Q3 2025 Interim Report

During the third quarter of 2025 and subsequently, Rubellite positively advanced its 2025 strategic priorities which include:

1. Optimize Development of Base Assets for Heavy Oil Growth;

2. Drive Top Quartile Capital Efficiencies;

3. Advance Enhanced Oil Recovery on Core Assets;

4. De-risk Exploration Prospects and Expand Portfolio;

5. Grow Land Base and Prospect Inventory for Chosen Play Strategies;

6. Increase Reserve-Based Net Asset Value and Potential Asset Value per Share;

7. Re-Establish Pristine Balance Sheet and Manage Risk; and

8. Drive Operational Excellence and Capture Cost Efficiencies.

• Conventional heavy oil sales production averaged 8,338 bbl/d, a 40% increase from the third quarter of 2024 (Q3 2024 - 5,954 bbl/d).

• Total sales production averaged 12,122 boe/d (71% heavy oil and natural gas liquids ("NGL")), a 104% increase from the third quarter of 2024 (Q3 2024 - 5,954 boe/d (100% heavy oil)).

• Rubellite brought 11 gross (9.0 net) heavy oil wells on production at Figure Lake and Frog Lake during the quarter.

• The Company's West Central 2025 drilling program commenced in July, adding 2 gross (1.0 net) liquids-rich conventional natural gas wells at East Edson to sales production late in the third quarter.

• Natural gas sales through the Figure Lake gas plant, operational since January 23, 2025, averaged 2.9 MMcf/d and 4 bbl/d of associated NGL.

  Capital Expenditures

• Exploration and development capital expenditures(1)totaled $33.7 million to drill, complete, equip and tie-in 5 gross (5.0 net) multi-lateral horizontal development wells at Figure Lake, 7 gross (5.5 net) multi-lateral horizontal development wells at Frog Lake and 2 gross (1.0 net) liquids-rich conventional natural gas wells at East Edson.

• Exploration and development spending in the third quarter included $1.5 million to expand the Figure Lake gas plant and gas gathering system, increasing capacity from 3.0 MMcf/d to 6.4 MMcf/d.

• Land and other spending totaled $1.5 million and included $0.2 million for seismic purchases (Q3 2024 - $2.9 million). In addition to land purchases during the quarter, the Company sold undeveloped land for proceeds of $5.5 million which served to fund other capital activities and reduce net debt. Subsequent to the end of the third quarter, Rubellite closed the sale of additional undeveloped land for $2.3 million.

• Decommissioning, abandonment and reclamation spending totalled $0.4 million during the third quarter of 2025 (Q3 2024 - $0.2 million).

  Financial Performance

• Adjusted funds flow(1)was $35.7 million ($0.38 per share), up 55% (9% per share) from the third quarter of 2024 (Q3 2024 - $23.0 million or $0.35 per share).

• Cash costs(1)were $18.6 million or $16.66/boe, down 33% on a per boe basis from the third quarter of 2024 (Q3 2024 - $13.5 million or

  $24.72/boe).

• Net income for the quarter was $5.6 million ($0.06 per share) compared to $15.0 million net income ($0.23 per share) in the third quarter of 2024.

  Balance Sheet and Liquidity

• As at September 30, 2025, net debt(1)was $138.4 million, a 10% reduction from $154.0 million as at December 31, 2024, driven by $17.4 million of positive free funds flow(1)during the first nine months of 2025 combined with $5.5 million of proceeds from the sale of undeveloped land which was used to reduce net debt and other balance sheet obligations.

• Rubellite had available liquidity(2)at September 30, 2025 of $48.0 million, comprised of the $140.0 million borrowing limit of Rubellite's first lien credit facility, less current bank borrowings of $90.6 million and outstanding letters of credit of $1.4 million.

1. Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures" in this interim report.

2. See "Liquidity, Capitalization and Financial Resources - Capital Management" in the Q3 2025 MD&A.

Heavy oil sales production from the Greater Figure Lake area averaged 5,110 bbl/d for the third quarter (Q2 2025 - 5,544 bbl/d). Additionally, gas sales contributed 2.9 MMcf/d plus associated natural gas liquids of 4 bbl/d which brought total sales production at Figure Lake for the third quarter to 5,601 boe/d (91% oil and liquids) (Q2 2025 - 6,064 bbl/d; 92% oil and liquids). Rubellite completed the expansion of the Figure Lake 1-13 Gas Plant to manage additional associated gas volumes in late August, establishing total throughput capacity of approximately 6.4 MMcf/d.

During the third quarter of 2025, Rubellite drilled and rig released 4 gross (4.0 net) development horizontal wells from the 9-35-63-18W4 pad (the "9-35 Pad"), all targeting the Wabiskaw Member of the Clearwater Formation, with 33 meter inter-leg spacing and 15,000m open hole length per the Figure Lake well design adopted in the latter half of 2024. Results from the 2025 development capital program to date across the Greater Figure Lake field continue to outperform expectations, with an average(1)IP30 of 259 bbl/d (9 wells) and IP60 of 239 bbl/d (8 wells), as compared to the McDaniel Tier 1 Type Curve(2)rates for 33 meter inter-leg spacing of 177 bbl/d (IP30) and 169 bbl/d(2)(IP60).

In addition to development drilling in the third quarter, 1 gross (1.0 net) step-out delineation well was drilled in the Edwand region with 50m inter-leg spacing and ~10,000m open hole length, to test and confirm productivity from a new pool in the Wabiskaw Member. The step-out well achieved an IP30 and IP60 of 48 bbl/d and 36 bbl/d, respectively.

Development drilling is continuing through the fourth quarter from the 9-35 Pad, including one waterflood pilot pattern consisting of a single horizontal multi-lateral well with two sets of four legs each (8 legs in total), with ~165 meters between the four-leg sets. Each 4-leg set will be drilled with 33 meter inter-leg spacing, and the waterflood producer well will have a planned total open hole length for the 8 legs of approximately 8,500 meters. A separate single leg water injection well will be drilled along the center line between the two 4-leg sets, and water injection is expected to commence in early 2026.

The Company advanced its novel natural gas-based re-injection pilot at Figure Lake for enhanced oil recovery, with an experimental well now configured at the 01-13-063-18W4 pad (the "1-13 Pad"), on the same site as the Figure Lake 1-13 Gas Plant. A total of ~25 MMcf of natural gas was injected into an existing open-hole multi-lateral well in order to confirm injectivity. Natural gas is being flowed back at controlled rates in advance of a second injection test, after which the well will be reconfigured for heavy oil production. Results from the waterflood pilot and natural gas-based re-injection experiment will inform future development patterns and enhanced oil recovery techniques to be implemented across the Greater Figure Lake area.

Rubellite also commenced testing larger diameter (200mm) boreholes at the 9-35 Pad to determine if incremental economic returns associated with improved inflow and productivity can be realized relative to the robust economics established for the existing 159mm boreholes drilled to date at Figure Lake. A total of 3 gross (3.0 net) wells with the 200mm borehole diameter will be drilled by year end.

A Sparky exploration well at Figure Lake is planned for the fourth quarter of 2025. If successful, there are approximately 15.0 net follow-up Sparky locations which would be incremental to the existing Clearwater development inventory.

During the third quarter, the Company was successful in acquiring 4.0 net sections of land. With the additional acreage, and adjusted to reflect both 2025 step-out and development drilling activity, Rubellite has an inventory of 260.2 net development locations(3)identified in the Wabiskaw, including 88.2 net proven and probable undeveloped(2)(3)booked locations. Under a one-rig program, which would provide for the drilling of 18 wells per year at Figure Lake, the Clearwater location count at Figure Lake represents ~14 years of low-risk development drilling inventory.

Production at the Frog Lake property averaged 2,697 bbl/d (100% heavy oil) for the third quarter of 2025, a 6% increase from the second quarter of 2025 (Q2 2025 2,539 bbl/d).

During the third quarter, 1 gross (1.0 net) Waseca North well, 4 gross (3.0 net) Waseca South wells, and 2 gross (1.5 net) exploratory General Petroleum ("GP") wells were drilled, for a total of 7 gross (5.5 net) wells.

Rubellite switched its drilling operations at Frog Lake in December 2024 to utilize OBM. The OBM trial at Frog Lake has confirmed the benefits of using OBM fluid consistent with Rubellite's operations at Figure Lake, where the use of OBM has modestly reduced the cost of the mud system net of recovered OBM suitable for re-use and the sales credit for OBM that is not fit for re-use. Additional benefits include improved hole cleaning and stability, accelerated time to stabilized reservoir production, reduced drill pipe wear, and reduced water handling and disposal costs as compared to conventional water-based mud systems. The Company is continuing to utilize OBM in its ongoing drilling operations at Frog Lake as it evaluates the effects on long term production performance in different formations across the Frog Lake field.

Results thus far from the 2025 capital drilling program targeting the Waseca North sand at Frog Lake (13 gross (9.5 net) wells) have achieved an average(1)IP30 and IP60 of 133 bbl/d (13 wells) and 113 bbl/d (13 wells) respectively, as compared to the McDaniel Waseca North Type Curve(2)IP30 and IP60 of 107 bbl/d and 104 bbl/d established by McDaniel at year-end 2024 using historical data obtained from wells drilled with water-based mud systems.

2 gross (2.0 net) of the 4 gross (3.0 net) South Waseca sand wells drilled in the third quarter, have achieved an average IP30 of 159 bbl/d as compared to the McDaniel South Type Curve(2)of 150 bbl/d, while the remaining wells are either still recovering load fluid or are within the 30 day initial production period.

In addition to continued drilling of the Waseca sand as the primary development zone at Frog Lake, the Company drilled 2 gross (1.5 net) exploratory wells in the third quarter of 2025, targeting the GP sand. One gross (0.5 net) was drilled using a single leg lined horizontal lateral design and one gross (1.0 net) was drilled with a lined "fish bone" design. Both wells were equipped with recycle strings to aid in the flow of solids and sand from the horizontal section of the wells, have fully recovered drilling fluids, are continuing to clean up, and are selling oil. Production performance to date is promising with the "fish-bone" design recording an IP30 of 134 bbl/d gross and current production of 150 bbl/d gross (field estimate). The single lined lateral well is currently producing at 75 bbl/d gross (field estimate). Learnings from these two wells will confirm type curve assumptions, inform mapping parameters, geological cutoffs, and the future well design for optimum economic development of both the GP and Sparky sands in the Mannville Stack at Frog Lake.

