExxonMobil and others). It funds acquisitions partly with a senior secured credit facility from MidFirst Bank, and that facility carries a hedging covenant — once borrowings pass a utilization threshold, the company must lock in future selling prices on a share of its output.
After drawing $15.0 million to fund the $16.3 million SCOOP/STACK Minerals Acquisition in August 2025, that covenant kicked in and, in the filing's words, the company "was required by terms in our Senior Secured Credit Facility to hedge 75% of our crude oil and natural gas production (excluding NGLs)."
Then prices went the wrong way for a hedger. Management describes WTI crude dropping below $56 a barrel in December 2025 and rising above $100 by March 2026, attributing the spike to "crude oil disruptions at key oil shipping routes in the Middle East, including the Strait of Hormuz." A producer that has sold its barrels forward does not capture that upside — it pays the difference. Realized (cash-settled) hedge losses were $3.75 million for the year, against $1.0 million of realized gains the prior year:
Derivative result
FY2026
FY2025
Realized gain (loss) — cash settled
$(3.8)M
$1.0M
Unrealized gain (loss) — mark-to-market
$0.9M
$(0.5)M
Net gain (loss) on derivatives
$(2.9)M
$0.5M
The per-barrel view is the clearest one: the cash cost of oil hedges was $6.07 per barrel in FY2026 versus a $0.84 per barrel benefit in FY2025. Unhedged, Evolution's realized oil price was $66.61 versus $66.71 — flat. After hedges, it was $60.54 versus $67.55, down 10.4%. Gas hedges went the other way but are much smaller in dollar terms, adding $0.10 per thousand cubic feet.
Two things follow. First, the loss is not evidence that the underlying assets deteriorated — they performed as expected. Second, this is a structural feature, not a one-off: the hedges exist because the debt exists, and the debt exists because management is buying assets. Expect the same mechanism to cut both ways in future years.
Production was flat, but the mix underneath it moved
Total volumes were 2,583 thousand BOE versus 2,582 — a difference of one. That stability hides real movement. Acquisitions added barrels: the SCOOP/STACK minerals purchase (August 2025), the TexMex working interests (April 2025, so FY2026 was its first full year), and ten gross new wells brought online at SCOOP/STACK. Those additions were offset by natural decline everywhere else, which is what a portfolio of mature, long-lived fields does absent new drilling.
By commodity, oil volumes fell 0.9% to 759 thousand barrels, gas rose 0.2% to 8,428 million cubic feet, and natural gas liquids rose 1.2%. Revenue mix followed prices more than volumes: gas revenue rose 6.5% on a 6.1% higher realized price ($2.97 per thousand cubic feet versus $2.80), while NGL revenue fell 4.2% on a 5.4% lower price. Oil revenue fell 1.1%, and part of that was an accounting catch-up rather than current-year performance — management flags "$1.2 million of prior period adjustments for transportation charges" at the Delhi Field "due to a new marketing contract entered into by the operator dating back to December 2024."
Field costs: two one-offs make the comparison look better than it is
Lease operating costs — what it costs to keep producing wells running — rose 2.0% to $50.3 million on flat volumes. The components tell a more useful story than the total, and two prior-year items distort it in opposite directions.
Other lease operating costs (the core field expense) rose from $32.3 million to $34.4 million, or from $12.50 to $13.33 per BOE. Management attributes $4.1 million of that to the TexMex acquisition annualizing, and notes costs were "elevated during the fiscal year due to the delay in transfer of operatorship from the previous seller to the current operator as well as an extensive workover program in Texas and New Mexico" — a workover being maintenance work on an existing well to restore its flow.
Two offsets flatter the comparison in different directions. FY2025 benefited from a $1.9 million operator credit at a Barnett Shale property following a joint-venture audit, which makes the prior-year cost base artificially low. FY2026 benefited from the end of CO2 purchases at Delhi — $2.6 million of net CO2 bought in FY2025, none this year — and from a $0.8 million refund of 2024–2025 property taxes passed along by the Barnett operator, which is why ad valorem and production taxes fell 16.6% to $4.8 million ($1.84 per BOE from $2.21).
