This news release contains certain specified financial measures that are not recognized by GAAP and used by management to evaluate the performance of the Company and its business. Since certain specified financial measures may not have a standardized meaning, securities regulations require that specified financial measures are clearly defined, qualified and, where required, reconciled with their nearest GAAP measure. See "Non-GAAP and Other Financial and Reserves Measures" in this news release and in the MD&A for further information on the definition, calculation and reconciliation of these measures and certain reserves measures. This news release also contains forward-looking information. See "Forward-Looking Information". Readers are also referred to the other information under the "Advisories" section in this news release for additional information.
FOURTH QUARTER AND ANNUAL 2025 OPERATIONAL AND FINANCIAL HIGHLIGHTS
Sales Production Volumes
Heavy oil: Averaged 8,295 bbl/d in the fourth quarter of 2025, up 7% from 7,754 bbl/d in the fourth quarter of 2024. Achieved record annual heavy oil sales production of 8,402 bbl/d, up 48% from 5,685 bbl/d in 2024 and above guidance of 8,325 to 8,400 bbl/d.
Total sales production: Delivered record fourth quarter average sales production of 13,042 boe/d (67% heavy oil and natural gas liquids ("NGL")), up 26% from 10,386 boe/d (77% heavy oil and NGL) in the fourth quarter of 2024, and record annual sales production of 12,494 boe/d (70% heavy oil and NGL), up 97% from 6,349 boe/d (91% heavy oil and NGL) in 2024 and exceeding guidance of 12,325 to 12,400 boe/d.
Heavy oil new wells: Brought 14 (12.5 net) heavy oil wells onstream at Figure Lake and Frog Lake in the fourth quarter, for a total of 46 (39.0 net) new heavy oil wells contributing to sales in 2025.
West Central natural gas new wells: Added 2 (1.0 net) liquids-rich conventional natural gas wells to production at East Edson at the end of the third quarter and 2 (1.0 net) additional wells late in the fourth quarter of 2025.
Figure Lake gas plant: With the initial facility start up in January and subsequent expansion in the second half of 2025, natural gas sales averaged 5.6 MMcf/d in the fourth quarter and 3.4 MMcf/d in 2025.
Capital Expenditures
Exploration and development spending(1): Spent $34.8 million in the fourth quarter and $114.6 million for 2025, at the high end of the guided range of $110.0 to $115.0 million. Fourth quarter spending included the drilling, completion, equipping and tie-in of 6 (6.0 net) multi-lateral horizontal Clearwater development wells and 1 (1.0 net) multi-lateral horizontal Sparky well at Figure Lake; 4 (3.0 net) multi-lateral horizontal Waseca development wells and 3 (2.5 net) single leg horizontal wells in new zones at Frog Lake; and 2 (1.0 net) liquids-rich conventional natural gas wells at East Edson, bringing total 2025 drilling activity to 53 (43.8 net) wells.
Figure Lake gas plant: Spent $0.7 million in the fourth quarter and $4.1 million in 2025 to finish initial construction and expand the gas plant and gas gathering system at Figure Lake, bringing processing capacity to 6.4 MMcf/d by the fourth quarter of 2025.
Land: Spent $0.3 million in the fourth quarter, bringing total land costs to $10.5 million in 2025. In the fourth quarter, the Company sold 7 sections of undeveloped land, subject to a retained gross overriding royalty, for $2.3 million, bringing total proceeds from the disposition of non-producing acreage in 2025 to $7.8 million, which funded other capital activities.
Geological and geophysical costs: Spent $3.8 million in the fourth quarter and $4.9 million in 2025 to shoot new 3D seismic and acquire trade data to support the development of the Clearwater and other Mannville Stack prospects, including the evaluation of new zones.
Abandonment and Reclamation: Spent $0.6 million in the fourth quarter and $1.9 million in 2025 on decommissioning, abandonment and reclamation activities and received seven reclamation certificates from the Alberta Energy Regulator ("AER") (2024 - one), with two additional reclamation certificates received subsequent to year-end.
Financial Performance
Adjusted funds flow(1):
$33.2 million ($0.35 per share) in the fourth quarter of 2025, up 5% from $31.6 million ($0.36 per share) in the fourth quarter of 2024.
