Modiin completes Big Foot: USD 116 million paid, while abandonment guarantees define the cash test
The completed Big Foot acquisition gives Modiin a producing oil asset, but the economic read now moves from the 12.5% working-interest headline to net cash after debt service, seller royalties, midstream credit support and plugging and abandonment guarantees.
The Big Foot transaction is no longer a conditional financing story for Modiin Yahash. On July 7, the rights in the US company holding a 12.5% working interest in the producing oil field were transferred, with economic effect from July 1, 2025. The partnership now owns exposure to an active, oil-weighted asset, backed by offtake agreements for the company's full share of crude oil and natural gas production. The closing also fixes the cash bridge: about USD 116 million was paid to the seller, plus about USD 5 million for Windstorm insurance and an operator-account balance, while the final seller settlement will be completed within 180 days. At the same time, the funding and obligation stack became binding: about USD 91 million of bank debt, seller royalties, a plugging and abandonment surety that starts at USD 35.143 million and may rise to USD 56.1 million, and a partnership-level contractual guarantee of up to USD 28.5 million. The test has therefore moved from whether the deal closes to whether the field generates net cash for unit holders after debt service, expenses and guarantees.
Completion Turns The Deal Into Operating Ownership
The rights in Walker Ridge Block 29, where Big Foot is located, were registered to the US holding company, which also joined the field's joint operating agreement. That step became possible after the existing field partners, Chevron and Equinor, said in early June that they would not exercise their preferential purchase rights.
This is a producing asset, not exploration optionality. In May, net production for the acquired rights was disclosed at about 4,500 to 5,000 barrels of oil equivalent per day, about 96% of it oil. In 2025, production for those rights totaled about 1.5 million BOE and revenue was about USD 100 million. In the first quarter of 2026, production was about 465 thousand BOE and revenue was about USD 32 million. Those numbers are large relative to the partnership's starting point, but they are not the same as cash available to unit holders. The cash first passes through the holding chain, Eventide's 10% stake, debt service, seller royalties and field obligations.
The Cash Price Fell, But The Bill Is Not Finished
The base purchase price was USD 190 million. At closing, the company paid the seller about USD 116 million, after deducting about USD 74 million of revenue net of expenses accumulated between July 1, 2025 and July 1, 2026. The effective date materially reduced the cash needed at closing. The final settlement within 180 days will still decide the exact all-in acquisition cost.
| Item | Closing Detail | Why It Matters |
|---|---|---|
| Seller payment | About USD 116 million, including the USD 10 million deposit | The cash entry price fell materially from the USD 190 million base price |
| Effective-date adjustment | About USD 74 million of revenue net of expenses was deducted | The economics of the July 2025 to July 2026 period already affected the closing price |
| Additional payment | About USD 5 million for Windstorm insurance and operator-account balance | Part of the entry cost sits outside the headline purchase price |
| Final settlement | Within 180 days from closing | The final price will depend on final revenue and expense data |
| Seller royalties | 1% on existing wells and 3% on new or redirected wells | Revenue is reduced before it reaches the partnership |
| Plugging and abandonment surety | USD 35.143 million, with potential increase to USD 56.1 million by the fifth anniversary | The field's end-of-life obligation is already part of the risk structure |
The structure combines purchased production with long-term obligations. Seller royalties reduce top-line economics, and capital, guarantee and collateral requirements keep liquidity tied to the field even when production is stable.
Debt And Guarantees Limit Distributions
The financing agreement signed at the end of June provides about USD 91 million for roughly five years, with final maturity on September 30, 2031. The loan bears Term SOFR plus a fixed annual margin of 3.98%, with a one-time upfront fee of 1.05% of the loan amount. Principal amortization begins on December 31, 2026 and steps up by annual buckets of 7%, 7%, 14%, 25% and 47%. That schedule pushes the heaviest principal burden toward the end of the term, while the covenants apply immediately.
The loan requires historical and projected DSCR of at least 1.15, and LTV of no more than 65% based on discounted 1P proved reserves. It also requires a debt-service reserve equal to the lower of USD 10 million or the next six months of principal and interest payments. A cash-sweep mechanism directs part of excess cash to accelerated repayment depending on coverage ratios. These provisions mean that cash available to the partnership is calculated only after debt service and reserves are secured.
There is an important legal distinction between the holding company and the partnership. The bank financing has full recourse to the holding company, with no recourse to the partnership itself. But at closing the partnership provided the seller with a contractual guarantee of up to USD 28.5 million to secure the holding company's purchase-agreement obligations. The bank debt is tied to the asset level, while the seller guarantee leaves one direct obligation at partnership level.
Reserves Support The Debt, Oil Prices Drive The Test
The Big Foot reserve report shows a meaningful asset base for the acquired 12.5% interest: 1P reserves of 5.629 million BOE net after third-party royalties, 2P reserves of 6.978 million BOE and 3P reserves of 8.889 million BOE. On an after-tax PV10 basis, the values are about USD 199.3 million for 1P, USD 229.7 million for 2P and USD 278.5 million for 3P. Those numbers help explain the bankability of the asset. They do not by themselves represent cash available to unit holders.
First, Eventide Big Foot Investment LP completed its 10% investment in the holding company, so the partnership's effective share in the asset and financing chain is 90%. Second, the revenue profile is almost entirely oil: 99.6% of 1P revenue and 99.7% of 2P and 3P revenue come from crude oil sales. The reserve assumptions use oil prices of USD 84.82 per barrel for the rest of 2026, then decline to USD 69.68 in 2027, USD 67.25 in 2028, USD 65.47 in 2029 and USD 63.75 in 2030. Any move in oil price, production rate or operating cost will flow directly into debt-service capacity and cash moving up the structure.
Third, plugging and abandonment costs are not a remote footnote. The reserve cash-flow tables include USD 33.65 million of abandonment costs, and the closing package already required a dedicated surety for that purpose. Acquiring a mature offshore field also means taking on environmental and operating obligations that affect cash from day one.
The Next Proof Is Reported Cash
Closing is a real execution milestone. The partnership moved from a conditional agreement to actual ownership, secured bank financing, brought in Eventide, signed production sale agreements and completed the transfer of rights.
From here, the focus moves to reported financial results. The next filings need to show actual Big Foot production contribution, operating expenses, financing cost, debt-service reserve build-up and the final seller settlement. Any update to the surety, the standby letter of credit for Enbridge Offshore Facilities or the abandonment-cost estimate will matter because each one affects free cash. A strong oil-price environment and stable production can make this structure look like a reasonable price for entering a producing asset at this scale.
The partnership now has to show meaningful net cash from Big Foot after every layer of the transaction: debt service, Eventide's share, seller royalties, guarantees, insurance, final settlement and abandonment costs. Stable cash generation without covenant pressure would confirm that Big Foot has changed the partnership's scale. If obligations absorb too much of the cash, the field may remain a large producing asset while much of the economics accrues to lenders, the seller and the asset's own capital requirements.
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