Tourmaline Oil (TOU) — Stock Analysis 2026 [3.6]

Analysis as of 10 September 2026. Fundamentals are from Tourmaline’s 2025 Annual Information Form (reserves effective 31 December 2025) and its Q2 2026 MD&A and interim financial statements (30 June 2026, dated 29 July 2026); market data is the 9 September 2026 close. Price deck: base Henry Hub US$3.00/MMBtu — the representative trailing average on the fixed US$2.00–4.00 grid — with every grid price run as a scenario (deep bear US$2.00 / bear US$2.50 / base US$3.00 / bull US$3.50 / deep bull US$4.00); WTI, the second deck for the liquids, is held at its own US$70/bbl base in every column; the U.S. EIA forecast is a 0% cross-check — no spot price is carried, so the section does not age with the daily quote. Rating: ★★★½ Solid quality / Overvalued (wide band) — the shares imply a flat Henry Hub of about US$4.38/MMBtu. All figures in Canadian dollars (C$) unless marked US$. Refreshed on each annual report, each quarterly report and on material events. For information only, prepared with AI assistance — see the disclaimer at the end.

Tourmaline Oil is Canada’s largest natural gas producer: 630,000 barrels of oil equivalent a day of guided 2026 output from two stacked-pay basins, and a marketing book that sells Alberta gas into Chicago, California, the Gulf Coast, Dutch TTF and Asian JKM. The thesis in one line: a best-in-class balance sheet and the deepest inventory in Canadian gas, priced by the market for a Henry Hub well above where gas has actually traded. It is worth a look now because the Spirit River sale, the end of deep-cut ethane processing and a pause in the NEBC build have reset the company to a leaner, cash-first shape. To screen Tourmaline against every North American upstream producer on the same fields, go to Metal Pilot.

1. Snapshot & thesis

Figure 1. Tourmaline in numbers, 9–10 September 2026

Figure data: Table 1, this analysis.

Table 1. Tourmaline in numbers

Source: Tourmaline Q2 2026 MD&A and interim financial statements (share count p.23, balance sheet p.34, net debt p.31); Tourmaline 2025 Annual Information Form (reserves p.13, production p.23–24, dividends p.26); FY2025 results release , 4 March 2026 (revenue, costs); share price per Google Finance , 9 Sep 2026 close; US$ at C$1.3798 (Bank of Canada , 9 Sep 2026). Cash margin per §2.6.

Here for the verdict? The statcards above and the rating in Section 9 are the whole story. Want the evidence? Read Section 2 (the assets) through Section 7 (the valuation).

Identity. Tourmaline Oil Corp. is an Alberta-incorporated E&P producer (oil & gas) in the energy-producer sector class, listed on the Toronto Stock Exchange (TSX: TOU) and headquartered in Calgary. It runs two core areas in the Western Canadian Sedimentary Basin — the Alberta Deep Basin and the Northeast British Columbia (NEBC) Montney — operates 33 gas plants across them, holds 12.87% of the listed royalty company Topaz Energy, and sold its third area, Spirit River, on 2 February 2026.

Thesis in brief. The bull case is quality and duration: 5,816 mmboe of 2P reserves after the sale, 22,439 unbooked locations behind them, 356% reserve replacement in 2025, and net debt of 0.48× cash flow backed by an undrawn C$2.55 billion revolver. The bear case is price: at a flat US$3.00 Henry Hub the 2026 guidance year leaves roughly zero free cash flow after the C$2.55 billion programme, and Canadian gas still clears at a discount the marketing book narrows but does not close. What tips it is the gas deck the reader holds, and whether the 2027–28 international contracts and the NEBC plants lift the realised price before the market stops paying for them in advance. Section 9 has the full rating.

2. Assets & operations

Tourmaline’s gas prices off a landlocked system: in Q2 2026 the AECO 5A benchmark averaged C$1.66/mcf while NYMEX settled at US$2.90, and the company’s own unhedged realisation was US$1.91/mcf. For the market backdrop behind that spread, see Natural Gas — A Complete Market Guide ; the commercial design described below is Tourmaline’s answer to it.

2.1 Portfolio overview

Table 2. Portfolio at 31 December 2025, and the 2026 changes

Source: Tourmaline 2025 AIF — area production p.24, core-area reserves and locations p.10–11, the Spirit River disclosure p.6; Q2 2026 interim statements note 6 (Aduro) and the 8 September 2026 early-warning report (Topaz stake). Reserves are 2P Company Gross, NI 51-101, effective 31 Dec 2025, evaluated by GLJ Ltd. and Deloitte LLP; the core areas do not sum to the total because the report aggregates “other Alberta” and the Peace River High separately. Spirit River’s 30,000 boe/d at the sale date is from the Q2 2026 MD&A p.6. Topaz is independently operated.

Concentration is low for a company this size. Production splits almost evenly — 50.0% Deep Basin, 46.2% NEBC Montney in FY2025 — and no single field carried 20% or more of the evaluator’s 2026 proved forecast (AIF p.22). Reserves tilt the other way: NEBC holds 63% of 2P, which is where the next decade of capital goes. No asset map is drawn (§10.1).

2.2 Revenue split — by product & by area

Figure 2. Revenue by product, FY2025

Figure data: Tourmaline 2025 AIF , p.24, revenue by product type for the year ended 31 December 2025 (revenue defined there as commodity sales plus the premium on risk management plus realised financial gains).

Figure 3. Production by core area, FY2025

Figure data: Tourmaline 2025 AIF , p.24, average daily production by area, annualised. Revenue by area is not disclosed, so production share stands in for the by-asset split; the two differ because the Deep Basin is the more liquids-rich area.

Read together, the two figures say what Tourmaline is: a gas company by volume and a half-liquids company by revenue — oil and condensate alone were 26.4% of FY2025 revenue on 8.3% of volume. That is why §7 carries WTI as a second deck, and why ending deep-cut ethane extraction in March 2026 — about 20,000 bbl/d of the lowest-value liquid — raises the netback: the company guides to C$65 million in 2026 and C$110 million in 2027 of avoided fees (AIF p.6). Q2 2026 already shows it: NGL volume fell 21% while the realised NGL price rose 55% to C$40.36/bbl (MD&A p.7, p.11).

2.3 Alberta Deep Basin

The Deep Basin is a tight-gas play running about 520 km northwest from Garrington to Grande Prairie, with up to fifteen stacked liquids-rich Cretaceous sands. Tourmaline is the largest producer in the play at about 330,000 boe/d on some 6,507 gross sections (AIF p.10). Year-end 2P reserves were 1,949.8 mmboe with 1,435 gross (1,280.8 net) booked locations; management identifies up to 15,223 gross horizontal and 86 vertical locations in the area.

Ownership of the plumbing is what makes it work: 23 operated gas plants, 11 wholly owned, and about 2.5 bcf/d of net processing capability, so a new well ties in on Tourmaline’s schedule. The key asset-level risk is maturity — the Deep Basin carries half the production on a third of the 2P.

2.4 NEBC Montney

The second core area runs from Grande Prairie to about 190 km northwest of Fort St. John, targeting liquids-rich Montney gas assembled over a decade of deals, most recently Aduro in June 2026. It is the larger asset on every forward measure: 3,866.2 mmboe of 2P, 63% of the company, about 325,000 boe/d of production, some 1,703 gross sections, 2,004 gross (1,973.9 net) booked and about 8,814 gross identified locations (AIF p.10–11). Ten facilities provide about 1.4 bcf/d (1.2 bcf/d net), including the 400 mmcf/d Gundy Creek deep-cut plant; Sunrise/Dawson and Gundy Creek are both sweet gas, a structural cost advantage over sour-gas Montney peers, and the NEBC assets earned MiQ Grade “A” methane certification in 2025 (FY2025 release).

Aitken is scheduled for Q4 2026 and Groundbirch/Monias for Q4 2027, with a one-year pause before Phase 2. The key asset-level risk is British Columbia: slower permitting, the Blueberry River First Nations consent framework over much of the play, and a new provincial royalty framework from 1 January 2027 (MD&A p.26).

2.5 Other assets & the divestment record

Spirit River. Sold on 2 February 2026 for C$765 million before adjustments, C$751.8 million net (interim note 4), after a C$1.2 billion impairment in Q4 2025 and a further C$24.8 million in Q1 2026. The complex carried 276.0 mmboe of 2P and 634 gross booked locations at year-end; about C$500 million of the proceeds went to debt. The sale is the one arm’s-length price in the file for this company’s own reserves — about C$2.72 per 2P boe — and §7.5 uses it.