Strip those out and the underlying trend is straightforward: per-barrel field costs on the working-interest assets are rising, and Evolution — which does not operate any of its fields — has limited direct control over them. The filing says so plainly: "we have limited ability to influence the operation or future development of such properties."
Corporate overhead moved the right way. General and administrative expense fell 5.7% to $7.4 million on lower compensation, and stock-based compensation fell to $2.3 million from $2.5 million. Depletion — the accounting charge that spreads the cost of buying and developing reserves across the barrels produced — rose 4.0% to $21.2 million, at $8.21 per BOE versus $7.89, because acquisitions enlarged the cost base being depleted.
The dividend now costs more than the business generates
This is where the year's numbers point somewhere uncomfortable. Evolution has paid 51 consecutive quarterly dividends since December 2013, $151.7 million cumulatively, and held the payout at $0.12 per quarter through FY2026. Management calls distributing free cash flow "a priority of our financial strategy."
The arithmetic for FY2026:
Cash item
FY2026
Cash from operating activities
$23.5M
Cash development capital expenditures
$(7.3)M
Free cash flow (operating cash less development capex)
~$16.2M
Dividends paid
$(16.9)M
Net acquisitions (SCOOP/STACK + Louisiana minerals)
$(23.0)M
Net borrowings drawn
$19.0M
Net equity sold via at-the-market program
$5.8M
Operating cash flow fell $9.5 million year over year, which management attributes to the $3.8 million of realized hedge losses (versus $1.0 million of gains) plus working capital timing. Dividends slightly exceeded free cash flow, and the acquisitions were funded entirely with debt and new shares. The balance sheet shows the cumulative effect: borrowings rose from $37.5 million to $56.5 million, and stockholders' equity fell from $71.8 million to $60.4 million, with retained earnings down from $25.1 million to $5.8 million — the net loss plus a dividend paid out of accumulated profits.
The forward math is tighter still. After the August 2026 equity offering (4.3 million shares at $3.25, $12.8 million net), there were 40.2 million shares outstanding as of September 1, 2026, against a weighted-average 34.3 million during FY2026. At the $0.12 quarterly rate reaffirmed on September 10, 2026, the annual cash dividend obligation is roughly $19.3 million — about 82% of the $23.5 million of operating cash flow the company just generated, before any capital spending at all. That is sustainable if commodity prices cooperate and hedge losses reverse; it leaves very little room if they do not.
Takeaway: Evolution's wells did what they were supposed to do — flat volumes, flat realized prices, positive operating income. The loss came from the financing structure wrapped around them: bank-mandated hedges that cost $6.07 per barrel when oil spiked past $100, plus higher interest on the debt that triggered those hedges. The real question for shareholders is not the loss, it's that issuing shares to fund acquisitions has raised the annual cost of the unchanged $0.48 dividend to roughly $19.3 million against $23.5 million of operating cash flow.
Reserves: stable in total, notably gassier
Proved reserves — the volumes engineers judge recoverable with reasonable certainty under current prices and costs — finished at 27.2 million BOE, up 0.4% from 27.1 million. The standardized measure (the after-tax present value of those reserves, discounted at 10%, using SEC-mandated trailing average prices) rose 0.8% to $156.4 million. At FY2026's production rate, reserves represent roughly 10.5 years of output.
The composition is where the movement is. Liquids fell from 62.2% to 54.6% of reserves, and the proved-developed share slipped from 83.7% to 82.2%. The reconciliation explains both:
+1.6 million BOE purchased via the SCOOP/STACK minerals and Louisiana minerals acquisitions
+0.4 million BOE from extensions, mainly new wells and undeveloped locations at SCOOP/STACK
+0.7 million BOE net revisions, itself a split: gas reserves up 2.2 million BOE because the SEC trailing twelve-month gas price rose 26.1%, offset by oil and NGL reserves down 1.4 million BOE "due to a reduction in the economic life of certain oil fields due to increased costs"
−2.6 million BOE produced and sold
That negative oil revision is the most informative line in the reserve table. Rising field costs — the same per-barrel inflation visible in operating expense — shortened the economic life of some oil properties, meaning wells now hit the point where they cost more to run than they earn sooner than previously modeled. Higher gas prices simultaneously extended gas reserves. The net result is a company that is becoming structurally gassier.