The rig at Frog Lake will remain active and focused on the drilling of Waseca South, Sparky, and GP sands for the remainder of 2025.

The Company commenced a "bottoms up" waterflood pilot at Marten Hills during the second quarter of 2025, with water injection initiated at its first injection well in April. Value is expected to be realized through reduced water handling costs, reduced production declines and enhanced reserve recoveries.

Net production at East Edson was close to flat quarter-over-quarter, averaging 3,291 boe/d for the third quarter, (Q2 2025 - 3,269 boe/d).

Non-operated drilling commenced in the third quarter and 2 gross (1.0 net) wells were drilled, completed, and brought on stream. The average IP30 (gross) for the two wells was 1,165 boe/d as compared to the McDaniel Type Curve(2)of 1,003 boe/d, meeting expectations. An additional 2 gross (1.0 net) wells are expected to be drilled and placed on production prior to year end.

In addition to exploration activities in the GP and Sparky zones at Frog Lake and the Sparky zone at Figure Lake, the Company is continuing to advance multiple additional new venture exploration prospects, pursuing both land capture and play concept de-risking activities while minimizing risked capital exposure. A total of $0.3 million was invested in the third quarter of 2025 to acquire seismic data for exploratory prospects that are expected to be evaluated in the next 12 months.

1. No wells were excluded from the calculation of average results except the criteria for producing days.

2. Type curve assumptions for the 33m spacing well design are based on the Total Proved plus Probable Undeveloped reserves contained in the 2024 McDaniel Reserve Report as disclosed in the Company's 2024 Annual Information Form available under the Company's profile on SEDAR+ at https://www.sedarplus.ca. "McDaniel" means McDaniel & Associates Consultants Ltd. independent qualified reserves evaluators. "McDaniel Reserve 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, 2024 and a preparation date of March 10, 2025. See "Estimated Drilling Locations".

3. Assuming a September 30, 2025, reference date, management estimates 260.2 net locations in the greater Figure Lake area, 65.6 net locations are recognized in the 2024 Year-End McDaniel Report as proved undeveloped and an additional 30.6 net locations are classified as probable undeveloped. The Company estimates a total of 326.2 net heavy oil development locations, 93.1 of which are proved and 45.6 are probable and included in the McDaniel Reserve Report. The following net reserve locations have been drilled through 2025: 8.0 proved undeveloped in Figure Lake, 4.5 proved undeveloped and 4.5 probable undeveloped in North Waseca, and 3.0 proved undeveloped in South Waseca.

   OUTLOOK AND GUIDANCE

   For the fourth quarter of 2025, Rubellite plans to spend a total of $30 to $35 million on exploration and development capital expenditures(1), bringing total spending for the year to $110 to $115 million. This increase over previous full year guidance of $100 to $110 million reflects: (1) the increased working interest from 50% to 100% for the drilling of four of seven gross wells at Frog Lake in the third quarter (two of the four 100% working interest wells were incorporated in previous guidance); (2) oil battery consolidation and facilities investments at Frog Lake to free up equipment for new pads and to reduce operating expenses; (3) accelerated non-operated spending at Edson on pipeline infrastructure for the Q1 2026 drilling program; (4) construction of additional surface pads at both Frog Lake and Figure Lake to optimize capital program execution; and (5) acquisition of additional bitcoin mining equipment to reduce flaring and monetize stranded solution gas.

   Rubellite's fourth quarter capital program includes: At Figure Lake:

   • Drilling of 4 gross (4.0 net) Clearwater 15,000m development wells remaining on the 9-35 Pad;

   • Drilling of 1 gross (1.0 net) Clearwater 8,500m producing well and one (1.0 net) single leg waterflood injector;

   • Drilling of 1 gross (1.0 net) Sparky exploration well; and

   • Core testing on a new core cut at the 9-35 Pad to progress enhanced oil recovery.

     At Frog Lake:

   • Drilling of 4 gross (2.0 net) South Waseca wells;

   • Drilling of 2 gross (1.0 net) GP exploration wells;

   • Drilling of 1 gross (0.5 net) exploratory Sparky well; and

   • Preliminary spending towards the acquisition of 3D seismic to better define geologically complex Mannville-Stack targets.

     At East Edson:

   • Participation in the drilling of 2 gross (1.0 net) Wilrich development wells to complete the 2025 drilling program.

Despite the ongoing volatility in oil prices, Rubellite is planning to maintain the operational efficiencies of its one rig drilling programs at each of Figure Lake and Frog Lake for the remainder of 2025, and to advance strategic initiatives such as land continuation and new capture, secondary recovery and exploration. The Company will continue to strive for meaningful per well capital cost reductions to maintain attractive rates of return and payout periods, and will manage its capital spending to prioritize free funds flow generation over production growth in this current weaker oil price environment.

Heavy oil sales volumes based on the current plan are expected to grow 47% to 50% year-over-year to average between 8,325 - 8,400 bbl/d in 2025, up from previous guidance of between 8,200 - 8,400 bbl/d. Total production sales volumes, including natural gas and NGL volumes at East Edson and Figure Lake, are forecast to average 12,325 - 12,400 boe/d in 2025, up from previous guidance of 12,200 - 12,400 boe/d.

Capital spending activity will continue to be funded from adjusted funds flow(1)combined with proceeds from the sale of undeveloped land, with excess free funds flow(1)used to reduce net debt(1)and for other balance sheet obligations. Aided by Rubellite's extensive commodity price risk management positions, the Company continues to forecast strong adjusted funds flow and free funds flow through the fourth quarter of 2025 based on the forward market for commodity prices as at November 5, 2025.

Rubellite's Clearwater and Mannville Stack production continues to realize an attractive offset to WCS benchmark pricing, resulting in a further improvement to its heavy oil wellhead differential guidance to a range of $3.75 to $4.00 per bbl, down from $4.00 to $4.50 per bbl previously. Initiatives to improve field operating costs have improved the Company's operating cost guidance to a range of $6.50 to $7.00 per boe as compared to $6.50 to $7.25 per boe previously. Additionally, transportation costs were normalized across operations during the third quarter, driving guidance for annual transportation costs down to $5.25 - $5.50 per boe versus $5.50 - $6.00 per boe previously.

Rubellite will continue to address end of life ARO, with total abandonment and reclamation expenditures of approximately $0.5 million planned for the fourth quarter of 2025. In combination with the $1.3 million of asset retirement obligation spending in the first three quarters of 2025, the Company is on track to exceed its Alberta Energy Regulator ("AER") area-based mandatory spending requirement for 2025 of $1.7 million.

1. Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures".

Capital spending and drilling activity for 2025 is summarized in the table below:

1. Includes one waterflood injection well.

2. Includes 5 gross (3.0 net) wells at Frog Lake targeting secondary exploration zones.

3. Excludes abandonment and reclamation spending, acquisitions and land expenditures, if any.

Rubellite's capital spending, drilling and operational guidance for 2025 are presented in the table below:

1. Previous full year 2025 guidance dated August 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 Measures".

4. Excludes land and acquisition spending, if any.

Susan Riddell Rose

President and Chief Executive Officer November 5, 2025

Three months ended September 30, Nine months ended September 30,

1. Per share amounts are calculated using the weighted average number of basic or diluted common shares.

2. Non-GAAP measure or ratio. See "Non-GAAP and other Financial Measures" contained in this interim report.

3. Well count reflects wells rig released during the period.

4. Conventional heavy oil sales production excludes tank inventory volumes.

5. Liquids means oil, condensate, ethane and butane.

6. Before risk management contracts; supplementary financial measure. See "Non-GAAP and Other Financial Measures".

7. Based on Q3 2025 and Q3 2024 annualized adjusted funds flow before transaction costs relative to period end net debt. Non-GAAP financial measure and ratio.

This third quarter 2025 interim report refers to certain non-GAAP measures and metrics commonly used in the oil and natural gas industry and provides forward-looking information and statements. Further detailed information regarding these measures is provided in this report in "Management's Discussion and Analysis - NON-GAAP AND OTHER FINANCIAL MEASURES" on pages 21 to 24 and "Management's Discussion and Analysis - FORWARD-LOOKING INFORMATION" on pages 24 and 25.

In addition to the disclosure set out in the Company's Management's Discussion and Analysis for the period ended September 30, 2025, we provide certain supplementary disclosure throughout this report in respect of certain specified financial measures (as such term is defined in National Instrument 51-112 - Non-GAAP and Other Financial Measures) and in respect of certain oil and gas metrics.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is management's discussion and analysis ("MD&A") of Rubellite Energy Corp.'s ("Rubellite", the "Company" or the "Corporation") operating and financial results for the three and nine months ended September 30, 2025, as well as the information and estimates concerning the Corporation's future outlook based on currently available information. This discussion should be read in conjunction with the Corporation's unaudited condensed interim consolidated financial statements and accompanying notes for the three and nine months ended September 30, 2025 as well as the audited consolidated financial statements and accompanying notes for the year ended December 31, 2024. Disclosure, which is unchanged from the December 31, 2024 MD&A has not been duplicated herein. The Corporation's financial statements are prepared in accordance with Canadian generally accepted accounting principles ("GAAP") which require publicly accountable enterprises to prepare their financial statements using IFRS Accounting Standards ("IFRS") as issued by the International Accounting Standards Board. The date of this MD&A is November 5, 2025.

This MD&A contains specified financial measures that are not recognized by GAAP and used by management to evaluate the performance of the Corporation 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 Measures" for further information on the definition, calculation and reconciliation of these measures. This MD&A also contains "Forward-Looking Information". Readers are also referred to the other advisory sections at the end of this MD&A for additional information.