Topaz Energy. Tourmaline created Topaz (TSX: TPZ) and has been selling it down — to 15.3% after an October 2025 secondary for C$221.2 million (AIF p.6), then to 12.87% (19,931,097 shares) after 3,598,397 shares paid for two minor 2026 acquisitions, Aduro in the NEBC Montney and an Alberta Deep Basin gas complex (early-warning report , 8 September 2026). Tourmaline also sells royalties to Topaz — C$277.5 million on the Crew and Bonavista lands in 2024 and C$38.7 million on the Aduro and other recent lands on 30 June 2026 — and paid it C$57.7 million of royalties and C$19.6 million of processing fees in H1 2026 (interim note 16). The Topaz Energy analysis covers the other side of that relationship.

The inventory beyond the reserves. The AIF counts 26,512 gross locations before the Spirit River sale — 2,316 proved undeveloped, 1,757 probable undeveloped and 22,439 unbooked (AIF p.74). At roughly 280 net wells a year the unbooked count is eighty years of drilling; §7 values it at a low conversion factor rather than ignoring it.

2.6 Production, reserves & costs

Table 3. Production and realised prices, FY2021–FY2025 (annualised)

Source: Tourmaline full-year results releases — FY2022 (2022 and 2021), FY2024 (2024 and 2023) and FY2025 ; daily rates annualised ×365; realised prices include realised hedging gains; 2021–2022 realised gas not stated on the same basis in the releases (—). The 2015–2020 series is not in this analysis’ source set.

Figure 4. Production by fiscal year, FY2021–FY2025

Figure data: Table 3.

Output grew 45% in four years, a 9.7% compound rate, from the drill bit and acquisitions. 2026 is the first step back: guidance of 620,000–640,000 boe/d absorbs the 30,000 boe/d Spirit River sale and the ethane cut, and H1 2026 averaged 629,945 boe/d (MD&A p.7–8). Operating cost crept up C$1.16/boe from 2021 but is guided down for 2026.

The comparable all-in construction. This series compares gas producers on one definition: realised price after royalties, less every cash cost including corporate overhead, then less depreciation, depletion and amortisation.

Table 4. Unit economics on the comparable all-in basis, FY2025

Source: realised price per the 2025 AIF p.18; royalties (C$513.9 m), operating, transportation and cash G&A per boe per the FY2025 results release ; DD&A of C$1,751.7 m (PP&E depletion C$1,741.4 m plus right-of-use depreciation C$10.3 m) per the Q2 2026 interim statements notes 6–7, over 232.8 mmboe produced. Royalties are deducted from the price so a Canadian gross-revenue filer compares with a US net-revenue-interest filer. US$ at the 2025 Bank of Canada average of C$1.3978.

The cash margin of US$1.82/mcfe ranks third of six in the peer set (§2.7), as does the fully-loaded US$0.92/mcfe. FY2025 DD&A of about C$3.0 billion is C$1.75 billion of recurring depletion plus the C$1.2 billion Spirit River impairment (interim note 4); recurring depletion runs at C$7.52/boe, and C$7.43/boe in H1 2026 (MD&A p.16).

Table 5. Reserves and after-tax NPV, 31 December 2025 (NI 51-101, forecast prices)

Source: Tourmaline 2025 AIF , p.13 (“Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue”), effective 31 Dec 2025, dated 2 Feb 2026, GLJ Ltd. (93.4% of 2P) and Deloitte LLP. Forecast prices and costs, not SEC constant prices — the consultant-average deck opens at US$3.74/MMBtu Henry Hub and C$3.00/MMBtu AECO in 2026 and escalates at 2%/yr from 2027 (p.17). The reserves include Spirit River; the per-category split of its 276.0 mmboe is not disclosed. Probable reserves are less certain than proved; the 2P figure is the NI 51-101 standard.

Proved RLI is 13.5 years and 2P RLI 25.3 years after the sale, on 2026 guidance; before the sale, on FY2025 output, the proved RLI is 14.0 years, the basis Table 6 compares. 2P added 829 mmboe in 2025 — 356% of production, 457 mmboe of it organic, at 2P finding-and-development cost of C$11.60/boe including future development capital (FY2025 release). The evaluators’ after-tax 2P value, C$29.05 billion, is C$75.63 per share on FY2025 weighted diluted shares — the number §7 restates to a US$3.00 deck.

2.7 Peer positioning

Peer set: the five senior US gas producers this blog analyses on the identical scorecard — EQT (NYSE: EQT), Expand Energy (Nasdaq: EXE), Antero Resources (NYSE: AR), Range Resources (NYSE: RRC) and CNX Resources (NYSE: CNX): North American gas-weighted producers above ~1.5 bcfe/d, none in a pending takeover. Every star in §9 is scored against this set.

Table 6. Quality metrics against the peer set, FY2025

Source: each company’s FY2025 Form 10-K as analysed in the posts linked in §10.1; Tourmaline per Tables 1, 4 and 5 (pre-sale proved reserves and proved RLI on FY2025 production). Leverage is each company’s own basis — net debt/EBITDA for the US names, net debt/annualised cash flow for Tourmaline (Q2 2026). Reserve figures are not on one standard: SEC constant-price proved reserves for the US names, NI 51-101 forecast-price proved reserves for Tourmaline; every reserve life in the table is struck on proved reserves, never on Tourmaline’s 2P.

Tourmaline is third on volume, third on both margins, first on leverage and fourth on proved RLI, and the only one outside Appalachia or Haynesville, selling into JKM and TTF, or on a Canadian reserve standard. To run these fields across the North American upstream universe, use the Metal Pilot upstream screener.

3. Financials & balance sheet

Table 7. Five-year financial summary (C$ millions except per-share)

Source: Tourmaline full-year results releases for 2021 , 2022 , 2023 , 2024 and 2025 , on the company’s own non-GAAP definitions; dividends per the 2025 AIF p.26. Revenue is commodity sales plus the premium on risk management plus realised financial gains, before royalties. FY2025 EP capital is the AIF’s exploration, development, facilities and G&G lines (p.22); FY2025 free cash flow is cash flow less capital before acquisitions and dispositions (C$3,395.6 m − C$2,988.6 m), the company’s definition. The FY2021 YoY needs a 2020 figure on the same basis, which the source set does not carry. IFRS cash flow from operations for FY2025 was C$3,386.9 m (four filed quarters, interim p.32). The company reports no EBITDA, so leverage is shown on its own cash-flow basis.

The table has one dominant feature: cash flow held between C$2.9 and C$4.9 billion a year while free cash flow fell from C$3.2 billion to C$0.4 billion, as capital doubled with the NEBC build. FY2025 net income of C$262.7 million carries the C$1.2 billion Spirit River impairment (interim note 4); cash flow per diluted share was C$8.84, down 1%, on 10% more production, and operating cash flow backs earnings in every year. The Financial Metrics for Commodity Investing guide sets out the three-statement test this paragraph applies.

Figure 5. Free cash flow by fiscal year, FY2021–FY2025

Figure data: Table 7.

The cost deck handed to the valuation. For 2026 the company guides operating cost to C$4.50–4.60/boe and cash G&A to about C$0.85/boe; transportation has no guidance and ran at C$5.29/boe in H1 2026 (MD&A p.14). Royalties are price-linked: the effective rate was 11.2% of commodity sales in H1 2026, and the gas rate moved from 7.4% of gas revenue in Q1 to 3.7% in Q2 as prices fell (MD&A p.12). Tax: Tourmaline held C$7.8 billion of tax pools at year-end 2025 and “expects to remain cash taxable for the foreseeable future” (AIF p.21); H1 2026 current tax was a C$19.8 million recovery after Bill C-15 accelerated deductions (MD&A p.17). Operating cost has risen C$1.16/boe over five years.

Balance sheet. Net debt on the company’s definition was C$1,508.3 million at 30 June 2026, 0.48× annualised Q2 cash flow (interim p.31) and below the company’s C$1.75 billion long-term debt target (Q2 2026 results release ). It comprises C$329.5 million of commercial paper at 2.78% and C$950 million of senior unsecured notes — C$250 million each at 4.856% (May 2027), 2.077% (January 2028) and 3.934% (March 2031), plus C$200 million at 2.529% (February 2029) — with a C$231.9 million working-capital deficit; the C$2.55 billion revolver is undrawn to June 2031 (interim note 9). Leases are C$41.4 million, Morningstar DBRS rates the issuer BBB (high) (AIF p.28), and at a flat US$2.50 Henry Hub the §7 build still holds net debt near 0.8× cash flow. The decommissioning provision is C$883.6 million (C$2.9 billion undiscounted over 61 years), which the reserve report already charges in its cash flows.

The hedge and marketing book. Board policy allows hedging up to 50% of forecast production (AIF p.24). At 30 June 2026 the financial book was C$96.4 million net liability and the physical-contract embedded derivatives a C$1,030.1 million asset (interim p.43); the company had 1,014 mmcf/d of 2026 gas hedged at an average C$4.97/mcf, including 100 mmcf/d of international exposure at C$16.25/mcf (Q2 2026 results release ).

