Prospera Energy's 140-Well Heavy-Oil Reactivation Model Targeting 3,000 boe/d in Western Canada

• Prospera Energy has identified more than 140 shut-in reactivation candidates, of which 42 are now screened as Tier One, with each project costing roughly $150,000 and paying back in six to eight months.
• The company is closing a $12 million non-brokered financing with proceeds directed almost entirely to its well reactivation programme.
• Year-end 2025 reserves show a 1P before-tax NPV10 of $130.6 million and a 2P figure of $202.0 million, with proved developed producing value guided to grow from $27 million to approximately $65 million during 2026.
• Management expects Q2 2026, due to be reported around mid-August, to be the company's strongest quarter to date, with netbacks trending toward $30/BOE.
• Key risks include a stated commodity price pause threshold near $55/barrel WTI, and execution risk in sand management during reactivations

Prospera Energy Inc. (TSXV:PEI) is executing one of the more capital-disciplined turnaround stories in the Western Canadian heavy-oil patch: reactivating wells that sat shut-in for two decades, using the cash flow from each one to fund the next. With a $12 million non-brokered financing set to close mid-July 2026, and commodity prices strengthened by the Strait of Hormuz supply disruption, the company is entering what CEO and Executive Chairman Shubham Garg calls its most important phase yet.

Scaling a Proven Heavy-Oil Reactivation Model

Prospera's investor group first put $16 million into the company - a private placement, a buyback-able royalty, and a senior loan - before the current management team took control of the board in October 2024. Since then, the group has raised a further $9 million, mostly from board members and their own network, and the board now owns 52% of the stock. The company is currently closing a $12 million non-brokered private placement with $10 million earmarked for the workover and reactivation programme and $2 million for working capital.

Production sat at roughly 800 boe/d (barrel of oil equivalent) gross following a first-quarter 2026 net sales average of 720 boe/d, up 9% year-on-year. Field operating netback improved sharply through the first quarter, from $4.78/BOE in January and $2.95/BOE in February to $27.70/BOE in March, and management expects the Q2 2026 netback to land near $30/boe against operating costs of $36-40/BOE and royalties of $10-11/BOE. Q2 2026 results, expected to be the company's best quarter to date, are due out around mid-August.

The Reactivation Model

Prospera's core thesis rests on Luseland, its flagship Saskatchewan heavy-oil pool, where wells that produced strongly decades ago were shut in as previous operators changed hands repeatedly and lost technical focus. The company has completed a blend of low-risk, modest-rate wells and higher-impact candidates for approximately $150,000 per project, with payback in six to eight months and a second payback typically following within 12-14 months.

"We don't push the wells to their max limit," Garg said. "One or two barrels less per day is better than doing a $30,000 rig job when that well sands in or needs a workover for some reason."

This discipline extends to how the company sequences its rig: rather than drilling a pool section end to end, Prospera brings on one or two wells, studies fluid behaviour and sand production for 30-45 days, and only then advances to the next candidate.

Interview with Shubham Garg, Executive Chairman & CEO of Prospera Energy

Reserves and Reservoir Quality

Prospera's 2025 year-end reserves show 1P before-tax NPV₁₀ of approximately $130.6 million and 2P of $202.0 million, against a reserve life index of roughly 41 to 50 years respectively. Proved developed producing (PDP) value stood at $27 million at year-end 2025, is expected to reach approximately $38 million by end of March 2026, and management is targeting $65 million by year-end 2026 from currently scheduled projects alone - before accounting for technical revisions on wells that have already outperformed initial reserve-auditor assumptions.

"This is not your shale play where it goes up and it collapses," Garg said. "These are long life 10 to 15 barrel per day wells that'll produce for the next 20 to 40 years."

Company data shows some wells in the pool with 45-55 years of production history at flat rates near 10 bbl/d, supporting management's case that today's reactivations should behave similarly rather than following a shale-style decline curve.

Growth Catalysts and Tier-One Inventory

Beyond the wells already online, Prospera has identified 42 additional Tier One reactivation candidates defined as wells expected to pay back within 8-9 months with out of a broader inventory of more than 140 shut-in wells. Management estimates the incremental operating cost of bringing new wells online at approximately $15/barrel, well below the current cost base, since fixed costs such as property tax and surface leases are already being carried across the suspended inventory.

Prospera frames Hemisphere Energy, which grew from roughly 1,400 boe/d to 3,800 boe/d and now pays a shareholder dividend, as its closest comparable targeting a similar path toward 3,000-3,500 boe/d before prioritising debt retirement. A polymer flood opportunity also exists at Luseland, based on results already demonstrated in neighbouring analog pools recovering 35-45% of oil in place, compared with Prospera's current 3-8% recovery factor.

The Investment Thesis for Prospera Energy

• Capital-efficient growth model: reactivations cost roughly $150,000 each with 6-8 month paybacks, funded increasingly from field cash flow rather than external capital.
• Large, de-risked inventory: 140+ shut-in wells remain, including 42 already screened as Tier One candidates with sub-nine-month payback profiles.
• Balance sheet repair underway: the $12 million financing is structured to retire approximately $30 million of senior debt, subordinated debt, and royalty obligations within 24 months.
• Reserve growth ahead of the numbers: PDP reserves are guided to grow from $27 million to $65 million through 2026, with a further technical revision expected once newer wells build production history.
• Commodity tailwind: Strait of Hormuz-related supply disruption and improving Western Canadian egress (Line 3, Trans Mountain, crude-by-rail expansions) support realized pricing.
• Board alignment: insiders hold a meaningful equity stake and have converted debt to equity rather than drawing cash from the company
• Watch items: Q2 2026 financial results (due mid-August), closing of the $12 million financing, and the pace of technical reserve revisions into the April 2027 reserve report.

Macro Thematic Analysis

Western Canadian heavy oil has spent much of the past decade discounted for reasons that Garg argues have now largely resolved: pipeline egress constraints, inconsistent federal policy support, and repeated commodity price shocks. Enbridge's Line 3 expansion and the Trans Mountain expansion together add roughly a million barrels a day of egress capacity, while crude-by-rail has added a further 300,000-400,000 barrels a day of flexibility. Saskatchewan's government has set a goal of adding 400,000 bbl/d of production by 2030, and a change in federal government has, in management's telling, shifted sentiment toward the sector.

Layered on top of that is a geopolitical dimension: the Strait of Hormuz disruption that emerged in early 2026 has tightened global heavy-sour supply, pushing WTI from a first-quarter average of $71.90 toward levels near $98 by mid-May. Garg frames the resulting valuation gap starkly: "We just saw a big deal happen this morning at about $200,000 Canadian per flowing barrel of oil...we're buying assets at 35,000 to 40,000, and we're bringing wells on at 3,000 to 10,000 a flowing barrel." With only five to seven junior public oil companies left listed in Canada, management argues that capital has been slow to re-rate the sector even as the underlying fundamentals have improved - a gap it expects to close gradually as more producers demonstrate results.

TL;DR

Prospera Energy (TSXV:PEI) is scaling a proven strategy of reactivating shut-in Saskatchewan heavy-oil wells at roughly $150,000 each, with 6-8 month paybacks. A $12 million financing closing mid-July funds the next phase of its 140-well inventory, including 42 Tier One candidates. Q2 2026 is expected to be the company's best quarter yet, with reserves guided to grow sharply through 2026. Management targets 3,000-3,500 boe/d, debt retirement within 24 months, and frames Hemisphere Energy as its closest growth comparable.

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