CAOEC Projects 5,709 Wells for Canada in 2026 as Early Spring Breakup Compresses Q1 Programs and Permian 3-Mile Laterals Set Records

Canada's drilling sector is tracking near 2025 levels through the first quarter of 2026, supported by an unusual combination of strong commodity prices and improved fiscal terms in Alberta, even as an unusually warm winter triggered an earlier-than-normal spring breakup that compressed Q1 program schedules. In the United States, the Permian Basin has crossed a technical threshold that is reshaping completion economics across the industry: average lateral lengths now routinely exceed 16,000 feet, with some wells extending past 20,000 feet, fundamentally changing the economics of each barrel produced.

Canada 2026: CAOEC Forecasts 5,709 Wells

The Canadian Association of Oilwell Drilling Contractors (CAOEC) projects 5,709 total wells drilled in Canada in 2026, up 161 wells (2.9 percent) from the 5,548 wells drilled in 2025. The forecast represents steady rather than explosive growth, with the primary headwinds being commodity price uncertainty and an early spring breakup compressing the Q2 program. Enserva, the industry services association formerly known as PSAC, released its companion 2025-2026 State of Industry Report in November 2025, projecting total oil and gas capital spending down approximately 2.2 percent in 2026 versus 2025, with British Columbia expected to rebound 6 percent on LNG Canada Phase 1 demand while Alberta and Saskatchewan decline roughly 4 percent each.

The quarterly active rig count forecast from CAOEC shows 261 active rigs in Q1 2026 (pre-breakup), dropping to 153 rigs in Q2 during spring breakup, then recovering to 211 in Q3 and 225 in Q4 as fall drilling programs ramp up.

Western Canada Sedimentary Basin drilling is split roughly 65 to 70 percent in Alberta and 20 to 25 percent in British Columbia, with Saskatchewan and smaller provinces accounting for the remainder. Horizontal wells now account for 98 percent of new wells drilled in Alberta, and 97 percent of those use horizontal multistage fracturing.

Early Breakup: Unusually Warm February and March

Alberta and Saskatchewan experienced significantly drier and warmer-than-normal conditions through February and early March 2026, triggering an early spring breakup that pushed load restrictions onto secondary roads several weeks ahead of the typical late-March or April timeline. The Baker Hughes North America rig count for the week ending March 28, 2026, showed a total of 696 active rigs across North America (U.S.: 543, Canada: 153), with Western Canadian oil-directed rigs dropping 19 week-over-week to 93 and gas-directed rigs falling five to 58 as breakup accelerated.

Field service companies and drilling contractors report that operators accelerated Q1 programs to complete planned wells ahead of breakup rather than risk losing rig-days to road bans, partially offsetting the seasonal compression. CAOEC's service rig fleet of approximately 600 workable units was running at 76 percent utilization in Q1, ahead of the 54 percent expected in Q2.

Montney and Duvernay: Deep Basin Liquids Driving Activity

The Montney Formation, straddling the Alberta-British Columbia border, remains the single most active drilling play in Canada. Its combination of high natural gas liquids yields, liquids-rich gas windows, and close proximity to LNG Canada's Phase 1 export terminal at Kitimat is driving a wave of development activity from producers including Canadian Natural Resources, Tourmaline Oil, Arc Resources, and Ovintiv.

The Duvernay Formation in west-central Alberta has attracted increased attention as a deep liquids-rich play with economics comparable to the best U.S. shale plays. Imperial Oil holds significant undeveloped Duvernay acreage through its ExxonMobil Canada subsidiary and is among the operators evaluating full-scale development programs as horizontal well technology and completion designs improve.

Permian Basin: The 3-Mile Lateral Revolution

In the United States, the Permian Basin has crossed a lateral length threshold that is reshaping well economics across the industry. The average lateral length for Permian Basin horizontal wells drilled in Q4 2025 and Q1 2026 has exceeded 16,000 feet for the first time, with some operators routinely drilling wells with laterals of 18,000 to 22,000 feet as acreage consolidation enables longer single-well drainage areas.

The economics are straightforward: a single 3-mile lateral well in the Midland Basin typically costs $8 to $9 million in total completed well cost but recovers 700,000 to 900,000 barrels of oil equivalent over its productive life. A comparable 1.5-mile lateral would cost roughly $5 million but recover only 350,000 to 450,000 BOE, making the longer well substantially more capital-efficient. The EIA projects Permian crude output to reach 6.6 million barrels per day in 2026, up 430,000 barrels per day year-over-year.

Completion intensity has also increased, with operators now routinely pumping 2,500 to 3,500 pounds of proppant per lateral foot. Water management has become a binding constraint in some areas. ConocoPhillips and Diamondback Energy have both announced multi-year water recycling commitments in their Permian operations, with Select Water Solutions setting a single-day facility record of 500,000 barrels of produced water supplied to a Permian operator in May 2025.

Technology at the Wellsite: AI and New Bit Designs

Several major operators have deployed AI and machine learning tools for real-time drilling optimization, with early adopters reporting reductions in non-productive time of 15 to 25 percent and improvements in rate of penetration of 10 to 15 percent. Halliburton deployed its Hypersteer MX directional drill bit in January 2026, a matrix-body design that combines shankless directional steerability with matrix-body durability, enabling longer drilling runs and fewer trips per well. Baker Hughes has similarly released data showing AI-assisted directional drilling reduces the number of bit trips per well by approximately 20 percent compared to conventional methods.

Simul-frac operations, where two wells are fractured simultaneously using a single crew and pump spread, continue to set production records in the Permian and are being evaluated for deployment in the Montney by several Canadian operators as stage counts increase with longer laterals.

Regulatory Streamlining in Alberta

The Alberta Energy Regulator has announced a streamlined digital licensing pathway for directional wells within defined low-risk operating areas, reducing typical license approval times from two to three weeks to two to three business days for qualifying applications. The initiative is part of a broader AER modernization program aimed at reducing administrative friction for operators during a period of elevated activity.

For real-time rig activity across Western Canada, see the Alberta Rig Activity Map and British Columbia Rig Activity Map, updated daily from AER and BC Energy Regulator source data. Related reading: North America Rig Count Falls to 729 as Shale Operators Hold Capital Discipline.