Table 8. Hedge and marketing book at 30 June 2026

Source: Tourmaline Q2 2026 interim statements , note 3, p.41–44; the 2026 hedge summary per the Q2 2026 results release . Volumes and prices are weighted averages per year as the note prints them; the embedded derivatives are Level 3 fair values discounted at 25%.

The largest position is not a hedge but the marketing book — six supply agreements selling North American gas against JKM or TTF, worth C$1.03 billion on the balance sheet and valued again by the reserve evaluator (AIF p.17), which is why §7 charges them once. The line to watch is the international swap book (−C$165.5 million), which loses as JKM and TTF rise.

Capital returns. Tourmaline paid C$3.30 per share in FY2025 — C$2.00 base plus C$1.30 of specials, about C$1.26 billion — against free cash flow of C$407 million: distributions ran 3.1× free cash flow. No special dividend has been paid in 2026, the C$0.50 quarterly base dividend continues (next payable 29 September), and the NCIB bought no shares in H1 2026 (MD&A p.22). At the 21 July strip the company forecasts C$880 million of 2026 free cash flow against about C$777 million of base dividends — covered, narrowly. Diluted shares rose 21% between 2021 and 2025, mostly for acquisitions, while production per diluted share rose about 19%.

4. Management, strategy & corporate structure

4.1 Management & governance

Michael L. Rose founded Tourmaline in 2008 and has been Chairman, President and Chief Executive Officer ever since; before it he led Duvernay Oil Corp., and Tourmaline’s stated template is the strategy much of the same team ran at Duvernay and, earlier, Berkley Petroleum Corp. (AIF p.4, p.30). Brian G. Robinson, CFO since 2008 and a director, retires on 1 November 2026; Jamie W. Heard, Vice President Capital Markets and a former Castleton Commodities International analyst, succeeds him (Q2 2026 results release ). Earl H. McKinnon has been Chief Operating Officer since December 2023; Sherra L. Aspin, Vice President Marketing since 2018, owns the international contracts in §3; Matthew G. Ockenden became Vice President Midstream in November 2025; W. Scott Kirker is Chief Legal Officer and External Affairs and Colin J. Frostad Vice President Exploration (AIF p.30–32).

The ten-member board has eight independent directors, led by Lead Director Andrew B. MacDonald, formerly Co-Head of Canadian Equities at Phillips, Hager & North. The committee chairs are Christopher E. Lee (Audit; former Deputy Chair of the Deloitte Canada board), Jill T. Angevine (Compensation; President of Brownstone Asset Management), MacDonald (Corporate Governance and Nominating), Lee A. Baker (Reserves; former CEO of Nordegg Resources) and Lucy M. Miller (Environment, Safety and Sustainability). Industry depth sits with Janet L. Weiss, President of BP Exploration (Alaska) from 2013 to 2020, and William D. Armstrong, CEO of Armstrong Oil & Gas; Travis J. Toews was Alberta’s Minister of Finance from 2019 to 2023 (AIF p.30–32).

The governance flag is role concentration. Rose holds the Chair, President and CEO roles together and the CFO sits on the board, mitigated by an independent Lead Director, 80% board independence and a dedicated Reserves Committee. Alignment is unusually high: directors and officers own 20.7 million shares, about 5.3%, and C$375.2 million of the roughly C$4.0 billion raised since inception came from directors, officers, employees and their associates (AIF p.3, p.32). The AIF discloses one historic receivership at a company Rose and Baker were directors of (Nordegg, 2016) and no sanctions.

4.2 Strategy & capital allocation

The stated strategy is to grow reserves, production and cash flow at an attractive return on capital, return cash through a base dividend plus surplus free cash flow, and be “one of the lowest-development-cost producers in the WCSB” (AIF p.4). The 2026 programme is C$2.55 billion for about 140 net Deep Basin and 140 net NEBC horizontals (MD&A p.8, p.19).

The July 2026 update reset the plan around free cash flow. The NEBC build completes Phase 1 — Aitken in Q4 2026, Groundbirch/Monias in Q4 2027 — then pauses for a year before Phase 2; capital is guided at C$2.55 billion for 2027 and C$2.3 billion for 2028, each generating more than C$1 billion of free cash flow at the July strip; the finished build is expected to add over C$400 million a year of structural cash flow, and the company holds a target of cutting operating and transportation cost by C$1.50/boe by 2031 against 1H 2025 (Q2 2026 results release ). Contracted international exposure rises to 253,000 mmbtu/d by exit 2027 and 333,000 mmbtu/d by exit 2028, storage grows from 10 bcf to 14 bcf in April 2027 (MD&A p.8), and a new AltaGas agreement takes propane and butane to export through the REEF terminal.

The capital-allocation rules are explicit: net debt below the C$1.75 billion long-term target, a C$2.00 base dividend, and specials paid from surplus free cash flow. The base dividend has been covered in every year, but the FY2025 specials were paid when free cash flow did not cover them (§3); no special has been declared in 2026, which is the rule working. Return on capital is the weakest part of the record: FY2025 cash flow of C$3.40 billion against C$2.93 billion of exploration and development capital left C$407 million of free cash flow.

4.3 Ownership & corporate structure

Tourmaline has no controlling shareholder and has absorbed more than a dozen companies since its 2008 incorporation (AIF p.2–3). The consequential transactions, most recent first:

Table 9. Material transactions, 2023–2026

Source: Tourmaline 2025 AIF , “General Development of the Business”, p.3–6; Aduro and the Topaz royalty sale per the Q2 2026 interim statements note 5; the second acquisition per the 8 September 2026 early-warning report ; Spirit River per interim note 4.

Subsidiaries and affiliates. Tourmaline Oil Marketing Corp. (Delaware) is wholly owned; Topaz Energy Corp. (TSX: TPZ) is 12.87%-held and equity-accounted; a 50-50 C$70 million joint development agreement with Clean Energy Fuels Corp. (April 2023) builds compressed-natural-gas stations (AIF p.4). There are no streams, preferred units or convertible securities.

Share capital. 388,601,707 common shares at 29 July 2026, plus 3.8 million in-the-money options (weighted exercise C$37.73) and 0.9 million restricted share units — 391.0 million fully diluted on the treasury method at C$62.38 (MD&A p.23; interim note 13). The NCIB allowed up to 19.3 million shares to 7 August 2026 and bought none in H1 2026. Dilution is the cost of the acquisition strategy: weighted diluted shares rose from 316.8 million in 2021 to 384.1 million in 2025, and 2026’s two deals were paid in Topaz shares instead — spending a listed asset rather than issuing equity.

5. ESG & sustainability

Environmental, health, safety and sustainability oversight sits with the board’s Environment, Safety and Sustainability Committee, entirely independent and chaired by Lucy M. Miller; the company runs integrated air-emissions, water and land-use strategies, annual environmental and occupational-health audits, and publishes a separate sustainability report (AIF p.25). The workforce is 544 full-time employees plus 692 consultants and contract operators (AIF p.25).

Table 10. ESG snapshot

Source: Tourmaline 2025 AIF p.6, p.25, p.30–32; MiQ grade per the FY2025 results release ; decommissioning per the Q2 2026 interim statements note 8. An emissions-intensity series, an absolute reduction target and a safety (TRIF) series are published, if at all, in the sustainability report, which is outside this analysis’ source set; none is inferred.

Read even-handedly, Tourmaline’s environmental position is better than its disclosure. Sweet gas at Sunrise/Dawson and Gundy Creek avoids the sour-gas processing most Montney peers run, the MiQ “A” grade is an independent methane check of the kind European and Asian buyers increasingly price, and ending deep-cut ethane extraction cuts energy-intensive processing. Against that, the AIF carries no quantified emissions target and the source set has no safety series — a gap the Dimension 9 score reflects rather than fills. The contested point is land: NEBC development runs under the Blueberry River consent framework, a real constraint on pace.

6. Risks

Tourmaline’s risk profile is dominated by the price its gas clears at — the Henry Hub level it cannot control and the Alberta and BC basis it spends heavily to escape — with a jurisdictional question in British Columbia and a capital-allocation question behind it.

Table 11. Risk register

Source: Tourmaline 2025 AIF risk factors and industry conditions; the Q2 2026 MD&A and interim statements (prices p.11, hedges note 3, BC royalty framework p.26); likelihood and impact are this analysis’ assessment.

Figure 6. Risk heat-map — the gas price and its basis dominate

Figure data: Table 11, this analysis.

