Structuring non-op participations for year-end 2026 and the 2027 program: oil and gas, geothermal, and brine.

On October 29, West Texas Intermediate closed above $100. A week later, after Democrats took both houses of Congress and every statewide office in Texas, it was trading near $91 — the sharpest post-election move in the oil market in memory, and a reminder that the war premium that has carried prices since February can leave faster than it arrived. The operators who drill the Permian, the Anadarko, and East Texas are still sending AFEs, because a $90 strip still pays out a well, and the tax provisions that make drilling capital efficient did not change on November 3 and cannot change before 2029. For private capital, that leaves the oldest opportunity in the business — a non-operated working interest in someone else's well — on an unusually compressed calendar and with an unusually clear need to underwrite price rather than assume it. And in Texas the "well" is no longer only an oil well: the same non-operated seat is now being sold in geothermal projects and Smackover brine units, on documents adapted from the oil patch and a tax and regulatory footing that is different in ways that matter. Money that wants a 2026 deduction has to be committed by December 31 and the wells have to be spud by March 31. Money that wants the 2027 program has to have its vehicle, its documents, and its diligence process built before the first package is offered in January. This article is about how to structure that vehicle, what the election did and did not change, and what the fund agreement, the purchase agreement, and the joint operating agreement each have to do before the first AFE arrives.

Why non-op, and why now

A non-operated working-interest owner pays its share of the costs and takes its share of the revenue but runs nothing: the operator picks the rig, the vendors, the completion design, and the timing, and bills the non-op through joint-interest billings under the JOA. That is the attraction for capital that wants exposure to the drill bit without a field office, and it is the risk, because the non-op's rights live almost entirely in three documents it did not draft.

The market for those interests is deep. Permian Resources reported roughly 190 bolt-on and ground-game transactions and about $1.05 billion deployed in the first half of 2026 alone; Northern Oil & Gas, the largest public non-op, closed a record 41 ground-game transactions in the first quarter against an evaluation pipeline it put at more than $10 billion. Pontem Energy Capital closed a $250 million non-op fund in January and EIV Capital raised $1.1 billion across new upstream and infrastructure vehicles in April. The private side of that market — the working-interest packages too small for a public company, the non-consent elections an operator would rather farm out, the estates and family offices selling into a hundred-dollar tape — is where a well-structured private vehicle competes.

Two things changed the arithmetic this year. The first is price: a Brent strip that averaged about $101 in September pays out a Permian well on a schedule that a $65 strip does not, and it pulled forward drilling that operators had deferred — AFEs that are now in non-ops' hands with thirty-day election clocks running, whatever the strip does next. The second is the tax law. The reconciliation act signed July 4, 2025 made 100 percent bonus depreciation permanent for property acquired after January 19, 2025, moved the business-interest limitation back to an EBITDA base, and left untouched the two provisions that have always made drilling capital tax-efficient: the election to deduct intangible drilling costs in the year incurred, and percentage depletion for independent producers. For a working-interest investor who holds the interest in a form that does not limit liability, Section 469(c)(3) still treats the activity as non-passive, so the IDC deduction reaches active income. None of that is new. What is new is that the depreciation side of the equation no longer phases down, and that there is a price environment in which operators want the capital.

The same seat at three tables: oil and gas, geothermal, and brine

The non-operated structure travels. A geothermal developer drilling injection and production wells in South Texas, and a brine developer assembling a Smackover unit in Hopkins or Franklin County, both need outside capital for the drilling phase and both are offering what amounts to a working interest: a share of costs and a share of revenue, with the developer as operator. The documents are being adapted from the AAPL form because there is no industry model for either, and the adaptation is where the risk sits.

