A 13-week cash flow template for oil & gas services.

01 Day-rate compression as a cash event, not a market commentary

Day rates do not compress smoothly in services. They reset on contract renewal, and renewal events cluster — every operator in a basin renegotiates within the same 60–90 day window because budgets are set on the same calendar, and because once two or three anchor operators clear 15–20% rate cuts in a quarter's bids that becomes the basin benchmark. The cash impact is binary at the contract line: the rate on a given fleet does not move, and then on a single day it steps down 10–20%. The 13-week document needs to see those step events individually.

The structural pattern is well documented. About 50–60% of US land frac and pressure-pumping work runs on 90-day or 6-month commitments, 20–30% is spot that reprices inside 30–60 days, and 10–30% is on annual frame MSAs with quarterly reset windows. Wireline carries shorter tenors — per-stage or per-job-day pricing with 90-day re-openers. Drilling-services contracts are the longest at 6–24 months, which is why drillers feel the cycle later but also recover later. Portfolio mix determines how quickly average realised rate tracks spot: a group with 30% spot exposure feels a WTI move six months earlier than one with 70% on annual frames.

Translate this into the cash document by carrying a contract-renewal schedule as a dedicated tab and pulling its outputs into weekly revenue: every active contract, the counterparty, current day rate, renewal date, expected post-renewal rate under three commodity scenarios (base, $10 down, $10 up), and the utilisation assumption behind each. Most services CFOs run a renewal log inside the commercial operations stack — Salesforce or a contract-management system that operations owns. The 13-week needs its own copy reconciled to finance, because the gap between when operations updates the log and when finance hears about a rate concession is where the cash surprises live. The renewal log is not a reference; it is an input.

The Q2 2026 read makes the point concretely. Most services groups went into 2026 with order books shaped by Q4 2025 renewals when WTI was printing $60 and trending down to $58. Realised average day rates are 10–15% below the same period in 2024, and that compression is locked in until the next renewal cycle reprices it. WTI is now at $100 and spot pricing is tightening, but the contract portfolio does not see that until renewals cluster in Q3 2026 and Q1 2027. A 13-week that treats day rate as a market variable will be wrong about cash; one that treats it as a contract-by-contract calendar event will be right.

02 Utilisation as a four-week leading signal for revenue and an eight-week signal for cash

Utilisation is the single most important leading indicator the services CFO has, and it sits on top of the weekly operations data the field already produces. Fleet utilisation today drives stages or pump hours billed this week; stages billed this week drive invoiced revenue four weeks out; invoiced revenue four weeks out drives cash receipts eight weeks out at typical 30–45 day terms, and twelve weeks out for operators on the wrong side of the slow-pay distribution. A utilisation move today is in the cash document at a known point eight to twelve weeks ahead.

Primary Vision's public frac spread count is the market-level proxy and a useful sanity check. The most recent 2026 print is 153 active spreads versus 201 a year earlier — a 24% YoY decline consistent with the day-rate compression cohort companies reported through 2025. But the market-level number is far too coarse for cash planning. The internal series that matters is fleet-by-fleet weekly utilisation — percentage of available days billing, stages per fleet per month, pump hours per unit, and the dedicated-versus-spot breakout. The market count tells you the cycle is soft. The internal series tells you which of your own fleets are sliding through 70% utilisation toward the stack-and-store trigger.

The cash translation is asymmetric. A 10-point utilisation drop on a fixed-cost fleet base can wipe out 20–40% of segment EBITDA because cost per unit of output rises while lease and debt service hold flat. The template models it explicitly: a sliding 12-week utilisation curve drives a revenue projection, which nets against a fixed-charge stack — equipment finance, operating lease, yard and storage, security, insurance, minimum maintenance capex — that is largely insensitive to utilisation until stack-and-store triggers. The cash chart through a utilisation drop is steeper than the revenue chart, and it is the cash chart the lender, the board, and the equipment lessor are pricing.

Fleet vintage matters for the same reason. Cohort companies with younger fleet (under five years average) run utilisation four to six points above median; older fleet (over eight years) runs below. Inside a private services group the vintage split is usually visible to operations but rarely surfaces in finance. The template carries a fleet-vintage column on the utilisation tab so the projection reflects realistic deployment order under stress.