The two risks that would break the thesis are the gas price and British Columbia. A Henry Hub near US$3.00 leaves the guidance year with almost no free cash flow after capital, which is the case §7 prices; the basis risk is why the international contracts and storage matter more than the financial hedges. British Columbia holds 63% of the reserves and nearly all of the growth capital, under a consent framework and a royalty regime that changes on 1 January 2027.

7. Valuation

Valuation as of 10 September 2026, in Canadian dollars (FX C$1.3798 per US$1.00, Bank of Canada daily average, 9 September 2026). Horizon: spot fair value. Price deck: base Henry Hub US$3.00/MMBtu — the representative trailing average snapped to the fixed US$2.00–4.00 grid (3-month US$2.94, 6-month US$2.93, 12-month US$3.59, all to end-August 2026 on the U.S. EIA Henry Hub monthly spot series; the three- and six-month windows are the representative ones because the twelve-month window carries January 2026’s US$7.72 spike) — with every grid price run as a scenario (deep bear US$2.00 / bear US$2.50 / base US$3.00 / bull US$3.50 / deep bull US$4.00). At the Q2 2026 realisation, with 90.65% of gas volume moving on Henry Hub and the rest on JKM and TTF contracts, the base is C$2.76/mcf realised before royalties. WTI is the second deck, and a dual deck: liquids were 41.0% of FY2025 revenue — the reserve report does not split value by commodity, so the latest fiscal year’s revenue share stands in — and the company’s name makes oil a headline commodity in any case. WTI is based at US$70/bbl, its twelve-month trailing average of US$75.87 leaned to the lower grid price because the 3-month US$83.06 and 6-month US$90.50 sit inside the March–May 2026 spike (EIA Cushing monthly spot), and it is held at that base in every scenario column: Henry Hub and WTI are not a documented co-moving pair — their five-year monthly correlation on the EIA series is 0.40, below 0.70 — so moving them together would invent a ratio. Condensate realises at 102.7% of the Canadian-dollar WTI price, oil at 97.1% and NGLs at 32.3% (Q2 2026). The EIA’s 9 September 2026 outlook (US$3.43 for 2026, US$3.28 for 2027) is carried as a 0%-weight cross-check; no spot deck is carried, so the section does not age with the daily quote. Discount rate 10% real, after tax, sensitised 8–12%. Share price C$62.38 (9 September 2026 close, TSX), 391.0 m fully-diluted shares, balance sheet as of 30 June 2026.

Tourmaline is valued on the E&P producer archetype, as a net asset value built from its evaluators’ own after-tax reserve values — restated to this section’s deck and rate, net of the Spirit River sale, with the unbooked inventory added at a low conversion factor — alongside two cash-flow multiples. The method behind the numbers is set out in the How to Value Commodity Stocks guide. The headline is a deck-to-value map: the blended fair value is C$36.67/share at the US$3.00 base price, C$21.39 at US$2.50 and C$52.05 at US$3.50, and each US$0.50/MMBtu of Henry Hub is worth about C$14.82 of net asset value per share, with each US$10/bbl of WTI worth another C$10.29; Table 17 and Figure 9 let a reader run the model at any gas and oil price. The tiers frame the structure: the producing reserves plus the whole equity bridge are worth C$21.93/share, the proved-undeveloped and probable reserves C$22.25, and the converted unbooked inventory C$5.75. The current price is set against that map only in §7.6.

7.1 Method selection

Tourmaline is a producer, so the blend starts from the E&P default in the valuation guide linked above — NAV/DCF 45% / EV/EBITDA 30% / a reserve or flowing-barrel read 25% — with one deviation, argued here. The guide’s reserve anchor of US$10.00 per boe is C$13.80 against the C$4.77 per 2P boe the company’s own evaluators put on its barrels after tax (C$29,050.4 m over 6,091.8 mmboe; Table 5), an overstatement of 189%, because the anchor is written for oil barrels and 77% of Tourmaline’s boe are gas at six mcf to the barrel. The flowing-barrel anchor has no dated median in this analysis’ source set. The guide’s first substitution, a cash-flow multiple on disclosed lines, is used, but it sits in the same input family as EV/EBITDA, so the two are capped at half the blend: NAV/DCF 50% / EV/EBITDA 30% / P/CF support 20%.

Table 12. Valuation method selection

Source: method-to-archetype mapping, anchors and the default weight set per The Commodity Investor, Part 11: How to Value Commodity Stocks , “The archetype is the unit of analysis” and “The valuation toolkit”. Weights deviate from the E&P default (45 / 30 / 25) for the reason argued above and are stated again in the assumptions box. Archetype per Section 1. Input families: intrinsic 50% (single method), cash-flow 50% (two methods, at the collinear ceiling), asset & capacity 0%, transaction 0%. Target multiples are derived in §7.3 from the archetype anchors, not from the Section 2.7 peer set, which stays a quality comparator.

7.2 Net asset value

Reserve basis. Tourmaline files under NI 51-101, so this net asset value rests on the evaluators’ after-tax NPV by reserve category, proved plus probable (2P): every NAV/share and P/NAV in this section is 2P-basis. On proved reserves alone — the three proved tranches at the same rate, deck and Spirit River removal, less the whole bridge — NAV/share is C$29.78 (1P-basis), the figure to read against a US filer’s proved-only NAV; it is a memo line beneath Table 16 and carries no weight.

Vehicle map. Tourmaline holds both core areas directly, as operated working interests of the parent company; the one listed affiliate is marked at market, and the two small 2026 acquisitions sit outside the reserve report the model starts from.

Table 13. Vehicle map

Source: this analysis; ownership and the evaluators’ scope per the Tourmaline 2025 AIF , p.3, p.13 and p.17; the embedded derivatives, the hedge book, Aduro and the Spirit River proceeds per the Q2 2026 interim statements , notes 3–5; the Topaz holding per the 8 September 2026 early-warning report .

Tax basis, the discount rate and abandonment. The rows start from the after-tax NPVs the evaluators publish, which already carry Tourmaline’s C$7.8 billion of company-level tax pools (AIF p.13, p.21), so the pools are inside the value rather than declined. Only the restatement terms — the deck and the exchange rate — are taxed by the model, at a 24.85% statutory rate (15% federal plus 8% Alberta and 12% British Columbia, weighted by FY2025 production by province). The model is struck at 10% real, after tax. That is the E&P convention’s rate for a single-basin, high-decline producer: Tourmaline is large, long-lived and investment-grade, which would earn 8%, but every barrel sits in one basin behind one egress system that prices off AECO and Station 2, and its tight-gas wells halve their producing output in under five years (note 5 to Table 14). The 8% row of Figure 8 shows what the lower rate would give. The reserve report is struck on an escalating forecast deck, so its rates are nominal; at the evaluators’ own 2% escalation this model’s 10% real is 12.20% nominal, and every category is re-struck to it along the evaluators’ own discount-rate disclosure. Abandonment is charged once, in the rows: the NPVs deduct abandonment and reclamation for every well, so the C$883.6 m IFRS provision is not bridged here; the relative legs in §7.3 and §7.4 deduct it, because neither EBITDA nor a cash-flow multiple carries it.

Stage risk (n/a), the probable reserves and the inventory. No asset the model values is pre-production, so every reserve row carries a 1.00 weight and neither the target P/NAV nor the rate takes a stage charge. Probable reserves enter at full value: they are evaluator-booked (GLJ Ltd. evaluates 93.4% of the 2P) and the standard NAV basis for a Canadian producer. The one risked line is the unbooked inventory — 22,439 locations at 0.05× the in-plan value per undeveloped barrel, near the floor of the 0–0.25× band because at about 280 net wells a year they are eighty years of drilling. §7.6 moves the factor with the scenario.

The per-asset NPV build. One block per reserve category: the evaluators’ filed after-tax value, re-struck to the model’s rate, less the Spirit River share, restated from the evaluators’ escalating deck — about US$3.70 Henry Hub and US$65–68 WTI in real terms — to this section’s flat US$3.00 and US$70.