The Company is a Canadian energy company headquartered in Calgary, Alberta engaged in the exploration, development, production and marketing of its diversified asset portfolio which includes conventional heavy crude oil from the Clearwater and Mannville Stack Formations in Eastern Alberta, liquids-rich conventional natural gas assets in the deep basin of West Central Alberta, and undeveloped bitumen leases in Northern Alberta. The Company is pursuing a robust growth plan focused on heavy oil exploration and development utilizing multi-lateral, horizontal drilling technology, targeting superior corporate returns and free funds flow generation while maintaining a conservative capital structure and prioritizing operational excellence. Additional information on the Company can be accessed on the Company's website at https://www.rubelliteenergy.com or on SEDAR+ at https://www.sedarplus.ca.

The Company's common shares trade on the Toronto Stock Exchange under the symbol "RBY".

Recombination Transaction

On October 31, 2024, the Company, Rubellite Energy Inc. and Perpetual Energy Inc. ("Perpetual") closed a recombination transaction by way of an arrangement under Section 193 of the Business Corporations Act (Alberta) (the "Recombination Transaction"). Comparative figures in the MD&A include Rubellite Energy Inc.'s results prior to the business combination and do not reflect any historical data from Perpetual. The conventional natural gas assets at East Edson acquired through the Recombination Transaction are included in the West Central cash generating unit ("CGU"). This MD&A contains certain information pertaining to the Company before and after giving effect to the Recombination Transaction. Any reference to information prior to October 31, 2024 are references to Rubellite Energy Inc. and any reference to information subsequent to October 31, 2024 are references to the Company. Accordingly, unless the context otherwise requires, references to the Company subsequent to October 31, 2024 shall mean "Rubellite Energy Corp." and references to the Corporation prior to October 31, 2024 shall mean "Rubellite Energy Inc".

Buffalo Mission Acquisition

On August 2, 2024, Rubellite closed the acquisition of Buffalo Mission Energy Corp. ("Buffalo Mission") (the "BMEC Acquisition"), a private Mannville Stack-focused heavy oil producer in the Frog Lake area. The total consideration paid was $96.6 million, inclusive of $23.5 million of assumed net debt, which consisted of $62.7 million in cash and the issuance of 5.0 million common shares of Rubellite to certain shareholders of Buffalo Mission.

Sales Production Volumes

• Conventional heavy oil sales production averaged 8,338 bbl/d, a 40% increase from the third quarter of 2024 (Q3 2024 - 5,954 bbl/d).

• Total sales production averaged 12,122 boe/d (71% heavy oil and natural gas liquids ("NGL")), a 104% increase from the third quarter of 2024 (Q3 2024 - 5,954 boe/d (100% heavy oil)).

• Rubellite brought 11 gross (9.0 net) heavy oil wells on production at Figure Lake and Frog Lake during the quarter.

• The Company's West Central 2025 drilling program commenced in July, adding 2 gross (1.0 net) liquids-rich conventional natural gas wells at East Edson to sales production late in the third quarter.

• Natural gas sales through the Figure Lake gas plant, operational since January 23, 2025, averaged 2.9 MMcf/d and 4 bbl/d of associated NGL.

  Capital Expenditures

• Exploration and development capital expenditures(1) totaled $33.7 million to drill, complete, equip and tie-in 5 gross (5.0 net) multi-lateral horizontal development wells at Figure Lake, 7 gross (5.5 net) multi-lateral horizontal development wells at Frog Lake and 2 gross (1.0 net) liquids-rich conventional natural gas wells at East Edson.

• Exploration and development spending also included $1.5 million to expand the Figure Lake gas plant and gas gathering system, increasing capacity from 3.0 MMcf/d to 6.4 MMcf/d.

• Land and other spending totaled $1.5 million and included $0.2 million for seismic purchases (Q3 2024 - $2.9 million). In addition to land purchases during the quarter, the Company sold undeveloped land for proceeds of $5.5 million which served to fund other capital activities and reduce net debt. Subsequent to the end of the third quarter, Rubellite closed the sale of additional undeveloped land for

  $2.3 million.

• Decommissioning, abandonment and reclamation spending totalled $0.4 million during the third quarter of 2025 (Q3 2024 - $0.2 million).

  Financial Performance

• Adjusted funds flow(1) was $35.7 million ($0.38 per share), up 55% (9% per share) from the third quarter of 2024 (Q3 2024 - $23.0 million or $0.35 per share).

• Cash costs(1) were $18.6 million or $16.66/boe, down 33% on a per boe basis from the third quarter of 2024 (Q3 2024 - $13.5 million or

  $24.72/boe).

• Net income for the quarter was $5.6 million ($0.06 per share) compared to $15.0 million net income ($0.23 per share) in the third quarter of 2024.

  Balance Sheet and Liquidity

• As at September 30, 2025, net debt(1) was $138.4 million, a 10% reduction from $154.0 million as at December 31, 2024, driven by

  $17.4 million of positive free funds flow(1) during the first nine months of 2025 combined with $5.5 million of proceeds from the sale of undeveloped land which was used to reduce net debt and other balance sheet obligations.

• Rubellite had available liquidity(2) at September 30, 2025 of $48.0 million, comprised of the $140.0 million borrowing limit of Rubellite's first lien credit facility, less current bank borrowings of $90.6 million and outstanding letters of credit of $1.4 million.

1. Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures".

2. See "Liquidity, Capitalization and Financial Resources - Capital Management".

Greater Figure Lake (Figure Lake and Edwand)

Heavy oil sales production from the Greater Figure Lake area averaged 5,110 bbl/d for the third quarter (Q2 2025 - 5,544 bbl/d). Additionally, gas sales contributed 2.9 MMcf/d plus associated natural gas liquids of 4 bbl/d which brought total sales production at Figure Lake for the third quarter to 5,601 boe/d (91% oil and liquids) (Q2 2025 - 6,064 bbl/d; 92% oil and liquids). Rubellite completed the expansion of the Figure Lake 1-13 Gas Plant to manage additional associated gas volumes in late August, establishing total throughput capacity of approximately 6.4 MMcf/d.

During the third quarter of 2025, Rubellite drilled and rig released 4 gross (4.0 net) development horizontal wells from the 9-35-63-18W4 pad (the "9-35 Pad"), all targeting the Wabiskaw Member of the Clearwater Formation, with 33 meter inter-leg spacing and 15,000m open hole length per the Figure Lake well design adopted in the latter half of 2024. Results from the 2025 development capital program to date across the Greater Figure Lake field continue to outperform expectations, with an average(1) IP30 of 259 bbl/d (9 wells) and IP60 of 239 bbl/d (8 wells), as compared to the McDaniel Tier 1 Type Curve(2) rates for 33 meter inter-leg spacing of 177 bbl/d (IP30) and 169 bbl/d(2) (IP60).

In addition to development drilling in the third quarter, 1 gross (1.0 net) step-out delineation well was drilled in the Edwand region with 50m inter-leg spacing and ~10,000m open hole length, to test and confirm productivity from a new pool in the Wabiskaw Member. The step-out well achieved an IP30 and IP60 of 48 bbl/d and 36 bbl/d, respectively.

Development drilling is continuing through the fourth quarter from the 9-35 Pad, including one waterflood pilot pattern consisting of a single horizontal multi-lateral well with two sets of four legs each (8 legs in total), with ~165 meters between the four-leg sets. Each 4-leg set will be drilled with 33 meter inter-leg spacing, and the waterflood producer well will have a planned total open hole length for the 8 legs of approximately 8,500 meters. A separate single leg water injection well will be drilled along the center line between the two 4-leg sets, and water injection is expected to commence in early 2026.

The Company advanced its novel natural gas-based re-injection pilot at Figure Lake for enhanced oil recovery, with an experimental well now configured at the 01-13-063-18W4 pad (the "1-13 Pad"), on the same site as the Figure Lake 1-13 Gas Plant. A total of ~25 MMcf of natural gas was injected into an existing open-hole multi-lateral well in order to confirm injectivity. Natural gas is being flowed back at controlled rates in advance of a second injection test, after which the well will be reconfigured for heavy oil production. Results from the waterflood pilot and natural gas-based re-injection experiment will inform future development patterns and enhanced oil recovery techniques to be implemented across the Greater Figure Lake area.

Rubellite also commenced testing larger diameter (200mm) boreholes at the 9-35 Pad to determine if incremental economic returns associated with improved inflow and productivity can be realized relative to the robust economics established for the existing 159mm boreholes drilled to date at Figure Lake. A total of 3 gross (3.0 net) wells with the 200mm borehole diameter will be drilled by year end.

A Sparky exploration well at Figure Lake is planned for the fourth quarter of 2025. If successful, there are approximately 15.0 net follow-up Sparky locations which would be incremental to the existing Clearwater development inventory.

During the third quarter, the Company was successful in acquiring 4.0 net sections of land. With the additional acreage, and adjusted to reflect both 2025 step-out and development drilling activity, Rubellite has an inventory of 260.2 net development locations(3) identified in the Wabiskaw, including 88.2 net proven and probable undeveloped(2)(3) booked locations. Under a one-rig program, which would provide for the drilling of 18 wells per year at Figure Lake, the Clearwater location count at Figure Lake represents ~14 years of low-risk development drilling inventory.

Frog Lake

Production at the Frog Lake property averaged 2,697 bbl/d (100% heavy oil) for the third quarter of 2025, a 6% increase from the second quarter of 2025 (Q2 2025 2,539 bbl/d).

During the third quarter, 1 gross (1.0 net) Waseca North well, 4 gross (3.0 net) Waseca South wells, and 2 gross (1.5 net) exploratory General Petroleum ("GP") wells were drilled, for a total of 7 gross (5.5 net) wells.

Rubellite switched its drilling operations at Frog Lake in December 2024 to utilize OBM. The OBM trial at Frog Lake has confirmed the benefits of using OBM fluid consistent with Rubellite's operations at Figure Lake, where the use of OBM has modestly reduced the cost of the mud system net of recovered OBM suitable for re-use and the sales credit for OBM that is not fit for re-use. Additional benefits include improved hole cleaning and stability, accelerated time to stabilized reservoir production, reduced drill pipe wear, and reduced water handling and disposal costs as compared to conventional water-based mud systems. The Company is continuing to utilize OBM in its ongoing drilling operations at Frog Lake as it evaluates the effects on long term production performance in different formations across the Frog Lake field.