Geothermal. A Texas geothermal participation looks like an oil and gas farm-in with a power purchase agreement bolted on. The resource is owned by the surface owner under Natural Resources Code Chapter 141 unless an instrument says otherwise, so the lease comes from a different estate than the mineral lease a non-op is used to reviewing, and the title opinion has to start there. The wells are permitted by the Railroad Commission under Statewide Rule 46 for injection, and a non-op should treat the issued permit, not the application, as a closing condition. Revenue is a power or heat contract — Sage Geosystems' first Texas project sells stored power to a rural electric cooperative, and its 150-megawatt agreement with Meta shows where the demand is — rather than a monthly production check, so the waterfall, the reserve, and the lender's collateral package follow a project-finance template more than a JIB. The tax footing is the most important difference. Intangible drilling costs are deductible for geothermal wells exactly as for oil and gas wells under Section 263(c), with the same working-interest exception and the same 90-day prepaid rule, so the December 31 and March 31 calendar applies. But geothermal also keeps the technology-neutral investment and production credits under Sections 48E and 45Y that the 2025 act stripped from wind and solar: full credit for projects that begin construction through 2033, phasing down only in 2034 to 2036, with the credit transferable for cash under Section 6418 and the foreign-entity rules to be satisfied. A geothermal participation can therefore be structured so that one class of investor takes the IDC deduction and another, or a credit buyer, takes the ITC — which is a very different fund agreement from an oil and gas program, and one that has to be designed before the first dollar is called.

Brine. A participation in a Smackover brine project is a working interest in a brine lease or a contractual unit, and three things distinguish it. First, title: as we wrote last month, Texas has not said which estate owns lithium in brine, so a non-op's interest is only as good as a title opinion that traces both estates and a leasing program that covers both; a drillsite opinion will not do. Second, the unit: there is no brine pooling statute, so the unit exists only by contract and every tract's consent is in the chain — a non-op is buying into a bundle of private agreements, not a Commission order, and the participation agreement must say what happens if a tract drops out. Third, tax: brine production wells are not oil, gas, or geothermal wells, so the IDC election does not reach them; cost recovery runs through 100 percent bonus depreciation on the equipment and plant, which turns on the placed-in-service date rather than the spud date, and through percentage depletion, which applies to lithium at its own statutory rate. The producer-level credit that matters is Section 45X, the advanced-manufacturing credit for critical minerals, which the 2025 act kept in full through 2030 and phases down from 2031 to 2033 — a credit earned by whoever produces the lithium carbonate, which a non-op participation agreement has to allocate expressly. Revenue is an offtake contract, often years from first delivery; the Franklin Project's own assessment puts first production in the early 2030s, which means a brine participation is a development-stage investment with a 2027 drilling program and a 2031 cash flow, and the fund agreement's term, its extension mechanics, and its capital-reserve policy must be written for that horizon rather than borrowed from a twelve-month drilling partnership.

Across all three, the same principle holds: the non-op's rights live in documents it did not draft, and the operator controls the pace, the vendors, and the data. The due-diligence sequence below — operating agreement and billing history first, title second, permits third — is the same whether the hole produces oil, hot brine for a turbine, or brine for a lithium plant.

What the election changed, and what it did not

November 3 produced the largest single-cycle shift in Texas politics in a generation and a divided federal government, and the two have different consequences for a non-op program. The market's first reaction was blunt: on November 4 Brent fell 8.7 percent to $94.62, its lowest level in two months, ExxonMobil dropped 4.6 percent and ConocoPhillips 5.2 percent, the ten-year Treasury yield eased to 4.88 percent, and the Dow had its best post-midterm session in more than forty years. Traders read a Democratic Congress as pressure on the administration to wind down the Iran war, and priced out part of the premium. By November 6, WTI was just under $91. That is the single most important fact for a year-end vehicle: the strip that justified the fourth-quarter AFE and the strip the first production will sell into are no longer the same number.

Washington: divided, which means stable. Democrats will hold at least 54 Senate seats and a House majority when the 120th Congress convenes in January; the presidency does not change until 2029. For the tax provisions that drive non-op economics — permanent 100 percent bonus depreciation, the IDC election, percentage depletion, the EBITDA-based interest limitation — that is the most protective configuration available. None of them can be repealed over a veto, and none of them can be extended or sweetened either; the reconciliation route that produced the 2025 act is closed to both parties for two years. Sponsors should expect oversight and appropriations fights rather than tax law, and should expect the real federal variable to be foreign policy: a Congress that campaigned against the war will use funding and war-powers votes to push toward a settlement, and every step in that direction takes dollars off the front of the curve. The federal lease-sale mandates and royalty-rate rollback in the 2025 act are law and stay law; what a Democratic House can do is slow the Interior Department's execution of them through the budget. For a Texas non-op buying fee-mineral acreage, that is a second-order effect.