$142.1 million ($1.52 per share) in 2025, up 52% (12% per share) from 2024 driven by a 97% increase in sales volumes and 20% lower cash costs, partially offset by a 10% decrease in average realized prices.
Cash costs(1):
$18.5 million or $15.41/boe in the fourth quarter of 2025, 21% lower on a per boe basis than the fourth quarter of 2024 (Q4 2024 - $18.6 million or $19.45/boe).
$78.6 million or $17.24/boe in 2025, 20% lower on a per boe basis than 2024 (2024 - $50.4 million or $21.68/boe).
Net income:
$9.7 million ($0.10 per share) in fourth quarter of 2025 (Q4 2024 - $26.7 million net income or $0.31 per share).
$32.6 million ($0.35 per share) in 2025 (2024 - $50.0 million or $0.73 per share).
Balance Sheet and Liquidity
Net debt(1): $143.1 million at December 31, 2025, down 7% from $154.0 million at December 31, 2024, driven by $11.6 million of positive free funds flow(1) used to reduce net debt and other obligations.
Available liquidity(2): $46.0 million at December 31, 2025, based on a $140.0 million first-lien credit facility borrowing limit, less $92.6 million of bank borrowings and $1.4 million in letters of credit.
(1)
Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial and Reserves Measures" in this news release.
(2)
See "Liquidity, Capitalization and Financial Resources - Capital Management" in the MD&A.
2025 GUIDANCE RECONCILIATION
During 2025, Rubellite recorded strong growth from a successful drilling program, which saw both heavy oil and total sales production exceed the high end of the 2025 guidance range. A comparison of the Company's most recent 2025 guidance metrics to actual results is provided below.
2025 Guidance(1)
2025 Actuals
Sales Production (boe/d)
12,325 - 12,400
12,494
Production mix (% liquids)(2)
70 %
70 %
Heavy oil sales production (bbl/d)
8,325 - 8,400
8,402
Exploration and development spending ($ millions)(3)(4)
$110 - $115
$114.6
Heavy oil wellhead differential ($/bbl)(3)
$3.75 - $4.00
$3.76
Royalties (% of revenue)(3)
13% - 14%
13 %
Production and operating costs ($/boe)(3)
$6.50 - $7.00
$6.48
Transportation costs ($/boe)(3)
$5.25 - $5.50
$5.18
General and administrative costs ($/boe)(3)
$3.00 - $3.50
$3.48
(1)
2025 guidance dated November 5, 2025.
(2)
Liquids means oil, condensate, ethane, propane and butane.
(3)
Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial and Reserves Measures".
(4)
Excludes abandonment and reclamation spending, land and acquisitions and geological expenditures, if any.
OPERATIONS UPDATE
Figure Lake
Rubellite drilled and rig released 4 (4.0 net) Clearwater development horizontal wells targeting the Wabiskaw Member of the Clearwater Formation in the fourth quarter, using the optimized 33 meter inter-leg spacing and 15,000 meters open hole length, bringing the 2025 total to 15 (15.0 net) development wells drilled with this design. Initial well performance continues to exceed expectations, with average(1) IP30/60 rates of 205 bbl/d (15 wells)/192 bbl/d (14 wells), as compared to the 2025 McDaniel Tier 1 type curve(2) IP30/60 of 201/193 bbl/d(2), which was revised up from the 2024 McDaniel Tier 1 type curve(2) IP30/60 of 177/169 bbl/d.
A waterflood pilot was also advanced in the fourth quarter, with an 8‑leg horizontal multi‑lateral producer and a dedicated 1‑leg injection well drilled from the 9-35-63-18W4 Pad (the '9-35 Pad'). Each 4-leg set was drilled with 33 meter inter-leg spacing with a total open hole length for the 8 legs of approximately 8,500 meters. Water injection began in early March.
The Company continued its natural‑gas re-injection pilot at the 01-13-063-18W4 pad (the '1-13 Pad'), on the same site as the Figure Lake 1-13 Gas Plant. The pilot injected ~25 MMcf into an existing multi‑lateral well to confirm injectivity, followed by controlled flow back ahead of a second injection cycle planned for early 2026.
