Follow-up to Modiin: NPB Looks Bigger, but Who Funds the Drilling Plan?
The updated NPB reserve report materially expands the paper value layer, with after-tax PV10 of about $214.9 million on a 2P basis, but that uplift rests on a roughly 101-well program and about $221 million of five-year development spending attributable to Modiin. Until the 2026 plan is presented and a funding route is visible, a large part of that value remains conditional rather than near-cash.
Starting Point
The main article argued that financing still shapes the Modiin story more than another asset presentation does. This follow-up isolates NPB because that is where the largest visible value layer now sits, and where the gap between reported value and financeable value is currently the sharpest.
The new report does change the picture. It updates the partnership's after-tax discounted value in NPB to about $124.4 million on a 1P basis, about $214.9 million on a 2P basis, and about $239.5 million on a 3P basis, all at a 10% discount rate. That is enough to make clear that NPB is not only a producing base. It is also a larger development platform than the market may have been crediting before.
But that is only half the story. The same reserve report says the estimates are not risk-adjusted for technical, commercial, or development risk, that discounted cash flow is not the same as fair value, and that the model rests on a multi-year development plan of about 100 wells over about 10 years. At the same time, the annual report says that as of the approval date of the financial statements, the 2026 development plan had still not been presented to the partnership. In other words, the evaluator already had a broad development path, while unitholders still do not have an approved 2026 budget.
That leads to the core conclusion of this follow-up:
- the reserve update answers the question of how large NPB could be,
- it still does not answer who is expected to fund the path there,
- and until the second question is addressed, the 2P and 3P layers remain leveraged optionality more than near-cash value.
The Reserve Report Looks Bigger, but It Is Not a Budget
To understand the gap, two statements have to be held together at once. The first is constructive: the multi-year plan presented to the evaluator includes about 101 wells, with 37 expected in the first three years and another 29 in years four and five. The second is much less comfortable: according to the annual report, the estimated cost of the development plan over the next five years is about $221 million attributable to the partnership, while the 2026 plan itself had still not been presented to Modiin as of the financial-statement approval date.
That is not a technical distinction. A reserve report can work with a broad development concept, operating assumptions, and a staged multi-year path. A lender, an outside funding partner, or the public market needs something else entirely: an annual drilling schedule, permits, a budget, participation ratios, a financing split, and an updated view of execution risk. In other words, the reserve report improves the quality of the question, but it does not yet provide all the documents needed for the answer.
There is also an important capital-discipline lesson from 2025. The partnership chose not to participate in the wells proposed under the 2025 plan, citing geological, engineering, and economic considerations, together with a weaker business environment and lower oil prices at the decision point, and the fact that those wells were not contractually required under the leases for that year. That can be read in two ways, and both are valid. On one hand, it shows discipline. On the other, it proves that Modiin does not intend to finance every plan simply because it appears in a reserve model.
| Issue | What the filings say | Why it matters for funding |
|---|---|---|
| Multi-year plan | About 101 wells over about 10 years | The updated value depends on a long development path, not only on already-producing wells |
| Heavy first stage | 37 wells expected in the first three years | Most of the funding pressure arrives early, before full execution certainty exists |
| Five-year cost | About $221 million attributable to Modiin | This is already a financing question, not just a geological one |
| 2026 still open | The 2026 plan had not yet been presented to the partnership | There is still no approved bridge from reserve model to first check |
| Lease obligations | The expected 2026 plan is also supposed to include wells that satisfy 2026 lease commitments | Part of future drilling is not only discretionary growth, but also a contractual and operating requirement |
There is a price nuance as well. The reserve model uses average oil prices of $49.53 per barrel in 2026, $50.92 in 2027, $52.23 in 2028, $53.48 in 2029, and $54.35 from 2030 onward, before estimated transportation costs of about $8.5 to $6.5 per barrel. The filing itself notes that the oil curve and spot prices at the publication date were higher than the deck used in the report. That means the model is not aggressive on oil price assumptions. But that still does not solve the financing question. Better pricing can improve returns. It does not replace capital.
The 2P Cash Path Is Still Hard
The most interesting number in the NPB report is not only the PV10. It is the annual cash-flow profile of the 2P plan. That is where it becomes obvious that development does not begin from a self-funding engine. It begins from a transition period that still burns cash.
Based on the undiscounted after-tax annual cash-flow schedule embedded in the 2P table, 2026 and 2027 are still negative, roughly negative $23.6 million in 2026 and negative $1.3 million in 2027. Only in 2028, 2029, and 2030 does the modeled after-tax cash flow turn positive, at about $10.8 million, $15.7 million, and $10.6 million respectively. Put differently, the first five years of the 2P program generate only about $12.2 million of cumulative after-tax cash flow, while development spending over those same five years is about $221.2 million.
That is the heart of the issue. Anyone looking only at the $214.9 million 2P PV10 could come away thinking the project now carries something close to built-in funding capacity. Inside the model itself, the early years still absorb very heavy upfront spending.
There are two more details worth emphasizing:
- The report assumes that 98% of project revenue comes from oil and only 2% from gas.
- That matters because Modiin continues to discuss gas-handling solutions, but the economics of NPB remain overwhelmingly oil-driven.