Austin: the regulator changed, the rules have not. Jon Rosenthal, a four-term state representative and a mechanical engineer with twenty-five years in the industry, won the Railroad Commission seat by about seven points and will be the first Democrat on the Commission in more than thirty years when he is sworn in in January. The Commission remains two-to-one Republican, and as TIPRO's Ed Longanecker observed, action requires a majority, so rulemakings and contested cases will still turn on Commissioners Christian and Craddick. What changes is the agenda: Rosenthal has said he will propose tighter flaring limits, emergency-preparedness audits with fines, published inspection results, groundwater monitoring, wastewater-disposal fees, and more money for staff and orphan-well plugging. The Permian Basin Petroleum Association's Ben Shepperd said he was "not overly concerned," and TXOGA pledged to be "a constructive partner." For a non-op, the practical translation is that the operator's compliance history — flaring, P-5 status, inactive-well counts, disposal permits — is now a diligence item with a sharper edge, because the agency's enforcement posture is likelier to tighten than loosen over the life of the investment, and the non-op pays its share of every fine the JOA passes through.

The Legislature: a House that flipped, a Senate that did not. Democrats won the Texas House for the first time in more than two decades, roughly 80 seats to 64 with a handful still being counted, while Republicans kept the Senate 19 to 12. Governor-elect Hinojosa holds the veto; Lieutenant Governor-elect Goodwin presides over a chamber her party does not control; Democrats also won the Attorney General, Comptroller, and Land Commissioner offices and all four Supreme Court seats on the ballot. The 2027 session that convenes January 12 is therefore a negotiated session, and for energy that cuts both ways. Severance-tax increases, a statewide flaring ban, or new produced-water liability cannot pass the Senate; repeal of the 2025 business-court and corporate-governance reforms cannot pass it either. The Business Court, Senate Bill 29, and the $5 million threshold stay. What can move is what both chambers want: orphan-well funding, pipeline and grid safety, water, and — if the data-center debate consumes the oxygen it consumed in the interim — very little else, which means the brine-minerals ownership question and a brine pooling statute are now less likely to be settled in 2027 than they were a month ago. A non-op vehicle whose acreage sits in East Texas should underwrite another two years of ownership uncertainty on the lithium side, and draft its leases accordingly.

Geothermal and critical minerals: the election helped more than it hurt. Both resources sit on rare bipartisan ground, and the new configuration strengthens rather than threatens them. In Washington, a Democratic Congress is far likelier to defend or extend the geothermal credits than to touch them, and the critical-minerals agenda — the 45X credit, Defense Production Act and Energy Department funding, the push to produce lithium at home — has been carried by both parties since 2022; the Texarkana lithium-depot bill will need a new Senate sponsor with Senator Cornyn departing, but its logic is defense policy, not party policy. Permitting reform for geothermal on federal land is one of the few energy bills that could pass a divided Congress. In Austin, the geothermal ownership statute passed in 2023 with votes from both parties and is not at risk in a split Legislature; the Railroad Commission's Rule 46 and Rule 82 programs are agency rules, not statutes, and remain in a two-to-one Republican commission's hands. Two things to watch. Commissioner-elect Rosenthal's platform of groundwater monitoring and wastewater-disposal fees, if it reaches the agenda, would touch the Class V injection wells that both a geothermal project and a brine project depend on — a cost item, not an existential one, but one a participation agreement should allocate. And his stated position that data centers should face a review of state water and power resources before approval cuts in geothermal's favor, since firm, dispatchable power sited next to the load is exactly what that review would reward. The new Land Commissioner matters too: the General Land Office leases the state's own acreage for geothermal and other minerals as well as oil and gas, and a change of administration there is a change in the counterparty for every project on Permanent School Fund land. On the brine side, the honest reading of the split Legislature is that the ownership question is less likely to be settled by statute in 2027 and more likely to be settled, eventually, by the courts — and the Supreme Court of Texas that will hear the first case after Cactus Water will seat four newly elected Democratic justices in January. None of that changes what a brine non-op should do, which is lease from both estates and build the record; it does change how long it should expect to carry the uncertainty.