Table 14. Per-asset NPV build — base case (US$3.00/MMBtu Henry Hub, US$70/bbl WTI, 10% real)

Notes to Table 14

1. The evaluators publish each category’s after-tax NPV at 0, 5, 8, 10, 15 and 20% nominal. The model’s rate, 12.20% nominal, falls between the 10% and 15% columns; the value is read between them on a timing profile fitted to all six published points, so it is exact at every published rate. The factors are 11,798.7 ÷ 12,627.3 (PDP), 667.7 ÷ 738.1 (PDNP), 4,832.3 ÷ 5,997.2 (PUD) and 7,794.6 ÷ 9,687.7 (probable).
2. Spirit River’s 276.0 mmboe of 2P is disclosed, but not its split by category or its NPV, so it is removed pro rata to volume from every row. That takes C$1,316.2 m of 2P after-tax value out at 10% nominal against the C$751.8 m the assets actually sold for: if the sold barrels were worth less than the average barrel, as the price suggests, the removal is too large by up to C$1.44/share, and NAV is biased down.
3. Gas. The evaluators’ consultant-average deck runs US$3.74/MMBtu in 2026 and US$3.70 real thereafter (AIF p.17), or US$3.70–3.71 weighted over each category’s volume profile. Realised gas moves from the Q2 2026 anchor — US$1.91/mcf at a US$2.90 NYMEX — on the 90.65% of volume priced off Henry Hub, giving C$2.76/mcf at the base and C$3.65 at the evaluators’ deck. The price change is taken net of royalty, and royalties are progressive: the gas rate was 7.4% of gas revenue at C$3.57/mcf in Q1 2026 and 3.7% at C$2.65 in Q2 (MD&A p.9, p.12), and the model reads the rate off the line through those two filed points — 4.20% at the base, 7.73% at the evaluators’ deck. Net of royalty that is C$0.72/mcf lower on the post-sale volumes: 6,466.7 bcf (PDP), 299.0 (PDNP), 7,385.9 (PUD) and 12,266.1 (probable).
4. Liquids. The evaluators’ WTI runs from US$59.92 in 2026 to US$67.79 real, or US$65.22–67.56 weighted over each category’s volumes, so the section’s flat US$70 adds value. Volumes are converted to WTI-equivalent barrels at the Q2 2026 realisation ratios (oil 97.1%, NGLs including condensate 57.1% of C$ WTI) — 194.3, 9.0, 250.8 and 400.1 mmbbl — and taken net of the liquids royalty curve through the two filed quarters (13.5% at US$72.05 WTI, 15.4% at US$93.05): C$5.32, 3.60, 3.16 and 2.71 per WTI-equivalent barrel higher.
5. PV factor. The present value at 12.20% nominal of one real unit of each category’s production, per unit of total production — 0.6487, 0.6227, 0.5608 and 0.3762 — read off a volume profile fitted to the evaluators’ before-tax NPVs plus development capital and abandonment, which it reproduces within 0.3% at every published rate. The PDP profile declines about 15% a year, so producing output halves in under five years: these are high-decline tight-gas wells.
6. Tax on the restatement terms at the 24.85% statutory rate: 15% federal plus 8% Alberta and 12% British Columbia, weighted by FY2025 production by province (AB 343,034 boe/d, BC 295,162 boe/d; AIF p.24). The pools are already inside the filed after-tax value. The marginal rate holds while the evaluators’ case stays taxable — its 2P future income tax is C$22.1 billion undiscounted — and would overstate the tax offset in any year the lower deck pushes into a loss; the full offset on all four deck terms is the outer bound, C$4.99/share, direction up.
7. The evaluators convert at US$0.740 per C$ from 2028 (C$1.3514; AIF p.17). Restating their discounted revenue net of royalty to the section’s C$1.3798 is +2.11%, after tax: for PDP, C$24,225.3 m × (1 − 14.32%) × 2.11% × 0.7515 = C$328.4 m.
8. Probable reserves at full value, as booked under NI 51-101 — evaluator-audited, not already inside the proved figure, so nothing is counted twice; the development capital they need (C$9.7 billion incremental to the proved plan) is inside their NPV.
9. (1,717.3 mmboe proved undeveloped + 2,358.4 mmboe probable undeveloped) ÷ (2,316 + 1,757) booked undeveloped locations (AIF p.19, p.74). The unbooked count is the pre-sale figure; Spirit River’s share is not disclosed.
10. Near the floor of the 0–0.25× band: at about 280 net wells a year the 22,439 locations are some eighty years of drilling, far beyond any plan the company has published. Roughly C$0.10 per unbooked boe, against C$2.00 in the plan.

Source: this analysis, from the Tourmaline 2025 AIF — the after-tax NPV table (p.13), the evaluators’ forecast prices and exchange rate (p.17), the development-capital schedule (p.20), production by province (p.24) and drilling locations (p.74), GLJ Ltd. and Deloitte LLP, effective 31 December 2025 — and the Q2 2026 MD&A (realised prices and royalties by product, p.9–12). The value column is headed Value rather than C$m because a build that multiplies heterogeneous terms cannot hold one unit — the unit sits in the cell, and only the = rows are a tranche’s own currency. Calibration: run at the evaluators’ own deck and rate (7.84% real), the same machinery returns C$28,085.2 m against the filed post-sale C$27,734.2 m, +1.27%. Contingent resources beyond 2P are not disclosed in the AIF and are not valued.

Table 15. Per-asset model — base case (US$3.00/MMBtu Henry Hub, US$70/bbl WTI, 10% real)

Source: this analysis. Every NPV in the last column reproduces from its block in Table 14; this table adds the reserve, cost, capital, tax and discounting inputs behind those figures. Unit costs and capital are the evaluators’ own undiscounted 2P figures for each category (2025 AIF p.14, p.20), before the pro-rata sale adjustment. The volumes and realisations are the post-sale reserves and the Q2 2026 realisation ratios applied to the base deck. The inventory factor sits near the floor of its band for the reason in note 10 to Table 14 and moves with the scenario in Table 24.

Table 16. NAV build-up and equity bridge (base case — US$3.00/MMBtu Henry Hub, US$70/bbl WTI, 10% real)

Source: this analysis; every balance-sheet line is cited to the Q2 2026 interim statements at 30 June 2026 — the balance sheet (p.34), the risk-management note (p.41–44), decommissioning (note 8), debt (note 9) and share capital (note 11) — and the G&A guidance to the Q2 2026 MD&A (p.14). The tiers sum to the published NAV/share: 21.93 + 22.25 + 5.75 = C$49.93 on the rounded tiers, C$49.92 unrounded — and the producing tier alone sits 65% below the C$62.38 price, so the market is paying for the developed reserves, all of the undeveloped and probable value and more. Reconciliation: the evaluators’ own post-sale 2P after-tax value is C$70.93/share before any bridge; this model prints C$49.92 because it runs on a US$3.00 Henry Hub rather than the evaluators’ US$3.70, at 10% real rather than their roughly 7.8%, and charges corporate G&A the reserve report leaves out — the calibration at the evaluators’ own deck and rate, +1.27%, is in the source line of Table 14. Post-period: the C$0.50 Q3 dividend (payable 29 September) is inside both the 9 September price and the 30 June balance sheet, so it is not bridged. Values computed on unrounded inputs, printed to one decimal (C$m) and two decimals (per share).

Figure 7. NAV build-up and equity bridge — the reserves carry it, corporate overhead and debt take C$2.7 billion off

Figure data: Table 16. “Producing” is the PDP and PDNP rows together (9,823.9 + 572.9); “Hedges, Topaz & other” nets the C$415.1 m hedge mark, the C$622.8 m Topaz stake and C$25.0 m of other assets against the C$231.9 m working-capital deficit. Equity NAV of C$19,517.7 m equates to C$49.92 per share.

Figure 8. NAV/share sensitivity — Henry Hub price × discount rate

		Henry Hub price (US$/MMBtu)
		2.00	2.50	Base3.00	3.50	4.00
Discount rate	8%	C$21.35	C$40.45	C$58.13	C$74.77	C$90.38
	10% (base)	C$17.16	C$34.18	C$49.92	C$64.74	C$78.64
	12%	C$13.87	C$29.18	C$43.34	C$56.66	C$69.16