- Even if oil prices stay above the deck used in the model, the project still has to get through the upfront capex, permits, partner approvals, and actual drilling before that value becomes real.
The simplest way to put it is this: the reserve report says NPB could be worth a lot if it is developed. It does not say the partnership already has the capital needed to get there.
The Existing Producing Base Generates Cash, but Not Enough to Self-Fund the Jump
It is important not to fall into the opposite extreme. NPB is not a weak field with no operating base. In 2025 the project contributed 394.3 thousand barrels net to the reporting entity, at an average realized price of $57.3 per barrel, with average third-party royalties of $9.7 per barrel, average production costs of $24.1 per barrel, and average net receipts of $23.5 per barrel. That is a real operating base, and it is why NPB remains the partnership's core asset.
But even that kind of producing base does not resemble a machine that can self-fund a $221 million five-year development jump. The mismatch looks even clearer one layer higher, at the partnership level. In 2025 Modiin reported $25.1 million of revenue, $5.4 million of EBITDA, and $6.8 million of cash flow from operations. Year-end cash and cash equivalents stood at $16.4 million. Against that, the bank loans taken for the 2022 to 2024 NPB development programs still stood at $21.2 million at year end.
| Layer | Relevant number | What it means in practice |
|---|---|---|
| NPB operating base | 394.3 thousand net barrels, average net receipts of $23.5 per barrel | There is a real producing asset here, but not one that self-funds a development leap of this size |
| Partnership cash | $16.4 million of cash and cash equivalents at year end 2025 | There is room to operate, but it is smaller than a single 2026 2P development budget |
| Internal cash generation | $6.8 million of operating cash flow in 2025 | Positive cash generation, but far below the $39.8 million development cost modeled for 2026 alone |
| Existing NPB leverage | $21.2 million of bank loans outstanding at year end 2025 | The project is already financed to a degree, so future debt does not start from a clean slate |
| Capital-markets dependence | 2025 financing activity contributed about $45.7 million net from bond issuance | That proves market access, but it also proves that the option layer is still not being funded by the business alone |
Gas is not the funding answer either. During 2025 the partnership sold about 1,014 thousand gas units for its share, generating about $635 thousand of revenue, but because of unusually high gas-marketing costs, the average result was a loss of about $1.3 per gas unit. That fits the reserve evaluator's own framing that gas is only 2% of project revenue. Gas solutions matter for operations, regulatory compliance, and efficiency. They do not yet answer who funds the drilling plan.
So Who Actually Funds NPB
The answer that emerges from the filings is not zero, but it is not simple either.
Project debt: the partnership has already funded the 2022 to 2024 NPB programs with bank debt. At year end 2025, $21.2 million of such loans remained outstanding. The financing package includes minimum DSCR thresholds, a minimum forecast DSCR of 1.50 for draws, payment-acceleration mechanics if forecast DSCR falls below 1.50, and an LTV ceiling of 65%. This is a real funding route, but not an open-ended one. The more aggressive the development path, the more dependent the financing case becomes on production delivery, oil price, permitting, and lender confidence.
Capital markets at the partnership level: the annual report is explicit that the partnership funds itself mainly through NPB oil revenue, public bond issuance, long-term bank financing, and equity raises. 2025 proved that Modiin can access the market. It also proved the price of that access: more public debt, more FX sensitivity, and a thicker financing-expense layer. So the public market is a route, but it is hard to describe it as a cheap or clean route.
A partner or partial monetization: this is probably the route that looks most natural from the filings themselves. Management writes that it is working to maximize the project's value, whether through annual drilling plans, through sale of the project or parts of it, or by bringing in a partner. If NPB genuinely looks larger, then outside project capital may be the cleanest way to translate part of that uplift into accessible value without forcing Modiin to write every check itself. The downside is obvious, common unitholders would keep a smaller economic slice. The upside is equally obvious, less dependence on aggressive debt or equity issuance at the partnership level.
There is also one constraint that is not purely a funding issue, but it does affect bankability. The annual report describes an ongoing dispute with the operator over unauthorized charges, access to information, and operator-audit findings, and says that a July 2025 mediation process did not resolve the disputes. A large development plan requires more than money. It also requires an operator, partner alignment, and a governance layer that outsiders can underwrite.
Conclusion
NPB really does look larger after the March 2026 reserve update. That point should not be softened. But what the new report solves is mainly the question of geological and economic scale. It does not solve the funding path. That is a different question.
As of late 2025 and early 2026, what exists is a real producing base, a larger 2P and 3P value layer, and a partnership that has already shown it can access both banks and the public market. What does not yet exist is a presented and approved 2026 plan, a signed financing architecture for the multi-year program, and proof that the early development years can be carried without loading too much additional risk onto common unitholders.
So the right read of NPB today is not, the reservoir is larger and the problem is solved. It is, the reservoir is larger, and that makes the financing test even more important. If a 2026 plan arrives with a budget, funding sources, a clear participation ratio, and perhaps a partner structure, the market can start treating 2P as something more reachable. If that does not happen, the PV10 will remain impressive, but still farther from unitholder cash than the headline suggests.
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