What that means for the vehicle. Underwrite the 2027 program on a strip materially below the September average — the forward curve and the pre-war range, not the spike — and show investors the case at both, because the PPM's sensitivity table is now the most-read page in it. Treat hedging authority as a decision the fund agreement must make, not a question it may defer; at $91 with a settlement in the headlines, a sponsor who cannot hedge the first eighteen months cannot protect the preferred return. Expect some operators to slow the pace of new AFEs into the first quarter if the strip keeps falling, and build the single-program partnership's spud covenant so that a delayed well is a remedy and not a lost deduction. Add the operator's regulatory record to the diligence checklist alongside its JIB history. For a geothermal participation, decide now who takes the IDC and who takes the credit, and paper the credit transfer before year-end rather than after. For a brine participation, write the term and the reserve for a 2031 cash flow and treat the issued Rule 82 permit and the unit's consent schedule as closing conditions. And on the tax side, do nothing differently: the December 31 and March 31 dates, the working-interest exception, bonus depreciation, and the geothermal and critical-minerals credits are exactly where they were in October, and are now insulated from Washington for the life of a 2026 or 2027 program.

The calendar

Three dates drive a year-end non-op program, and the vehicle has to be designed around them rather than discovered against them.

December 31, 2026. An investor who wants the 2026 deduction must be admitted, and must have paid or be unconditionally obligated to pay the drilling costs, before year-end. That means the subscription documents, the accredited-investor verification, the capital-call mechanics, and the operator's turnkey or AFE commitment all have to be executed in the fourth quarter — in practice, a vehicle formed in October or November, not December.

March 31, 2027. Prepaid intangible drilling costs are deductible in the year paid only if drilling begins within 90 days after the close of that year, under Section 461(i)(2). The operator's commitment to spud by the end of March is therefore not a scheduling courtesy; it is a term of the deal, and it belongs in the participation or turnkey agreement with a remedy if it slips. The rule applies to geothermal wells as it does to oil and gas wells; it does not apply to brine production wells, where the year-end question is instead whether the plant and equipment are placed in service in time for bonus depreciation.

January 2027. Sponsors who intend to run a 2027 program — a blind-pool fund or an evergreen acquisition vehicle that buys packages through the year — should have the vehicle formed, the Form D ready, the fund documents final, and the diligence checklist and title process standing before the first package is offered, because the packages that come to market in January are priced off a December strip and move quickly.

Three vehicles

Most of the private non-op capital we see is organized one of three ways, and the choice should follow the capital, not the sponsor's habit.

The single-program partnership. A GP/LP or LLC formed for a defined set of wells under one or two operators, typically closed in the fourth quarter for a drilling program that spuds in the first. This is the year-end vehicle. Its documents are short because the assets are known; its complexity is in the tax structure (investor general-partner interests during the drilling phase, converting to limited interests afterward, so that the IDC deduction is non-passive and the liability exposure is bounded) and in the operator's commitment to timing. It is the right vehicle for a sponsor with a specific AFE in hand and investors with a specific deduction in mind.

The blind-pool non-op fund. A committed-capital fund that buys non-op positions across multiple operators and basins over an investment period, with a preferred return, a carried interest, and a clawback. This is the vehicle for a sponsor with sourcing capability and a track record, and it is where the fund agreement does the most work: concentration limits by operator, basin, and well; capital-call mechanics that match AFE timing rather than a real-estate closing calendar; a waterfall built for monthly commodity revenue, hedging gains and losses, and periodic asset sales rather than rent; and a reserve policy for the non-consent decisions the fund will face in year three when its own capital is called out.

