Modiin Energy in the First Quarter: Operating Recovery Meets Big Foot's Larger Funding Need

Modiin Energy enters 2026 with a quarter that clarifies the story without cleaning it up. Operationally, the first quarter was much better than the fourth quarter of 2025: revenue rose 41%, EBITDA returned to positive territory, and the net loss narrowed. The problem is that this improvement has not yet reached the cash account, because the main NPB customer moved from current plus 30 payment terms to current plus 60, and trade receivables jumped from $1.7 million to $4.1 million. At the same time, after the balance-sheet date, the partnership signed the Big Foot transaction at a completely different scale: a $190 million base purchase price, a $10 million deposit, and dependence on financing, partners, waiver of the right of first refusal and approvals. So this quarter is not only an update on oil production in Colorado. It moves the market's focus to whether the partnership can close a much larger funding structure without eroding unitholder economics. The next proof point is twofold: whether the collection delay is truly one-off, and whether Big Foot advances with financing and partners that leave public unitholders with a meaningful economic share.

The quarter improved, but cash did not arrive

Modiin Energy is an oil and gas exploration and development partnership, but its current economics are no longer only about exploration. Most revenue comes from the NPB project in Colorado, where there is existing production, potential operating cash flow and dedicated bank debt. Alongside NPB are Chittim Ranch in Texas, Grapevine and Cassini in California, and Samson in Israel, but in the first quarter NPB alone generated $5.6 million of the partnership's $6.1 million revenue. In other words, the current operating business remains highly concentrated, while most of the upside sits in assets, deals and development plans that still require funding and execution.

First-quarter revenue was $6.1 million, compared with $4.3 million in the fourth quarter of 2025. That is a real improvement, not just an accounting movement: oil barrels sold increased to about 93,500 from about 80,000 in the prior quarter, and the average sales price after transportation cost rose to about $63.7 per barrel from about $51.6. EBITDA, the non-IFRS metric the partnership uses for operating profit before depreciation, depletion and amortization, returned to a profit of $1.45 million after negative EBITDA of $0.8 million in the fourth quarter.

But that is only half the picture. Compared with the first quarter of 2025, revenue fell 34%, because barrels sold declined from about 142,000 to about 93,500, while EBITDA fell 59% from $3.53 million. The prior-year quarter benefited from the initial contribution of the 2024 NPB drilling program, so that comparison reminds investors that the partnership still needs a new funded development plan to restore production momentum. That was also the open issue in the prior annual coverage: reserves and assets can look larger, but without a funded work plan they do not turn into cash quickly enough.

The chart shows why the quarter deserves caution. Revenue recovered versus late 2025, but operating cash flow weakened to a $1.42 million outflow. For a small partnership trying to advance a $190 million transaction, cash quality matters more than the headline of positive EBITDA.

The sharpest point in the quarter is not the year-over-year revenue decline. It is where the cash got stuck. Payment terms for the NPB customer moved from current plus 30 to current plus 60. The immediate result was a 146% jump in receivables, from $1.7 million at the end of 2025 to $4.1 million at the end of March 2026, and negative operating cash flow despite positive EBITDA.

Management expects this to be a one-off timing adjustment, with no similar impact expected in the following quarters. That is an important statement, but also a clear test. If receivables fall in the second or third quarter and operating cash flow turns positive, the first-quarter improvement will look higher quality. If receivables stay elevated, the market gets a different story: the business is selling better than in the prior quarter, but it is also financing more customer credit.

Even within NPB, revenue quality is not uniform. In oil, the average price attributable to the partnership was $62.7 per barrel after about $8.5 of transportation cost, royalties were $10.4 per barrel, and production costs were $24 per barrel. Net receipts were $28.3 per barrel. That is still an asset with positive operating economics at first-quarter price levels, but gas remains a weak point: the partnership's share of gas sales was about 254,000 units for about $137,000 of revenue, while gas marketing costs of about $551,000 created an average loss of about $1.9 per gas unit.

The conclusion is that the quarter should not be read as a full recovery. It proves that the business can earn more when price and volume improve, but it has not yet proven that profit reaches the cash account quickly or that gas has stopped weighing on project economics.

Big Foot raises the scale before the funding structure is closed

After the balance-sheet date, Modiin Energy signed, through a wholly owned indirect subsidiary, an agreement to acquire a 12.5% working interest in Walker Ridge Block 29, where the Big Foot Prospect is located, a producing deepwater oil field in the Gulf of America. The field is operated by Chevron, which holds 60%, while Equinor holds 27.5%. For the acquired interest, net production is about 4,500 to 5,000 BOE per day, about 96% of it oil. In 2025, production for the acquired rights was about 1.5 million BOE and revenue was about $100 million. In the first quarter of 2026, production was about 465,000 BOE and revenue was about $32 million.