03 Operator slow-pay as a structural cash event, tracked per operator

Upstream operators slow-pay in downturns even when the balance sheet does not require it, because their treasury teams are running the same trough playbook the services group is. The structural pattern across the 2014–16, 2020, and 2024–25 cycles is consistent: peak-cycle DSO of 55–65 days for typical US OFS suppliers stretches to 75–95 at the trough — a +20–30 day move. Outliers (smaller E&Ps, PE-backed independents under their own pressure) push 120+ on disputed items. The aggregate AR ageing misses the dispersion; the per-operator pattern is the early signal.

The tactics are not new. Operators extend standard terms from 30 to 60 to 90 days as policy; they slow approval and dispute resolution as implicit extension; they contest small-dollar items aggressively to delay parent payment. Enverus elevates "dispute duration" as a KPI alongside DSO precisely because dispute is the polite name for slow-pay. We have seen investment-grade operators with 80% FCF return-to-shareholder commitments push services vendors from net-45 to net-75 inside a single budget cycle, then settle the new term as next year's default.

The cash document's job is to make that pattern visible per-operator and update from actual remittance behaviour weekly. Each material operator gets a row in the receivables tab: contract value, invoiced AR by ageing bucket, average actual pay days trailing 90, dispute log, credit limit, and a realistic-pay-date forecast that updates off remittance rather than stated terms. The aggregate ageing — 30/60/90/over-90 — goes to the bank monthly; the per-operator view is reviewed weekly. The aggregate tells the lender whether the book is ageing. The per-operator view tells you which conversation to have on Monday.

Texas mechanics liens as cash leverage

For Texas-exposed work, the mineral lien under Property Code Chapter 56 is the most powerful collection tool services CFOs have, and it is materially underused. The mechanic is clean: six months from the last date of service to file the lien affidavit, Notice of Intent served ten days before recording, foreclosure suit within one year. Once recorded, the lien can supersede senior secured lender interest, makes the operator's asset harder to sell, and can be filed post-petition without violating the automatic stay. All claimants are of equal status, with priority dating back to the first date of work. In Texas bankruptcy dockets through the 2015–20 cycle, dozens to hundreds of mineral lien claimants appeared in nearly every mid-cap E&P filing. The names repeat.

We do not recommend filing as a first move. We do recommend that the cash document carry a "lien trigger" column on the per-operator AR row — typically 90 to 120 days past due on undisputed invoices — that flags the operator for Notice of Intent to Lien preparation. The notice is a procedural step and the most credible payment-terms conversation a services CFO can have with an operator using dispute as slow-pay. The call that changes the cash trajectory is rarely the lender call; it is the call where the services CFO references the lien window and the operator's treasurer realises the working-capital lever has a cost.

04 The equipment-finance line and the stack-and-store decision

Equipment-finance density in oil & gas services is the highest of any sub-sector we work in. From public-cohort filings: pressure pumping and completions run 0.5–1.5x EBITDA in equipment-finance debt plus 0.3–0.8x in operating leases; wireline runs lighter at 0.3–1.0x and 0.2–0.6x; drilling services carries the heaviest at 1.0–2.5x and 0.2–1.0x. In trough years the ratios blow out because EBITDA collapses before the obligations do — the line does not move when utilisation moves. The 13-week needs to surface the fixed-charge stack as a separate output and run it against the cash projection without netting.

The stack-and-store decision is where the cash-document discipline pays for itself. The intuition that idling a fleet recovers most of its operating cost is half-right and dangerous. Stacking removes 40–70% of direct operating cost — fuel, crew, mobilisation, consumables, some repair — but the fixed-cost layer continues largely intact: 100% of lease payments, debt service, yard and storage, security, insurance, and the minimum maintenance and preservation capex required to keep the unit re-deployable. The net cash benefit is positive but materially smaller than the headline operating-cost reduction implies. The CFO who tells the board "we can stack the third fleet and save $4.2M a quarter" is right about the gross saving and wrong about the cash saving by half. The template runs the maths line-by-line: variable cost avoided, fixed cost retained, net cash benefit, and the trigger threshold where the conversation moves from contingent to active.

The restructuring toolkit sits behind the trigger threshold and the cash document is what gives the CFO lead time to deploy it. Covenant relief — temporary leverage or FCCR resets, suspended maintenance tests, cure rights, EBITDA add-back rebasing for idled assets — works when the downturn is short and the lender group is concentrated; the pre-call within 21 days of the trigger reading buys the room. PIK toggles, capitalised interest, and maturity extension are the next layer for instruments with the documentary flexibility. Lease deferrals — deferred payments, extended terms, conversion to finance-style schedules, equipment returns under contract modification — work when the lessor can re-market the asset. Dividend and distribution restrictions are nearly automatic once any of the above lands. None of these conversations work without lead time. The cash document is the lead time.