A well targeting the Sparky Formation (1.0 net) drilled in the fourth quarter is delivering encouraging results, with an IP30 rate of 286 bbl/d and water cuts below 10%. The well has 6 legs and approximately 7,750 meters of horizontal length. Follow up development on this discovery, and continuous production of the initial well, will require the construction of a permanent all season access road and expansion of the pad which is planned for second half 2026. The well will be shut in during spring breakup and will require interim temporary infrastructure to allow for production from the well to restart late in Q2 2026.
Subsequent to the end of the year, a single rig drilling program is continuing at the 8-26-61-16W4 pad (the '8-26 Pad') following up two successful step-out delineation wells drilled in 2024. During the first quarter of 2026, a total of 4 (4.0 net) primary producers, 1 (1.0 net) waterflood pilot producer and 1 (1.0 net) injector pair are expected to be drilled at the 8-26 Pad. A polymer producer and injector pilot pair is also planned for the 8-26 Pad, which are scheduled to drill over quarter end. Results to date on the 8-26 Pad have been positive, with the first well drilled recording an IP30 of 286 bbl/d and the second drill recording an IP15 of 335 bbl/d in the early stages of production.
In addition, two multi-lateral horizontal producer-to-injector conversions on two separate pads are also planned for the first quarter of 2026 to evaluate the impact of waterflood where historical production has occurred through primary multi-lateral drilling development. Learnings regarding the performance of the multiple Enhanced Oil Recovery ("EOR") pilot schemes being evaluated will inform future development plans.
Frog Lake
Rubellite drilled and rig released 7 (5.5 net) wells during the fourth quarter, which included 4 (3.0 net) Waseca South wells, 2 (1.5 net) General Petroleum ("GP") wells and 1 (1.0 net) Sparky well. The Waseca drilling program for 2025 on average slightly exceeded McDaniel type curve(2) assumptions as per the below:
Waseca North program: 14 (10.0 net) wells achieved average IP30/IP60 rates of 133/112 bbl/d, as compared to the 2025 McDaniel type curve(2) of 122/117 bbl/d and the 2024 McDaniel type curve(2) of 107/104 bbl/d
Waseca South program: 7 (5.5 net) wells achieved average IP30/IP60 rates of 153/145 bbl/d, as compared to the 2025 McDaniel type curve(2) of 145/145 bbl/d and the 2024 McDaniel type curve(2) of 150/150 bbl/d.
Four (3.0 net) GP wells were drilled using both single‑leg and fishbone designs. All the wells were equipped with recycle strings to aid in the recovery of solids and sand from the horizontal section of the wells with the exception of an unlined fishbone well. Early IP30(1) performance across the completed wells ranged between 44–134 bbl/d, averaging 78 bbl/d. The McDaniel year-end 2025 type curve(2) for GP has an IP30/IP60 of 73/72 bbl/d. The Company is encouraged by the early performance of the GP wells and nearby offset activity, and continues to optimize well design for future development.
One (1.0 net) Sparky well was drilled but encountered lost circulation after ~40 meters of horizontal lateral length and drilling was suspended. After obtaining a bottom hole pressure, the well was equipped for an extended test period.
Approximately 26 km2 of new 3D seismic was acquired in the fourth quarter of 2025 and into the first quarter of 2026 to support future drilling plans at Frog Lake. The 3D seismic shoot was originally planned for first quarter of 2026, but was accelerated into fourth quarter due to crew availability.
Rubellite continued its drilling program at Frog Lake over year-end and into the first quarter of 2026, completed the program, and then paused drilling activity in early February to allow the rig, which has been operating continuously for several years, to be serviced and recertified over the next several months. The recess is expected to be approximately 90 days and will: (1) allow Rubellite to observe performance from the recent secondary zone wells; (2) evaluate well design and operational learnings in these early stages of delineation of the GP and Sparky zones; and (3) understand partner elections for participation in the drilling program planned at Frog Lake in mid-2026.
East Edson
Net production at East Edson was 3,802 boe/d (11% liquids) for the fourth quarter and averaged 3,517 boe/d (10% liquids) in 2025, as 2 (1.0 net) wells drilled at the end of third quarter and two (1.0 net) wells drilled in the fourth quarter were fracked and placed on production. Subsequent to the reporting period, 2 (1.0 net) additional wells were rig released, completed, equipped and tied-in with a portion of capital spending and activity occurring in the fourth quarter of 2025.
