BSIN — Q2 2026 Financial Report Analysis

Higher oil prices kept revenue up 5% on 31% less production, while the real story is a helium plant that has to be built and paid for before it earns anything

Big Sky Industrial, until June 2026 called U.S. Energy Corp., is a small oil producer turning itself into a helium and carbon-storage business in Montana. Its second quarter of 2026 had two parts. Its remaining oil wells brought in $2.1 million of revenue, up 5.2% from a year earlier. Production fell 31%, but the average price it got for its oil rose 41%, from $55.14 to $77.73 a barrel. Its net loss narrowed to $2.3 million ($0.04 a share) from $6.1 million ($0.19). Most of that improvement came from charges in last year's quarter that did not come back this year, not from the business getting better.

The figures that matter more for the stock are about the build-out. The company spent $9.7 million in cash on its helium project in the first half. It says it still needs $20–25 million to reach first helium sales in the first quarter of 2027. It had $16.4 million of available liquidity on August 4.

At a glance

• Revenue of $2.1 million (+5.2%) came entirely from a higher oil price. Oil volumes fell 22% after the company sold its Wyoming and West Texas wells. The oil business is now a small cash-generating sideline, not a growth engine.
• The net loss narrowed by $3.8 million, but $3.2 million of that came from last year's one-off charges ($2.76 million impairment plus a $0.42 million loss on asset sales). Excluding those, the operating loss improved by about $0.7 million.
• Remaining project spending is $20–25 million, against $16.4 million of liquidity (cash plus undrawn credit line) on August 4. Before counting the ongoing operating losses, that leaves $3.6–8.6 million to find. The likely sources are more share sales or new project financing, and the share count has already risen 53% since December.

BOE (barrel of oil equivalent) puts oil and gas on one scale, with 6,000 cubic feet of gas counted as one barrel. Lease operating expense (LOE) is the day-to-day cost of keeping wells running. Operating margin is operating profit (here, loss) as a share of revenue.

Takeaway: The oil numbers are now a sideshow. The quarter's real test is whether Big Sky can pay for its helium plant without excessive further dilution. Management puts the remaining spend at $20–25 million, against $16.4 million of liquidity, and the plant earns nothing until early 2027. Shareholders have already funded $17.2 million of equity this year, and the share count is up 53% since December. More of the same is the most likely way to close the gap.

Price did the work, volume went the other way

The 10-Q's revenue table shows two forces pulling in opposite directions:

• Volume: oil sold fell from 33,445 to 26,166 barrels (-22%). At last year's $55.14 price, the lost barrels would have cost about $0.40 million of revenue. Natural gas and liquids volumes roughly halved (-51%), and that revenue fell from $0.18 million to $0.10 million.
• Price: the $22.59 a barrel higher oil price on the 26,166 barrels sold added about $0.59 million.

Price outweighed volume, so oil revenue rose $0.19 million (+10%) and total revenue rose $0.11 million. Management attributes the volume drop to "the divestitures of our properties in Wyoming and West Texas and the natural decline in production in remaining producing assets." Compared with the previous quarter, volumes were roughly flat. Q1 2026 works out to about 34,290 BOE (the six-month total minus Q2), against 33,747 in Q2. Revenue still rose from about $1.6 million to $2.1 million because the realized oil price climbed: the six-month average was $71.05 against $77.73 in Q2. This means the asset sales are mostly behind the company, and from here oil revenue will track the oil price fairly directly.

Cost per barrel improved slightly. LOE fell to $29.48 per BOE from $31.14, which the company says is a change in which wells are left, not a cost-cutting program. LOE plus production taxes (about $4.89 per BOE) take roughly $34 of a $63 BOE. That leaves about $29 per BOE before overhead. At around 371 BOE/day, the field cannot cover a corporate overhead line of $2.6 million a quarter.