This asset could change the partnership's scale. The issue is that a purchase agreement is not a funding structure. The base purchase price is $190 million, subject to adjustments from an effective date of July 1, 2025. In addition, there is contingent consideration of up to $15 million, seller royalties of 1% on existing-well revenue and 3% on new-well revenue, and a $10 million deposit held in escrow. Closing depends on waiver of the existing partners' right of first refusal, government and regulatory approvals, third-party consents and provision of required guarantees.

The Eventide agreement adds an important layer, but it does not close the whole story. Eventide received an option to buy units that would give it 10% of the acquiring company's equity after issuance, subject to completion of the asset acquisition and the company's capital-raising needs. In addition, the company will pay Eventide's general partner $1.9 million for asset identification and evaluation services, in a structure that changes depending on whether the option is exercised, and will receive asset-management and coordination services from it after closing. This can add expertise and a partial source of capital, but it also highlights that the transaction needs partners, services, funding and an incentive layer above the asset itself.

The most important sentence here is that the partnership's existing financial resources are not sufficient to finance its full share of the acquisition, and it is examining bank financing, equity financing or debt financing in the capital market. After the quarter, an expansion of Series B convertible bonds brought in about NIS 52 million, roughly $17 million, and cash near the approval date of the financial statements was about $25 million. That improves liquidity versus the end of March, but against a $190 million base price and a $10 million deposit, it is bridge capital rather than a complete solution.

The debt position does not currently point to covenant pressure. For Series C bonds, the loan-to-collateral ratio was 23%, versus a 50% ceiling. In the NPB bank loan, LTV was 22.6%, versus a 65% ceiling, and coverage ratios were 2.43 and 2.2, above the minimum 1.25 threshold. Still, this flexibility is not free: cash declined from $16.4 million at the end of 2025 to $8.9 million at the end of March, mainly because of a $2.6 million Series C bond repayment and $2.9 million of interest payments. The post-period Series B issuance puts more air back into the cash account, but it also reminds investors that the partnership is relying on the capital market to keep its largest options open.

Hedging adds another layer of complexity. The partnership hedged 190,800 barrels of oil for April 2026 through December 2027 through Collar transactions, with a $55 per barrel put and call prices of $65 to $73.3. The hedge protects a cash-flow floor, but when oil rises it also caps part of the upside and created a derivative liability of $2.4 million and other comprehensive loss of $2.8 million at the end of March. A stronger oil environment therefore supports revenue, but it is not fully open to the partnership.

Chittim advanced, NPB is still waiting for a plan

At Chittim Ranch, there was progress that was not in place at the end of 2025. Carapace received a non-binding offer to acquire all of Modiin Energy's rights in the project for $6 million in cash, a transaction that, if completed, is expected to generate a pre-tax gain of about $2.2 million. At the same time, the LFO transaction is moving forward: in the first stage, $10 million was transferred to escrow, and in April 2026 LFO confirmed that Carapace obtained 93% of the mineral-right-owner consents, above the required 88% threshold, so the funds were released from escrow.

This development strengthens the Carry path at Chittim, but it is still not free cash at the public partnership level. Carapace is still working to complete the second stage of the LFO transaction, after which LFO will have 30 days to review the final closing statement. In other words, Chittim is less stuck than before, but it has still not become a clean monetization channel for Modiin Energy.

At NPB, the picture is the opposite: the asset is operating and generates most revenue, but the 2026 plan has not yet been presented to the partnership. The operator is preparing a plan that includes approvals for drilling work, new drilling, production facilities and natural-gas treatment facilities, and management expects it to include wells that satisfy 2026 lease commitments. That wording explains why NPB has still not closed its main proof point. The partnership invested $2.8 million in NPB in the first quarter, but there is still no approved development plan tying reserves, budget, permits and cash-flow timing together.

Conclusion

The first-quarter conclusion is that the partnership improved operationally versus late 2025, but has not yet proven that improvement converts into stable cash. NPB remains the main revenue source, Chittim advanced through the LFO path, and Big Foot could change the partnership's scale. The key constraint has shifted from "are there assets" to "at what cost of capital will those assets reach unitholders." In the coming quarters, the market will focus less on quarterly revenue and more on funding completion, partners, closing terms and a return to positive operating cash flow.

The strongest counter-thesis is that this caution may prove too high: the partnership improved versus the fourth quarter, expanded Series B bonds, showed comfortable covenant headroom, and signed a transaction that can add a producing asset much larger than the existing business. If NPB payment terms created only a one-off delay, if Chittim moves to final closing, and if Big Foot arrives with financing and partners on reasonable terms, Modiin Energy could look different within a few quarters. If any of those conditions stalls, the first quarter will be remembered less as an operating recovery and more as the quarter in which the opportunity set grew faster than the ability to finance it.