Federal Lease Sales Are Now on a Schedule. Your Service Contracts Should Be Too.

What a fixed leasing calendar through 2040 means for service companies signing multi-year work.

A federal lease sale in May across portions of the Permian Basin in Texas and New Mexico brought in more than $4 billion in receipts on 33,530 acres. The Texas Railroad Commission, citing Interior’s preliminary results, called that roughly four times the previous onshore federal record of $972 million, which dates to 2018. Then in August, the third Gulf of America sale drew $82.7 million in high bids. Those are very different numbers, and neither one tells a service company when its crews will be busy.

I’d argue that gap, between the day a lease sells and the day a rig shows up, is where most of the contract risk sits. Federal leasing now runs on a calendar the statute sets. That makes the pipeline easier to see and the timing of actual work easier to get wrong.

The Statute Sets the Calendar Through 2040

The 2025 budget law, the One Big Beautiful Bill Act, requires 30 Gulf of America lease sales. According to Interior’s offshore leasing program, that means one by December 15, 2025, two a year (by March 15 and August 15) from 2026 through 2039, and a last one by March 15, 2040. Each has to offer at least 80 million acres. The lease terms follow Interior’s March 2020 sale, with exceptions for royalty and primary term. Counting from 2026, that’s 14 years of twice-a-year sales, plus one in 2040. The law sets the royalty at 12.5 percent, which Interior called the lowest deepwater rate since 2007. It also raises the cap on Gulf revenue sharing from $500 million to $650 million for fiscal years 2025 through 2034.

Three sales have happened so far. December 2025 drew 30 companies, with high bids on 181 blocks. On March 11, 2026, 13 companies bid, and the high bids totaled $47.0 million on 25 blocks. On August 12, 16 companies submitted 69 bids totaling $99.5 million, and the high bids came to $82.7 million on 59 blocks. That’s a 76 percent jump in high bids from the March sale, on more than twice as many blocks.

The next Gulf sale is due by March 15, 2027, and Interior has to publish a final notice at least 30 days before it. Anyone planning capacity around that sale should read the notice the day it posts, because the notice sets the block count and the terms. Interior’s release for the first sale put the Gulf’s undiscovered, technically recoverable resources at 29.59 billion barrels of oil and 54.84 trillion cubic feet of natural gas, and it offered about 15,000 unleased blocks. The acreage on offer is large, and the bidding has swung widely from one sale to the next.

Onshore Has Its Own Rhythm

The Bureau of Land Management runs oil and gas lease sales in a number of states every quarter. Third-quarter sales brought in $372.1 million on 344 parcels and 293,963 acres, across Montana and the Dakotas, New Mexico, Wyoming, Colorado, Nevada, Utah, and the eastern states. The first quarter was $592.7 million. The second, with the May sale in it, was $4.1 billion. BLM puts the year-to-date total at $5.1 billion.

Revenue fell more than 90 percent from the second quarter to the third. Nobody should read that as a collapse in appetite for federal acreage, because one big sale can swamp a year. For scale, a Colorado sale BLM reported in June brought in $35.3 million on 147 parcels and 134,173 acres. BLM also says the 2025 law reset the royalty rate for new onshore production to a minimum of 12.5 percent, reversing the 16.67 percent rate that applied before. That belongs in any conversation about what bidders were pricing.

What the Sale Numbers Don’t Tell You

A lease sale buys the right to drill. The work comes later, after seismic, permits, financing, and a development decision. Deepwater leases from these Gulf sales carry a 10-year primary term, so a lessee has a decade to decide when and whether to move.

Interior’s fiscal 2024 offshore revenue shows how little bonus bids say on their own: $6.5 billion in royalties, $372.5 million in bonuses, and $122.8 million in rental payments. Royalties come from production, and production comes from work. My read is that sale results measure appetite, not activity.

Production moves on its own schedule. EIA says federal Gulf crude oil production rose 0.2 million barrels per day, or 10 percent, in the first half of 2026 compared with the first half of 2025, and in September it forecast a 3 percent increase for the full year. Four large projects have come online since January 2025: Whale at about 38,000 barrels per day, Ballymore at about 58,000, Shenandoah at about 70,000, and Salamanca at about 25,000. EIA expects four smaller ones by the end of 2026. Those starts came from projects already in the pipeline. A sale today shows up in activity years from now, not next quarter.

Treat $4 billion in Permian bids as a near-term order book and you’ll hire and buy equipment too early. Ignore the sale calendar and you’ll miss years of future demand. The contract is where you manage the space between.

Three things are worth watching before you commit capacity: the final notice for the March 2027 Gulf sale, which will set the block count and terms; the next BLM quarterly results, to see whether the second quarter was a one-time spike; and whether bidder counts in the Gulf keep climbing, as they did from 13 companies in March to 16 in August. None of that tells you when a given customer starts work. It does show how much new acreage is entering the system.

Five Contract Terms for Work That Starts Years Out

None of this is exotic. It’s ordinary drafting applied to a longer timeline than most contracts assume.

Price comes first. If you sign a multi-year agreement against a lease that may not see a rig for years, you need a way to adjust rates. Does the rate stay fixed for the whole term? Do escalators track labor, fuel, or materials? Can either side reopen pricing at a defined milestone, like a final investment decision or a spud date?

Then capacity. If you’re holding crews, equipment, or vessel time for a customer’s future program, who pays when the program slips or the customer gives up the lease? Reservation fees, minimum commitments, and release dates deserve the same attention as day rates.

Assignment is the one people forget. Leases change hands after sales, so the customer who signs with you today may not be the operator when the work shows up. Check the consent rights, whether the agreement binds a successor, and whether you can ask for new credit support when ownership changes.

Payment security matters more with a counterparty that’s new to the basin or the acreage. Between 13 and 30 companies bid in each of the three Gulf sales so far, and they don’t all have the same balance sheet. Parent guarantees, letters of credit, and prepayment for early work are ordinary asks at that stage. They’re a lot easier to get before the first invoice than after.

Last, permits. Work on federal acreage depends on approvals your customer doesn’t control. Say up front who bears the cost of delay, how much notice you get when a permit slips, and when either side can walk away. A vague excusable-delay clause tends to fall apart the first time both sides read it closely.

The statute fixes the sale dates through 2040. It doesn’t fix the date anyone drills. The contract has to cover the space in between.