What the headline numbers hide

• Most of the improvement is the absence of last year's charges. Q2 2025 included a $2.76 million ceiling-test impairment, a write-down of the oil properties' book value when lower oil prices reduced the value of reserves, plus a $0.42 million loss on asset sales. Neither recurred. The ceiling test at June 30, 2026 used $71.90 oil and produced no write-down. Excluding those items, the operating loss was about $3.06 million a year ago, against $2.39 million now.
• Overhead went up, not down. General and administrative (G&A) expense, the cost of running the company rather than the wells, rose 18% to $2.65 million. Cash compensation rose 40% ($0.63 million to $0.88 million), which the 10-Q attributes to "discretionary employee compensation accrued in the current period." Stock-based compensation rose 50% ($0.56 million to $0.85 million). G&A alone was 124% of revenue.
• A small paper hedging gain flattered the loss. On April 7 the company bought a "costless collar" on 3,800 barrels a month from June 2026 to July 2027. This contract guarantees at least $65 a barrel (WTI average) but gives up any gain above $88.09. That covers about 44% of Q2's roughly 8,700 barrels a month of oil output. The quarter's $167 thousand derivative gain is entirely unrealized: no cash changed hands, and settlements received were zero. Without it, the net loss would have been about $2.45 million.
• Cash burn is smaller than the loss, but still real. First-half operating cash flow was -$3.25 million, against a net loss of $5.47 million. The gap is mostly non-cash items: $1.15 million of depreciation, depletion and amortization (DD&A, the accounting charge for using up wells and equipment) and $1.13 million of stock compensation. Investing outflows were $10.09 million, of which $9.70 million was industrial-gas capital spending. Total first-half cash need was about $13.3 million. It was covered by $17.2 million of share sales ($8.1 million from a March underwritten offering and $9.1 million through a "committed equity facility," under which an investor, Roth Principal, buys shares at a 2.5% discount on demand) and a $2.0 million credit-line draw.
• Dilution is the main per-share story. Weighted average shares rose 60% year on year. Even with the improvement, the loss per share narrowed faster ($0.19 to $0.04) than the dollar loss ($6.06 million to $2.28 million) partly because the loss is now spread across more shares. Shares outstanding went from 34.4 million at December 31 to 52.5 million at June 30. As of June 30, about $15.9 million (or 15.3 million shares, whichever is lower) remained available under the equity facility. In May, shareholders removed the cap that had limited issuance to 19.99% of the share count.
• Leverage is low, but the liabilities are not just debt. Debt was $4.5 million at June 30, against $6.0 million of cash, a small net cash position. After a $4.0 million draw in July, debt was $8.5 million on August 4, against $4.9 million of cash. The balance sheet also carries $8.3 million of asset retirement obligations (the estimated cost of plugging and cleaning up old wells). Lenders have suspended financial covenant tests through the quarter ending March 31, 2027. That removes a near-term trip-wire, and it shows the company could not comfortably meet those tests while it builds the plant.
• A schedule wording difference to watch. The 10-Q's "Recent Developments" section still says commissioning is "targeted for the third quarter of 2026." The same-day earnings release says "late 2026." Both keep first gas and first revenue in the first quarter of 2027, so the release is the more recent wording.

The helium project in plain numbers

The planned plant at the Big Sky Carbon Hub in Toole County, Montana takes in up to 8.0 million cubic feet of raw gas a day. From that it would produce about 14.4 million cubic feet (MMcf) of helium a year and about 125,000 metric tons of CO₂, which would be injected underground or reused.

• Helium sales are contracted. On April 27 the company signed a five-year deal with an unnamed investment-grade industrial gas company. The buyer must pay for up to about 1.2 MMcf a month whether or not it takes delivery ("100% take-or-pay"). The price is a fixed $285 per thousand cubic feet at the plant gate, with inflation-linked increases from March 2028 and a price reset in year three. At the full 14.4 MMcf a year, that is about $4.1 million of annual helium revenue (our arithmetic: 14,400 Mcf × $285). That is useful contracted income, but on its own it is not large relative to a $20–25 million remaining build cost. The company's own risk factors note that the fixed price "limits our ability to benefit from higher helium prices."
• The bigger value depends on carbon credits. The company puts the federal Section 45Q tax credit for storing CO₂ at about $130 million over the first 12 years of Phase 1. To claim it, the EPA must first approve the company's monitoring and verification ("MRV") plans for the Big Rose and Cut Bank sites. Both are in review, and approval is "expected in the coming months." Under the 2025 Synergy acquisition, the company also owes the seller 18% of the cash it actually realizes from carbon sequestration in the area. It must also pay 100% of Synergy's retained 20% share of costs, for up to 78 months or $20 million, whichever comes first.
• Phase 2, a second plant on the same site, is in early planning and not in management's base case.

Outlook

Management gave no revenue or earnings guidance. It did give a timeline: gathering pipelines installed over summer and fall 2026, plant commissioning late 2026, MRV approvals "in the coming months," and first gas and first helium revenue in Q1 2027. On spending, the 10-Q puts the remaining near-term program at $20–25 million, plus up to $0.5 million for plugging old wells. It will be funded by "cash on hand, operating cash flows, proceeds from the divestiture of oil and natural gas properties, borrowings under our credit facility, additional equity issuances, and potential project-specific financing."

Our read: the oil business will roughly break even at the field level and lose money after overhead until helium starts. Each quarter until then will look like this one: a loss of $2–3 million and steady share issuance. Three things will show whether the plan is on track:

1. EPA approval of the MRV plans. Without them, the 45Q credit value, which is most of the project's long-term value, stays out of reach.
2. How the $3.6–8.6 million funding gap is closed. Equity-facility sales at a discount dilute existing holders. Project-level debt or an asset sale would not.
3. Whether commissioning holds at late 2026. EPC (engineering, procurement and construction) delays or cost overruns would hit a company with only $16.4 million of liquidity hard.

With the oil-asset sales mostly done, the next oil-price move matters more than volumes. The $65 floor on about 44% of output limits the downside through July 2027.

The Q2 2026 Form 10-Q (filed August 11, 2026) and the same-day earnings release are the sources for all figures. Adjusted EBITDA is the company's non-GAAP measure, earnings before interest, tax, depreciation and certain non-cash items. Its reconciliation adds back DD&A, stock compensation, the unrealized derivative gain, securities gains or losses and, in 2025, the impairment and loss on sale.