Results thus far from the 2025 capital drilling program targeting the Waseca North sand at Frog Lake (13 gross (9.5 net) wells) have achieved an average(1) IP30 and IP60 of 133 bbl/d (13 wells) and 113 bbl/d (13 wells) respectively, as compared to the McDaniel Waseca North Type

Curve(2) IP30 and IP60 of 107 bbl/d and 104 bbl/d established by McDaniel at year-end 2024 using historical data obtained from wells drilled with water-based mud systems.

2 gross (2.0 net) of the 4 gross (3.0 net) South Waseca sand wells drilled in the third quarter, have achieved an average IP30 of 159 bbl/d as compared to the McDaniel South Type Curve(2) of 150 bbl/d, while the remaining wells are either still recovering load fluid or are within the 30 day initial production period.

In addition to continued drilling of the Waseca sand as the primary development zone at Frog Lake, the Company drilled 2 gross (1.5 net) exploratory wells in the third quarter of 2025, targeting the GP sand. One gross (0.5 net) was drilled using a single leg lined horizontal lateral design and one gross (1.0 net) was drilled with a lined "fish bone" design. Both wells were equipped with recycle strings to aid in the flow of solids and sand from the horizontal section of the wells, have fully recovered drilling fluids, are continuing to clean up, and are selling oil. Production performance to date is promising with the "fish-bone" design recording an IP30 of 134 bbl/d gross and current production of 150 bbl/d gross (field estimate). The single lined lateral well is currently producing at 75 bbl/d gross (field estimate). Learnings from these two wells will confirm type curve assumptions, inform mapping parameters, geological cutoffs, and the future well design for optimum economic development of both the GP and Sparky sands in the Mannville Stack at Frog Lake.

The rig at Frog Lake will remain active and focused on the drilling of Waseca South, Sparky, and GP sands for the remainder of 2025.

Marten Hills

The Company commenced a "bottoms up" waterflood pilot at Marten Hills during the second quarter of 2025, with water injection initiated at its first injection well in April. Value is expected to be realized through reduced water handling costs, reduced production declines and enhanced reserve recoveries.

East Edson

Net production at East Edson was close to flat quarter-over-quarter, averaging 3,291 boe/d for the third quarter, (Q2 2025 - 3,269 boe/d).

Non-operated drilling commenced in the third quarter and 2 gross (1.0 net) wells were drilled, completed, and brought on stream. The average IP30 (gross) for the two wells was 1,165 boe/d as compared to the McDaniel Type Curve(2) of 1,003 boe/d, meeting expectations. An additional 2 gross (1.0 net) wells are expected to be drilled and placed on production prior to year end.

Other Exploration

In addition to exploration activities in the GP and Sparky zones at Frog Lake and the Sparky zone at Figure Lake, the Company is continuing to advance multiple additional new venture exploration prospects, pursuing both land capture and play concept de-risking activities while minimizing risked capital exposure. A total of $0.3 million was invested in the third quarter of 2025 to acquire seismic data for exploratory prospects that are expected to be evaluated in the next 12 months.

1. No development wells were excluded from the calculation of average results except by the criteria for producing days.

2. Type curve assumptions for the 33 meter spacing well design are based on the Total Proved plus Probable Undeveloped reserves contained in the 2024 McDaniel Reserve Report as disclosed in the Company's 2024 Annual Information Form available under the Company's profile on SEDAR+ at https://www.sedarplus.ca. "McDaniel" means McDaniel & Associates Consultants Ltd. independent qualified reserves evaluators. "McDaniel Reserve 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, 2024 and a preparation date of March 10, 2025. See "Estimated Drilling Locations.

3. Assuming a September 30, 2025, reference date, management estimates 260.2 net locations in the greater Figure Lake area, 65.6 net locations are

recognized in the 2024 Year-End McDaniel Report as proved undeveloped and an additional 30.6 net locations are classified as probable undeveloped. The Company estimates a total of 326.2 net heavy oil development locations, 93.1 of which are proved and 45.6 are probable and included in the McDaniel Reserve Report. The following net reserve locations have been drilled through 2025: 8.0 proved undeveloped in Figure Lake, 4.5 proved undeveloped and

4.5 probable undeveloped in North Waseca, and 3.0 proved undeveloped in South Waseca.

For the fourth quarter of 2025, Rubellite plans to spend a total of $30 to $35 million on exploration and development capital expenditures(1), bringing total spending for the year to $110 to $115 million. This increase over previous full year guidance of $100 to $110 million reflects: (1) the increased working interest from 50% to 100% for the drilling of four of seven gross wells at Frog Lake in the third quarter (two of the four 100% working interest wells were incorporated in previous guidance); (2) oil battery consolidation and facilities investments at Frog Lake to free up equipment for new pads and to reduce operating expenses; (3) accelerated non-operated spending at Edson on pipeline infrastructure for the Q1 2026 drilling program; (4) construction of additional surface pads at both Frog Lake and Figure Lake to optimize capital program execution; and (5) acquisition of additional bitcoin mining equipment to reduce flaring and monetize stranded solution gas.

Rubellite's fourth quarter capital program includes: At Figure Lake:

• Drilling of 4 gross (4.0 net) Clearwater 15,000m development wells remaining on the 9-35 Pad;

• Drilling of 1 gross (1.0 net) Clearwater 8,500m producing well and one (1.0 net) single leg waterflood injector;

• Drilling of 1 gross (1.0 net) Sparky exploration well; and

• Core testing on a new core cut at the 9-35 Pad to progress enhanced oil recovery.

  At Frog Lake:

• Drilling of 4 gross (2.0 net) South Waseca wells;

• Drilling of 2 gross (1.0 net) GP exploration wells;

• Drilling of 1 gross (0.5 net) exploratory Sparky well; and

• Preliminary spending towards the acquisition of 3D seismic to better define geologically complex Mannville-Stack targets.

  At East Edson:

• Participation in the drilling of 2 gross (1.0 net) Wilrich development wells to complete the 2025 drilling program.

Despite the ongoing volatility in oil prices, Rubellite is planning to maintain the operational efficiencies of its one rig drilling programs at each of Figure Lake and Frog Lake for the remainder of 2025, and to advance strategic initiatives such as land continuation and new capture, secondary recovery and exploration. The Company will continue to strive for meaningful per well capital cost reductions to maintain attractive rates of return and payout periods, and will manage its capital spending to prioritize free funds flow generation over production growth in this current weaker oil price environment.

Heavy oil sales volumes based on the current plan are expected to grow 47% to 50% year-over-year to average between 8,325 - 8,400 bbl/d in 2025, up from previous guidance of between 8,200 - 8,400 bbl/d. Total production sales volumes, including natural gas and NGL volumes at East Edson and Figure Lake, are forecast to average 12,325 - 12,400 boe/d in 2025, up from previous guidance of 12,200 - 12,400 boe/d.

Capital spending activity will continue to be funded from adjusted funds flow(1) combined with proceeds from the sale of undeveloped land, with excess free funds flow(1) used to reduce net debt(1) and for other balance sheet obligations. Aided by Rubellite's extensive commodity price risk management positions, the Company continues to forecast strong adjusted funds flow and free funds flow through the fourth quarter of 2025 based on the forward market for commodity prices as at November 5, 2025.

Rubellite's Clearwater and Mannville Stack production continues to realize an attractive offset to WCS benchmark pricing, resulting in a further improvement to its heavy oil wellhead differential guidance to a range of $3.75 to $4.00 per bbl, down from $4.00 to $4.50 per bbl previously. Initiatives to improve field operating costs have improved the Company's operating cost guidance to a range of $6.50 to $7.00 per boe as compared to $6.50 to $7.25 per boe previously. Additionally, transportation costs were normalized across operations during the third quarter, driving guidance for annual transportation costs down to $5.25 - $5.50 per boe versus $5.50 - $6.00 per boe previously.

Rubellite will continue to address end of life ARO, with total abandonment and reclamation expenditures of approximately $0.5 million planned for the fourth quarter of 2025. In combination with the $1.3 million of asset retirement obligation spending in the first three quarters of 2025, the Company is on track to exceed its Alberta Energy Regulator ("AER") area-based mandatory spending requirement for 2025 of $1.7 million.

1. Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures".

Capital spending and drilling activity for 2025 is summarized in the table below:

1. Includes one waterflood injection well and 1 (1.0 net) well targeting the exploratory Sparky zone.

2. Includes 5 gross (3.0 net) wells at Frog Lake targeting secondary exploration zones.

3. Excludes abandonment and reclamation spending, acquisitions and land expenditures, if any.

Rubellite's capital spending, drilling and operational guidance for 2025 are presented in the table below:

1. Previous full year 2025 guidance dated August 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 Measures".

4. Excludes land and acquisition spending.

Rubellite uses capital expenditures to measure its capital investments compared to the Company's annual budgeted expenditures related to both property, plant and equipment assets ("PP&E") and exploration and evaluation assets ("E&E") assets. The capital budget excludes acquisition and disposition activities. "Capital Expenditures" is not a standardized measure; therefore, may not be comparable with the calculation of similar measures by other entities. For a reconciliation of cash flow used in investing activities to capital expenditures, refer to the section entitled "Non-GAAP and Other Financial Measures" contained within this MD&A.

The following tables summarize capital expenditures for both PP&E and E&E assets, excluding non-cash items:

Three months ended September 30,

1. Capital expenditures is a non-GAAP measure. See "Non-GAAP and Other Financial Measures".

Nine months ended September 30,

1. Capital expenditures is a non-GAAP measure. See "Non-GAAP and Other Financial Measures".

Capital expenditures by CGU

Three months ended September 30, Nine months ended September 30,

1. Excludes corporate capital expenditures; Non-GAAP measure. See "Non-GAAP and Other Financial Measures".

Wells drilled by area

Three months ended September 30, Nine months ended September 30,

1. 1 gross (1.0 net) well drilled on the 9-35 Pad at Figure Lake was spud on September 29, 2025 and rig released October 17, 2025 and not included in the Q3 2025 well count.

2. 1 gross (1.0 net) well drilled on the 14-19 Pad in Frog Lake was spud on September 23, 2025 and rig released on October 4, 2025 and not included in the Q3 2025 well count.

3. Four wells drilled in Q3 2025 and nine wells drilled in the first nine months of 2025 were at 100% working interest as Frog Lake Energy Resources Corp. ("FLERC") has elected gross overriding royalty positions in these wells.