Other Exploration
In addition to activity in the GP and Sparky zones at Frog Lake and the Sparky zone at Figure Lake, Rubellite continued advancing multiple new venture exploration prospects, including land capture and play concept de-risking initiatives while minimizing risked capital exposure.
(1)
No development wells were excluded from the calculation of average results except by the criteria for producing days.
(2)
Type curve assumptions are based on the total proved plus probable undeveloped reserves contained in the McDaniel Report as disclosed in the AIF available under the Company's profile on SEDAR+ at www.sedarplus.ca. Year-end 2024 McDaniel Figure Lake Tier 1 Type Curve type curve of 177 bbl/d (IP30) and 169 bbl/d (IP60) based on the reserves contained in the 2024 McDaniel Report, as disclosed in the Company''s 2024 AIF. "McDaniel Report" means the independent engineering evaluation of the heavy crude oil and conventional natural gas and NGL reserves, prepared by McDaniel with an effective date of December 31, 2025 and a preparation date of March 10, 2026.
OUTLOOK AND GUIDANCE
For the first quarter of 2026, Rubellite is forecasting a total of $30 to $32 million in exploration and development spending(1). In addition to development drilling in its core operating areas, capital spending in Q1 2026 will support longer term strategic initiatives including: (1) advancing multiple EOR pilots in the Clearwater, with water injection at six waterflood pilots expected to have been initiated by mid-2026; (2) the producer-injector pair drilled for a polymer flood pilot planned to begin injection in Q4 2026; (3) additional injection/production cycles in the novel gas injection EOR pilot at Figure Lake; and (4) ongoing exploration activities.
First quarter capital projects in the Company's core properties include:
At Figure Lake:
Drilling and completion of 4 (4.0 net) 15,000m, 12 leg, Clearwater development wells on the 8-26 Pad;
Drilling and completion of 1 (1.0 net) 10,000m, 8 leg, waterflood pilot producer-injector pair on the 8-26 Pad;
Drilling of 1 (1.0 net) 10,000m, 8 leg, polymer flood pilot producer-injector pair on the 8-26 Pad, the producer is expected to be drilled over quarter end and included in the Q2 2026 well count and the injector drilled in Q2 2026;
Completion and initiation of water injection at the 9-35 Pad waterflood pilot producer-injector pair drilled in Q4 2025;
Conversion of up to two existing mature multi-lateral producers to waterflood injectors; and
Additional core testing to continue to inform EOR initiatives.
At Ukalta:
Conversion of an existing mature multi-lateral producer to waterflood injector with water injection expected to begin in Q2 2026.
At Frog Lake:
Drilling and completion of 3 (2.5 net) South Waseca wells; and
Spending to finish shooting and processing the 3D seismic survey initiated in Q4 2025 to assist in positioning wells in the geologically complex Mannville Stack targets.
At East Edson:
Participation in the drilling, completion, equipping and tie-in of 2 (1.0 net) Wilrich development wells initiated in late 2025.
In addition, first quarter 2026 spending will include capital to drill 1 (1.0 net) exploration well on a new venture prospect.
Factoring in the positive initial performance from the fourth quarter of 2025 and first quarter of 2026 drilling program to date, heavy oil sales volumes are expected to average between 8,300 to 8,400 bbl/d in the first quarter of 2026, while total production sales volumes, including natural gas and NGL volumes at East Edson and Figure Lake, are forecast to average 13,300 to 13,400 boe/d in the first quarter of 2026, for growth of approximately 2% relative to the fourth quarter of 2025.
Rubellite will closely monitor the production performance of the recent drilling program and anticipates providing full year guidance with the issuance of its Q1 2026 results in May.
Capital spending activity is expected to be funded from adjusted funds flow(1), with any excess free funds flow(1) used to reduce net debt(1) and for other balance sheet obligations.
Initiatives to improve field operating costs and reduce transportation costs in Rubellite's Clearwater and Mannville Stack production will continue to keep operating costs low at $6.50 to $7.25/boe guided for the first quarter of 2026 and transportation costs are expected to be in the $4.50 to $5.00/boe range. Blending demand for Clearwater and Mannville Stack heavy oil is expected to continue to translate into attractive offsets to WCS benchmark pricing, resulting in heavy oil wellhead differential guidance in the range of $3.50 to $4.00 per bbl.