Notes to Figure 8

1. Checksum — the US$2.50 column at the base rate, re-run through Table 14’s blocks: realised gas C$2.14/mcf, C$2.10 net of a 1.71% royalty; PDP 11,264.1 − (8,190.5 gas lower − 1,032.9 liquids higher) × 0.6487 × 0.7515 + 328.4 = C$8,103.0 m; PDNP C$496.5 m; PUD C$1,372.2 m; probable C$3,734.4 m; inventory 22,439 × 1.0007 × C$1.1748 × 0.05 = C$1,318.9 m; enterprise NAV C$15,025.1 m − 1,317.8 net debt + 576.3 hedge − 1,337.0 G&A − 231.9 working capital + 647.8 Topaz and other = C$13,362.5 m ÷ 391.0 m = C$34.18.
2. Rate rows — every row moves with the rate axis: each reserve category is re-struck at the row’s nominal equivalent (8% real is 10.16% nominal, 12% is 14.24%) along the evaluators’ own discount-rate disclosure, inside its published 0–20% range, so nothing is extrapolated; the inventory row, the hedge mark and the capitalised G&A re-discount with them. Nothing is held at a disclosed rate.
3. Cost — the evaluators’ operating costs +10% at the base price take NAV/share to C$46.32 (−7.2%); price +10% (Henry Hub US$3.30, WTI US$77) with a 5% cost lag delivers C$64.35 (+28.9%) against C$66.15 (+32.5%) on the price-only row — about a tenth of the leverage given back to cost.
4. FX — at C$1.5178/US$ (+10%) NAV/share is C$63.81 (+27.8%); at C$1.2418/US$ (−10%) it is C$36.16 (−27.6%), the deck and the hedge strikes moved and the Canadian-dollar costs held. Every molecule prices off a US-dollar benchmark while the cost base is local, so a stronger Canadian dollar cuts the equity; the debt is all Canadian-dollar. The financial-risk note’s own FX sensitivity sits in the audited FY2025 statements, which are not in this analysis’ source set (n/d).
5. Stage risk — n/a: no asset the model values is pre-production, and every reserve row carries a 1.00 weight. The one risked line is the unbooked inventory at 10.5% of enterprise NAV, below the 25% at which a band move is tested; at a factor of zero NAV/share is C$44.17 (−C$5.75).
6. Schedule slip — the proved-undeveloped and probable tranches, 40.8% of enterprise NAV, deferred one further year give C$47.90 (−C$2.02). The milestones that would do it are the NEBC Phase 1 plants — Aitken in Q4 2026, Groundbirch/Monias in Q4 2027 — ahead of a Phase 2 the company has already paused for a year.
7. Second deck — WTI is held at US$70/bbl in every column of this grid and of Table 24 (not co-moved; see the opening block). WTI one step down alone (US$60, Henry Hub held at US$3.00, 10%) gives C$39.38 (−C$10.54, −21.1%) — the WTI row of Table 17 and the first row of Figure 9. The part of the liquids exposure carried at a mark rather than the deck: the oil collars and sold oil calls, held at their net C$2.7 m carrying value before tax, and the Topaz stake at market (C$622.8 m), a royalty on gas and liquids alike; the oil swaps (17,255 bbl/d in 2026) are re-marked with WTI.

Figure data: this analysis’ model (Tables 14–16), every cell recomputed from the tranche blocks at that column’s price and that row’s rate, never scaled from the base cell. Price columns are the fixed Henry Hub grid, grid version 2026-09 (US$2.00–4.00); base case US$3.00 at 10% real, WTI held at US$70. A one-step (US$0.50/MMBtu) Henry Hub move out of the base shifts NAV/share by C$14.82, or 30%; the deck sensitivity is tabulated in Table 17.

Figure 9. NAV/share — Henry Hub price × WTI price, 10% real

		Henry Hub price (US$/MMBtu)
		2.00	2.50	Base3.00	3.50	4.00
WTI price (US$/bbl)	60	C$6.62	C$23.64	C$39.38	C$54.20	C$68.10
	70 (base)	C$17.16	C$34.18	C$49.92	C$64.74	C$78.64
	80	C$27.45	C$44.47	C$60.21	C$75.03	C$88.93
	90	C$37.50	C$54.52	C$70.26	C$85.08	C$98.98
	100	C$47.31	C$64.32	C$80.06	C$94.88	C$108.78

Notes to Figure 9

1. Checksum — Henry Hub US$2.50 and WTI US$60 at 10%: PDP C$7,042.2 m + PDNP 449.4 + PUD 188.7 + probable 2,468.0 + inventory 686.1 = C$10,834.4 m; − 1,317.8 net debt + 647.1 hedge − 1,337.0 G&A − 231.9 working capital + 647.8 Topaz and other = C$9,242.6 m ÷ 391.0 m = C$23.64. The US$70 row reproduces Figure 8’s base-rate row cell for cell, so the two grids agree where they meet.

Figure data: this analysis’ model, every cell recomputed at that column’s Henry Hub price and that row’s WTI price, 10% real, never scaled. Columns are the fixed Henry Hub grid and rows the fixed WTI grid, both grid version 2026-09; base case US$3.00 and US$70. The scenario columns of Table 24 run along the WTI US$70 row, because WTI is held; a reader who holds Henry Hub at US$3.50 and WTI at US$80 reads C$75.03 straight off the grid.

Deck sensitivity. The grids hold the recomputed values; this table names the value of one step of each deck so a reader can move the valuation to their own gas and oil view. Nothing here is a fitted slope — every figure is the difference between two recomputed grid prices.

Table 17. Deck sensitivity — value per US$0.50/MMBtu step of Henry Hub, out of the base price (C$/share unless stated; base rate, target multiples held, WTI held)

Source: this analysis, Tables 14–16 and 24. Per step is the step out of the base price, US$3.00 → US$3.50 Henry Hub (or US$70 → US$80 WTI); % of base is that step divided by the line’s own base-price value — a leverage read. ¹ The lines are smooth but not straight: NAV/share moves C$17.01 from US$2.00 to US$2.50, C$15.74 to US$3.00, C$14.82 to US$3.50 and C$13.90 to US$4.00, because the gas royalty is progressive and the hedge book gives back value as the price rises (C$701.5 m after tax at US$2.00, C$92.7 m at US$4.00). ² Free cash flow after all capital crosses zero at US$2.98/MMBtu, a cent below the base, so its percentage of a near-zero base is not meaningful (n/m); cash tax starts only at US$4.26, above the grid. ³ The WTI step also decays across its grid (C$10.54 from US$60 to US$70, C$9.80 from US$90 to US$100). ⁴ The scenario blend steps 11.66 → 15.29 → 15.37 → 17.18 because the discount rate, the inventory factor and the target multiples all move with the column. How to use it: start from the base-price values (NAV/share C$49.92, blended fair value C$36.67) and add or subtract the per-step figure for every US$0.50/MMBtu away from US$3.00 — a flat US$3.20 deck gives a NAV/share of about C$55.8 and a held-multiple blend of about C$40.6; for WTI alone, add C$6.07 of blend per US$10/bbl above US$70; for a reading that also moves the rate, the inventory factor and the multiples, use the scenario columns of Table 24.

P/NAV price map. Figure 8’s base-rate row multiplied by the E&P archetype’s five fixed P/NAV levels, inventory factor 0.05 and WTI US$70. It carries no weight and has no current-price column or target row; the 0.84× target from §7.3 is named beneath, and where C$62.38 sits is said once, by the market-implied deck in §7.5.

Table 18. P/NAV price map — share price implied by each P/NAV level at each grid price (C$/share, 2P-basis)

Source: this analysis, solved on Tables 14–16: each cell is the Figure 8 base-rate NAV/share at that column’s Henry Hub price (17.16 / 34.18 / 49.92 / 64.74 / 78.64) multiplied by the row’s P/NAV. The levels are the archetype’s fixed set — producers and E&Ps 0.50× to 1.50× in quarter steps — so two producers read column-for-column; Tourmaline’s 0.84× target, derived in §7.3, reads C$41.93 at the base price, between the 0.75× and 1.00× levels. Unweighted: it translates a multiple and a deck into a share price without today’s quote — parity at the base price is C$49.92, and the deck at which parity would print today’s C$62.38 is a flat US$3.42/MMBtu, while today’s price sits almost exactly on the 1.25× level at the base.

7.3 Relative valuation

At C$62.38 and 391.0 m diluted shares, market capitalisation is C$24,390 m and enterprise value C$25,940 m — the company’s net debt (debt plus the working-capital deficit, C$1,508.3 m) plus C$41.4 m of leases. Each target multiple is the archetype’s fixed anchor moved by the drivers the Section 9 scorecard has already scored; reading Tourmaline against peers’ observed multiples is the peer comparison ’s job. Forward metrics are the FY2026 guidance year at the base deck. The base deck sits 19.8% below Henry Hub’s five-year average of US$3.74 (EIA monthly spot, September 2021–August 2026), inside ±25%, so the scenarios flex the deck and the multiples together rather than normalising one side.

Table 19. Target-multiple driver line (one line, applied to every multiple)

Source: this analysis; each term is tied to one scored dimension, capped at ±10% in total, and no fact is charged under two labels. Dimensions 2 and 9 score at the archetype norm and carry no term; Dimension 4’s inventory is already priced in the NAV’s inventory row, so it is not charged again in the multiple. Dimension 8 carries a negative term against four stars, and the reason is stated: the four stars score the rule of law, while the term charges the egress-driven basis that every Western Canadian gas producer’s multiple carries and a US Gulf-priced producer’s does not. Jurisdiction is charged here, in the multiple, and not again in the discount rate. The line is printed once and reused for every multiple, so one scorecard moves every read the same way:

Target P/NAV = 0.80× anchor × (1 + 0.05) = 0.840× → 0.84× · Target EV/EBITDA = 5.0× anchor × 1.05 = 5.25× → 5.3× · Target P/CF = 4.5× anchor × 1.05 = 4.73× → 4.7×. Rounded figures are the ones used in every table below.