4. 1 gross (0.3 net) injection waterflood well was drilled at Marten Hills on the 12-35 Pad during Q1 2025.

5. 1 gross (1.0 net) horizontal evaluation well was drilled in Q1 2025 and 1 gross (1.0 net) vertical stratigraphic evaluation well was drilled in Q1 2024. The wells were transferred to E&E expense in Q1 2025.

Capital Expenditures

During the third quarter of 2025, Rubellite invested a total of $33.7 million in exploration and development activities, before land and other corporate spending, related primarily to drill, complete, equip and tie-in 5 gross (5.0 net) multi-lateral horizontal Clearwater wells at Figure Lake, 5 gross (4.0 net) multi-lateral horizontal Waseca wells and 2 gross (1.5 net) single leg lined GP wells at Frog Lake, and 2 gross (1.0 net)

horizontal multi-frac Wilrich wells at East Edson. A portion of capital to drill 1 gross (1.0 net) additional well at Figure Lake and 1 gross (1.0 net) additional well at Frog Lake was spent during the third quarter with both wells rig released early in the fourth quarter. Facilities spending included $1.5 million for gas gathering and pipeline tie-ins at Figure Lake, supporting the solution gas conservation project.

During the first nine months of 2025, the Company spent $79.8 million on exploration and development activities, before land and other corporate spending, primarily related to the two rig program to drill, complete, equip and tie-in 14 gross (14.0 net) wells at Figure Lake, 19 gross (14.0 net) wells at Frog Lake, 1 gross (0.3 net) waterflood injection well at Marten Hills, 2 gross (1.0 net) wells at East Edson and 1 gross (1.0 net) exploratory evaluation well. Capital spending also included $3.4 million for facilities spending at Figure Lake for the solution gas conservation project and $0.9 million at East Edson for lease construction, facility improvements and pipelines to support the ongoing drilling program with the 50% joint venture partner.

Land and seismic purchases were $1.5 million in the third quarter of 2025, with total land and seismic spending in 2025 of $11.3 million to acquire core area lands prospective for Clearwater development and to capture acreage on multiple exploration prospects.

During the third quarter of 2025, the Company disposed of undeveloped lands for proceeds of $5.5 million and recorded a corresponding gain on disposition.

During the third quarter of 2025, Rubellite spent $0.4 million (Q3 2024 - nominal) on abandonment and reclamation projects, with total asset retirement obligation expenditures of $1.3 million (2024 - $0.1 million) during the first nine months of 2025. No additional reclamation certificates were received from the AER in the third quarter of 2025, maintaining the total at two certificates received to date in 2025 (2024 -nil).

Three months ended September 30, Nine months ended September 30,

1. Conventional natural gas production at East Edson yielded a heat content of 1.18 GJ/Mcf during the third quarter of 2025 (Q3 2024 - nil) resulting in higher realized natural gas prices on a $/Mcf basis.

2. Primarily from West Central CGU which produces liquids-rich conventional natural gas.

Sales production for the three and nine months ended September 30, 2025 by CGU:

Three months ended September 30, Nine months ended September 30,

1. Primarily from the Clearwater and Mannville Stack formations in Eastern Alberta, which includes gas sales production at Figure Lake which commenced in Q1 2025 and assets at Frog Lake that were acquired in Q3 2024.

2. Acquired through the Recombination Transaction with Perpetual in Q4 2024, which includes assets at East Edson that produce liquids-rich conventional natural gas.

Sales production for the three and nine months ended September 30, 2025 increased by 6,168 boe/d (104%) and 7,315 boe/d (146%) from the comparative periods of 2024, driven by successful drilling programs, Figure Lake solution gas tie-in, the BMEC Acquisition at Frog Lake in the third quarter of 2024 and the Recombination Transaction with Perpetual in the fourth quarter of 2024. The Company has increased its previously announced guidance range to 8,325 to 8,450 bbl/d (previously 8,200 to 8,400 bbl/d) of heavy oil sales volumes and 12,325 to 12,400 boe/d (previously 12,200 to 12,400 boe/d) of total sales volumes.

During the first half of 2025, 21 gross (18.0 net) wells from the Eastern Heavy Oil drilling program began contributing to sales, with an additional 11 gross (9.0 net) wells added during the third quarter, resulting in a total of 32 gross (27.0 net) wells contributing to sales in 2025. At the end of the third quarter, 4 gross (3.5 net) additional wells were recovering OBM drilling fluid and not yet contributing to sales. The Company's West Central 2025 drilling program commenced in the third quarter, adding 2 gross (1.0 net) liquids-rich conventional natural gas wells to sales production late in the third quarter.

At Figure Lake, a new gas plant commenced operations on January 23, 2025 and added 2.9 MMcf/d and 2.7 MMcf/d of natural gas sales on average during the three and nine months ended September 30, 2025. For the three and nine months ended September 30, 2025, assets acquired through the Recombination Transaction at East Edson added 3,291 boe/d and 3,421 boe/d of natural gas and NGL sales production (Q3 2024 and 2024 - nil) and the Frog Lake assets acquired through the BMEC Acquisition in August 2024 added 2,697 bbl/d and 2,554 bbl/d of heavy oil sales production (Q3 2024 - 1,528 bbl/d; 2024 - 513 bbl/d).

As a result of the Recombination Transaction and Figure Lake solution gas conservation, Rubellite's sales product mix was comprised of 71% conventional heavy crude oil and NGL and 29% conventional natural gas during the three and nine months ended September 30, 2025 (2024 comparative periods - 100% conventional heavy crude oil).

Three months ended September 30, Nine months ended September 30,

1. Converted from $/GJ using a standard energy conversion rate of 1.06 GJ:1 Mcf.

2. Before risk management contracts; supplementary financial measure. See "Non-GAAP and Other Financial Measures".

Rubellite's oil and natural gas revenue for the three and nine months ended September 30, 2025 increased by $14.6 million or 33% and $76.1 million or 70% from the comparative periods of 2024, primarily driven by the increase in sales volumes partially offset by lower oil prices.

Oil revenue for the third quarter of 2025 of $55.5 million represented 95% of total revenue while conventional heavy crude oil production was 69% of total sales volumes. The 27% increase in oil revenue was driven by the 40% increase in heavy crude oil production, partially offset by a 9% decrease in average realized oil prices. Compared to the third quarter of 2024, the WCS average price decreased to $75.10/bbl (Q3 2024 - $83.95/bbl), attributable to the 14% decrease in WTI oil prices, partially offset by an increase in the CAD$/US$ rate to $1.38 (Q3 2024

- $1.36) and a narrowing of the WCS differential to US$10.39/bbl (Q3 2024 - US$13.55/bbl).

During the first nine months of 2025, oil revenue was $170.6 million and represented 92% of total revenue while conventional heavy crude oil production was 69% of total sales volumes. The 56% increase in oil revenue was driven by the 69% increase in heavy crude oil production, partially offset by a 7% decrease in average realized oil prices. Relative to the comparative period of 2024, the WCS average price decreased 8% to $77.88/bbl (2024 - $84.45/bbl) driven by a 14% decrease in WTI oil prices to US$66.70/bbl (2024 - US$77.54/bbl), partially offset by an increase in the CAD$/US$ rate to $1.40 (2024 - $1.36) and the narrowing of the WCS differential to US$11.11/bbl (2024 - US$15.49/bbl).

Rubellite's realized oil price reflects a price offset for quality and optimization of sales delivery points, which averaged $2.70/bbl and $3.82/bbl for the three and nine months ended September 30, 2025 as compared to $4.20/bbl and $4.57/bbl in the comparative periods of 2024.

Natural gas revenue of $1.3 million in the third quarter of 2025 represented 2% of total revenue while natural gas production was 29% of total sales volumes. Natural gas revenues reflected AECO Daily Index prices of $0.63/Mcf. For the nine months ended September 30, 2025, natural gas revenue was $9.2 million and 5% of total revenue while natural gas production was 29% of total sales volumes, reflecting AECO Daily Index prices of $1.50/Mcf.

NGL revenue of $1.5 million in the third quarter of 2025 represented 3% of total revenue and total sales volumes. For the nine months ended September 30, 2025, NGL revenue of $5.7 million represented 3% of total revenue and total sales volumes.

The Company uses "average realized prices after risk management contracts" which is not a standardized measure, and therefore may not be comparable with the calculation of similar measures by other entities. The measure is used by management to calculate Rubellite's net realized price, taking into account the monthly settlements of financial crude oil and natural gas forward sales, differentials and foreign exchange contracts. These contracts are put in place to protect Rubellite's adjusted funds flow from potential downside risk and volatility and to lock in economics on drilling programs and acquisitions.

The following table details realized and unrealized gains and losses on risk management contracts:

Three months ended September 30, Nine months ended September 30,

1. Supplementary financial measure. See "Non-GAAP and Other Financial Measures".

2. Includes gain (loss) on CAD/USD foreign exchange risk management contracts.

The following table calculates average realized prices after risk management contracts, which is not a standardized measure:

Three months ended September 30, Nine months ended September 30,

1. Supplementary financial measure. See "Non-GAAP and Other Financial Measures".

2. Includes CAD/USD foreign exchange risk management contracts.

The realized gain on risk management contracts totaled $4.0 million or $3.56/boe for the third quarter of 2025, compared to a gain of $0.2 million or $0.31/boe for the third quarter of 2024. For the nine month period ending September 30, 2025, the realized gain on risk management contracts totaled $8.6 million or $2.56/boe (2024 - realized loss of $0.6 million or $0.42/boe). Hedging gains or losses are attributable to reference price fluctuations relative to pricing on commodity contracts driven by changes in AECO, WTI and WCS differential benchmark prices as well as fluctuations in foreign exchange rates and the percentage of production volumes hedged at any given time.

The unrealized loss on risk management contracts was $7.4 million for the third quarter of 2025 (Q3 2024 - $11.4 million unrealized gain) and the unrealized loss on risk management contracts was $3.0 million for the nine month period ended September 30, 2025 (2024 - $1.1 million unrealized gain). Unrealized gains and losses represent the change in the mark-to-market value of risk management contracts for future periods as forward commodity prices and foreign exchange rates change. Unrealized gains and losses on risk management contracts are excluded from the Company's calculation of cash flow from operating activities as non-cash items. Risk management contract gains and losses vary depending on commodity prices and the nature and extent of the risk management contracts in place, which in turn, vary with the Company's assessment of commodity price risk, committed capital spending and other factors.