Gas-exposed services groups run on a different commodity. Henry Hub spiked to $7.72 in January 2026 on a cold-weather print, settled back to $2.77 by April, and was the structural offset for gas-focused services through the 2025 oil compression. Haynesville-led platforms that indexed their cash document only to WTI missed the working-capital cushion gas gave them. The template carries both commodity series and a per-fleet basin tag so the projection reflects actual exposure.

05 The Monday review — what the CFO, ops, and the regions actually do with the document

A cash document updated weekly and reviewed by nobody is a compliance exercise. The cadence that turns it into a decision tool is a 60-minute Monday review with the CFO, head of operations, and regional operations leaders. The agenda is not variance-to-forecast — that is housekeeping. The agenda is the four service-line cash events the document was built to surface: utilisation by fleet versus trigger, contract renewals in the next 8 and 13 weeks, per-operator AR with realistic-pay dates, and the fixed-charge stack against the 13-week cash floor.

The decisions are deliberate. Which fleet redeploys to which basin this week. Which contracts up for renewal in the next 60 days get fought on rate versus utilisation versus walked. Which operator relationships need an explicit payment-terms conversation and which need the Notice of Intent to Lien path teed up. Where the stack-and-store trigger sits and whether utilisation is closing on it. Whether the lender pre-call gets scheduled this week rather than next month. The decisions are the document's output; the forecast number is the input.

1. Is the contract-renewal schedule reconciled weekly between operations and finance — renewal dates, current rates, expected post-renewal rates, utilisation assumptions — on the cash document, not in a separate commercial spreadsheet?
2. Are operator payments tracked individually with realistic-pay dates that update from remittance behaviour, and is there a lien-trigger column for Texas-exposed work at 90–120 days past due on undisputed invoices?
3. Is the fixed-charge stack — equipment finance, operating lease, yard, security, insurance, minimum maintenance capex — shown explicitly so the cash floor under a stack-and-store scenario is visible without extra calculation?
4. Is the stack-and-store trigger threshold documented, communicated to operations, and reviewed against utilisation weekly so the decision moves from contingent to active before the cash event forces it?
5. Is the lender pre-call scheduled at the trigger reading rather than at the covenant breach, so the room to negotiate covenant relief and lease deferrals exists when it is needed?

06 When the document extends to 26 weeks, and when it stays at 13

Services groups with material multi-year framework agreements — larger pressure-pumping platforms with anchor operators on 24-month dedicated-fleet contracts, or drilling-services groups with long-tenor rig contracts — extend to 26 weeks. The renewal-clustering pattern and slow-pay tracking carry a longer information horizon when the contract book extends, and lender review cycles on those groups typically ask for 26-week visibility into covenant compliance. The renewal schedule, utilisation logic, per-operator AR tracking, and fixed-charge stack carry forward unchanged.

Spot-market-heavy groups — wireline-led platforms, smaller workover, ancillary services — stay at 13 weeks. The cash signal beyond is dominated by spot pricing assumption, so additional weeks add forecast variance without adding decision quality.

For mixed groups — integrated pumping-plus-wireline platforms with mixed tenors — we run the document at 13 weeks with a 26-week extended outlook on the contract-renewal tab only. Cash projection holds at 13; contract calendar visibility runs longer because that is where the renewal-clustering signal sits. Lender packs include both; the Monday review uses the 13-week.

07 What the template earns when the cycle turns

The cycle is already turning. WTI averaged $58 in December 2025 — under the US new-well breakeven RSM modelled for 2026 — and bounced to $91 in March and $100 in April on a geopolitical print. Cohort companies are reporting tightening spot pricing and rising frac spread counts in the Permian and Haynesville. Day rates on contracts renewing through Q3 2026 will reflect the recovery. But the order book a services group is sitting on today still reflects the December low: realised average day rates 10–15% below 2024, locked until renewal cycles reprice them through H2 2026 and Q1 2027. Cash recovery lags commodity recovery by 90–180 days at minimum.

The 13-week document earns its keep at exactly this point in the cycle, because the divergence between spot commodity and contract economics is at its widest. CFOs running a generic 13-week tell the board "the cycle is turning, cash will follow." CFOs running the services-specific template tell the board which fleets reprice in which weeks, which operators are still on Q4 2025 terms and which have moved, which contracts are worth fighting on rate versus utilisation, and where the fixed-charge stack sits against the lowest cash week of the next quarter. The first answer is correct and useless. The second is what the room needs.