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Key Insights

• In 2025, a total of 13,295 UWIs were spudded across B.C., Alberta, Saskatchewan and Manitoba, of which 7,985 (~60%) were brought on production by year-end.
• Heavy oil plays (notably the Clearwater and Mannville formations) accounted for about 43% of all UWIs spudded, reflecting extensive use of multi-lateral horizontal drilling.
• The Montney formation continued to dominate well performance metrics, contributing roughly 69% of the Top 100 wells by initial first three-month calendar daily average boe rate.
• Canadian Natural Resources (CNRL) was the most active driller (over 2,100 UWIs), while Ovintiv Canada had the most high-performing wells (32 of the Top 100).
• Drilling activity occurred against a backdrop of moderate oil prices (WTI averaged in the mid-$60s, Western Canadian Select in the low $50s) and weak natural gas prices (AECO hub gas often <$2, even briefly negative), which encouraged investment in oil projects with quick payouts and led many gas producers to defer new drilling.

Drilling Activity Overview

Record UWI Count: Operators across Western Canada spudded 5,676 wells from surface in 2025, a decrease of about 6% from 6,025 wells spudded in 2024. There were 13,295 oil and gas UWIs in 2025, however, up 6% from 12,551 UWIs the prior year. In 2025, about 7,985 UWIs (60% of those drilled) were tied in and producing by the end of the year, indicating efficient project execution and a front-loaded drilling calendar.

Heavy Oil Dominance: Nearly half of all 2025 UWIs came from shallow heavy oil plays. In fact, the top four formations by well count were the Clearwater, Waseca, Sparky and McMurray — all heavy oil or bitumen reservoirs in Alberta. The Clearwater formation alone saw ~2,332 UWIs spud (roughly 18% of all activity), making it the single busiest play. This heavy oil focus marks a strategic shift toward lower-cost, short-cycle projects: even with moderate oil prices, these wells were highly economical. By contrast, gas-directed drilling was comparatively restrained due to poor gas prices (see Market Context below).

Multi-lateral Technology: A major factor boosting UWI counts was the extensive use of multi-lateral horizontal wells in heavy oil reservoirs. In plays such as the Clearwater and Mannville Stack (Waseca, Sparky, etc.), operators drilled multiple lateral legs from one surface location, and each lateral is counted as a separate UWI. This practice maximizes reservoir contact and production per well pad.

It’s estimated that 43% of all UWIs spudded were in these multilateral-heavy oil projects, indicating thousands of lateral legs drilled. The result was an increase in reported UWIs without a proportional increase in surface land disturbance or drilling rigs needed (since one rig can drill several laterals on one pad). This technological approach was pivotal in achieving 2025’s high UWI count and rapidly adding production in heavy oil areas.

Top Operators by Drilling and Performance

Most Active Drillers, by UWIs Spudded: During 2025, Canadian Natural drilled by far the most UWIs, capitalizing on its expansive heavy oil and thermal oilsands programs, plus some gas development. Cenovus was second, reflecting its broad asset base in both oilsands and conventional plays.

Notably, several mid-size companies focusing on heavy oil made the Top 10: for example, Spur Petroleum and Headwater Exploration (both heavily focused in the Clearwater play) each drilled hundreds of UWIs. This underscores how the heavy oil boom enabled smaller operators to contribute significantly to overall activity. Traditional large-cap E&Ps such as Whitecap and Baytex also maintained active drilling programs in their core areas (e.g. Viking and Clearwater for Tamarack; Clearwater, Peace River and light oil for Baytex). See the Top 10 operators and their UWI spud counts in the chart below.

Top 10 current operators by number of UWIs spudded in 2025. Of note, Tourmaline Oil just missed the cut in 11^th place with 371 UWIs spudded.

Leaders in Well Performance: A different set of companies led the pack when looking at well performance rather than quantity. Considering the Top 100 wells of 2025 by initial production rate (barrels of oil equivalent per day, first 3 months average), the operators with the most entries in this top tier were:

• Ovintiv Canada – 32 wells in the Top 100
• CNRL – 17 wells
• Cenovus – 13 wells
• Shell Canada – 11 wells
• Murphy Oil – 10 wells
• Tourmaline Oil – 4 wells
• Others such as ConocoPhillips, Pacific Canbriam, Advantage Energy had 2–3 each; several companies had 1 top well.