Undeveloped reserves stand at 4.8 million BOE and carry an estimated $74.8 million of future development cost, concentrated at Chaveroo, the Williston Basin and SCOOP/STACK. Against $4–6 million of planned annual capital spending, that is a long development runway.
No write-down was required this year. Under full-cost accounting, a company must test whether the book value of its properties exceeds the discounted value of its reserves and charge the excess to earnings if it does. The test used $72.93 per barrel of oil and $3.62 per million Btu of gas, and passed. Management also ran it on more recent July–September 2026 prices ($76.56 oil, $3.60 gas) and reports it would still pass — a useful disclosure, because the ceiling test is the main path by which a price slump would show up as a large accounting loss.
The strategy shift: buying royalties, not wells
Three of the last four acquisitions were mineral and royalty interests rather than working interests: SCOOP/STACK minerals ($16.3 million, August 2025), Louisiana minerals across the Haynesville/Bossier ($6.2 million, December 2025 through June 2026), and, after year end, Permian minerals in the Midland Basin ($16.0 million, August 2026, adding 3,420 net royalty acres in Reagan, Martin, Midland, Glasscock and Upton Counties, Texas).
Royalty interests entitle the owner to a share of production revenue without bearing the cost of drilling or operating the wells — as the filing puts it, "generally without associated lifting expenses or drilling and completions costs." Given that the year's clearest negative operating trend is per-barrel field cost inflation on assets someone else operates, tilting the portfolio toward interests that carry no operating cost at all is a coherent response to the company's own results. Management also sold 3,700 net non-core, non-producing acres at SCOOP/STACK for $3.1 million on June 30, 2026, so this is some rotation, not pure accumulation.
Liquidity and what to watch next
Cash ended at $6.1 million (from $2.5 million), against $56.5 million drawn on a facility with a $65.0 million borrowing base — $7.7 million of headroom at year end after $0.8 million of letters of credit. Working capital was a $1.8 million deficit, improved from $4.0 million, which management attributes largely to the current portion of derivative liabilities that move with forward prices each quarter. The weighted average interest rate on borrowings fell to 6.69% from 7.48%. The facility matures June 30, 2028, and all covenants (leverage under 3.00x, current ratio above 1.00x, tangible net worth above $40.0 million) were met.
After the August offering, borrowings, and a temporary borrowing-base increase to $73.0 million, available capacity was $12.2 million as of September 1, 2026.
Management's stated plans for fiscal 2027: capital expenditures of $4.0 to $6.0 million — excluding the Permian acquisition, any further acquisitions, and any drilling at Chaveroo — including roughly ten gross wells coming online at SCOOP/STACK.
Three things worth watching:
The October borrowing-base redetermination. The temporary increase to $73.0 million expires October 20, 2026, and the semi-annual fall redetermination begins around October 1. The borrowing base is set by lenders against reserve value; a lower one would tighten the acquisition pipeline and, mechanically, the hedging requirement too.
Whether hedge losses reverse. The $3.8 million of realized losses came from an oil spike management ties to Middle East shipping disruption. If prices settle back toward the strike levels, the same covenant that cost money in FY2026 costs little — and if prices fall, it protects cash flow. This line item is the single largest swing factor in next year's earnings and is not a reflection of operating performance either way.
Dividend coverage against a larger share count. Volumes are flat-to-slightly-growing only because acquisitions offset decline, and each acquisition so far has been funded with debt or new equity that raises the dividend bill. The Permian royalties should help — royalty revenue arrives with no operating cost attached — but the burden of proof is now on whether the acquired assets generate enough incremental cash to cover the roughly $2.1 million of additional annual dividend that the offering's 4.3 million new shares created.
My read: the operating business is stable and unimpaired, the reserve base is holding, and no covenant is under stress. But FY2026 consumed the cushion — retained earnings down to $5.8 million, debt up 51%, share count up — to keep the payout and the acquisition program running simultaneously. FY2027 is where those two priorities either start paying for each other or start competing.