The acquisition vehicle. A single-purpose company formed to buy one package — a working-interest divestiture, an estate, an operator's non-consent farmout — often with a bank or a mezzanine lender alongside the equity. Its documents are the PSA and the credit agreement, and its diligence is the title. It is the vehicle for the opportunistic buyer, and it is the one most often formed too late to do the title work properly.

Whichever vehicle, the securities analysis is the same. The offering is Regulation D — 506(b) where the sponsor already knows its investors, 506(c) where it is building a list and will solicit generally. The 506(c) verification burden fell substantially in March 2025, when the SEC staff said a sponsor may rely on a minimum investment of $200,000 for an individual or $1 million for an entity, together with the investor's written representation that it is accredited and that the investment is not financed for the purpose, absent contrary knowledge; for a non-op vehicle whose minimum is already in that range, that guidance removed most of the friction that kept sponsors in 506(b). The fund itself usually sits outside the Investment Company Act under Section 3(c)(9), the exemption for companies substantially all of whose business is owning oil and gas leases and royalties, which is one more reason to keep the vehicle's assets to working interests and not let it drift into midstream, power sales, or minerals-and-royalties without re-running the analysis; a geothermal participation with a power purchase agreement and a brine participation with an offtake contract each need that analysis done on their own facts. Form D is due fifteen days after the first sale, and the Texas notice filing with it.

The fund agreement

Beyond the mechanics above, four provisions separate a non-op fund agreement that works from one that was adapted from a real-estate form.

First, capital calls that fit AFEs. An operator's AFE under the AAPL form gives the non-op thirty days to elect and then bills on the operator's schedule; the fund agreement needs call notices, default remedies, and a working-capital reserve that fit that cadence, and it needs to say what happens when an investor defaults in the middle of a completion.

Second, the non-consent policy. Every non-op fund will eventually face an operation it does not want to fund. The agreement should say who decides, under what standard, and whether the fund may farm out or sell down rather than go non-consent and absorb the penalty.

Third, hedging authority. After a ten-dollar week, investors will ask whether the fund will protect the first eighteen months of production, and the agreement should either authorize a defined hedging program or prohibit one; silence produces an argument in the first downturn, and the first downturn may already have started.

Fourth, disclosure that describes the actual risk. The private placement memorandum should address title, operator performance and credit, non-consent exposure, commodity price (including the war premium that analysts estimated at up to $30 a barrel in October and that the market began removing within hours of the election), the timing conditions on the tax treatment, and — where the vehicle touches East Texas or any play with unsettled ownership law — the regulatory and ownership uncertainties of that play. Risk factors copied from a technology offering do not survive investor counsel, and they do not survive a plaintiff's lawyer in a $60 market either — a market that, after this week, no PPM should treat as hypothetical.

The PSA

A non-op PSA should be drafted from the buyer's side on three points. Title first: the defect mechanism, the individual and aggregate thresholds, and the special warranty must be calibrated to the fact that the buyer will rely on the operator's title work and its own acquisition opinion and will not be able to cure defects itself after closing; a non-op has no landman in the field. JOA-specific representations second: that the seller is not in default, that no non-consent elections or unpaid AFEs are outstanding, that preferential rights and consents to assign have been identified and the notice periods will run before closing, and that the joint-interest-billing account is current. Transition third: the assignment must be recognized by the operator, the JIB account transferred, and the buyer substituted into the JOA's notice provisions on the closing date, or the buyer will spend its first quarter chasing the operator's land department while AFEs go unanswered. Texas law gives the buyer one more deadline to track: under Property Code §91.402, proceeds are due within 120 days after the end of the month of first sale, and the operator's division-order process starts from the recorded assignment, not the signed PSA.

The JOA

A non-op does not usually get to rewrite the JOA, but it must read it before it buys, and the 2015 AAPL Form 610 leaves the provisions that matter most to be filled in. The non-consent penalty — commonly 300 percent of drilling costs and 500 percent of completion costs in current forms, but negotiable — and the election period decide what a non-consent decision actually costs. The COPAS accounting procedure's audit window, the right to well data and daily drilling reports, and the operator's obligation to share AFEs and completion designs decide whether the non-op can supervise its investment at all. Preferential rights and the maintenance-of-uniform-interest clause decide whether the buyer can close and whether it can exit. The operator's standard of care and the removal mechanism are the non-op's only leverage when operations go wrong. And for interests large enough to matter, the forum: a JOA dispute between sophisticated parties over $5 million now belongs in the Texas Business Court, and a non-op that has amended its JOA to say so has a very different negotiating position from one that has not.