Table 20. Forward EBITDA build — FY2026 guidance year at the base deck

Source: this analysis; guidance per the Q2 2026 MD&A (production p.8, costs p.13–14, capital p.19); the volume mix and the realisation ratios per the Q2 2026 production and pricing tables (MD&A p.7–11); the finding-and-development cost per the FY2025 results release . “Forward” is the next twelve months = the FY2026 guidance year; the volume ties to guidance with nothing added above it. Revenue is built stream by stream — each product’s share of volume at its own realisation against its own benchmark — rather than a reported netback moved by a price slope. Check against the company: run at the 21 July strip the same build returns cash flow of C$3,533 m and free cash flow of C$983 m, against the company’s own forecast of about C$3.5 billion and C$880 million with hedges. At the current price the company trades on 9.89× this forward EBITDA, against the 5.3× target — the gap is a deck: the market prices a gas price well above US$3.00, not a premium multiple on this one.

Table 21. Relative valuation — implied value per share (base case)

Source: this analysis; anchors per the valuation guide linked in §7.1, “The valuation toolkit” (E&P producer: P/NAV 0.80×, EV/EBITDA 5.0×). The implied enterprise value crosses every claim the NAV bridge charges except corporate G&A, which EBITDA already carries; the decommissioning provision is deducted here because EBITDA carries no abandonment, and the fixed-price physical deliveries for the rest of 2026 are left out of the hedge line because the Q2-anchored realisation in Table 20 already carries them. Values computed on unrounded inputs. To run the same net asset value and the same multiples across every North American upstream producer, screen the sector on Metal Pilot.

The two reads are C$10.17 apart for a structural reason: 5.3× prices one guided year in which Tourmaline spends C$2.55 billion to hold production flat, while the net asset value prices the 25 years of 2P reserves that spending maintains — C$28.00 per share of development and inventory value, C$23.52 of it after the 0.84× target.

7.4 Further weighted methods

The third weighted read capitalises Tourmaline’s forward cash flow after interest and cash tax at the archetype’s cash-flow anchor moved by the same driver line. It is an equity multiple, so it crosses no bridge. Every input is a disclosed or derived line, and the same lines carry on into the guidance-year free-cash-flow bridge beneath it.

Table 22. P/CF support and the guidance-year free-cash-flow bridge

Source: this analysis; guidance, interest and tax per the Q2 2026 MD&A ; D&A of C$1,751.7 m is FY2025 depletion plus right-of-use depreciation (interim notes 6–7), excluding the Spirit River impairment; the tax horizon per the 2025 AIF p.21. The maintenance-capital split is not disclosed — the company guides total capital only — so it is derived from the FY2025 producing-reserve finding-and-development cost and labelled as such. The C$0.05 of free cash flow is a finding, not a rounding: at a flat US$3.00 Henry Hub the guidance year covers its capital programme and not much else, and the base dividend (about C$777 m) is paid from the balance sheet.

The method lands at C$30.90, C$11.03 below the net asset value read and C$0.86 below the EV multiple: both cash-flow reads see the same guided year, which is why this one is capped at 20% and has the shallowest step in Table 17.

7.5 Cross-checks

Every line below is reported and reconciled to the blend, and none of them carries weight. The P/NAV price map sits in §7.2 beneath the deck sensitivity, and the guidance-year cash bridge under the P/CF build in §7.4.

Table 23. Cross-checks — reported, reconciled, never weighted

Source: this analysis; the market-implied and flip prices solved on the Tables 14–22 model; Henry Hub averages and the cycle range from the U.S. EIA monthly spot series to end-August 2026; the forecast from the EIA Short-Term Energy Outlook , 9 September 2026; reserve values per the 2025 AIF p.13 and the year-end results releases (FY2022–FY2025) linked in §3; recycle ratios per the FY2025 results release ; consensus per MarketBeat , read 10 September 2026.

7.6 Scenarios & fair value

Every weighted method is re-run in every column of the Henry Hub grid, WTI held at US$70. The discount rate steps to 12% and 14% on the downside and holds at the 10% convention on the upside, since a lower rate would price a single-basin gas producer as safer than the industry does; the inventory factor moves along its band; and the target multiples flex on the standard steps, because a base deck 19.8% below the five-year average is near mid-cycle.

Table 24. Scenarios & fair value — inputs, value per method and the blend by grid price (C$/share)

Source: this analysis; weights per §7.1 (the deviation is argued there, not here); scenario names by offset from the base price. Base blend on a calculator: 0.50 × 41.93 + 0.30 × 31.76 + 0.20 × 30.90 = 20.97 + 9.53 + 6.18 = C$36.67 (on unrounded values, 36.674; the rounded contributions sum to 36.68). Inputs behind the rows, by column: inventory factor 0.03 / 0.04 / 0.05 / 0.06 / 0.07 within its band; the flexed targets 0.67× · 4.2× · 3.8× (deep bear), 0.76× · 4.8× · 4.2× (bear), 0.84× · 5.3× · 4.7× (base), 0.92× · 5.8× · 5.2× (bull) and 1.01× · 6.4× · 5.6× (deep bull); forward EBITDA C$1,356.6 m / 2,014.3 / 2,624.0 / 3,198.9 / 3,739.0; forward cash flow C$1,303.3 m / 1,961.0 / 2,570.7 / 3,145.6 / 3,685.7; the hedge mark after tax, re-marked in every column, C$701.5 m / 561.1 / 415.1 / 253.9 / 92.7, and for the EV/EBITDA leg, which leaves out the remaining 2026 physical deliveries, C$488.2 m / 395.3 / 297.0 / 184.1 / 71.1, giving claims of C$1,297.3 m / 1,390.2 / 1,488.4 / 1,601.4 / 1,714.4. WTI is held at its US$70 base in every column, as the opening block states, and liquids enter each column at their Q2 2026 realisation ratios. Adding the 3.2% forward dividend yield, the implied one-year total return at the base is −38.0% — reported, not rated. Illustrative scenarios, not forecasts.

Figure 10. Value per share by method and scenario — every method sits below the price until the deep-bull gas deck

		Scenario (Henry Hub deck, WTI held at US$70)
		Deep BearUS$2.00	BearUS$2.50	BaseUS$3.00	BullUS$3.50	Deep BullUS$4.00
Method	NAV × 0.84 (50%)	C$7.60(−82%)	C$21.68(−48%)	C$41.93(base)	C$61.29(+46%)	C$83.33(+99%)
	EV/EBITDA (30%)	C$11.39(−64%)	C$21.02(−34%)	C$31.76(base)	C$43.60(+37%)	C$56.43(+78%)
	P/CF support (20%)	C$12.53(−59%)	C$21.22(−31%)	C$30.90(base)	C$41.59(+35%)	C$53.17(+72%)
	Blended fair value	C$9.72(−73%)	C$21.39(−42%)	C$36.67(base)	C$52.05(+42%)	C$69.23(+89%)

Source: this analysis; each cell recomputed at its column’s deck, rate, inventory factor and multiples (Table 24); data-level ranked 0–9 across the whole grid. The net asset value carries much the steepest leverage — it is the only method that prices the undeveloped and probable reserves, and on a gas deck below the evaluators’ those reserves lose value fastest — while the cash-flow reads compress; that is why the NAV anchors the blend and the P/CF support is capped. Current share price C$62.38 (9 September 2026); market-implied deck a flat US$4.38/MMBtu Henry Hub. The bracketed figure under each value is its change against the same row’s base-case value.

Conclusion. The blended base-case fair value is C$36.67, inside a C$9.72 (Deep Bear, US$2.00) – C$69.23 (Deep Bull, US$4.00) range, against a C$62.38 price — an implied −41.2%, Overvalued, published as Overvalued (wide band) because the Deep Bear blend sits 84% below the price. At the base deck the guidance-year free cash flow is C$20.7 m after the whole C$2.55 bn programme — C$0.05/share, a 0.1% free-cash-flow yield. Rating-flip prices: the read is already the bottom band, so there is no downward flip; the base blend crosses up into Modestly overvalued above a flat US$3.35/MMBtu Henry Hub (+11.7% from the base price) and into Fairly valued above US$4.02 (+34.0%). The one assumption that drives the downside is a gas price that stays near or below US$2.50 while the NEBC build is still absorbing capital — a world in which the guidance year burns C$590 m after the programme. The three methods span C$11.03 at the base: the two multiples see one guided year of a C$2.55 billion programme, and the net asset value sits above both because it counts the reserves that programme maintains. The framing that matters is the tiers and the implied deck together: the producing reserves plus the whole bridge are worth C$21.93/share, the market pays C$62.38, so C$40.45 of the price is a bet on C$28.00 of undeveloped, probable and unbooked value — value this model prices at a flat US$3.00 Henry Hub and the market at a flat US$4.38. That is a defensible view for a company whose international contract book grows to 333,000 mmbtu/d by 2028; it is simply not this section’s.