Ovintiv’s dominance here reflects its focus on high-rate Montney wells. Despite not drilling as many wells as CNRL or Cenovus overall, Ovintiv’s Montney gas and condensate program delivered an outsized share of the very best wells.

Major oilsands players such as CNRL and Cenovus also featured prominently, thanks to a few exceptional wells (for example, high-rate SAGD producers or top-tier Montney wells in their portfolios). Shell and Murphy, neither Top 10 drillers by UWI count, managed to place many wells in the Top 100 by targeting high-impact projects (Shell in the Deep Basin gas, Murphy in the Montney and Duvernay). This contrast illustrates how companies optimized for volume vs. those optimized for well productivity pursued different strategies in 2025, both successfully.

Top-Performing Wells of 2025

Highest-Rate Gas Well: Ovintiv Canada drilled the most prolific gas well of the year in the Montney formation. This well, in the Heritage field area of northeast B.C., achieved an initial production of about 32 mmcf/d of gas (calendar daily average rate over the first three months). It was brought onstream in February 2025. This remarkable rate showcases the Montney’s potential when a top-quality reservoir interval is combined with optimized completion techniques. The well’s location and depth indicate it targeted the over-pressured Montney zone known for extremely high deliverability.

Highest-Rate Oil Well: The top oil well of 2025 was drilled by Archer Exploration in the Charlie Lake formation of northwest Alberta. Located in the Elmworth area, this well flowed approximately 1,021 bbls/d on average in its first three months. It came on production in August 2025. The Charlie Lake is a lesser-known Triassic light oil play, so this result was a positive surprise, exceeding the initial rates of wells in more prominent oil plays. Archer’s success with this well highlights there are still individual wells in traditional plays that can yield exceptional production with the right approach.

These two standout wells reflect the diversity of the basin’s resources: a deep unconventional gas well delivered the year’s largest gas rate, while a shallower conventional oil well captured the top oil rate. They also underscore that top performance can come from both major operators (Ovintiv) and smaller ones (Archer), depending on the play and opportunity.

Key Formations: Activity vs. Performance

Dominant Formations by Well Performance: Among the top-producing wells of 2025, the Montney shale utterly dominated. Of the Top 100 wells (by boe rate), 69 wells were Montney producers (spanning Upper, Middle and Lower Montney zones). This confirms that the Montney remains the premier formation for high initial production in the WCSB, thanks to its large gas and condensate reserves and ongoing drilling efficiency improvements.

The McMurray formation (part of the Athabasca oilsands) accounted for 19 of the Top 100 wells — these were primarily high-rate SAGD wells producing bitumen.

Other formations making minor contributions to the Top 100 included the Wilrich and Falher (Deep Basin Cretaceous gas sands) with a handful of entries each, and one or two wells from plays like the Leduc (Devonian reef oil) and Duvernay (shale oil).

In short, no other formation came close to the Montney in terms of delivering elite wells; the Montney’s share (about 69%) far surpassed all others combined. This mirrors recent years and indicates that if a company’s goal is to drill a Top 10 well, the Montney is the place to be.

Most-Drilled Formations: By contrast, the formations that saw the most drilling activity in 2025, based on UWIs, were largely heavy oil and shallow sand plays.

The chart below indicates the most active target formations by number of UWIs spudded, and illustrates the contrast between conventional heavy oil plays, unconventional plays, and others.

Top 10 projected formations by number of UWIs spudded in 2025. The first three (Clearwater, Waseca and Sparky) are heavy oil formations in Alberta, each with well over 1,000 UWIs. By comparison, the Montney (in Alberta) had ~470 UWIs spudded, Duvernay had 289 wells, and other plays had fewer. This highlights the concentration of drilling in heavy oil targets.

This ranking underscores that heavy oil plays dominated drilling: the Clearwater was the top target, followed by the Waseca and Sparky (these are Cretaceous sand members in the Mannville group, also heavy oil reservoirs in east-central Alberta), and then the McMurray (bitumen sands in northern Alberta). Each of these four formations saw well over a thousand new UWIs. The Bluesky (a Peace River region heavy oil sand) also contributed a significant number of UWIs.