Three months ended September 30, Nine months ended September 30,

1. Non-GAAP ratio. See "Non-GAAP and Other Financial Measures".

Rubellite's royalties consist of Crown royalties payable to the Alberta provincial government, royalties payable to Indian Oil and Gas Canada ("IOGC"), and other freehold and GORR royalties. The mix between Crown, IOGC and freehold production as a percentage of total production can change the composition of royalties from one period to the next. Under the Alberta Modernized Royalty Framework ("MRF"), the Company pays a Crown royalty of between 5% and 20% on wells where mineral rights are leased from the Crown. Under the Indian Oil and Gas Act, the Company pays a royalty of between 10% and 40% on wells where mineral rights are leased. The remainder of royalties are attributable to the composition of freehold and GORR royalties, some of which are price sensitive.

Total royalties for the three and nine months ended September 30, 2025, were $8.0 million and $25.1 million, an increase from the comparative periods of 2024 on higher production, increased revenue and a higher percentage of wells with gross overriding royalties ("GORR").

On a per boe basis, royalties were $7.18/boe and $7.46/boe, a decrease from the comparative periods of 2024 as a result of higher sales volumes and lower prices, which more than offset the higher percentage of wells drilled on lands with a GORR. Royalties as a percentage of revenue were higher than the comparative periods of 2024 due to increased number of wells receiving higher GORR royalty rates.

Three months ended September 30, Nine months ended September 30,

1. Non-GAAP measure. See "Non-GAAP and Other Financial Measures".

Total net operating costs for the three and nine months ended September 30, 2025 increased to $7.2 million and $22.6 million from $4.6 million and $10.0 million in the comparative periods of 2024 as a result of increased production volumes.

On a per boe basis, net operating costs for the three and nine months decreased by 24% to $6.46/boe and 8% to $6.72/boe (Q3 2024 -

$8.46/boe; 2024 - $7.29/boe). During the third quarter of 2025, costs were lower due to a reduction in carbon taxes driven by legislative changes announced in early 2025 and operational efficiencies at the Frog Lake property acquired in the third quarter of 2024. For the nine month period ended September 30, 2025, the reduction was driven by lower well servicing costs and third party processing fees, partially offset by higher repairs and maintenance costs in all areas.

Three months ended September 30, Nine months ended September 30,

Transportation costs include clean oil trucking costs and NGL transportation, as well as costs to transport natural gas from the plant gate to commercial sales point. Costs for the three and nine months ended September 30, 2025 increased to $5.2 million and $18.1 million, up from

$4.2 million and $10.6 million in the comparative periods of 2024 as a result of higher volumes.

On a per boe basis, transportation costs of $4.66/boe were 39% lower than the third quarter of 2024 (Q3 2024 - $7.67/boe) and 30% lower during the first nine months of 2025 (2024 - $7.73/boe). The decrease related to improved trucking rates realized for the Company's Clearwater and Frog Lake assets and the addition of natural gas volumes which incur lower transportation costs relative to the heavy oil assets.

The following tables highlight Rubellite's operating netbacks for the three and nine months ended September 30, 2025 and 2024:

Three months ended September 30, 2025 Three months ended September 30, 2024

Eastern

West

1. Non-GAAP measure. See "Non-GAAP and Other Financial Measures".

2. Realized hedging in the third quarter of 2025 is comprised of a $1.8 million gain on oil contracts and a $2.1 million gain on gas contracts (Q3 2024 - $0.2 million gain on oil contracts and nil on gas contracts).

Nine months ended September 30, 2025 Nine months ended September 30, 2024

Eastern

West

1. Non-GAAP measure. See "Non-GAAP and Other Financial Measures".

2. Realized hedging for the first nine months of 2025 is comprised of a $2.7 million gain on oil contracts and a $5.9 million gain on gas contracts (2024 - $0.6 million loss on oil contracts and nil on gas contracts).

Three months ended September 30, 2025 Three months ended September 30, 2024

Eastern

West

1. Non-GAAP measure. See "Non-GAAP and Other Financial Measures".

2. Realized hedging in the third quarter of 2025 is comprised of a $2.37/bbl gain on oil contracts and a $1.11/Mcf gain on gas contracts (2024 - $0.31/bbl gain on oil contracts and nil on gas contracts).

Nine months ended September 30, 2025 Nine months ended September 30, 2024

Eastern

West

1. Non-GAAP measure. See "Non-GAAP and Other Financial Measures".

2. Realized hedging for the first nine months of 2025 is comprised of a $1.19/bbl gain on oil contracts and a $1.01/Mcf gain on gas contracts (2024 - $0.42/ bbl loss on oil contracts and nil on gas contracts).

Rubellite's Eastern Heavy Oil operating netback for the three and nine months ended September 30, 2025 increased to $38.6 million and

$115.3 million (Q3 2024 - $29.6 million; 2024 - $76.2 million) as a result of higher sales volumes. On a per boe basis, the decrease during the three and nine months ended September 30, 2025 relative to the comparable periods of 2024 was driven by lower realized oil prices, partially offset by lower royalties and net operating and transportation costs.

Rubellite's total operating netback for the three and nine months ended September 30, 2025 increased to $37.9 million and $119.6 million from $29.6 million and $76.2 million in the comparative periods of 2024. On a per boe basis, the decrease was driven by lower total realized prices, reflecting lower oil prices and the addition of natural gas to the sales product mix through the Recombination Transaction and the completion of the Figure Lake gas plant, partially offset by reduced royalties and net operating and transportation costs.

For the three and nine month ended September 30, 2025, the operating netback after a realized gain on risk management contracts was

$37.53/boe and $38.16/boe (Q3 2024 - $54.33/boe; 2024 - $55.28/boe).

Three months ended September 30, Nine months ended September 30,

1. Prior to the Recombination Transaction, Rubellite Energy Inc. and Perpetual were considered related parties due to the existence of a Management and Operating Services Agreement ("MSA") and certain officers and directors being key management of, and having significant influence over, Rubellite Energy Inc. while also being key management of and having deemed control over Perpetual. Under the MSA, Rubellite Energy Inc. made payments to Perpetual for certain technical, capital and administrative services provided to Rubellite Energy Inc. on a relative cost sharing basis.

G&A expenses for the three and nine months ended September 30, 2025 increased to $5.2 million and $15.9 million (Q3 2024 - $1.0 million; 2024 - $2.6 million). Prior to the Recombination Transaction, G&A expenses, excluding MSA costs, consisted primarily of legal fees, computer software licenses, insurance, professional fees and public company costs. After the Recombination Transaction was completed, G&A expenses in Rubellite increased to include all G&A costs previously billed through the MSA including people, office and computer costs and recoveries.

For the three and nine months ended September 30, 2025, G&A costs on a per boe basis decreased to $3.24/boe and $3.58/boe from

$4.87/boe and $5.18/boe in the comparative periods of 2024 due to higher sales volumes.

Three months ended September 30, Nine months ended September 30,

The Company calculates depletion using the net book value of the asset, future development costs associated with proved and probable reserves, salvage values on associated production equipment, as well as proved plus probable reserves. As at September 30, 2025, depletion was calculated on a $496.4 million depletable balance (December 31, 2024 - $473.4 million), $387.5 million in future development costs (December 31, 2024 - $436.3 million) and excluded an estimated $9.2 million of salvage value (December 31, 2024 - $8.7 million).

Depletion and depreciation expense for the third quarter of 2025 was $23.6 million or $21.18/boe (Q3 2024 - $13.1 million or $23.95/boe). For the first nine months of 2025, depletion and depreciation expense was $70.0 million or $20.82/boe (2024 - $30.8 or $22.48/boe). The increase in depletion related to a higher depletable base than the comparable period as a result of the BMEC Acquisition and the Recombination Transaction. On a per boe basis, depletion was lower in the three and nine months ended September 30, 2025 relative to the comparable periods of 2024, as a result of the Recombination Transaction, as the West Central assets have higher reserves relative to production resulting in a lower per unit cost of reserves relative to Rubellite's Eastern Heavy Oil assets. Depletion will fluctuate from one period to the next depending on the amount of capital spent, the amount of reserves added and volumes produced.

There were no indicators of impairment for either of the Company's CGUs as at September 30, 2025, therefore, an impairment test was not performed.

E&E assets are tested for impairment when internal or external indicators of impairment exist as well as upon reclassification to oil and natural gas interests in PP&E. At September 30, 2025, the Company conducted an assessment of indicators of impairment for the Company's E&E assets. In performing the assessment, management determined there were no indicators of impairment.

During the first nine months of 2025 there have been no transfers between E&E and PP&E. During 2024, the Company transferred $20.8 million of E&E to PP&E. As a result of the transfer, the Company performed the required impairment test to estimate the recoverable amount of the CGU. It was determined that the recoverable amount of the CGU exceeded its carrying value, resulting in no impairment.

Three months ended September 30, Nine months ended September 30,

Total cash finance expense for the three and nine months ended September 30, 2025 increased to $2.6 million and $7.4 million (Q3 2024 -

$2.0 million; 2024 - $4.1 million) as a result of higher average outstanding bank debt during the period, the addition of the term loan in the third quarter of 2024 and interest on lease liabilities from the Recombination Transaction. The effective aggregate interest rate on the Company's bank line for both the three and nine month period ended September 30, 2025 was 6.2% (Q3 2024 - 8.6%; 2024 - 8.5%) and the interest rate on the term loan was 11.5%.

Non-cash finance expense represents accretion on decommissioning obligations, accretion on the other provision and amortization of debt issue costs.

For the three and nine months ended September 30, 2025, cash finance expense on a per boe basis decreased from the comparative periods of 2024 due to higher sales volumes.

($ thousands) December 31, 2024 Recognized in earnings Recognized in equity September 30, 2025

For the three and nine months ended September 30, 2025, the Company recorded a deferred income tax expense of $1.8 million and $9.5 million (Q3 2024 - income tax expense of $5.4 million; 2024 - income tax expense of $6.8 million).