Rubellite will continue to address end of life asset retirement obligations ("ARO"), with total abandonment and reclamation expenditures of approximately $0.8 million planned for the first quarter of 2026 to progress its AER area-based mandatory spending requirement for 2026 of $1.4 million.
(1) Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial and Reserves Measures".
Planned exploration and development spending and drilling activity for the first quarter of 2026 is summarized in the table below:
Q1 2026
Exploration and Development Spending
($ millions)(2)
# of wells
(gross/net)
Figure Lake(1)
6 / 6.0
Frog Lake
3 / 2.5
Marten Hills
-/-
East Edson
2 / 1.0
Exploration
1 / 1.0
Total
$30 - $32
12 /10.5
(1) Includes one waterflood injection well.
(2) Excludes abandonment and reclamation spending, acquisitions and land and geological expenditures, if any.
Rubellite's financial and operational guidance for the first quarter of 2026 is presented in the table below:
Q1 2026 Guidance
Sales Production (boe/d)
13,300 - 13,400
Production mix (% oil and liquids)(1)
67 %
Heavy Oil Production (bbl/d)
8,300 - 8,400
Exploration and Development spending ($ millions)(2)(3)
$30 - $32
Heavy oil wellhead differential ($/bbl)(2)
$3.50 - $4.00
Royalties (% of revenue)(2)
13% - 14%
Production and operating costs ($/boe)(2)
$6.50 - $7.25
Transportation costs ($/boe)(2)
$4.50 - $5.00
General and administrative costs ($/boe)(2)
$3.00 - $3.50
(1)
Liquids means oil, condensate, ethane, propane and butane.
(2)
Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial and Reserves Measures".
(3)
Excludes abandonment and reclamation, land, geological and acquisition expenditures, if any.
YEAR-END 2025 RESERVES HIGHLIGHTS
As presented in the McDaniel Report(1), Rubellite's total proved plus probable reserves(1) at year-end 2025 were 53.1 MMboe, comprised of 55% heavy crude oil (2024 year-end total proved plus probable reserves were 53.0 MMboe, 51% heavy crude oil). The Company's total proved plus probable reserves grew by 0.1 MMboe (0.1%) year-over-year, resulting in production replacement(4) of 4.6 MMboe by 1 times.
Growth in reserves is attributed to the successful drilling programs at Figure Lake and Frog Lake which combined to add 6.1 MMboe to the year-end proved plus probable reserves balance. This organic growth through the drill bit in the Clearwater, Sparky, Waseca and GP plays accounted for all additions of 6.1 MMboe, and resulted in production replacement(4) from the Company's heavy oil properties of 3.3 MMboe by 1.9 times.
Other highlights from the McDaniel Report(1) include:
Total proved reserves increased 0.5% (0.2 MMboe) to 32.9 MMboe from 32.7 MMboe and representing 62% of the Company's proved plus probable reserves (2024, 62%).
Proved developed producing reserves were 18.1 MMboe, an increase of 2% and representing 34% of the Company's proved plus probable reserves (2024 year-end proved developed producing reserves were 17.7 MMboe; 33% of total proved plus probable reserves).
Proved plus probable developed producing reserves were 23.3 MMboe, representing 44% of total proved plus probable reserves (2024 year-end proved plus probable developed producing 23.0 MMboe; 43% of proved plus probable reserves).
Rubellite's total capital expenditures(4) of $130.0 million (which excludes $0.5 million of corporate capital) resulted in total proved plus probable additions of 4.6 MMboe and included a change in future development capital of $21.2 million. The reserve additions resulted in finding and development ("F&D") costs(4) of $32.73/boe. Higher than normal cost of reserve additions were observed this year due to a negative technical revision in the Edson Joint Venture property, which offset the positive additions in the heavy oil properties. Rubellite had cash proceeds from dispositions of undeveloped land of $7.8 million which had no reserves assigned prior to the disposition.