The highest ranked non-heavy-oil play was the Montney formation in Alberta, with 470 UWIs spudded. If Montney wells drilling in B.C. (410 UWIs) were added, the total Montney count would be higher.

Lloydminster refers to Mannville heavy oil drilling on the Saskatchewan side of the border, also sizable at 345 UWIs.

The Spirit River formation (which includes Falher and Notikewin) saw 341 gas UWIs in the Deep Basin, showing that some gas drilling continued despite price headwinds. Finally, the Duvernay shale had 289 UWIs, reflecting ongoing development of this light oil (condensate) play in Alberta.

Activity vs. Productivity: Formations driving drilling activity were not the same as those yielding the highest-rate wells. Heavy oil formations topped the drilling counts due to their favourable economics and multi-lateral drilling approach, but these wells typically have modest per-well production rates and thus do not appear among “top wells” lists.

Conversely, the Montney formation dominated the top wells and is highly productive but accounted for a relatively small share of total wells drilled. This difference illustrates a two-pronged strategy in the basin: one emphasizes high volume of lower-rate wells (heavy oil) for steady, low-cost output, and the other emphasizes lower volume of high-rate wells (Montney, Deep Basin) for large individual well returns. Both strategies were successful in 2025 within their contexts.

Market Context

Oil Prices: 2025 saw lower oil prices globally. Brent crude averaged around $69–$70/bbl for the year, with a downward trend from the mid-$70s in January to the low $60s by December. The market was characterized by a persistent oversupply (global production growth outpacing demand), which kept prices in check. For Canadian producers, benchmark West Texas Intermediate averaged in the mid-$60s, and Western Canadian Select (heavy oil) traded around the low $50s/bbl for much of the year. These prices, although not as high as the prior year, were sufficient to make heavy oil projects profitable — a key reason why heavy oil drilling surged. Companies could confidently invest in projects like the Clearwater that break even at ~$25–$30/bbl and still generate strong returns at $50+ heavy oil prices.

Natural Gas Prices: On the gas side, conditions were challenging. Western Canadian natural gas prices hit record lows in 2025. The AECO hub price often hovered near $1 per mmBtu, and during the summer glut, prices turned negative on several occasions (meaning producers had to pay to dispose of gas). This price collapse was driven by regional oversupply and pipeline bottlenecks that prevented excess gas from reaching higher-priced markets. In response, many gas producers shut in wells and slashed drilling for pure gas projects. This is reflected in the relatively modest Montney well count and Deep Basin activity — it likely would have been higher if gas prices were stronger. By late 2025, gas prices recovered slightly (back above $2 as winter demand picked up), but the annual picture remained weak.

Impact on Drilling Strategy: The commodity price environment prompted a shift in capital allocation. Stable-to-soft oil prices encouraged producers to favour projects with quick payouts (hence the heavy oil drilling focus), as these could generate cash flow even if prices dipped further. Ultra-low gas prices disincentivized new gas drilling except in the most liquid-rich areas; many gas wells that were drilled focused on condensate (which tracks oil prices) rather than dry gas. In essence, 2025’s market context rewarded the heavy oil and liquid-rich projects and put a premium on cost efficiency. The industry’s ability to maintain drilling activity in this climate demonstrates improved cost structures and the attractive economics of plays like the Clearwater.

Conclusion: In summary, drilling activity in Western Canada during 2025 was driven by heavy oil horizontals and sustained by the basin’s top-tier gas play (Montney) on the performance side. The interplay of moderate oil prices and weak gas prices shaped company behaviours — pushing investment toward oil opportunities and technological innovations like multi-lateral drilling to maximize returns. The Western Canadian Sedimentary Basin showcased its versatility: it can churn out thousands of low-cost heavy oil wells while simultaneously delivering some of the most productive unconventional gas wells in the world. This dual capability positions the region well for the future, balancing near-term profitability with long-term resource potential.

Note: All prices are in USD.

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Bruce Hancock is Director, Technical Advisory Group, at geoLOGIC systems ltd. He has over 40 years’ experience in oil and gas exploration, development and production.