Rubellite's strategy targets the maintenance of a strong capital base to retain investor, creditor and market confidence to support the execution of its business plans. The Company manages its capital structure and adjusts its capital spending in light of changes in economic conditions, available liquidity, and the risk characteristics of its underlying assets. The Company considers its capital structure to include share capital, bank debt, term loans and adjusted working capital. To manage its capital structure and available liquidity, Rubellite may from time to time issue equity or debt securities, sell assets, and adjust its capital spending to manage current and projected debt levels. The Company will continue to regularly assess changes to its capital structure, with considerations for both short-term liquidity and long-term financial sustainability.

1. Bank debt shown net of cash balance of $2.6 million as at December 31, 2024. Adjusted working capital deficit excludes the cash balance of $2.6 million as at December 31, 2024.

2. Non-GAAP measure or ratio. See "Non-GAAP and Other Financial Measures".

3. Based on Q3 2025 adjusted funds flow, before transaction costs of $35.7 million (Q3 2024 - $25.0 million). See "Non-GAAP and Other Financial Measures" for more details.

At September 30, 2025, Rubellite had net debt of $138.4 million, a 10% decrease from $154.0 million at December 31, 2024. Net debt decreased as a result of adjusted funds flow for the first nine months of 2025 of $108.9 million exceeding capital expenditures including land and other expenditures of $91.5 million, which generated free funds flow $17.4 million and proceeds of $5.5 million from the sale of undeveloped land during the third quarter. The positive free funds flow and proceeds from the undeveloped land disposition were primarily used to reduce net debt and other obligations which included the $3.8 million reduction of the other provision, $1.3 million of spending on decommissioning activities and $2.6 million in payments for cash-settled share-based compensation.

Rubellite had available liquidity at September 30, 2025 of $48.0 million, comprised of the $140.0 million Credit Facility Borrowing Limit, less bank borrowings of $90.6 million and outstanding letters of credit of $1.4 million.

As at September 30, 2025, the Company's first lien credit facility had a borrowing limit of $140.0 million (December 31, 2024 - $140.0 million). The initial term is to May 31, 2026 and may be extended for a further twelve months to May 31, 2027 subject to lender approval. If not extended by May 31, 2026, all outstanding advances would be repayable on May 31, 2027. The next semi-annual borrowing base redetermination is scheduled on or before November 30, 2025.

As at September 30, 2025, $90.6 million was drawn against the credit facility (December 31, 2024 - $108.5 million) and $1.4 million (December 31, 2024 - $3.6 million) of letters of credit have been issued. Borrowings under the credit facility bear interest at the lenders' prime rate or CORRA rates, plus applicable margins and standby fees. The applicable CORRA margins range between 2.8% and 6.3%. The effective aggregate interest rate on the credit facility at September 30, 2025 was 6.2% per annum. For the period ended September 30, 2025, if interest rates changed by 1% with all other variables held constant, the impact on cash finance expense and net income and comprehensive income would be $0.7 million.

The credit facility is secured by general first lien security agreements covering all present and future property of the Company.

At September 30, 2025, the credit facility was not subject to any financial covenants and the Company was in compliance with all customary non-financial covenants.

On August 2, 2024, Rubellite entered into a senior secured second-lien term loan which was placed, directly or indirectly, with certain directors and officers, and their affiliates, of Rubellite and the Company's significant shareholder for $20.0 million. The term loan bears interest at 11.5% annually with interest payments to be paid quarterly and matures in five years from the date of issue, and can be repaid by the Company without penalty at any time. In conjunction with the closing of the Recombination Transaction, the term loan was converted to a third-lien obligation of the Company.

During the three and nine months ending September 30, 2025, Rubellite paid $0.6 and $1.7 million in cash interest payments to the holders of the term loan (three and nine months ended September 30, 2024 - $0.4 million).

At September 30, 2025, the term loan has been recorded at the present value of future cash flows, net of $0.9 million (December 31, 2024 -

$1.0 million) in issue and discount costs which are amortized over the remaining term using a weighted average effective interest rate of 13.0%.

The term loan is not subject to any financial covenants and the Company was in compliance with all customary non-financial covenants.

At September 30, 2025, entities controlled or directed by the Company's Chief Executive Officer ("CEO") hold $18.4 million of the outstanding term loan.

At September 30, 2025, there were 93.6 million common shares outstanding, net of 0.1 million shares held in trust for employee compensation programs (December 31, 2024 - 92.9 million common shares outstanding, net of 0.2 million of shares held in trust).

On August 2, 2024, in conjunction with the closing of the BMEC Acquisition, Rubellite issued 5.0 million common shares to certain shareholders of Buffalo Mission, which were valued at $10.4 million using the Company's share price on the closing date of the transaction of

$2.07 per share.

On October 31, 2024, in conjunction with the closing of the Recombination Transaction, Rubellite issued 25.4 million common shares which were valued at $51.7 million using the Company's share price on the closing date of the transaction of $2.04 per share.

At November 5, 2025 there were 93.6 million common shares outstanding, net of 0.1 million shares held in trust for employee compensation programs.

The following table summarizes information about options and performance awards and restricted awards outstanding as the date of this MD&A:

1. Perpetual awards from the Recombination Transaction include 0.9 million deferred options, 0.3 million deferred shares, 0.8 million share options and 0.3 million performance share rights. All Perpetual awards from the Recombination Transaction were adjusted both in number issued and exercise price by the exchange ratio of 5:1.

2. Total awards outstanding include 1.4 million legacy awards that can be settled for cash or from shares in the trust as opposed to treasury. Shares in the trust as at November 5, 2025 0.8 million.

As at November 5, 2025, Rubellite had entered into the following oil commodity risk management contracts:

As at November 5, 2025, Rubellite had entered into the following natural gas commodity risk management contracts:

(1) Inclusive of 15,000 GJ/d sold at $3.19/GJ and a $5.82/GJ realized gain on 12,500 GJ/d of contracted volumes closed out during the period.

As at November 5, 2025, Rubellite entered into the following foreign exchange risk management contracts:

(1) At expiry on December 31, 2026 if the calendar 2027 forward strip is above 1.3890 CAD$/US$, Rubellite knocks into a $5.0 million US$/month contract at 1.3890 CAD$/US$ for the 2027 calendar year.

(1) If the monthly average exchange rate is below the floor price, settlement for that month will occur at the floor price. If the monthly average exchange rate is above the ceiling price, settlement for that month will be against the reset price. No settlement occurs when the monthly average exchange rate is between the floor and ceiling price.

The Company has a drilling commitment on certain GORR lands that must be fulfilled by June 30, 2026 (the "Commitment Date"). In the event the Company fails to fulfill the drilling commitment, the Company is required to pay $0.1 million per well not spud by the Commitment Date. As at September 30, 2025, the Company has drilled 24 gross (24.0 net) of the 59 gross (59.0 net) wells that are required to meet the drilling commitment. Subsequent to September 30, 2025, the Company has drilled an additional 3 gross (3.0 net) wells for a total of 27 gross (27.0 net) wells required to meet the drilling commitment.

Decommissioning obligations are estimated based on the Company's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells and facilities, and the estimated timing of the costs to be incurred in future periods.

The increase in the provision due to the passage of time, which is referred to as accretion, is recognized as non-cash finance expense in the consolidated statements of income and comprehensive income. Decommissioning obligations are further adjusted at each period end date for changes in the risk-free interest rate, after considering additions and dispositions of PP&E. Decommissioning obligations are also adjusted for revisions to future cost estimates and the estimated timing of costs to be incurred in future periods.

The following significant assumptions were used to estimate the Company's decommissioning obligations:

The other provision was assumed as part of the Recombination Transaction and relates to a "Settlement Agreement" Perpetual entered into to resolve litigation by providing amounts to settle asset retirement obligations without any party admitting liability, wrongdoing or violation of laws, regulations, public policy or fiduciary duties. The Company will make annual installment payments of $3.75 million until the total amount of the Settlement Principal is paid. The annual scheduled payment was made on March 28, 2025 and all scheduled payments made prior to March 28, 2026 will have the interest forgiven. As of March 28, 2026, interest will accrue and be payable on the outstanding Settlement Principal annually at an interest rate equal to the applicable Bank of Canada prime rate on the date of payment. The Company is able to prepay all, or any portion, of the outstanding balance of the Settlement Principal at any time without bonus or penalty.

Rubellite has no material off balance sheet arrangements.

Throughout this MD&A and in other materials disclosed by the Company, Rubellite employs certain measures to analyze financial performance, financial position and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss), cash flow from (used in) operating activities, and cash flow from (used in) investing activities, as indicators of Rubellite's performance.

The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to capital expenditures, is set forth below:

Three months ended September 30, Nine months ended September 30,

Three months ended September 30,

Nine Months Ended September 30,

The following table reconciles net operating costs from production and operating expenses and other income in the Company's consolidated statement of income (loss) and comprehensive income (loss).

Three months ended September 30, Nine months ended September 30,

Refer to reconciliations in the MD&A under the "Operating Netbacks" section for current period and comparative information.

The following table reconciles working capital and net debt as reported in the Company's statements of financial position:

($ thousands) As of September 30, 2025 As of December 31, 2024

1. Calculation of current assets less current liabilities has been adjusted for the removal of the current portion of risk management contracts, decommissioning liabilities, lease liabilities, share-based compensation and other provisions.

2. Excludes other non-current liabilities.

the ability of the Company to generate the funds necessary to finance capital expenditures, expenditures on decommissioning obligations, expenditures on share based compensation and meet its financial obligations.

Adjusted funds flow is not intended to represent net cash flows from operating activities calculated in accordance with IFRS.

The following table reconciles net cash flows from operating activities, as reported in the Company's statements of cash flows, to adjusted funds flow:

Three months ended September 30, Nine months ended September 30,

diluted

The following table shows the calculation of the removal of capital expenditures from adjusted funds flows pre transaction costs:

Three months ended September 30, Nine months ended September 30,

Rubellite calculates certain non-GAAP measures per boe as the measure divided by weighted average daily production. Management believes that per boe ratios are a key industry performance measure of operational efficiency and one that provides investors with information that is also commonly presented by other crude oil and natural gas producers. Rubellite also calculates certain non-GAAP measures per share as the measure divided by outstanding common shares, weighted average common shares or diluted weighted average common shares.