Diligence that reads the JOA first

Our non-op diligence starts with the JOA and the joint-interest-billing history, not with the title, because clean title to a poorly governed interest is still a poor investment. The title work follows — mineral-estate title for an oil and gas package, surface-estate and Chapter 141 title for a geothermal lease, both estates for brine — scaled by the firm's document pipeline so that a package of dozens of wells or tracts can be examined on a fixed fee and a defined timeline. For a year-end program the sequence is fixed by the calendar above: vehicle and offering documents in the first two weeks, operator participation agreement with the spud covenant in the third, subscriptions and verification through the fourth, closing before the holidays, title and curative running in parallel so the January JIBs land in a vehicle that owns what it paid for.

For sponsors forming a vehicle, we deliver the fund documents, the acquisition forms, and the ongoing compliance calendar as one fixed-fee set through the energy capital formation practice; for buyers of a single package, the PSA, title, and closing are handled together through the transactions practice. Every closing — the cap table, the subscription record, the AFE elections, the division orders — lands in the same maintained record, so that the 2027 program, the second close, or the eventual sale starts from a file rather than a reconstruction.

Scott Beckmen is the Managing Partner of Windward Counsel, PC, a business law firm in Flower Mound, Texas. This article is general information about Texas and federal law and market conditions as of its date, not legal, tax, or investment advice about any offering, vehicle, or investment; tax outcomes depend on each investor's facts, and nothing here is a prediction of commodity prices or returns. Nothing here is an offer to sell or a solicitation of an offer to buy any security. Attorney advertising. Not certified by the Texas Board of Legal Specialization.

Questions this article answers

What is the deadline to deduct prepaid intangible drilling costs for 2026?

Prepaid IDCs are deductible in the year paid only if drilling begins within 90 days after the close of that tax year (Section 461(i)(2)) — for a calendar-year 2026 investor, by March 31, 2027. The investor must also be admitted and have paid, or be unconditionally obligated to pay, before December 31, 2026.

Did the November 2026 election change bonus depreciation or the IDC deduction?

No. Permanent 100 percent bonus depreciation, the IDC election, percentage depletion, and the EBITDA-based interest limitation were enacted in July 2025 and cannot be repealed over a presidential veto; with Congress and the White House in different hands through January 2029, they are also unlikely to be changed.

Does the IDC deduction apply to geothermal and lithium brine wells?

It applies to geothermal wells exactly as to oil and gas wells under Section 263(c), including the 90-day prepaid rule. It does not apply to brine production wells; a brine participation recovers cost through bonus depreciation on plant and equipment (which turns on the placed-in-service date) and percentage depletion.

Can a non-op fund raise capital under Rule 506(c) without collecting investors' tax returns?

Since March 2025, SEC staff guidance allows an issuer to treat verification as satisfied where the minimum investment is at least $200,000 for an individual or $1 million for an entity and the investor represents in writing that it is accredited and that the investment is not financed for the purpose, absent contrary knowledge.

What did the election change at the Texas Railroad Commission?

Jon Rosenthal, an engineer and four-term state representative, becomes the first Democrat on the three-member Commission in more than thirty years in January 2027. The Commission remains two-to-one Republican, so rulemakings and contested cases still require a Republican vote, but the enforcement and transparency agenda is likely to shift — which makes an operator's compliance history a diligence item for any non-op.

What should a non-op read before buying a working interest?

The joint operating agreement and the joint-interest-billing history first — non-consent penalties, election periods, audit rights, preferential rights, operator removal — then title, then permits. Clean title to a poorly governed interest is still a poor investment.

This article is general information about developments in Texas and federal law as of its publication date, not legal advice about any specific tract, lease, project, or offering. Laws and rules change; talk to counsel about your situation before acting. Attorney advertising.