At the Eastern Heavy Oil cash generating unit ("CGU") level, exploration and development expenditures(4) totalled $100.5 million, land expenditures of $10.5 million, after adjusting for the $7.8 million of cash proceeds related to the sale of land with no reserves assigned or net book value, geological and geophysical spending was $4.9 million, and the change in future development capital for Rubellite's heavy oil assets was $36.4 million. With heavy oil reserve additions of 6.3 MMboe, the Adjusted Heavy Oil F&D costs per boe(4) on a 2P basis were $22.93/boe with a recycle ratio(4) of 2.0, based on a 2025 heavy oil operating netback(4) of $45.15/boe. For more details see section "Adjusted F&D Ratios".
The McDaniel Report includes a total of 214 (167.2 net) booked undeveloped drilling locations, which are comprised of 139 (109.2 net) proved undeveloped and 75 (58.0 net) probable undeveloped locations. Of these, 111 (109.7 net) are in the Figure Lake area with 72 (71.1 net) that are proved undeveloped and 39 (38.6 net) probable undeveloped.
Continued drilling success in 2025 in the Figure Lake property resulted in outperformance, in aggregate, relative to the 2024 type curves. In the McDaniel Report, IP30 rates were increased on Figure Lake Tier 1 and Tier 2 type curves to 201 bbl/d (2024 - 177 bbl/d) and 144 bbl/d (2024 - 120 bbl/d), respectively. In the Edwand sub-area of Figure Lake, which has it's own type curves, IP30 rates were also increased to 191 bbl/d (2024 - 175 bbl/d), as were proved plus probable estimated ultimate recoverable ("EUR") volumes to 125 Mboe per well (2024 - 115 Mboe per well).
At Frog Lake, success in drilling, and executing well operational strategies to deal with sand production, resulted in both developed producing and undeveloped reserve adds in the GP formation. Four (3.0 net) GP wells were drilled in 2025 with developed producing reserves, with an additional 17 (8.5 net) booked undeveloped locations. Of these undeveloped locations, 7 (3.5 net) are proved undeveloped and 10 (5.0 net) are probable undeveloped. In the McDaniel Report, the GP type curve has an IP30 rate of 73 bbl/d and proved plus probable reserves of 85 Mboe.
All abandonment, decommissioning and reclamation obligations are included in the McDaniel Report, consistent with year-end 2024. Decommissioning obligations for wells assigned reserves are forecast to occur at end of life while the additional costs expected to be incurred to abandon and reclaim non-reserve wells, facilities and pipelines are forecast in accordance with regulatory asset retirement obligation spending requirements for inactive wells.
Rubellite's undeveloped land was independently assessed in the Seaton-Jordan Report(3), at $59.6 million, an increase of 22% from $48.8 million.
Based on the three consultant average price (McDaniel, GLJ Ltd., Sproule Associates Limited) forecasts (the "Consultant Average Price Forecast") used by McDaniel, the net present value ("NPV") of Rubellite's total proved plus probable reserves (discounted at 10%) before income tax, was $651.5 million (2024, $721.5 million). The 10% NPV10 decrease from year-end 2024 is related directly to the reduction in commodity price forecasts based on the Consultant Average Price Forecast, and to a lesser degree, the negative technical revisions in the Edson Joint Venture property, offset by positive reserve revisions and additions in the Company's heavy oil properties.
Based on the Consultant Average Price Forecast, Rubellite's reserve-based net asset value ("NAV")(4) (discounted at 10%) at year-end 2025, is estimated at $556.6 million ($5.95 per share) as compared to $601.1 million ($6.47 per share) at year-end 2024. The reserve-based NAV is inclusive of the independent assessment of undeveloped land and net of the Company's total net debt(4) and other obligations(4), which includes $143.1 million of net debt and $16.2 million for the undiscounted amount of the other provision(4).
(1)
"McDaniel Report" means the independent engineering evaluation of the Company's heavy crude oil, conventional natural gas and NGL reserves, prepared by McDaniel with an effective date of December 31, 2025 and a preparation date of March 10, 2026.
(2)
Type curve assumptions are based on the total proved plus probable Undeveloped reserves contained in the McDaniel Report as disclosed in the Company's AIF which will be available under the Company's profile on SEDAR+ at www.sedarplus.ca.