"Average realized price" is comprised of total oil and natural gas revenue, as determined in accordance with IFRS, divided by the Company's total sales production on a per barrel basis.

"Realized oil price" is comprised of oil commodity sales from production, as determined in accordance with IFRS, divided by the Company's oil sales production.

"Realized natural gas price" is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company's natural gas sales production.

"Realized NGL price" is comprised of NGL commodity sales from production, as determined in accordance with IFRS, divided by the Company's NGL sales production.

"Realized gain (loss) on natural gas contracts per Mcf" is comprised of the realized gain or loss on natural gas contracts, as determined in accordance with IFRS, divided by the Company's total natural gas sales production.

"Realized gain (loss) on oil contracts per boe" is comprised of the realized gain or loss on oil contracts, as determined in accordance with IFRS, divided by the Company's total oil sales production.

"Realized gain (loss) on risk management contracts per boe" is comprised of the realized gain or loss on risk management contracts, as determined in accordance with IFRS, divided by the Company's total sales production.

"Royalties as a percentage of revenue" is comprised of royalties, as determined in accordance with IFRS, divided by oil and natural gas revenue from sales production as determined in accordance with IFRS.

"Royalties per boe" is comprised of royalties, as determined in accordance with IFRS, divided by the Company's total sales production. "Net operating expense per boe" is comprised of net operating expense, divided by the Company's total sales production.

"Transportation cost ($/boe)" is comprised of transportation cost, as determined in accordance with IFRS, divided by the Company's total sales production.

"G&A cost ($/boe)" is comprised of G&A expense, as determined in accordance with IFRS, divided by the Company's total sales production.

"Depletion and depreciation expense ($/boe)" is comprised of depletion expense, as determined in accordance with IFRS, divided by the Company's total sales production.

"Market value of shares" is comprised of common shares outstanding multiplied by the market price of shares.

"Heavy oil wellhead differential ($/bbl)" represents the differential the Company receives for selling its heavy crude oil production relative to the Western Canadian Select reference price (CAD$/bbl) prior to any price or risk management activities.

The Company's Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P"), as defined by National Instrument 52-109. The Company's CEO and CFO have designed, or caused to be designed under their supervision, internal controls over financial reporting ("ICFR"), as defined by National Instrument 52-109, to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of financial statements for external purposes in accordance with IFRS Accounting Standards.

There were no changes in the Company's DC&P or ICFR during the period beginning July 1, 2025 and ending on September 30, 2025 that have materially affected, or are reasonably likely to materially affect, the Company's ICFR. It should be noted that a control system, including the Company's disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

Certain information in this MD&A including management's assessment of future plans and operations, and including the information contained under the headings "Operations Update" and "Outlook and Guidance" may constitute forward-looking information or statements (together "forward-looking information") under applicable securities laws. The forward-looking information includes, without limitation, statements with respect to: future capital expenditures, production and various cost forecasts; the anticipated sources of funds to be used for capital spending; expectations as to future exploration, development and drilling activity, regulatory application and the benefits to be derived from such drilling including production growth; maintaining the one rig drilling program at each of Figure Lake and Frog Lake for the remainder of 2025; the plan to advance strategic initiatives such as land continuation and new capture, secondary recovery and exploration; the ability to obtain meaningful per well capital cost reductions to maintain attractive rates of return and payout periods; the plan to manage capital spending to prioritize free funds flow generation over production growth in the current commodity price environment; the use of excess free funds flow to reduce net debt and for other balance sheet obligations; adjusted funds flow, free funds flow and commodity price forecasts; Rubellite's business plan; and including the forward-looking information contained under the heading "Outlook and Guidance" and "Nature of Business".

Forward-looking information is based on current expectations, estimates and projections that involve a number of known and unknown risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by Rubellite and described in the forward-looking information contained in this MD&A. In particular and without limitation of the foregoing, material factors or assumptions on which the forward-looking information in this MD&A is based include: the successful operation of the Company's assets, forecast commodity prices and other pricing assumptions; forecast production volumes based on business and market conditions; foreign exchange and interest rates; near-term pricing and continued volatility of the market; accounting estimates and judgments; future use and development of technology and associated expected future results; the ability to obtain regulatory approvals; the successful and timely implementation of capital projects; ability to generate sufficient cash flow to meet current and future obligations and future capital funding requirements (equity or debt); the ability of Rubellite to obtain and retain qualified staff and equipment in a timely and cost-efficient manner, as applicable; the retention of key properties; forecast inflation, supply chain access and other assumptions inherent in Rubellite's current guidance and estimates; climate change; severe weather events (including wildfires, floods and drought); the continuance of existing tax, royalty, and regulatory regimes; the accuracy of the estimates of reserves volumes; ability to access and implement technology necessary to efficiently and effectively operate assets; risk of wars or other hostilities or geopolitical events (including the ongoing war in Ukraine and conflicts in the Middle East), civil insurrection and pandemics; risks relating to Indigenous land claims and duty to consult; data breaches and cyber attacks; risks relating to the use of artificial intelligence; changes in laws and regulations, including but not limited to tax laws, royalties and

environmental regulations (including greenhouse gas emission reduction requirements and other decarbonization or social policies) and including uncertainty with respect to the interpretation and impact of omnibus Bill C-59 and the related amendments to the Competition Act (Canada), and the interpretation of such changes to the Company's business); political, geopolitical and economic instability; trade policy, barriers, disputes or wars (including new tariffs or changes to existing international trade requirements) and general economic and business conditions and markets, among others.

Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described herein and under "Risk Factors" in the Company's Annual Information Form and MD&A for the year ended December 31, 2024 and in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR+ website https://www.sedarplus.ca and at Rubellite's website https://www.rubelliteenergy.com. Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Rubellite's management at the time the information is released, and Rubellite disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities law.

The following is a list of abbreviations that may be used in this MD&A:

bbl barrel

bbl/d barrels per day

Mbbl thousand barrels

MMbbl million barrels

boe barrels of oil equivalent

boe/d barrels of oil equivalent per day

Mcf thousand cubic feet

MMcf million cubic feet

Mcf/d thousand cubic feet per day

MMcf/d million cubic feet per day

GJ gigajoule

This MD&A contains certain industry metrics which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this document to provide readers with additional measures to evaluate Rubellite's performance; however, such measures are not reliable indicators of Rubellite's future performance and future performance may not compare to Rubellite's performance in previous periods and therefore such metrics should not be unduly relied upon.

Barrel of oil equivalent ("boe") may be misleading, particularly if used in isolation. In accordance with National Instrument 51-101 ("NI 51-101"), a conversion ratio for conventional natural gas of 6 Mcf:1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, utilizing a conversion on a 6 Mcf:1 bbl basis may be misleading as an indicator of value as the value ratio between conventional natural gas and heavy crude oil, based on the current prices of natural gas and crude oil, differ significantly from the energy equivalency of 6 Mcf:1 bbl. A conversion ratio of 1 bbl of heavy crude oil to 1 bbl of NGL has also been used throughout this MD&A.

Any references in this MD&A to initial production rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Such rates are based on field estimates and may be based on limited data available at this time.

Of the 326.2 net heavy oil drilling development locations disclosed in this MD&A, 93.1 net are proved and 45.6 net are probable undeveloped locations in the McDaniel Reserve Report at year end 2024. Of those heavy oil locations, a total of 8.0 net Figure Lake proved undeveloped,

4.5 net North Waseca proved undeveloped, 4.5 net North Waseca probable undeveloped, and 3.0 South Waseca proved undeveloped have been drilled through 2025. There are 9.5 net proven natural gas locations and 4.4 net probable natural gas locations in the McDaniel Reserve Report at year end 2024. Of those natural gas locations, a total of 1.0 net proven undeveloped gas location has been drilled through 2025. Unbooked drilling locations are the internal estimates of Rubellite based on Rubellite's or the acquired assets prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by Rubellite's management as an estimation of Rubellite's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Rubellite will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which Rubellite will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been de-risked by Rubellite drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management of Rubellite has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

AECO Alberta Energy Company

E&E Exploration and evaluation

ESG Environmental, social and governance

GAAP Generally accepted accounting principles

G&A General and administrative

IAS International Accounting Standard

IASB International Accounting Standards Board

IFRS International Financial Reporting Standards

NGL Natural gas liquids

PP&E Property, plant and equipment

WTI West Texas Intermediate

WCS Western Canadian Select

1. Non-GAAP measure, ratio or supplementary measure. See "Non-GAAP and Other Financial Measures".

2. Per share amounts are calculated using the weighted average number of basic or diluted common shares.

3. Includes cash and non-cash consideration.

4. Conventional heavy oil sales production excludes tank inventory volumes.

5. Q4 2024 includes $4.2 million in transaction costs related to the Recombination Transaction with Perpetual, Q3 2024 includes $2.0 million in transaction costs related to the BMEC Acquisition and Q4 2023 includes $0.1 million in transaction costs related to a Clearwater asset acquisition.

Oil and natural gas revenue has ranged between $27.2 million and $66.6 million over the prior eight quarters largely due to increasing sales volumes from 4,209 boe/d to 12,425 boe/d, partially offset by volatility in commodity pricing. Net income (loss) has ranged between a loss of

$4.2 million and income of $26.7 million primarily due to increased production, corporate acquisitions and dispositions, volatility of commodity prices and its impact on revenue, royalties and realized and unrealized risk management contract gains and losses and deferred income taxes.

(Cdn$ thousands, except per share amounts, unaudited)

Three months ended September 30, Nine months ended September 30,

See accompanying notes to the condensed interim consolidated financial statements.

Share Capital Contributed

Retained

Total

(Cdn$ thousands, except share amounts, unaudited)

(thousands) ($thousands)

surplus

earnings

Equity

purchase

Share Capital Share

Contributed

Retained

Total

(Cdn$ thousands, except share amounts, unaudited)

(thousands) ($thousands) warrants

surplus

earnings

Equity

Balance at September 30, 2024 67,593 $ 153,855 $ 2,000 $ 4,234 $ 74,093 $ 234,182

See accompanying notes to the condensed interim consolidated financial statements.