Table 25. Assumptions and data gaps

Source: this analysis, §7.1–§7.6. The box is rendered as a table rather than a paragraph because the gap register would otherwise run past the length at which it stops being scannable. It is in addition to the AI-assistance and not-investment-advice disclosure in §10.2.

8. Near-term catalysts (1–3 years)

Table 26. Near-term catalysts

Source: Tourmaline 2025 AIF p.4–6 (ethane, Trafigura, Uniper); the Q2 2026 results release and MD&A (NEBC schedule, 2027–2028 capital and free cash flow, storage). Timing is company guidance, not a guarantee, and the fee savings and free-cash-flow figures are the company’s own estimates at the strip.

Three of these are contracted rather than hoped for: the ethane savings are quantified, and the Trafigura and Uniper contracts are signed and priced off benchmarks that do not clear through AECO — shifting the realised price away from the landlocked benchmark §6 names as the thesis risk. The swing factor is the NEBC build: plants on schedule and a pause that holds would turn the 2027–28 free-cash-flow plan into reported numbers, moving both the capital-allocation star and the value read.

9. Rating & verdict

Table 27. Scorecard rationale

Σ(weight × score), in the table’s published order = 0.60 + 0.45 + 0.60 + 0.75 + 0.30 + 0.25 + 0.25 + 0.25 + 0.19 = 3.64/5 → ★★★½.

Composite: ★★★½, Solid. Source: Table 27 — the producer archetype’s five dominant dimensions at 15% and four at 6.25%, rounded to the nearest half-star per the Metal Pilot Company Scorecard and scored against the §2.7 peer set; the # column keeps each dimension’s reference number, rows in weight order.

Value read: Overvalued (wide band), as of 10 September 2026 (§7). Two-axis verdict: Solid quality × Overvalued → “Full — the market already sees it.” The base-case blend of C$36.67 sits 41.2% below the C$62.38 price, on a 2P-basis net asset value of C$49.92 per share (C$21.93 producing, C$22.25 development, C$5.75 resource), and the reason is a gas price rather than a defect: the shares imply a flat Henry Hub of about US$4.38/MMBtu against this analysis’ US$3.00 base, and the read flips up to Modestly overvalued only above US$3.35. The “(wide band)” qualifier is there because a US$2.00 gas world would take the blend 84% below today’s quote.

The scorecard is barbelled, and that is the finding: the balance sheet is the best in the peer set at ★★★★★, five dimensions hold ★★★★, and capital allocation sits at ★★ because distributions ran ahead of free cash flow and the share count grew about as fast as production. Cost and ESG at ★★★ are the norm for a Western Canadian gas producer rather than a weakness peculiar to this one. That is why the composite lands at 3.64 rather than the 4-plus the raw materials might support.

The bull case is that 2027 shows the machine: Phase 1 finished, capital stepping down, the ethane fees gone, the Trafigura contract live and more than C$1 billion of free cash flow at the strip. The bear case is that the market has already paid for that: at a flat US$3.00 Henry Hub the guidance year covers its capital programme with C$20.7 m to spare, the dividend comes from the balance sheet, and the Spirit River sale — the only arm’s-length price for these barrels in the file — values the reserve base at C$36.71 a share. What tips it is the gas price, and then the cash; the §8 catalysts are the things to watch. To rank Tourmaline against every North American upstream producer on these same nine dimensions, screen the sector on Metal Pilot.

10. Sources, methodology & disclaimer

10.1 Sources, methodology & data vintage

Company filings. Tourmaline Oil Corp. Annual Information Form for the year ended 31 December 2025 , dated 4 March 2026 — reserves and after-tax NPVs by category, the evaluators’ forecast prices and costs, future development capital, production history by area and province, drilling locations, the corporate history, directors and officers, dividends and risk factors; the consolidated reserve report of GLJ Ltd. (93.4% of 2P) with Deloitte LLP evaluating the Spirit River and other properties is incorporated in it. Q2 2026 MD&A and unaudited interim condensed consolidated financial statements (30 June 2026, dated 29 July 2026) — production, realised prices and royalties by product, guidance, the balance sheet, the risk-management note, decommissioning, debt, the Aduro acquisition, the Spirit River disposition and share capital. Full-year results releases for 2021 , 2022 , 2023 , 2024 and 2025 (4 March 2026); the Q2 2026 results release (29 July 2026); the 8 September 2026 early-warning report on the Topaz holding.

Market & price data. TOU close of C$62.38 and TPZ close of C$31.25 on 9 September 2026 (Google Finance ); CAD/USD C$1.3798, Bank of Canada daily average, 9 September 2026; Henry Hub and WTI monthly spot series, January 2017–August 2026, from the U.S. Energy Information Administration (the WTI series ); the EIA Short-Term Energy Outlook of 9 September 2026; analyst consensus per MarketBeat , read 10 September 2026.

Peer set and cross-links. The five US peers are analysed on this identical scorecard: EQT , Expand Energy , Antero Resources , Range Resources and CNX Resources ; the US names side by side in US Upstream Natural Gas Producers Compared ; the other side of the royalty relationship in the Topaz Energy analysis .

Methodology note. Archetype: E&P producer (oil & gas), all nine scorecard dimensions applied, scored against the peer set in §2.7. Reserve standard NI 51-101, forecast prices and costs, Company Gross — not the SEC constant-price standard the US peers file under, which every side-by-side table says. Units: Tourmaline’s boe at 6 mcf : 1 bbl, with bcfe and mcfe for peer comparisons; the 6 : 1 convention overstates a gas boe against an oil boe at today’s price ratio, which is why the reserve anchor is set aside in §7.1. Royalties are deducted from price in the unit economics so a Canadian gross-revenue filer compares with US net-revenue-interest filers. The valuation’s inputs, weights and gaps are set out in Table 25; the arithmetic behind every published figure is kept as a runnable model beside this post and re-executed on each revision. Figures: every figure is an inline HTML/CSS component; a proportional-symbol map of the two core areas is omitted because the component library does not render it legibly at this scale, and Table 2 carries the footprint. Where the source set and a data provider conflicted, the filing was used.

Documents to add before the next run. The FY2025 audited consolidated financial statements and annual MD&A (FX sensitivity, FY2025 interest and cash tax) and the current corporate presentation (maintenance-capital split, contract schedule) are outside this run’s source set (Table 25, field 11); a category split of the Spirit River reserves would close the pro-rata removal.

Re-run log. 10 September 2026 — full refresh to the 9 September 2026 close, the Q2 2026 interim filings and the current template: Section 7 rebuilt on a Henry Hub US$3.00 grid with WTI as a held second deck and a 10% real rate; FY2025 depletion restated to C$1.75 billion (C$7.52/boe) excluding the C$1.2 billion Spirit River impairment, which lifts the fully-loaded margin to US$0.92/mcfe; net debt and the five-year table re-sourced to company filings; an impairment-distorted return on invested capital withdrawn; the MiQ Grade “A” certification, the 12.87% Topaz stake and the AIF’s 5.3% insider ownership added. Net effect: composite 3.70 → 3.64 (★★★½ unchanged); read Modestly overvalued → Overvalued (wide band). 15 September 2026 — pre-launch verification against the source set: filing page references aligned to one pagination, the two 2026 Topaz-funded acquisitions and the cost-reduction target corrected to their disclosures, the EV/EBITDA leg’s hedge series printed beside Table 24, prose tightened; no model input changed. Net effect: none — NAV/share C$49.92, base blend C$36.67, implied return −41.2%, read Overvalued (wide band), on 391.0 m diluted shares at the C$62.38 close. Data as of 10 September 2026, on the 9 September close. Update cadence: refreshed on each annual report, each quarterly report and on material events (the Q3 2026 report, a NEBC plant commissioning, a change in the capital plan or the dividend). Provenance: Tourmaline Oil Corp. — Annual Information Form — 2025; Tourmaline Oil Corp. — Quarterly Report — Q2 2026.

10.2 Disclaimer & disclosure

This analysis is for informational purposes only and is not investment advice; it does not account for any individual’s circumstances, and readers should do their own research or consult a licensed financial adviser. It is a point-in-time snapshot as of 10 September 2026: prices, multiples and the valuation read move, and reserve, production and net-asset-value figures are estimates — NI 51-101 reserves on forecast prices do not represent market value, and probable reserves are less certain than proved. The scorecard and verdict are an analytical read, not a personal buy or sell instruction. Prepared with AI assistance (Claude Opus 5) under human editorial direction; the author holds no position in Tourmaline Oil Corp. or any peer-set company at publication. Metal Pilot is a research tool, not a financial adviser.