(3)
The value of Rubellite's undeveloped land was assessed by an independent third party, Seaton-Jordan & Associates Ltd., as at December 31, 2025 in a report dated January 26, 2026 (the "Seaton-Jordan Report"). Estimates of the value of Rubellite's undeveloped acreage was prepared in accordance with NI 51-101 5.9(1)(e) for purposes of the net asset value calculation and is based on past Crown land sale activity, adjusted for tenure and other considerations. No undeveloped land value is assigned where reserves have already been booked, even if the corresponding lease contains multiple prospective formations that have not yet been assigned reserves .
(4)
Non-GAAP financial measure or non-GAAP ratio. See "Non-GAAP and Other Financial and Reserves Measures" in this news release.
YEAR-END 2025 RESERVES DATA
The following presentation summarizes the Company's crude oil, natural gas liquids and conventional natural gas reserves and the net present values before income tax of future net revenue for the Company's reserves using the forecast prices and costs reflected in the McDaniel Report. The McDaniel Report has been prepared in accordance with definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). McDaniel prepared the McDaniel Report using their own technical assumptions and interpretations, methodologies and cost assumptions and the equal weighting of the Consultant Average Price Forecast as outlined in the table below entitled "Price Forecast". See "Reserves Data and Industry Metrics" for additional cautionary language, explanations and discussion and "Forward-Looking Information" for principal assumptions and risks that may apply.
Corporate Reserves
Light & MediumCrude Oil
Natural GasLiquids
ConventionalNatural Gas
Barrels of oilequivalent
(Mbbl)
(Mbbl)
(MMcf)
(Mboe)
Proved
Developed Producing
8,485
878
52,212
18,065
Developed Non-producing
48
14
742
185
Undeveloped
9,078
548
29,954
14,619
Total Proved ("1P")(1)
17,610
1,441
82,907
32,869
Total Probable
11,608
826
46,596
20,199
Total Proved plus Probable ("2P")(1)
29,218
2,266
129,504
53,068
(1) May not add due to rounding.
Reserves Value
The estimated before tax net present value ("NPV") of future net revenues associated with Rubellite's reserves effective December 31, 2025, and based on the McDaniel Report and the Consultant Average Price Forecast, are summarized in the following table:
($ thousands)
0 %
5 %
10 %
15 %
20 %
Proved
Developed Producing
318,180
297,581
268,892
244,180
224,027
Developed Non-producing
3,844
3,233
2,775
2,434
2,171
Undeveloped
231,446
163,672
116,809
83,536
59,265
Total Proved(1)
553,471
464,485
388,476
330,150
285,463
Total Probable
519,985
360,275
263,019
200,268
157,698
Total Proved plus Probable(1)
1,073,455
824,760
651,496
530,418
443,160
(1) May not add due to rounding.
Price Forecast
The Consultant Average Price Forecast December 31, 2025 price forecast used for the purposes of preparing the McDaniel Report is summarized as follows:
Year
WTI @ Cushing
WCS @ Hardisty
AECO/NIT spot
Exchange Rate
(US$/bbl)
(C$/bbl)
(C$/MMbtu)
($US/$CDN)
2026
59.92
65.13
3.00
0.728
2027
65.10
70.43
3.30
0.737
2028
70.28
76.90
3.49
0.740
2029
71.93
78.71
3.58
0.740
2030
73.37
80.29
3.65
0.740
2031
74.84
81.90
3.72
0.740
2032
76.34
83.53
3.80
0.740
2033
77.87
85.20
3.88
0.740
2034
79.42
86.91
3.95
0.740
2035
81.01
88.65
4.03
0.740
2036+
+2 %
+2 %
+2 %
constant
For comparison purposes, the Consultant Average Price Forecast December 31, 2024 price forecast used for the purposes of preparing the 2024 McDaniel Report is summarized below:
Year
WTI @ Cushing
WCS @ Hardisty
AECO/NIT spot
Exchange Rate
(US$/bbl)
(C$/bbl)
(C$/MMbtu)
($US/$CDN)
2025
71.58
82.69
2.36
0.712
2026
74.48
84.27
3.33
0.728
2027
75.81
83.81
3.48
0.743
2028
77.66
85.70
3.69
0.743
2029
79.22
87.45
3.76
0.743
2030
